ITEM 1. BUSINESS
GENERAL
Cleco Corporation was incorporated on October 30, 1998, under the laws of the State of Louisiana. Cleco Corporation is a public utility holding company which holds investments in several subsidiaries, including Cleco Power and Midstream, which are its operating business segments. Cleco Corporation, subject to certain limited exceptions, is exempt from regulation as a public utility holding company pursuant to provisions of the Public Utility Holding Company Act of 2005.
Cleco Power’s predecessor was incorporated on January 2, 1935, under the laws of the State of Louisiana. Cleco Power was organized on December 12, 2000. Cleco Power is an electric utility engaged principally in the generation, transmission, distribution and sale of electricity within Louisiana. Cleco Power is regulated by the LPSC and FERC, which determine the rates Cleco Power can charge its customers, as well as other regulators. Cleco Power serves approximately 276,000 customers in 107 communities in central and southeastern Louisiana. Cleco Power’s operations are described below in the consolidated description of Cleco’s business segments.
Midstream, organized effective September 1, 1998, under the laws of the State of Louisiana, is a merchant energy subsidiary that owns and operates a merchant power plant (Evangeline). Midstream also owns a 50 percent interest in a merchant power plant (Acadia) and operates the plant on behalf of its partner.
At December 31, 2008, Cleco employed 1,320 people. Cleco’s mailing address is P.O. Box 5000, Pineville, Louisiana 71361-5000, and its telephone number is (318) 484-7400. Cleco’s homepage on the Internet is located at http://www.cleco.com. Cleco Corporation’s and Cleco Power’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings with the SEC are available, free of charge, through Cleco’s website after those reports or filings are filed electronically with or furnished to the SEC. Cleco’s filings also can be obtained at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. Cleco’s electronically filed reports also can be obtained on the SEC’s Internet site located at http://www.sec.gov. Cleco’s corporate governance guidelines, code of business conduct, ethics and business standards, and the charters of its board of directors’ audit, compensation, executive, finance, nominating/governance and qualified legal compliance committees are available on its website and available in print to any shareholder upon request. Information on Cleco’s website or any other website is not incorporated by reference into this Report and does not constitute a part of this Report.
At December 31, 2008, Cleco Power employed 1,023 people. Cleco Power’s mailing address is P.O. Box 5000, Pineville, Louisiana, 71361-5000, and its telephone number is (318) 484-7400.
Cleco Power meets the conditions specified in General Instructions I(1)(a) and (b) to Form 10-K and therefore is permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, Cleco Power has omitted from this Report the information called for by Item 4 (Submission of Matters to a Vote of Security Holders) of Part I of Form 10-K; the following Part II items of Form 10-K: Item 6 (Selected Financial Data) and Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations); and the following Part III items of Form 10-K: Item 10 (Directors, Executive Officers, and Corporate Governance of the Registrants), Item 11 (Executive Compensation), Item 12 (Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters), and Item 13 (Certain Relationships and Related Transactions, and Director Independence).
OPERATIONS
Cleco Power
Segment Financial Information
Summary financial results of the Cleco Power segment for years 2008, 2007, and 2006 are presented below.
For additional information on Cleco Power’s results of operations, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Cleco Power’s Results of Operations.”
Certain Factors Affecting Cleco Power
As an electric utility, Cleco Power is affected, to varying degrees, by a number of factors influencing the electric utility industry in general. These factors include, among others,
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fluctuations in the price of natural gas, an increasingly competitive business environment, the cost of compliance with environmental and reliability regulations, conditions in the credit markets and global economy and changes in the federal and state regulation of generation, transmission, and the sale of electricity. For a discussion of various regulatory changes and competitive forces affecting Cleco Power and other electric utilities, see “- Regulatory Matters, Industry Developments, and Franchises” and Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Market Restructuring.” For a discussion of risk factors affecting Cleco Power’s business, see Item 1A, “Risk Factors - Rodemacher Unit 3 Construction Costs,” “- Rodemacher Unit 3 Technical Specifications,” “- Cleco Power’s Rates and Rate Case,” “- Fuel Cost Audits,” “- Hedging and Risk Management Activities,” “- Future Electricity Sales,” “- Purchased Power,” “- Weather Sensitivity,” “- Commodity Prices,” “- Cleco Power Generation Facilities,” “- ERO,” “- Environmental Compliance,” “- Regulatory Compliance,” “- Termination of the Rodemacher Unit 3 Project or the Amended EPC Contract,” “- Retail Electric Service,” “- Cleco Credit Ratings,” “- Storm Restoration Costs,” and “- Global Financial Crisis.”
Power Generation
Cleco Power operates and either owns or has an ownership interest in three steam electric generating stations and one gas turbine. As of December 31, 2008, Cleco Power’s aggregate net electric generating capacity was 1,318 MW. This amount reflects the maximum production capacity these units can sustain over a specified period of time. The following table sets forth certain information with respect to Cleco Power’s generating facilities:
(1) Based on capacity testing of the generating units performed between June and September 2007.
(2) When oil is used on a standby basis, capacity may be reduced.
(3) Represents Cleco Power’s 30% ownership interest in the capacity of Rodemacher Unit 2, a 523-MW generating unit.
(4) Represents Cleco Power’s 50% ownership interest in the capacity of Dolet Hills, a 650-MW generating unit.
The following table sets forth the amounts of power generated by Cleco Power for the years indicated.
In May 2006, Cleco Power began construction of Rodemacher Unit 3, a 600-MW solid-fuel power plant at its Rodemacher facility, which will provide a portion of the utility’s power supply needs. Rodemacher Unit 3 will be capable of burning various solid fuels, but primarily is expected to burn petroleum coke produced by several refineries throughout the Gulf Coast region. The total capital cost of the project, including AFUDC, Amended EPC Contract costs, and other development expenses, is estimated at $1.0 billion. Cleco Power anticipates the plant will be substantially complete and operational in the second half of 2009. For additional information on Rodemacher Unit 3, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Regulatory Matters - Rodemacher Unit 3.”
Fuel and Purchased Power
Changes in fuel and purchased power expenses reflect fluctuations in types and pricing of fuel used for electric generation, fuel handling costs, availability of economical power for purchase, and deferral of expenses for recovery from customers through the fuel adjustment clause in subsequent months. For a discussion of certain risks associated with changes in fuel costs and their impact on utility customers, see Item 1A, “Risk Factors - Fuel Cost Audits” and “- Purchased Power.”
The following table sets forth the percentages of power generated from various fuels at Cleco Power’s electric generating plants, the cost of fuel used per MWh attributable to each such fuel, and the weighted average fuel cost per MWh.
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Power Purchases
When the market price of power is more economical than self-generation of power or when Cleco Power needs power to supplement its own electric generation, and when transmission capacity is available, Cleco Power purchases power from energy marketing companies or neighboring utilities. These purchases are made from the wholesale power market in the form of generation capacity and/or energy. During 2008, portions of Cleco Power’s capacity and power purchases were made at contract prices, and the remainder were made at prevailing market prices.
The following table sets forth the average cost and amounts of power purchased by Cleco Power on the wholesale market.
During 2008, 55.7% of Cleco Power’s energy requirements were met with purchased power, down from 58.0% in 2007. The primary factor causing the decrease was the increased generation from Cleco Power’s own facilities as a result of less maintenance work performed during 2008. For information on Cleco Power’s ability to pass on to its customers substantially all of its fuel and purchased power expenses, see “- Regulatory Matters, Industry Developments, and Franchises - Rates.”
During 2008, Cleco Power obtained approximately 40.4% of its annual capacity from short- and long-term power purchase agreements. One agreement is with Bear Energy for 500 MW of annual capacity through 2009. The second agreement was with NRG Power Marketing, Inc. (NRG). The term of this agreement was one year during which Cleco Power purchased 115 MW from May through October and 100 MW during the remainder of 2008. A third capacity and energy agreement with Union Power Partners, L.P. (UPP) supplied a 218-MW next day call from May through September 2008. Cleco Power also has a long-term contract, which expires in April 2018, for the purchase of 20 MW of power from the Sabine River Authority, which operates a hydroelectric generating plant. In addition, Cleco Power has a wholesale power contract with the city of Natchitoches, which provided 42 MW of capacity in 2008. The current contract expires in December 2009.
As a result of its 2008 short-term RFP for 2009 resources, Cleco Power successfully negotiated a power purchase agreement with Acadia for 235 MW of capacity and energy for 2009. Cleco Power has received approval for the power purchase agreement from the LPSC and FERC.
Management expects to meet its native load demand in 2009 with Cleco Power’s own generation capacity, wholesale power market purchases, and power purchase agreements with Bear Energy and Acadia, in addition to capacity requested in a RFP that was issued on January 6, 2009 for a minimum capacity amount of 50 MW up to 200 MW in order to serve additional load. On February 9, 2009, a winning bidder was selected. Cleco Power is currently negotiating the terms of the contract and anticipates signing a power purchase agreement by the end of the first quarter of 2009. The requested products for supply will start April 1, 2009 and continue through October 31, 2009. For additional information on Cleco Power’s risks associated with purchased power contracts, see Item 1A, “Risk Factors - Purchased Power.”
Cleco Power has an IRP team to evaluate its long-term capacity requirements. IRP is a process to evaluate resources in order to provide reliable and flexible power supplies to electric customers at the lowest reasonable cost. A full range of options are being analyzed, including:
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new plant construction;
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fuel conversion projects;
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repowering projects;
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renewable resource projects; and
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demand-side management.
The process considers both operational and economic features, such as construction, operating and fuel costs, fuel diversity, reliability, deliverability, ease of dispatch, environmental impact, and other risk factors. The IRP team has developed a framework for evaluating proposed options to optimize service for Cleco Power’s customers’ needs and to reduce and stabilize their fuel cost without sacrificing reliability. Any viable generation alternative must then be validated through an LPSC-sanctioned RFP process. The resource planning effort employs software to model complex factors including the need for energy, market conditions, commodity pricing, new legislation and regulations, plant output, weather and other factors expected to impact the electric industry in future years. Cleco Power released a RFP in October 2007 seeking long-term resources to fill the needs identified by the latest IRP. Bids for this RFP were received in December 2007 and Cleco Power notified bidders that were selected for the short list. On February 26, 2009, Cleco Power announced that it had chosen the acquisition of 50 percent of the Acadia power station, or one of its two 580-MW units, as the lowest bid in its 2007 long-term RFP for capacity beginning in 2010. Cleco Power will own and operate one unit and operate the other 580-MW unit on behalf of Acadia. Prior to closing the transaction, valued at approximately $300.0 million, Cleco Power must complete its due diligence, finalize and execute definitive agreements, and receive approvals from the LPSC and FERC. Cleco Power and Acadia plan to complete the transaction by the end of 2009 in a process that remains under the supervision of an independent monitor appointed by the LPSC. For additional information on Cleco Power’s power supply, see Item 1A, “Risk Factors - Rodemacher Unit 3 Construction Costs” and “- Purchased Power.”
Because of its location on the transmission grid, Cleco Power relies on two main suppliers of electric transmission when accessing external power markets. At times, constraints limit the amount of purchased power these transmission providers can deliver into Cleco Power’s service territory. Cleco
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Power’s power contracts, as well as spot market power purchases, may be affected by these transmission constraints. For information on the Acadiana Load Pocket project and how transmission constraints in this area are expected to be reduced, see Part II, Item 7A, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Matters - Acadiana Load Pocket.”
Coal and Lignite Supply
Cleco Power uses coal for generation at Rodemacher Unit 2. In 2007, Cleco Power entered into agreements with Rio Tinto Energy America and Peabody Energy which will provide the majority of coal needs through 2014. The coal supply agreements are fixed-price (without reopeners) and together provide for the full requirements to support Cleco Power’s minimum case planned dispatch of Rodemacher Unit 2 (4 million tons total over the 7-year period). To the extent that the actual dispatch of the unit exceeds the minimum case model, Cleco Power expects to make additional spot purchases to maintain inventory within targeted levels. The volume commitment was designed to reasonably assure that excess inventory will not accumulate during the term of the agreement. With respect to transportation of coal, Cleco Power had a three-year agreement with Union Pacific Railroad Company (UP) for transportation of coal from the Powder River Basin to Rodemacher Unit 2 through 2008. A new three-year agreement with UP was entered into in June 2008, providing rail transportation to the facility through 2011. Cleco Power leases approximately 241 railcars to transport its coal under two long-term leases. One of the railcar leases expires in March 2017, and the other expires in March 2021.
Cleco Power uses lignite for generation at the Dolet Hills power station. Substantially all of the lignite used to fuel Dolet Hills is obtained under two long-term agreements. One of the agreements expires on December 31, 2010. The other agreement has no specific expiration date. Factors that could cause the agreement to expire are the depletion of all economically surface mineable lignite reserves or the closing of the mine and the completion of reclamation work. Cleco Power and SWEPCO, each a 50% owner of Dolet Hills, have acquired an undivided 50% interest in the other’s leased and owned lignite reserves in northwestern Louisiana. In May 2001, Cleco Power and SWEPCO entered into a long-term agreement with DHLC for the mining and delivery of such lignite reserves. These reserves are expected to provide a substantial portion of the Dolet Hills’ unit’s fuel requirements throughout the life of the contract with DHLC. The term of this contract runs until all economically mineable lignite has been mined, which is currently estimated to be around 2016.
Additionally, Cleco Power and SWEPCO have entered into an agreement which expires in 2010 with Red River Mining Company to purchase lignite. Cleco Power’s minimum annual purchase requirement of lignite under this agreement is 550,000 tons. The lignite price under the contract is a base price per MMBtu, subject to escalation, plus certain “pass-through” costs. DHLC provides all of the lignite in excess of the 550,000 tons base commitment. For information regarding deferred mining costs and obligations associated with the DHLC mining agreement see, Part II, Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 3 - Regulatory Assets and Liabilities - Deferred Mining Costs” and Note 15 - “Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees - Off-Balance Sheet Commitments and Disclosures about Guarantees.”
The continuous supply of coal and lignite may be subject to interruption due to adverse weather conditions or other factors that may disrupt mining operations or transportation to the plant site. At December 31, 2008, Cleco Power’s coal inventory at Rodemacher Unit 2 was approximately 302,000 tons (about a 137-day supply), and Cleco Power’s lignite inventory at Dolet Hills was approximately 227,000 tons (about a 37-day supply).
Natural Gas Supply
During 2008, Cleco Power purchased a total of 17,087,000 MMBtu of natural gas for the generation of electricity. The annual and average per-day quantities of gas purchased by Cleco Power from each supplier are shown in the table below.
Cleco Power owns the natural gas pipelines and interconnections at its Rodemacher and Teche power stations. This allows it to access various natural gas supply markets, which helps to maintain a more economical fuel supply for Cleco Power’s customers.
Natural gas was available without interruption throughout 2008. Cleco Power expects to continue to meet its natural gas requirements with purchases on the spot market through daily, monthly, and seasonal contracts with various natural gas suppliers. However, future supplies to Cleco Power remain vulnerable to disruptions due to weather events and transportation delays. Large industrial users of natural gas, including electric utilities, generally have low priority among gas users in the event pipeline suppliers are forced to curtail deliveries due to inadequate supplies. As a result, prices may increase rapidly in response to temporary supply interruptions. Although prices may increase rapidly, Cleco Power enters into economic hedge positions to mitigate the volatility in fuel costs as encouraged by an LPSC order. For additional information on these economic hedge positions, see Item 1A, “Risk Factors - Hedging and Risk Management Activities” and Part II, Item 7A, “Quantitative and Qualitative Disclosures about Market Risk - Commodity Price Risks.” Currently, Cleco Power anticipates that its diverse supply options and
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alternative fuel capability, combined with its solid-fuel generation resources, are adequate to meet its fuel needs during any temporary interruption of natural gas supplies.
Fuel Oil Supply
Cleco Power stores fuel oil as an alternative fuel source at its Rodemacher and Teche power stations. The Rodemacher power station has storage capacity for an approximate 95-day supply, and the Teche power station has storage capacity for an approximate 28-day supply. However, in accordance with Cleco Power’s current fuel oil inventory practices, Cleco Power had approximately an 89-day supply of fuel oil stored at its Rodemacher facility and a 16-day supply at its Teche facility at December 31, 2008. During 2008, no fuel oil was purchased or burned.
Sales
Cleco Power’s 2008 and 2007 system peak demands, which occurred on July 28, 2008, and August 14, 2007, were 2,113 MW and 2,216 MW, respectively. Sales and system peak demand are affected by weather and are highest during the summer air-conditioning season. In 2008, Cleco Power experienced above-normal summer weather. In 2007, Cleco Power experienced above-normal summer weather and a mild winter. For information on the effects of future energy sales on Cleco Power’s financial condition, results of operations, and cash flows, see Item 1A, “Risk Factors - Weather Sensitivity” and “- Future Electricity Sales.” For information on the financial effects of seasonal demand on Cleco Power’s quarterly operating results, see Part II, Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 22 - Miscellaneous Financial Information (Unaudited).”
Capacity margin is the net capacity resources (either owned or purchased) less native load demand divided by net capacity resources. Each year, members of the SPP submit forecasted native load demand and the forecasted mix of net capacity resources to meet this demand. Cleco Power’s actual capacity margin of 12.8% in 2008 was slightly above the SPP’s capacity benchmark of 12%. During 2007, Cleco Power’s capacity margin was 6.2%, primarily due to higher than expected native load demand. Cleco Power anticipates a 12.0% capacity margin for 2009 which includes power purchase agreements with Acadia and Bear Energy. For additional information on Cleco Power’s power contracts and its evaluation of other supply options, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Regulatory Matters - Generation RFP.”
Midstream
Summary financial results of the Midstream segment for 2008, 2007, and 2006 are presented below.
As of December 31, 2008, Midstream wholly and directly owned four active limited liability companies that operated mainly in Louisiana.
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Evangeline, which owns and operates a combined-cycle natural gas-fired power plant.
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APH, which owns 50% of Acadia, a combined-cycle natural gas-fired power plant.
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Generation Services, which offers power station operations and maintenance services. Its customers are Evangeline and Acadia.
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CLE Intrastate, which owns a natural gas interconnection that allows Evangeline to access the natural gas supply market.
Effective February 1, 2007, the ownership interests of Midstream’s transmission interconnection facilities, Perryville and Attala, were transferred to Cleco Corporation. Perryville and Attala are no longer included in the financial results of the Midstream segment effective February 1, 2007. In accordance with SFAS No. 131, the net operating results for Midstream for periods prior to February 1, 2007, have been adjusted to reflect this organizational change.
The following table sets forth certain information with respect to Midstream’s operating generating facilities.
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Midstream competes against regional and national companies that own and operate merchant power stations.
Prior to November 2007, Evangeline’s capacity was dedicated to one customer, Williams, which was the counterparty to the Evangeline Tolling Agreement. In November 2007, Williams completed the assignment of its interest in the Evangeline Tolling Agreement to Bear Energy. The terms of the Evangeline Tolling Agreement, set to expire in 2020, were unchanged. The Evangeline Tolling Agreement gives the tolling counterparty the right to own, dispatch, and market all of the electric generation capacity of the respective facility. Under a tolling agreement, the tolling counterparty is responsible for providing its own natural gas to the facility and pays a fixed fee and a variable fee for operating and maintaining the respective facility. In May 2008, JPMorgan Chase & Co. acquired Bear Stearns Companies Inc. In connection with the acquisition, JPMorgan Chase & Co. has guaranteed certain obligations of Bear Stearns Companies Inc.’s subsidiaries, including Bear Energy’s obligations under the Evangeline Tolling Agreement.
Prior to March 2006, Acadia’s capacity also was dedicated to one customer, CES, which was the counterparty to the Calpine Tolling Agreements. In December 2005, the Calpine Debtors filed for protection under Chapter 11 of the Bankruptcy Code and subsequently filed a motion with the Calpine Debtors Bankruptcy Court to reject the Calpine Tolling Agreements. In March 2006, Acadia and CES executed amendments to the Calpine Tolling Agreements, which were approved by the Calpine Debtors Bankruptcy Court, permitting Acadia to suspend its obligations under the agreements. Currently, Acadia’s output is sold through an energy management services agreement with a third party marketer. For additional information on the above tolling agreements and related transactions, risks and uncertainties, see Item 1A, “Risk Factors - Evangeline Plant Performance” and “- Evangeline Tolling Agreement,” and Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Midstream - Significant Factors Affecting Midstream - Earnings are primarily affected by the following factors.” For additional information on the Calpine bankruptcy and the suspension of the Calpine Tolling Agreements, see Part II, Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 20 - Calpine Bankruptcy Settlement.”
CLE Intrastate’s revenue is generated primarily from a monthly reservation fee paid by Evangeline for access to the Columbia Gulf interconnect and from a transportation fee that varies depending on the amount of gas transported through the interconnect for use by Evangeline.
At December 31, 2008, Midstream and its subsidiaries employed 65 people: 62 within Generation Services and 3 at Midstream.
For additional information on Midstream’s operations, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Midstream.”
Customers
No single customer accounted for 10% or more of Cleco’s consolidated revenue or Cleco Power’s revenue in 2008, 2007, or 2006. For additional information regarding Cleco’s sales and revenue, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations.”
Construction and Financing
For information on Cleco’s construction program, financing and related matters, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Cash Generation and Cash Requirements.”
REGULATORY MATTERS, INDUSTRY DEVELOPMENTS, AND FRANCHISES
Rates
Cleco Power’s electric operations are subject to the jurisdiction of the LPSC with respect to retail rates, standards of service, accounting and other matters. Cleco Power also is subject to the jurisdiction of FERC with respect to rates for wholesale service, accounting, interconnections with other utilities, and the transmission of power and reliability. Periodically, Cleco Power has sought and received from both the LPSC and FERC increases in base rates to cover increases in operating costs and costs associated with additions to generation, transmission, and distribution facilities.
Cleco Power’s electric rates include a fuel and purchased power cost adjustment clause that enables it to adjust rates for monthly fluctuations in the cost of fuel and purchased power. Revenue from certain off-system sales to other utilities and energy marketing companies is passed on to customers through a reduction in fuel cost adjustment billing factors. Recovery of fuel adjustment clause costs is subject to refund until monthly approval is received from the LPSC; however, all amounts are subject to a periodic fuel audit by the LPSC. Cleco Power currently has fuel adjustment filings for 2003 through 2008 subject to review. In July 2006, the LPSC began an audit of Cleco Power’s fuel adjustment clause filings for the period January 2003 through December 2004. This review is pending and Cleco Power does not anticipate the LPSC to proceed until the third quarter of 2009. Management is currently unable to predict the timing of the fuel cost audits for the open years 2005 through 2008. Cleco Power could be required to make a refund of previously recorded revenue as a result of these audits, and such refund could result in a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
In July 2006, Cleco Power’s current RSP with the LPSC, which governs its retail regulatory return on equity, was extended with modifications to certain terms until the in-service date of Rodemacher Unit 3, which is expected to be operational in the second half of 2009. During 2006, the LPSC approved the recovery of a portion of the carrying costs of capital associated with the construction of Rodemacher Unit
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3. Also during 2006, the LPSC approved an interim rate increase to recover storm restoration costs incurred by Cleco Power relating to Hurricanes Katrina and Rita. In March 2007, after completing a review of the restoration costs, Cleco Power and the LPSC Staff filed a settlement agreement allowing recovery of $158.0 million, essentially all of Cleco Power’s Hurricanes Katrina and Rita storm costs. The agreement also authorized the issuance of securitized bonds to finance the restoration costs. The collection of a special storm recovery charge from Cleco Power’s customers will securitize the bonds. The LPSC approved the settlement agreement and issued a securitization financing order in September 2007. In March 2008, the securitization financing was completed, collection of the interim surcharge ceased and the right to bill and collect unamortized storm damage costs from customers was sold to Cleco Katrina/Rita, a special purpose, wholly-owned subsidiary of Cleco Power. For additional information about the recovery of storm restoration costs, see Part II, Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 3 - Regulatory Assets and Liabilities - Deferred Storm Restoration Costs - Katrina/Rita.”
For additional information on Cleco Power’s retail and wholesale rates, including Cleco Power’s RSP, see Item 1A, “Risk Factors - Retail Electric Service” and - “Fuel Cost Audits” and Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Regulatory Matters - Retail Rates of Cleco Power,” and - “Wholesale Rates of Cleco.”
Cleco Power’s Rate Case
The LPSC directed Cleco Power to file a full base rate case at least 12 months prior to the expected in-service date of Rodemacher Unit 3. On July 14, 2008, Cleco Power filed a request for a new rate plan with the LPSC to increase its base rates for electricity. Cleco Power is seeking recovery of revenues sufficient to cover the addition of Rodemacher Unit 3 to its existing expense and rate base levels. Although base revenues will increase under Cleco Power’s proposed rate plan, fuel costs and collection of financing charges are expected to decrease. Seven industrial customers have filed interventions in the rate case, which is currently in the discovery phase. At this time, Cleco Power anticipates a settlement of the rate case in the second quarter of 2009. The new rates are expected to be effective upon the commercial operation date of Rodemacher Unit 3.
Franchises
Cleco Power operates under nonexclusive franchise rights granted by governmental units, such as municipalities and parishes (counties), and enforced by state regulation. These franchises are for fixed terms, which may vary from 10 years to 50 years or more. In the past, Cleco Power has been substantially successful in the timely renewal of franchises as each reached the end of its term. Cleco Power’s next municipal franchise expires in 2011.
Renewed Franchises
Cleco Power renewed the following franchise agreements during 2007. No franchises were renewed in 2008.
Other Franchise Matters
On February 13, 2007, the City Council of Eunice voted to accept a city-wide franchise proposal with South Louisiana Electric Membership Cooperative (SLEMCO) a local electric cooperative. The cooperative will now have the opportunity to serve customers city-wide. However, both utilities are required to follow the LPSC 300-foot rule regulation to determine which utility can provide electricity to the customer. In general, if a utility’s distribution system is within 300 feet of the new customer’s meter point, that utility automatically serves the customer. Otherwise, the customer may choose the electricity provider. The LPSC is currently reviewing its “300-foot rule” (Docket No. R-28955). Management is unable to predict the time of completion of this review. This decision is not expected to have a material impact on Cleco Power’s results of operations or financial condition, but may reduce future customer and load growth as both utilities compete for new customers.
In June 2007, SLEMCO entered into a limited franchise agreement with the City of Crowley. Cleco Power also provides electric service to Crowley under an existing franchise agreement. The new agreement allows SLEMCO to compete for new customers in areas of the city that have been annexed by Crowley since 2003. This decision does not have a material impact on Cleco Power’s results of operations or financial condition, but could reduce customer and load growth as both utilities compete for new customers. Cleco Power has not experienced any reduction in customers or load growth since the signing of the limited franchise by SLEMCO.
Historically, Cleco Power has been allowed to recover municipal franchise fees as part of the base rates it charges retail customers. Consequently, franchise fees are recovered from customers both inside and outside a franchised area. In October 2007, the LPSC ordered the billing of franchise fees as a separate line item on customer bills. The decision provided that 50% of the franchise fee would continue to be included in base rates charged to retail customers and 50% of the franchise fee would be included on customer bills as a separate line item, billed only to customers within the franchised area. This decision is not expected to have a material impact on Cleco Power’s results of operations or financial condition.
On May 14, 2008, the Town of Elizabeth entered into a lease/franchise agreement with Cleco Power under which its electrical system will be leased to Cleco Power. The agreement is for 10 years with two 10-year renewal terms. Approximately 225 Cleco Power customers are located in Elizabeth.
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On January 13, 2009, the Coushatta City Council voted to accept the early renewal of its franchise agreement with Cleco Power. The Coushatta agreement was set to expire in November 2010. The renewal term is set for 30 years. Approximately 1,400 Cleco Power customers are located in Coushatta.
Industry Developments
For information on industry developments, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Market Restructuring.”
Wholesale Electric Competition
For a discussion of wholesale electric competition, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Market Restructuring - Wholesale Electric Markets.”
Retail Electric Competition
For a discussion of retail electric competition, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Market Restructuring - Retail Electric Markets.”
Legislative and Regulatory Changes and Matters
Various federal and state legislative and regulatory bodies are considering a number of issues that could shape the future of the electric utility industry. Such issues include, among others:
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passage of the Energy Independence and Security Act of 2007;
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regulation of previously deregulated retail electric markets;
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the ability of electric utilities to recover stranded costs;
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the role of electric utilities, independent power producers and competitive bidding in the purchase, construction and operation of new generating capacity;
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the pricing of transmission service on an electric utility’s transmission system;
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FERC’s assessment of market power and utilities’ ability to buy generation assets;
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mandatory transmission reliability standards;
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the authority of FERC to grant utilities the power of eminent domain;
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increasing requirements for renewable energy sources;
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comprehensive multi-emissions environmental legislation;
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regulation of greenhouse gas emissions;
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FERC’s increased ability to impose financial penalties; and
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the American Recovery and Reinvestment Act of 2009.
The Registrants are unable, at this time, to predict the outcome of such issues or effects on their financial position, results of operations, or cash flows.
For information on certain regulatory matters and regulatory accounting affecting Cleco, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Regulatory Matters.”
ENVIRONMENTAL MATTERS
Environmental Quality
Cleco is subject to federal, state, and local laws and regulations governing the protection of the environment. Violations of these laws and regulations may result in substantial fines and penalties. Cleco has obtained the environmental permits necessary for its operations, and management believes Cleco is in compliance in all material respects with these permits, as well as all applicable environmental laws and regulations. Environmental requirements continue to increase as a result of new legislation, administrative actions, and judicial interpretations. Therefore, the future effects of existing and potential requirements are difficult to determine. Cleco Power may request recovery from its retail customers of its costs to comply with environmental laws and regulations. If revenue relief were to be approved by the LPSC, then Cleco Power’s retail rates could increase. If the LPSC were to deny Cleco Power’s request to recover all or part of its environmental compliance costs, such a decision could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows. Cleco’s capital expenditures related to environmental compliance were $4.6 million during 2008 and are estimated to total $5.1 million in 2009. The following table lists capital expenditures for environmental matters by subsidiary.
The decrease in projected environmental capital expenditures at Cleco Power from 2008 to 2009 primarily relates to the installation of new low NOx burners at the Rodemacher Unit 2 Power Station during 2008. The increase in projected capital expenditures at Evangeline from 2008 to 2009 primarily relates to the installation of a system to remove aquatic vegetation in the lake which cools the circulating water from the generating units at the plant. The installation of this system is expected to be completed during 2009.
Air Quality
The state of Louisiana regulates air emissions from each of Cleco’s generating units through the Air Quality regulations of the LDEQ. In addition, the LDEQ has been delegated authority over and implements certain programs established by the EPA. The LDEQ establishes standards of performance and requires permits for certain generating units in Louisiana. All of Cleco’s generating units are subject to these requirements.
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The federal CAA established a regulatory program to address the effects of acid rain and imposed restrictions on SO2 emissions from certain generating units. The federal CAA requires these generating stations to possess a regulatory “allowance” for each ton of SO2 emitted beginning in the year 2000. The EPA allocates a set number of allowances to each affected unit based on its historic emissions. As of December 31, 2008, Cleco Power and Midstream had sufficient allowances for 2008 operations and expect to have sufficient allowances for 2009 operations under the Acid Rain Program.
The federal CAA required the EPA to revise NOx emission limits for existing coal-fired boilers. In November 1996, the EPA finalized rules lowering the NOx emission rate for certain boilers, which apply to Rodemacher Unit 2 and Dolet Hills. The rules also allowed an “early elect” option to achieve compliance with a less restrictive NOx limit beginning no later than January 1, 1997. Cleco Power exercised this option in December 1996. Early election protected Cleco Power from any further reductions in the NOx permitted emission rate until 2008 when the limit was lowered by 8%. Rodemacher Unit 2 and Dolet Hills have been in compliance with the NOx early election limits since their inception and also were in compliance with the reduced limit in 2008. Cleco Power’s Phase I low NOx burner project was permitted by the LDEQ and installed in 2006 to achieve compliance with the reduced 2008 acid rain permit limits for NOx at Dolet Hills. Rodemacher Unit 2 has achieved compliance with these reduced acid rain NOx limits in its current configuration. With its low NOx burner project completed, Rodemacher Unit 2 is able to achieve compliance by an even greater margin. The additional NOx reductions achieved by the low NOx burner projects may qualify for early reduction credits under the federal Clean Air Interstate Rule (CAIR), which was recently reinstated as discussed below. Significant future reductions in NOx emissions limits may require other capital improvements at one or both of the units.
NOx emissions from the Evangeline and Acadia generating units are within the units’ respective permitted limits, as these units use modern turbine and selective catalytic reduction technology that reduces NOx emissions to low levels.
On March 10, 2005, CAIR was finalized by the EPA. CAIR covered the District of Columbia and 28 eastern states, including Louisiana, and provides a federal framework requiring states to reduce emissions of SO2 and NOx. CAIR called for NOx reductions to begin in the year 2009 and SO2 reductions in 2010. Louisiana promulgated state regulations to incorporate these requirements. The LDEQ chose to remain under the Federal Implementation Plan (FIP) for compliance with CAIR SO2 provisions. It also proposed to follow the FIP for the Annual NOx and Ozone Season NOx trading programs with the exception of the NOx allowance allocation methodology. This rule has been heavily litigated by multiple parties in the case known as North Carolina vs. EPA. On July 11, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated CAIR. On September 24, 2008, the EPA, industry groups and environmental groups filed petitions with the D.C. Circuit Court, requesting a rehearing of North Carolina vs. EPA. On December 23, 2008, the U.S. Court of Appeals for the D.C. Circuit ruled on these petitions filed by the EPA and industry intervenors. The Court granted the EPA’s petition to the extent that the case be remanded without vacature for the agency to conduct further proceedings consistent with the Court’s opinion in the case, and denied the remaining petitions. The Court determined that, notwithstanding the flaws of CAIR, remanding it without vacature was preferable in that it preserved the environmental benefits of the rule. As a result, CAIR went into effect in its entirety on January 1, 2009 and will remain in effect until the EPA re-writes the rule to address the flaws identified by the Court in the initial CAIR rule. The EPA does not have a specified timeframe to complete the new rule, however, Cleco expects it to take from one to two years to complete. At this time, Cleco cannot determine what the new rule requirements will entail. Cleco had previously evaluated potential compliance strategies to meet the emission reductions contemplated by the CAIR regulations. The installation of new low NOx burners and enhancements to the SO2 scrubber at Dolet Hills were expected to be an integral part of meeting the CAIR NOx and SO2 reduction provisions. Likewise, the installation of the new low NOx burners at Rodemacher Unit 2 in 2008 will help meet CAIR NOx reduction requirements. Cleco will rely on its previous compliance strategy to meet the CAIR requirements and also may include additional emission controls, purchase of allowances, or fuel changes to enhance its compliance.
On March 15, 2005, the EPA issued final rules regarding mercury emissions from electric utility boilers. The federal Clean Air Mercury Rule (CAMR) established “standards of performance” limiting mercury emissions from new and existing coal-fired power plants and created a market-based cap-and-trade program. CAMR emissions reductions were to take effect in January 2010. Louisiana adopted the EPA’s federal CAMR regulations by reference and incorporated these requirements in Louisiana’s state regulations. Cleco owns units that would have been subject to CAMR, namely Dolet Hills and Rodemacher Unit 2. However, on February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit in New Jersey v. EPA, vacated both the EPA’s rule delisting coal- and oil-fired electric generating units (EGUs) from regulation under Section 112 of the CAA and the entire CAMR rule. As a result of the court’s action, EGUs are subject to regulation under Section 112, which will require the EPA to promulgate maximum achievable control technology (MACT) standards for hazardous air pollutants for coal- and oil-fired EGUs.
Similar to the CAIR rule, the EPA and other petitioners asked the U.S. Court of Appeals for the D.C. Circuit to rehear the case of New Jersey vs. EPA. On May 20, 2008, the D.C. Circuit court denied the EPA’s and industry intervenors’ petitions for rehearing. On October 17, 2008, the EPA petitioned the Supreme Court for a writ of certiorari to review the judgment of the D.C. Circuit Court of Appeals in the New Jersey case. Among the reasons cited for filing the petition are that the Court of Appeals’ decision effectively divests the EPA of the discretion that Congress conferred on the agency to consider alternative regulatory approaches to combating air pollution from power plants and prevents the EPA from
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reconsidering a listing decision that, under the plain terms of the Act, is not yet a final agency action subject to judicial review. In September 2008, industry intervenors also petitioned the Supreme Court to review the case. On February 6, 2009, the EPA moved to dismiss their motion for Supreme Court review of the New Jersey vs. EPA case. On February 23, 2009, the Supreme Court denied the industry petitioners’ request for a review of the lower court’s decision of the case. As such, CAMR is vacated.
The EPA will have to move forward to set MACT standards for coal- and oil-fired EGUs under Section 112 of the CAA which requires that: 1) new sources must adopt at minimum “the emission control that is achieved in practice by the best controlled similar source, as determined by the Administrator” and 2) existing sources must adopt emission controls equal to the “average emission limitation achieved by the best performing 12 percent of the existing source.” At this time, Cleco anticipates that the EPA would take approximately two years to gather new data and promulgate an updated MACT standard for EGUs and another three years for the regulations to become effective.
On January 7, 2009, the EPA issued guidance directing state permitting authorities to make case-by-case MACT determinations, consistent with the requirements of Section 112(g) of the CAA, for coal- and oil-fired EGUs that began actual construction or reconstruction between March 29, 2005 and March 14, 2008. The EPA issued the guidance in response to the New Jersey decision which left unresolved the question of whether EGUs that began actual construction or reconstruction between March 2005 and March 2008 were subject to case-by-case MACT pursuant to Section 112(g). Rodemacher Unit 3 is a unit that began construction between the dates in question, and was permitted as a “minor source” within the context of what constitutes hazardous air pollutants under Section 112(g) rules. Cleco does not currently believe that case-by-case MACT applies to Rodemacher Unit 3. The LDEQ is ultimately responsible for making a determination regarding the applicability of case-by-case MACT to Rodemacher Unit 3. Should case-by-case MACT apply to Rodemacher Unit 3, there could be impacts on the final capital cost of the unit and/or delays in the construction schedule. Cleco is not able to quantify the potential impact to capital investment, operating costs or construction delay associated with the application of case-by-case MACT standards to Rodemacher Unit 3 at this time.
Congress may consider bills related to climate change during upcoming sessions, such as bills related to mandatory cuts in CO2 and other greenhouse gas (GHG) emissions, renewable portfolio standards, and energy efficiency. All of these types of climate change proposals may potentially affect the electric generating industry. On April 2, 2007, the Supreme Court ruled in Massachusetts v. EPA that CO2 and three other GHGs are air pollutants under the federal CAA. As air pollutants, the Supreme Court’s decision would require the EPA to regulate GHG emissions from new motor vehicles if, in the EPA’s judgment, such GHG emissions may reasonably be anticipated to endanger public health or welfare. Based on the Supreme Court’s decision that GHGs are “air pollutants,” the EPA could decide to use its authority under the CAA to regulate GHGs, including CO2, from motor vehicles and stationary sources such as power plants. Thus, the Supreme Court ruling could possibly lead to the federal regulation of CO2 and other GHG emissions in the upcoming years independent of any climate change bill being considered by Congress. On July 11, 2008, the EPA released an Advance Notice of Proposed Rulemaking (ANPR) discussing the EPA’s efforts with respect to the endangerment determination concerning motor vehicle GHG emissions in light of the Supreme Court’s Massachusetts v. EPA decision. The ANPR also considered how GHG emissions from stationary sources might be regulated under various provisions of the CAA and the potential impacts and effects of doing so. The new presidential administration has indicated that addressing climate change is a high priority and may consider regulating GHGs under the CAA. Cleco will continue to monitor the development of new legislative and regulatory initiatives and requirements relating to climate change and the potential impacts of such developments. At this time, Cleco cannot predict the outcome of the ANPR process, whether the new administration will regulate GHGs under the CAA, any resulting changes to federal regulations, or the impact on Cleco’s operations from any climate change initiatives.
The enactment of federal or state renewable portfolio standards (RPS) mandating the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal, could result in certain changes in Cleco’s business or its competitive position. These changes could include costs for renewable energy credits and capital expenditures for renewable generation resources. RPS legislation has been enacted in many states and the new presidential administration may pursue legislation to create a national RPS. States such as Louisiana that do not have RPS requirements could adopt such requirements in the future or be subject to federal RPS requirements. Cleco is evaluating the impacts of potential RPS legislation on its businesses based on the RPS programs in other states. Cleco will continue to monitor developments related to RPS at the federal and state levels.
On March 12, 2008, the EPA set new National Ambient Air Quality Standards (NAAQS) for Ozone; the new primary 8-hour ozone standard is set at 0.075 parts per million (ppm) and the new secondary standard at a form and level identical to the primary standard. The previous primary and secondary standards were each effectively set at 0.084 ppm. The previous standard was set in 1997 and Louisiana had five parishes in the Baton Rouge area that had not yet attained compliance with the standards. The LDEQ estimates that 21 additional parishes could be in violation of the new standard, including DeSoto Parish, the location of Cleco’s Dolet Hills Power Station. Cleco cannot determine at this time whether DeSoto Parish will ultimately be listed as non-attainment because much work must be done by the LDEQ to make those non-attainment designations. The state must make the initial designations by June 2009, final designations by 2010 and by 2012-2013 promulgate regulations on how Louisiana will
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comply. Since NOx emissions are a precursor to ozone formation, existing fossil fuel fired units located in or near these newly designated ozone non-attainment areas that do not currently utilize best available control technology could be targeted for installation of additional NOx emission controls.
In February 2005, Cleco Power received notices from the EPA requesting information relating to the Rodemacher and Dolet Hills Power Stations. The apparent purpose of the investigation is to determine whether Cleco Power has complied with New Source Review and New Source Performance Standards requirements under the CAA in connection with capital expenditures, modifications, or operational changes made at these facilities. Cleco Power has completed its response to the initial data request. It is unknown at this time whether the EPA will take further action as a result of the information provided by Cleco Power.
On March 19, 2008, Cleco Power received a consolidated compliance order and notice of potential penalty (CO/NOPP) from the LDEQ for alleged violations of the air quality rules at its Dolet Hills and Rodemacher Power Stations. For Dolet Hills, the CO/NOPP alleges that upon a file review conducted on or about February 26, 2008, the LDEQ found that Cleco Power was in violation of conditions in its Title V permit regarding compliance assurance tests to be conducted upon its continuous monitoring systems. Upon review of the LDEQ findings and the Part 75 regulations, Cleco Power contends that the actions taken were allowed under the Part 75 regulations, as well as the Title V permit. In regard to the Rodemacher Power Station violations, the CO/NOPP states that a file review of the Rodemacher facility was conducted on or about September 14, 2007, and that upon the agency’s review of the Quarterly Stack Emissions Reports required under 40 CFR Part 60 submitted by Cleco Power, the LDEQ found that Rodemacher Unit 2 exceeded opacity limits at various times during the second, third and fourth quarters of 2007. On May 15, 2008, Cleco Power and the LDEQ entered into a dispute resolution agreement to give the parties additional time to discuss resolution of this CO/NOPP. On August 18, 2008, Cleco offered to resolve the matter in a settlement agreement. On December 12, 2008, the parties extended the dispute resolution agreement to March 16, 2009. Cleco continues to negotiate a settlement with the LDEQ and anticipates reaching a final agreement by the new deadline. Cleco is unable to determine what the final settlement with the LDEQ will entail.
Water Quality
Cleco has received from the EPA and the LDEQ permits required under the federal Clean Water Act for waste water discharges from its five generating stations. Waste water discharge permits have fixed dates of expiration, and Cleco applies for renewal of these permits within the applicable time periods.
The LDEQ issued a Louisiana Pollutant Discharge Elimination System (LPDES) waste water permit renewal for Evangeline Power Station on June 22, 2006. This waste water permit contains certain additional Copper and Total Dissolved Solids (TDS) permit limitations that Cleco contends are beyond the legal authority of LDEQ to include in the waste water permit. Cleco challenged these permit provisions by filing a de novo review judicial appeal on September 26, 2006, in district court in East Baton Rouge Parish, Louisiana. While litigation has been filed, Cleco actively is engaged with the LDEQ in settlement discussions regarding the appealed provisions of the waste water permit. In December 2008, Cleco filed an application with the LDEQ modifying its LPDES permit to incorporate new Copper and TDS discharge limitations that were agreed to by both parties. Cleco expects to receive the modified water permit with new Copper and TDS limits in the third or fourth quarter of 2009, provided no adverse public comments are received. Until the final permit is received, the filed litigation is still pending and the appealed Copper and TDS permit limitations are stayed. The uncontested portions of the Evangeline waste water permit were effective January 1, 2007.
Section 316(b) of the Clean Water Act regulates potential adverse environmental impacts to all aquatic species due to water intake structures. These regulations establish requirements applicable to the location, design, construction, and capacity of cooling water intake structures. Section 316(b) is applicable to Cleco’s Teche Power Station and Evangeline Power Station. On July 2, 2007, the EPA officially suspended the Phase II, 316(b) rule as a result of a January 2007 decision by the U.S. Court of Appeals for the Second Circuit which largely overturned the EPA’s final Phase II 316(b) rule. The appeals court decision limits or rejects the use of cost effectiveness and cost benefit tests historically recognized by other federal courts. Due to the suspension of the rule, mandatory compliance dates for the completion of studies and assessments will likely be delayed for some time until the EPA can re-write a new rule for Phase II facilities which addresses the court’s concerns. Until the EPA promulgates a replacement Phase II rule, the EPA has indicated that it will ask permit writers to use “Best Professional Judgment” in evaluating permit renewals until a new 316(b) rule is promulgated. In April 2008, the U.S. Supreme Court agreed to hear an appeal of the case with regard to a single issue: whether Section 316(b) of the Clean Water Act, 33 U.S.C. 1326(b), authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. Unless the Second Circuit’s decision is overturned by the Supreme Court, the EPA and the LDEQ could mandate that the next generation of permit renewals, which for applicable Cleco facilities will occur in the 2010-2011 timeframe, include a more expensive, technology-based approach (i.e., modifications to existing intake structures or conversion to cooling tower systems). At this time, it is uncertain which technology option, if any, will be required to be installed on Cleco’s intake structures and the associated costs of those modifications. Cleco anticipates that any new requirements for its affected facilities would be established as the facilities go through the water discharge permit renewal process.
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Solid Waste Disposal
The Solid Waste Division of the LDEQ has adopted a permitting system for the management and disposal of solid waste generated by power stations. Cleco has received all required permits from the LDEQ for the on-site disposal of solid waste from its generating stations. Cleco has renewed the solid waste permits for the existing Rodemacher and Dolet Hills solid waste units and is in the process of upgrading them according to the current Solid Waste Regulations and permit requirements. These upgrades are not expected to result in substantial costs.
Hazardous Waste Generation
Cleco produces certain wastes that are classified as hazardous at its five generating stations and at other locations. Cleco does not treat, store long-term, or dispose of these wastes on-site; therefore, no permits are required. All hazardous wastes produced by Cleco are disposed of at federally permitted hazardous waste disposal sites.
Toxic Substances Control Act (TSCA)
The TSCA directs the EPA to regulate the marketing, disposal, manufacturing, processing, distribution in commerce, and use of PCBs. Cleco may continue to operate equipment containing PCBs under the TSCA. Once the equipment reaches the end of its usefulness, the EPA regulates handling and disposal of the equipment and fluids containing PCBs. Within these regulations, the handling and disposal is allowed only through EPA approved and permitted facilities.
The EPA revised TSCA regulations to require utilities to report data on the manufacture or import of organic compounds every five years. Cleco submitted this information in December 2006 for its applicable facilities.
Toxics Release Inventory (TRI)
The TRI requires an annual report from industrial facilities on about 650 substances that they release into air, water, and land. The TRI ranks companies based on how much of a particular substance they release on a state and parish (county) level. Annual reports are due to the EPA on July 1 following the reporting year-end. Cleco has submitted required TRI reports on its activities, and the TRI rankings are available to the public. The rankings do not result in any federal or state penalties.
Electric and Magnetic Fields (EMFs)
The possibility that exposure to EMFs 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 some public attention. Cleco Power funds scientific research on EMFs through various organizations. To date, there are no definitive results, but research is continuing. Lawsuits alleging that the presence of electric power transmission and distribution lines has an adverse effect on health and/or property values have arisen in several states. Cleco Power is not a party in any lawsuits related to EMFs.
Other
On October 8, 2007, Cleco received a Special Notice for Remedial Investigation and Feasibility Study from the EPA. The special notice requested that Cleco Corporation and Cleco Power, along with many other listed PRPs, enter into negotiations with the EPA for the performance of a Remedial Investigation and Feasibility Study at an area known as the Devil’s Swamp Lake just northwest of Baton Rouge, Louisiana. The EPA has identified Cleco as one of many companies sending PCB wastes for disposal to the site. The Devil’s Swamp Lake site has been proposed to be added to the National Priorities List (NPL) based on the release of PCBs to fisheries and wetlands located on the site. The EPA has yet to make a final determination on whether to add Devil’s Swamp Lake to the NPL. The EPA and a number of PRPs met on January 31, 2008, for an organizational meeting to discuss the background of the site. The PRPs began discussing a potential proposal to the EPA on February 19, 2008. Negotiations among the PRPs and the EPA are ongoing in regard to the remedial investigation and feasibility study at the Devil’s Swamp site, with little progress having been made since the January 2008 meeting. The PRPs alleged to have disposed PCBs at the site have proposed a tentative cost sharing formula with the facility owner to fund the remedial investigation. The response to the proposal has been pending for months. Since this investigation is in the preliminary stages, management is unable to determine whether the costs associated with possible remediation of the facility site will have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
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ITEM 1A.
ITEM 1A. RISK FACTORS
The following risk factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, the Registrants.
Cleco Power’s Rates and Rate Case
The LPSC and FERC regulate the rates that Cleco Power can charge its customers. On July 14, 2008, Cleco Power filed a new rate plan for its retail rates that is expected to go into effect when Rodemacher Unit 3 begins commercial operations. The LPSC could disallow the recovery of material costs or an adequate return on capital.
Cleco Power’s ongoing financial viability depends on its ability to recover its costs from its LPSC-jurisdicational customers in a timely manner through its LPSC-approved rates and its ability to pass through to its FERC customers in rates its FERC-authorized revenue requirements. Cleco Power’s financial viability also depends on its ability to recover in rates an adequate return on capital, including long-term debt and equity. If Cleco Power is unable to recover any material amount of its costs in rates in a timely manner or recover an adequate return on capital, its results of operations, financial condition and cash flows could be materially adversely affected.
Cleco Power’s revenues and earnings are substantially affected by regulatory proceedings known as rate cases. During those cases, the LPSC determines Cleco Power’s rate base, depreciation rates, operation and maintenance costs, and administrative and general costs that Cleco Power may recover from its retail customers through its rates. These proceedings may examine, among other things, the prudence of Cleco Power’s operation and maintenance practices, level of subject expenditures, allowed rates of return, and previously incurred capital expenditures. The LPSC has the authority to disallow costs found not to have been prudently incurred. These regulatory proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or reducing rates. Rate cases generally have long timelines, which may be limited by statute. Decisions are typically subject to appeal, potentially leading to additional uncertainty.
Cleco Power’s current base rates have been extended through the start of Rodemacher Unit 3. On July 14, 2008, Cleco Power filed a rate plan to establish new rates to be effective upon commercial operation of the Rodemacher Unit 3. As part of the new rate plan, Cleco Power has requested a return on equity of 12.25%. Cleco Power’s current base rates allow it the opportunity to earn a maximum regulated return on equity of 11.65%, which is based on a return on equity of 11.25%, with any regulated earnings between 11.25% and 12.25% shared between shareholders and customers in a 40/60 ratio. Seven industrial customers have filed interventions in the rate case, which is currently in the discovery phase. At this time, Cleco Power anticipates a settlement of the rate case in the second quarter of 2009, with new rates effective upon commercial operation of Rodemacher Unit 3. Cleco Power is currently recording AFUDC associated with construction of Rodemacher Unit 3. Once the plant begins commercial operations, Cleco Power will no longer record AFUDC related to Rodemacher Unit 3. Recovery of the Rodemacher Unit 3 investment is the largest component in Cleco Power’s general rate plan that was filed with the LPSC. If the LPSC does not increase Cleco Power’s base rates or denies Cleco Power’s request to recover material costs, including those incurred in the construction of Rodemacher Unit 3, Cleco Power’s results of operations, financial condition, and cash flows could be materially adversely affected. For additional information on Cleco Power’s rate case, see Item 1, “Business - Regulatory Matters, Industry Developments, and Franchises - Rates - Cleco Power’s Rate Case.”
Storm Restoration Costs
The recovery of costs resulting from Hurricanes Gustav and Ike is subject to LPSC review and approval, and recovery of some of the costs could be disallowed.
Restoration costs incurred by Cleco Power from damage caused by Hurricanes Gustav and Ike during the third quarter of 2008 are subject to a prudency review by the LPSC in which Cleco Power will be required to demonstrate that the costs were prudently incurred. Accordingly, Cleco Power may not be able to recover some of the storm costs incurred, which could be material.
The costs will be reviewed by the LPSC as part of Cleco’s pending rate case. If the LPSC were to deny Cleco Power’s request to recover substantial restoration costs incurred, such a decision could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
Rodemacher Unit 3 Construction Costs
The recovery of costs incurred to construct Rodemacher Unit 3 is subject to LPSC review and approval, and some of the costs could be disallowed.
Costs incurred in the construction of Rodemacher Unit 3 are subject to a prudency review by the LPSC. Cleco Power filed a new rate plan with the LPSC on July 14, 2008, seeking to recover the construction costs through its base rates. Cleco Power will be required to demonstrate that the costs incurred to construct Rodemacher Unit 3 are prudently incurred and demonstrate the impact of the operation of the facility on its customers. Accordingly, Cleco Power may not be able to recover some of the costs incurred to construct the facility, which could be substantial.
Furthermore, although the Amended EPC Contract is generally a fixed-price agreement, unforeseen events could result in changes in the scope of the project that may result in a
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delay in the completion of Rodemacher Unit 3 or result in additional costs. It may be more difficult to obtain LPSC approval to recover such additional costs. If the LPSC were to deny Cleco Power’s request to recover substantial costs incurred in the construction of the facility, such a decision could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
Rodemacher Unit 3 Technical Specifications
Cleco Power is exposed to certain risks related to the design, construction and operation of Rodemacher Unit 3. This project has technology risk, fuel supply risk, and general contractor and certain material subcontractor performance risk.
Rodemacher Unit 3 is designed to utilize circulating fluidized bed (CFB) generating technology. Under the Amended EPC Contract, Shaw is liable for liquidated damages for non-performance. However, Cleco Power’s ability to collect any damages for breach is contingent on the demonstration of such damages and on Shaw’s financial abilities. Failure by Shaw to meet its obligations under the Amended EPC Contract could have a material adverse impact on the plant’s efficiency, in-service date, and final cost. The Amended EPC Contract does not protect Cleco Power against force majeure events or design/specification oversight which may result in increased and potentially unrecoverable costs to Cleco Power. Although Cleco Power currently delivers coal via rail to the Rodemacher facility, plans are for Rodemacher Unit 3 to primarily use petroleum coke, which can be delivered most economically via barges on the Mississippi and Red Rivers, requiring a conveyor system which crosses an interstate and local highways. Navigable waterway events such as blockages or low water, or conveyor outages could impact Cleco Power’s ability to transport and deliver fuel to Rodemacher Unit 3.
Global Financial Crisis
The global financial crisis may negatively impact Cleco’s business and financial condition.
The continued credit crisis and related turmoil in the global financial system may have an impact on Cleco’s business and financial condition. Cleco may face significant challenges if conditions in the financial markets do not improve. Cleco’s ability to access the capital markets may be severely restricted at a time when Cleco would like, or need, to do so, which could have a material impact on its ability to fund capital expenditures or debt service or on Cleco’s flexibility to react to changing economic and business conditions. If Cleco Corporation’s or Cleco Power’s credit ratings were to be downgraded by Moody’s or by Standard & Poor’s, Cleco Corporation or Cleco Power, as the case may be, would be required to pay additional fees and higher interest rates under its bank credit and other debt agreements. During 2008, Cleco’s pension plan portfolio experienced significant losses and may experience further losses in the future. The losses, in conjunction with plan funding requirements, could result in
required pension plan contributions significantly higher and earlier than previously anticipated, which could have a material negative impact on Cleco’s results of operations and financial condition. Further, the credit crisis could have a material negative impact on Cleco’s lenders or its customers causing them to fail to meet their obligations to Cleco or to delay payment of such obligations. Additionally, the crisis could lead to reduced electricity usage, which could have a material negative impact on Cleco’s results of operations and financial condition.
Future Electricity Sales
Cleco Power’s future electricity sales and corresponding base revenue and cash flows could be adversely affected by general economic conditions.
General market conditions can negatively impact the businesses of Cleco Power’s industrial customers, resulting in decreased power purchases and lower base revenue. The current U. S. recession could lead to reduced power usage by Cleco Power’s customers. Cleco Power’s largest industrial customers, specifically those who manufacture wood and paper products (who generated base revenue of approximately $24.6 million in 2008), have experienced a downturn in their respective markets. The downturn in residential home construction has caused a significant reduction in the demand and prices for lumber and other wood products. The paper industry has been vulnerable in recent years as a result of a mature market with pressures from overseas manufacturers. Reduced production or the shut down of any of these customers’ facilities could substantially reduce Cleco Power’s base revenue.
The high cost of energy, in general, has become problematic in many industries and has increased interest by industrial customers in switching to alternative sources of energy, including on-site power generation. Also, retail customers may consume less electricity due to increased conservation efforts or increased electric usage efficiency.
Fuel Cost Audits
The LPSC conducts fuel audits that could result in Cleco Power making substantial refunds of previously recorded revenue.
Generally, fuel and purchased power expenses are recovered through the LPSC-established fuel adjustment clause, which enables Cleco Power to pass on to its customers substantially all such charges. Recovery of fuel adjustment clause costs is subject to a periodic fuel audit by the LPSC.
Cleco Power currently has fuel adjustment clause filings for 2003 through 2008 subject to review. In July 2006, the LPSC commenced a periodic fuel audit of Cleco Power’s fuel adjustment clause filings for January 2003 through December 2004. This review is pending and Cleco Power does not anticipate the LPSC to proceed until the third quarter of 2009. Management is currently unable to predict the timing of the fuel cost audits for the open years 2005 through 2008. Cleco Power could be required to make a substantial refund of
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previously recorded revenue as a result of these audits, and such refund could result in a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows. The most recent audit completed by the LPSC covered 2001 and 2002 and resulted in a refund of $16.0 million to Cleco Power’s retail customers in the first quarter of 2005.
Hedging and Risk Management Activities
Cleco Power is subject to market risk associated with economic hedges relating to open natural gas contracts. Cleco has risk management policies which cannot eliminate all risk involved in its energy commodity activities.
Cleco Power utilizes economic hedges to mitigate the risks associated with a fixed-price wholesale power contract that is not included in the fuel adjustment clause. Any realized gain or loss attributable to these hedges is recorded on the income statement as a component of operating revenue, net. Accordingly, changes in the market value of these hedging arrangements caused by natural gas price volatility will impact the Registrants’ results of operations, financial condition, and cash flows.
Cleco Power also has entered into economic hedge positions to mitigate the volatility in fuel costs passed through to its retail customers. When these positions close, actual gains or losses are deferred and included in the fuel adjustment clause in the month the physical contract settles. However, recovery of any of these fuel adjustment clause costs is subject to, and may be disallowed as part of, a prudency review or a periodic fuel audit conducted by the LPSC.
Cleco Power manages its exposure to energy commodity activities by establishing and enforcing risk limits and risk management procedures. These risk limits and risk management procedures may not be as effective as planned, particularly if intentional misconduct is involved, and cannot eliminate all risk associated with these activities.
Purchased Power
Nonperformance of Cleco Power’s power purchase agreements and transmission constraints could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
Cleco Power does not supply all of its customers’ power from the generation facilities it owns and must purchase additional energy and capacity from the wholesale power market in order to meet customers’ demands. During 2008, Cleco Power met approximately 55.7% of its energy needs with purchased power. A 500-MW power purchase agreement with Bear Energy, which expires in 2009, and other short- and long-term power purchase agreements provided approximately 40.4% of Cleco Power’s capacity needs in 2008. Cleco Power plans to meet its 2009 energy and capacity needs with the Bear Energy 500-MW contract; a 235-MW contract with Acadia Power Partners; a 20-MW long-term contract with Sabine River Authority; and a 41-MW wholesale power contract with the city of Natchitoches. On January 6, 2009, Cleco issued a RFP for a minimum capacity amount of 50 MW up to 200 MW in order to serve additional load. On February 9, 2009, a winning bidder was selected. Cleco Power is currently negotiating the terms of the contract and anticipates signing a power purchase agreement by the end of the first quarter of 2009. The requested products for supply will start April 1, 2009 and continue through October 31, 2009. If any provider of additional energy or capacity does not perform under their respective contracts, Cleco Power would have to replace these supply sources with alternative market sources, the terms of which may not be as favorable and could increase the ultimate cost of power to Cleco Power’s customers.
Because of Cleco Power’s location on the transmission grid, Cleco Power relies on two main suppliers of electric transmission when accessing external power markets. At times, physical constraints limit the amount of purchased power these transmission providers can deliver into Cleco Power’s service territory, which in turn can affect capacity or power purchases under long-term contracts, as well as spot market power purchases. If the amount of purchased power actually delivered into Cleco’s transmission system were less than the amount of power contracted for delivery, Cleco Power may rely on its own generation facilities to meet customer demand. Cleco Power’s incremental generation cost at that time could be higher than the cost to purchase power from the wholesale power market, thereby increasing its customers’ ultimate cost. In addition, the LPSC may not allow Cleco Power to recover part or all of its incremental generation cost, which could be substantial.
Commodity Prices
Cleco Power is subject to the fluctuation in the market prices of various commodities which may increase the cost of producing power.
Cleco Power purchases coal, lignite, natural gas and fuel oil under long-term contracts and on the spot market. Historically, the markets for oil, natural gas and coal have been volatile and are likely to remain volatile in the future. Cleco Power’s retail rates include a fuel adjustment clause that enables it to adjust rates for monthly fluctuations in the cost of fuel and purchased power. However, recovery of any of these fuel adjustment clause costs is subject to, and may be disallowed as part of, a prudency review or a periodic fuel audit conducted by the LPSC.
Evangeline Plant Performance
Evangeline has certain plant performance obligations defined in its tolling agreement. Failure to perform these obligations could expose Evangeline to adverse financial penalties.
Performance requirements in the Evangeline tolling agreement include, but are not limited to, maintaining plant performance characteristics such as heat rate and demonstrated generation capacity and maintaining specified availability levels with a combination of plant availability and replacement power.
CLECO CORPORATION
CLECO POWER
FORM 10-K
Obligations under the tolling agreement include, but are not limited to, maintaining various types of insurance, maintaining power and natural gas metering equipment, and paying scheduled interest and principal payments on debt. In addition to the performance obligations by Evangeline, there are a guarantee and various commitments required by Cleco Corporation. If Evangeline fails to operate within specified requirements, the facility may purchase replacement power on the open market and provide it to the tolling counterparty in order to meet contractual performance specifications. Providing replacement power maintains availability levels, but exposes Evangeline to power commodity price volatility and transmission constraints. If availability targets under the tolling agreement are not met and economical purchased power and transmission are not available, Cleco Corporation’s results of operations, financial condition, and cash flows could be materially adversely affected.
Cleco Power Generation Facilities
Cleco Power’s generation facilities are susceptible to unplanned outages, significant maintenance requirements and interruption of fuel deliveries.
The operation of power generation facilities involves many risks, including breakdown or failure of equipment, fuel supply interruption and performance below expected levels of output or efficiency. Some of Cleco Power’s facilities were originally constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant expenditures to operate at peak efficiency or availability. If Cleco Power fails to make adequate expenditures for equipment maintenance, Cleco Power risks incurring more frequent unplanned outages, higher than anticipated operating and maintenance expenditures, increased fuel or power purchase costs, and potentially the loss of revenue related to competitive opportunities.
Cleco Power’s generating facilities are fueled primarily by coal, natural gas, and lignite. The deliverability of these fuel sources may be constrained due to such factors as higher demand, production shortages, weather-related disturbances or lack of transportation capacity. If the suppliers are unable to deliver the contracted volume of fuel, Cleco Power would have to replace any deficiency with alternative sources, which may not be as favorable and could increase the ultimate cost of fuel to customers. Fuel and purchased power expenses are recovered from customers through the fuel adjustment clause, which is subject to refund until either a prudency review or a periodic fuel audit is conducted by the LPSC.
ERO
In 2005, FERC’s authority was expanded to include the establishment and enforcement of mandatory reliability standards on the transmission system, as well as the capacity to impose fines and civil penalties on those who fail to comply with those standards.
The Energy Policy Act of 2005 authorizes the creation of an ERO with authority to establish and enforce mandatory reliability standards, subject to FERC approval, for users of the nation’s transmission system. In July 2006, FERC named NERC as the ERO. FERC has approved more than 95 reliability standards developed by NERC. A final order was issued by FERC in March 2007, and in June 2007, FERC began enforcing compliance with these standards. New standards are continually being developed and existing standards will be modified as needed.
As these standards continue to be adopted and modified, they may impose additional compliance requirements on Cleco Power, Acadia, and Evangeline operations which may result in an increase in capital expenditures and operating expenses. Failure to comply with the reliability standards approved by FERC can result in the imposition of fines and civil penalties.
Environmental Compliance
Cleco’s costs of compliance with environmental laws and regulations are significant. The costs of compliance with new environmental laws and regulations, as well as the incurrence of incremental environmental liabilities, could be significant to the Registrants.
Cleco is subject to extensive environmental oversight by federal, state, and local authorities and is required to comply with numerous environmental laws and regulations related to air quality, water quality, waste management, natural resources, and health and safety. Cleco also is required to obtain and comply with numerous governmental permits in operating its facilities. Existing environmental laws, regulations and permits could be revised or reinterpreted, and new laws and regulations could be adopted or become applicable to Cleco. For example, Congress is considering climate change legislation that, if ultimately enacted, could impose a cap on CO2 emissions by electric generating units such as Cleco and subject electric generating units to an emissions allowance-based trading system. Cleco may incur significant capital expenditures or additional operating costs to comply with these revisions, reinterpretations, and new requirements. If Cleco fails to comply with these revisions, reinterpretations, and requirements, it could be subject to civil or criminal liabilities and fines or may be forced to shut down or reduce productions from its facilities.
Environmental advocacy groups, states, other organizations, some government agencies, and the new presidential administration are focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Future changes in environmental regulations governing CO2 could make some of Cleco’s electric generating units uneconomical to maintain or operate. In addition, any legal obligation that would require Cleco to substantially reduce its CO2 emissions beyond present levels could require extensive mitigation efforts and could raise uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation facilities.
Cleco Power may request recovery from its retail customers of its costs to comply with new environmental laws and
CLECO CORPORATION
CLECO POWER
FORM 10-K
regulations. If revenue relief were to be approved by the LPSC, then Cleco Power’s retail rates could increase. If the LPSC were to deny Cleco Power’s request to recover all or part of its environmental compliance costs, such an adverse decision could have a material effect on the Registrants’ results of operations, financial condition, and cash flows.
Regulatory Compliance
Cleco operates in a highly regulated environment and adverse regulatory decisions or changes in applicable regulations could have a material adverse effect on the Registrants’ businesses or result in significant additional costs.
Cleco’s business is subject to extensive federal, state, and local energy, environmental and other laws and regulations. The LPSC regulates Cleco’s retail operations, and FERC regulates Cleco’s wholesale operations. The construction, planning, and siting of Cleco’s power plants and transmission lines also are subject to the jurisdiction of the LPSC and FERC. Additional regulatory authorities have jurisdiction over some of Cleco’s operations and construction projects including the EPA, the United States Bureau of Land Management, the United States Fish and Wildlife Services, the United States Department of Energy, the United States Army Corps of Engineers, the United States Department of Homeland Security, the Occupational Safety and Health Administration, the United States Department of Transportation, the LDEQ, the Louisiana Department of Health and Hospitals, the Louisiana Department of Natural Resources, the Louisiana Department of Public Safety, regional water quality boards, and various local regulatory districts.
Cleco must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective orders. Should Cleco be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on Cleco, Cleco’s business could be adversely affected. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to Cleco or Cleco’s facilities in a manner that may have a detrimental effect on the Registrants’ business or result in significant additional costs because of Cleco’s need to comply with those requirements.
Weather Sensitivity
The operating results of Cleco Power are affected by weather conditions and may fluctuate on a seasonal and quarterly basis.
Weather conditions directly influence the demand for electricity, particularly kWh sales to residential customers. In Cleco Power’s service territory, demand for power peaks during the hot summer months. As a result, Cleco Power’s financial results may fluctuate on a seasonal basis. In addition, Cleco Power has sold less power, and consequently earned less income, when weather conditions were milder. Unusually mild weather in the future could adversely impact the Registrants’ results of operations, financial condition, and cash flows.
Severe weather, including hurricanes and winter storms, can be destructive, causing outages and property damage that can potentially result in additional expenses and lower revenue.
Termination of the Rodemacher Unit 3 Project or the Amended EPC Contract
The abandonment of the Rodemacher Unit 3 project or termination of the Amended EPC Contract could result in unrecoverable costs.
Cleco Power may determine that its decision to construct, own and operate Rodemacher Unit 3 is no longer justified due to changes in circumstances or for other reasons. If Cleco Power decided to abandon the project, the LPSC may not allow Cleco Power to recover some or all of its incurred costs. The Amended EPC Contract allows Cleco Power to terminate the agreement at its sole discretion, but exercise of this termination right would require Cleco Power to pay termination costs, subject to specified limitations. At December 31, 2008, the maximum termination costs would have been $761.7 million payable to Shaw. Termination costs under the Amended EPC Contract could result in a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
Retail Electric Service
Cleco Power’s retail electric rates and business practices are regulated by the LPSC.
Cleco Power’s retail rates for residential, commercial, and industrial customers and other retail sales are regulated by the LPSC, which conducts an annual review of Cleco Power’s earnings and regulatory return on equity. Cleco Power files annual monitoring reports with the LPSC for 12-month periods ended September 30. Cleco Power could be required to make a substantial refund of previously recorded revenue as a result of the LPSC review, and such refund could result in a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
Cleco Credit Ratings
A downgrade in Cleco Corporation’s or Cleco Power’s credit rating could result in an increase in their respective borrowing costs and a reduced pool of potential investors and funding sources.
While the senior unsecured debt ratings of Cleco Corporation and Cleco Power are currently investment grade, in recent years such ratings have been downgraded or put on negative watch by Moody’s and Standard & Poor’s. Cleco Corporation or Cleco Power cannot assure that its current debt ratings will remain in effect for any given period of time or that one or more of its debt ratings will not be lowered or withdrawn entirely by a rating agency. Credit ratings are not recommendations to buy, sell, or hold securities and each rating should be evaluated independently of any other rating. If Moody’s or Standard & Poor’s were to downgrade Cleco Corporation or Cleco Power’s long-term ratings, particularly below investment
CLECO CORPORATION
CLECO POWER
FORM 10-K
grade, the value of their debt securities would likely be adversely affected, and the borrowing cost of Cleco Corporation or Cleco Power would likely increase. In addition, Cleco Corporation or Cleco Power would likely be required to pay higher interest rates in future debt financings and be subject to more onerous debt covenants, and its pool of potential investors and funding sources could decrease.
Holding Company
Cleco Corporation is a holding company, and its ability to meet its debt obligations and pay dividends on its common stock is dependent on the cash generated by its subsidiaries.
Cleco Corporation is a holding company and conducts its operations primarily through its subsidiaries. Substantially all of Cleco’s consolidated assets are held by its subsidiaries. Accordingly, Cleco’s ability to meet its debt obligations and to pay dividends on its common stock is largely dependent upon the cash generated by these subsidiaries. Cleco’s subsidiaries are separate and distinct entities and have no obligation to pay any amounts due on Cleco’s debt or to make any funds available for such payment. In addition, Cleco’s subsidiaries’ ability to make dividend payments or other distributions to Cleco may be restricted by their obligations to holders of their outstanding securities and to other general business creditors. Moreover, Cleco Power, Cleco’s principal subsidiary, is subject to regulation by the LPSC, which may impose limits on the amount of dividends that Cleco Power may pay Cleco Corporation.
Evangeline Tolling Agreement
Failure by JPMorgan Chase & Co. to fulfill its guarantee obligations under the Evangeline Tolling Agreement could have a material adverse effect on Cleco’s results of operations, financial condition, and cash flows.
In May 2008, JPMorgan Chase & Co. acquired Bear Stearns Companies Inc. In connection with the acquisition, JPMorgan Chase & Co. has guaranteed certain obligations of Bear Stearns Companies Inc.’s subsidiaries, including Bear Energy’s obligations under the Evangeline Tolling Agreement. If JPMorgan Chase & Co. or any successor or assignee were to fail to perform its payment obligations, such failure could have a material adverse effect on Cleco Corporation’s results of operations, financial condition, and cash flows for the following reasons, among others:
§
If such failure to perform constituted a default under the tolling agreement, the holders of the Evangeline bonds would have the right to declare the outstanding principal amount ($168.9 million at December 31, 2008) and interest to be immediately due and payable, which could result in:
o
Cleco’s seeking to refinance the bonds, the terms of which may be less favorable than existing terms;
o
Cleco’s causing Evangeline to seek protection under federal bankruptcy laws; or
o
the trustee of the bonds foreclosing on the mortgage and assuming ownership of the Evangeline plant;
§
Cleco may not be able to enter into agreements in replacement of the Evangeline Tolling Agreement on terms as favorable as that agreement or at all;
§
Cleco’s equity investment in Evangeline may be impaired, requiring a write-down to its fair market value, which could be substantial; and
§
Cleco’s credit ratings could be downgraded, which would increase borrowing costs and limit sources of financing.
Evangeline and Acadia Generation Facilities
Evangeline’s and Acadia’s generation facilities are susceptible to unplanned outages, significant maintenance requirements, interruption of fuel deliveries, and transmission constraints.
The operation of power generation facilities involves many risks, including breakdown or failure of equipment, fuel interruption, and performance below expected levels of output or efficiency. If adequate expenditures for equipment maintenance are not made, a facility may incur more frequent unplanned outages, higher than anticipated operating and maintenance expenditures, increased fuel costs, and potentially the loss of revenue related to competitive opportunities.
Evangeline’s and Acadia’s generating facilities are fueled by natural gas. The deliverability of this fuel source may be constrained due to such factors as higher demand, production shortages, weather-related disturbances or lack of transportation capacity.
Because of Acadia’s location on the transmission grid, Acadia relies on two main suppliers of electric transmission when accessing external power markets. However, at times, physical constraints limit the amount of power these transmission providers can deliver.
CLECO CORPORATION
CLECO POWER
FORM 10-K
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
CLECO
Electric Transmission Substations
As of December 31, 2008, Cleco Corporation owned one active transmission substation in Louisiana and one active transmission substation in Mississippi.
CLECO POWER
All of Cleco Power’s electric generating stations and all other electric operating properties are located in the state of Louisiana. Cleco Power considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes. For information on Cleco Power’s generating facilities, see Item 1, “Business - Operations - Cleco Power - Power Generation.”
Electric Generating Stations
As of December 31, 2008, Cleco Power either owned or had an ownership interest in three steam electric generating stations and one gas turbine with a combined name plate capacity of 1,359 MW, and a combined electric net generating capacity of 1,318 MW. The net generating capacity is the result of capacity testing performed between June and September 2007, as required by NERC. This amount reflects the maximum production capacity these units can sustain over a specified period of time. For additional information on Cleco Power’s generating facilities, see Item 1, “Business - Operations - Cleco Power - Power Generation.”
Electric Substations
As of December 31, 2008, Cleco Power owned 71 active transmission substations and 223 active distribution substations.
Electric Lines
As of December 31, 2008, Cleco Power’s transmission system consisted of approximately 67 circuit miles of 500-kiloVolt (kV) lines; 464 circuit miles of 230-kV lines; 662 circuit miles of 138 kV lines; and 21 circuit miles of 69-kV lines. Cleco Power’s distribution system consisted of approximately 3,446 circuit miles of 34.5-kV lines and 8,043 circuit miles of other lines.
General Properties
Cleco Power owns various properties throughout Louisiana, which include a headquarters office building, regional offices, service centers, telecommunications equipment, and other general-purpose facilities.
Title
Cleco Power’s 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 Cleco Power’s property, plant and equipment is subject to a lien of Cleco Power’s Indenture of Mortgage, which does not impair the use of such properties in the operation of its business. As of December 31, 2008, no obligations were outstanding under the Indenture of Mortgage.
MIDSTREAM
Midstream considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes. For information on Midstream’s generating facilities, see Item 1, “Business - Operations - Midstream.”
Electric Generation
As of December 31, 2008, Midstream owned one steam electric generating station, Evangeline, and had a 50% ownership interest in an additional station, Acadia, both located in Louisiana. For additional information on Midstream’s generating facilities, see Item 1, “Business - Operations - Midstream.”
Title
Midstream’s assets are owned in fee, including Midstream’s portion of Acadia. Evangeline is subject to a lien securing obligations under an Indenture of Mortgage, which does not impair the use of such properties in the operation of its business.
CLECO CORPORATION
CLECO POWER
FORM 10-K
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
CLECO
For information on legal proceedings affecting Cleco, see Part I, Item I, “Business - Environmental Matters - Environmental Quality - Water Quality” and “- Air Quality” and Part II, Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 15 - Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees - Litigation.”
CLECO POWER
For information on legal proceedings affecting Cleco Power, see Part II, Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 15 - Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees - Litigation.”
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
CLECO
There were no matters submitted to a vote of security holders of Cleco Corporation during the fourth quarter of 2008.
CLECO POWER
The information called for by Item 4 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
CLECO CORPORATION
CLECO POWER
FORM 10-K
Board of Directors of Cleco
The names of the members of the Board of Directors of Cleco, their ages, dates of election, employment history and committee assignments as of December 31, 2008, are included below. The term of each directorship is three years, and directors are divided among three classes. The terms of the three classes are staggered in a manner so that only one class is elected by the shareholders annually.
NAME OF DIRECTOR
AGES AS OF DECEMBER 31, 2008
Sherian G. Cadoria
Age 68; Elected 1993
Brigadier General, U.S. Army (retired)
Retired President, Cadoria Speaker and Consultancy Service, Mansura, LA
Member of the Audit, Nominating/Governance and Qualified Legal Compliance committees
Richard B. Crowell
Age 70; Elected 1997
Partner, law firm of Crowell & Owens, Alexandria, LA
Member of the Audit, Nominating/Governance and Qualified Legal Compliance committees
J. Patrick Garrett
Age 65; Elected 1981
Retired President and Chief Executive Officer, Windsor Food Company, Ltd., Houston, TX
Chairman of the Board and chairman of the Executive, Nominating/Governance and Qualified Legal Compliance committees
Elton R. King
Age 62; Elected 1999
Retired President of network and carrier services group, BellSouth Telecommunications, Inc., Atlanta, GA. Also retired president and Chief Executive Officer of Visual Networks, Inc.
Member of the Compensation and Finance committees
Logan W. Kruger
Age 58; Elected 2008
President, Chief Executive Officer and Director of Century Aluminum Company, Monterey, CA since December 2005. Executive Vice President of Technical Services, Inco Limited from September 2003 to September 2005; President, Inco Asia Pacific from September 2005 to November 2005.
Member of the Audit and Compensation committees
Michael H. Madison
Age 60; Elected 2005
President and Chief Executive Officer, Cleco Corporation, Pineville, LA
Member of the Executive Committee
William L. Marks
Age 65; Elected 2001
Retired Chairman and Chief Executive Officer, Whitney Holding Corporation and Whitney National Bank, New Orleans, LA
Chairman of the Finance Committee and member of the Compensation and Executive committees
Robert T. Ratcliff Sr.
Age 66; Elected 1993
Chairman, President and Chief Executive Officer, Ratcliff Construction Company, LLC, Alexandria, LA
Member of the Audit and Finance committees
William H. Walker Jr.
Age 63; Elected 1996
Retired Chairman, Howard Weil, Inc., New Orleans, LA
Chairman of the Compensation Committee and member of the Executive and Finance committees
W. Larry Westbrook
Age 69; Elected 2003
Retired Chief Financial Officer and Senior Risk Officer of Southern Company, Atlanta, GA
Chairman of the Audit Committee and member of the Compensation, Executive and Finance committees
CLECO CORPORATION
CLECO POWER
FORM 10-K
Executive Officers of Cleco
The names of the executive officers of Cleco and certain subsidiaries, their positions held, five-year employment history, ages, and years of service as of December 31, 2008, are presented below. Executive officers are appointed annually to serve for the ensuing year or until their successors have been appointed.
CLECO CORPORATION
CLECO POWER
FORM 10-K
On January 28, 2004, Perryville entered into an agreement to sell its 718-MW power plant to Entergy Louisiana. As part of the sales process, Perryville and PEH filed voluntary petitions in the Perryville and PEH Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. Ms. Samil and Mr. Fontenot were managers of Perryville and/or PEH within the two years preceding the voluntary bankruptcy filing.
CLECO CORPORATION
CLECO POWER
FORM 10-K
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND CLECO CORPORATION’S PURCHASES OF EQUITY SECURITIES
CLECO CORPORATION
Cleco Corporation’s common stock is listed for trading on the New York Stock Exchange (NYSE). For information on the high and low sales prices for Cleco Corporation’s common stock as reported on the NYSE Composite Tape and dividends paid per share during each calendar quarter of 2008 and 2007, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 22 - Miscellaneous Financial Information (Unaudited).” During the year ended December 31, 2008, none of Cleco Corporation’s equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of Cleco Corporation or any of its “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934. For information on Cleco Corporation’s common stock repurchase program, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 7 - Common Stock - Common Stock Repurchase Program.”
Subject to the prior rights of the holders of the respective series of Cleco Corporation’s preferred stock, such dividends as determined by the Board of Directors of Cleco Corporation may be declared and paid on the common stock from time to time out of funds legally available. The provisions of Cleco Corporation’s charter applicable to preferred stock and certain provisions contained in the debt instruments of Cleco under certain circumstances restrict the amount of retained earnings available for the payment of dividends by Cleco Corporation. The most restrictive covenant, which is in Cleco Corporation’s credit facility, requires Cleco Corporation’s total indebtedness to be less than or equal to 65% of total capitalization. At December 31, 2008, approximately $431.2 million of retained earnings were unrestricted.
On January 30, 2009, Cleco Corporation’s Board of Directors declared a quarterly dividend of $0.225 per share payable on February 16, 2009, to common shareholders of record on February 9, 2009.
As of January 30, 2009, there were 6,929 holders of record of Cleco Corporation’s common stock, and the closing price of Cleco Corporation’s common stock as reported on the NYSE Composite Tape was $22.85 per share.
CLECO POWER
There is no market for Cleco Power’s membership interests. All of Cleco Power’s outstanding membership interests are owned by Cleco Corporation. Distributions on Cleco Power’s membership interests are paid when and if declared by Cleco Power’s Board of Managers. Any future distributions also may be restricted by any credit or loan agreements that Cleco Power may enter into from time to time.
Some provisions in Cleco Power’s debt instruments restrict the amount of equity available for distribution to Cleco Corporation by Cleco Power under specified circumstances. The most restrictive covenant requires Cleco Power’s total indebtedness to be less than or equal to 65% of total capitalization. At December 31, 2008, approximately $320.3 million of member’s equity was unrestricted.
There were no distributions from Cleco Power to Cleco Corporation during 2007 and 2008.
Cleco Corporation made no equity contributions to Cleco Power in 2008. During 2007, Cleco Corporation made $85.0 million of equity contributions to Cleco Power.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
CLECO
The information set forth below should be read in conjunction with the Consolidated Financial Statements and the related Notes in Item 8, “Financial Statements and Supplementary Data.”
In accordance with FIN 46R, effective March 31, 2004, Cleco deconsolidated Evangeline from its consolidated financial statements and began reporting its investment in Evangeline on the equity method of accounting. As a result, the assets and liabilities of Evangeline no longer are reported on Cleco Corporation’s Consolidated Balance Sheets but instead are represented by one line item corresponding to Cleco’s equity investment in Evangeline. Effective April 1, 2004, Evangeline’s revenue and expenses (excluding income taxes) are netted and reported as equity income from investees on Cleco Corporation’s Consolidated Statements of Income. For additional information on the financial results of Evangeline, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees.”
Perryville and PEH were deconsolidated from Cleco in connection with their bankruptcy filings, and no income or loss associated with those subsidiaries was recognized in Midstream’s consolidated financial statements subsequent to the bankruptcy filing on January 28, 2004. On October 11, 2005, an order confirming PEH and Perryville’s plan of reorganization became final. In accordance with FIN 46R, Cleco recorded its investment in Perryville on the equity method of accounting. In accordance with APB Opinion No. 18, since PEH and Perryville had a negative cost basis and incurred losses for 2004 and the first and second quarters of 2005, PEH and Perryville were not to be reflected in Cleco Corporation’s Consolidated Statements of Income until such time as PEH and Perryville had sufficient income to exceed their
CLECO CORPORATION
CLECO POWER
FORM 10-K
negative cost basis and cumulative losses. In the third quarter of 2005, Perryville recognized earnings sufficient to exceed PEH’s and Perryville’s initial negative cost basis and cumulative losses incurred after January 28, 2004. The previous financial results of Perryville and PEH were reintegrated with Cleco’s consolidated financial results effective in the third quarter of 2005.
Cleco’s adoption of SFAS No. 123(R) on January 1, 2006, impacted Cleco’s consolidated financial results for 2008, 2007, and 2006 as compared to prior years. Cleco’s adoption of SFAS No. 158 on December 31, 2006, impacted Cleco’s consolidated financial position as of December 31, 2008, 2007, and 2006 as compared to prior years. For additional information regarding the adoption of SFAS No. 123(R) and SFAS No. 158, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies - Recent Accounting Standards.”
Cleco’s consolidated financial results for 2007 included the settlement of Acadia’s pre-petition unsecured claims against CES and Calpine and amounts received by APH relating to Cajun’s purchase of CAH’s 50% equity ownership interest in Acadia, offset by a pre-tax impairment loss. For additional information, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 20 - Calpine Bankruptcy Settlement.”
Cleco’s adoption of FIN 48 on January 1, 2007, impacted Cleco’s consolidated financial results for 2008 and 2007 as compared to prior years. For additional information regarding the adoption of FIN 48, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies - Recent Accounting Standards.”
Five-Year Selected Financial Data
CLECO POWER
The information called for by Item 6 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(a) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
CLECO CORPORATION
CLECO POWER
FORM 10-K
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Cleco is a regional energy services holding company that conducts substantially all of its business operations through its two primary subsidiaries:
§
Cleco Power, an integrated electric utility services company regulated by the LPSC, FERC, and other regulators, which serves approximately 276,000 customers across Louisiana and also engages in energy management activities; and
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Midstream, a merchant energy company regulated by FERC, which owns and operates a merchant power plant (Evangeline). Midstream also owns a 50 percent interest in a merchant power plant (Acadia) and operates the plant on behalf of its partner.
For information on Cleco’s affiliated companies and the services each company provides to other affiliates, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 17 - Affiliate Transactions.”
Recent market conditions have limited the availability and have increased the costs of capital for many companies. The inability to raise capital on favorable terms could negatively affect Cleco Corporation’s and Cleco Power’s ability to maintain and expand its businesses. After assessing the current operating performance, liquidity, and credit ratings of Cleco, management believes that it will have access to the capital markets at prevailing market rates for companies with comparable credit ratings.
While management believes that Cleco remains a strong company, Cleco continues to focus on several challenges and factors that could affect its results of operations and financial condition in the near term.
Cleco Power
Many factors affect Cleco Power’s primary business of selling electricity. These factors include the presence of a stable regulatory environment, which can impact cost recovery and return on equity, as well as the recovery of costs related to growing energy demand and rising fuel prices; the ability to increase energy sales while containing costs; and the ability to meet increasingly stringent regulatory and environmental standards.
As part of a plan to diversify its fuel mix, combat rising fuel prices and resolve its long-term generation capacity needs, Cleco Power began constructing a 600-MW solid-fuel generating unit at its Rodemacher power plant in May 2006. When complete, Rodemacher Unit 3 will meet a portion of the utility’s power supply needs and help stabilize customer fuel costs. The project’s capital cost, including carrying costs during construction, is estimated at $1.0 billion. Cleco Power anticipates the plant will be substantially complete and operational in the second half of 2009. Cleco Power’s current base rates have been extended through the commercial operation of Rodemacher Unit 3.
On July 14, 2008, Cleco Power filed a rate plan to establish new rates to be effective upon commercial operation of Rodemacher Unit 3. As part of the new rate plan, Cleco Power has requested a return on equity of 12.25%. Cleco Power’s current base rates allow it the opportunity to earn a maximum regulated return on equity of 11.65%, which is based on a return on equity of 11.25%, with any regulated earnings between 11.25% and 12.25% shared between shareholders and customers in a 40/60 ratio. Cleco Power is currently recording AFUDC associated with construction of Rodemacher Unit 3. Once the unit begins commercial operations, Cleco Power will no longer record AFUDC related to Rodemacher Unit 3. Recovery of the Rodemacher Unit 3 investment is the largest component in Cleco Power’s new rate plan proposal. If the LPSC does not increase Cleco Power’s base rates or denies Cleco Power’s request to recover costs incurred in the construction of Rodemacher Unit 3, Cleco Power’s results of operations, financial condition, and cash flows could be materially adversely affected. For additional information, see Part I, Item 1, Business - Regulatory Matters, Industry Developments, and Franchises - Rates - Cleco Power’s Rate Case,” and “- Financial Condition - Liquidity and Capital Resources - Regulatory Matters -“Rodemacher Unit 3.”
Cleco Power continues to evaluate a range of other power supply options for 2009 and beyond. As such, Cleco Power is continuing to update its IRP to look at future sources of supply. Cleco Power released a RFP in October 2007 seeking long-term resources to fill the needs identified by the latest IRP. Bids were received in December 2007 and Cleco Power notified bidders if their bids were selected for the short list. On February 26, 2009, Cleco Power announced that it had chosen the acquisition of 50 percent of the Acadia power station, or one of its two 580-MW units, as the lowest bid in its 2007 long-term RFP for capacity beginning in 2010. Cleco Power will own and operate one unit and operate the other 580-MW unit on behalf of Acadia. Prior to closing the transaction, valued at approximately $300.0 million, Cleco Power must complete its due diligence, finalize and execute definitive agreements, and receive approvals from the LPSC and FERC. Cleco Power and Acadia plan to complete the transaction by the end of 2009 in a process that remains under the supervision of an independent monitor appointed by the LPSC.
In September 2008, Cleco Power’s distribution and transmission systems sustained substantial damage from two hurricanes. On September 1, 2008, Hurricane Gustav made landfall in southeastern Louisiana as a Category 2 hurricane, affecting Cleco Power’s entire service territory and leaving approximately 246,000 customers without electricity. On September 12, 2008, only three days after Cleco Power’s storm team restored service to customers affected by Hurricane Gustav, Hurricane Ike began moving toward the Texas coastline causing new power outages. The storm officially made landfall in Texas on September 13, 2008, also as a Category 2
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hurricane. Hurricane Ike left approximately 80,000 Cleco customers without power and caused extensive flooding in the southern portion of Cleco Power’s service territory. Crews restored power by September 16, 2008 to all customers whose service could be reconnected after Hurricane Ike. The current estimate of the cost of restoration for Hurricanes Gustav and Ike is approximately $78.7 million, of which approximately 84% related to Hurricane Gustav and the remaining 16% to Hurricane Ike. Of the $78.7 million, $46.7 million was capitalized, and with approval from the LPSC, the remaining uncapitalized costs were offset against Cleco Power’s existing storm damage reserves. For additional information on the financial impact of Hurricanes Gustav and Ike, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 19 - Storm Restoration.”
Midstream
Acadia resides in the Southeastern Electric Reliability Council (SERC)-Entergy sub-region. For merchant generators, this sub-region is challenged both by the general oversupply of gas-fired generation available to serve the Entergy system needs and the physical transmission constraints that can limit the amount of power that can be delivered. The SERC-Entergy sub-region has reserve margins among the highest in the nation. These high reserve margins can lead to lower capacity factors and lower profitability for Acadia. In the coming years, the wholesale power market within the SERC-Entergy sub-region is expected to tighten as load grows. The tightening wholesale power market is expected to result in higher wholesale power prices. At times, transmission availability limits the wholesale markets accessible by Acadia resulting in limited buyers for Acadia’s output. Because of Acadia’s location on the transmission grid, Acadia has interconnections with two main suppliers of electric transmission when accessing external power markets.
Acadia markets short-, mid- and long-term products where available. Through its third-party energy marketer, Acadia pursues opportunities in the hourly, weekly, monthly, and annual markets. In addition, Acadia actively participates in long-term requests for capacity and energy. Acadia’s success in these marketing efforts is a primary driver of its earnings and cash flow.
In May 2008, Acadia was notified that Cleco Power selected its proposal to fulfill Cleco Power’s capacity and energy needs as defined in the Cleco Power 2009 short-term RFP. The proposal was for a 235-MW product beginning March 1, 2009, and ending October 1, 2009. The definitive agreement between Acadia and Cleco Power was executed on July 31, 2008 and has been approved by the LPSC and FERC.
On February 26, 2009, Cleco Power announced that it had selected Acadia’s proposal to fulfill Cleco Power’s capacity and energy needs as defined in the Cleco Power 2007 long-term RFP. Under the proposed arrangement, Cleco Power would acquire and operate one of Acadia’s generating units and operate the other unit, as described further above under “- Cleco Power.”
Midstream’s other principal source of revenue is the Evangeline Tolling Agreement, under which Bear Energy has the right to dispatch the electric generation capacity of the facility. Profitability of Midstream’s investment in Evangeline depends principally upon continued performance by Bear Energy of its payment obligations under the tolling agreement and controlling maintenance expenses associated with the facility, which increased substantially in 2008.
RESULTS OF OPERATIONS
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 revenue and expenses during the reporting period. Actual results could differ materially from those estimates.
Cleco Consolidated Results of Operations -
Year ended December 31, 2008,
Compared to Year ended December 31, 2007
Consolidated net income applicable to common stock decreased $49.2 million, or 32.5%, in 2008 compared to 2007 primarily due to decreased Midstream and Corporate earnings. Partially offsetting these decreases were increased Cleco Power earnings.
Operating revenue, net increased $49.6 million, or 4.8%, in 2008 compared to 2007 largely as a result of higher fuel cost recovery revenue at Cleco Power.
Operating expenses increased $32.2 million, or 3.5%, in 2008 compared to 2007 primarily due to higher fuel costs at Cleco Power.
Interest income decreased $6.3 million, or 53.9%, in 2008 compared to 2007 primarily due to lower interest rates and lower average investment balances.
Allowance for other funds used during construction increased $32.0 million, or 97.1%, in 2008 compared to 2007,
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primarily due to increased construction activity at Rodemacher Unit 3.
Equity income from investees decreased $98.7 million, or 106.0%, in 2008 compared to 2007. The decrease primarily was due to decreased equity earnings at APH, resulting from the $78.2 million 2007 settlement of Acadia’s claims against CES and Calpine and $60.0 million received by APH during 2007 relating to Cajun’s purchase of CAH’s 50% equity ownership interest in Acadia, offset by a $45.8 million pre-tax impairment loss.
Other income decreased $28.3 million, or 95.7%, in 2008 compared to 2007 as a result of amounts received by APH during 2007 relating to Cajun’s purchase of CAH’s 50% equity ownership interest in Acadia. For additional information, see “- Midstream - Equity Income from Investees” and “- Other Income.”
Other expense increased $3.6 million, or 80.9%, in 2008 compared to 2007 primarily due to a decrease in the cash surrender value of life insurance policies at Cleco Corporation. Partially offsetting this increase was APH’s payment in 2007 to acquire Calpine’s interest in Acadia’s claim against Cleco Power regarding a potential electric metering error at the Acadia facility.
Interest charges increased $14.4 million, or 38.0%, in 2008 compared to 2007 primarily due to the carrying cost of the tax benefits of storm damage costs, a favorable 2007 settlement with the IRS, and interest related to the issuances of new senior notes, solid waste disposal facility bonds, GO Zone bonds, and storm recovery bonds. Partially offsetting this increase was the allowance for borrowed funds used during construction associated with the construction activity at Rodemacher Unit 3, the repayments of medium-term and senior notes at Cleco Power and Cleco Corporation, respectively, the storm damage surcredit, and interest related to retainage from Shaw.
Federal and state income taxes decreased $52.3 million, or 73.9%, in 2008 compared to 2007 primarily due to a decrease in pre-tax income, excluding equity AFUDC.
Results of operations for Cleco Power and Midstream are more fully described below.
CLECO POWER
Significant Factors Affecting Cleco Power
Revenue is primarily affected by the following factors:
As an electric utility, Cleco Power is affected, to varying degrees, by a number of factors influencing the electric utility industry in general. These factors include, among others, an increasingly competitive business environment, the cost of compliance with environmental and reliability regulations, conditions in the credit markets and global economy, and changes in the federal and state regulation of generation, transmission, and the sale of electricity. For a discussion of various regulatory changes and competitive forces affecting Cleco Power and other electric utilities, see Part I, Item 1 “Business - Regulatory Matters, Industry Developments, and Franchises - Franchises” and “- Financial Condition - Market Restructuring.” For a discussion of risk factors affecting Cleco Power’s business, see Item 1A, “Risk Factors - Rodemacher Unit 3 Construction Costs,” “- Rodemacher Unit 3 Technical Specifications,” “- Cleco Power’s Rates and Rate Case,” “- Fuel Cost Audits,” “- Hedging and Risk Management Activities,” “- Future Electricity Sales,” “- Purchased Power,” “- Weather Sensitivity,” “- Commodity Prices,” “- Cleco Power Generation Facilities,” “- ERO,” “- Environmental Compliance,” “- Regulatory Compliance,” “- Termination of the Rodemacher Unit 3 Project or the Amended EPC Contract,” “- Retail Electric Service,” “- Cleco Credit Ratings,” “- Storm Restoration Costs,” and “- Global Financial Crisis.”
Cleco Power’s residential customers’ demand for electricity largely is affected by weather. Weather generally is measured in cooling degree-days and heating degree-days. A cooling degree-day is an indication of the likelihood that a consumer will use air conditioning, while a heating degree-day is an indication of the likelihood that a consumer will use heating. An increase in heating degree-days does not produce the same increase in revenue as an increase in cooling degree-days, because alternative heating sources are more available. Normal heating degree-days and cooling degree-days are calculated for a month by separately calculating the average actual heating and cooling degree-days for that month over a period of 30 years.
Cleco Power’s expected retail sales are dependent upon factors such as weather conditions, natural gas prices, customer conservation efforts, retail marketing and business development programs, and the economy of Cleco Power’s service area. Over the last five years, kilowatt-hour sales to Cleco Power’s retail electric customers have grown an average of 0.5% per year. Growth in industrial sales has been mitigated due to a large industrial customer which began self-generation operations in 2007 and another large industrial customer beginning self-generation operations in early 2009. These operations combined with downturns in the wood and paper industries result in a projected five year rate of decline of 0.1% in overall retail sales. As a result of new long-term contracts with wholesale customers, sales for resale are expected to begin to improve in 2009.
Other issues facing the electric utility industry that could affect sales include:
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imposition of federal and/or state renewable portfolio standards;
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legislative and regulatory changes;
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increases in environmental regulations and compliance costs;
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cost of power impacted by the price increases of natural gas, the addition of lower cost solid-fuel plants, and the addition of additional generation capacity;
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increase in capital and operations and maintenance costs due to higher construction and labor costs;
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retention or loss of large industrial customers and municipal franchises;
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changes in electric rates compared to customers’ ability to pay;
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access to transmission systems;
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need for additional transmission capacity for reliability purposes; and
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turmoil in the credit markets and global economy.
For more information on energy legislation in regulatory matters that could affect Cleco, see “- Financial Condition - Market Restructuring - Wholesale Electric Markets.”
Cleco Power’s revenues and earnings also are substantially affected by regulatory proceedings known as rate cases. During those cases, the LPSC determines Cleco Power’s rate base, depreciation rates, operation and maintenance costs, and administrative and general costs that Cleco Power may recover from its customers through its rates. These proceedings may examine, among other things, the prudence of Cleco Power’s operation and maintenance practices, level of subject expenditures, allowed rates of return, and previously incurred capital expenditures. The LPSC has the authority to disallow costs found not to have been prudently incurred. These regulatory proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or reducing rates. Rate cases generally have long timelines, which may be limited by statute. Decisions are typically subject to appeal, potentially leading to additional uncertainty.
Cleco Power’s current base rates have been extended through the commercial operation date of Rodemacher Unit 3. On July 14, 2008, Cleco Power filed with the LPSC a request for a new rate plan to establish rates to be effective upon commercial operation of Rodemacher Unit 3. For additional information see “- Overview - Cleco Power.”
Other expenses are primarily affected by the following factors:
The majority of Cleco Power’s non-fuel cost recovery expenses consist of other operations, maintenance, depreciation, and taxes other than income taxes. Other operations expenses are affected by, among other things, the cost of employee benefits, insurance expenses, and the costs associated with energy delivery and customer service. Maintenance expenses associated with Cleco Power’s plants generally depend upon their physical characteristics, as well as the effectiveness of their preventive maintenance programs. Transmission and distribution maintenance expenses are generally affected by the level of repair and rehabilitation of lines to maintain reliability. Depreciation expense primarily is affected by the cost of the facility in service, the time the facility was placed in service, and the estimated useful life of the facility. Taxes other than income taxes generally include payroll taxes and ad valorem taxes. Cleco Power anticipates certain non-fuel cost recovery expenses to be higher in 2009 compared to 2008. These expenses include higher generation expenses related to operations and maintenance, salaries, benefits, and training, and higher outside consulting fees in the areas of tax planning, regulatory, legal and strategy. In addition, Cleco Power expects the implementation of the Pension Protection Act, in conjunction with material pension plan portfolio losses in 2008, will result in annual pension contributions going-forward that are significantly higher than estimates calculated in prior years. For additional information, see “- Regulatory Matters - Pension Protection Act of 2006.”
Cleco Power’s Results of Operations -
Year ended December 31, 2008,
Compared to Year ended December 31, 2007
Cleco Power’s net income for 2008 increased $29.2 million, or 34.4%, compared to 2007. Contributing factors include:
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higher allowance for other funds used during construction,
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lower other operations and maintenance expenses,
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lower taxes other than incomes taxes,
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lower depreciation expense, and
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higher other operations revenue.
These were partially offset by:
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higher interest charges,
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lower interest income,
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higher non-recoverable fuel and power purchased, and
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lower base revenue.
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The following chart shows how cooling and heating degree-days varied from normal conditions and from the prior period. Cleco Power uses temperature data collected by the National Oceanic and Atmospheric Administration to determine cooling and heating degree-days.
Base
Base revenue during 2008 decreased $1.4 million, or 0.4%, compared to 2007. The decrease was primarily due to lower electric sales to retail and wholesale customers, generally resulting from changes in weather, hurricane-related outages, and decreases in the amount being recovered for storm restoration costs through a monthly customer surcharge and in base rates. The monthly cost to customers was reduced in March 2008 when the storm costs were financed through the issuance of storm recovery bonds by Cleco Katrina/Rita. These decreases were partially offset by higher sales to municipal customers.
For information on the effects of future energy sales on Cleco Power’s financial condition, results of operations, and cash flows, see Part I, Item 1A, “Risk Factors - Future Electricity Sales.”
Fuel Cost Recovery
Fuel cost recovery revenue billed to customers during 2008 compared to 2007 increased $46.2 million, or 7.3%, primarily due to increases in the per-unit cost of power purchased for utility customers and higher volumes of fuel used for electric generation. Partially offsetting the increase were decreased volumes of power purchased for utility customers and
decreases in the per-unit cost of fuel used for electric generation.
Other Operations
Other operations revenue increased $1.5 million, or 4.3%, in 2008 compared to 2007, primarily due to $3.7 million of higher transmission revenue, customer fees, and pole attachment revenue, partially offset by a $2.2 million net loss relating to economic hedge transactions associated with fixed-price power being provided to a wholesale customer. For information on Cleco’s energy commodity activities, see Item 7A, “Quantitative and Qualitative Disclosures about Market Risk - Risk Overview - Commodity Price Risks.”
Operating Expenses
Operating expenses increased $31.3 million, or 3.4%, in 2008 compared to 2007. Fuel used for electric generation (recoverable) decreased $38.7 million, or 14.6%, primarily due to lower per-unit costs of fuel used as compared to the same period of 2007, as a result of realized gains on fuel hedging due to the price volatility of natural gas. Partially offsetting this decrease were higher volumes of fuel used for electric generation, primarily from the absence in 2008 of plant outages as compared to the same period of 2007. Power purchased for utility customers (recoverable) increased $85.0 million, or 23.0%, primarily due to higher per-unit costs of purchased power. Partially offsetting this increase were lower volumes of purchased power. Fuel used for electric generation and power purchased for utility customers generally are influenced by natural gas prices, as well as availability of transmission. However, other factors such as scheduled and/or unscheduled outages, unusual maintenance or repairs, or other developments may affect fuel used for electric generation and power purchased for utility customers. Non-recoverable fuel and power purchased increased $1.5 million, or 6.0%, primarily due to higher capacity payments made during 2008. Other operations expense decreased $4.0 million, or 4.1%, primarily due to lower employee benefit costs and administrative expenses. Maintenance expenses during 2008 decreased $3.7 million, or 7.9%, compared to 2007 primarily due to less distribution and generating station maintenance work performed during 2008. Depreciation expense decreased $2.1 million, or 2.7%, primarily due to $3.6 million of lower storm amortization costs, partially offset by $1.5 million related to normal recurring additions to fixed assets. Taxes other than income taxes decreased $6.6 million, or 17.7%, primarily due to a change in the accounting treatment of city franchise fees as a result of an LPSC order and lower property taxes.
Interest Income
Interest income decreased $1.5 million, or 27.3%, during 2008 compared to 2007 primarily due to a lower recovery of interest costs relating to Cleco Power’s lower deferred lignite mining costs. For additional information, see “- Financial Condition - Other Matters - Lignite Deferral.”
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Allowance for Other Funds Used During Construction
Allowance for other funds used during construction increased $32.0 million, or 97.1%, during 2008 compared to 2007 primarily due to increased construction activity at Rodemacher Unit 3. Allowance for other funds used during construction comprised 57.1% of Cleco Power’s net income for 2008, compared to 38.9% for 2007.
Interest Charges
Interest charges increased $17.7 million, or 59.9%, during 2008 compared to 2007 primarily due to the following: $9.6 million related to the May 2008 issuance of senior notes; $7.2 million related to the March 2008 issuance of storm recovery bonds; $3.6 million related to the November 2007 issuance of solid waste disposal facility bonds; $7.5 million related to the carrying cost of the tax benefits of storm damage costs; $6.6 million primarily related to a favorable 2007 settlement with the IRS; and $0.4 million related to the December 2008 issuance of GO Zone bonds. Partially offsetting this increase was $6.5 million of allowance for borrowed funds used during construction associated with the construction activity at Rodemacher Unit 3, $5.9 million related to the storm damage surcredit, $2.1 million related to the repayment of medium-term notes during 2007, $1.7 million related primarily to lower interest rates on Cleco Power’s credit facility, and $1.0 million related to interest on retainage from Shaw.
Income Taxes
Income tax expense decreased $1.7 million, or 5.6%, during 2008 compared to 2007, primarily due to a decrease in pre-tax income excluding equity AFUDC.
MIDSTREAM
Significant Factors Affecting Midstream
Earnings are primarily affected by the following factors:
Midstream’s equity earnings from investees are derived primarily from the Evangeline Tolling Agreement with Bear Energy, which prior to November 2007, was with Williams, and from its 50% interest in Acadia, which prior to March 2006 derived its revenue from two tolling agreements with CES. Subsequent to March 2006, Acadia contracted with a third-party marketer to sell its output. Revenue from tolling contracts generally is affected by the availability and efficiency of the facility and the level at which it operates. A facility’s availability can be protected by providing replacement power to the tolling counterparties. The Evangeline Tolling Agreement gives the tolling counterparty the right to own, dispatch, and market all of the electric generation capacity of the respective facility. Bear Energy is responsible for providing its own natural gas to Evangeline. In November 2007, Williams completed the assignment of its interest in the Evangeline Tolling Agreement to Bear Energy. The terms of the agreement were unchanged. In May 2008, JPMorgan Chase & Co. acquired Bear Stearns Companies Inc. In connection with the acquisition, JPMorgan Chase & Co. has guaranteed certain obligations of its subsidiaries, including Bear Energy’s obligations under the Evangeline Tolling Agreement.
Under the Evangeline Tolling Agreement, Bear Energy pays Evangeline a fixed fee and a variable fee for operating and maintaining the facility. The Evangeline Tolling Agreement is accounted for as an operating lease. For additional information on Cleco’s operating leases, see “- Critical Accounting Policies - Midstream” and Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 14 - Operating Leases.” Equity income from the Evangeline Tolling Agreement correlates with the seasonal usage of the plant. Evangeline’s 2008 revenue was recognized in the following manner:
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17% in the first quarter;
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22% in the second quarter;
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44% in the third quarter; and
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17% in the fourth quarter.
Revenue under the Evangeline Tolling Agreement, which is reflected in equity income from investees, is anticipated to be recognized in a similar manner for 2009. For additional information on recognition of revenue from the Evangeline Tolling Agreement, see “- Critical Accounting Policies - Midstream” and Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies - Revenue and Fuel Costs - Equity Income.”
Prior to the suspension of the Calpine Tolling Agreements, CES paid Acadia a fixed fee and a variable fee for operating and maintaining the facility. Currently, a third party marketer provides energy management services for Acadia. For information on Cleco’s investment in Acadia and the Calpine bankruptcy settlement, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees” and Note 20 - “Calpine Bankruptcy Settlement.”
For additional information on the factors affecting Midstream, see Part I, Item 1A, “Risk Factors - Evangeline Plant Performance,” “- Evangeline Tolling Agreement,” and “- Evangeline and Acadia Generation Facilities.”
Expenses are primarily affected by the following factors:
Midstream’s expenses include depreciation, maintenance, and other operations expenses. Depreciation expense is affected by the cost of the facility in service, the time the facility was placed in service, and the estimated useful life of the facility. Maintenance expenses generally depend on the physical characteristics of the facility, the frequency and duration of the facility’s operations, and the effectiveness of preventive maintenance. Other operating expenses mainly relate to administrative expenses, employee benefits, and generation operating expenses.
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Other Factors Affecting Midstream
Perryville and Attala
Effective February 1, 2007, the ownership interests of Midstream’s transmission interconnection facilities, Perryville and Attala, were transferred to Cleco Corporation. In accordance with SFAS No. 131, the net operating results for Midstream for periods prior to February 1, 2007, have been adjusted to reflect this organizational change.
Acadia
Acadia’s output currently is sold through an energy management services agreement with a third party marketer. Prior to March 2006, Acadia’s output was sold through the Calpine Tolling Agreements. In December 2005, the Calpine Debtors filed for protection under Chapter 11 of the Bankruptcy Code and subsequently filed a motion with the Calpine Debtors Bankruptcy Court to reject the Calpine Tolling Agreements. In March 2006, Acadia and CES executed amendments to the Calpine Tolling Agreements, permitting Acadia to suspend its obligations under the agreement. During 2006, APH drew against the $15.0 million letter of credit issued by Calpine. Under an April 2007 settlement between Cleco and Calpine, Acadia received a pre-petition general unsecured claim against Calpine of $185.0 million in connection with the Calpine Tolling Agreements and Calpine’s guaranty of those agreements. Acadia made a dividend by assignment to APH for its portion of the claims. In May 2007, APH sold its claim of $85.0 million at 92% of face value. In September 2007, after all regulatory approvals were received, the sale of CAH’s Assets to Cajun was completed. At the closing of the sale, APH received an $85.0 million payment from Cajun for the agreed upon value of the priority and guaranteed distributions, plus a $2.9 million break-up fee and other expense reimbursements. For additional information on Acadia and the Calpine bankruptcy, see “- Overview - Midstream” and Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 20 - Calpine Bankruptcy Settlement.”
Evangeline
In accordance with FIN 46R, Cleco reports its investment in Evangeline on the equity method of accounting and reflects Evangeline’s net operating results in the equity income from investees’ line. For additional information on FIN 46R and the equity method of accounting related to Evangeline, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees.”
Midstream’s Results of Operations -
Year ended December 31, 2008,
Compared to Year ended December 31, 2007
Factors affecting Midstream during 2008 are described below.
Operating Revenue and Operating Expenses
Operating revenue increased $2.9 million, or 56.4%, in 2008 compared to 2007. Operating expenses increased $1.7 million, or 17.7%, in 2008 compared to 2007. The increases were primarily due to the accounting treatment of Acadia’s power plant operations, maintenance, and engineering services resulting from Cajun’s purchase of Calpine’s 50% ownership interest in Acadia in September 2007. Prior to September 2007, Calpine employees provided power plant operations, maintenance, and engineering services to Acadia. Subsequent to September 2007, these services were provided by Midstream. As a result, revenue and expenses associated with plant operations for Acadia are included in affiliate revenue and operating expenses, respectively.
Interest Income
Interest income decreased $1.0 million, or 100.0%, in 2008 compared to 2007, primarily due to lower investment balances at APH.
Equity Income from Investees
Equity income from investees decreased $98.6 million, or 107.7%, in 2008 compared to 2007. The decrease was due to a $91.5 million decrease in equity earnings at APH and a $7.1 million decrease at Evangeline. This decrease at APH was primarily due to the absence in 2008 of the settlement of Acadia’s pre-petition unsecured claims against CES and
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Calpine and amounts received by APH in 2007 relating to CAH’s 50% equity ownership interest in Acadia. Partially offsetting these decreases was an impairment loss recorded during 2007. The decrease at Evangeline was primarily due to higher maintenance expenses largely relating to a planned combustion turbine major inspection outage during 2008, higher maintenance expenses under Evangeline’s long-term maintenance contract, and higher other unplanned maintenance expenses as compared to 2007. Maintenance expenses at Evangeline during 2009 are expected to be at lower levels as compared to 2008 primarily due to lower planned and unplanned maintenance expenses and lower expected expenses under Evangeline’s long-term maintenance contract, while revenues at Evangeline during 2009 are expected to be comparable to 2008 revenues. As previously discussed, Midstream’s ownership interests in Perryville and Attala were transferred to Cleco Corporation effective February 1, 2007, and are no longer reported as equity income from investees on Midstream’s financial statements. In accordance with SFAS No. 131, operating results for prior periods have been adjusted to reflect this new structure. For additional information, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 11 - Disclosures about Segments."
Other Income
Other income decreased $27.9 million, or 100.0%, during 2008 compared to 2007, as a result of amounts being received by APH during 2007 relating to Cajun’s purchase of CAH’s 50% equity ownership interest in Acadia. Of this amount, $25.0 million represented consideration of APH’s guaranteed payments from Acadia and $2.9 million represented break-up fees.
Other Expense
Other expense decreased $1.2 million, or 97.5%, during 2008 compared to 2007, primarily due to APH’s payment during 2007 to acquire Calpine’s interest in Acadia’s claim against Cleco Power regarding a potential electric metering error at the Acadia facility.
Interest Charges
Interest charges decreased $12.1 million, or 63.4%, during 2008 compared to 2007, primarily due to a lower interest rate and a lower balance on affiliate debt relating to APH’s investment in Acadia.
Income Taxes
Income tax expense decreased $43.8 million, or 119.6%, during 2008 compared to 2007, primarily due to a decrease in pre-tax income.
Cleco Consolidated Results of Operations -
Year ended December 31, 2007,
Compared to Year ended December 31, 2006
Consolidated net income applicable to common stock increased $78.5 million, or 107.7%, in 2007 compared to 2006 primarily due to increased Midstream and Cleco Power earnings. The increase at Midstream was primarily due to increased earnings at APH, resulting from the settlement of Acadia’s pre-petition unsecured claims against CES and Calpine and amounts received by APH relating to Cajun’s purchase of CAH’s 50% equity ownership interest in Acadia, offset partially by a pre-tax impairment loss.
Operating revenue, net increased $29.9 million, or 3.0%, in 2007 compared to 2006 largely as a result of higher base and fuel cost recovery revenue at Cleco Power.
Operating expenses increased $47.4 million, or 5.4%, in 2007 compared to 2006 primarily due to increased fuel costs, capacity payments, depreciation expense and other operations and maintenance expenses at Cleco Power.
Interest income increased $1.3 million, or 12.5%, in 2007 compared to 2006 largely as a result of higher average investment balances.
Allowance for other funds used during construction increased $25.2 million, or 323.6%, primarily due to increased construction activity at Rodemacher Unit 3.
Equity income from investees increased $68.7 million, or 280.9%, in 2007 compared to 2006. The increase primarily was due to increased earnings at APH as discussed above.
Other income increased $22.1 million, or 298.4%, in 2007 compared to 2006 primarily due to the sale of CAH’s 50% equity ownership interest in Acadia, partially offset by the absence of the receipt in 2007 of life insurance proceeds at Cleco Corporation. For additional information, see “- Midstream - Equity Income from Investees” and “- Other Income.”
Interest charges decreased $6.3 million, or 14.2%, in 2007 compared to 2006 primarily due to higher allowance for borrowed funds used during construction associated with the construction activity at Rodemacher Unit 3. Partially offsetting this decrease was increased interest related to draws against Cleco Power’s credit facility, interest related to the issuance of solid waste disposal facility bonds, and the accrual of interest related to uncertain tax positions.
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FORM 10-K
Federal and state income taxes increased $28.7 million, or 68.3%, in 2007 compared to 2006 primarily due to the $105.8 million increase in pre-tax income for 2007 compared to 2006. The effective income tax rate decreased from 36.0% to 31.8% in 2007 compared to 2006, mainly due to the flowthrough of tax benefits associated with AFUDC equity.
Results of operations for Cleco Power and Midstream are more fully described below.
Cleco Power’s Results of Operations -
Year ended December 31, 2007,
Compared to Year ended December 31, 2006
Cleco Power’s net income for 2007 increased $19.8 million, or 30.6%, compared to 2006. Contributing factors include:
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higher base revenue,
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higher other operations revenue,
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higher allowance for other funds used during construction,
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lower interest charges, and
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lower effective income tax rate.
These were partially offset by:
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absence of favorable customer credit adjustments,
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higher non-recoverable fuel and power purchased,
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higher other operations and maintenance expenses,
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higher depreciation expense, and
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lower interest income.
The following chart shows how cooling and heating degree-days varied from normal conditions and from the prior period. Cleco Power uses temperature data collected by the National Oceanic and Atmospheric Administration to determine cooling and heating degree-days.
Base
Base revenue during 2007 increased $11.5 million, or 3.4%, compared to 2006. The increase primarily was due to the recovery of storm restoration costs through a monthly customer surcharge that began in May 2006. These storm-related costs were being amortized to depreciation expense based on the amounts collected monthly from customers through this surcharge. Also contributing to the increase in base revenue were higher retail and wholesale kWh sales, primarily from colder winter weather as compared to 2006.
Fuel Cost Recovery
Fuel cost recovery revenue billed to customers during 2007 compared to 2006 increased $17.3 million, or 2.8%, primarily due to increases in the per-unit cost of fuel used for electric
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generation and higher volumes of power purchased for utility customers.
Electric Customer Credits
The $4.7 million change in electric customer credits is the result of the absence in 2007 of favorable adjustments made during 2006 related to prior RSP filing periods. The potential refunds associated with the RSP are based on results for each 12-month period ended September 30. For additional information on the accrual of electric customer credits, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 12 - Electric Customer Credits.”
Other Operations
Other operations revenue increased $5.1 million, or 17.0%, in 2007 compared to 2006 primarily due to a $1.1 million mark-to-market gain in 2007 as compared to a $4.3 million mark-to-market loss in 2006 relating to economic hedge transactions associated with fixed-price power being provided to a wholesale customer. These increases were partially offset by lower transmission services revenue. For information on Cleco’s energy commodity activities, see Item 7A, “Quantitative and Qualitative Disclosures about Market Risk - Risk Overview - Commodity Price Risks.”
Operating Expenses
Operating expenses increased $42.9 million, or 4.9%, in 2007 compared to 2006. Fuel used for electric generation (recoverable) increased $9.0 million, or 3.5%, primarily due to higher per-unit costs of fuel used as compared to 2006. Partially offsetting this increase were lower volumes of fuel used for electric generation. Power purchased for utility customers (recoverable) increased $7.9 million, or 2.2%, largely due to higher volumes of purchased power. The primary factor causing the increase in volumes of purchased power was the decreased generation of power from Cleco Power’s facilities due to scheduled major maintenance. Fuel used for electric generation and power purchased for utility customers generally are influenced by natural gas prices, as well as availability of transmission. However, other factors such as scheduled and/or unscheduled outages, unusual maintenance or repairs, or other developments may affect fuel used for electric generation and power purchased for utility customers. Non-recoverable fuel and power purchased increased $2.1 million, or 9.4%, primarily due to higher capacity payments made during 2007. Other operations expense increased $9.8 million, or 11.2%, primarily due to the absence in 2007 of the $3.5 million recognition of previously recorded storm restoration expenses as a regulatory asset as a result of the LPSC’s February 2006, approval of Cleco Power’s request to recover these storm restoration costs. Also contributing to the increase were $1.9 million of higher general liability claims and storm expenses, primarily from the absence in 2007 of insurance and damage costs adjustments recorded in 2006, $3.4 million of higher transmission and distribution operation expenses, and $1.0 million of higher customer collection costs, employee benefit costs, and payroll and administrative expenses. Maintenance expenses during 2007 increased $9.1 million, or 24.2%, compared to 2006 primarily due to the absence of the $3.0 million recognition of previously recorded storm restoration expenses as a regulatory asset as a result of the LPSC’s February 2006, order. Also contributing to the increase was $7.1 million more of distribution and generating station maintenance work performed during 2007. Partially offsetting these increases was the $1.0 million recognition of other previously recorded storm restoration expenses as a regulatory asset during 2007. Depreciation expense increased $5.2 million, or 7.0%, primarily as a result of $3.9 million of storm amortization costs and $1.3 million of normal recurring additions to fixed assets.
Interest Income
Interest income decreased $2.0 million, or 27.0%, during 2007 compared to 2006 primarily due to lower average investment balances. Lower investment balances were the result of construction payments for Rodemacher Unit 3 being partially funded by these investments.
Allowance for Other Funds Used During Construction
Allowance for other funds used during construction increased $25.2 million, or 323.6%, during 2007 compared to 2006 primarily due to increased construction activity at Rodemacher Unit 3. Allowance for other funds used during construction comprised 38.9% of Cleco Power’s net income for 2007, compared to 12.0% for 2006.
Interest Charges
Interest charges decreased $6.7 million, or 18.4%, during 2007 compared to 2006 primarily due to the allowance for borrowed funds used during construction associated with the construction activity at Rodemacher Unit 3 and the repayment of medium-term notes during 2007. Partially offsetting this decrease was interest related to draws against Cleco Power’s credit facility during 2007, interest related to the issuance in late 2006 and late 2007 of solid waste disposal facility bonds, and the accrual of interest related to uncertain tax positions, which was previously recorded in tax expense.
Income Taxes
Income tax expense decreased $3.4 million, or 10.4%, during 2007 compared to 2006 primarily due to decreased pre-tax book net income excluding AFUDC equity. Cleco Power’s effective income tax rate decreased from 33.8% to 25.9% during 2007 compared to 2006, mainly due to the flow-through of tax benefits associated with AFUDC equity.
CLECO CORPORATION
CLECO POWER
FORM 10-K
Midstream’s Results of Operations -
Year ended December 31, 2007,
Compared to Year ended December 31, 2006
Midstream’s net income for 2007 increased $63.1 million compared to 2006 primarily due to Acadia. Factors affecting Midstream during 2007 are described below.
Operating Expenses
Operating expenses increased $2.1 million, or 28.2%, in 2007 compared to 2006. The increase primarily was due to higher employee benefit costs and higher administrative expenses.
Interest Income
Interest income increased $1.0 million in 2007 compared to 2006 primarily due to higher investment balances at APH. Higher investment balances were primarily the result of amounts received by APH relating to the settlement of Acadia’s pre-petition unsecured claims against CES and Calpine.
Equity Income from Investees
Equity income from investees increased $70.2 million, or 329.0%, in 2007 compared to 2006. The increase was due to a $71.3 million increase in equity earnings at APH, partially offset by a $1.1 million decrease at Evangeline. The $71.3 million increase in earnings at APH primarily was due to $78.2 million related to the settlement of Acadia’s pre-petition unsecured claims against CES and Calpine and $60.0 million related to amounts received by APH relating to the sale of the CAH Assets. Partially offsetting these increases was an impairment loss of $45.8 million recorded in 2007, the absence in 2007 of APH’s draw against the $15.0 million letter of credit issued by Calpine, $3.0 million of lower merchant revenue, $1.6 million of higher turbine maintenance expenses, and $1.5 million from the absence of insurance claim settlements. The impairment charge represents the difference between the $234.8 million carrying value and the $189.0 million market value. The decrease at Evangeline primarily was due to purchases of replacement power related to an unscheduled outage at the facility, as well as higher interest charges related to uncertain tax positions. These decreases were partially offset by higher revenue from replacement energy and the absence in 2007 of prior year adjustments related to fixed asset accounting and depreciation. As previously discussed, Midstream’s ownership interests in Perryville and Attala were transferred to Cleco Corporation effective February 1, 2007, and are no longer reported as equity income from investees on Midstream’s financial statements. In accordance with SFAS No. 131, operating results for 2006 have been adjusted to reflect this new structure. For additional information, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 11 - Disclosures about Segments."
Other Income
Other income increased $27.9 million during 2007 compared to 2006 as a result of amounts received by APH relating to the sale of the CAH Assets. At the closing of the sale, APH received an $85.0 million payment from Cajun for the agreed upon value of the priority and guaranteed distributions, plus a $2.9 million break-up fee. Of these amounts, $27.9 million is included in other income ($25.0 million represents consideration of APH’s guaranteed payments from Acadia and $2.9 million represents break-up fees). The remaining $60.0 million is included in equity income from investees. For additional information, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 20 - Calpine Bankruptcy Settlement.”
Other Expense
Other expense increased $1.2 million during 2007 compared to 2006 primarily due to APH’s payment to acquire Calpine’s interest in Acadia’s claim against Cleco Power regarding a potential electric metering error at the Acadia facility.
Income Taxes
Income tax expense increased $33.4 million during 2007 compared to 2006 due to a $96.4 million increase in pre-tax income for 2007 compared to the same period of 2006. Midstream’s effective income tax rate increased from (610.7)% to 38.1% during 2007 compared to 2006, mainly due to higher pre-tax income, tax adjustments booked in 2006, and interest related to tax positions being accounted for as interest expense in 2007, compared to tax expense in 2006, as a result of the adoption of FIN 48.
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CLECO POWER
FORM 10-K
CLECO POWER LLC - NARRATIVE ANALYSIS OF
RESULTS OF OPERATIONS
For a narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items of Cleco Power between the year ended December 31, 2008 and the year ended December 31, 2007, see “Results of Operations - Cleco Power’s Results of Operations - Year ended December 31, 2008, Compared to Year ended December 31, 2007.”
For a narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items of Cleco Power between the year ended December 31, 2007, and the year ended December 31, 2006, see “Results of Operations - Cleco Power’s Results of Operations - Year ended December 31, 2007, Compared to Year ended December 31, 2006.”
The narrative analyses referenced above should be read in combination with Cleco Power’s Financial Statements and the Notes contained in this Form 10-K.
CRITICAL ACCOUNTING POLICIES
Cleco’s critical accounting policies include those accounting policies that are both important to Cleco’s financial condition and results of operations and those that require management to make difficult, subjective, or complex judgments about future events, which could result in a material impact to the financial statements of Cleco Corporation’s segments or to Cleco as a consolidated entity. The financial statements contained in this report are prepared in accordance with accounting principles generally accepted in the United States of America, which require Cleco to make estimates and assumptions. Estimates and assumptions about future events and their effects cannot be made with certainty. Management bases its current estimates and assumptions on historical experience and on various other factors that are believed to be reasonable under the circumstances. On an ongoing basis, these estimates and assumptions are evaluated and, if necessary, adjustments are made when warranted by new or updated information or by a change in circumstances or environment. Actual results may differ significantly from these estimates under different assumptions or conditions. For additional information on Cleco’s accounting policies, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies.”
Cleco believes that the following are the most significant critical accounting policies for the Company:
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Cleco accounts for pensions and other postretirement benefits under SFAS No. 87, SFAS No. 106, and SFAS No. 158. To determine assets, liabilities, income, and expense relating to pension and other postretirement benefits, management must make assumptions about future trends. Assumptions and estimates include, but are not limited to, discount rate, expected return on plan assets, future rate of compensation increases, and medical inflation trend rates. These assumptions are
reviewed and updated on an annual basis. Changes in the rates from year to year and newly enacted laws could have a material effect on Cleco’s financial condition and results of operations by changing the recorded assets, liabilities, income, expense, or required funding of the pension plan obligation. One component of pension expense is the expected return on plan assets. It is an assumed percentage return on the market-related value of plan assets. The market-related value of plan assets differs from the fair value of plan assets by the amount of deferred asset gains or losses. Actual asset returns that differ from the expected return on plan assets are deferred and recognized in the market-related value of assets on a straight-line basis over a five-year period. The 2008 return on pension plan assets was (26.9)% compared to an expected long-term return of 8.4%. For 2007, the return on plan assets was 5.7% compared to an expected long-term return of 8.4%.
Cleco uses the Citigroup Pension Liability Index, adjusted by 0.14% for differences in cash flows, in determining the discount rate applied to its pension plans. Management believes the use of the Citigroup Pension Index, as adjusted, is appropriate because the index’s cash flows are materially similar to those of Cleco’s pension plans. As a result of the annual review of assumptions, the discount rate decreased from 6.48% to 6.01%.
A change in the assumed discount rate creates a deferred actuarial gain or loss. Generally, when the assumed discount rate decreases compared to the prior measurement date, a deferred actuarial loss is created. When the assumed discount rate increases compared to the prior measurement date, a deferred actuarial gain is created. Actuarial gains and losses also are created when actual results, such as assumed compensation increases, differ from assumptions. The net of the deferred gains and losses is amortized to pension expense over the average service life of the remaining plan participants, 16 years for Cleco’s plan, when it exceeds certain thresholds defined in SFAS No. 87 and SFAS No. 106. This approach to amortization of gains and losses has the effect of reducing the volatility of pension expense attributable to investment returns. Over time, it is not expected to reduce or increase the pension expense relative to an approach that immediately recognizes losses and gains.
The decrease in the discount rate combined with accumulated differences between assumed long-term return on plan assets and actual return is expected to increase pension expense by $3.4 million in 2009 compared to 2008. Since both assumptions are evaluated yearly, the increase may not extend past 2009.
Cleco Power made a $6.0 million discretionary contribution to the pension plan in December 2008. There were no discretionary contributions to the pension plan in 2007 or 2006. Future discretionary contributions may be made depending on changes in assumptions, the ability to utilize the contribution as a tax deduction and
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FORM 10-K
requirements concerning recognizing a minimum pension liability. Currently, Cleco Power expects to be required to make $80.0 million in contributions to the pension plan over the next five years. The required contributions are driven by liability funding target percentages set by law which could cause the required contributions to be uneven among the years. The ultimate amount and timing of the contributions will be affected by changes in the discount rate, changes in the funding regulations, and actual returns on fund assets. For additional information on pensions and other postretirement benefits, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 9 - Pension Plan and Employee Benefits.”
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Cleco accounts for income taxes under SFAS No. 109. Under this method, income tax expense and related balance sheet amounts are comprised of a “current” portion and a “deferred” portion. The current portion represents Cleco’s estimate of the income taxes payable or receivable for the current year. The deferred portion represents Cleco’s estimate of the future income tax effects of events that have been recognized in the financial statements or income tax returns in the current or prior years. Cleco makes assumptions and estimates when it records income taxes, such as its ability to deduct items on its tax returns, the timing of the deduction, and the effect of regulation by the LPSC on income taxes. Cleco’s income tax expense and related assets and liabilities could be affected by changes in its assumptions and estimates and by ultimate resolution of assumptions and estimates with taxing authorities. The actual results may differ from the estimated results based on these assumptions and may have a material effect on Cleco’s results of operations. For additional information about Cleco Corporation’s income taxes, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 10 - Income Taxes.”
Effective January 1, 2007, Cleco adopted the provisions of FIN 48 relating to uncertain tax positions. FIN 48 requires management to estimate the reliability of positions taken on tax returns. These estimates could differ significantly from the ultimate outcome. For additional information on the adoption of FIN 48, see Item 8, “Financial Statements and Supplemental Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies - Recent Accounting Standards.”
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Cleco Corporation consolidates entities as required by ARB No. 51, as amended by SFAS No. 94, and interpreted by FIN 46R. Generally, a parent consolidates entities in which it controls, either directly or indirectly, the majority of the voting interest. Additionally, a parent could be required to consolidate an entity in which it does not control a majority voting interest if the subsidiary is a variable interest entity and meets certain criteria contained in FIN 46R. An entity is a variable interest entity if it lacks the ability to finance its activities without support from other parties; if its owners lack controlling financial interest in the entity; or if the entity either conducts substantially all of its activities with or on behalf of an investor or if voting rights are disproportional to risks and rewards. While consolidation or the equity method of accounting will not affect net income applicable to common shareholders, it may affect specific line items within the income statement, such as revenue, specific expense line items, and income from equity investees. Consolidation or the equity method of accounting of an entity will affect specific balance sheet items such as property, plant and equipment and long-term debt, which will cause changes in total assets and total liabilities. Shareholders’ equity should not be affected by consolidation or the equity method of accounting of entities.
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Part of the compensation employees and directors receive is in the form of equity instruments. The instruments may take the form of restricted stock, stock options, stock equivalent units, or other types of equity instruments as described in the compensatory plans. Prior to January 1, 2006, Cleco recognized expense related to equity instruments granted to employees and directors using the intrinsic value method as described in APB Opinion No. 25, not using the fair value method as described in SFAS No. 123. Effective January 1, 2006, Cleco adopted SFAS No. 123(R), which requires recognizing equity compensation at fair value. For additional information on stock-based compensation, see Item 8, “Financial Statements and Supplemental Data - Notes to the Financial Statements - Note 7 - Common Stock - Stock-Based Compensation.”
Cleco Power
SFAS No. 71 determines how to account for actions by regulators that control the price an entity can charge its customers. Cleco Power’s prices are regulated by the LPSC and FERC. By determining what costs can be recovered by Cleco Power through the price it charges its customers, regulatory assets and liabilities are recognized. Future changes made by the regulatory bodies could have a material impact on the operations and financial condition of Cleco Power. Below are three areas that could be materially impacted by future actions of regulators.
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The LPSC determines the ability of Cleco Power to recover prudent costs incurred in developing long-lived assets. If the LPSC was to rule that the cost of current or future long-lived assets was imprudent and not recoverable, Cleco Power could be required to write down the imprudent cost and incur a corresponding impairment loss. At December 31, 2008, the carrying value of Cleco Power’s long-lived assets was $2.0 billion and is expected to be $2.4 billion at the end of 2009, primarily due to the construction of Rodemacher Unit 3.
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CLECO POWER
FORM 10-K
Currently, Cleco Power has concluded that none of its long-lived assets are impaired.
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Cleco Power has concluded it is probable that regulatory assets can be recovered from ratepayers in future rates. At December 31, 2008, Cleco Power had $318.8 million in regulatory assets, net of regulatory liabilities. Actions by the LPSC could limit the recovery of these regulatory assets, causing Cleco Power to record a loss on some or all of the regulatory assets. For additional information on the LPSC and regulatory assets, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies - Regulation,” Note 3 - “Regulatory Assets and Liabilities,” and “- Financial Condition - Other Matters - Lignite Deferral.”
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The LPSC determines the amount and type of fuel and purchased power costs that Cleco Power can charge customers through the fuel adjustment clause. Changes in the determination of allowable costs already incurred by Cleco Power could cause material changes in fuel revenue. In 2004, the LPSC accepted a settlement relating to its fuel audit that required Cleco Power to refund $16.0 million to customers in 2005. This refund was made to customers in February 2005. For the years ended December 31, 2008, 2007, and 2006, Cleco Power reported fuel revenue of $680.9 million, $634.6 million, and $617.3 million, respectively.
Midstream
Generally, Midstream is most affected by market conditions and changes in contract counterparty credit ratings and financial condition. The most important are listed below.
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Certain triggering events could cause Midstream to determine that its long-lived assets or its equity method investments may be impaired according to applicable accounting guidance. Triggering events which apply to long-lived assets include, but are not limited to, a significant decrease in the market value of long-lived assets, significant changes in a tolling agreement counterparty’s financial condition, a significant change in legal factors, such as adverse changes in environmental laws, or a current operating or cash flow loss combined with a projection of continued losses in the future. An equity method investment is required to be tested for impairment if an “other than temporary” decline in market value occurs. Any impairment calculated is subject to many assumptions and estimations. Management must make assumptions about expected future cash flows, long-term interest rates, estimates about the probability of the occurrence of future events, and estimates of market value of assets without a readily observable market price. Differences between the estimate made at a particular balance sheet date and actual events could cause material adjustments to an impairment charge. In September 2007, Midstream recognized an impairment of its indirect equity investment in Acadia of $45.8 million. At December 31, 2008, Midstream had $1.1 million in long-lived assets and $234.3 million in equity method investments. For additional information on the impairment charges, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees.”
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Midstream records income from Evangeline as income from an equity investment and accounts for the Evangeline Tolling Agreement as an operating lease. If the tolling agreement was to be modified to the extent that it would make lease accounting no longer appropriate, future results could materially differ from those currently reported. Under current lease accounting rules, over the first 10 years of the tolling agreement, Evangeline will recognize revenue that will not be billed and collected until the last 10 years of the tolling agreement. If lease accounting was to cease, the revenue would be recognized as billed, causing the revenue recognized in the first 10 years to be lower than it would have been under lease accounting. As of December 31, 2008, Evangeline had recorded $26.2 million in revenue that will not be billed and collected until the last 10 years of the tolling agreement, beginning in the year 2010. If the tolling agreement is modified substantially, the $26.2 million may not be collectible, and Evangeline may be required to incur a loss of some or all of the $26.2 million. For additional information on the tolling agreement, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 14 - Operating Leases.”
FINANCIAL CONDITION
Liquidity and Capital Resources
General Considerations and Credit-Related Risks
Credit Ratings and Counterparties
Financing for operational needs and construction requirements is dependent upon the cost and availability of external funds from capital markets and financial institutions. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations, and policies, Cleco Corporation’s credit rating, the credit rating of Cleco Corporation’s subsidiaries, the cash flows from routine operations, and the credit ratings of project counterparties. The following table presents the credit ratings of Cleco Corporation, Cleco Power, Evangeline, and Cleco’s tolling agreement counterparty at December 31, 2008:
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CLECO POWER
FORM 10-K
Cleco notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
At December 31, 2008, Moody’s and Standard & Poor’s outlooks for both Cleco Corporation and Cleco Power were stable. If Cleco Corporation or Cleco Power’s credit rating were to be downgraded by Moody’s or Standard & Poor’s, Cleco Corporation and/or Cleco Power would be required to pay additional fees and higher interest rates under their bank credit and other debt agreements. For additional information on the impacts of a downgrade in credit ratings, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 15 - Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees - Risks and Uncertainties - Cleco Power.”
On May 30, 2008, JPMorgan Chase & Co. announced it had completed the acquisition of the Bear Stearns Companies Inc. JPMorgan Chase & Co. is guaranteeing certain obligations of Bear Stearns Companies Inc. and its subsidiaries, including obligations under the Evangeline Tolling Agreement. At December 31, 2008, Moody’s outlook for Evangeline was stable. The tolling agreement is the principal source of cash flow for Evangeline. For more information regarding Evangeline’s tolling agreement, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 15 - Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees - Risk and Uncertainties - Cleco Corporation - Evangeline Tolling Agreement.”
In August 2005, Cleco Power entered into an EPC contract with Shaw to construct Rodemacher Unit 3. Under the terms of the Amended EPC Contract, in the event Cleco Power does not maintain a senior unsecured credit rating of either: (i) Baa3 or better from Moody’s or (ii) BBB- or better from Standard & Poor’s, Cleco Power will be required to provide a letter of credit to Shaw in the amount of $20.0 million. In the event of further downgrade to both of its credit ratings to: (i) Ba2 or below from Moody’s, and (ii) BB or below from Standard & Poor’s, Cleco Power will be required to provide an additional $15.0 million letter of credit to Shaw.
With respect to any open power or natural gas trading positions that Cleco may initiate in the future, Cleco may be required to provide credit support (or pay liquidated damages). The amount of credit support that Cleco may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price of power and natural gas, the changes in open power and gas positions, and changes in the amount counterparties owe Cleco. Changes in any of these factors could cause the amount of requested credit support to increase or decrease.
Global Financial Crisis
The continued credit crisis and related turmoil in the global financial system may have an impact on Cleco’s business and financial condition. Cleco may face significant challenges if conditions in the financial markets do not improve. Cleco’s ability to access the capital markets may be severely
restricted at a time when Cleco would like, or need, to do so, which could have a material impact on its ability to fund capital expenditures or debt service or on Cleco’s flexibility to react to changing economic and business conditions. The credit crisis could have a material negative impact on Cleco’s lenders or Cleco’s customers causing them to fail to meet their obligations to Cleco or to delay payment of such obligations. Moreover, as a result of the global financial crisis, the pension plan portfolio experienced significant losses during 2008. For a discussion of certain risks related to the global financial crisis, see Item 1A, “Risk Factors - Global Financial Crisis.”
Debt
At December 31, 2008, Cleco Corporation and Cleco Power were in compliance with the covenants in their credit facilities. If Cleco Corporation were to default under the covenants in its various credit facilities, it would be unable to borrow additional funds under the facilities. Further, if Cleco Power were to default under its credit facility, Cleco Corporation would be considered in default under its credit facility. The bonds issued by Evangeline are non-recourse to Cleco Corporation, and a default on these bonds would not be considered a default under Cleco Corporation’s credit facility. If Cleco Corporation’s credit rating were to be downgraded one level below investment grade, Cleco Corporation would be required to pay fees and interest at a rate of 0.45% higher than the current level for its $150.0 million credit facility. A similar downgrade to the credit ratings of Cleco Power would require Cleco Power to pay fees and interest at a rate of 0.70% higher than the current level on its $275.0 million credit facility.
Cleco Consolidated
Cleco had no short-term debt outstanding at December 31, 2008, or December 31, 2007. At December 31, 2008, Cleco’s long-term debt outstanding was $1.2 billion, of which $63.5 million is long-term debt due within one year, compared to $869.1 million at December 31, 2007, which included $100.0 million long-term debt due within one year. The long-term debt due within one year represents $50.0 million of medium-term notes which mature in May 2009 and $13.5 million of principal payments for the Cleco Katrina/Rita storm recovery bonds scheduled to be paid in the next twelve months.
For Cleco, the $301.3 million increase in long-term debt from December 31, 2007, was primarily due to Cleco Katrina/Rita’s issuance of $180.6 million storm recovery bonds, the issuance by the Rapides Finance Authority of $32.0 million of 6.00% solid waste disposal facility bonds due October 1, 2038, the issuance by the Louisiana Public Facilities Authority of $100.0 million 7.00% GO Zone bonds due December 1, 2038, the issuance by Cleco Power of $250.0 million of 6.65% senior notes due in 2018 and $30.0 million in draws against Cleco Corporation’s credit facility. These were partially offset by the payment of $100.0 million of Cleco Corporation 7.00% senior notes at maturity and Cleco Power’s $190.0 million credit facility payment during 2008. For additional information, see “- Cleco Corporation (Holding Company Level)” and “- Cleco Power” below, and also see Item
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FORM 10-K
8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 6 - Debt.”
At December 31, 2008, and December 31, 2007, Cleco had a working capital surplus of $105.5 million and $48.1 million, respectively. Included in working capital at December 31, 2008 and 2007 was $62.3 million and $17.9 million, respectively, which was restricted for the use of debt payments. The $57.4 million increase in working capital is primarily due to net proceeds from the issuance of bonds, partially offset by additions to property plant and equipment, including Rodemacher Unit 3.
Cash and cash equivalents available at December 31, 2008, were $97.5 million combined with $380.0 million facility capacity ($105.0 million from Cleco Corporation and $275.0 million from Cleco Power) for total liquidity of $477.5 million. Cash and cash equivalents available at December 31, 2008 decreased $31.5 million when compared to cash and cash equivalents available at December 31, 2007. This decrease is primarily due to additions to property, plant and equipment, primarily Rodemacher Unit 3 and $160.0 million aggregate net pay down of Cleco Corporation’s and Cleco Power’s credit facilities. These decreases were partially offset by cash received from the issuance of bonds.
At December 31, 2008, Cleco and Cleco Power were exposed to concentrations of credit risk through their short-term investments classified as cash equivalents. In order to mitigate potential credit risk, Cleco and Cleco Power have established guidelines for short-term investments. For more on the concentration of credit risk through short-term investments classified as cash equivalents, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 5 - Fair Value of Financial Instruments.”
Cleco Corporation (Holding Company Level)
Cleco Corporation had no short-term debt outstanding at December 31, 2008, or December 31, 2007. At December 31, 2008, Cleco Corporation’s long-term debt outstanding was $30.0 million, of which none was due within one year, compared to $100.0 million of long-term debt of which all was due within one year at December 31, 2007. Cleco Corporation’s 7.00% Senior Notes were repaid May 1, 2008 upon maturity.
Cleco Corporation’s $150.0 million five-year credit facility matures on June 2, 2011. This facility provides for working capital and other needs. Cleco Corporation’s borrowing costs under the facility are equal to LIBOR plus 0.65%, including facility fees. The facility contains the following material covenants:
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a requirement that Cleco maintain at all times total indebtedness equal to or less than 65% of total capitalization;
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a requirement that Cleco maintain a ratio of earnings before interest, taxes, depreciation, and amortization to interest expense as of the end of any fiscal quarter of at least 2.50 to 1.00;
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a prohibition against incurring debt other than under the facility, subject to the following permitted exceptions, among others: (i) up to $425.0 million (less borrowings under the facility) of specified types of other debt may be incurred; (ii) guarantees of Cleco Power obligations and (iii) other specified guarantees, up to specified amounts;
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a prohibition against creating liens upon any property, subject to permitted exceptions;
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restrictions on merging, consolidating, or selling assets outside the ordinary course of business;
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limitations on the payment of dividends, redemptions or repurchases of equity securities and payments in respect of subordinated debt, subject to various exceptions;
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a prohibition against making loans or investments, subject to permitted exceptions, including exceptions for investments of up to $10.0 million per year in subsidiaries other than Cleco Power and loans of up to $20.0 million in the aggregate to such subsidiaries;
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a prohibition against transactions with affiliates, subject to permitted exceptions;
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a prohibition against Cleco and Cleco Power entering into agreements or arrangements that prohibit or restrict their ability to incur liens, or Cleco Power’s ability to pay dividends or to repay debt or make payments to Cleco, subject to permitted exceptions; and
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a prohibition against entering into speculative and other hedge agreements intended to be a borrowing of funds.
At December 31, 2008, $30.0 million was outstanding under Cleco Corporation’s $150.0 million credit facility. The interest rate of outstanding borrowings under the credit facility at December 31, 2008 was 1.725%. Off-balance sheet commitments also reduced available borrowings under the credit facility by $15.0 million, leaving available capacity of $105.0 million. An uncommitted line of credit with a bank in an amount up to $10.0 million is available to support Cleco Corporation’s working capital needs. For more information about these commitments, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 15 - Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees - Off-Balance Sheet Commitments and Disclosures about Guarantees.”
Cash and cash equivalents available at December 31, 2008, were $5.9 million, combined with $105.0 million facility capacity, for total liquidity of $110.9 million. Cash and cash equivalents available at December 31, 2008 decreased $111.1 million when compared to cash and cash equivalents available at December 31, 2007, primarily due to the $100.0 million repayment of Cleco Corporation’s 7.00% senior notes at maturity and the payment of dividends.
Cleco Power
There was no short-term debt outstanding at Cleco Power at December 31, 2008, or December 31, 2007. At December 31, 2008, Cleco Power’s long-term debt outstanding was $1.1 billion, $63.5 million of which was due within one year, compared to $769.1 million at December 31, 2007, of which none was due within one year. The long-term debt due within one year
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represents $50.0 million of medium-term notes which mature in May 2009 and $13.5 million of principal payments for the Cleco Katrina/Rita storm recovery bonds scheduled to be paid in the next twelve months.
For Cleco Power, the $371.3 million debt increase from December 31, 2007, was primarily due to Cleco Katrina/Rita’s issuance of $180.6 million storm recovery bonds, the 2008 issuance by the Rapides Finance Authority of $32.0 million of 6.00% solid waste disposal facility bonds due October 1, 2038, the 2008 issuance by the Louisiana Public Facilities Authority of $100.0 million 7.00% GO Zone bonds due December 1, 2038, and the issuance of $250.0 million of 6.65% senior notes due in 2018. These were partially offset by the $190.0 million repayment on outstanding borrowings under Cleco Power’s credit facility during 2008.
Cleco Power’s $275.0 million five-year credit facility matures on June 2, 2011. This facility provides for working capital and other needs. Cleco Power’s borrowing costs under the facility are equal to LIBOR plus 0.40%, including facility fees. The facility includes the following material covenants:
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a requirement that Cleco Power maintain at all times total indebtedness equal to or less than 65% of total capitalization;
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a requirement that Cleco Power maintain a ratio of earnings before interest, taxes, depreciation, and amortization to interest expense as of the end of any fiscal quarter of at least 2.50 to 1.00;
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a prohibition against creating liens upon any property, subject to permitted exceptions;
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restrictions on merging, consolidating, or selling assets outside the ordinary course of business;
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a prohibition against making loans, subject to permitted exceptions; and
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a prohibition against amending Cleco Power’s Indenture of Mortgage dated July 1, 1950.
At December 31, 2008, and December 31, 2007, Cleco Power had a working capital surplus of $88.0 million and $24.7 million, respectively. Included in working capital at December 31, 2008 and 2007 was $62.3 million and $17.9 million, respectively, which was restricted for the use of debt payments. The $63.3 million increase in working capital is primarily due to net proceeds from the issuance of bonds, partially offset by additions to property plant and equipment, including Rodemacher Unit 3.
At December 31, 2008, no borrowings were outstanding under Cleco Power’s $275.0 million, five-year revolving credit facility. An uncommitted line of credit with a bank in an amount up to $10.0 million also is available to support Cleco Power’s working capital needs.
On March 6, 2008, Cleco Katrina/Rita issued $180.6 million aggregate principal amount of senior secured storm recovery bonds. The bonds were issued in two tranches, with one tranche of $113.0 million initial principal amount with a final maturity date of March 1, 2020 and bearing interest of 4.41% per annum. The other tranche was for $67.6 million initial principal amount with a final maturity date of March 1, 2023 and bearing interest at 5.61% per annum. The resulting weighted average interest rate of both tranches is 4.86% per annum, and the effective weighted average life is seven years. Proceeds from the bonds were used to repay loans under Cleco Power’s revolving credit facility and for general corporate purposes. Debt service for the bonds will be paid by a special monthly storm recovery surcharge paid by all Cleco Power’s retail customers. For the years ended December 31, 2008, and 2007, Cleco Power collected $21.1 million and $24.2 million, respectively, of storm recovery surcharges.
On June 3, 2008, Cleco Power issued $250.0 million aggregate principal amount of senior unsecured notes at an interest rate of 6.65%. The notes mature on June 15, 2018. The net proceeds from this offering were used for general corporate purposes, including financing a portion of the construction costs of Rodemacher Unit 3 and repaying borrowings under Cleco Power’s $275.0 million, five-year revolving credit facility, a portion of which was used to fund some of the construction costs of Rodemacher Unit 3.
The Louisiana State Bond Commission approved the issuance of $152.0 million of tax-exempt bonds to finance the qualifying costs of the solid waste disposal facilities at Rodemacher Unit 3. The Governor’s office allocated $60.0 million for issuance in 2006, another $60.0 million for issuance in 2007, and the remaining $32.0 million for issuance in 2008. These bonds were issued by the Rapides Finance Authority in November 2006, November 2007, and October 2008, respectively. The bonds issued in 2006 have a fixed interest rate of 4.70% per annum, and the maturity date is November 1, 2036. The 2006 bonds may be called at the option of the issuer at the direction of Cleco Power after November 1, 2016. The bonds issued in 2007 initially had a variable interest rate which was reset weekly via an auction agent. In March 2008, Cleco Power exercised a provision in the bond indenture to change the variable interest rate to a fixed interest rate through a reoffering of the bonds. As a part of the reoffering, the holders of the original auction rate bonds were required to tender them. The reoffered bonds have a five-year term with a fixed rate of 5.25% per annum, with the option to call at the end of the five years. If Cleco Power does not call the bonds at the end of the five years, the bonds will become variable rate. Cleco Power currently plans to remarket the bonds at the end of the five-year period. The maturity date of the 2007 bonds is November 1, 2037. The bonds issued in 2008 have a maturity date of October 1, 2038 and initially bear interest at 6.0% per annum until October 1, 2011, at which time they are subject to mandatory tender for purchase at par. Cleco Power plans to remarket the bonds at the end of the three-year period.
On December 10, 2008, the Louisiana Public Facilities Authority issued $100.0 million of GO Zone bonds on behalf of Cleco Power. The bonds mature on December 1, 2038 and initially bear interest rate of 7.00% per annum until December 1, 2011, at which time they are subject to mandatory tender for purchase at par. Cleco Power plans to remarket the bonds at the end of the three-year period. The proceeds from this offering are to be used for new distribution and transmission
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projects in three of the GO Zone parishes: St. Mary, St. Tammany, and Iberia.
Cash and cash equivalents available at December 31, 2008, were $91.5 million, combined with $275.0 million facility capacity for total liquidity of $366.5 million. Cash and cash equivalents at December 31, 2008 increased $79.6 million, when compared to cash and cash equivalents at December 31, 2007. This increase is primarily due to cash received from the issuance of bonds, partially offset by additions to property, plant and equipment, including Rodemacher Unit 3, and payments toward Cleco Power’s credit facility.
In February 2006, the LPSC approved Cleco Power’s plans to build Rodemacher Unit 3. Terms of the approval included acceptance of an LPSC Staff recommendation that Cleco Power collect from customers an amount equal to 75% of the carrying costs of capital during the construction phase of the unit. Cleco Power had collected $85.5 million and $31.5 million at December 31, 2008, and December 31, 2007, respectively. In addition to this recovery, Cleco Power is funding the construction costs related to Rodemacher Unit 3 by utilizing cash on hand, available funds from its credit facility, the issuance of long-term debt, and equity contributions from Cleco Corporation.
Midstream
Midstream had no short- or long-term debt outstanding at December 31, 2008, or December 31, 2007.
Evangeline, which is accounted for under the equity method, had no short-term debt outstanding at December 31, 2008 or December 31, 2007. Evangeline had $168.9 million and $177.1 million of long-term debt outstanding at December 31, 2008, and December 31, 2007, respectively, in the form of 8.82% senior secured bonds due 2019. Of these amounts, $7.1 million and $8.2 million were due within one year at December 31, 2008, and December 31, 2007, respectively. The bonds issued by Evangeline are non-recourse to Cleco Corporation.
Cash Generation and Cash Requirements
Restricted Cash
Various agreements to which Cleco is subject contain covenants that restrict its use of cash. As certain provisions under these agreements are met, cash is transferred out of related escrow accounts and becomes available for general corporate purposes. At December 31, 2008, and 2007, $103.0 million and $18.0 million of cash, respectively, was restricted on Cleco Corporation’s Consolidated Balance Sheets. At December 31, 2008, restricted cash consisted of $0.1 million under the Diversified Lands mitigation escrow agreement, $14.7 million held in escrow for the construction of Cleco Power’s solid waste disposal facilities at Rodemacher Unit 3, $44.6 million reserved at Cleco Power for GO Zone project costs, $27.4 million reserved at Cleco Power for future storm restoration costs, and $16.2 million at Cleco Katrina/Rita restricted for payment of operating expense, interest and principal on storm recovery bonds. Restricted cash at Cleco Power at December 31, 2008, increased $85.0 million compared to December 31, 2007, primarily due to the cash received from the issuance of solid waste disposal facility bonds in October 2008, the issuance of GO Zone bonds in December 2008, the establishment of a restricted reserve at Cleco Katrina/Rita related to the storm recovery bonds in March 2008 and the establishment of a reserve for future storm restoration costs in March 2008. A portion of this storm reserve was utilized during November 2008 to fund operations and maintenance expenses related to damage caused by Hurricanes Gustav and Ike. Evangeline’s restricted cash is not reflected in Cleco Corporation’s Consolidated Balance Sheets due to the equity method of accounting. Evangeline’s restricted cash at December 31, 2008, and 2007, was $25.0 million and $33.3 million, respectively. This cash is restricted under Evangeline’s senior secured bond indenture.
Cleco Cash Flows
Net Cash Provided by Operating Activities
Net cash provided by operating activities was $89.5 million during 2008, $263.0 million in 2007, and $91.4 million in 2006.
Cash from operating activities during 2008 decreased $173.5 million from that reported in 2007, primarily due to the absence of proceeds from the 2007 sale of bankruptcy claims, lower dividends from equity investments, and higher margin deposits. These were partially offset by higher collections of customer accounts and lower retainage payments.
Net cash provided by operating activities increased $171.6 million in 2007 compared to 2006, primarily due to the receipt of proceeds from the sale of bankruptcy claims, higher dividends from equity investments, lower margin deposits, and lower fuel oil and materials inventory purchases. These were partially offset by lower collections of customer accounts.
Net Cash Used in Investing Activities
Net cash used in investing activities was $368.7 million during 2008, $480.7 million in 2007, and $251.0 million in 2006. Net cash used in 2008 was lower than 2007 primarily due to lower additions to property, plant and equipment related to the Rodemacher Unit 3 project. Net cash used in 2007 was higher than 2006 primarily due to higher additions to property, plant and equipment related to the Rodemacher Unit 3 project.
During 2008, Cleco had additions to property, plant and equipment, net of AFUDC, of $270.8 million, a $12.2 million investment in New Market Tax Credits, a $6.4 million investment in Perryville, and $85.0 million of cash became restricted, primarily related to solid waste disposal, GO Zone and storm restoration bonds. This was partially offset by a $4.0 million return of equity from Evangeline.
During 2007, Cleco had additions to property, plant and equipment, net of AFUDC, of $477.2 million, a $2.2 million investment in company- and trust-owned life insurance policies, and an $8.4 million investment in Acadia. This was partially
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offset by a $6.5 million transfer of cash from restricted accounts.
During 2006, Cleco had additions to property, plant and equipment, net of AFUDC, of $228.7 million, a $3.4 million investment in company- and trust-owned life insurance policies, a $24.4 million transfer of cash to restricted accounts, and a $7.0 million investment in Attala. This was partially offset by $11.2 million of dividends, primarily from APH and Perryville.
Net Cash Provided by Financing Activities
Net cash provided by financing activities was $247.7 million during 2008, $154.2 million in 2007, and $132.9 million in 2006. Net cash provided by financing activities in 2008 was higher than 2007 primarily due to the issuance of long-term debt, partially offset by retirements of long-term debt and the absence in 2008 of proceeds from the 2007 conversion of stock options to common stock. Net cash provided by financing activities in 2007 was more than 2006 primarily due to $190.0 million in draws on Cleco Power’s credit facility. This was partially offset by the absence in 2007 of proceeds from the 2006 sale of common stock.
During 2008, Cleco received net proceeds of $651.5 million from the issuance of long-term debt, which was partially offset by $190.0 million of cash used to repay borrowings under Cleco Power’s credit facility and $160.0 million of cash used for repayment of long-term debt.
During 2007, Cleco received $190.0 million from draws on Cleco Power’s credit facility, $60.0 million from the issuance of long-term debt, and $9.5 million from the conversion of stock options to common stock. This was partially offset by $50.3 million of cash used for repayment of long-term debt and $53.7 million used for common and preferred stock dividends.
During 2006, Cleco received $157.5 million of net proceeds from the sale of 6.9 million shares of common stock and $60.0 million from the issuance of long-term debt. This was partially offset by $40.4 million of cash used for repayment of long-term debt and $49.1 million for common and preferred stock dividends.
Cleco Power Cash Flows
Net Cash Provided by Operating Activities
Net cash provided by operating activities was $62.1 million during 2008, $97.6 million in 2007, and $102.7 million in 2006.
Cash from operating activities in 2008 decreased $35.5 million from that reported in 2007, primarily due to higher margin deposits and higher materials inventory purchases. This was partially offset by lower retainage payments.
Cash from operating activities in 2007 decreased $5.1 million from that reported in 2006 primarily due to higher income taxes, and lower collections of customer accounts. These were partially offset by lower fuel oil and materials inventory purchases, and lower margin deposit requirements.
Net Cash Used in Investing Activities
Net cash used in investing activities was $353.2 million during 2008, $469.6 million in 2007, and $251.8 million in 2006. Net cash used in 2008 was $116.4 million lower than 2007 primarily due to lower additions to property, plant and equipment related to the Rodemacher Unit 3 project. Net cash used in 2007 was higher than 2006, primarily due to higher additions to property, plant and equipment related to the Rodemacher Unit 3 project.
During 2008, Cleco Power had additions to property, plant and equipment, net of AFUDC, of $269.7 million compared to $476.2 million and $228.2 million in 2007 and 2006, respectively. This was partially offset by the restriction of $85.0 million of cash, primarily related to solid waste disposal, GO Zone and storm restoration bonds.
Net Cash Provided by Financing Activities
Net cash provided by financing activities was $370.8 million during 2008, compared to $282.1 million in 2007, and $67.5 million in 2006. Net cash provided by financing activities in 2008 was $88.7 million higher than 2007, primarily due to the issuance of long-term debt, partially offset by retirements of long-term debt and the absence in 2008 of the 2007 net contribution from Cleco.
Net cash provided by financing activities in 2007 was $214.6 million higher than 2006 primarily due to $190.0 million in draws on Cleco Power’s credit facility and a net contribution from Cleco of $35.0 million. This was partially offset by retirement of long-term debt.
Shelf Registrations
At December 31, 2008, Cleco Power’s Shelf Registration Statement No. 333-132832 had a remaining capacity allowing for the issuance of $350.0 million in debt securities.
Construction Overview
Cleco allocates its construction budget among its major first-tier subsidiaries - Cleco Power and Midstream. Cleco Power construction costs relate primarily to assets that may be included in Cleco Power’s rate base and, if considered prudent by the LPSC, can be recovered from its customers. Those assets also earn a rate of return authorized by the LPSC and are subject to the rate agreement. Such assets consist of improvements to Cleco Power’s distribution system, transmission system, and generating stations. Midstream’s construction activities pertain predominately to Evangeline and Acadia.
Cleco’s 2009 expenditures for construction and debt maturity are estimated to total $274.0 million, which includes $210.0 million of estimated construction expenditures, excluding AFUDC, and $64.0 million of estimated debt maturity payments. Cleco’s 2009 estimated construction expenditures include $91.0 million for Rodemacher Unit 3 project costs, excluding AFUDC.
For the five-year period ending in 2013, Cleco’s expenditures for construction and debt maturity are expected to total approximately $1.1 billion, which includes $800.0 million of estimated construction expenditures, excluding AFUDC, and $300.0 million of estimated debt maturity payments. Approximately 12% of the planned construction expenditures for the five-year period is expected to be for Cleco Power’s construc-
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CLECO POWER
FORM 10-K
tion of Rodemacher Unit 3. Total additional planned Rodemacher project costs, excluding AFUDC, are estimated at $92.0 million. Approximately 17% of the planned construction expenditures for the five-year period is expected to be for Cleco Power’s portion of the joint project to upgrade the Acadiana Load Pocket transmission system. Total additional planned Acadiana Load Pocket project costs, excluding AFUDC, are estimated at $134.0 million. Approximately 20% of the planned construction expenditures will support line extensions and substation upgrades to accommodate new business and load growth at Cleco Power. The remaining 51% will be for the rehabilitation of older transmission, distribution, and generation assets at Cleco Power and the purchase of computer hardware and software upgrades for Cleco.
Evangeline’s 2009 expenditures for construction and debt are estimated to total $7.0 million, which includes $10.0 million of estimated construction expenditures, partially offset by increased debt of $3.0 million. For the five-year period ending in 2013, Evangeline’s expenditures for construction and debt maturity are expected to total $76.0 million, which includes $26.0 million of estimated construction expenditures and $50.0 million of estimated debt maturity payments. The construction and debt maturity payments for Evangeline are not included in Cleco’s totals due to the equity method of accounting for Evangeline. For more information on the equity method of accounting related to Evangeline, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements -Note 13 - Equity Investment in Investees.” For information on the maturities of Cleco’s debt, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 6 - Debt.”
Acadia’s 2009 expenditures for construction and debt maturity are estimated to total $12.0 million, which includes estimated construction expenditures of $11.0 million and $1.0 million of estimated debt payments. For the five-year period ending in 2013, Acadia’s expenditures for construction are expected to total $29.0 million, which includes $20.0 million of estimated construction expenditures and $9.0 million of estimated debt payments. The construction and debt maturity payments for Acadia are not included in Cleco’s totals due to the equity method of accounting. For more information on the equity method of accounting related to Acadia, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees.”
Cleco believes cash and cash equivalents on hand, together with cash generated from operations, borrowings from credit facilities, and the net proceeds of any issuances of equity or debt securities, will be adequate to fund normal ongoing capital expenditures, working capital, and debt service requirements for the foreseeable future.
Cleco Power Construction Overview
Cleco Power’s construction expenditures, excluding AFUDC, totaled $269.7 million in 2008, $476.2 million in 2007, and $228.2 million in 2006. The increase in construction expenditures from 2006 to 2007, and the decrease in construction expenditures from 2007 to 2008 is primarily due to costs related to the construction at Rodemacher Unit 3.
Cleco Power’s construction expenditures for 2009, excluding AFUDC, are estimated to be $209.0 million. Cleco Power’s 2009 estimated construction expenditures include $91.0 million for Rodemacher Unit 3 project costs, excluding AFUDC. For the five-year period ending in 2013, estimated construction expenditures are expected to total $770.0 million. Approximately 12% of the planned construction is expected to be for Cleco Power’s construction of Rodemacher Unit 3. Total additional planned Rodemacher project costs, excluding AFUDC, are estimated at $92.0 million. Approximately 17% of the planned construction expenditures for the five-year period is expected to be for Cleco Power’s portion of the joint project to upgrade the Acadiana Load Pocket transmission system. Total additional planned Acadiana Load Pocket project costs, excluding AFUDC, are estimated at $134.0 million. Approximately 20% of the planned construction in the five-year period will support line extensions and substation upgrades to accommodate new business and load growth. The remaining 51% will be for the rehabilitation of older transmission, distribution, and generation assets.
The construction of Rodemacher Unit 3 is being performed by Shaw under the Amended EPC Contract. For more information on the EPC contract, see “- Regulatory Matters - Rodemacher Unit 3 - Construction.”
For more information on the Acadiana Load Pocket, see “- Regulatory Matters - Wholesale Rates of Cleco - Acadiana Load Pocket.”
In 2008, 23.0% of Cleco Power’s construction requirements was funded internally. In 2007 and 2006, 20.5% and 45.0%, respectively, of Cleco Power’s construction requirements were funded internally. In 2009, 42% of construction requirements are expected to be funded internally. After the completion of Rodemacher Unit 3 in 2009, 100.0% of the remaining construction requirements are expected to be funded internally for the five-year period ending 2013. All computations of internally funded construction exclude AFUDC.
Other Subsidiary Construction
Other subsidiaries had construction expenditures of $1.0 million during 2008, $1.0 million during 2007, and $0.5 million during 2006. Other subsidiary expenditures for construction and debt payments in 2009 are estimated to total $1.0 million. For the five-year period ending 2013, estimated construction expenditures and debt payments are expected to total $3.0 million. The majority of the planned other construction in the five-year period will consist of upgrades of computer hardware and software for Support Group.
Other Cash Requirements
Cleco Power’s regulated operations and Midstream’s merchant power plants are Cleco’s primary sources of internally generated funds. These funds, along with the issuance of additional debt and equity in future years, will be used for general corporate purposes, construction, and to repay corporate debt.
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Contractual Obligations and Other Commitments
Cleco, in the course of normal business activities, enters into a variety of contractual obligations. Some of these result in direct obligations that are reflected in Cleco’s Consolidated Balance Sheets while others are commitments, some firm and some based on uncertainties, that are not reflected in the consolidated financial statements. The obligations listed in the following table do not include amounts for ongoing needs for which no contractual obligation existed as of December 31, 2008, and represent only the projected future payments that Cleco was contractually obligated to make as of December 31, 2008.
(1)
Long-term debt existing as of December 31, 2008, is debt that has a final maturity of January 1, 2010, or later (current maturities of long-term debt are due within one-year). Cleco’s anticipated interest payments related to long-term debt also are included in this category. Scheduled maturities of debt will total $63.5 million for 2009 and $1.1 billion for the years thereafter. These amounts also include capital lease maturities. For additional information regarding Cleco’s long-term debt, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 6 - Debt” and “- Debt” above.
(2)
Capital leases are maintained in the ordinary course of Cleco’s business activities. These leases include mobile data terminal leases and barges.
(3)
Operating leases are maintained in the ordinary course of Cleco’s business activities. These leases include tolling agreements and towboat, rail car, vehicle, office space, operating facilities, office equipment, and operating equipment leases and have various terms and expiration dates from 1 to 15 years. For additional information regarding Cleco’s operating leases, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 14 - Operating Leases.”
(4)
Significant purchase obligations for Cleco are listed below:
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Fuel Contracts: To supply a portion of the fuel requirements for Cleco Power’s generating plants, Cleco has entered into various commitments to obtain and deliver coal, lignite, petroleum coke, and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. Generally, fuel and purchased power expenses are recovered through the LPSC-established fuel adjustment clause, which enables Cleco Power to pass on to customers substantially all such charges. For additional information regarding fuel contracts, see Part I, Item 1, “Business - Operations - Cleco Power - Fuel and Purchased Power.”
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Power Purchase Agreements: Cleco Power has entered into agreements with energy suppliers for purchased power to meet system load and energy requirements, replace generation from Cleco Power owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. Cleco Power also has entered into agreements to purchase transmission capacity. For additional information regarding power purchase agreements, see “- Regulatory Matters - Generation RFP” below.
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EPC contract: Cleco Power entered into the Amended EPC Contract with Shaw to construct Rodemacher Unit 3. For more information, see “- Regulatory Matters - Rodemacher Unit 3 - Construction.”
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Gas Futures Contracts: Cleco Power entered into natural gas purchase contracts in order to hedge the risk associated with the volatility in the cost of fuel purchased for utility generation and the risk associated with the fixed-price power that is being provided to a wholesale customer through December 2010. For more information, see Item 7A, “Quantitative and Qualitative Disclosures about Market Risk - Risk Overview - Commodity Price Risk.”
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Purchase orders: Cleco has entered into purchase orders in the course of normal business activities.
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For purposes of this table, it is assumed that all terms and rates related to the above obligations will remain the same, and all franchises will be renewed according to the rates used in the table.
(5)
Other long-term liabilities primarily consist of obligations for franchise payments, deferred compensation, facilities use, SERP and other postretirement obligations, and various operating and maintenance agreements.
*
Long-term debt, long-term maintenance agreements, and various other operating and maintenance agreements related to Cleco Corporation’s equity investments in Perryville and Attala, and Midstream’s equity investments in Evangeline and Acadia are not reflected in the chart above. For additional information on these entities, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 13 - Equity Investment in Investees.”
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Other Commitments
The obligations listed in the following table represent the projected future payments that Cleco may be obligated to make relative to uncertain tax positions as of December 31, 2008. For more information on Cleco’s uncertain tax positions, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 10 - Income Taxes - Uncertain Tax Positions.”
In addition to the uncertain tax positions, Cleco has accrued franchise tax and interest of $9.2 million under SFAS No. 5.
Off-Balance Sheet Commitments
Cleco Corporation and Cleco Power have entered into various off-balance sheet commitments, in the form of guarantees and standby letters of credit, in order to facilitate their activities and the activities of Cleco Corporation’s subsidiaries and equity investees (affiliates). Cleco Corporation entered into these off-balance sheet commitments in order to entice desired counterparties to contract with its affiliates by providing some measure of credit assurance to the counterparty in the event Cleco’s affiliates do not fulfill certain contractual obligations. If Cleco Corporation had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with Cleco’s affiliates, or may have contracted with them at terms less favorable to its affiliates.
The off-balance sheet commitments are not recognized on Cleco’s Consolidated Balance Sheets, because it has been determined that Cleco’s affiliates are able to perform these obligations under their contracts and that it is not probable that payments by Cleco will be required. Some of these commitments reduce borrowings available to Cleco Corporation under its credit facility pursuant to the terms of the credit facility. Cleco’s off-balance sheet commitments as of December 31, 2008, are summarized in the following table, and a discussion of the off-balance sheet commitments follows the table. The discussion should be read in conjunction with the table to understand the impact of the off-balance sheet commitments on Cleco’s financial condition.
Cleco Corporation provided a limited guarantee to Entergy Louisiana and Entergy Gulf States for Perryville’s performance, indemnity, representation, and warranty obligations under the Sale Agreement, the Power Purchase Agreement, and other ancillary agreements related to the sale of the Perryville facility. As of December 31, 2008, the aggregate guarantee of $277.4 million is limited to $142.4 million due to the performance of some of the underlying obligations that were guaranteed. The discounted probability-weighted liability under the guarantees and indemnifications as of December 31, 2008, was $0.3 million, resulting in a corresponding reduction in the available credit under Cleco’s credit facility, which was determined in accordance with the facility’s definition of a contingent obligation. The contingent obligation reduces the amount available under the credit agreements by an amount equal to the maximum reasonably anticipated liability in
respect of the contingent obligation as determined in good faith. For additional information on this guarantee, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 15 - Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees.”
In November 2004, Cleco completed the sale of substantially all of the assets of Cleco Energy. Cleco Corporation provided guarantees to the buyers of Cleco Energy’s assets for the payment and performance of the indemnity obligations of Cleco Energy. The aggregate amount of the guarantees is $1.4 million, and the guarantees expire in 2009.
If Evangeline fails to perform certain obligations under its tolling agreement, Cleco Corporation will be required to make payments to the Evangeline Tolling Agreement counterparty. Cleco Corporation’s obligation under the Evangeline
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commitment is in the form of a standby letter of credit from investment grade banks and is limited to $15.0 million. Ratings triggers do not exist in the Evangeline Tolling Agreement. Cleco expects Evangeline to be able to meet its obligations under the tolling agreement and does not expect Cleco Corporation to be required to make payments to the counterparty. However, under the covenants associated with Cleco Corporation’s credit facility, the entire net amount of the Evangeline commitment reduces the amount that can be borrowed under the credit facility. The letter of credit for Evangeline is expected to be renewed annually until 2020.
In January 2006, Cleco Corporation provided a $0.5 million guarantee to Entergy Mississippi for Attala’s obligations under the Interconnection Agreement. This guarantee will be effective through the life of the agreement.
The State of Louisiana allows employers of certain financial net worth to self-insure their workers’ compensation benefits. Cleco Power has a certificate of self-insurance from the Louisiana Office of Workers’ Compensation and is required to post a $0.5 million letter of credit, an amount equal to 110% of the average losses over the previous three years, as surety.
As part of the Lignite Mining Agreement entered into in 2001, Cleco Power and SWEPCO, joint owners of Dolet Hills, have agreed to pay the lignite miner’s loan and lease principal obligations when due, if the lignite miner does not have sufficient funds or credit to pay. Any amounts paid on behalf of the miner would be credited by the lignite miner against the next invoice for lignite delivered. At December 31, 2008, Cleco Power’s 50% exposure for this obligation was approximately $7.4 million. The lignite mining contract is in place until 2011 and does not affect the amount Cleco Corporation can borrow under its credit facility.
The following table summarizes the expected termination date of the guarantees and standby letters of credit discussed above.
Inflation
Annual inflation rates, as measured by the U.S. Consumer Price Index, have averaged approximately 3.31% during the three years ended December 31, 2008. Cleco believes inflation, at this level, does not materially affect its results of operations or financial condition. However, under existing regulatory practice, only the historical cost of a plant is recoverable from customers. As a result, Cleco Power’s cash flows designed to provide recovery of historical plant costs may not be adequate to replace property, plant and equipment in future years.
Regulatory Matters
Generation RFP
Short-Term RFP for 2009 Resources
In March 2008, Cleco Power issued a RFP for a minimum of 50 MW up to 450 MW to meet its 2009 capacity and energy requirements. Cleco Power has selected and negotiated a 235-MW peaking product with Acadia. The product is for supply starting March 1, 2009 and ending October 1, 2009. Cleco Power has received approval for this agreement from the LPSC and FERC.
On January 6, 2009, Cleco Power issued a RFP for a minimum capacity amount of 50 MW up to 200 MW in order to serve additional load. The requested products for supply will start April 1, 2009 and continue through October 31, 2009. On February 9, 2009, a winning bidder was selected. Cleco Power is currently negotiating the terms of the contract and anticipates signing a power purchase agreement by the end of the first quarter of 2009.
Long-Term RFP
In June 2007, Cleco Power filed a proposed RFP with the LPSC for up to approximately 600 MW of intermediate and/or peaking resources to meet projected load growth over a 10-year period beginning in 2010. To meet these needs, Cleco Power is looking for products for a term of 2 to 30 years. Out of the approximately 600-MW total, up to approximately 350 MW may be sourced from a peaking resource. After LPSC review, the RFP was issued in October 2007, and bids were received in December 2007. On February 26, 2009, Cleco Power announced that it had chosen the acquisition of 50 percent of the Acadia power station, or one of its two 580-MW units, as the lowest bid in its 2007 long-term RFP. Cleco Power will own and operate one unit and operate the other 580-MW unit on behalf of Acadia. Prior to closing the transaction, valued at approximately $300.0 million, Cleco Power must complete its due diligence, finalize and execute definitive agreements, and receive approvals from the LPSC and FERC. Cleco Power and Acadia plan to complete the transaction by the end of 2009 in a process that remains under the supervision of an independent monitor appointed by the LPSC.
Rodemacher Unit 3
Background
Cleco Power is in the process of constructing Rodemacher Unit 3, which will provide a portion of the utility’s power supply
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needs. Rodemacher Unit 3 will be capable of burning various solid fuels but primarily is expected to burn petroleum coke produced by several refineries throughout the Gulf Coast region. Cleco Power has entered into contracts with suppliers to collectively supply over 900,000 tons per year of petroleum coke for a three- to five-year period beginning in 2009, representing two-thirds of Rodemacher Unit 3 fuel requirements for such period. Cleco Power is in late stage negotiations to procure the remaining Rodemacher Unit 3 fuel requirements for such period. All environmental permits for the unit have been received. By Shaw’s estimations, physical construction is estimated at 87% complete as of December 31, 2008. Cleco Power anticipates the plant will be substantially complete and operational in the second half of 2009.
CCN
In May 2006, the LPSC issued its order granting Cleco Power a CCN to construct, own, and operate Rodemacher Unit 3. The CCN authorizes Cleco Power to issue up to $700.0 million of securities and other financial instruments during the 2006 through 2010 time frame in order to finance Rodemacher Unit 3. The CCN requires that Cleco Power provide the LPSC Staff with an advanced review of any specific long-term debt issuance, and the Staff has the right to object.
A condition within the LPSC’s implementing order requires that Cleco Power submit periodic updates during the construction phase of Rodemacher Unit 3. At its September 2006 business meeting, the LPSC approved a Rodemacher Unit 3 post-certification monitoring plan that requires, at least quarterly, reports addressing construction progress, expenditures, project financing, environmental compliance, and other related matters. Cleco Power is in compliance with this monitoring plan. The monitoring plan will remain in place for at least six months after the unit begins commercial operation.
Construction
In May 2006, Cleco Power and Shaw entered into an Amended EPC Contract, which provided for substantial completion of the construction of Rodemacher Unit 3 by September 30, 2009. On July 2, 2008, Cleco Power and Shaw amended this contract further to provide for substantial completion as early as June 30, 2009, as well as changes to other commercial terms for a lump-sum price of $794.5 million. As a result of the amendment, Cleco Power is no longer liable for excess labor costs as contemplated under the original agreement. The total capital cost estimate for the project, including AFUDC, Amended EPC Contract costs, and other development expenses, remains at $1.0 billion. As of December 31, 2008, Cleco Power had incurred approximately $865.7 million in project costs, including AFUDC. Under the Amended EPC Contract, Shaw is subject to payment of liquidated damages if certain operating performance criteria and schedule dates are not met. The Amended EPC Contract allows for termination at Cleco Power’s sole discretion, which would require payment of termination fees, or if certain milestones, approvals, or other typical commercial terms and conditions are not met. As of December 31, 2008, the maximum termination costs would have been $761.7 million or an additional $21.4 million more than the capital expended to date. In support of its performance obligations, Shaw has provided a $58.9 million letter of credit to Cleco Power. In addition to the letter of credit, Shaw also posted a $200.0 million payment and performance bond in favor of Cleco Power in support of its performance obligations under the Amended EPC Contract. The Amended EPC Contract also provides for Shaw to: (a) allow retention, or (b) issue an additional letter of credit, in an amount equal to 7.5% of the payments made by Cleco Power under the contract. Effective January 31, 2008, Shaw had issued an additional letter of credit in the amount of $42.0 million and Cleco has retained amounts of $12.7 million. The retention and letters of credit are provided in support of Shaw’s potential payment of liquidated damages, or other payment performance obligations. The Amended EPC Contract also provides in the event Cleco Power does not maintain a senior unsecured credit rating of either: (i) Baa3 or better from Moody’s or (ii) BBB- or better from Standard & Poor’s, Cleco Power will be required to provide a letter of credit to Shaw in the amount of $20.0 million. In the event of further downgrade to both of its credit ratings to: (i) Ba2 or below from Moody’s, and (ii) BB or below from Standard & Poor’s, Cleco Power will be required to provide an additional $15.0 million letter of credit to Shaw.
In December 2008, Cleco Power received correspondence from Shaw requesting recovery of $12.3 million in force majeure related costs and a schedule extension of fifteen days allegedly incurred as a result of Hurricanes Gustav and Ike. Cleco Power is reviewing the documentation for validity and applicability. The Registrants do not believe the resolution of this potential claim will have a material adverse impact to the Registrants’ results of operations or financial condition. Additionally, the Registrants do not believe the resolution of this potential claim will have a material adverse impact on the cost of Rodemacher Unit 3.
Environmental Matters
For information on environmental matters, see Part I, Item 1, “Business - Regulatory Matters, Industry Developments, and Franchises - Environmental Matters.”
Retail Rates of Cleco Power
Retail rates regulated by the LPSC accounted for approximately 97% of Cleco Power’s 2008 and 2007 revenue.
Fuel Rates
The cost of fuel used for electric generation and the cost of power purchased for utility customers are recovered through an LPSC-established fuel adjustment clause that enables Cleco Power to pass onto its customers substantially all such charges. These fuel and purchased power costs are subject to audit by the LPSC pursuant to the Fuel Adjustment Clause General Order issued in November 1997 in Docket No. U-21497, which anticipates that an audit will be performed not less than every other year. The LPSC has reviewed Cleco Power’s fuel and purchased power costs through the year
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and, in July 2006, began an audit of Cleco Power’s fuel adjustment clause filings for the period January 2003 through December 2004. Management is currently unable to predict the timing of the fuel cost audits for the open years 2005 through 2008. Cleco Power could be required to make a substantial refund of previously recorded revenue as a result of these audits, and such refund could result in a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
To help stabilize electricity costs, the LPSC in 2001 suggested hedging the exposure to natural gas price volatility through the use of financial instruments. Cleco Power hedges a portion of the projected natural gas volumes used to serve its native electric load during each year. The hedge quantity is reviewed and adjusted periodically based on projected market indicators.
In February 2008, the LPSC opened an inquiry and issued a request for comments to investigate the potential for incentive-based mechanisms for fuel cost recovery. Management is unable to predict the time of completion and cannot determine the impact any potential rulemaking may have on the financial condition and results of operations of Cleco Power.
Base Rates
Beginning in 1996, the amount of Cleco Power’s yearly retail earnings has been subject to the terms of a RSP established by Cleco Power and the LPSC in a 1996 earnings review settlement. The RSP establishes a target return on common equity and requires all or a portion of regulated earnings for each yearly review period above the targeted regulatory rate of return on equity to be credited to Cleco Power’s customers.
The terms of the current RSP were approved by the LPSC in July 2006, and became effective October 1, 2006, along with Cleco Power’s request to extend the terms of the RSP to the in-service date of Rodemacher Unit 3, which is expected to begin commercial operations in the second half of 2009. The current RSP allows Cleco Power the opportunity to earn a maximum regulated return on equity of 11.65%. This maximum return is based on a return on equity of 11.25%, with any regulated earnings between 11.25% and 12.25% shared between shareholders and customers in a 40/60 ratio. All regulated earnings over 12.25% will be returned to customers. The amount of credits due customers, if any, is determined by Cleco Power and the LPSC annually, based on results for each 12-month period ended September 30. The RSP terms require the credits to be included on customers’ bills the following summer.
For information concerning amounts accrued and refunded by Cleco Power as a result of the RSP and information on the Staff’s RSP reviews, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 12 - Electric Customer Credits.”
The LPSC directed Cleco Power to file a full base rate case at least 12 months prior to the expected in-service date of Rodemacher Unit 3. On July 14, 2008, Cleco Power filed a request for a new rate plan with the LPSC to increase its base rates for electricity. Cleco Power is seeking recovery of revenues sufficient to cover the addition of Rodemacher Unit 3 to its existing expense and rate base levels. Although base revenues will increase under Cleco Power’s proposed rate plan, fuel costs and collection of financing charges are expected to decrease. Seven industrial customers have filed interventions in the rate case, which is currently in the discovery phase. At this time, Cleco Power anticipates a settlement of the rate case in the second quarter of 2009. The new rates are expected to be effective upon the commercial operation date of Rodemacher Unit 3. For information relating to the risks associated with Cleco Power’s rate increase request, see Part I, Item 1A, “Risk Factors - Rodemacher Unit 3 Construction Costs” and “- Cleco Power’s Rates and Rate Case.”
Storm Cost Recovery
During 2006, the LPSC approved an interim rate increase to recover storm restoration costs incurred by Cleco Power relating to Hurricanes Katrina and Rita. In September 2007, the LPSC approved securitization and recovery of Cleco Power’s storm restoration costs related to Hurricanes Katrina and Rita. In March 2008, the securitization financing was completed, collection of the interim surcharge ceased, and the right to bill and collect unamortized storm damage costs from customers was sold to Cleco Katrina/Rita, a special purpose, wholly owned subsidiary of Cleco Power. As part of the approval, the LPSC also authorized the funding and securitization of a $50.0 million reserve for Cleco Power’s future, extraordinary storm costs. For information concerning the recovery of storm restoration costs relating to Hurricanes Katrina and Rita, see Item 8, “Financial Statements and Supplementary - Notes to the Financial Statements - Note 3 - Regulatory Assets and Liabilities - Deferred Storm Restoration Costs - Katrina/Rita.”
In September 2008, Cleco Power’s distribution and transmission systems sustained substantial damage from Hurricanes Gustav and Ike. The current estimate of the cost of restoration for Hurricanes Gustav and Ike totaled approximately $78.7 million, of which approximately 84% related to Hurricane Gustav and the remaining 16% to Hurricane Ike. Of the $78.7 million, $46.7 million was capitalized, and with approval from the LPSC, the remaining uncapitalized costs were offset against Cleco Power’s existing storm damage reserves. Restoration costs incurred by Cleco Power from damage caused by Hurricanes Gustav and Ike are subject to a prudency review by the LPSC in which Cleco Power will be required to demonstrate that the restoration costs were prudently incurred. Accordingly, Cleco Power may not be able to recover some of the storm costs incurred, which could be material. The costs are being reviewed by the LPSC as part of Cleco’s pending rate case. If the LPSC were to deny Cleco Power’s request to recover substantial restoration costs incurred, such a decision could have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
IRP
For information on Cleco Power’s IRP team and its evaluation of generation supply options, see Part I, Item 1, “Business -
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Operations - Cleco Power - Fuel and Purchased Power - Power Purchases.”
Wholesale Rates of Cleco
Power Sales
Cleco’s wholesale electric power sales are regulated by FERC via cost- and market-based tariffs. Both Evangeline and Acadia have received approval by FERC to use market-based rates based on Cleco’s initial request to FERC in 1999 for market-based rates and Cleco’s demonstration of its lack of market power. These tariffs, including the associated codes of conduct accompanying them, are updated periodically to comply with FERC directives. Cleco updates its filing every three years to demonstrate its lack of market power. Such an update was completed in December 2003 for each entity to comply with FERC’s requirement to amend market-based rates to add “market behavior rules” to the codes of conduct. Contracts utilizing market-based tariffs do not require prior approval by FERC but are reported each quarter pursuant to FERC’s requirement for reporting of sales by authorized power marketers.
In April 2004, FERC issued an order revising the methodology to be used in assessing whether a jurisdictional electric utility has generation market power, requiring a utility to pass a screening test as a condition for securing and/or retaining approval to sell electricity in wholesale markets at market-based rates. Reviews conducted by FERC in 2005 and 2006 of filings submitted by Cleco’s authorized power marketing entities, Cleco Power, Evangeline, and Acadia, concluded that Cleco had demonstrated a lack of market power in Cleco Power’s control area, and the power marketing entities may continue to charge market-based rates for wholesale power. Currently, Cleco Power’s next scheduled market power analysis is due to FERC by June 30, 2009.
Transmission Service
Cleco’s electric transmission rates are regulated by FERC via cost-based, pro forma open access transmission tariffs (OATTs), a FERC-approved document outlining rates, charges, rules and conditions under which a utility provides electric transmission service. The pro forma OATT was instituted by FERC in 1996 with the issuance of Order Nos. 888 and 889. These orders required FERC-regulated electric utilities to offer third parties access to transmission under terms and conditions comparable to the terms and conditions followed by the utilities for use of their own systems. The goal of these orders was to ensure that the provision of transmission service is reasonable and not unduly discriminatory or preferential.
On February 15, 2007, FERC issued Order No. 890 amending its regulations and the pro forma tariff adopted in FERC Order Nos. 888 and 889. The amendments addressed apparent deficiencies in the pro forma tariff and standardized several industry practices relating to the provision of wholesale transmission service. The order became effective on May 14, 2007, and contained various implementation deadlines ranging from 30 days to one year. Order No. 890 was modified by FERC with Order No. 890-A and 890-B, effective March 2008 and September 2008, respectively, which clarified certain changes to the pro forma OATT adopted in Order No. 890. Cleco Power has incorporated these new requirements and business practices into its operations and anticipates no significant impact to Cleco.
Acadiana Load Pocket
In September 2008, Cleco Power entered into an agreement with Lafayette Utilities System, a municipal utility, and Entergy Gulf States Louisiana, a subsidiary of Entergy Corporation, to upgrade interconnected transmission systems in south Louisiana. The project received LPSC approval in February 2009 and confirmation that it is in the public’s interest. Also in February 2009, approval was received from the SPP, Cleco Power’s reliability coordinator, to begin construction. The joint project includes expanding and upgrading the electric transmission infrastructure in south central Louisiana in an area known as the “Acadiana Load Pocket.”
The project includes upgrades to certain existing electric facilities as well as the construction of new substations, transmission lines, and capacitor banks. The total estimated cost is approximately $200.0 million. Each utility is responsible for various components of the project. Cleco Power’s portion of the cost is approximately $150.0 million, including AFUDC. Construction is anticipated to begin in 2009 with the final phase completed in 2012. Upgrading the interconnected transmission system is expected to increase capacity, reduce transmission constraints, and improve electric service for customers served by all three utilities.
Franchises
For information on the treatment of franchise fees paid to municipalities by the state’s utilities, see Part I, Item 1, “Business - Regulatory Matters, Industry Developments, and Franchises - Franchises.”
Market Restructuring
Wholesale Electric Markets
Regional Transmission Organization
In 1999, FERC issued Order No. 2000, which established a general framework for all transmission-owning entities in the nation to voluntarily place their transmission facilities under the control of an appropriate RTO. Although participation was voluntary, FERC made it clear that any jurisdictional entity not participating in a RTO likely would be subject to regulatory directives. FERC later relaxed its mandate to participate in a RTO, but continued to insist upon large regional models. Many transmission-owning entities and system operators have been trying to interpret and implement FERC’s directives by attempting to organize and/or join acceptable RTOs. In October 2004, FERC granted the SPP status as a RTO.
In April 2004, Entergy filed at FERC to make potentially significant modifications to its transmission tariff. The
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modifications would incorporate an independent third-party entity, the ICT, into its transmission operations, with the ICT having access to pertinent information regarding the Entergy transmission system. After receiving approval from FERC and state commissions (including the LPSC), the SPP began a four-year trial as Entergy’s acting ICT on November 17, 2006.
As with RTO developments at large, other various parties, including several state commissions, utilities, and other industry participants, are participants in the RTO and Entergy proceedings described above. As both the SPP and Entergy proceedings could impact the ability to transport power into and out of the Cleco control area, Cleco will continue monitoring developments in these proceedings and plans to be a participant in these and all other proceedings affecting the availability and sale of power in and around Louisiana.
Electric Reliability Organization
The Energy Policy Act of 2005 added Section 215 to the Federal Power Act, which provides for a uniform system of mandatory, enforceable reliability standards. In July 2006, FERC named the NERC as the ERO that will be required to develop the mandatory reliability standards. Formed in 1968, NERC’s goal is to help maintain and improve the reliability of North America’s bulk power system. All public utilities subject to FERC’s authority will be required to comply with the incorporated standards and could be subjected to financial penalties if they violate FERC’s reliability or business practice standards. In March 2007, FERC issued Order No. 693 approving 83 standards submitted by NERC for approval. The rules essentially deal with documentation and the standardization of practices across the industry. FERC began enforcement of these standards on June 18, 2007. Cleco Power has incorporated these new reliability standards into its operations. Cleco will continue to monitor and provide input in the development of new proposed standards and will implement processes as necessary to achieve compliance with the standards.
For a discussion of risks associated with FERC’s regulation of Cleco Power’s wholesale electric business, see Part I, Item 1A, “Risk Factors - ERO.”
Retail Electric Markets
Cleco Power and a number of parties, including other Louisiana electric utilities, certain power marketing companies, and various associations representing industry and consumers, have been participating in electric industry restructuring activities before the LPSC since 1997. During 2000, the LPSC Staff developed a transition to competition plan that was presented to the LPSC. In November 2001, the LPSC directed its Staff to monitor neighboring jurisdictions and to report back the success or failure of those efforts 12 months after any such initiatives begin. In September 2004, the LPSC reviewed a large customer retail choice pilot program study compiled by the Louisiana State University Center for Energy Studies. The study concluded that retail customers 5 MW or larger could lower their electric costs through direct access to overbuilt regional electric markets. The study also concluded that there would be minimal negative impact to remaining customers based on utilities’ ability to avoid purchase power costs for existing large customers. Cleco Power filed comments on the study in January 2005 stating the study’s suggested savings were overstated, and the impact on remaining captive customers was understated. In April 2005, the LPSC conducted a technical conference to discuss retail choice for large customers. At this time, Cleco cannot predict whether any regulation enacting a large customer pilot program or otherwise affecting Cleco Power will be adopted and, if adopted, what form such legislation or regulation may take. A potentially competitive environment presents both the opportunity to supply electricity to new customers and the risk of losing existing customers. Cleco Power is striving to be able to compete effectively should retail access be adopted at some future time in Louisiana. At this time, the LPSC has deferred pursuing retail open access pending developments at the federal level and in other states.
In April 2002, the LPSC adopted order R-26172 governing the way electric generation sources are to be solicited and tested versus self-build options of a utility. Cleco Power conducted a RFP pursuant to this order during 2003. In January 2004, the LPSC amended its prior order to formally add the requirement that the soliciting utility employ an independent monitor. The independent monitor’s role is to assure the RFP process is run fairly, that bidder data is treated confidentially, and that no preference is afforded bids from affiliate companies of the utility or the utility’s own self-build proposals. For additional information on Cleco Power’s 2007, 2008 and 2009 RFPs, see “- Regulatory Matters - Generation RFP.”
Currently, the LPSC does not provide exclusive service territories for electric utilities under its jurisdiction. Instead, retail service is obtained through a long-term nonexclusive franchise. The LPSC uses a “300-foot rule” for determining the supplier for new customers. The “300-foot rule” requires a customer to take service from the electric utility that is within 300 feet of the respective customer. If the customer is beyond 300 feet from any existing utility service, they may choose their electric supplier. The LPSC is currently reviewing its “300 foot rule” (Docket No. R-28955). Management is unable to predict the time of completion and cannot determine the impact any potential rulemaking may have on the financial condition and results of operations of Cleco Power. The application of the current rule has led to competition with neighboring utilities for retail customers at the borders of Cleco Power’s service areas. Such competition has led to complaints by competitors that Cleco Power has violated the 300-foot rule. Several complaints have been made by competitors who operate as rural electric cooperatives and, if the LPSC were to rule in favor of such competitors, Cleco Power may be fined. Management does not believe any such fines, if imposed, would have a material impact on Cleco Power’s financial condition. Cleco Power also competes in its service area with suppliers of alternative forms of energy, some of which may be less costly than electricity for certain applications. Cleco Power could experience some competition for electric sales to industrial customers in the form of cogeneration or from independent power producers.
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For information on dual franchise attempts, see Part I, Item 1, “Business - Regulatory Matters, Industry Developments, and Franchises - Franchises.”
Other Matters
Lignite Deferral
Cleco Power operates a generating unit jointly owned with SWEPCO that uses lignite as its fuel source.
In May 2001, Cleco Power (along with SWEPCO) entered into the Lignite Mining Agreement with DHLC, the operator of the Dolet Hills mine. As ordered then by the LPSC, Cleco Power’s retail customers began receiving fuel cost savings equal to 2% of the projected costs under the previous mining contract (the benchmark price) through the year 2011. Actual mining costs incurred above 98% of the benchmark price were deferred, and could be recovered from retail customers through the fuel adjustment clause only when the actual mining costs are below 98% of the benchmark price. The benchmark price used the GDP-IPD index as a proxy for the numerous escalators in the previous mining contract. During the course of the contract, Cleco Power and SWEPCO determined that the GDP-IPD index did not appropriately reflect the increase in mining costs caused by sharp increases in diesel fuel and electricity costs associated with the mining operation. Because of this disconnect between the GDP-IPD index and actual mining costs, a significant amount of mining costs was being deferred by Cleco Power. At December 31, 2008, and 2007, Cleco Power had $26.8 million and $29.4 million, respectively, in deferred costs remaining uncollected.
In 2006, Cleco Power recognized that there was a possibility it may not recover all or part of the lignite mining costs it had deferred. On November 15, 2006, Cleco Power and SWEPCO submitted a joint application to the LPSC requesting approval for Cleco Power to recover its existing deferral balance, and eliminate any future benchmarking of lignite mining costs. In December 2007, the LPSC approved a settlement agreement between Cleco Power, SWEPCO and the LPSC Staff authorizing Cleco Power to recover the existing deferred mining cost balance, including interest, over approximately 11.5 years. The settlement also established a new benchmark utilizing the contract’s escalators to assure a minimum 2% savings to customers compared to the costs under the prior mining contract. This benchmarking will end after April 2011. Cleco Power and SWEPCO also agreed to commit to continued operation of the mining operation through 2016 as long as the operation of the mine was considered prudent. Cleco Power has not recorded any additional deferred fuel costs under the new benchmarking method.
Pension Protection Act of 2006
In August 2006, the President signed the Pension Protection Act of 2006. The new law replaces the defined benefit pension plan funding rules with a new funding system that became effective in 2008. Plan contributions are required if assets are less than 100% of liabilities. Pension plans that were not fully funded at the beginning of 2008 were to meet interim targets of 92% in 2008, 94% in 2009, and 96% in 2010.
Furthermore, the calculation for the pension funding liability was subject to a new methodology beginning in 2008. The new methodology features the yield on investment grade corporate bonds (of the highest quality rating levels) with maturity dates that match the durations of the pension liabilities owed plan participants (broken down into three maturity segments). A temporary extension of the single corporate bond rate remained in effect for plan year 2007.
In December 2008, this Act was amended. The primary amendments include allowing a phase-in of the funding targets, allowing a 24-month asset smoothing and allowing plans to look back to prior year funding percentages to determine restrictions on benefits.
Cleco expects the implementation of the Pension Protection Act, in conjunction with the material 2008 plan portfolio losses, will result in annual pension contributions going-forward that are significantly higher than those estimates calculated in prior years. For a discussion of certain risks related to the global financial crisis, see item 1A, “Risk Factors - Global Financial Crisis.”
New Accounting Standards
For discussion of new accounting standards, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 2 - Summary of Significant Accounting Policies - Recent Accounting Standards.”
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk Overview
Market risk inherent in Cleco’s market risk-sensitive instruments and positions includes potential changes arising from changes in interest rates and the commodity market prices of power and natural gas in the industry on different energy exchanges. Cleco is subject to market risk associated with economic hedges relating to open natural gas contracts. Cleco also is subject to market risk associated with its remaining tolling agreement counterparty. For additional information concerning Cleco’s market risk associated with its remaining counterparty, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - General Considerations and Credit-Related Risks.”
Cleco uses SFAS No. 133 to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market. Generally, Cleco Power’s market risk-sensitive instruments and positions qualify for the normal-purchase, normal-sale exception to mark-to-market accounting of SFAS No. 133, as modified by SFAS No. 149, since Cleco Power takes physical delivery and the instruments and positions are used to satisfy customer requirements.
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Cleco’s exposure to market risk, as discussed below, represents an estimate of possible changes in the fair value or future earnings that would occur, assuming possible future movements in the interest rates and commodity prices of power 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.
Cleco monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide aggregate counterparty credit exposure, and corporate-wide aggregate counterparty concentration levels. Cleco manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits or letters of credit from counterparties or their affiliates, as deemed necessary. Cleco Power has agreements in place with various counterparties that authorize the netting of financial transactions and contract payments to mitigate credit risk for transactions entered into for risk management purposes.
Access to capital markets is a significant source of funding for both short-term and long-term capital requirements not satisfied by operating cash flows. Recent market conditions have limited the availability and have increased the costs of capital for many companies. The inability to raise capital on favorable terms could negatively affect Cleco’s ability to maintain and expand its businesses. After assessing the current operating performance, liquidity, and credit ratings, management believes that it will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. If Cleco Corporation’s or Cleco Power’s credit ratings were to be downgraded by Moody’s or by Standard & Poor’s, Cleco Corporation or Cleco Power, as the case may be, would be required to pay additional fees and higher interest rates under its bank credit and other debt agreements.
Interest Rate Risks
Cleco monitors its mix of fixed- and variable-rate debt obligations in light of changing market conditions and from time to time may alter that mix, for example, refinancing balances outstanding under its variable-rate credit facility with fixed-rate debt. For details, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 6 - Debt.” Calculations of the changes in fair market value and interest expense of the debt securities are made over a one-year period.
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, 2008, the carrying value of Cleco’s long-term fixed-rate debt was approximately $1.1 billion, with a fair market value of approximately $1.1 billion. There is a $62.7 million difference between the carrying value of the debt and the market value of such debt, which is driven by the spread between the stated rate of Cleco’s debt as compared to the current market yield for debt with similar risk profiles, maturities, and terms as Cleco’s debt. Fair value was determined using quoted market prices. Each 1% increase in the average interest rates applicable to such debt would result in a corresponding decrease of approximately $83.6 million in the fair value of these instruments. If these instruments are held to maturity, no change in stated value will be realized.
At December 31, 2008, Cleco had $30.0 million principal amount of long-term variable-rate debt outstanding under its $150.0 million five-year credit facility at an interest rate of 1.725%. The borrowings under the credit facility are considered long-term as the credit facility does not expire until 2011. The borrowing costs under the facility are equal to LIBOR plus 0.65%, including facility fees. The existing borrowing had a 30-day term and matured January 15, 2009. The amounts of the borrowings were renewed at maturity, rather than repaid. Each 1% increase in the interest rate applicable to such debt would have resulted in a $0.3 million decrease in pre-tax earnings of Cleco. Cleco had no short-term variable-rate debt as of December 31, 2008.
Commodity Price Risks
Management believes Cleco has controls in place to minimize the risks involved in its financial and energy commodity activities. Independent controls over energy commodity functions consist of a middle office (risk management), a back office (accounting), regulatory compliance staff, as well as oversight by a risk management committee comprised of officers and the General Manager - Internal Audit, who are appointed by Cleco Corporation’s Board of Directors. VaR limits are recommended by the Risk Management Committee and monitored through a daily risk report that identifies the current VaR and market conditions.
During 2005, Cleco Power entered into certain financial hedge transactions it considers economic hedges to mitigate the risk associated with fixed-price power to be provided to a wholesale customer through December 2010. These transactions are derivatives as defined by SFAS No. 133 but do not meet the accounting criteria to be considered hedges. These transactions are marked-to-market with the resulting gain or loss recorded on the income statement as a component of operating revenue, net. At December 31, 2008, the positions had a mark-to-market loss of $0.2 million, which is a decrease of $2.2 million from the mark-to-market value of $2.0 million at December 31, 2007. In addition, these positions resulted in a realized gain of $0.9 million in 2008. In light of these economic hedge transactions, volatility in natural gas prices will likely cause fluctuations in the market value of open natural gas positions and ultimately in Cleco Power’s future earnings.
Cleco Power provides fuel for generation and purchases power to meet the power demands of customers. Cleco Power has entered into positions to mitigate the volatility in customer fuel costs, as encouraged by an LPSC order. In December 2004, Cleco Power implemented a fuel stabilization
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policy (which was filed with the LPSC and subsequently amended in June 2006) to target higher levels of minimum hedging percentages and mitigate the volatility in customer fuel costs. The change in positions could result in increased volatility in the marked-to-market amounts for the financial positions. These positions are marked-to-market with the resulting gain or loss recorded on the balance sheet as a component of the accumulated deferred fuel asset or liability and a component of the risk management assets or liabilities. When these positions close, actual gains or losses are deferred and included in the fuel adjustment clause in the month the physical contract settles. Based on market prices at year end, the net mark-to-market impact related to open natural gas positions at December 31, 2008, and 2007, were losses of $57.4 million and $7.0 million, respectively. Deferred losses relating to closed natural gas positions at December 31, 2008, and 2007, totaled $6.4 million and $3.1 million, respectively.
Cleco utilizes a VaR model to assess the market risk of its hedging portfolios, including derivative financial instruments. VaR represents the potential loss in fair value for an instrument from adverse changes in market factors over a defined period of time with a specified confidence level. VaR is calculated daily, using the variance/covariance method with delta approximation, assuming a holding period of one day, and a 95% confidence level for natural gas and power positions. Volatility is calculated daily from historical forward prices using the exponentially weighted moving average method.
Based on these assumptions, the VaR relating to Cleco Power’s hedge transactions for 2008, as well as the VaR at December 31, 2008, and 2007, are summarized in the following table.
All open positions were transacted by Cleco Power. The increase in VaR at December 31, 2008, compared to December 31, 2007, is primarily due to market volatility. Under Cleco’s VaR model, changes in market value of open positions in excess of $0.2 million over Cleco’s estimated VaR are deemed material. During 2008, the $0.2 million limit was exceeded two times.
The following table summarizes the market value maturities of open natural gas contracts at December 31, 2008. All contracts were transacted by Cleco Power.
For additional information on the market value maturities of contracts, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 5 - Fair Value of Financial Instruments.”
Cleco Power
Please refer to “- Risk Overview” above for a discussion of market risk inherent in Cleco Power’s market risk-sensitive instruments.
Cleco Power has entered into various fixed- and variable-rate debt obligations. For details, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 6 - Debt.” Please refer to “- Interest Rate Risks” above for a discussion of how Cleco Power monitors its mix of fixed- and variable-rate debt obligations and the manner of calculating changes in fair market value and interest expense of its debt obligations.
As of December 31, 2008, the carrying value of Cleco Power’s long-term fixed-rate debt was approximately $1.1 billion, with a fair market value of approximately $1.1 billion. There is a $62.7 million difference between the carrying value of the debt and the market value of such debt, which is driven by the spread between the stated rate of Cleco Power’s debt as compared to the current market yield for debt with similar risk profiles, maturities, and terms as Cleco Power’s debt. Fair value was determined using quoted market prices. Each 1% increase in the average interest rates applicable to such debt would result in a corresponding decrease of approximately $83.6 million in the fair values of these instruments. If these instruments are held to maturity, no change in stated value will be realized.
At December 31, 2008, Cleco Power had no long-term or short-term variable-rate debt outstanding.
Please refer to “- Commodity Price Risks” above for a discussion of controls, transactions, VaR, and market value maturities associated with Cleco Power’s energy commodity activities.
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ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of
Directors of Cleco Corporation:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Cleco Corporation (the "Company") and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions in 2007, the manner in which it accounts for share-based compensation in 2006 and the manner in which it accounts for defined benefit pension and other postretirement plans effective December 31, 2006.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
New Orleans, Louisiana
February 26, 2009
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Consolidated Statements of Income
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Consolidated Balance Sheets
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Consolidated Statements of Comprehensive Income
Consolidated Statements of Changes in Common Shareholders’ Equity
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Report of Independent Registered Public Accounting Firm
To the Member and Board of
Managers of Cleco Power LLC:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15 (a)(1) present fairly, in all material respects, the financial position of Cleco Power LLC and its subsidiary at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 15 (a)(2) presents fairly, in all material aspects, 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 based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards 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.
As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions in 2007, the manner in which it accounts for share-based compensation in 2006 and the manner in which it accounts for defined benefit pension and other postretirement plans effective December 31, 2006.
/s/ PricewaterhouseCoopers LLP
New Orleans, Louisiana
February 26, 2009
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Consolidated Statements of Income
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Consolidated Balance Sheets
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Consolidated Statements of Cash Flows
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Consolidated Statements of Comprehensive Income
Consolidated Statements of Changes in Member’s Equity
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Index to Applicable Notes to the Financial Statements of Registrants
Note
The Company
Cleco Corporation and Cleco Power
Note
Summary of Significant Accounting Policies
Cleco Corporation and Cleco Power
Note
Regulatory Assets and Liabilities
Cleco Corporation and Cleco Power
Note
Jointly Owned Generation Units
Cleco Corporation and Cleco Power
Note
Fair Value of Financial Instruments
Cleco Corporation and Cleco Power
Note
Debt
Cleco Corporation and Cleco Power
Note
Common Stock
Cleco Corporation and Cleco Power
Note
Preferred Stock
Cleco Corporation
Note
Pension Plan and Employee Benefits
Cleco Corporation and Cleco Power
Note
Income Taxes
Cleco Corporation and Cleco Power
Note
Disclosures about Segments
Cleco Corporation
Note
Electric Customer Credits
Cleco Corporation and Cleco Power
Note
Equity Investment in Investees
Cleco Corporation
Note
Operating Leases
Cleco Corporation and Cleco Power
Note
Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees
Cleco Corporation and Cleco Power
Note
FERC Staff Investigations and LPSC Fuel Audit
Cleco Corporation and Cleco Power
Note
Affiliate Transactions
Cleco Corporation and Cleco Power
Note
Intangible Asset
Cleco Corporation and Cleco Power
Note
Storm Restoration
Cleco Corporation and Cleco Power
Note
Calpine Bankruptcy Settlement
Cleco Corporation
Note
Accumulated Other Comprehensive Loss
Cleco Corporation and Cleco Power
Note
Miscellaneous Financial Information (Unaudited)
Cleco Corporation and Cleco Power
Notes to the Financial Statements
Note 1 - The Company
General
Cleco Corporation is a holding company composed of the following:
§
Cleco Power is an integrated electric utility services subsidiary regulated by the LPSC and FERC, which determine the rates Cleco Power can charge its customers, as well as other regulators. Cleco Power serves approximately 276,000 customers in 107 communities in central and southeastern Louisiana. Cleco Power also engages in energy management activities. Cleco Power owns all of the outstanding membership interests in Cleco Katrina/Rita, a special purpose entity, that is consolidated with Cleco Power in its financial statements.
§
Midstream is a merchant energy subsidiary regulated by FERC. Midstream owns and operates a merchant power plant (Evangeline) and owns a 50 percent interest in a merchant power plant (Acadia), which it operates on behalf of its partner.
§
Cleco Corporation’s other operations consist of a holding company, two transmission interconnection facility subsidiaries, a shared services subsidiary, and an investment subsidiary. Effective February 1, 2007, the ownership interests of the two transmission interconnection facilities were transferred to Cleco Corporation from Midstream. In accordance with SFAS No. 131, the net operating results for Cleco Corporation and Midstream for periods prior to February 1, 2007, were adjusted to reflect this organizational change.
Note 2 - Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 revenue and expenses during the reporting period. Actual results could differ from those estimates.
Principles of Consolidation
The accompanying consolidated financial statements of Cleco include the accounts of Cleco and its majority-owned subsidiaries after elimination of intercompany accounts and transactions.
Cleco has adopted the provisions of FIN 46R on its scheduled effective dates. Cleco has determined that it is not the primary beneficiary of Evangeline, Perryville, Attala, and Acadia. Cleco determined it was not the primary beneficiary by examining all interest that could absorb expected losses and expected gains. This examination used assumptions about the expected rate of inflation, changes in the market price of natural gas as compared to the market price of electricity, length of contracts, variability of revenue stream as compared to variability of expenses, and maximum exposure to loss. These are considered variable interest entities. In accordance with FIN 46R, Cleco reports its investment in these entities on the equity method of accounting. As a result, the assets and liabilities of these entities are represented by one
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line item corresponding to Cleco’s equity investment in these entities. The pre-tax results of operations of these entities are reported as equity income from investees on Cleco Corporation’s Consolidated Statements of Income. For additional information on the operations of these entities, see Note 13 - “Equity Investment in Investees.”
Reclassifications
Certain reclassifications have been made to the 2007 and 2006 financial statements to conform them to the presentation used in the 2008 financial statements. These reclassifications had no effect on Cleco Corporation’s net income applicable to common stock or total common shareholders’ equity or Cleco Power’s net income or total member’s equity.
Statements of Cash Flows
The Consolidated Statements of Cash Flows of Cleco Corporation and the Consolidated Statements of Cash Flows of Cleco Power are prepared using the “indirect method” described in SFAS No. 95. This method requires that net income be adjusted to remove the effects of all deferrals and accruals of operating cash receipts and payments and the effects of all investing and financing cash flow items.
Regulation
Cleco Power maintains its accounts in accordance with the Uniform System of Accounts prescribed for electric utilities by FERC, as adopted by the LPSC. Cleco Power’s retail rates are regulated by the LPSC, and its rates for transmission services and wholesale power sales are regulated by FERC. Cleco Power follows SFAS No. 71, which 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.
Pursuant to SFAS No. 71, Cleco Power has recorded regulatory assets and liabilities primarily for extraordinary storm restoration costs, construction carrying costs, and the effects of income taxes. In addition, Cleco Power has recorded regulatory assets for deferred mining costs, interest costs, estimated future asset removal costs, postretirement plan costs, tree trimming costs, training costs, storm surcredit, fuel and energy purchases, and related hedging gains and losses, and has recorded regulatory liabilities for fuel transportation revenue, as a result of rate actions of regulators. For information regarding the regulatory assets and liabilities recorded by Cleco Power, see Note 3 - “Regulatory Assets and Liabilities.”
Any future plan adopted by the LPSC for purposes of transitioning utilities from LPSC regulation to retail competition may affect the regulatory assets and liabilities recorded by Cleco Power if the criteria for the application of SFAS No. 71 cannot continue to be met. At this time, Cleco cannot predict whether any legislation or regulation affecting Cleco Power will be enacted or adopted and, if enacted, what form such legislation or regulation may take.
Asset Retirement Obligation
Cleco has recorded asset retirement obligations (liabilities) in accordance with SFAS No. 143, that became effective on January 1, 2003, and FIN 47, effective for fiscal years ending after December 15, 2005. SFAS No. 143 requires an entity to record an ARO when there is a legal obligation under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel to incur costs to remove an asset when the asset is retired. FIN 47 requires an ARO which is conditional on a future event to be recorded even if the event has not yet occurred.
At the point the liability for asset retirement is incurred, SFAS No. 143 requires capitalization of the costs to the related property, plant and equipment asset. For asset retirement obligations existing at the time of adoption, the statement requires capitalization of costs at the level that existed at the point of incurring the liability. These capitalized costs are depreciated over the same period as the related property asset. Cleco Power recorded the depreciation expense for past periods at the date of adoption as a regulatory asset in accordance with SFAS No. 71, because Cleco Power believes the LPSC will allow it to recover these costs in future rates. Cleco Power also defers the current depreciation of the asset retirement cost as a regulatory asset under SFAS No. 71.
Under SFAS No. 143, the initial ARO liability recorded is accreted to its present value each accounting period. Cleco Power defers this accretion as a regulatory asset based on its determination that these costs can be collected from customers. For additional information on Cleco’s AROs, see Note 3 - “Regulatory Assets and Liabilities - Deferred Asset Removal Costs.”
Property, Plant and Equipment
Property, plant and equipment consist primarily of regulated utility generation and energy transmission assets. Regulated assets, utilized primarily for retail operations and electric transmission and distribution, are stated at the 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. Jointly owned assets are reflected in property, plant and equipment at Cleco Power’s share of the cost to construct or purchase the assets. For information on jointly owned assets, see Note 4 - “Jointly Owned Generation Units.”
Cleco’s cost of improvements to property, plant and equipment is capitalized. Costs associated with repairs and major maintenance projects are expensed as incurred. Cleco capitalizes the cost to purchase or develop software for internal use. The amounts of unamortized computer software costs at December 31, 2008, and 2007 were $3.8 million and $6.8 million, respectively. Amortization of capitalized computer software costs charged to expense for the years ending December 31, 2008, 2007, and 2006 was $3.0 million, $3.8 million, and $4.0 million, respectively.
Upon retirement or disposition, the cost of Cleco Power’s depreciable plant and the cost of removal, net of salvage value, are charged to accumulated depreciation. For Cleco’s
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other depreciable assets, upon disposition or retirement, the difference between the net book value of the property and any proceeds received for the property is recorded as a gain or loss on asset disposition on Cleco’s Consolidated Statements of Income. Any cost incurred to remove the asset is charged to expense. Annual depreciation provisions expressed as a percentage of average depreciable property for Cleco Power were 3.29% for 2008, 3.31% for 2007, and 3.32% for 2006.
Depreciation on property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets, as follows:
Property, plant and equipment consist of:
The table below discloses the amounts of plant acquisition adjustments reported in Cleco Power’s property, plant and equipment and the associated accumulated amortization reported in accumulated depreciation. The plant acquisition adjustment primarily relates to the 1997 acquisition of Teche. The acquisition adjustment represents the amount paid by Cleco Power for the assets of Teche in excess of their carrying value.
Deferred Project Costs
Cleco Power defers costs related to the initial stage of a construction or acquisition project during which time the feasibility of the acquisition or construction of property, plant and equipment is being investigated. In February 2006, the LPSC approved Cleco Power’s plan to construct Rodemacher Unit 3. The $11.2 million of preliminary project development costs spent by Cleco Power prior to December 31, 2005 was capitalized when actual construction began in May 2006. Cleco Power had spent approximately $0.8 million as of December 31, 2008 and $1.6 million as of December 31, 2007 for various IRP projects. These projects are still in the initial stages of development and as result are classified as other deferred charges on Cleco Power’s Consolidated Balance Sheets.
Inventories
Fuel inventories consist of coal, lignite, and oil used to generate electricity.
Materials and supplies inventory consists of transmission and distribution line construction and repair material, and generating station and transmission and distribution substation repair materials.
Both fuel and materials and supplies inventories are stated at average cost and are issued from inventory using the average cost of existing inventory. The amount of storeroom operating expenses allocated to inventory for the years ended December 31, 2008, and 2007 was $2.6 million and $3.7 million, respectively. Deferred storeroom operating expenses remaining in materials and supplies inventory as of December 31, 2008, and 2007 were $4.4 million and $1.8 million, respectively.
Accounts Receivable
Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. As of December 31, 2008, and 2007, the allowance for doubtful accounts amounted to $1.6 million and $1.0 million, respectively. There is no off-balance sheet credit exposure related to Cleco’s customers.
Insurance Reserves
Cleco maintains property insurance on generating stations, buildings and contents, and substations. Cleco is self-insured for any damage to transmission and distribution lines. To mitigate the exposure to potential financial loss for damage to lines, Cleco maintains an LPSC-approved reserve, supported by monthly charges to operating expense.
Cleco also maintains liability and workers’ compensation insurance to mitigate financial losses due to injuries and damages to the property of others. Cleco’s insurance covers claims that exceed certain self-insured limits. For claims that do not meet the limits to be covered by insurance, Cleco maintains reserves.
Cash Equivalents
Cleco 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.
Restricted Cash
Various agreements to which Cleco is subject contain covenants that restrict its use of cash. As certain provisions under these agreements are met, cash is transferred out of related escrow accounts and becomes available for general corporate purposes. At December 31, 2008, and December 31, 2007, $103.0 million and $18.0 million of cash, respectively, were restricted. At December 31, 2008, restricted cash consisted of $0.1 million under the Diversified Lands mitigation escrow agreement, $14.7 million held in escrow for the construction of Cleco Power’s solid waste disposal facilities at
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Rodemacher Unit 3, $44.6 million reserved at Cleco Power for GO Zone project costs, $27.4 million reserved at Cleco Power for future storm restoration costs, and $16.2 million at Cleco Katrina/Rita restricted for payment of operating expense, interest and principal on storm recovery bonds. Restricted cash at Cleco Power at December 31, 2008, increased $85.0 million compared to December 31, 2007, primarily due to the cash received from the issuance of solid waste disposal facility bonds in October 2008, the issuance of GO Zone bonds in December 2008, the establishment of a restricted reserve at Cleco Katrina/Rita related to the storm recovery bonds, and the establishment of a reserve for future storm restoration costs in March 2008. A portion of this storm reserve was utilized during November 2008 to fund operations and maintenance expenses related to damage caused by Hurricanes Gustav and Ike. For more information regarding the use of the restricted storm reserve, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 19 - Storm Restoration.”
Equity Investments
Cleco reports its investment in unconsolidated affiliated companies on the equity method of accounting, as defined in APB Opinion No. 18. The amounts reported on Cleco’s balance sheet represent assets contributed by Cleco plus Cleco’s share of the net income of the affiliate, less any distributions of earnings (dividends) received from the affiliate. For additional information, see Note 13 - “Equity Investment in Investees.”
Cleco applies the provisions of APB Opinion No. 18 to account for equity method investment impairments. Under this standard, Cleco evaluates at each balance sheet date whether events and circumstances have occurred that indicate a possible other-than-temporary decline in the fair value of the investment and the possible inability to recover the carrying value through operations. Cleco uses estimates of the future cash flows from the investee and observable market transactions in order to calculate fair value and recoverability. An impairment is recognized when an other-than-temporary decline in market value occurs and recovery of the carrying value is not probable. During 2007, Cleco recorded a pre-tax impairment loss of $45.8 million ($28.2 million after tax) on its indirect investment in Acadia. The impairment was recorded on the income from equity investees line item on the income statement. No impairments were recorded for 2008 or 2006. For more information, see Note 13 - “Equity Investment in Investees.”
Income Taxes
Cleco accounts for income taxes under SFAS No. 109. Income tax expense and related balance sheet amounts are comprised of a current portion and a deferred portion. The current portion represents Cleco’s estimate of the income taxes payable or receivable in the current year. The deferred portion represents Cleco’s estimate of the future income tax effects of events that have been recognized in the financial statements or income tax returns in the current or prior years. Cleco makes assumptions and estimates when it records
income taxes, such as its ability to deduct items on its tax returns, the timing of the deduction and the effect of regulation by the LPSC on income taxes. Cleco’s income tax expense and related assets and liabilities could be affected by its assumptions and estimates, changes in such assumptions and estimates, and by ultimate resolution of assumptions and estimates with taxing authorities.
Cleco Corporation and its subsidiaries record current and deferred federal and state income taxes at a composite rate of 38.5%. Cleco files a federal consolidated income tax return for all wholly owned subsidiaries. Cleco and its subsidiaries record current and deferred income tax liabilities based on amounts that would be recorded had each affiliate prepared separate tax returns. The federal effective tax rate could be different than the statutory or composite rate due to differences in recognition between the statements of income and the income tax return. Cleco Power generally records temporary differences between book and tax income under the flow-through method of accounting for state purposes as required by LPSC guidelines. During 2005, the LPSC required Cleco Power to record deferred tax expense and normalize the state tax benefit derived from the casualty losses relating to Hurricanes Katrina and Rita. The LPSC found normalization for state taxes related to storm deductions to be more appropriate due to the size of such deductions. This change in treatment resulted in a deferred state income tax benefit in 2008 and 2007 and additional deferred state income tax expense in 2006. For additional information on income taxes, see Note 10 - “Income Taxes.”
Investment Tax Credits
Investment tax credits, which were deferred for financial statement purposes, are amortized to income over the estimated service lives of the properties that gave rise to the credits.
Debt Expenses, Premiums, and Discounts
Expenses, premiums, and discounts applicable to debt securities are amortized to income ratably over the lives of the related issues. Expenses and call premiums related to refinanced Cleco Power debt are deferred and amortized over the life of the new issue.
Revenue and Fuel Costs
Utility Revenue. Revenue from sales of electricity is recognized based upon the amount of energy delivered. The costs of fuel and purchased power used for retail customers currently are recovered from customers through the fuel adjustment clause, based upon fuel costs and amounts of purchased power incurred in prior months. These adjustments are subject to audit and final determination by regulators. Excise taxes and pass-through fees collected on the sale of electricity are not recorded in utility revenue.
Unbilled Revenue. Cleco Power accrues estimated revenue monthly for energy delivered since the latest billings. The monthly estimated unbilled revenue amounts are recorded as
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revenue and a receivable and are reversed the following month.
Other Revenue. Other revenue is recognized at the time products or services are provided to and accepted by customers. Economic hedges are derivatives and do not meet the criteria to be considered accounting hedges. These transactions are marked-to-market with the resulting gain or loss recorded as a component of other revenue. For additional information on mark-to-market accounting, see “- Risk Management” below.
Equity Income. The results of equity investees are not consolidated with the results of Cleco, but instead are reported as equity investments. Their revenues and expenses are netted and reported on one line item as equity income from investees on Cleco Corporation’s Consolidated Statements of Income. For more information, see Note 13 - “Equity Investment in Investees.”
Midstream directly owns all of the equity interest in Evangeline and indirectly owns 50% of Acadia. Evangeline’s revenues are derived from its tolling agreement, which is considered to be an operating lease pursuant to SFAS No. 13 and SFAS No. 29. Several revenue provisions within the tolling agreement contain annual fixed escalations, which are required to be recognized straight-line over the life of the tolling agreement instead of when due to be paid by the tolling agreement counterparty. Other provisions, such as penalties and bonuses, are considered to be contingent rents and are recognized when the contingencies are fulfilled. A significant portion of Evangeline’s revenue is derived from its capacity payment, which it receives when the plant is available to produce electricity. Evangeline also recognizes variable revenue from the tolling agreement which depends on the way the plant is dispatched and how much electricity is produced.
Acadia’s revenues are primarily derived from the interaction of the natural gas market as compared to the electricity market. Acadia recognizes revenue when it produces and sells electricity into the wholesale market, which generally occurs when market value of electricity is above the cost to produce electricity and transmission services are available.
Cleco Corporation owns 100% of Perryville and Attala. Both companies provide transmission to a single customer. The transmission tariffs charged by both companies are regulated by FERC.
Taxes/Excise Taxes. Cleco Power collects a sales and use tax on the sale of electricity that subsequently is remitted to the state in accordance with state law. These amounts are not recorded as income or expense on the income statement but are reflected at gross amounts on Cleco’s balance sheet as a receivable until the tax is collected and as a payable until the liability is paid due to the pass-through nature of this item. Additionally, Cleco Power collects a consumer fee for one of its franchise agreements. This fee is not recorded on Cleco’s income statement as revenue and expense, but is reflected at gross amounts on Cleco’s balance sheet as a receivable until it is collected and as a payable until the liability is paid. Cleco currently does not have any excise taxes reflected on its income statement.
AFUDC
The capitalization of AFUDC by Cleco Power is a utility accounting practice prescribed by FERC and the LPSC. AFUDC represents the estimated cost of financing construction and is not a current source of cash. 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, was 12.8% on a pre-tax basis (7.9% net of tax) for 2008, 12.2% on a pretax basis (7.5% net of tax) for 2007, and 12.3% on a pre-tax basis (7.6% net of tax) for 2006.
Capitalized Interest
Cleco and its subsidiaries, except Cleco Power (see AFUDC above), capitalize interest costs related to longer-term construction projects. Other than AFUDC at Cleco Power, no interest was capitalized in 2008, 2007, or 2006.
Risk Management
Market risk inherent in Cleco’s market risk-sensitive instruments and positions includes potential changes arising from changes in interest rates and the commodity market prices of power and natural gas in the industry on different energy exchanges. Cleco’s Energy Market Risk Management Policy authorizes the use of various derivative instruments, including exchange traded futures and option contracts, forward purchase and sales contracts, and swap transactions to reduce exposure to fluctuations in the price of power and natural gas. Cleco uses SFAS No. 133 to determine whether the market risk-sensitive instruments and positions are required to be marked-to-market. Generally, Cleco Power’s market risk-sensitive instruments and positions qualify for the normal-purchase, normal-sale exception to mark-to-market accounting of SFAS No. 133, as modified by SFAS No. 149, since Cleco Power takes physical delivery and the instruments and positions are used to satisfy customer requirements. Cleco Power has entered into certain financial transactions it considers economic hedges to mitigate the risk associated with the fixed-price power to be provided to a wholesale customer through December 2010. The economic hedges cover approximately 97% of the estimated daily peak hour power sales to the wholesale customer. These transactions are derivatives as defined by SFAS No. 133 but do not meet the accounting criteria to be considered hedges. These transactions are marked-to-market with the resulting gain or loss recorded on the income statement as a component of operating revenue, net. For the year ended December 31, 2008, there was a net mark-to-market loss of $2.2 million and a realized gain of $0.9 million recorded in other operations revenue related to these economic hedge transactions. Cleco Power could experience realized losses in future periods as natural gas or power is purchased to meet its contractual obligations.
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Cleco Power has entered into other positions to mitigate the volatility in customer fuel costs. These positions are marked-to-market with the resulting gain or loss recorded on the balance sheet as a component of the accumulated deferred fuel asset or liability and a component of risk management assets or liabilities. When these positions close, actual gains or losses will be included in the fuel adjustment clause and reflected on customers’ bills as a component of the fuel cost adjustment. Based on market prices at December 31, 2008, and 2007, the net mark-to-market impact relating to these positions was a loss of $57.4 million and $7.0 million, respectively.
Cleco Power maintains margin accounts with commodity brokers used to partially fund the acquisition of natural gas futures, options and swap contracts. These contracts/positions are used to mitigate the risks associated with the fixed-price power sales and volatility in customer fuel costs noted above. At December 31, 2008, and 2007, Cleco Power had deposited collateral of $16.5 million and $3.0 million, respectively, to cover margin requirements relating to open natural gas futures, options and swap positions.
Cleco and Cleco Power maintain a master netting agreement policy and monitor credit risk exposure through review of counterparty credit quality, corporate-wide aggregate counterparty credit exposure, and corporate-wide aggregate counterparty concentration levels. Cleco manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and by requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Cleco Power has agreements in place with various counterparties that authorize the netting of financial buys and sells and contract payments to mitigate credit risk for transactions entered into for risk management purposes.
Recent Accounting Standards
The Registrants adopted, or will adopt, the recent accounting standards listed below on their respective effective dates.
In September 2006, the FASB issued SFAS No. 157, which provides guidance on how companies should measure fair value when required for recognition or disclosure purposes under generally accepted accounting principles. Specifically, SFAS No. 157 creates a common definition of fair value throughout generally accepted accounting principles, establishes a fair value hierarchy, and requires companies to make expanded disclosures about fair value measurements. This statement was effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB amended SFAS No. 157. FSP No. FAS 157-1 excludes fair value lease calculations pursuant to SFAS No. 13, as amended, from SFAS No. 157, but does not exclude assets and liabilities acquired pursuant to SFAS No. 141(R). FSP No. FAS 157-2 defers the effective date of SFAS No. 157 by one year for non-financial assets and liabilities that are not recognized or disclosed at fair value on a recurring basis. The adoption of SFAS No. 157 and the related FSPs did not have a material impact on the financial condition or results of operations of the Registrants. For more information regarding SFAS No. 157 related disclosures, see Note 5 - “Fair Value of Financial Instruments.”
In February 2007, the FASB issued SFAS No. 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. SFAS No. 159 was effective for fiscal years beginning after November 15, 2007. The Registrants did not elect the fair value option for eligible items existing at the effective date. The adoption of SFAS No. 159 did not have an impact on the financial condition or results of operations of the Registrants.
In April 2007, the FASB issued FSP No. FIN 39-1, which amends FIN 39. The new guidance permits companies to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement and fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. FSP No. FIN 39-1 was effective for fiscal years beginning after November 15, 2007. Upon the adoption of FSP No. FIN 39-1, Cleco Corporation and Cleco Power adopted the policy to net the fair value of derivative instruments along with the right to reclaim cash collateral or obligation to return cash collateral. In accordance with the provisions of this FSP, the netting was applied retrospectively to the prior balance sheet presented as a change to an accounting principle. The following table represents the right to reclaim cash collateral netted against the fair value of derivative instruments for both Cleco Corporation and Cleco Power.
Cleco Corporation and Cleco Power’s Condensed Consolidated Balance Sheets at December 31, 2007, have been retrospectively adjusted due to the adoption of FSP No. FIN 39-1. The retrospective adjustments to the December 31, 2007, balance sheets are described in the following tables.
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The retrospective adoption of FSP No. FIN 39-1 had no effect on net income, earnings per share, shareholders’ equity or member’s equity of the Registrants.
In June 2007, the FASB ratified EITF No. 06-11. This consensus requires companies to record the realized income tax benefits from dividends or dividend equivalents that are charged to retained earnings and are paid to employees to the additional paid-in capital pool. This consensus was effective prospectively for dividends declared in fiscal years beginning after September 15, 2007. This consensus may be adopted early in financial periods for which financial statements have not been issued. Entities shall disclose the nature of any change in their accounting policy for income tax benefits of dividends on share-based payment awards resulting from the adoption of this guidance. The adoption of this EITF did not have an impact on the financial condition or results of operations of the Registrants.
In June 2007, the FASB ratified EITF No. 07-3. This consensus requires companies that make non-refundable advance payments for future research and development activities to capitalize the payments until the goods have been delivered or the related services performed. This consensus is effective for financial statements issued for fiscal years beginning after December 15, 2007. Earlier application is not permitted. The adoption of this EITF did not have an impact on the financial condition or results of operations of the Registrants.
In December 2007, the FASB released SFAS No. 141(R). This revision requires the acquirer of a business to recognize assets acquired, liabilities assumed, and any non-controlling interests at their fair market values. The statement gives guidance on the calculation of goodwill or gain from a bargain purchase and expands the required disclosures. The provisions of this statement are applicable to acquisitions either through one transaction or through a step acquisition. This SFAS is applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. This statement may not be adopted early. The adoption of this statement will only impact the financial condition and results of operations of the Registrants if they are involved in transactions within the scope of this statement after its effective date.
In December 2007, the FASB released SFAS No. 160. This statement gives guidance on the presentation and disclosure of noncontrolling interests (currently known as minority interests) of consolidated subsidiaries. This statement requires the noncontrolling interest to be included in the equity section of the balance sheet, requires disclosure on the face of the consolidated income statement of the amounts of consolidated net income attributable to the consolidated parent and the noncontrolling interest, and expands disclosures. The provisions of this statement are to be applied prospectively to fiscal years beginning on or after December 15, 2008. Early adoption is prohibited. The adoption of this statement will only impact the financial condition and results of operations of the Registrants if they are involved in transactions within the scope of this statement after its effective date.
In December 2007, the FASB ratified EITF No. 07-1. This EITF prescribes the income statement presentation and disclosures for participants in collaborative arrangements. A collaborative arrangement is defined as a contractual arrangement that involves a joint operating activity, usually outside of a legal entity. The provisions of this EITF are effective for fiscal years beginning after December 15, 2008, and shall be applied retrospectively for all collaborative arrangements existing as of the effective date. Management is currently evaluating the impact this EITF will have on the financial condition or results of operations of the Registrants.
In March 2008, the FASB issued SFAS No. 161 which enhances the disclosures about an entity’s derivative and hedging activities. The disclosures include how and why a derivative instrument is used, how the derivative instrument and the hedged item are related, and the impact of the derivative instrument and the hedged item on the entity’s financial statements. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. Since this SFAS is only a change in disclosure, the adoption will not have an impact on the financial condition or results of operations of the Registrants.
In April 2008, the FASB issued FSP No. FAS 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. This FSP amends SFAS No. 142 to allow an entity’s own experience in renewing arrangements or to use market assumptions about renewal in determining the useful life of a recognized intangible asset. This FSP also requires additional disclosure about the renewal costs. FSP No. FAS 142-3 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. Early adoption is prohibited. The adoption of FSP No. FAS 142-3 is not expected to have an impact on the financial condition or results of operations of the Registrants.
In May 2008, the FASB issued SFAS No. 162 which identifies, categorizes and ranks sources of GAAP. This SFAS has four broad categories. An entity is required to use the highest category of GAAP specified by a pronouncement. If a particular transaction is not specified by a pronouncement within the categories, an entity can then apply accounting pronouncements for similar transactions (unless such analogy is prohibited by a particular pronouncement) followed by other accounting literature. This SFAS is effective 60 days following the SEC’s approval of the PCAOB’s amendments to Auditing Standard Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” The adoption of SFAS No. 162 is not expected to have an impact on the financial condition or results of operations of the Registrants.
In June 2008, the FASB issued FSP EITF No. 03-6-1 which gives guidance on determining whether non-vested instruments issued in share-based payment transactions are participating securities when calculating earnings per share. This FSP states that non-vested share-based instruments that contain nonforfeitable rights to dividends or dividend equivalents
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are participating securities and are required to be included in the computation of earnings per share pursuant to the two-class method. This FSP is effective for fiscal years and interim periods beginning after December 15, 2008. Earnings per share for prior periods presented are required to be adjusted retrospectively to conform to this FSP. Early adoption of this FSP is prohibited. Management is currently evaluating the impact this FSP will have on the financial condition and results of operations of the Registrants.
In September 2008, the FASB issued FSP No. FAS 133-1 and FIN 45-4 which amends SFAS No. 133 and FIN 45 by expanding disclosure requirements for entities selling credit derivatives. The disclosures include the nature of the derivative, the maximum potential amount of future payments, the fair value, the nature of any recourse or collateral, and the current status of the payment/performance risk. The provisions of this FSP are effective for interim and annual periods ending after November 15, 2008. Since this FSP is only a change in disclosure, the adoption will not have an impact on the financial condition or results of operations of the Registrants.
In September 2008, the FASB ratified EITF No. 08-5 which provides guidance on issuer’s accounting and disclosure at fair value for liabilities that contain inseparable third-party credit enhancements. The EITF requires issuers of liabilities to exclude the third-party credit enhancement when calculating the fair value of the liability for both recognition and disclosure purposes. Also, proceeds received by the issuer for liabilities within the scope of the EITF represent consideration for both the liability and the credit enhancement and shall be allocated to both the liability and the premium for the credit enhancement. The provisions of this EITF are effective on a prospective basis in the first reporting period beginning on or after December 15, 2008. Earlier application is permitted. Management is currently evaluating the impact this FSP will have on the financial condition and results of operations of the Registrants.
In September 2008, the SEC and the FASB issued a joint release clarifying fair value accounting. The clarifications cover topics such as inactive markets, broker quotes, disorderly sales, internally generated assumptions and other-than-temporary impairment. This joint release does not have a stated effective date, but its guidance should be considered for valuations made on or after its release date. The application of this release did not have an impact on the financial condition and results of operations of the Registrants.
In October 2008, the FASB issued FSP No. FAS 157-3 which provides guidance on calculating fair value in an inactive market. This FSP is effective upon issuance, including prior periods for which financial statements have not been issued. The adoption of this FSP did not have an impact on the financial condition or results of operations of the Registrants.
In November 2008, the FASB ratified EITF No. 08-6 which provides guidance on four issues affecting equity method investees. The EITF gives guidance on initial carrying value of an equity method investee, underlying indefinite-lived intangible asset impairment testing, equity investee’s issuance of its shares and how to account for a change from the equity method to the cost method. This EITF is effective for all interim and fiscal periods beginning on or after December 15, 2008. The adoption of this statement will only impact the financial condition and results of operations of the Registrants, if they are involved in transactions within the scope of this EITF after its effective date.
In December 2008, the FASB announced the implementation of the FASB Accounting Standards Codification which will become the single source of authoritative nongovernmental U.S. GAAP and will supersede existing FASB, AICPA, EITF and related literature. The thousands of U.S. GAAP pronouncements will be reorganized into roughly 90 accounting topics which will be displayed in a consistent format. The Codification structure is expected to be effective after June 30, 2009.
In December 2008, the FASB issued FSP No. FAS 132(R)-1 which amends SFAS No. 132(R) which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. This FSP also includes a technical amendment to SFAS No. 132(R) that requires a nonpublic entity to disclose net periodic benefit cost for each annual period for which a statement of income is presented. This FSP is effective for the first fiscal year ending after December 15, 2009. Since the adoption of this FSP is only a change in disclosure, the adoption of the FSP will not have any effect on the financial condition or results of operations of the Registrants.
In December 2008, the FASB issued FSP No. FAS 140-4 and FIN 46(R)-8 which amend SFAS No. 140 and FIN 46(R), respectively, to require public entities to provide additional disclosures about transfers of financial assets and additional disclosures about involvement with variable interest entities. This FSP shall be effective for the first reporting period (interim or annual) ending after December 15, 2008, and shall apply for each annual and interim reporting period thereafter. Since the adoption of this FSP is only a change in disclosure, the adoption of the FSP will not have any effect on the financial condition or results of operation of the Registrants.
Earnings per Average Common Share
The following table shows the calculation of basic and diluted earnings per share.
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Stock option grants excluded from the computation of 2006 diluted earnings per share are presented in the table below. These stock option grants were excluded from the computation of 2006 diluted earnings per share because they had exercise prices higher than the average market price. There were no stock option grants excluded from the computation of 2008 or 2007 diluted earnings per share.
Stock-Based Compensation
For information on Cleco’s stock-based compensation, see Note 7 - “Common Stock - Stock-Based Compensation.”
Note 3 - Regulatory Assets and Liabilities
Cleco Power follows SFAS No. 71, which 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.
Pursuant to SFAS No. 71, Cleco Power has recorded regulatory assets and liabilities primarily for extraordinary storm carrying and restoration costs and the effects of income taxes. In addition, Cleco Power has recorded regulatory assets for deferred mining costs, interest costs, estimated future asset removal costs, postretirement plan costs, tree trimming costs, training costs, storm surcredit, fuel and energy purchases, and related hedging gains and losses, and has recorded regulatory liabilities for fuel transportation revenue and recovered construction carrying costs, as a result of rate actions of regulators.
The deferred storm restoration costs, deferred mining costs, deferred interest costs, postretirement plan costs, deferred asset removal costs, deferred tree trimming costs, deferred training costs, and deferred storm surcredit are presented in the line items entitled “Regulatory Assets - Other,” the deferred fuel and purchased power costs and related hedging gains and losses are presented on the line item entitled “Accumulated Deferred Fuel,” the deferred fuel transportation revenue and the deferred construction carrying costs are presented on the line items entitled “Regulatory Liabilities - Other,” on Cleco Corporation’s Consolidated and Cleco Power’s Consolidated Balance Sheets. Under the current regulatory environment, Cleco Power believes these regulatory assets will be fully recoverable; however, if in the future, as a result of regulatory changes or competition, Cleco Power’s ability to recover these regulatory assets would no longer be probable, then to the extent that such regulatory assets were determined not to be recoverable, Cleco Power would be required to write-down such assets. In addition, potential deregulation of the industry or possible future changes in the method of rate regulation of Cleco Power could require discontinuance of the application of SFAS No. 71. Cleco Power does not earn a return on these regulatory assets through current rates, but is collecting carrying costs on the outstanding deferred costs relating to deferred mining costs and deferred fuel and purchased power.
The following chart summarizes Cleco Power’s regulatory assets and liabilities at December 31, 2008, and 2007.
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Deferred Taxes
At December 31, 2008, and 2007, Cleco Power had recorded $174.8 million and $126.7 million, respectively, of SFAS No. 109 net regulatory assets related to probable future taxes payable that will be recovered from customers through future rates. Amounts recorded as regulatory assets are partially offset by deferred tax liabilities resulting from the regulatory requirement to flow through the current tax benefits to customers of certain accelerated deductions that are recovered from customers as they are paid. The recovery periods for regulatory assets and liabilities are based on assets’ lives, which are typically 30 years or greater. The amounts deferred are attributable to differences between book and tax recovery periods. The $48.1 million increase in regulatory assets and liabilities - deferred taxes, net is primarily the result of AFUDC equity for Cleco Power’s construction of Rodemacher Unit 3.
Deferred Mining Costs
Cleco Power operates a generating unit jointly owned with SWEPCO that uses lignite as its fuel source.
In May 2001, Cleco Power (along with SWEPCO) entered into the Lignite Mining Agreement with DHLC, the operator of the Dolet Hills mine. As then ordered by the LPSC in dockets U-21453, U-20925(SC), and U-22092(SC) (Subdocket G), Cleco Power’s retail customers began receiving fuel cost savings equal to 2% of the projected costs under the previous mining contract (the benchmark price) through the year 2011. Actual mining costs incurred above 98% of the benchmark price were deferred, and could be recovered from retail customers through the fuel adjustment clause only when the actual mining costs are below 98% of the benchmark price. The benchmark price used the GDP-IPD index as a proxy for the numerous escalators in the previous mining contract. During the course of the contract, Cleco Power and SWEPCO determined that the GDP-IPD index did not appropriately reflect the increase in mining costs caused by sharp increases in diesel fuel and electricity costs associated with the mining operation. Because of this disconnect between the GDP-IPD index and actual mining costs, a significant amount of mining costs were being deferred by Cleco Power. Cleco Power recognized that there was a possibility it may not recover all or part of the lignite mining costs currently deferred.
In November 2006, Cleco Power and SWEPCO submitted a joint application to the LPSC requesting approval for Cleco Power to recover its existing deferral balance, and eliminate any future benchmarking of lignite mining costs. In December 2007, the LPSC approved a settlement agreement between Cleco Power, SWEPCO and the LPSC Staff authorizing Cleco Power to recover the existing deferred mining cost balance, including interest, over approximately 11.5 years. The settlement also established a new benchmark utilizing the contract’s escalators to assure a minimum 2% savings to customers compared to the costs under the prior mining contract. This benchmarking will end after April 2011. At December 31, 2008, and 2007, Cleco Power had $26.8 million and $29.4 million, respectively, in mining costs deferred and uncollected.
Cleco Power and SWEPCO agreed to commit to continued operation of the mining operation through 2016 as long as the operation of the mine was considered prudent. Cleco Power has not recorded any additional deferred fuel costs under the new benchmarking method.
Deferred Storm Restoration Costs - Katrina/Rita
At December 31, 2007, Cleco Power had approximately $127.6 million of unamortized storm restoration costs deferred as regulatory assets relating to damage caused by Hurricanes Katrina and Rita. The restoration costs relating to Hurricanes Katrina and Rita were amortized to depreciation expense based on amounts collected monthly from customers through a surcharge, according to the terms of an interim storm recovery plan approved by the LPSC in February 2006. In March 2007, after completing a review of the restoration costs, Cleco Power and the LPSC Staff filed a settlement agreement allowing recovery of essentially all of Cleco Power’s Hurricanes Katrina and Rita storm costs. The agreement authorized the issuance of securitized storm recovery bonds to finance the restoration costs from Hurricanes Katrina and Rita and the collection of a special storm recovery charge from Cleco Power’s customers to pay principal, interest and other amounts related to the bonds. The LPSC approved the settlement agreement and issued a securitization financing order in September 2007. In March 2008, the securitization financing was completed, collection of the interim surcharge ceased, and the
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right to bill and collect unamortized storm damage costs from customers was sold to Cleco Katrina/Rita, a special purpose, wholly owned subsidiary of Cleco Power.
Cleco Katrina/Rita issued $180.6 million aggregate principal amount of senior secured storm recovery bonds in March 2008. A portion of the net proceeds of $176.0 million from the issuance of the bonds was used to purchase from Cleco Power the right to bill and collect from customers unamortized storm damage costs relating to Hurricanes Katrina and Rita thereby reducing Cleco Power’s regulatory asset established for this purpose. Cleco Power used $50.8 million of such proceeds to establish a storm reserve fund for future storm damage costs, with the remaining portion of the proceeds, which is reimbursement of previously unrecovered storm costs from Hurricanes Katrina and Rita, was used for working capital and other general corporate purposes. In November 2008, Cleco received approval from the LPSC to utilize Cleco Power’s restricted storm reserves for operations and maintenance costs related to Hurricanes Gustav and Ike. For additional information on storm costs, see Note 6 - “Debt” and Note 19 - “Storm Restoration.”
Deferred Interest Costs
Cleco Power’s deferred interest costs include additional deferred capital construction financing costs authorized by the LPSC. At December 31, 2008, and 2007, these costs totaled $7.8 million and $9.4 million, respectively, and are being amortized over the estimated lives of the respective assets constructed.
Deferred Asset Removal Costs
Under SFAS No. 143, Cleco Power determined that a liability exists for cleanup and closing costs of solid waste facilities associated with its generating stations that use lignite and coal for fuel. Applying FIN 47, Cleco Power determined that a liability exists for costs which may be incurred in the future for removal of asbestos from its general service buildings, the removal of transmission towers on leased rights-of-way and for the abatement of PCBs in transformers.
A FIN 47 liability was not recorded for the site used by Cleco Power’s generating station using coal due to the remote probability that the site will be retired, since a new unit is currently being constructed at the site. Under FIN 47, Cleco Power did not recognize an obligation for the costs of removing transmission towers on leased rights-of-way because of the indeterminate life of these assets. PCBs were common in transformers purchased before 1976. During the 30 years since then, most of the transformers containing PCBs either have been replaced or, during routine maintenance, have been remediated. The liability on remaining pre-1976 transformers is considered immaterial to Cleco Power.
At December 31, 2008, and 2007, the liability for solid waste facility closure costs at the generating station using lignite is estimated at $0.4 million and is included in other deferred credits. At December 31, 2008, and 2007, Cleco Power’s liability for removal of asbestos is estimated at $0.2 million and also is included in other deferred credits. Cleco Power’s ARO liability, including FIN 47 liabilities, at January 1, 2007, was $0.5 million.
Under SFAS No. 143, the ARO liability recorded is accreted to its present value each accounting period, and the ARO asset is depreciated. Cleco Power defers the accretion and depreciation expense as a regulatory asset based on its determination that these costs can be collected from customers. At December 31, 2008, and 2007, Cleco Power’s regulatory assets relating to AROs totaled $0.7 million, and were equal to the sum of the accumulated accretion of the ARO liability and the accumulated depreciation on the ARO assets. The sum of the yearly accretion expense and depreciation expense was less than $0.1 million.
Prior to the adoption of SFAS No. 143, Cleco Power did not recover in rates any allowances for closure costs for any assets in use or retired and has not recognized any additional depreciation or utilized depreciation rates that include a negative salvage component.
Deferred Postretirement Costs
On December 31, 2006, Cleco adopted SFAS No. 158, which requires companies to recognize the funded status of their postretirement benefit plans as a net liability or asset. The net liability or asset is defined as the difference between the benefit obligation and the fair market value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. Since Cleco Power is considered the plan sponsor, at December 31, 2006, Cleco Power recognized a change in net pension plan liability of $38.7 million. Historically, the LPSC has allowed Cleco Power to recover pension plan expense. Cleco Power, therefore, recorded the $38.7 million as a regulatory asset based on its determination that these costs can be collected from customers. The amount and timing of the recovery will be based on the changing funded status of the pension plan in future periods. At December 31, 2008, and 2007, Cleco Power had postretirement plan cost deferred as a regulatory asset of $112.2 million and $11.5 million, respectively. For additional information on Cleco’s pension plan and adoption of SFAS No. 158, see Note 9 - “Pension Plan and Employee Benefits.”
Deferred Tree Trimming Costs
In January 2008, the LPSC approved Cleco Power’s request to establish a regulatory asset which is being charged with actual expenditures at Cleco Power’s grossed-up rate of return for costs incurred to trim, cut or remove trees that were damaged by Hurricanes Katrina and Rita, but were not addressed as part of the restoration efforts. The amount of expenditures subject to deferral as a regulatory asset was limited to $12.0 million by the LPSC. Recovery of these expenditures was requested as part of Cleco Power’s base rate application filed July 14, 2008. At December 31, 2008, Cleco Power had deferred $5.9 million in tree trimming expenditures.
Deferred Training Costs
In February 2008, the LPSC approved Cleco Power’s request to establish a regulatory asset which is being charged with
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training costs associated with existing processes and technology for new employees at Rodemacher Unit 3. Normally these types of training costs would be expensed as incurred; however, this LPSC order allows Cleco Power to defer the training costs and seek recovery in rates when Rodemacher Unit 3 goes into service. At December 31, 2008, Cleco Power had deferred $2.5 million of Rodemacher Unit 3 training costs.
Deferred Storm Surcredit, net
Cleco Power has recorded a storm surcredit as the result of a settlement with the LPSC that addressed, among other things, the recovery of the storm damages related to Hurricanes Katrina and Rita. In the settlement, Cleco Power was required to implement a surcredit to provide ratepayers with the economic benefit of the carrying charges of all accumulated deferred income tax liabilities due to the storm damage costs at a 12.2% rate of return. The accumulated deferred income tax liability includes deductions for operation and maintenance expense, casualty loss, and depreciation against taxable income in the year incurred and all subsequent periods. The settlement, through a true-up mechanism, allows the surcredit to be adjusted to reflect the actual tax deductions allowed by the IRS. During the second quarter of 2008, the regulatory liability was reduced by $4.2 million through this true-up mechanism to reflect the expected amounts to be refunded through the surcredit to ratepayers. During the third quarter and the fourth quarter of 2008, the regulatory liability was reduced by an additional $0.7 million to represent the economic benefit of a reduction in the regulatory liability when the underlying tax positions are settled.
Cleco Power also was allowed to record a corresponding regulatory asset in an amount representing the flow back of the carrying charges to ratepayers. This amount is being amortized over the life of the storm recovery bonds. The corresponding regulatory asset will be adjusted through the same surcredit true-up mechanism at the time of a final determination of the tax benefit for storm damage costs by the IRS.
As a result of the settlement with the LPSC, Cleco Power was required to implement a surcredit when funds were withdrawn from the restricted storm reserve. In October 2008, Cleco Power withdrew funds from the restricted storm reserve to pay for damage caused by Hurricanes Gustav and Ike resulting in the establishment of a surcredit. However, rather than refunding this amount, Cleco Power requested and received approval from the LPSC to replenish the restricted storm reserve.
Deferred Fuel Transportation Revenue
In June 2003, pipeline assets owned by a Cleco Power affiliate, providing transportation of fuel to two Cleco Power generating stations, were sold to Cleco Power. Prior to June 2003, the expenses associated with the pipeline assets were recovered from customers through Cleco Power’s fuel adjustment clause, since these expenses were billed to Cleco Power by the affiliate energy company. Rather than prepare a formal rate filing requesting recovery of the pipeline assets’ cost, in March 2005, Cleco Power requested and the LPSC authorized Cleco Power to recover the cost of the assets until Cleco Power’s next base rate case. On July 14, 2008, Cleco Power filed a request for a new rate plan with the LPSC. Cleco Power currently anticipates a settlement of the rate case in the second quarter of 2009. The new rates are expected to be effective upon the commercial operation date of Rodemacher Unit 3. Cleco Power recorded a regulatory liability representing the estimated amount of revenue to be collected from customers through October 2009, when the current RSP is estimated to expire. The balance deferred at December 31, 2008, was $0.4 million.
Deferred Construction Carrying Costs
In February 2006, the LPSC approved Cleco Power’s plans to build Rodemacher Unit 3. Terms of the approval included authorization for Cleco Power to collect from customers an amount equal to 75% of the LPSC-jurisdictional portion of the carrying costs of capital during the construction phase of the unit. In any calendar year during the construction period, the amount collected from customers is not to exceed 6.5% of Cleco Power’s projected retail revenues. Cleco Power began collection of the carrying costs in May 2006. For the 12-month periods ended December 31, 2008, and 2007, Cleco Power collected $54.1 million and $26.6 million, respectively. A regulatory liability was established for the carrying costs due to the terms of the LPSC order which requires Cleco Power, as part of its base rate application to recover Rodemacher Unit 3 ownership costs, to submit a plan to return to customers the carrying costs over a shorter period than the life of the Rodemacher Unit 3 asset.
Deferred Fuel and Purchased Power Costs
The cost of fuel used for electric generation and the cost of power purchased for utility customers are recovered through the LPSC-established fuel adjustment clause, which enables Cleco Power to pass on to its customers substantially all such charges. For the year 2008, approximately 97% of Cleco Power’s total fuel cost was regulated by the LPSC, while the remainder was regulated by FERC. Deferred fuel and purchased power costs recorded at December 31, 2008, and 2007, were under-recoveries of $69.2 million and $9.4 million, respectively, and are scheduled to be collected from customers in future months. The $59.8 million increase in the unrecovered costs was primarily the result of a $50.4 million decrease in the market value of open natural gas hedge positions, a $3.3 million loss on closed natural gas hedge positions, both due to declining natural gas prices since December 2007, and deferral of $5.5 million in additional fuel and purchased power costs.
Note 4 - Jointly Owned Generation Units
Two electric generation units operated by Cleco Power are jointly owned with other utilities. The joint-owners are responsible for their own share of the capital and the operating and maintenance costs of the respective units. Cleco Power recognized $104.8 million, $92.3 million, and $85.6 million as its proportionate share of operating and maintenance expenses
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associated with these two units, which include fuel costs of $86.9 million, $72.0 million, and $70.0 million, during the years ended December 31, 2008, 2007, and 2006, respectively.
Note 5 - Fair Value of Financial Instruments
The amounts reflected in Cleco’s and Cleco Power’s Consolidated Balance Sheets at December 31, 2008, and 2007, for cash and cash equivalents, accounts receivable, accounts payable, and short-term debt approximate fair value because of their short-term nature. Estimates of the fair value of Cleco’s and Cleco Power’s long-term debt and Cleco’s nonconvertible preferred stock are 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 obtained by Cleco and Cleco Power for debt and by Cleco for preferred stock with similar maturities.
Cleco’s convertible preferred stock relates to establishment of the ESOP. The ESOP borrowed $30.0 million, and subsequently, Cleco Power purchased the loan. The amount of the loan was directly offset by Cleco Power’s guarantee of the loan. The fair value of Cleco’s convertible preferred stock was estimated assuming its conversion into common stock at the market price per common share at December 31, 2006, with proceeds from the sale of the common stock used to repay the principal balance of Cleco Power’s loan to the ESOP. The loan was repaid in full in July 2006, and the ESOP preferred stock was converted to Cleco common stock in the first quarter of 2007.
The estimated fair value of energy market positions is based upon observed market prices when available. When such market prices are not available, management estimates market value at a discrete point in time by assessing market conditions and observed volatility. These estimates are subjective in nature and involve uncertainties. Therefore, actual results may differ from these estimates.
Cleco
Cleco Power
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The financial instruments not marked-to-market are reported on Cleco’s and Cleco Power’s Consolidated Balance Sheets at carrying value. The financial instruments marked-to-market represent market risk recorded in the financial statements because, to the extent Cleco and Cleco Power have an open position, they are exposed to the risk that fluctuating market prices may adversely affect their financial condition or results of operations upon settlement. Original value represents the fair value of the positions at the time originated.
At December 31, 2008, Cleco and Cleco Power were exposed to concentration of credit risk through their short-term investments classified as cash equivalents. Cleco had $5.8 million in short-term investments in an institutional money market fund. If the money market funds failed to perform under the terms of the investment, Cleco would be exposed to a loss of the invested amounts. Cleco Power had $96.1 million in short-term investments in several institutional money market funds. If the money market funds failed to perform under the terms of the investments, Cleco Power would be exposed to a loss of the invested amounts. Collateral on these types of investments is not required by either Cleco or Cleco Power. In order to mitigate potential credit risk, Cleco and Cleco Power have established guidelines for short-term investments. Money market funds must have at least $1.0 billion in assets under management; must have been in existence for not less than two years; must have portfolios not comprised of more than 50% of securities issued by foreign entities and must be rated in the top two ratings categories by at least one nationally recognized rating agency. Commercial paper must be issued by a company with headquarters in the U.S. which is rated not less than A1 by Standard & Poor’s or P1 by Moody’s. Investments in commercial paper rated A2 by Standard & Poor’s or P2 by Moody’s may be made if approved by the appropriate level of management.
Cleco Power was exposed to concentration of credit risk through its energy marketing assets. At December 31, 2008, Cleco Power had energy marketing assets with an estimated fair value of $117.9 million. These energy marketing assets represent open natural gas purchase positions, primarily financial hedge transactions. Cleco Power entered into these positions to mitigate the volatility in the cost of fuel purchased for utility generation and the risk associated with the fixed-price power that is being provided to a wholesale customer through December 2010. If the counterparties to these assets fail to perform under the terms of the investment, Cleco would be exposed to a loss of $117.9 million. For information about credit risk management and how these risks are mitigated on energy marketing assets, see Note 2 - “Summary of Significant Accounting Policies - Risk Management.”
SFAS No. 157 requires entities to classify assets and liabilities measured at their fair value according to three different levels, depending on the inputs used in determining fair value.
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Level 1 - unadjusted quoted prices in active, liquid markets for the identical asset or liability;
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Level 2 - quoted prices for similar assets and liabilities in active markets or other inputs that are observable for the asset or liability, including inputs that can be corroborated by observable market data, observable interest rate yield curves and volatilities;
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Level 3 - unobservable inputs based upon the entities own assumptions.
The tables below disclose for Cleco and Cleco Power the fair value of financial assets and liabilities measured on a recurring basis and within the scope of SFAS No. 157.
Cleco chose to defer for one year the provisions of SFAS No. 157 for non-financial assets and liabilities in accordance with FSP No. FAS 157-2.
The derivative assets and liabilities are classified as either current or non-current depending on when the positions close. All derivative current assets and current liabilities are reported as a net current risk management asset or liability. All derivative non-current assets and non-current liabilities are reported net in other deferred charges or other deferred credits. Net presentation is appropriate due to the right of offset included in the master netting agreements. In accordance with FSP No. FIN 39-1, the net current and net non-current derivative positions are netted with the applicable margin deposits. At December 31, 2008, a net current risk management asset of
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$0.4 million represented deferred option premiums. Non-current derivative asset positions were $0.2 million, reduced by non-current margin deposits of $0.6 million which was recorded in other deferred charges on the balance sheet. At December 31, 2008, a net current risk management liability of $30.1 million represented the current derivative positions of $44.8 million reduced by current margin deposits of $14.6 million. The non-current liability derivative positions of $13.0 million, reduced by non-current margin deposits of $3.6 million were recorded in other deferred charges. The $204.8 million in institutional money market funds at December 31, 2008, was reported on the Cleco Consolidated balance sheet in cash and cash equivalents, current restricted cash, and restricted non-current cash in the amounts of $101.9 million, $62.3 million, and $40.6 million, respectively. At Cleco Power, cash and cash equivalents, current restricted cash, and restricted non-current cash at December 31, 2008, contained $96.1 million, $62.3 million, and $40.6 million, respectively.
Cleco utilizes different valuation techniques for fair value calculations. In order to measure the fair value for Level 1 assets and liabilities, Cleco obtains the closing price from published indices in active markets for the various instruments and multiplies by the appropriate number of instruments held. Level 2 fair values for assets and liabilities are determined by obtaining the closing price from published indices in active markets for instruments that are similar to Cleco’s assets and liabilities. The fair value obtained is then discounted to the current period using a U.S. Treasury published interest rate as a proxy for a risk-free rate of return. For some options, Cleco uses the Black-Scholes model using observable and available inputs to calculate the fair value, consistent with the income approach. These techniques have been applied consistently from fiscal period to fiscal period. Level 3 fair values allow for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Cleco had no Level 3 assets or liabilities at December 31, 2008.
Note 6 - Debt
Cleco
Cleco’s total indebtedness as of December 31, 2008, and 2007, was as follows.
The amounts payable under long-term debt agreements for each year through 2013 and thereafter are listed below.
At December 31, 2008, and 2007, Cleco had no outstanding short-term debt. Cleco had $63.5 million and $100.0 million of long-term debt due within one year at December 31, 2008, and 2007, respectively. In May 2008, Cleco repaid $100.0 million of 7.00% senior notes, at maturity.
The capital lease in the chart above is for mobile computers with local area network capabilities. The lease term is for five years. The mobile computers can be purchased at the
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end of the lease term. The lease payments are due at the beginning of each month. The monthly lease payment is derived by multiplying the total acquisition costs by 1.92% for a full month and 0.06% per day for a partial month.
The amounts payable under the capital lease agreement for the next five years are listed below.
Cleco Power
Cleco Power’s total indebtedness as of December 31, 2008, and 2007, was as follows.
The amounts payable under long-term debt agreements for each year through 2013 and thereafter are listed below.
At December 31, 2008, and 2007, Cleco Power had no outstanding short-term debt. At December 31, 2008, Cleco Power had $63.5 of long-term debt due within one year,
compared to no long-term debt due within one year at December 31, 2007.
In March 2008, Cleco Katrina/Rita issued $180.6 million aggregate principal amount of senior secured storm recovery bonds. The bonds were issued in two tranches, with one tranche of $113.0 million initial principal amount, with a final maturity date of March 1, 2020 and bearing interest of 4.41% per annum. The other tranche was for $67.6 million initial principal amount, with a final maturity date of March 1, 2023 and bearing interest at 5.61% per annum. The resulting weighted average interest rate of both tranches is 4.86% per annum, and the effective weighted average life is seven years. In June 2008, Cleco Power issued $250.0 million aggregate principal amount of senior unsecured notes at an interest rate of 6.65%. The notes mature on June 15, 2018. In October 2008, the Rapides Finance Authority issued $32.0 million of solid waste disposal facility bonds on behalf of Cleco Power. Cleco Power is obligated to pay the debt service on such bonds. The bonds mature October 1, 2038, and initially bear an interest rate of 6.0% per annum until October 1, 2011, at which time they are subject to mandatory tender for purchase at par. Cleco Power plans to remarket the bonds at the end of the three-year period.
In December 2008, the Louisiana Public Facilities Authority issued $100.0 million of GO Zone bonds on behalf of Cleco Power. Cleco Power is obligated to pay the debt service on such bonds. The bonds mature on December 1, 2038 and initially bear interest rate of 7.00% per annum until December 1, 2011, at which time they are subject to mandatory tender for purchase at par. Cleco Power plans to remarket the bonds at the end of the three-year period.
The capital lease in Cleco Power’s total indebtedness chart is for mobile computers with local area network capabilities. The lease term is for five years. The mobile computers can be purchased at the end of the lease term. The lease payments are due at the beginning of each month. The monthly lease payment is derived by multiplying the total acquisition costs by 1.92% for a full month and 0.06% per day for a partial month.
The amounts payable under the capital lease agreement for the next five years are listed below.
Credit Facilities
Cleco has two separate revolving credit facilities, one for Cleco Corporation and one for Cleco Power, with a maximum aggregate capacity of $425.0 million.
Cleco Corporation has a revolving five-year credit facility with a maximum capacity of $150.0 million that matures in 2011. Cleco Corporation’s borrowing costs under this facility are equal to LIBOR plus 0.65%, including facility fees. This facility provides for working capital and other needs. If Cleco Power defaults under the Cleco Power facility, then Cleco Corporation would be considered in default under the Cleco
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Corporation facility. At December 31, 2008, there was $30.0 million outstanding under Cleco Corporation’s credit facility. The interest rate was 1.725% at December 31, 2008 for outstanding borrowings under this credit facility. At December 31, 2008, Cleco Corporation was in compliance with the covenants in this credit facility. Off-balance sheet commitments entered into by Cleco Corporation with third parties for certain types of transactions between those parties and Cleco’s subsidiaries, other than Cleco Power, reduce the amount of credit available to Cleco Corporation under the facility by an amount equal to the stated or determinable amount of the primary obligation. At December 31, 2008, the $150.0 million of capacity was reduced by outstanding credit facility borrowings of $30.0 million and off-balance sheet commitments of $15.0 million, leaving available capacity of $105.0 million. An uncommitted line of credit with a bank in an amount up to $10.0 million also is available to support Cleco Corporation’s working capital needs.
Cleco Power has a revolving credit facility with a maximum capacity of $275.0 million that matures in 2011. This facility provides for working capital and other needs. Cleco Power’s borrowing cost under this facility is equal to LIBOR plus 0.40%, including facility fees. At December 31, 2008, there were no outstanding borrowings under this credit facility and Cleco Power was in compliance with the covenants in this credit facility. An uncommitted line of credit with a bank in an amount up to $10.0 million also is available to support Cleco Power’s working capital needs.
Note 7 - Common Stock
Stock-Based Compensation
Effective January 1, 2006, Cleco adopted the provisions of SFAS No. 123(R) for its share-based compensation plans. Cleco previously accounted for these plans under APB Opinion No. 25 and related interpretations and provided disclosure requirements established by SFAS No. 123. At December 31, 2008, Cleco had two stock-based plans within the scope of SFAS No. 123(R): the ESPP and the LTICP. Substantially all employees, excluding officers and general managers, may choose to participate in the ESPP and purchase a limited amount of common stock at a discount through a stock option agreement. Options or restricted shares of stock, known as non-vested stock as defined by SFAS No. 123(R), common stock equivalents, and stock appreciation rights may be granted to certain officers, key employees, or directors of Cleco Corporation and its subsidiaries pursuant to the LTICP.
Under APB Opinion No. 25, no share-based employee compensation was reflected in Cleco’s income statement, other than for non-vested stock grants, as all compensatory stock options granted had an exercise price equal to the fair market value of common stock on the date of grant, and ESPP options were considered noncompensatory. However, Cleco disclosed a pro forma fair value expense, as required by SFAS No. 123. The fair market value of non-vested stock was recorded as compensation expense during the service periods, which are generally three years, after which the restrictions lapse, and assuming obtainment of vesting requirements was probable. Under SFAS No. 123(R), all share-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as an expense in the income statement over the grant’s requisite service period. Awards that vest pro rata during the requisite service period that contain only a service condition could be viewed not as one award, but instead as multiple awards with separate vesting schedules and are defined as having a graded vesting schedule. As allowed by SFAS No. 123(R), Cleco has elected to view grants with graded vesting schedules as one award and recognize the related compensation expense on a straight-line basis over the requisite service period. Effective January 1, 2006, the ESPP was amended and met the definition of a noncompensatory plan pursuant to SFAS No. 123(R). The ESPP’s discount rate is 5%, substantially all employees can participate in the ESPP, and the plan does not contain optionality features beyond those listed by SFAS No. 123(R). Cleco is not required to recognize a fair-value expense related to the ESPP.
Cleco adopted SFAS No. 123(R) using the modified prospective method, which requires compensation expense to be recorded for all non-vested options and non-vested stock beginning in the first quarter of adoption. Under this transition method, compensation cost recognized includes the cost for all share-based payments granted prior to, but not yet vested, as of January 1, 2006. This cost was based on the grant-date fair value. The cost for all share-based awards granted subsequent to January 1, 2006, represents the grant-date fair value. Results for prior periods have not been restated. Cleco Corporation and Cleco Power reported pre-tax compensation expense for their share-based compensation plans as shown in the following table.
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Prior to the adoption of SFAS No. 123(R), Cleco did not disclose the amount of the stock-based compensation costs capitalized in property, plant and equipment. As required by SFAS No. 123(R), the amount of stock-based compensation capitalized in property, plant and equipment for the years ended December 31, 2008, and 2007, was $0.9 million and $3.0 million, respectively.
Cash received from options exercised under all share-based compensation plans for the years ended December 31, 2008, and 2007, were $1.0 million and $8.2 million, respectively. The associated tax benefit for options exercised for the years ended December 31, 2008, and 2007 was $0.1 million and $1.1 million, respectively. No cash was paid to settle equity instruments granted under the share-based compensation plans for the years ended December 31, 2008 or 2007.
Share-Based Plan Descriptions and Share Information
Stock Options
LTICP stock options may be granted to certain officers, key employees, or directors of Cleco. The directors’ stock options have an exercise price calculated by averaging the high and low stock price on the grant date rounded to the nearest one-eighth, are immediately exercisable, and expire after ten years. The employees’ stock options have an exercise price calculated by averaging the high and low stock price on the grant date rounded to the nearest one-eighth, vest one-third each year, beginning on the third anniversary of the grant date, and expire after ten years. Prior to the adoption of SFAS No. 123(R), Cleco recorded no charge to expense with respect to the granting of stock options at fair market value or above to employees or directors. However, pursuant to SFAS No. 123(R) the estimated fair value was calculated using the Black-Scholes option pricing model and was included in the pro forma disclosures. The fair market values of LTICP stock options granted in 2007 and the stock options granted prior to the adoption of SFAS No. 123(R), which were expensed for the first time in 2006, were measured on the grant date using the Black-Scholes option-pricing model, with the following weighted-average assumptions. There were no stock options granted in 2008.
A summary of LTICP stock option activity during the year ended December 31, 2008, is presented below.
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The total intrinsic value of options exercised during the years ended December 31, 2008, 2007, and 2006 was $0.2 million, $2.8 million, and $0.8 million, respectively.
Non-Vested Stock and Common Stock Equivalent Units
Through December 31, 2005, Cleco granted employees two types of non-vested stock with market and/or performance objectives. The first type, target shares, can be voted, and employees receive dividends on the shares prior to the lapse of the restrictions. The second type, opportunity shares, is not issued to employees until the market and/or performance objectives have been met; therefore, these shares cannot be voted, nor do employees receive dividends on the shares prior to the lapse of the restrictions. Both types of grants require the satisfaction of the service requirement, as well as the achievement of one or more market-based or performance-based objectives in order to obtain vesting. However, if certain events occur, such as retirement after age 55 prior to the end of the service period, then employees would vest in a pro rata number of target and opportunity shares.
In 2006, 2007, and 2008, Cleco granted non-vested stock and common stock equivalent units (CEUs) to certain employees. The non-vested stock is classified as equity since the grant can only be settled in shares of Cleco Corporation common stock. The recipients of the non-vested stock can vote the shares; however, dividends are not paid until the end of the service period and only in proportion to the non-vested stock that actually vests. The CEUs granted are classified as liabilities since the grant can only be settled in cash. Recipients of the CEUs will receive a dividend equivalent under the same terms as the dividends paid on the non-vested stock. In order to vest, both instruments require the satisfaction of a service requirement and a market-based requirement. Recipients of both types of instruments are eligible to receive opportunity instruments if certain market-based measures are exceeded.
At December 31, 2008, the number of target and opportunity restricted shares and CEUs previously granted for which restrictions had not lapsed totaled 650,208. Cleco also grants to employees and directors non-vested stock with only a service period requirement. These grants require the satisfaction of a pre-determined service period in order for the shares to vest. During the vesting period, the employees and directors can vote and receive dividends on the shares. At December 31, 2008, the number of shares of non-vested stock previously granted with only a service period requirement for which the period had not ended was 81,911.
The fair value of shares of non-vested stock granted in 2008, 2007, and 2006 under the LTICP is estimated on the date of grant, and the CEUs granted in 2008, 2007, and 2006 under the LTICP are marked-to-market using the Monte Carlo simulation model with the assumptions listed in the following table.
A summary of non-vested stock activity during the year ended December 31, 2008, is presented below.
The fair value of shares of non-vested stock which vested during the years ended December 31, 2008, 2007, and 2006 was $2.4 million, $3.7 million, and $3.9 million, respectively.
During the years ended December 31, 2008, 2007, and 2006, Cleco did not significantly modify any of the terms of outstanding awards. Certain awards of stock-based compensation allowed vesting of a pro rata share of granted instruments upon retirement after age 55 but before the end of the normal vesting period, regardless of whether the performance or market-based measures were achieved. These same awards contained a provision of accelerated vesting of the entire grant upon retirement after age 65 but before the end of the normal vesting period, regardless of whether the performance or market-based measures were achieved. In all periods presented, Cleco has recognized stock-based compensation expense for these provisions, which is known
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as the non-substantive vesting period approach. The grants of non-vested stock to employees in January 2008, 2007, and 2006 did not contain the accelerated vesting provisions included in the prior years’ grants.
A maximum of 3.2 million shares of Cleco Corporation common stock can be granted under the LTICP. As of December 31, 2008, there were approximately 1.5 million shares available for future grants under the LTICP. Equity instruments awarded to employees and directors historically have come from issuing new shares of common stock. As of December 31, 2008, there were 83,181 non-vested share-based compensation arrangements granted under the LTICP that are expected to vest over an average period of 1.6 years. The total unrecognized before-tax compensation cost was $1.6 million for non-vested share-based compensation arrangements granted under the LTICP.
Retained Earnings Restrictions
Various debt agreements contain covenants that restrict the amount of retained earnings that may be distributed as dividends to common shareholders. The most restrictive covenant requires Cleco Corporation’s total indebtedness to be less than or equal to 65% of total capitalization. At December 31, 2008, approximately $431.2 million of retained earnings were unrestricted.
Shareholder Rights Plan
In July 2000, Cleco Corporation’s Board of Directors adopted the Shareholder Rights Plan (Rights Plan). Under the Rights Plan, the holders of common stock as of August 14, 2000, received a dividend of one right for each share of common stock held on that date. In the event an acquiring party accumulates 15% or more of Cleco Corporation’s common stock, the rights would, in essence, allow the holder to purchase Cleco Corporation’s common stock at half the current fair market value. Cleco Corporation generally would be entitled to redeem the rights at $.01 per right at any time until the tenth day following the time the rights become exercisable. The rights expire on July 30, 2010.
Employee Stock Purchase Plan
In January 2000, Cleco Corporation’s Board of Directors adopted the ESPP. Shareholders approved the plan in April 2000, and the plan was implemented on October 1, 2000.
Regular, full-time, and part-time employees of Cleco Corporation and its participating subsidiaries, except officers, general managers, and employees who own 5% or more of Cleco Corporation’s stock, may participate in the ESPP. An eligible employee enters into an option agreement to become a participant in the ESPP. Under the agreement, the employee authorizes payroll deductions in an amount not less than $10 but not more than $350 each pay period. Payroll deductions are accumulated during a calendar quarter and applied to the purchase of common stock at the end of each quarter, which is referred to as an “offering period.” Pending the purchase of common stock, payroll deductions remain as general assets of Cleco. No trust or other fiduciary account has been established in connection with the ESPP. At the end of each offering period, payroll deductions are automatically applied to the purchase of shares of common stock. The number of shares of common stock purchased is determined by dividing each participant’s payroll deductions during the offering period by the option price of a share of common stock. Prior to January 1, 2006, the option price of a share of common stock was equal to 85% of the lower of the closing price at the beginning or the end of each offering period. Effective January 1, 2006, the option price of a share of common stock is equal to 95% of the price of stock on the last trading day of each offering period.
A maximum of 684,000 shares of common stock may be purchased under the ESPP, subject to adjustment for changes in the capitalization of Cleco Corporation. The Compensation Committee of Cleco Corporation’s Board of Directors administers the ESPP. The Compensation Committee and the Board of Directors each possess the authority to amend the ESPP, but shareholder approval is required for any amendment that increases the number of shares covered by the ESPP. As of December 31, 2008, there were 433,555 shares of common stock left to be purchased under the ESPP.
Common Stock Issuance
In August 2006, Cleco Corporation issued 6.9 million shares of common stock in a public offering. Cleco’s net proceeds from the issuance totaled $157.5 million.
Common Stock Repurchase Program
In 1991, the Board of Directors authorized management to repurchase up to $30.0 million of common stock. At December 31, 2008, approximately $16.1 million of common stock was available for repurchase under this authorization. Purchases are made on a discretionary basis at times and in amounts as determined by management, subject to market conditions, legal requirements, and other factors. The purchases may not be announced in advance and may be made in the open market or in privately negotiated transactions. Cleco Corporation did not purchase any common stock under the repurchase authorization in 2008, 2007, or 2006. There is no expiration date for the program.
Note 8 - Preferred Stock
Within the ESOP, each share of Cleco Corporation 8.125% Convertible Preferred Stock Series of 1991 (ESOP preferred stock) was convertible into 9.6 shares of Cleco Corporation common stock (Cleco common stock). The annual dividend rate on a share of ESOP preferred stock was generally the higher of $8.125 per share or 9.6 times the annual dividend rate for a share of Cleco common stock.
The amount of total capitalization reflected in Cleco Corporation’s Consolidated Financial Statements has been reduced by an amount of deferred compensation expense related to the shares of convertible preferred stock that have not yet been allocated to ESOP participants. For the years 2007 and 2008, no income tax benefit was recorded in Cleco Corporation’s Consolidated Financial Statements.
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At December 31, 2006, the ESOP had allocated 190,634 shares of ESOP preferred stock to 401(k) Plan participants. In March 2007, in order to comply with provisions of the Pension Protection Act of 2006, 190,372 shares of ESOP preferred stock were converted into 1.8 million shares of Cleco common stock. The ESOP trustee holds the newly converted shares of Cleco common stock on behalf of the 401(k) Plan participants. After such conversion, no shares of ESOP preferred stock remain outstanding.
As a result of this conversion, total shareholders’ equity reported on Cleco Corporation’s Consolidated Balance Sheets at December 31, 2007, did not change. Cleco Corporation recorded a $19.1 million reduction in preferred stock with a corresponding increase in common shareholders’ equity.
Upon involuntary liquidation of their stock, preferred shareholders are entitled to receive par value for shares held before any distribution is made to common shareholders. Upon voluntary liquidation, preferred shareholders are entitled to receive the redemption price per share applicable at the time such liquidation occurs, plus any accrued dividends.
Information about the components of preferred stock capitalization is as follows.
The 4.5% cumulative preferred stock not subject to mandatory redemption has an optional redemption price of $101 per share.
Note 9 - Pension Plan and Employee Benefits
SFAS No. 158
On December 31, 2006, Cleco adopted SFAS No. 158, which requires companies to recognize the funded status of their postretirement benefit plans as a net liability or asset. The net liability or asset is defined as the difference between the benefit obligation and the fair market value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation, whereas for other benefit plans, the benefit obligation is the accumulated postretirement benefit obligation. Net actuarial gains/losses, prior period service costs, and transition obligations/assets are a component of accumulated other comprehensive income, net of income tax in shareholders’ equity.
SFAS No. 158 requires companies to set their measurement date to correspond with their fiscal year end, eliminating the option to use an earlier measurement date. The measurement date provision is effective for fiscal years ending after December 15, 2008. Cleco’s measurement date currently is the same as its fiscal year end; therefore, the measurement date provision had no impact on the Registrants.
Pension Plan and Other Benefits Plan
Most employees are covered by a noncontributory, defined benefit pension plan. 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 10 years of employment with Cleco Corporation. Cleco Corporation’s policy is to base its contributions to the employee pension plan upon actuarial computations utilizing the projected unit credit method, subject to the IRS’s full funding limitation. During 2008, Cleco made a discretionary contribution in the amount of $6.0 million. No discretionary contributions were made in 2007 or 2006. Currently, a contribution required by funding regulations could be as much as $1.0 million in 2009. A discretionary contribution may be made during 2009. However, the decision by management to make a contribution in 2009 and the amount, if any, has not been determined. Currently, Cleco Power expects to be required to make $80.0 million in contributions to the pension plan over the next five years. The required contributions are driven by liability funding target percentages set by law which could cause the required contributions to be uneven among the years. The ultimate amount and timing of the contributions will be affected by changes in the discount rate, changes in the funding regulations, and actual returns on fund assets. Cleco Power is considered the plan sponsor, and Support Group is considered the plan administrator.
Cleco Corporation’s retirees and their dependents are eligible to receive medical, dental, vision, and life insurance benefits (other benefits). Cleco Corporation recognizes the expected cost of these benefits during the periods in which the benefits are earned.
The employee pension plan and other benefits obligation plan assets and funded status at December 31, 2008, and 2007, are presented in the following table.
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The employee pension plan accumulated benefit obligation at December 31, 2008, and 2007, is presented in the following table.
SFAS No. 158 requires the disclosure of the net actuarial gains/losses, transition obligations/assets, and prior period service costs included in other comprehensive income as a result of being included as a component of net periodic benefit costs. The following table presents those items for the employee pension plan and other benefits plan at December 31, 2007 and 2008.
SFAS No. 158 also requires the disclosure of the net gains/losses, transition obligations/assets, and prior period service costs/credits in accumulated other comprehensive income that have not been recognized as components of net periodic benefit costs and the amounts expected to be recognized in 2009. The following table presents those items for the employee pension plan and other benefits plans for December 31, 2007, 2008, and 2009.
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The components of net periodic pension and other benefits cost for 2008, 2007, and 2006 are as follows.
Since Cleco Power is the pension plan sponsor and the related trust holds the assets, the prepaid benefit cost of the pension plan is reflected at Cleco Power. The liability of Cleco Corporation’s other subsidiaries is transferred, with a like amount of assets, to Cleco Power monthly. The expense of the pension plan related to Cleco Corporation’s other subsidiaries for the years ended December 31, 2008, 2007, and 2006 was $1.5 million, $2.0 million, and $2.2 million, respectively.
Cleco Corporation is the plan sponsor for the other benefit plans. There are no assets set aside in a trust, and the liabilities are reported on the individual subsidiaries’ financial statements. The expense related to other benefits reflected in Cleco Power’s Consolidated Statements of Income for the years ended December 31, 2008, 2007, and 2006 was $2.2 million, $2.1 million, and $1.7 million net of the estimated Medicare Part D subsidy of $0.3 million, $0.3 million, and $0.4 million. Cleco Power’s allocated amount of the other benefit liability was $26.4 million and $25.3 million at December 31, 2008, and 2007, respectively.
The measurement date used to determine the pension and other postretirement benefits is December 31. The assumptions used to determine the benefit obligation and the periodic costs are as follows.
The expected return on plan assets was determined by examining the risk profile of each target category as compared to the expected return on that risk, within the parameters determined by the retirement committee. The result was also compared to the expected rate of return of other comparable plans. In assessing the risk as compared to return profile, historical returns as compared to risk was considered. The historical risk compared to returns was adjusted for the expected future long-term relationship between risk and return. The adjustment for the future risk compared to returns was, in part, subjective and not based on any measurable or observable events.
Employee pension plan assets may be invested in publicly traded domestic common stocks, including Cleco Corporation common stock; U.S. Government, federal agency and corporate obligations; an international equity fund, commercial real estate funds; a hedge fund-of-funds; and pooled temporary investments. The table below shows a breakdown of the plan assets by investment category based on market values at December 31, 2008, and 2007.
As of December 31, 2008, the pension plan held no shares of Cleco Corporation common stock. None of the plan participants’ future annual benefits is covered by insurance contracts. As a result of the significant market declines, the pension plan portfolio experienced significant losses during 2008 that resulted in a $96.2 million decrease in the funded status of the plan. These losses, in conjunction with funding requirements, may lead to increased or earlier contributions than previously anticipated. In December 2008, Cleco became aware that, through its hedge fund-of-funds manager, a portion of its pension plan assets were invested in the Madoff feeder fund investment, Ascot Fund Limited. The total losses
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associated with this fund were approximately $0.7 million. In January 2009, Cleco Power elected to liquidate the holdings of the hedge fund-of-funds manager. Proceeds from the hedge fund-of-funds manager will be reallocated to the plan’s other equity managers.
Cleco Corporation’s retirement committee has established investment performance objectives of the pension plan assets. Over a three- to five-year period, the objectives are for the pension plan’s annualized total return to:
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Exceed the assumed rate of return on plan assets;
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Exceed the annualized total return of a customized index consisting of a mixture of Standard & Poor’s 500 Index; Russell Mid Cap Value Index; Morgan Stanley Capital International Europe, Australia, Far East Index; Lehman Brothers U.S. Universal Index; and the median real estate manager performance in the Hewitt Investment Group open end real estate universe; and
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Rank in the upper 50 percent of a universe of composite pension funds.
In order to meet the objectives and to control risk, the retirement committee has established guidelines that the investment managers must follow.
Domestic Equity Portfolios
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Equity holdings of a single company must not exceed 10% of the manager’s portfolio.
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A minimum of 25 stocks should be owned.
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Equity holdings in a single sector should not exceed the lesser of three times the sector’s weighting in the Standard & Poor’s 500 Index or 35% of the portfolio.
International Equity Portfolios
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Equity holdings of a single company should not exceed 5% of the manager’s portfolio.
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A minimum of 30 stocks should be owned.
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Equity holdings in a single sector should not exceed 35%.
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Currency hedging decisions are at the discretion of the investment manager.
Debt Portfolios
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At least 85% of the debt securities should be investment grade securities (BBB- by Standard & Poor’s or Baa3 by Moody’s) or higher.
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Bond purchases should be limited to readily marketable securities.
Real Estate Portfolios
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Real estate funds should be invested primarily in direct equity positions, with debt and other investments representing less than 25% of the fund.
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Leverage should be less than 70% of the market value of the fund.
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Investments should be focused on existing income-producing properties, with land and development properties representing less than 40% of the fund.
Hedge Fund-of-Funds
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The fund should be invested in a minimum of 20 individual partnerships.
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No individual partnership should exceed 10% of the fund-of-funds.
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The fund should be diversified across several different “styles” of partnerships, including event-driven strategies, fixed income arbitrage and trading, and other arbitrage strategies. The fund generally should not be invested in emerging markets, short-term only, traditional Commodity Trading Advisor’s or derivative-only strategies.
Fund managers are allowed limited use of derivatives, subject to policies and guidelines established by the committee and to the following restrictions:
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Derivatives may be used only if the vehicle is deemed by the manager to be more attractive than a similar investment in the underlying cash market; or if the vehicle is being used to manage risk of the portfolio.
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The derivatives may not be used in a speculative manner or to leverage the portfolio.
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The derivatives may not be used as short-term trading vehicles.
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Investment managers shall alert the Retirement Committee, in writing, before engaging in strategies which use derivatives. The written communication shall include the nature and purpose of the strategy, a quantification of the magnitude of the program in absolute dollar terms, an outline of the methods to be used to monitor the program, and an outline of the process to be followed in reporting on commitments relative to established guidelines and on the success of the proposed strategy.
Due to the nature of the hedge fund-of-funds, its manager is exempt from the above derivative policy.
The Retirement Committee has established the following investment asset allocation target percentages for the pension plan assets.
The estimated impact of future Medicare subsidies reduced the January 1, 2008, and 2007, accumulated postretirement benefit obligation by $5.8 million for each year, and reduced the other benefit costs for the twelve months ended December 31, 2008, and 2007, as follows.
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The assumed health care cost trend rates used to measure the expected cost of other benefits was 9.0% in 2009, 2008, and 2007. The rate declines to 5.0% by 2028 and remains at 5.0% thereafter. 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.
The projected benefit payments and projected receipts pursuant to Medicare Part D subsidy, the employee pension plan, and other benefits obligation plan for each year through 2013 and the next five years thereafter are listed below.
SERP
Certain key executives and key managers of Cleco are covered by the SERP. The SERP is a non-qualified, non-contributory, defined benefit pension plan. Benefits under the plan reflect an employee’s years of service, age at retirement, and the sum of the highest base salary paid out of the last five calendar years and the average of the three highest bonuses paid during the last 60 months prior to retirement, reduced by benefits received from any other defined benefit pension plan, SERP Plan or Cleco contributions under the enhanced 401(k) Plan to the extent such contributions exceed the limits of the 401(k) Plan. Cleco Corporation does not fund the SERP liability, but instead pays for current benefits out of the general funds available. Cleco Power has formed a Rabbi Trust designated as the beneficiary for life insurance policies issued on the SERP participants. Proceeds from the life insurance policies are expected to be used to pay SERP participants’ life insurance benefits, as well as future SERP payments. However, since this is a non-qualified plan, the assets of the trust could be used to satisfy general creditors of Cleco Power in the event of insolvency. All SERP benefits are paid out of the general cash available of the respective companies from which the officer retired. No contributions to the SERP were made during the three-year period ended December 31, 2008. Cleco Power is considered the plan sponsor, and Support Group is considered the plan administrator.
The SERP’s funded status at December 31, 2008, and 2007, is presented in the following table.
The SERP’s accumulated benefit obligation at December 31, 2008, and 2007, is presented in the following table.
SFAS No. 158 requires the disclosure of the net actuarial gains/losses, transition obligations/assets, and prior period service costs included in other comprehensive income as a result of being amortized as a component of net periodic benefit costs. The following table presents those items for the SERP at December 31, 2007 and 2008.
SFAS No. 158 also requires the disclosure of the net gains/losses, transition obligations/assets, and prior period service costs/credit in accumulated other comprehensive income that have not been recognized as components of net periodic benefit costs and the amounts expected to be recognized in 2009. The following table presents those items for SERP for December 31, 2007, 2008, and 2009.
The components of the net SERP cost for 2008, 2007, and 2006 are as follows.
To calculate periodic costs and the benefit obligation, the SERP uses the same discount rate and average rate of compensation increase as the employee pension plan for the
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same time periods. The SERP also uses the same measurement dates. The expected return on plan assets is not applicable since the SERP has no assets.
The liabilities of the SERP are reported on the individual subsidiaries’ financial statements. The expense related to the SERP reflected on Cleco Power’s Consolidated Statements of Income for the years ended December 31, 2008, 2007, and 2006 was $1.0 million, $1.1 million, and $1.0 million, respectively. Cleco Power’s allocated amount of the SERP liability was $12.1 million and $11.4 million at December 31, 2008, and 2007, respectively. Cleco Corporation’s other subsidiaries reflected expense relative to SERP of $3.0 million, $3.2 million, and $2.8 million for the years ended December 31, 2008, 2007, and 2006, respectively. At December 31, 2008, and 2007, Cleco Corporation’s other subsidiaries’ allocated amount of SERP liability was $21.1 million and $18.3 million, respectively.
The projected benefit payments for the SERP for each year through 2013 and the next five years thereafter are listed below.
401(k)/ESOP Plan
Most employees are eligible to participate in the 401(k) Plan, which was amended in April 1991 to include a leveraged ESOP. The ESOP was established with 300,000 convertible preferred shares which served as Cleco Corporation’s match to employees’ 401(k) Plan contributions and funded dividend payments on allocated shares. By late March 2006, substantially all of the ESOP preferred shares were fully allocated to current and former 401(k) Plan participants. Beginning January 2007, Cleco Corporation made matching contributions and funded dividend reinvestments with Cleco Corporation common stock. On March 26, 2007, the ESOP trustee converted all outstanding 190,372 shares of ESOP preferred stock into 1.8 million shares of Cleco Corporation common stock. Beginning January 2008, Cleco Corporation made matching contributions and funded dividend reinvestments with cash.
The table below contains information about the 401(k) Plan and the ESOP.
Cleco Power is the plan sponsor for the 401(k) Plan. The expense of the 401(k) Plan related to Cleco Corporation’s other subsidiaries was $1.0 million, $0.6 million, and $0.5 million for the years ended December 31, 2008, 2007, and 2006, respectively. The expense related to the dividend requirements of the ESOP on convertible preferred stock is reflected on Cleco Corporation’s Consolidated Statements of Income for the years ended December 31, 2007 and 2006.
Note 10 - Income Taxes
Cleco
For the years ended December 31, 2008 and December 31, 2007, income tax expense was less than the amount computed by applying the statutory federal rate to income before tax. For the year ended December 31, 2006, income tax expense was more than the amount computed by applying the statutory federal rate to income before tax. The differences are as follows.
Information about current and deferred income tax expense is as follows.
The $0.3 million change in total tax benefit from items charged directly to stockholders’ equity in 2008 compared to 2007 was primarily due to the tax effect of other post-employment benefit adjustments booked to accumulated
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other comprehensive income per SFAS No. 158. For additional information, see Note 2 - “Summary of Significant Accounting Policies - Recent Accounting Standards.”
The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2008, and 2007, was comprised of the tax effect of the following.
Management considers it more likely than not that all deferred tax assets will be realized. Consequently, deferred tax assets have not been reduced by a valuation allowance.
Cleco Power
Income tax expense is less than the amount computed by applying the statutory rate to income before tax, as follows.
Information about current and deferred income tax expense is as follows.
The $0.3 million change in total tax benefit from items charged directly to stockholders’ equity in 2008 compared to 2007 was primarily due to the tax effect of other post-employment benefit adjustments booked to accumulated other comprehensive income per SFAS No. 158. For additional information, see Note 2 - “Summary of Significant Accounting Policies - Recent Accounting Standards.”
The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2008, and 2007, was comprised of the tax effect of the following.
Management considers it more likely than not that all deferred tax assets will be realized. Consequently, deferred tax assets have not been reduced by a valuation allowance.
Uncertain Tax Positions
Effective January 1, 2007, Cleco adopted the provisions of FIN 48 which provide guidance on accounting for uncertain tax positions. With the adoption of FIN 48, Cleco classified all interest related to uncertain tax positions as a component of
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interest expense and interest payable. The total amount of interest associated with tax positions recognized on Cleco Corporation’s and Cleco Power’s Consolidated Balance Sheets was $26.4 million and $15.9 million as of December 31, 2008, respectively. The total amount of interest expense related to uncertain tax positions recognized on the income statements of both Cleco Corporation and Cleco Power for the year ended December 31, 2008, was $0.8 million. The total liability for unrecognized tax benefits for Cleco Corporation and Cleco Power at December 31, 2007 and 2008 is shown in the following table:
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In the first quarter of 2008, Cleco and the IRS agreed to apply industry-wide guidelines as the basis for settling a potential dispute regarding the amount of indirect overhead costs required to be capitalized for tax purposes. Based on acceptance of the settlement guidelines, Cleco recorded, in the first quarter of 2008, an estimated interest benefit of approximately $2.1 million.
The federal income tax years that remain subject to examination by the IRS are 2001 through 2007. The Louisiana state income tax years that remain subject to examination by the Louisiana Department of Revenue are 2000 through 2007.
During the twelve months ended December 31, 2008, there were no decreases in unrecognized tax benefits relating to settlements or a lapse of the applicable statute of limitation, and there were no material changes to tax years that remain subject to examination by major tax jurisdictions.
Note 11 - Disclosures about Segments
Cleco
Cleco’s reportable segments are based on its method of internal reporting, which disaggregates business units by first-tier subsidiary. Reportable segments were determined by applying SFAS No. 131. Cleco’s reportable segments are Cleco Power and Midstream. The reconciling items in the following tables consist of the holding company, a shared services subsidiary, two transmission interconnection facilities, and an investment subsidiary. Effective February 1, 2007, the ownership interests of Midstream’s transmission interconnection facilities were transferred to Cleco Corporation. In accordance with SFAS No. 131, the prior period presentation has been adjusted to reflect this change in organizational structure.
Each reportable segment engages in business activities from which it earns revenue and incurs expenses. Segment managers report periodically to Cleco’s Chief Executive Officer (the chief operating decision-maker) with discrete financial information and, at least quarterly, present discrete financial information to Cleco Corporation’s Board of Directors. Each reportable segment prepared budgets for 2008 that were presented to and approved by Cleco Corporation’s Board of Directors.
The financial results of Cleco’s segments are presented on an accrual basis. Management evaluates the performance of its segments and allocates resources to them based on segment profit and the requirements to implement new strategic initiatives and projects to meet current business objectives. Material intercompany transactions occur on a regular basis. These intercompany transactions relate primarily to joint and common administrative support services provided by Support Group. For information on these services, see Note 17 - “Affiliate Transactions.”
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SEGMENT INFORMATION
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Cleco Power
Cleco Power 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 standards applicable to segment reporting as defined by SFAS No. 131.
Note 12 - Electric Customer Credits
Beginning in 1996, the amount of Cleco Power’s yearly retail earnings has been subject to the terms of a RSP established by Cleco Power and the LPSC in a 1996 earnings review settlement. The RSP establishes a target return on common equity and requires all or a portion of regulated earnings for each yearly review period above the targeted regulatory rate of return on equity to be credited to Cleco Power’s customers.
The terms of the current RSP were approved by the LPSC in July 2006, and became effective October 1, 2006, in accordance with Cleco Power’s request to extend the RSP to the in-service date of Rodemacher Unit 3, which is expected to be operational in the second half of 2009. The current RSP allows Cleco Power the opportunity to earn a maximum regulated return on equity of 11.65%. This maximum return is based on a return on equity of 11.25%, with any regulated earnings between 11.25% and 12.25% shared between shareholders and customers in a 40/60 ratio. All regulated earnings over 12.25% will be returned to customers. The amount of credits due customers, if any, is determined by Cleco Power and the LPSC annually, based on results for each 12-month period ended September 30. The RSP terms require the credits to be included on customers’ bills the following summer.
The terms of the original 1996 LPSC RSP settlement, effective through September 30, 2006, allowed Cleco Power 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 were credited to customers. This effectively allowed Cleco Power the opportunity to realize a regulatory rate of return up to 12.625%.
Cleco’s reported earnings for the 12-month period ended December 31, 2006, increased due to reversals of previously accrued credits of $4.7 million.
The $4.7 million reversal of previously accrued credits mentioned above was the result of two events. The first event was the April 2006 settlement of issues raised in the LPSC’s review of Cleco Power’s RSP filings for the 12-months ended September 30, 2002, 2003, and 2004. Based on the terms of the settlement, Cleco Power reversed previously accrued customer credits of $3.2 million in the first quarter of 2006, and refunded $1.3 million as credits on customers’ September 2006 utility bills. In this proceeding, the LPSC also reserved the right to further review Cleco Power’s calculation of working capital included in the filings. Cleco Power reached an agreement of the working capital issue with the LPSC, reversed previously accrued customer credits of $0.3 million in December 2006, and refunded an additional $3.2 million of previously accrued credits to customers in March 2007.
The second event was the April 2006 filing by Cleco Power of its required RSP monitoring report for the 12-month period ended September 30, 2005. Based on the reassessment of amounts filed in this monitoring report, the results of the Staff’s review as discussed above, and projections for the year 2006, Cleco Power reversed in the first quarter of 2006, an additional $1.2 million of customer credits previously accrued for the 12-months ended September 30, 2005, and 2006.
The Staff completed the review of Cleco Power’s RSP monitoring reports for the 12-month periods ended September 30, 2005 and 2006, during 2007. The Staff’s reports indicated
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that no customer refunds were due for these periods based on the filings. In January 2008, Cleco Power filed its monitoring report for the 12-month period ended September 30, 2007. Cleco Power anticipates that the LPSC Staff will complete the review of this report by the end of the third quarter of 2009.
In February 2009, the LPSC granted Cleco Power an extension until April 30, 2009 in which to file its monitoring report for the year ended September 30, 2008.
Cleco Power’s Consolidated Balance Sheets at December 31, 2008, and 2007 reflect the following accruals for estimated electric customer credits.
The amounts reported under the line item other deferred credits relate to potential fuel audit issues and currently are not due. All customer credits relating to Cleco Power’s RSP were recorded as a reduction in revenue due to the nature of the credits. The accruals were based upon the original 1996 settlement, the modified terms of the RSP extension, the 2004 resolution of the 2001 through 2002 fuel audit, annual issues as agreed to between Cleco and the LPSC, and Cleco’s assessment of issues that remain outstanding.
In February 2006, the LPSC approved Cleco Power’s request to recover storm restoration costs incurred for Hurricanes Katrina and Rita. As part of this approval, the LPSC required that effective during the interim recovery period (Phase I), which began with the May 2006 billing cycle, Cleco Power’s portion of the shared regulated earnings between the 12.25% and 13.00% allowed return on equity (between 11.25% and 12.25% effective October 1, 2006) be credited against outstanding Hurricanes Katrina and Rita storm restoration costs, rather than being shared between shareholders and customers. In September 2007, as a result of Phase II of the LPSC Staff’s review of storm restoration costs, the LPSC approved a settlement agreement between Cleco Power and the LPSC Staff allowing recovery of essentially all of Cleco Power’s Hurricanes Katrina and Rita storm costs. As part of the agreement, Cleco Power will continue to forgo its share of any excess earnings calculated according to the term of the current RSP (unless modified in a subsequent base rate proceeding). As of December 31, 2008, Cleco Power had not credited any earnings against storm restoration costs. For information concerning this agreement, see Note 3 - “Regulatory Assets and Liabilities.”
Note 13 - Equity Investment in Investees
Cleco reports its investment in Acadia, Evangeline, and certain other subsidiaries on the equity method of accounting in accordance with APB Opinion No. 18, after consideration of FIN 46R. Under the equity method, the assets and liabilities of these entities are reported as equity investment in investees on Cleco Corporation’s Consolidated Balance Sheets. The revenue and expenses (excluding income taxes) of these
entities are netted and reported as equity income from investees on Cleco Corporation’s Consolidated Statements of Income.
Equity investment in investees represents primarily Midstream’s $178.7 million investment in Acadia, owned 50% by APH and 50% by Cajun, and its $55.6 million investment in Evangeline, owned 100% by Midstream. Equity investment in investees also represents a $7.4 million investment in Attala and a $7.5 million investment in Perryville, both owned 100% by Cleco Corporation. Equity investments which are less than 100% owned by Cleco Innovations LLC represent less than $0.1 million of the total balance.
The table below presents the equity (loss) income from each investment accounted for using the equity method.
For the year ended December 31, 2007, APH’s equity income included net proceeds of $78.2 million from the settlement of the Calpine bankruptcy claims. It also included $60.0 million of priority distributions received at the closing of the sale of CAH’s 50% equity ownership interest in Acadia, partially offset by a $45.8 million other-than-temporary impairment of the carrying value of the investment in Acadia at the APH level. For more information on these claims, see Note 20 - “Calpine Bankruptcy Settlement.”
For the year ended December 31, 2006, APH’s equity income included the drawing in full of a $15.0 million letter of credit. The letter of credit, of which APH was the beneficiary, was posted by Calpine to support its obligations under the Calpine Tolling Agreements.
Acadia
Since Acadia is owned 50% by APH and 50% by Cajun, neither owner is the primary beneficiary, and Acadia is accounted for as an equity method investment.
Cleco’s current assessment of its maximum exposure to loss related to Acadia at December 31, 2008, consists of its equity investment of $178.7 million. The table below presents the components of Midstream’s equity investment in Acadia.
The $78.2 million non-cash distribution is the distribution of the CES claim from Acadia to APH. The cash distributions of
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$136.5 million were used to pay interest and repay principal on a loan from Cleco Corporation relating to this investment.
Midstream’s equity, as reported on the balance sheet of Acadia at December 31, 2008, was $204.8 million. The difference between the $204.8 million and the equity investment in investee of $178.7 million shown in the previous table is $26.1 million, and consists of the $45.8 million other-than-temporary impairment of APH’s investment in Acadia, partially offset by $19.7 million of interest capitalized on funds contributed by Acadia.
In December 2005, the Calpine Debtors, including CES and the subsidiary which owned the other 50% of Acadia, filed voluntary petitions in the Calpine Debtors Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. In 2006, APH drew the entire $15.0 million Calpine letter of credit due to the default of CES under the tolling agreements. This amount was reported as equity income from investees on Cleco Corporation’s Consolidated Statements of Income.
In May 2007, the Calpine Debtors Bankruptcy Court approved the terms of the April 2007 settlement agreement with Calpine that resolved issues surrounding the Calpine bankruptcy filing and its effect on the Acadia facility. In September 2007, after all regulatory approvals were received, the sale of CAH’s Assets to Cajun was completed. For additional information, see Note 20 - “Calpine Bankruptcy Settlement.”
The table below contains summarized financial information for Acadia.
Income taxes recorded on APH’s financial statements related to Midstream’s 50% ownership interest in Acadia were a $7.4 million benefit for the year ended December 31, 2008, compared to expense of $34.3 million for the year ended December 31, 2007, and a $4.1 million benefit for the year ended December 31, 2006. The decrease in income tax expense at APH is primarily due to the absence in 2008 of the settlement of Acadia’s pre-petition unsecured claims against CES and Calpine.
Evangeline
Since its inception, Cleco has had 100% ownership and voting interest of Evangeline. Through an analysis of variable interests, such as Cleco’s investment, the long-term debt, the tolling counterparty, and the potential to absorb expected losses and gains, Cleco has determined that it is not the primary beneficiary. The determination is driven by several factors such as:
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The tolling counterparty is at risk to absorb market losses and gains, which are primarily determined by the relative price of electricity and natural gas.
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The debt is non-recourse to Cleco; therefore, the debt-holders main security is the underlying assets of Evangeline.
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Cleco’s risk of loss is limited to its investment plus the $15.0 million letter of credit issued on behalf of the tolling counterparty.
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The size of Evangeline’s debt compared to the size of Cleco’s investment at risk.
Since Cleco is not the primary beneficiary, Evangeline is accounted for as an equity method investment.
Cleco’s current assessment of its maximum exposure to loss related to Evangeline at December 31, 2008, consists of its equity investment of $55.6 million and $15.0 million of possible draws on the letter of credit Cleco has posted on Evangeline’s behalf, for a total of $70.6 million. The table below presents the components of Midstream’s equity investment in Evangeline.
The table below contains summarized financial information for Evangeline.
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The difference between the equity investment in investee and member’s deficit shown in the tables above is due to income tax items being reported in the corresponding tax accounts on Midstream’s financial statements, rather than the equity investment account.
The difference between Evangeline’s income before taxes on the table above and the equity income on the previous equity income from investment table is due to tax adjustments made to reflect Evangeline’s financial statements on a stand-alone basis.
Cleco Corporation has posted a $15.0 million letter of credit on behalf of the Evangeline Tolling Agreement counterparty. The letter of credit can be drawn in the event Evangeline defaults on the tolling agreement.
Evangeline’s restricted cash at December 31, 2008, and 2007, was $25.0 million and $33.3 million, respectively. This cash is restricted under Evangeline’s senior secured bond indenture.
Income tax expense recorded on Midstream’s financial statements related to Midstream’s 100% ownership interest in Evangeline was $1.0 million, $4.0 million, and $8.6 million for the years ended December 31, 2008, 2007, and 2006, respectively.
Prior to November 9, 2007, all of the capacity and output of the power plant had been tolled to Williams which paid Evangeline certain fixed and variable amounts. In November 2007, The Williams Companies, Inc. assigned all of its rights and interests in its tolling agreement with Evangeline to Bear Energy. In May 2008, JPMorgan Chase & Co. completed the acquisition of Bear Stearns Companies Inc., the parent company of Bear Energy. For more information regarding Bear Energy and the announced purchase by JPMorgan Chase & Co., see Note 15 - Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees - Risks and Uncertainties.”
Other Subsidiaries 100% owned by Cleco Corporation
The information about these entities is aggregated because their operations, size and risk are materially similar. Both entities own transmission assets, provide transmission services to one customer under a long-term contract at a FERC approved cost of service rate, and are capitalized with 100% equity.
Through an analysis of variable interest, such as Cleco’s investment and the single counterparty that has a long-term lease of the facilities, Cleco has determined that it is not the primary beneficiary of either entity. The determination is driven by several factors such as:
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Each entity has only one customer under the long-term agreements accounted for as direct financing leases.
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Both entities can only charge FERC approved tariffs.
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Both entities have the ability to change the tariff if actual expenses are materially different than expected expenses.
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The requirement of the lease counterparty to make lease payments regardless of the use of the assets.
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Cleco’s risk of loss is limited to its investment.
Since Cleco is not the primary beneficiary, the investment in Perryville and Attala are accounted for as equity method investments.
Cleco’s current assessment of its maximum exposure to loss with respect to Perryville and Attala at December 31, 2008, consists of its equity investment of $14.9 million. The table below presents the components of Cleco Corporation’s equity investments in Perryville and Attala.
The tables below contain summarized financial information for Perryville and Attala.
The difference between the equity investment in investee and member’s equity shown in the tables above is due to income tax items being reported in the corresponding tax accounts on Cleco Corporation’s financial statements, rather than the equity investment account.
The transmission assets utilized by Perryville and Attala are accounted for as direct financing leases and are included in other assets in the summarized financial information above.
Income tax expense recorded on Cleco’s financial statements related to Cleco Corporation’s 100% interest in Perryville and Attala was $0.6 million, $0.6 million, and $1.4 million for the years ended December 31, 2008, 2007, and 2006, respectively.
Note 14 - Operating Leases
The following is a schedule of operating leases that Cleco maintains in the ordinary course of business activities. The majority of Cleco’s operating leases are for line construction and operating vehicles and for railcars for coal deliveries, both utilized by Cleco Power. The remaining leases provide for office and operating facilities and office equipment. These leases have various terms and expiration dates. Midstream has operating lease obligations of less than $0.1 million for
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2009. The following table is a summary of expected operating lease payments for Cleco Corporation and Cleco Power for the years indicated.
Cleco’s operating leases for line construction and maintenance vehicles have a term of seven years with an additional one-year renewal. The lease payment is determined by taking the equipment’s original cost multiplied by the adjusted rental factor. Contingent rents are based on the change in the LIBOR rate at May 15, 2001, compared to December 31, 2008, 2007, and 2006. For the years ended December 31, 2008, 2007, and 2006, lease expenses of $1.5 million, $1.6 million, and $1.4 million, respectively, were recognized. Contingent rents were less than $0.1 million for the years ended December 31, 2008, 2007, and 2006, respectively.
The railcar leases are divided into two groups. The first group has 120 railcars, and the lease expires on March 31, 2021. The second group of railcars has 121 cars, and the lease expires on March 31, 2017. Cleco Power pays a monthly rental fee per car. For the years ended December 31, 2008, 2007, and 2006, operating lease expenses of $1.1 million, $1.1 million, and $1.0 million, respectively, were recognized. The railcar leases do not contain contingent rent payments.
Cleco’s operating leases for vehicles, office and operating facilities, and office equipment have lease terms from three to ten years. The monthly lease payment is determined by summing the monthly equipment amortization with the lowest monthly interest rate multiplied by the amortized value. Contingent rents are calculated by comparing the difference between the lowest rate at December 1984 to the lowest rate at December 2008, 2007, and 2006. For the years ended December 31, 2008, 2007, and 2006, lease expenses of $1.8 million, $1.3 million, and $1.3 million, respectively, were recognized. For the years ended December 31, 2008, 2007, and 2006, contingent rents were less than $0.2 million, $0.1 million, and $0.1 million, respectively.
On November 14, 2008, Cleco Power was notified by GE Capital Commercial, Inc. that it was electing to terminate the lease agreement pertaining to company vehicles and other equipment. Pursuant to the terms of the lease agreement, the termination date was effective January 13, 2009, sixty days from the date of notice. Cleco Power has one year from the termination date to enter into a new operating lease with a third party and/or negotiate the sale of such equipment. For more information regarding operating leases, see Note 15 - “Litigation, Other Commitments and Contingencies, and
Disclosures about Guarantees - Other Contingencies - CBL Capital Corporation.”
Note 15 - Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees
Litigation
On June 22, 2005, the City of Alexandria, Louisiana (the City), a current wholesale municipal customer of Cleco Power, filed a lawsuit in Ninth Judicial District Court against Cleco Corporation, Cleco Power, and certain other subsidiaries. The lawsuit alleges unspecified damages as a result of certain sales made to the City, revenue derived by Cleco using the City’s power generating facilities under contracts with the City, and other alleged improper conduct, including, without limitation, allegations that Cleco fraudulently mishandled the management of the City’s power requirements under the contracts. The lawsuit was removed to and currently is pending in the U.S. District Court for the Western District of Louisiana. Effective December 30, 2008, the City Council of Alexandria passed an ordinance authorizing the mayor to settle the litigation by executing a new 13-year power supply agreement with Cleco. Cleco expects to complete final negotiations and satisfaction of conditions precedent for the agreement to commence later in 2009. Pending satisfaction of these conditions, the presiding judge has dismissed the claims asserted in the litigation without prejudice. Management believes the dispute will not have a material adverse effect on the Registrants’ financial condition, results of operations, or cash flows.
On October 8, 2007, Cleco received a Special Notice for Remedial Investigation and Feasibility Study from the EPA. The special notice requested that Cleco Corporation and Cleco Power, along with many other listed potentially responsible parties, enter into negotiations with the EPA for the performance of a Remedial Investigation and Feasibility Study at an area known as the Devil’s Swamp Lake just northwest of Baton Rouge, Louisiana. The EPA has identified Cleco as one of many companies sending PCB wastes for disposal to the site. The Devil’s Swamp Lake site has been proposed to be added to the National Priorities List (NPL) based on the release of PCBs to fisheries and wetlands located on the site. The EPA has yet to make a final determination on whether to add Devil’s Swamp Lake to the NPL. The EPA and a number of PRPs met on January 31, 2008, for an organizational meeting to discuss the background of the site. The PRPs began discussing a potential proposal to the EPA on February 19, 2008. Negotiations among the PRPs and the EPA are ongoing in regard to the remedial investigation and feasibility study at the Devil’s Swamp site, with little progress having been made since the January 2008 meeting. The PRPs alleged to have disposed PCBs at the site have proposed a tentative cost sharing formula with the facility owner to fund the remedial investigation. The response to the proposal has been pending for months. Since this investigation is in the preliminary stages, management is unable to determine whether the costs associated with possible remediation of the facility site will
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have a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
Cleco is involved in regulatory, environmental, and legal proceedings before various courts, regulatory commissions, and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings, such as fuel review and environmental issues, could involve substantial amounts. Management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. Management believes the disposition of these matters will not have a material adverse effect on the Registrants’ financial condition, results of operations, or cash flows.
Off-Balance Sheet Commitments and Disclosures about Guarantees
Cleco Corporation and Cleco Power have entered into various off-balance sheet commitments, in the form of guarantees and standby letters of credit, in order to facilitate their activities and the activities of Cleco Corporation’s subsidiaries and equity investees (affiliates). Cleco Corporation and Cleco Power also have agreed to contractual terms that require them to pay third parties if certain triggering events occur. These contractual terms generally are defined as guarantees in FIN 45. Guarantees issued or modified after December 31, 2002, that fall within the initial recognition scope of FIN 45 are required to be recorded as a liability. Outstanding guarantees that fall within the disclosure scope of FIN 45 are required to be disclosed for all accounting periods ended after December 15, 2002.
Cleco Corporation entered into these off-balance sheet commitments in order to entice desired counterparties to contract with its affiliates by providing some measure of credit assurance to the counterparty in the event Cleco’s affiliates do not fulfill certain contractual obligations. If Cleco Corporation had not provided the off-balance sheet commitments, the desired counterparties may not have contracted with Cleco’s affiliates or may have contracted with them at terms less favorable to its affiliates.
The off-balance sheet commitments are not recognized on Cleco’s Consolidated Balance Sheets, because it has been determined that Cleco’s affiliates are able to perform these obligations under their contracts and that it is not probable that payments by Cleco will be required. Some of these commitments reduce borrowings available to Cleco Corporation under its credit facility pursuant to the terms of the credit facility. Cleco’s off-balance sheet commitments as of December 31, 2008, are summarized in the following table, and a discussion of the off-balance sheet commitments follows the table. The discussion should be read in conjunction with the table to understand the impact of the off-balance sheet commitments on Cleco’s financial condition.
Cleco Corporation provided a limited guarantee and an indemnification, which fall within the recognition scope of FIN 45, to Entergy Louisiana and Entergy Gulf States for Perryville’s performance, indemnity, representation, and warranty obligations under the Sale Agreement, the Power Purchase Agreement, and other ancillary agreements related to the sale of the Perryville facility. As of December 31, 2008, the aggregate guarantee of $277.4 million is limited to $142.4 million due to the performance of some of the underlying obligations that were guaranteed. Management believes it is unlikely that Cleco Corporation will have any other liabilities which would give rise to indemnity claims. The discounted probability-weighted liability under the guarantees and indemnifications as of December 31, 2008, was $0.3 million, resulting in a corresponding reduction in the available credit under Cleco’s credit facility, which was determined in accordance with the facility’s definition of a contingent obligation. The contingent obligation reduces the amount available under the credit agreements by an amount equal to the reasonably anticipated liability in respect of the contingent obligation as determined in good faith.
In November 2004, Cleco completed the sale of substantially all of the assets of Cleco Energy. Cleco Corporation provided guarantees to the buyers of Cleco Energy’s assets for the payment and performance of the indemnity obligations of Cleco Energy. The aggregate amount of the guarantees is $1.4 million, and the guarantees expire in 2009. These guarantees do not fall within the scope of FIN 45. Cleco Energy issued guarantees and indemnifications that fall within the recognition scope of FIN 45, because they relate to the past performance obligations of the disposed assets and also contain provisions requiring payment for potential damages. The maximum aggregate potential payment under the guarantees and indemnifications is $1.2 million. The discounted
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probability-weighted liability under the FIN 45 guarantees and indemnifications as of December 31, 2008, was $0.1 million.
If Evangeline fails to perform certain obligations under its tolling agreement, Cleco Corporation will be required to make payments to the Evangeline Tolling Agreement counterparty. Cleco Corporation’s obligation under the Evangeline commitment is in the form of a standby letter of credit from investment grade banks and is limited to $15.0 million. Ratings triggers do not exist in the Evangeline Tolling Agreement. Cleco expects Evangeline to be able to meet its obligations under the tolling agreement and does not expect Cleco Corporation to be required to make payments to the counterparty. However, under the covenants associated with Cleco Corporation’s credit facility, the entire net amount of the Evangeline commitment reduces the amount that can be borrowed under the credit facility. The letter of credit for Evangeline is expected to be renewed annually until 2020.
In January 2006, Cleco Corporation provided a $0.5 million guarantee to Entergy Mississippi for Attala’s obligations under the Interconnection Agreement. This guarantee will be effective through the life of the agreement.
The State of Louisiana allows employers of certain financial net worth to self-insure their workers’ compensation benefits. Cleco Power has a certificate of self-insurance from the Louisiana Office of Workers’ Compensation and is required to post a $0.5 million letter of credit, an amount equal to 110% of the average losses over the previous three years, as surety.
As part of the Lignite Mining Agreement entered into in 2001, Cleco Power and SWEPCO, joint owners of Dolet Hills, have agreed to pay the lignite miner’s loan and lease principal obligations when due, if the lignite miner does not have sufficient funds or credit to pay. Any amounts paid on behalf of the miner would be credited by the lignite miner against the next invoice for lignite delivered. At December 31, 2008, Cleco Power’s 50% exposure for this obligation was approximately $7.4 million. The lignite mining contract is in place until 2011 and does not affect the amount Cleco Corporation can borrow under its credit facility.
The following table summarizes the expected termination date of the guarantees and standby letters of credit discussed above.
In its bylaws, Cleco Corporation has agreed to indemnify directors, officers, agents, and employees who are made a party to a pending or completed suit, arbitration, investigation, or other proceeding whether civil, criminal, investigative or administrative, if the basis of inclusion arises as the result of acts conducted in the discharge of their official capacity. Cleco Corporation has purchased various insurance policies to reduce the risks associated with the indemnification. In its Operating Agreement, Cleco Power provides for the same indemnification as described above with respect to its managers, officers, agents, and employees.
Generally, neither Cleco Corporation nor Cleco Power has recourse that would enable them to recover amounts paid under their guarantee or indemnification obligations. The one exception is the insurance contracts associated with the indemnification of directors, managers, officers, agents, and employees. There are no assets held as collateral for third parties that either Cleco Corporation or Cleco Power could obtain and liquidate to recover amounts paid pursuant to the guarantees.
Long-term Purchase Obligations
Cleco Corporation had no unconditional long-term purchase obligations at December 31, 2008. Cleco Power has several unconditional long-term purchase obligations related to the purchase of lignite, coal, petroleum coke, limestone, energy capacity, and energy delivery facilities. The aggregate amount of payments required under such obligations at December 31, 2008, is as follows.
Payments under these agreements for the years ended December 31, 2008, 2007, and 2006 were $31.6 million, $27.8 million, and $13.4 million, respectively.
Other Contingencies
General Electric Services Corporation
Cleco Power has entered into an operating lease agreement with General Electric Equipment Services Corporation for leasing of railcars in order to transport coal to its Rodemacher Power Station. The lease contains a provision for early termination, along with an associated termination fee. The termination provision can only be exercised in December 2010. If exercised by Cleco Power, the termination fee would be approximately $1.3 million. At this time, Cleco Power has no plans to early terminate this lease.
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CBL Capital Corporation
Cleco Power has entered into an operating lease agreement with CBL Capital Corporation, which was acquired by GE Capital Commercial, Inc. (GE Capital). This is a master leasing agreement for company vehicles and other equipment. On November 14, 2008, Cleco Power was notified by GE Capital that it was electing to terminate the lease. Pursuant to the terms of the lease agreement, the termination date was effective January 13, 2009, sixty days from the date of notice. Cleco Power has one year from the termination date to enter into a new operating lease with a third party and/or negotiate the sale of such equipment for the unamortized balance. The unamortized balance of equipment under the GE Capital lease was $6.4 million at December 31, 2008.
New Market Tax Credits
In August 2008, Cleco Corporation acquired a 99.9% equity interest in U.S. Bank New Market Tax Credit Fund 2008-1 LLC (the LLC). The LLC was formed by U.S. Bancorp Community Development Corporation to provide capital for investments to businesses in distressed or low income areas. These investments will generate new market tax credits and historical tax credits that can be used to reduce the federal income tax liability of Cleco Corporation. The transaction obligates Cleco to make $213.1 million of equity contributions to the entity over the life of the investment.
Of the $200.9 million, $25.0 million is due to be paid within the next twelve months. The investment and associated debt are presented on the balance sheet, net in other deferred credits due to the right of offset.
The equity contribution does not contain a stated rate of interest. In accordance with APB Opinion No. 21, Cleco has recorded the liability and investment at its calculated fair value within the framework of SFAS No. 157. In order to calculate the fair value, management used an imputed rate of interest assuming that Cleco obtained financing of a similar nature from a third party. The imputed rate was used in a net present value model in order to calculate the fair value of the remaining portion of the delayed equity contributions. The table below contains the disclosures required by APB Opinion No. 21 for equity investments with an imputed interest.
The gross investment amortization expense is recognized over the seven-year compliance period using the cost method in accordance with EITF No. 94-1.
Other
Cleco has accrued for liabilities to third parties, employee medical benefits, and storm damages.
Prior to Cleco Katrina/Rita’s issuance of the storm recovery bonds in March 2008, charges to Cleco Power’s operating expenses to provide a reserve for future storm damages were based upon the average amount of noncapital, uninsured storm damages experienced by Cleco Power during the previous six years, excluding costs for Hurricanes Katrina and Rita. The settlement agreement signed with the LPSC in March 2007 allowed, among other items, the funding and securitization of $50.8 million for a reserve for future storm costs; at which time, the amount authorized to accrue for future storm damages was reduced. For more information regarding storm restoration costs, see Note 3 - “Regulatory Assets and Liabilities - Deferred Storm Restoration Costs - Katrina/Rita” and Note 19 - “Storm Restoration.”
For information on contingencies relating to regulatory agency matters, see Note 16 - “FERC Staff Investigations and LPSC Fuel Audit.”
Risks and Uncertainties
Cleco Corporation
Cleco Corporation could be subject to possible adverse consequences if Cleco’s counterparties fail to perform their obligations or if Cleco Corporation or its affiliates are not in compliance with loan agreements or bond indentures.
Evangeline Tolling Agreement
In May 2008, JPMorgan Chase & Co. acquired Bear Stearns Companies Inc. In connection with the acquisition, JPMorgan Chase & Co. has guaranteed certain obligations of its subsidiaries, including Bear Energy’s obligations under the Evangeline Tolling Agreement. If JPMorgan Chase & Co. or any successor or assignee were to fail to perform its payment obligations, such failure could have a material adverse effect on Cleco Corporation’s results of operations, financial condition, and cash flows for the following reasons, among others:
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If such failure to perform constituted a default under the tolling agreement, the holders of the Evangeline bonds would have the right to declare the entire outstanding principal amount ($168.9 million at December 31, 2008) and interest to be immediately due and payable, which could result in:
o
Cleco seeking to refinance the bonds, the terms of which may be less favorable than existing terms;
o
Cleco causing Evangeline to seek protection under federal bankruptcy laws; or
o
the trustee of the bonds foreclosing on the mortgage and assuming ownership of the Evangeline plant;
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Cleco may not be able to enter into agreements in replacement of the Evangeline Tolling Agreement on terms as favorable as that agreement or at all;
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Cleco’s equity investment in Evangeline may be impaired, requiring a write-down to its fair market value, which could be substantial; and
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Cleco’s credit ratings could be downgraded, which would increase borrowing costs and limit sources of financing.
Other
Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows. Recent market conditions have limited the availability and have increased the costs of capital for many companies. The inability to raise capital on favorable terms could negatively affect Cleco Corporation’s and Cleco Power’s ability to maintain and expand their businesses. After assessing the current operating performance, liquidity, and credit ratings of Cleco, management believes that Cleco will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. If Cleco Corporation’s credit rating was to be downgraded by Moody’s or by Standard & Poor’s, Cleco Corporation would be required to pay additional fees and higher interest rates under its bank credit and other debt agreements.
Changes in the regulatory environment or market forces could cause Cleco to determine its assets have suffered an other than temporary decline in value, whereby an impairment would be required to be taken and Cleco’s financial condition could be materially adversely affected.
Cleco Power
Cleco Power supplies a portion of its customers’ electric power requirements from its own generation facilities. In addition to power obtained from power purchase agreements, Cleco Power purchases power from other utilities and marketers to supplement its generation at times of relatively high demand or when the purchase price of power is less than its own cost of generation. Due to its location on the transmission grid, Cleco Power relies on two main suppliers of electric transmission when accessing external power markets. At times, constraints limit the amount of purchased power these transmission providers can deliver into Cleco Power’s service territory.
Access to capital markets is a significant source of funding for both short- and long-term capital requirements not satisfied by operating cash flows. Recent market conditions have limited the availability and have increased the costs of capital for many companies. The inability to raise capital on favorable terms could negatively affect Cleco Power’s ability to maintain and expand its businesses. After assessing the current operating performance, liquidity, and credit ratings of Cleco Power, management believes that Cleco Power will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. If Cleco Power’s credit ratings were to be downgraded by Moody’s or by Standard & Poor’s, Cleco Power would be required to pay additional fees and higher interest rates under its bank credit and other debt agreements.
Under the terms of the Amended EPC Contract, in the event Cleco Power does not maintain a senior unsecured credit rating of either: (i) Baa3 or better from Moody’s or (ii) BBB- or better from Standard & Poor’s, Cleco Power will be required to provide a letter of credit to Shaw in the amount of $20.0 million. In the event of further downgrade to both of its credit ratings to: (i) Ba2 or below from Moody’s, and (ii) BB or below from Standard & Poor’s, Cleco Power will be required to provide an additional $15.0 million letter of credit to Shaw.
Note 16 - FERC Staff Investigations and LPSC Fuel Audit
FERC Staff Investigations
In July 2003, FERC issued an order approving a Consent Agreement between the FERC Staff and Cleco that settled the FERC investigation following Cleco’s disclosure in November 2002 of certain energy marketing and trading practices. The terms of the Consent Agreement, effective on August 24, 2003, included, but were not limited to: (i) filing revised codes of conduct by Cleco’s public utility subsidiaries that impose more stringent restrictions on affiliate relations; (ii) implementation of a Compliance Plan for FERC regulatory compliance; and (iii) payment of certain penalties and remedies, including payment of a $0.8 million civil penalty to FERC.
In November 2005, after a review of Cleco’s October 2005 quarterly compliance report, the FERC Staff initiated a preliminary, non-public investigation into certain representations made by Cleco. In response to data requests from the FERC Staff, Cleco provided information regarding those representations, as well as compliance with the Code of Conduct and Compliance Plan contained in the Consent Agreement. The information primarily concerned the possible sharing of employees and information among Cleco’s subsidiaries, as well as the accuracy of information furnished to the FERC Staff in connection with reporting on compliance with the Consent Agreement. On June 12, 2007, FERC issued an order approving a Stipulation and Consent Agreement between Cleco and the FERC’s Office of Enforcement which completely resolved these matters. FERC’s investigation was terminated, and Cleco was released of any further claims arising from such investigation. Cleco agreed to pay a one-time civil penalty of $2.0 million and adhere to a new one-year compliance plan. In June 2007, Cleco paid the penalty, the payment of which was not passed through, directly or indirectly, to any existing or future customers.
LPSC Fuel Audit
The LPSC Fuel Adjustment Clause General Order issued November 6, 1997, in Docket No. U-21497 provides that an audit will be performed not less than every other year. Cleco Power currently has fuel adjustment clause filings for 2003 through 2008 subject to audit. In July 2006, the LPSC informed Cleco Power that it was planning to conduct a periodic fuel audit that included fuel adjustment clause filings for January 2003
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through December 2004. Cleco Power believes that it has provided the LPSC Staff with all of the information requested. Management is currently unable to predict the timing of the fuel cost audits for the years 2005 through 2008. However, it is not anticipated that the LPSC Staff will begin another audit until the current audit is complete. Cleco Power could be required to make a substantial refund of previously recorded revenue as a result of these audits, and such refund could result in a material adverse effect on the Registrants’ results of operations, financial condition, and cash flows.
Note 17 - Affiliate Transactions
Cleco
Cleco has affiliate balances that were not eliminated as of December 31, 2008. The balances were not eliminated due to the use of the equity method of accounting for Evangeline, Perryville, Attala, and Acadia. For information on these affiliates, see Note 13 - “Equity Investment in Investees.”
Effective July 1, 1999, Cleco entered into service agreements with affiliates that provide Cleco access to professional services and goods. Services and goods provided by Cleco Power are charged at management’s estimate of fair market value or fully loaded cost, whichever is higher. Services provided to Cleco Power are charged at management’s estimate of fair market value or fully loaded cost, whichever is lower, with the exception of Support Group, which charges only fully loaded cost in order to comply with Cleco’s affiliate policy.
Affiliate goods and services received by Cleco primarily involve services provided by Support Group and Generation Services. Support Group provides joint and common administrative support services in the areas of information technology; finance, cash management, accounting and auditing; human resources; corporate communications; project consulting; risk management; strategic and corporate development; legal, ethics and regulatory compliance; facilities management; supply chain and inventory management and other administrative services. Generation Services provides electric power plant operations and maintenance expertise. Following is a summary of charges from each affiliate included in Cleco Corporation’s Consolidated Statements of Income.
Following is a reconciliation of Cleco intercompany revenue.
Cleco had the following affiliate receivable and payable balances associated with the service agreements between Cleco and its affiliates.
Cleco Power
Effective July 1, 1999, Cleco Power entered into service agreements with affiliates that provide Cleco Power access to professional services and goods. The services and goods are charged to Cleco Power at management’s estimate of fair market value or fully loaded cost, whichever is lower, with the exception of Support Group, which charges only fully loaded cost in order to comply with Cleco’s affiliate policy.
Affiliate goods and services received by Cleco Power primarily involve services provided by Support Group. Support Group provides joint and common administrative support services in the areas of information technology; finance, cash management, accounting and auditing; human resources; corporate communications; project consulting; risk management; strategic and corporate development; legal, ethics and regulatory compliance; facilities management; supply chain and inventory management and other administrative services. A summary of charges from each affiliate included in Cleco Power’s Consolidated Statements of Income follows.
Cleco Power also entered into agreements to provide goods and services to affiliated companies. The goods and
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services are charged by Cleco Power at fully loaded cost or management’s estimate of fair market value, whichever is higher, in order to comply with Cleco’s affiliate policy. The majority of the services provided by Cleco Power to affiliates relates to the lease of office space to Support Group. Following is a reconciliation of Cleco Power’s affiliate intercompany revenue.
Cleco Power had the following affiliate receivable and payable balances associated with the service agreements between Cleco Power and its affiliates.
For the years ended December 31, 2007, and 2006, Cleco Power received contributions from Cleco Corporation in the amounts of $85.0 million and $50.0 million, respectively. Cleco Power did not receive any contributions from Cleco Corporation during the year ended December 31, 2008.
Affiliates that participate in the defined benefit pension plan sponsored by Cleco Power transfer their liability and an equal amount of cash on a periodic basis to Cleco Power. The following table shows the amounts transferred by affiliates during 2008 and 2007.
Note 18 - Intangible Asset
During the first quarter of 2008, Cleco Katrina/Rita acquired a $177.5 million intangible asset which includes $176.0 million for the right to bill and collect storm recovery charges from customers of Cleco Power and $1.5 million of financing costs. This intangible asset is expected to have a life of 12 years, but could have a life of up to 15 years depending on the time period required to collect the required amount from Cleco Power’s customers. The intangible asset is being amortized according to the estimated collections from Cleco Power’s customers. At the end of its life, this asset will have no residual value. During the twelve months ended December 31, 2008, Cleco Katrina/Rita recognized amortization expense of $9.7 million. For additional information on Cleco Katrina/Rita storm costs and securitization, see Note 3 - “Regulatory Assets and Liabilities - Deferred Storm Restoration Costs - Katrina/Rita.” The following tables provide additional information about this intangible asset.
Note 19 - Storm Restoration
In September 2008, Cleco Power’s distribution and transmission systems sustained substantial damage from two separate hurricanes. The damage to equipment from both storms required replacement, as well as repair of existing assets.
On September 1, 2008, Hurricane Gustav made landfall in southeastern Louisiana as a Category 2 hurricane, causing power outages to approximately 246,000, or 90%, of Cleco Power’s electric customers and affecting Cleco Power’s entire service territory. By September 9, 2008, power was restored to all customers who lost service after Hurricane Gustav. Hurricane Gustav’s restoration costs are approximately $66.1 million, of which 58.6%, or $38.7 million, was capitalized.
On September 13, 2008, Hurricane Ike made landfall in southeast Texas as a Category 2 hurricane, affecting power service to approximately 80,000 of Cleco Power’s electric customers in Cleco Power’s southern service territory. By September 16, 2008, restoration efforts for all customers whose service could be reconnected were complete. Hurricane Ike’s restoration costs are approximately $12.6 million, of which 63.5%, or $8.0 million, was capitalized.
With approval from the LPSC, the remaining uncapitalized costs were offset against Cleco Power’s existing storm damage reserves, leaving a balance of $27.4 million in the restricted storm reserve at December 31, 2008.
Note 20 - Calpine Bankruptcy Settlement
Bankruptcy Proceedings
In December 2005, the Calpine Debtors filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the Calpine Debtors Bankruptcy Court. Prior to Cajun’s purchase, CAH, a wholly owned subsidiary of Calpine and one of the Calpine Debtors, owned a 50% interest in Acadia, and APH owned the other 50% interest in Acadia.
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In December 2005, the Calpine Debtors filed a motion with the Calpine Debtors Bankruptcy Court seeking to reject the Calpine Tolling Agreements. In March 2006, the Calpine Debtors Bankruptcy Court entered an order permitting Acadia to suspend its obligations to CES under the Calpine Tolling Agreements in view of CES’s non-performance of the agreements.
Settlement Agreement
In April 2007, Cleco announced that a settlement agreement had been reached with Calpine, subject to the approval of the Calpine Debtors Bankruptcy Court, which resolved issues related to the Acadia power plant. The settlement included the fixing of Acadia’s claims against the Calpine Debtors and an agreement by the parties to certain bidding procedures (Bidding Procedures) which governed the sale of CAH’s interest in Acadia and certain related assets (collectively, the CAH Assets). In May 2007, the Calpine Debtors Bankruptcy Court approved the terms of the settlement and entered orders approving the Claims Settlement Agreement and the Bidding Procedures Order.
The Claims Settlement Agreement addressed Acadia’s outstanding claims against the Calpine Debtors. Under the Claims Settlement Agreement, Acadia received a pre-petition general unsecured claim against each of CES and Calpine (as guarantor of CES’s obligations under the Calpine Tolling Agreements) for $185.0 million.
In May 2007, APH sold its claims of $85.0 million against CES and Calpine to JPMorgan Chase Bank, N.A. at 92% of face value. The pre-tax proceeds from this sale were $78.2 million which was included in APH’s equity income.
The Bidding Procedures Order set forth the procedures governing the sale of the CAH Assets. Under the Bidding Procedures Order, APH agreed to serve as the “stalking horse bidder” for the CAH Assets. APH’s agreement was subject to certain terms and conditions, including payment to APH of a $2.9 million break-up fee in the event APH was not the successful purchaser. APH and CAH entered into a purchase agreement whereby APH agreed to purchase the CAH Assets for $60.0 million plus assumed liabilities, subject to any higher or better offers.
The Calpine Debtors Bankruptcy Court approved the transfer of the operations, maintenance and project management functions of the Acadia power plant to subsidiaries of Midstream upon the closing of the CAH asset sale. A subsidiary of Calpine had been performing these functions since the Acadia power plant became operational.
Acadia Auction Results
In July 2007, CAH conducted an auction for the CAH Assets. APH participated in the auction. At the conclusion of the auction, Cajun emerged as the successful bidder, with a price of $189.0 million.
In September 2007, after all regulatory approvals were received, the sale of CAH’s Assets to Cajun was completed. At the closing of the sale, APH received an $85.0 million payment from Cajun for the agreed upon value of the priority and
guaranteed distributions, plus a $2.9 million break-up fee and other expense reimbursements. This $85.0 million payment is separate from APH’s $85.0 million pre-petition unsecured claim that it sold in May 2007. APH also acquired, for $1.25 million (subject, in certain circumstances, to reduction), Calpine’s interest in Acadia’s claim against Cleco Power regarding a potential electric metering error at the Acadia power plant. APH recognized this as other expense on Cleco’s Consolidated Statements of Income.
At the completion of the sale, management reviewed the carrying value of APH’s 50% ownership in Acadia. Using Calpine’s sale as a market indicator of value, APH recognized an impairment charge of $45.8 million, which is the difference between the $234.8 million carrying value and the $189.0 million market value. The impairment charge is reflected in equity income from investees on Cleco’s Consolidated Statements of Income.
As a result of the closing and the subsequent settlement of future priority distribution payments owed to APH, the Acadia LLC Agreement was amended to remove APH’s priority distribution rights and give each member (APH and Cajun) a 50% ownership and economic interest in Acadia.
Note 21 - Accumulated Other Comprehensive Loss
The components of accumulated other comprehensive loss are summarized below for both Cleco and Cleco Power. Where applicable, transactions are reported net of income taxes.
Cleco
Cleco Power
CLECO CORPORATION
CLECO POWER
FORM 10-K
Note 22 - Miscellaneous Financial Information (Unaudited)
Cleco
Quarterly information for Cleco for 2008 and 2007 is shown in the following table.
Cleco Corporation’s common stock is listed for trading on the New York Stock Exchange under the ticker symbol “CNL.” Cleco Corporation’s preferred stock is not listed on any stock exchange. On December 31, 2008, Cleco had 6,973 common shareholders and 88 preferred shareholders, as determined from the records of the transfer agent.
On January 30, 2009, Cleco Corporation’s Board of Directors declared a quarterly dividend of $0.225 per share payable on February 16, 2009, to common shareholders of record on February 9, 2009. Preferred dividends also were declared payable March 2, 2009, to preferred shareholders of record on February 16, 2009.
Cleco Power
Quarterly information for Cleco Power for 2008 and 2007 is shown in the following table.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, each of Cleco Corporation’s and Cleco Power’s management has evaluated, as of the end of the period covered by this report, with the supervision and participation of each of Cleco Corporation’s and Cleco Power’s chief executive officer and chief financial officer, the effectiveness of Cleco Corporation’s and Cleco Power’s disclosure controls and procedures as defined by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (Disclosure Controls), as the case may be. Based on that evaluation, such officers concluded that the design and operation of each of Cleco Corporation’s and Cleco Power’s disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports each of the Registrants files and submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
During Cleco Corporation’s and Cleco Power’s fourth fiscal quarter of 2008, there have been no changes in either Cleco Corporation’s and Cleco Power’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, respectively, each of Cleco Corporation’s and Cleco Power’s internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
The management of Cleco Power and Cleco Corporation is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934. Cleco Power and Cleco Corporation’s internal control over financial reporting is a process designed by, or under the supervision of, each of Cleco Power’s and Cleco Corporation’s principal executive and financial officers and effected by Cleco Power’s and Cleco Corporation’s board
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of managers or directors, as the case may be, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Management has designed its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with accounting principles generally accepted in the United States of America. Management’s assessment included review and testing of both the design effectiveness and operating effectiveness of controls over relevant assertions related to significant accounts and disclosures in the financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The management of Cleco Power and Cleco Corporation, under the supervision of each of the Registrants’ principal executive officer and principal financial officer, conducted an assessment of the effectiveness of Cleco Power’s and Cleco Corporation’s respective internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, the management of Cleco Power and Cleco Corporation concluded that, as of December 31, 2008, the Registrants’ internal control over financial reporting was effective.
The effectiveness of Cleco Corporation’s and Cleco Power’s internal control over financial reporting as of December 31, 2008, have been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 63 of this Annual Report on Form 10-K.
Certifications
The certifications of the Registrants’ Chief Executive Officer and Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1, 31.2, 31.3, and 31.4 to this Annual Report on Form 10-K. Additionally, as required by Section 303A.12(a) of the New York Stock Exchange (“NYSE”) Listed Company Manual, Cleco’s Chief Executive Officer filed a certification with the NYSE on May 13, 2008, reporting that he was not aware of any violation by Cleco of the NYSE’s Corporate Governance listing standards.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
CLECO CORPORATION
CLECO POWER
FORM 10-K
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANTS
Audit Committee Financial Expert
Cleco’s board of directors has determined that Mr. W. Larry Westbrook, who serves as the Chairman of the Audit Committee of the Board of Directors, fulfills the requirements for an independent audit committee financial expert for both Cleco Corporation and Cleco Power.
Financial Manager’s Code of Conduct
Both Cleco Corporation and Cleco Power have a code of conduct that applies to their principal executive officer, principal financial officer, principal accounting officer, and treasurer. This code of conduct is posted on Cleco’s homepage on the Internet’s World Wide Web located at http://www.cleco.com. This code of conduct also is available free of charge by request sent to: Shareholder Services, Cleco, P.O. Box 5000, Pineville, LA 71361-5000.
CLECO
The information set forth, (i) under the caption “Proposal Number I - Election of Three Class III Directors,” (ii) under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” and (iii) under the caption “Report of the Audit Committee” in the 2009 Proxy Statement relating to the Annual Meeting of Shareholders to be held on April 24, 2009, filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 (2009 Proxy Statement), is incorporated herein by reference. See also “Part I - Item 4 - Board of Directors of Cleco.”
CLECO POWER
The information called for by Item 10 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
CLECO
The information set forth, (i) under the subcaption “Independence and Organization of the Board of Directors” under the caption “Proposal Number I - Election of Three Class III Directors,” (ii) under the caption “Compensation Discussion and Analysis,” (iii) under the caption “Executive Officers Compensation,” (iv) under the caption “Director Compensation,” and (v) under the caption “Report of the Compensation Committee” in the 2009 Proxy Statement is incorporated herein by reference.
CLECO POWER
The information called for by Item 11 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
CLECO CORPORATION
CLECO POWER
FORM 10-K
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
CLECO
Security Ownership
The information set forth, (i) under the caption “Security Ownership of Directors and Management” and (ii) under the caption “Security Ownership of Certain Beneficial Owners” in the 2009 Proxy Statement is incorporated herein by reference.
Equity Compensation Plan Information
Cleco has compensation plans under which equity securities of Cleco Corporation are authorized for issuance as approved by security holders. Cleco does not have such plans that have not been approved by security holders. The table below provides information about compensation plans under which equity securities of Cleco Corporation were authorized for issuance at December 31, 2008.
For additional information on compensation plans using equity securities, see Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 7 - Common Stock.” This information should be read in conjunction with the Consolidated Financial Statements and related Notes thereto.
CLECO POWER
The information called for by Item 12 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
CLECO
The information set forth under the subcaptions “Independence and Organization of the Board of Directors,” and “Cleco’s Code of Business Conduct & Ethics” under the caption “Proposal Number I - Election of Three Class III Directors” in the 2009 Proxy Statement is incorporated herein by reference.
CLECO POWER
The information called for by Item 13 with respect to Cleco Power is omitted pursuant to General Instruction I(2)(c) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
CLECO
The information set forth under “Relationship with Accountants” regarding fees paid to Cleco’s independent auditors in the 2009 Proxy Statement is incorporated herein by reference.
CLECO POWER
The information set forth under “Relationship with Accountants” regarding fees paid to Cleco’s independent auditors in the 2009 Proxy Statement is incorporated herein by reference.
PricewaterhouseCoopers LLP provides professional services for Cleco Power that are directly billed to Cleco Corporation, the cost of which is allocated to Cleco Power though not billed directly to them.
CLECO CORPORATION
CLECO POWER
FORM 10-K
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The Exhibits designated by an asterisk are filed herewith, except for exhibits 32.1, 32.2, 32.3, and 32.4, which are furnished herewith (and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liability of that section). The Exhibits not so designated previously have been 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.
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CLECO POWER
FORM 10-K
EXHIBITS
CLECO CORPORATION
CLECO POWER
FORM 10-K
CLECO CORPORATION
CLECO POWER
FORM 10-K
CLECO CORPORATION
CLECO POWER
FORM 10-K
CLECO CORPORATION
CLECO POWER
FORM 10-K
CLECO CORPORATION
CLECO POWER
FORM 10-K
CLECO CORPORATION (Parent Company Only)
SCHEDULE I
Condensed Statements of Income
CLECO CORPORATION
CLECO POWER
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CLECO CORPORATION (Parent Company Only)
SCHEDULE I
Condensed Balance Sheets
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CLECO CORPORATION (Parent Company Only)
SCHEDULE I
Condensed Statements of Cash Flows
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CLECO CORPORATION (Parent Company Only) Notes to the Condensed Financial Statements
Note 1 - Summary of Significant Accounting Policies
The condensed financial statements represent the financial information required by SEC Regulation S-X 5-04 for Cleco Corporation, which requires the inclusion of parent company only financial statements if the restricted net assets of consolidated subsidiaries exceed 25% of total consolidated net assets as of the last day of its most recent fiscal year. As of December 31, 2008, Cleco Corporation’s restricted net assets of consolidated subsidiaries were $543.6 million and exceeded 25% of its total consolidated net assets.
Cleco Corporation’s major, first-tier subsidiaries consist of Cleco Power and Midstream.
Cleco Power contains the LPSC-jurisdictional generation, transmission, and distribution electric utility operations serving Cleco’s traditional retail and wholesale customers. Midstream owns and operates merchant generation stations and invests in joint ventures that own and operate merchant generation stations.
In January 2007, FERC approved the transfer of the ownership interests of Attala and Perryville to Cleco Corporation whereby Attala and Perryville would become first-tier subsidiaries of Cleco Corporation. The transfer was effective February 1, 2007.
The accompanying financial statements have been prepared to present the financial position, results of operations, and cash flows of Cleco Corporation on a stand-alone basis as a holding company. Investments in subsidiaries and other investees are stated at cost plus equity in undistributed earnings from the date of acquisition. These financial statements should be read in conjunction with Cleco’s consolidated financial statements.
Note 2 - Debt
Cleco Corporation had no short-term debt outstanding at December 31, 2008, or December 31, 2007. At December 31, 2008, Cleco Corporation’s long-term debt outstanding was $30.0 million, of which none was due within one year, compared to $100.0 million of long-term debt of which all was due within one year at December 31, 2007. Cleco Corporation’s $100.0 million, 7.00% Senior Notes were repaid May 1, 2008, at maturity.
Cleco Corporation’s $150.0 million five-year credit facility matures on June 2, 2011. At December 31, 2008, $30.0 million was outstanding under this credit facility. This facility provides for working capital and other needs. Cleco Corporation’s borrowing costs under the facility are equal to LIBOR plus 0.65%, including facility fees.
At December 31, 2008, off-balance sheet commitments and outstanding credit facility borrowings reduced available borrowings by $15.0 million and $30.0 million, respectively, leaving available capacity of $105.0 million. An uncommitted line of credit with a bank in an amount up to $10.0 million also is available to support Cleco’s working capital needs.
Note 3 - Dividends and Equity Contributions
No dividends were received from Cleco Power for the years ended December 31, 2008, 2007, and 2006. Some provisions in Cleco Power’s debt instruments restrict the amount of equity available for distribution to Cleco Corporation by Cleco Power under specified circumstances. The most restrictive covenant requires Cleco Power’s total indebtedness to be less than or equal to 65% of total capitalization. At December 31, 2008, approximately $320.3 million of member’s equity were unrestricted. Cleco Corporation made no equity contributions to Cleco Power in 2008. During the years 2007 and 2006, Cleco Corporation made equity contributions to Cleco Power of $85.0 million, and $50.0 million, respectively.
Cleco Corporation received $9.6 million and $15.5 million in cash dividends from Midstream during the years ended December 31, 2008, and 2006, respectively. Cleco Corporation received no cash dividends from Midstream during the year ended December 31, 2007. For the years ended December 31, 2008, 2007, and 2006, Cleco Corporation made no equity contributions to Midstream.
Note 4 - Income Taxes
In addition to the income tax benefit of $2.8 million, and income tax expense of $4.0 million, and $4.6 million reflected in Cleco Corporation (Parent Company Only) Condensed Statements of Income, income tax expense of $21.3 million, $66.8 million, and $37.4 million is reflected in equity income of subsidiaries, net of tax for the years ended 2008, 2007, and 2006, respectively.
Note 5 - Commitments and Contingencies
For information regarding commitments and contingencies related to Cleco Corporation, see Part II, Item 8, “Financial Statements and Supplementary Data - Notes to the Financial Statements - Note 15 - Litigation, Other Commitments and Contingencies, and Disclosures about Guarantees - Off-Balance Sheet Commitments and Disclosures about Guarantees.”
CLECO CORPORATION
CLECO POWER
FORM 10-K
CLECO CORPORATION
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 2008, 2007, and 2006
CLECO POWER LLC
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 2008, 2007, and 2006
CLECO CORPORATION
CLECO POWER
FORM 10-K
SCHEDULE III
ACADIA POWER PARTNERS, LLC
Consolidated Financial Statements
December 31, 2008, 2007, and 2006
CLECO CORPORATION
CLECO POWER
FORM 10-K
ACADIA POWER PARTNERS, LLC
CLECO CORPORATION
CLECO POWER
FORM 10-K
Report of Independent Registered Public Accounting Firm
To the Members of
Acadia Power Partners, LLC:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, changes in members' capital, and cash flows present fairly, in all material respects, the financial position of Acadia Power Partners, LLC (the "Company") and its subsidiary at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ending December 31, 2008 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 standards of the Public Company Accounting Oversight Board (United States). Those standards 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.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, the Company's operating revenues are dependent on the success of a third party to market its electricity generation. External factors that could impact the success of the third party's marketing efforts raise substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
As discussed in Note 7 to the consolidated financial statements, the Company has significant transactions with related parties.
/s/ PricewaterhouseCoopers LLP
New Orleans, Louisiana
February 26, 2009
CLECO CORPORATION
CLECO POWER
FORM 10-K
ACADIA POWER PARTNERS, LLC
Consolidated Statements of Income
CLECO CORPORATION
CLECO POWER
FORM 10-K
ACADIA POWER PARTNERS, LLC
Consolidated Balance Sheets
CLECO CORPORATION
CLECO POWER
FORM 10-K
ACADIA POWER PARTNERS, LLC
Consolidated Statements of Cash Flows
CLECO CORPORATION
CLECO POWER
FORM 10-K
ACADIA POWER PARTNERS, LLC
Consolidated Statements of Changes in Members’ Capital
CLECO CORPORATION
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ACADIA POWER PARTNERS, LLC Notes to Consolidated Financial Statements
Note 1 - Description of Business and Organization
Acadia Power Partners, LLC (Acadia) is a Delaware limited liability company formed on October 13, 1999, for the purpose of designing, developing, constructing, owning, and operating a 1,160 MW natural gas-fired electric generation plant (the Facility) located in Acadia Parish, Louisiana.
Acadia’s members (the Members) are Acadia Power Holdings LLC (APH), a subsidiary of Cleco Midstream Resources LLC (Midstream), and prior to September 13, 2007, Calpine Acadia Holdings, LLC (CAH), a subsidiary of Calpine Corporation (Calpine). On September 13, 2007, CAH sold its interest in Acadia along with certain related assets to Cajun Gas Energy L.L.C. (Cajun), an affiliate of pooled investment funds managed by King Street Capital Management, L.P.
In accordance with Acadia’s Second Amended and Restated Limited Liability Company Agreement (the LLC Agreement) dated May 9, 2003, the Members each own a 50% interest in Acadia and share in profits and losses of Acadia in proportion to their ownership interests. Acadia is governed by an executive committee with two representatives from each Member.
Note 2 - Calpine Bankruptcy
Bankruptcy Proceedings
In December 2005, Calpine and certain of its subsidiaries, including CAH, Calpine Energy Services, L.P. (CES), and Calpine Central, LP (CCLP), (collectively the Calpine Debtors), filed for protection under Chapter 11 (the Bankruptcy Filing) of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York (the Calpine Debtors Bankruptcy Court). The Calpine Debtors continued to operate their business and manage their properties as “debtors-in-possession” under the jurisdiction of the Calpine Debtors Bankruptcy Court. Acadia did not file for bankruptcy and continued to operate in the normal course of business. However, Acadia had an operation and maintenance agreement with CCLP, an indirect, wholly-owned subsidiary of Calpine, and tolling agreements with CES. For information on these agreements, see Note 7 - “Related Party Transactions.” CCLP continued to operate under the terms of the operation and maintenance agreement; however CES ceased performance under the terms of the tolling agreements in 2006.
CAH’s Bankruptcy Filing was an event of default under the LLC Agreement. The LLC Agreement provides for the business of Acadia to continue without dissolution in the event of the bankruptcy of a Member. Any actions accorded to the Members under the default provisions of the LLC Agreement were subject to approval by the Calpine Debtors Bankruptcy Court. Such actions may include, among others, acquisition of all of the Facility by a single Member, the sale of the defaulting Member’s interest, or sale of the Facility to a third party. However, APH was precluded from exercising any remedies based on the default by virtue of the automatic stay provided under the Calpine Debtors Bankruptcy Court proceedings.
In March 2006, Acadia filed a motion with the Calpine Debtors Bankruptcy Court to compel CES to perform under the then-existing power purchase agreements and to pay amounts due and owed under such agreements since the commencement of CES’s Bankruptcy Filing. On March 15, 2006, Acadia and CES amended each of the power purchase agreements, suspending Acadia’s obligations under the power purchase agreements. The Calpine Debtors Bankruptcy Court approved these amendments on March 22, 2006. The amendments resolved certain relief requested by Acadia’s motion.
Settlement Agreement
In April 2007, a settlement agreement was reached with Calpine which resolved issues related to Acadia. The settlement included the fixing of Acadia’s claims against the Calpine Debtors and an agreement by the parties to certain bidding procedures governing the sale of CAH’s interest in Acadia and certain related assets (the CAH Assets). In May 2007, the Calpine Debtors Bankruptcy Court approved the terms included in the Claims Settlement Agreement and Bidding Procedures Order.
Under the Claims Settlement Agreement, Acadia received a pre-petition general unsecured claim against CES and Calpine relating to obligations under the tolling agreements of $185.0 million. Acadia recorded the amount, net of $14.8 million discount on the sale of the claim, as a gain on settlement of the bankruptcy claim. In May 2007, Acadia made a dividend by assignment of the claim to APH and CAH.
Under the Bidding Procedures Order governing the sale of the CAH Assets, APH agreed to purchase the CAH Assets for $60.0 million plus accrued liabilities, subject to any higher or better offers. However, in July 2007, CAH conducted an auction for the CAH Assets, and Cajun emerged as the successful bidder with a bid price of $189.0 million.
The Calpine Debtors Bankruptcy Court also approved the transfer of the operations, maintenance and project management functions performed by CCLP to subsidiaries of Midstream upon the closing of the CAH asset sale.
Note 3 - Going Concern and Ongoing Operations
The accompanying consolidated financial statements have been prepared assuming that Acadia will continue as a going concern.
Acadia continues to have a third party market electricity on its behalf. However, marketing opportunities for Acadia are significantly impacted by the price of gas, the current over supply of gas-fired generation in the region, and transmission availability which can in turn limit the number of possible customers for Acadia’s output. Due to these factors, management can not predict whether it or the third party marketer will be successful in its marketing efforts. Management plans to continue to identify potential customers and continue bilateral
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discussions with counterparties for long-term sales and similar agreements to further hedge Acadia’s exposure to market risk. However, due to these uncertainties and without the addition of non-operating cashflow such as external financing and/or additional equity from Acadia’s members, neither of which are assured or readily available, there is substantial doubt about Acadia’s ability to continue as a going concern.
The consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amount and classification of liabilities that may result from the outcome of these uncertainties.
Note 4 - Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of Acadia and its wholly-owned subsidiary, Acadia Partners Pipeline LLC (the Pipeline). All intercompany balances have been eliminated upon consolidation.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosures of contingent assets and liabilities at the date of these financial statements. Actual results could differ from these estimates. The most significant estimates with regard to these financial statements relate to the useful lives and carrying value of the Facility, related depreciation, impairment of property, plant and equipment and allowance for doubtful accounts receivable.
Statements of Cash Flows
The statements of cash flows are prepared using the “indirect method” described in Statement of Financial Accounting Standards (SFAS) No. 95, “Statements of Cash Flows.” This method requires that net income be adjusted to remove the effects of all deferrals and accruals of operating cash receipts and payments and the effects of all investing and financing cash flow items.
Cash and Cash Equivalents
Acadia considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The carrying amount of these instruments approximates fair value due to their short-term maturity.
Accounts Receivable and Accounts Payable
Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively, and are recorded at the invoiced amount. Outstanding accounts receivable are reviewed by management and an allowance for doubtful accounts is established, if necessary. Acadia’s
allowance for doubtful accounts at December 31, 2008, was $0.5 million. Acadia had no allowance for doubtful accounts at December 31, 2007. The $0.5 million allowance at December 31, 2008, is related to over-billings from Calpine to Acadia.
Materials and Supplies Inventory
Materials and supplies inventory is comprised of spare parts and is valued at the lower of cost or market. The value of large spare parts estimated to be used within one year are determined using the specific identification method when issued from inventory. For other spare parts, the value of the part when issued from inventory is generally determined using the weighted average cost method.
Other Current Assets
Other current assets include prepaid expenses for insurance and the Long Term Program (LTP) payments. Prepaid expense for insurance included in other current assets was $0.4 million and $0.3 million at December 31, 2008, and 2007, respectively. Prepaid LTP payments included in other current assets were $1.1 million and $1.8 million at December 31, 2008, and 2007, respectively. For additional information on the LTP, see Note 9 - “Commitments and Contingencies - Long Term Program.”
Property, Plant and Equipment, Net
Property, plant and equipment, net is stated at cost less accumulated depreciation. Asset additions, when ready for their intended use, are transferred from construction work in progress to property, plant and equipment. Upon retirement or disposition, the difference between the net book value of the property and any proceeds received from the property is recorded as a gain or loss on asset disposition on the income statement. Any cost incurred to remove the asset is charged to expense.
The cost of repairs and minor replacements is charged to expense as incurred. The cost of substantial improvements is capitalized.
Property, plant and equipment, net of estimated salvage value of 10% is depreciated using the straight-line method over the estimated useful lives of the assets, generally 35 years for Acadia’s power plant assets, including interconnect pipelines. For all power plant assets with useful lives of 10 years or less, no salvage value is estimated. Annual depreciation provisions expressed as a percentage of total depreciable property for Acadia were 2.99% for 2008, 3.11% for 2007, and 2.93% for 2006.
As of December 31, 2008, and 2007, the components of property, plant and equipment, net consisted of the following.
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FORM 10-K
For the years ended December 31, 2008, 2007 and 2006, depreciation expense was $14.8 million, $15.4 million, and $14.6 million, respectively.
In accordance with SFAS No. 144, “Accounting For the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144), Acadia evaluates the impairment of long-lived assets based on the projection of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In accordance with SFAS No. 144, such cash flows do not include interest or tax expense cash outflows. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values.
Major Maintenance
During 2006 and 2007, as major maintenance occurred, and as parts were replaced on the plant’s steam and combustion turbines, the maintenance costs were either expensed or transferred to property, plant and equipment and depreciated over the parts’ estimated useful lives, which is generally three to six years, depending on the nature of maintenance activity performed under the LTP in place at that time.
In January 2008, the LTP was amended, which amendment modified the maintenance and payment schedules. Under the amended LTP, major parts are now warrantied. Acadia makes quarterly payments to Siemens Energy based on a combination of the number of plant starts and/or run hours in that period. These payments are expensed as incurred. As outages occur, Acadia is billed for labor related to the outage and any parts not covered under the warranty. The labor is expensed as incurred, and accruals are recorded through the normal accounts payable process.
Income Taxes
Acadia is a limited liability company and, for tax purposes, has elected to be treated as a partnership. The financial results of Acadia are included in tax returns of the individual members. Accordingly, no recognition has been given to income taxes in these consolidated financial statements.
Revenue Recognition
Acadia had two tolling agreements with CES whereby the capacity revenue was accounted for as a lease. Lease accounting treatment requires operating leases with minimum lease rentals that vary over time to be levelized over the term of the contract. Acadia levelized these contract revenues on a straight-line basis. These tolling agreements were cancelled by the court in May 2007. In addition, Acadia had a service agreement that was classified as an executory contract, and revenue was recognized upon transmission or delivery to customers. For information on this contract, see Note 7 - “Related Party Transactions - Tolling Agreements with CES.”
Beginning in April 2006, Acadia entered into an agreement with Tenaska Power Services Company (Tenaska) to market electricity from Acadia. Acadia recognizes revenue for sales under the agreements as deliveries are made. For information on the marketing agreement, see Note 8 - “Significant Contractual Obligations - Energy Management Services Agreement.”
Concentration of Credit Risk
The financial instruments that potentially expose Acadia to credit risk consist primarily of short-term investments classified as cash equivalents and accounts receivable.
Acadia had $1.4 million in short-term investments in an institutional money market fund at December 31, 2008. If the counterparty failed to perform under the terms of the investment, Acadia would be exposed to a loss of the invested amounts. In order to mitigate this potential credit risk, Acadia has adopted investment guidelines for investments in money market funds, which specify the size, years in existence, portfolio makeup and rating agency category.
SFAS No. 157 requires entities to classify assets and liabilities measured at their fair value according to three different levels, depending on the inputs used in determining fair value.
§
Level 1 - unadjusted quoted prices in active, liquid markets for the identical asset or liability;
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Level 2 - quoted prices for similar assets and liabilities in active markets or other inputs that are observable for the asset or liability, including inputs that can be corroborated by observable market data, observable interest rate yield curves and volatilities;
§
Level 3 - unobservable inputs based upon the entities own assumptions.
At December 31, 2008, Acadia’s short-term investment was a Level 2 investment with a fair value of $1.4 million.
Acadia has an agreement with Tenaska to market electricity on behalf of Acadia. The agreement can be terminated upon Acadia’s seven-day notice to Tenaska. Acadia recognizes revenue for sales under the agreement as deliveries are made. Acadia’s receivables relating to these sales have exposure to trends within the energy industry, including declines in the creditworthiness of its customers. Acadia does not believe there is significant credit risk associated with Tenaska due to its payment history. For information on the marketing agreement, see Note 8 - “Significant Contractual Obligations - Energy Management Services Agreement.”
Fair Value of Financial Instruments
The carrying amounts reported in the balance sheets for accounts receivable and accounts payable approximate their fair values due to their short-term maturities.
Note 5 - Business Risks
Several current issues in the power industry could have an effect on Acadia’s financial performance. Some of the business risks that could cause future results to differ from historical results include: (1) legislative and regulatory initiatives regarding deregulation, regulation or restructuring of the electric utility industry; (2) the extent and timing of the entry of additional competition in the market in which Acadia operates;
CLECO CORPORATION
CLECO POWER
FORM 10-K
(3) state, federal and other rate regulations in the areas in which Acadia does business; (4) changes in or application of environmental and other laws and regulations to which Acadia is subject; (5) changes in market conditions, including developments in energy and commodity supply, volume and pricing; (6) weather and other natural phenomena; and (7) the direct or indirect effects on the business resulting from the financial difficulties of competitors of Acadia, including but not limited to, their effects on liquidity in the trading and power industry and the views of the capital markets regarding the energy or trading industry.
Note 6 - Recent Accounting Standards
Acadia adopted, or will adopt, the recent accounting standards listed below on their respective effective dates.
In September 2006, the FASB issued SFAS No. 157, which provides guidance on how companies should measure fair value when required for recognition or disclosure purposes under generally accepted accounting principles. Specifically, SFAS No. 157 creates a common definition of fair value throughout generally accepted accounting principles, establishes a fair value hierarchy, and requires companies to make expanded disclosures about fair value measurements. This statement is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB amended SFAS No. 157. FSP No. FAS 157-1 excludes fair value lease calculations pursuant to SFAS No. 13, as amended, from SFAS No. 157, but does not exclude assets and liabilities acquired pursuant to SFAS No. 141(R). FSP No. FAS 157-2 defers the effective date of SFAS No. 157 by one year for non-financial assets and liabilities that are not recognized or disclosed at fair value on a recurring basis. The adoption of SFAS No. 157 and the related FSPs did not have a material impact on the financial condition or results of operations of Acadia.
In February 2007, the FASB issued SFAS No. 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. Acadia did not elect the fair value option for eligible items existing at the effective date. The adoption of SFAS No. 159 did not have an impact on the financial condition or results of operations of Acadia.
In December 2007, the FASB released SFAS No. 141(R). This revision requires the acquirer of a business to recognize assets acquired, liabilities assumed, and any non-controlling interests at their fair market values. The statement gives guidance on the calculation of goodwill or gain from a bargain purchase and expands the required disclosures. The provisions of this statement are applicable to acquisitions either through one transaction or through a step acquisition. This SFAS is applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. This statement may not be adopted early. The adoption of this statement will only impact the financial condition and results of operations of Acadia if it is involved in transactions within the scope of this statement after its effective date.
In December 2007, the FASB released SFAS No. 160. This statement gives guidance on the presentation and disclosure of noncontrolling interests (currently known as minority interests) of consolidated subsidiaries. This statement requires the noncontrolling interest to be included in the equity section of the balance sheet, requires disclosure on the face of the consolidated income statement of the amounts of consolidated net income attributable to the consolidated parent and the noncontrolling interest, and expands disclosures. The provisions of this statement are to be applied prospectively to fiscal years beginning on or after December 15, 2008. Early adoption of this statement is prohibited. The adoption of this statement will only impact the financial condition and results of operations of Acadia if it is involved in transactions within the scope of this statement after its effective date.
In April 2008, the FASB issued FSP No. FAS 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. This FSP amends SFAS No. 142 to allow an entity’s own experience in renewing arrangements or to use market assumptions about renewal in determining the useful life of a recognized intangible asset. This FSP also requires additional disclosure about the renewal costs. FSP No. FAS 142-3 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. Early adoption of FSP No. FAS 142-3 is prohibited. The adoption of FSP No. FAS 142-3 is not expected to have an impact on the financial condition or results of operations of Acadia.
In May 2008, the FASB issued SFAS No. 162 which identifies, categorizes and ranks sources of U.S. generally accepted accounting principles (GAAP). This SFAS has four broad categories. An entity is required to use the highest category of GAAP specified by a pronouncement. If a particular transaction is not specified by a pronouncement within the categories, an entity can then apply accounting pronouncements for similar transactions (unless such analogy is prohibited by a particular pronouncement) followed by other accounting literature. This SFAS is effective 60 days following the SEC’s approval of the PCAOB’s amendments to Auditing Standard Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” The adoption of SFAS No. 162 is not expected to have an impact on the financial condition or results of operations of Acadia.
In December 2008, the FASB announced the implementation of the FASB Accounting Standards Codification which will become the single source of authoritative nongovernmental GAAP and will supersede existing FASB, AICPA, EITF and related literature. The thousands of U.S. GAAP pronouncements will be reorganized into roughly 90 accounting topics which will be displayed in a consistent format. The Codification structure is expected to be effective after June 30, 2009.
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CLECO POWER
FORM 10-K
Note 7 - Related Party Transactions
Tolling Agreements with CES
Acadia had two tolling agreements with CES. In accordance with the terms of the CES tolling agreements, CES supplied all fuel necessary to generate the energy it took from the Facility and paid Acadia a capacity charge and an operation and maintenance fee. Prior to the suspension of the tolling agreements in March 2006, these agreements were accounted for as operating leases, and therefore, capacity revenue was recognized on a straight-line basis. Due to varying payments contained in the contract, the difference between the amount billed to CES and capacity revenue recognized under the contract was recorded as deferred revenue or lease levelization asset in the consolidated balance sheets.
CES provided a letter of credit in favor of APH to collateralize its obligations under its tolling agreements with Acadia. The terms of the letter of credit allowed APH to make a draw in the event of a CES default under the tolling agreements. Acadia’s limited liability company agreement required that a draw in favor of APH be treated as a distribution thereby reducing APH’s member interest in Acadia. Due to CES’s Bankruptcy Filing, in 2006 APH submitted drawing certificates in the amount of $15.0 million on the letter of credit. Since the letter of credit collateralized CES’s obligations under the tolling agreements and since drawing upon the letter of credit satisfied CES’s obligations to Acadia to the extent of the letter of credit draws, the criteria for revenue recognition were met, as collection was reasonably assured. Accordingly, Acadia recognized revenue in 2006 for the amount of the letter of credit draws totaling $15.0 million and reduced APH’s member’s interest by the same amount. Acadia did not recognize revenue under the tolling agreements for the years ended December 31, 2008, 2007 or 2006 beyond that collateralized by the CES letter of credit.
Acadia recorded revenues of $15.0 million for the year ended December 31, 2006, pursuant to the CES tolling agreements. In September 2007, subsequent to the approval of the Calpine Debtors Bankruptcy Claims Settlement Agreement and the sale of the CAH Assets to Cajun, APH received payment from Cajun for the agreed upon value of the priority and guaranteed distributions under the tolling agreements.
Project Management Agreement/Operations and Maintenance Agreement
Acadia contracted with CCLP to provide project management services, which included the operation of the Facility and administrative and billing services, and operation and maintenance of the generating assets, under two separate agreements. The project management agreement (PMA) was dated February 29, 2000, and the operating and maintenance (O&M) agreement was dated July 27, 2001. Both were set to terminate on February 29, 2050, unless terminated by CCLP with 90 days notice. Acadia reimbursed CCLP for costs and expenses of $7.3 million and $14.8 million within plant operating expense for the years ended December 31, 2007 and 2006, respectively.
Beginning September 14, 2007, upon the closing of the CAH asset sale and with the approval of the Calpine Debtors Bankruptcy Court, the project management function and the operation and maintenance functions were transferred to APH, who subsequently contracted with Cleco Generation Services LLC (Generation Services) and Cleco Support Group LLC (Support Group) to provide project management and O&M services. Generation Services is a subsidiary of Midstream and Support Group is a subsidiary of Cleco Corporation. The responsibilities and duties to be performed by Generation Services and Support Group under the PMA and the O&M agreements are the same as the responsibilities of CCLP under the original PMA and O&M agreements. For the year ended December 31, 2008, and 2007, Acadia recorded payments to Generation Services of $3.5 million and $0.9 million, respectively for O&M services. For the year ended December 31, 2008, and 2007, Acadia recorded payments to Support Group of $1.0 million and $0.3 million, respectively for project management services. At December 31, 2008, Acadia had affiliate payable balances of $0.3 million and less than $0.1 million to Generation Services and Support Group, respectively.
Electric Service Agreement
Acadia has an agreement for electric service with Cleco Power, LLC (Cleco Power), a subsidiary of Cleco Corporation, dated December 15, 2001. The agreement covers electrical purchases of the Facility pursuant to Cleco Power’s LPSC Rate Schedule GS and its Rider Schedule for Long-Term Economic Development Services, subject to approval by the Louisiana Public Service Commission (LPSC). Based on this agreement, Acadia recognized expense of $2.2 million, $2.1 million and $2.0 million within plant operating expense for electricity received for the years ended December 31 2008, 2007 and 2006, respectively.
Interconnection and Operating Agreement
Acadia has an Interconnection and Operating Agreement with Cleco Power, dated February 25, 2000, pursuant to which Acadia’s Facility is interconnected to Cleco Power’s adjacent transmission facilities. Acadia is obligated to construct, own, operate and maintain all the interconnection facilities and equipment on its side of the point of interconnections, and Cleco Power is obligated to construct, own, operate, and maintain the interconnection facilities and equipment on its side of the point of interconnection. Based on this agreement, Acadia paid Cleco Power for the operation and maintenance of Acadia’s interconnection facilities and recognized expense of less than $0.1 million within plant operating expense for each of the years ended December 31, 2008, 2007 and 2006.
Other
Cleco Corporation routinely makes purchases on behalf of Acadia or makes payments for Acadia as financial obligations of Acadia arise. Amounts are reimbursed to Cleco Corporation by Acadia throughout the year. These purchases and/or payments amounted to $1.3 million and $0.1 million for the
CLECO CORPORATION
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FORM 10-K
years ended December 31, 2008, and 2007, respectively. At December 31, 2008, and 2007, the balance owed to Cleco Corporation for these transactions was less than $0.1 million.
Note 8 - Significant Contractual Obligations
Energy Management Services Agreement
On April 7, 2006, Acadia entered into an agreement with Tenaska to market electricity from Acadia. The agreement can be terminated upon Acadia’s seven-day notice to Tenaska. For the years ended December 31, 2008, 2007 and 2006, Acadia recognized $74.0 million, $63.5 million, and $82.2 million, respectively, in revenues related to this agreement. Acadia recognized $63.3 million, $53.3 million, and $65.5 million in operating expense related to this agreement for the years ended December 31, 2008, 2007, and 2006, respectively.
Power Purchase Agreement
In July 2008, Acadia entered into an agreement to provide Cleco Power a minimum of 50 MW up to 235 MW to meet Cleco Power’s 2009 capacity and energy requirements. The agreement is for supply starting March 1, 2009, and ending October 1, 2009. This agreement has received approval from the LPSC and FERC.
Tolling Agreements
In October 2000, Acadia entered into a tolling agreement with Aquila that was effective for 20 years beginning July 1, 2002. In May 2003, Acadia terminated this tolling agreement with Aquila in return for a cash settlement of $105.5 million. CAH and APH agreed to distribute the proceeds as follows: (i) CAH received the $105.5 million cash distribution in 2003; (ii) APH was entitled to receive an annual priority cash distribution of $14.0 million starting from July 2003 through June 30, 2022; (iii) all distributions in excess of the first $14.0 million were allocated between members in accordance with their respective interest; (iv) the priority distributions included imputed interest based on the rate of approximately 12.1%. Imputed interest for the years ended December 31, 2007 and 2006, of $4.1 million and $6.0 million, respectively, was recorded as an adjustment to the Member capital balances of APH and CAH. Due to the 2007 payment of the priority distributions, there was no imputed interest for the year ended December 31, 2008.
The priority distribution for 2006 was not paid or accrued by Acadia due to the fact that there was no distributable cash, the management committee did not declare a distribution and there was uncertainty as to whether cash would be available and whether the management committee would declare a distribution in the future. Under the LLC Agreement, priority distributions are cumulative, but only to the extent of available distributable cash and management committee declaration.
In September 2007, subsequent to the approval of the Calpine Debtors Bankruptcy Claims Settlement Agreement and the sale of the CAH Assets to Cajun, APH received payment from Cajun in the amount of $60.0 million for the agreed upon value of the priority distributions. The $60.0 million distributions, reduced by interest on the distribution previously recorded, is reflected in the Consolidated Statements of Changes in Members’ Capital for the year 2007.
Pipeline Operating Agreement
Millennium Midstream Energy, LLC assumed responsibility for pipeline operations and maintenance in 2005 under the Pipeline Operations Agreement. The agreement covers all operations, repair, improvements, alterations, inspections, testing, protection and other operations and activities that are necessary to maintain pipeline assets in accordance with federal safety and maintenance standards and the regulations of the Louisiana Office of Conservation, and to accomplish the business objectives of Acadia. Acadia recognized expense of $0.1 million within plant operating expense for each of the years ended December 31, 2007, and 2006, for these services. Acadia terminated this agreement in the first quarter of 2007, and responsibilities were assumed by Cleco Corporation.
In January 2008, Acadia executed a new pipeline operation and maintenance agreement with GT Operating Company LLC. Acadia recognized expense of $0.1 million within plant operating expense for the year ended December 31, 2008. Management anticipates no significant change to the level of payments for pipeline operations and maintenance in the future.
Note 9 - Commitments and Contingencies
Long Term Program
Acadia entered into a LTP for spare parts, maintenance and related technical services on May 3, 2002 with Siemens Energy. The term of the agreement, with respect to each of Acadia’s four combustion turbines, began upon the commercial operation date and terminates on an individual combustion turbine basis at the end of the scheduled maintenance following the second major inspection of each respective combustion turbine or sixteen years, whichever comes first. In August 2006, an amendment was made to the LTP which established maintenance and payment schedules based on estimates of the number of starts in a given period. The actual timing of maintenance may vary based on actual starts versus estimated starts due to operational and performance considerations. Prior to this amendment, the maintenance and payment schedules were based on the estimated number of run hours.
In January 2008, Acadia and Siemens Energy executed an amendment to the LTP modifying the maintenance and payment schedules based on the number of plant starts and/or run hours. The purpose of the amendment was to attempt to better stabilize maintenance costs incurred for planned outages. Management anticipates no significant change to the current level of maintenance payments made to Siemens Energy in the future.
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Planned and Unscheduled Outages
In November 2006, the combustion gas turbine unit CT-25 had a 14-day outage for work performed on the hot gas path (HGP). The cost of repairs totaling $2.9 million was included in plant operating expense for the year ended December 31, 2006. In addition to the repair costs, Acadia also removed from service parts with a net book value of $1.4 million related to the unit CT-25 outage, which also is included in plant operating expense for the year ended December 31, 2006.
In 2007, based on updated outage information relating to the combustion gas turbine unit CT-25, an additional $0.4 million of net book value for turbine parts was charged to expense. Also in May and June of 2007, combustion gas turbine unit CT-11 had a planned one-month outage to perform work on the HGP. Turbine parts with a net book value of $3.1 million were charged to expense.
Siemens Energy replaced the Generator Rotor Pole Cross-Over on CT-24 and CT-25 generators during the planned outage in February 2008. This resulted in removal expense of $0.2 million and asset retirements of less than $0.1 million.
Acadia Metering Dispute
A potential electric metering error issue surfaced as a result of a 2005 review of the metering at the Facility. The potential error caused Acadia to unknowingly generate excess power during the period June 2002 through May 2005, for which it received no compensation. Acadia’s management decided that a right to assert a claim for compensation existed against a company with a transmission interconnection with the Facility. In April 2007, Acadia assigned to each of its Members the right to assert a claim for 50% of the potential compensation owed by this company.
In September 2007, as part of Calpine’s sale to Cajun, APH obtained 100% of the right to assert a claim for the metering error, at which time APH wrote-off the entire claim and recognized $1.3 million expense in 2007.
Other Contingencies
Acadia is involved in various legal and litigation matters arising in the normal course of business. Management does not expect that the outcome of these proceedings will have a
material adverse effect on the financial position, results of operations or cash flows of Acadia.
Note 10 - Environmental Matters
The state of Louisiana regulates air and water emissions from Acadia’s facility under the authority of the Louisiana Department of Environmental Quality (LDEQ). In addition, the LDEQ has been delegated authority over and implements certain environmental regulatory programs established by the United States Environmental Protection Agency under the Clean Air Act and the Clean Water Act. The LDEQ establishes specific standards for performance and requires permits for certain electric generating units in Louisiana. Acadia is currently in compliance in all material respects with the LDEQ regulations as well as its air and water permit requirements.
In order to correct instances where exceedences of temperature and pH limitations have occurred, and to facilitate compliance with whole effluent toxicity testing limitations, Acadia has submitted an application to LDEQ to modify its water discharge permit. Specifically, the permit application requests the relocation of its main plant outfall in order to allow proper mixing of effluents from Acadia. Acadia anticipates that this relocation will resolve the issues associated with the permit exceedences with no material impact on expected capital costs, operating costs, or cash flows.
Note 11 - Subsequent Event
On February 26, 2009, Cleco Power announced that it had chosen the acquisition of 50 percent of the Acadia power station, or one of its two 580-MW units, as the lowest bid in its 2007 long-term RFP for capacity beginning in 2010. Cleco Power will own and operate one unit and operate the other 580-MW unit on behalf of Acadia. Prior to closing the transaction, valued at approximately $300.0 million, the parties must complete due diligence, finalize and execute definitive agreements, and receive approvals from the LPSC and FERC. Cleco Power and Acadia plan to complete the transaction by the end of 2009 in a process that remains under the supervision of an independent monitor appointed by the LPSC.
CLECO CORPORATION
CLECO POWER
FORM 10-K
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 CORPORATION
(Registrant)
By:
/s/ Michael H. Madison
(Michael H. Madison)
(President, Chief Executive Officer and Director)
Date: February 26, 2009
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 dates indicated.
SIGNATURE
TITLE
DATE
/s/ Michael H. Madison
President, Chief Executive Officer and Director
February 26, 2009
(Michael H. Madison)
(Principal Executive Officer)
/s/ R. Russell Davis
Vice President, Chief Accounting Officer &
Interim CFO
February 26, 2009
(R. Russell Davis)
(Principal Financial Officer and Principal Accounting Officer)
DIRECTORS*
SHERIAN G. CADORIA
RICHARD B. CROWELL
J. PATRICK GARRETT
ELTON R. KING
LOGAN W. KRUGER
WILLIAM L. MARKS
ROBERT T. RATCLIFF, SR.
WILLIAM H. WALKER, JR.
W. LARRY WESTBROOK
*By:
/s/ Michael H. Madison
February 26, 2009
(Michael H. Madison, as Attorney-in-Fact)
CLECO CORPORATION
CLECO POWER
FORM 10-K
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)
By:
/s/ Michael H. Madison
(Michael H. Madison)
(Chief Executive Officer and Manager)
Date: February 26, 2009
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 dates indicated.
SIGNATURE
TITLE
DATE
/s/ Michael H. Madison
Chief Executive Officer and Manager
February 26, 2009
(Michael H. Madison)
(Principal Executive Officer)
/s/ R. Russell Davis
Vice President, Chief Accounting Officer &
Interim CFO
February 26, 2009
(R. Russell Davis)
(Principal Financial Officer and Principal Accounting Officer)
MANAGERS*
SHERIAN G. CADORIA
RICHARD B. CROWELL
J. PATRICK GARRETT
ELTON R. KING
LOGAN W. KRUGER
WILLIAM L. MARKS
ROBERT T. RATCLIFF, SR.
WILLIAM H. WALKER, JR.
W. LARRY WESTBROOK
*By:
/s/ Michael H. Madison
February 26, 2009
(Michael H. Madison, as Attorney-in-Fact)