ITEM 1. BUSINESS
WEBSITE ACCESS TO REPORTS
We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934 (Exchange Act) available free of charge on or through our internet website, www.cinergy.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (SEC).
As of January 1, 2006, The Union Light, Heat and Power Company (ULH&P) ceased to be subject to the reporting requirements of section 13(a) or 15(d) of the Exchange Act. ULH&P is considering discontinuing filing reports and other information under such sections.
ORGANIZATION
Cinergy Corp., a Delaware corporation organized in 1993, owns all outstanding common stock of The Cincinnati Gas & Electric Company (CG&E) and PSI Energy, Inc. (PSI), both of which are public utilities, as well as Cinergy Investments (Investments), its non-regulated investment holding company.
CG&E, an Ohio corporation organized in 1837, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through ULH&P, in nearby areas of Kentucky. CG&E is responsible for the majority of our power marketing and trading activity. CG&E’s principal subsidiary, ULH&P, a Kentucky corporation organized in 1901, provides electric and gas service in northern Kentucky.
CG&E is transitioning out of a market development period for residential customers and is in the competitive retail electric market for non-residential customers. CG&E is also transitioning to deregulation of electric generation and a competitive retail electric service market in the state of Ohio. Applicable legislation governing the transition period provides for a market development (frozen rate) period that began January 1, 2001, ended December 31, 2004 for non-residential customers and ended December 31, 2005 for residential customers. At the end of these market development periods, CG&E did not implement market rates, but rather a rate stabilization plan (RSP) approved by the Public Utilities Commission of Ohio (PUCO) that covers the period after the market development period through 2008. The RSP, among other things, increases rates for environmental costs and capacity reserves and provides for a fuel and emission allowance cost recovery mechanism through 2008. See “CG&E Electric Rate Stabilization Plan” for additional information.
PSI, an Indiana corporation organized in 1942, is a vertically integrated and cost of service regulated electric utility that provides service in north central, central, and southern Indiana.
The following table presents further information related to the operations of our domestic utility companies, CG&E, PSI, and ULH&P (our utility operating companies):
(1) See “Electric Industry - Kentucky” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) - Future Expectations/Trends” for further discussion of the transfer of certain generation assets in January 2006. Following the transfer of generating assets, generation will be provided to cities of Covington, KY; Florence, KY; and Newport, KY by ULH&P.
The following table presents further information related to the operations of our other principal subsidiaries, Cinergy Services, Inc. (Services) and Investments:
(1) Services provides the noted services to our subsidiaries.
(2) Natural gas marketing and trading operations are primarily conducted through Cinergy Marketing & Trading, LP (Marketing & Trading), one of Cinergy’s subsidiaries.
MERGER
On May 8, 2005, Cinergy Corp. entered into an agreement and plan of merger with Duke Energy Corporation (Duke), a North Carolina corporation, whereby Cinergy Corp. will be merged with Duke. Under the merger agreement, each share of Cinergy Corp. common stock will be converted into 1.56 shares of the newly formed company, Duke Energy Holding Corp (Duke Energy Holding).
The merger agreement has been approved by both companies’ Boards of Directors. Consummation of the merger is subject to customary conditions, including, among others, the approval of the shareholders of both companies and the approvals of various regulatory authorities.
Immediately following consummation of the merger, former Cinergy shareholders will own approximately 24 percent of Duke Energy Holding’s common stock. Paul Anderson, Duke’s CEO and Chairman of the Board will remain Chairman of the combined company and Jim Rogers, Cinergy’s CEO and Chairman of the Board, will become the President and CEO of the combined company. The new Duke Energy Holding board will be comprised of 10 members appointed by Duke and five members appointed by Cinergy.
The merger will be recorded using the purchase method of accounting whereby the total purchase price of approximately $9 billion will be allocated to Cinergy’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of the closing of the merger.
The merger is expected to close in the first half of 2006. However, the actual timing is contingent on the receipt of several approvals including: The Federal Energy Regulatory Commission (FERC), Federal Communications Commission (FCC), Nuclear Regulatory Commission (NRC), state regulatory commissions of Ohio, Indiana, Kentucky, North Carolina, and South Carolina, and shareholders of each company. The status of these matters is as follows:
Completed:
• On August 11, 2005, the United States Department of Justice and the Federal Trade Commission granted early termination of the waiting period imposed by the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
• In November 2005, the Kentucky Public Service Commission (KPSC) approved Duke’s and Cinergy’s application seeking approval of a transfer and acquisition of control of ULH&P.
• In November 2005, the state utility regulatory agency in South Carolina approved Duke’s application requesting authorization to enter into a business combination.
• In December 2005, the PUCO approved Cinergy’s application of a change in control with respect to CG&E. The PUCO affirmed the approval in February 2006.
• In December 2005, the FERC approved Duke’s and Cinergy’s application requesting approval of the merger and the subsequent internal restructuring and consolidation of the merged company.
• In February 2006, the NRC approved Duke’s application requesting approval of the merger.
• The FCC has approved assignment of all eight Cinergy wireless telecommunications licenses.
• In light of the repeal of the Public Utility Holding Company Act of 1935 (PUHCA 1935), as amended, effective February 2006, the merger will no longer require SEC authorization under the PUHCA 1935.
Pending:
• In June 2005, PSI filed a petition with the Indiana Utility Regulatory Commission (IURC) concerning, among other things, certain merger-related affiliate agreements, the sharing of merger-related benefits with customers, and deferred accounting of certain merger-related costs. On December 15, 2005, PSI filed with the IURC a settlement agreement reached with the staff of the IURC, the Indiana Office of Utilities Consumer Counsel and the PSI Industrial Group. Settlement hearings were held in January 2006 and a final order is expected in March 2006.
• In July 2005, Duke filed an application with the state utility regulatory agency in North Carolina. The application requests both the authorization to enter into a business combination transaction and the approval of various affiliate agreements. Hearings were held in January 2006 and a final order is expected in March 2006.
• Special meetings of shareholders of both companies for the purpose of voting on the merger will be held on March 10, 2006.
The merger agreement also provides that Duke and Cinergy will use their reasonable best efforts to transfer five generating stations located in the midwest from Duke to CG&E. This transfer will require regulatory approval by the FERC and, with respect to one plant located in Indiana the IURC. The FERC approved this transaction in December 2005. CG&E and the Duke affiliate that owns the interest in the Indiana plant filed an application with the IURC requesting approval for the transfer (as well as the declination by the IURC of jurisdiction over CG&E following the transfer) in October 2005. A final order approving the transfer and the IURC’s declination of jurisdiction over CG&E was received in February 2006. Duke and Cinergy intend to effectuate the transfer as an equity infusion into CG&E at book value. In conjunction with the transfer, Duke Capital LLC, a subsidiary of Duke, and CG&E intend to enter into a financial arrangement covering a multi-year period, to eliminate any potential cash shortfalls that may result from CG&E owning and operating the five stations. At this time, we cannot predict the outcome of this matter.
The merger agreement contains certain termination rights for both Duke and Cinergy, and further provides that, upon termination of the merger agreement under specified circumstances, a party would be required to pay the other party’s fees and expenses in an amount not to exceed $35 million and/or a termination fee of $300 million in the case of a fee payable by Cinergy to Duke or a termination fee of $500 million in the case of a fee payable by Duke to Cinergy. Any termination fee would be reduced by the amount of any fees and expenses previously reimbursed by the party required to pay the termination fee.
Although Management believes that the merger should close in the first half of 2006, the actual timing of the transaction could be delayed or the merger could be abandoned by the parties in the event of the inability to obtain one or more of the required regulatory approvals on acceptable terms.
BUSINESS SEGMENTS
We conduct operations through our subsidiaries and manage our businesses through the following three reportable segments:
• Regulated Business Unit (Regulated);
• Commercial Business Unit (Commercial); and
• Power Technology and Infrastructure Services Business Unit (Power Technology and Infrastructure).
The following section describes the activities of our business segments as of December 31, 2005.
See Note 18 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for financial information by business segment.
Regulated
Regulated consists of PSI’s regulated generation and transmission and distribution operations, and CG&E and its subsidiaries’ regulated electric and gas transmission and distribution systems. Regulated plans, constructs, operates, and maintains Cinergy’s transmission and distribution systems and delivers gas and electric energy to consumers. Regulated also earns revenues from wholesale customers primarily by these customers transmitting electric power through Cinergy’s transmission system. These businesses are subject to cost of service ratemaking where rates to be charged to customers are based on prudently incurred costs over a test period plus a reasonable rate of return. Regulated operated approximately 57,000 circuit miles (the total length in miles of separate circuits) of electric lines to provide regulated transmission and distribution service to approximately 1.6 million customers as of December 31, 2005. Regulated operated approximately 10,062 miles of gas mains (gas distribution lines that serve as a common source of supply for more than one service line) and service lines to provide domestic regulated transmission and distribution services to approximately 511,000 customers as of December 31, 2005. See “Item 2. Properties” for a further discussion of the transmission and distribution systems owned by our utility operating companies.
Detail of Regulated’s operations can be found in the following sections:
• Generation - Fuel Supply and Emission Allowances - Describes Regulated’s generation capacity, sources of fuel, and its various cost recovery mechanisms;
• Transmission and Distribution - Describes Regulated’s agreements with the regional utilities and regional transmission organization (RTO) that coordinate the planning and operation of generation and transmission facilities and the associated cost recovery mechanisms;
• Gas Supply - Describes Regulated’s responsibility to purchase and deliver natural gas to native load (the total requirements of a wholesale utility’s franchised retail market) customers and the mechanisms used to fulfill this responsibility; and
• Revenue Data and Customer Base - Describes the primary revenue sources for the various business operations of Regulated.
Generation - Fuel Supply and Emission Allowances
As of December 31, 2005, the total winter electric capacity (including our portion of the total capacity for the jointly-owned plants) of Regulated’s generating plants was 7,543 megawatt (MW). Approximately 73 percent of this generation portfolio is coal-fired. See “Item 2. Properties” for a further discussion of the generating facilities.
Each year PSI purchases over 15 million tons of coal to generate electricity, primarily from mines located in Indiana, Kentucky and Illinois. The price of coal has increased significantly in 2005 and 2004 as compared to prior years. The primary driving forces behind the increase in coal prices are (1) increases in demand for electricity, (2) high and volatile gas prices and limited gas supply, which has increased reliance on coal-fired generation, (3) environmental regulation, and (4) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, we have a general practice to procure a substantial portion of coal through fixed-price contracts of varying length. We hold fixed-price contracts that will source substantially all of our expected 2006 coal requirements. We evaluate the appropriate amount of contract coal and length of contracts based on market conditions, including pricing trends, volatility and supplier reliability. See “Contractual Cash Obligations” in “Item 7. MD&A - Liquidity and Capital Resources” for further detail on PSI’s total commitment under fixed-price coal contracts.
Regulated has natural gas-fired peaking plants that have a capacity of 1,751 MW, including the 488 MW Wheatland facility acquired in May 2005. For more information on the Wheatland acquisition, see “Electric Industry - Indiana” in “Item 7. MD&A - Future Expectations/Trends.” The fuel for these units is primarily obtained through the natural gas spot market as it is difficult to forecast the natural gas requirements for these plants. For further information on the risk of purchasing natural gas see “Item 7. MD&A - Market Risk Sensitive Instruments.”
At times, Regulated purchases power to meet the energy needs of its customers. Factors that could cause Regulated to purchase power for its customers include generating plant outages, extreme weather conditions, summer reliability, growth, and price. We believe we can obtain enough purchased power to meet future needs. However, during periods of excessive demand, the price and availability of these purchases may be significantly impacted.
ULH&P purchases energy from CG&E pursuant to a contract effective January 1, 2002, which was approved by the FERC and the KPSC. This five-year agreement is a negotiated fixed-rate contract with CG&E.
The KPSC has approved a long-term electric supply plan for ULH&P that will replace the current contract with CG&E. Under this new plan, CG&E transferred ownership of approximately 1,100 MWs of electric generating capacity to ULH&P in January 2006. This capacity was used to service the aforementioned ULH&P power supply contract. The assets were acquired at net book value and will not affect electric rates for ULH&P’s customers in 2006. See “Electric Industry - Kentucky” in “Item 7. MD&A - Future Expectations/Trends” for additional information.
Cinergy is studying the feasibility of constructing an integrated coal gasification combined cycle (IGCC) generating station to help meet increased demand over the next decade. PSI would be a majority owner of the facility and operate it. An IGCC plant turns coal to gas, removing most of the sulfur dioxide (SO2) and other emissions before
the gas is used to fuel a combustion turbine generator. The technology uses less water and has fewer emissions than a conventional coal-fired plant with currently required pollution control equipment. Another benefit is the potential to remove mercury and carbon dioxide upstream of the combustion process at a lower cost than conventional plants. In August 2005, PSI and Vectren Energy Delivery of Indiana, Inc. filed a joint petition at the IURC seeking cost recovery of the feasibility study as well as engineering and preconstruction costs associated with the consideration and exploration of constructing an IGCC plant. If a decision is reached to move forward with constructing such a plant, PSI would seek approval from the IURC to begin construction. If approved, we would anticipate the IURC’s subsequent approval to include the assets in PSI’s rate base.
Regulated monitors alternative sources of coal and natural gas to assure a continuing availability of economical fuel supplies. As such, it will maintain its practice of purchasing a portion of coal and natural gas requirements on the open market and will continue to investigate least-cost coal options to comply with new and existing environmental requirements. Cinergy and PSI believe that they can continue to obtain enough coal and natural gas to meet future needs. However, future environmental requirements may significantly impact the availability and price of these fuels.
PSI recovers retail and a portion of its wholesale fuel costs from customers on a dollar-for-dollar basis through a cost recovery mechanism (commonly referred to as a fuel adjustment clause). In addition to the fuel adjustment clause, PSI utilizes a purchased power tracking mechanism approved by the IURC for the recovery of costs related to certain specified purchases of power necessary to meet native load peak demand requirements to the extent such costs are not recovered through the existing fuel adjustment clause.
Regulated emits SO2 and nitrogen oxides (NOX) in the generation of electricity and maintains emission allowances to offset their emissions in order to comply with SO2 and NOX emission reduction requirements. In 2005, the average market prices of SO2 allowances rose more than 100 percent from 2004 and more than 400 percent from 2003. PSI utilizes a cost tracking mechanism as approved by the IURC allowing it to recover substantially all of its emission allowance costs from its customers. Cinergy is continually evaluating market conditions and managing our overall cost structure through the addition of pollution control equipment, where economically feasible, and the use of emission allowance markets to help manage our emissions costs.
Transmission and Distribution
Cinergy (through our utility operating companies) and other non-affiliated utilities in a nine-state region are parties to the East Central Area Reliability Coordination (ECAR) Agreement. Through the ECAR Agreement, ECAR supports the planning and operation of generation and transmission facilities, which provide for reliability of regional bulk power supply. Beginning January 1, 2006, ReliabilityFirst will assume the functions of ECAR. ReliabilityFirst is designed to create a single regional reliability council under the North American Electric Reliability Council structure to include member companies from the ECAR, Mid-America Interconnected Network, Inc., and Mid-Atlantic Area Council Regional Reliability Councils. ReliabilityFirst’s purpose is to create a uniform set of reliability standards for the combined regions, with a goal of preserving and enhancing electric service reliability and security for the interconnected electric systems within the region. Cinergy has joined ReliabilityFirst as a Transmission Company.
Cinergy (through our utility operating companies) is also a member of the Midwest Independent Transmission System Operator, Inc. (Midwest ISO), a RTO established in 1998 as a non-profit organization which maintains functional control over the combined transmission systems of its members. In 2005, the Midwest ISO began administering an energy market within its footprint.
The Midwest ISO is the provider for transmission service requested on the transmission facilities under its tariff. It is responsible for the reliable operation of those transmission facilities and the regional planning of new transmission facilities. The Midwest ISO administers energy markets utilizing Locational Marginal Pricing (LMP) (i.e., the energy price for the next MW may vary throughout the Midwest ISO market based on transmission congestion and energy losses) as the methodology for relieving congestion on the transmission facilities under its functional control. See “Midwest ISO” for further detail regarding the Midwest ISO energy markets.
Transmission and Distribution Cost Recovery
A transmission cost recovery mechanism was established under CG&E’s RSP to permit CG&E to recover Midwest ISO charges. CG&E filed a distribution base rate case to recover certain distribution costs, effective January 1, 2006 and we have deferred certain costs in 2004 and 2005 pursuant to its RSP. The parties to the proceeding have agreed upon and filed a settlement setting the recommended annual revenue increase at approximately $51 million. See “CG&E Electric Rate Stabilization Plan” for additional information.
PSI has received IURC approval for the recovery of Midwest ISO costs.
Transmission System Interconnections
The following map illustrates the interconnections between our electric systems and other electric systems.
Gas Supply
Regulated is responsible for the purchase and the subsequent delivery of natural gas to native load customers. Regulated’s natural gas procurement strategy is to buy firm natural gas supplies (natural gas intended to be available at all times) and firm interstate pipeline transportation capacity during the winter season (November through March) and during the non-heating season (April through October) through a combination of firm supply and transportation capacity along with spot supply and interruptible transportation capacity. This strategy allows Regulated to assure reliable natural gas supply for its high priority (non-curtailable) firm customers during peak winter conditions and provides Regulated the flexibility to reduce its contract commitments if firm customers choose alternate gas suppliers under Regulated’s customer choice/gas transportation programs. However, due to market conditions in the spring of 2005, a greater portion of firm supply was acquired for the summer. In 2005, firm supply purchase commitment agreements provided approximately 98 percent of the natural gas supply, with the remaining gas purchased on the spot market. These firm supply agreements feature two levels of gas supply, specifically (1) base load, which is a continuous supply to meet normal demand requirements, and (2) swing load, which is gas available on a daily basis to accommodate changes in demand due primarily to changing weather conditions.
Regulated manages natural gas procurement-price volatility mitigation programs for CG&E and ULH&P. These programs pre-arrange between 25-75 percent of winter heating season base load gas requirements and up to 50 percent of summer season base load requirements up to 3 years in advance of the delivery month. CG&E and ULH&P use primarily fixed-price forward contracts and contracts with a ceiling and floor on the price. As of December 31, 2005, CG&E and ULH&P, combined, had hedged approximately 55 percent of their winter 2005/2006 base load requirements. See the “Gas Industry” section of “Item 7. MD&A - Future Expectations/Trends” for further information.
Interstate pipelines either (1) transport gas purchased directly to the distribution systems or (2) inject gas purchased into pipeline storage facilities for future withdrawal and delivery. The majority of the gas supply comes from the Gulf of Mexico coastal areas of Texas and Louisiana.
Natural gas prices remained in the $8 - $9 per thousand cubic feet (Mcf) range through most of the summer due primarily to the warmer than normal summer and the increased use of gas to fire electric generation peaking units. Extensive damage to the natural gas infrastructure along the Gulf Coast caused by Hurricanes Katrina and Rita pushed the price of natural gas into the
$12 - $14 per Mcf range by late September. Natural gas prices remained in the $12 per Mcf range for the remainder of 2005. Winter delivery prices for early 2006 remained in the $11 - $12 per Mcf range in the midwest or about 40 percent greater than last winter. Forward prices for the remainder of 2006 have now fallen below $10 per Mcf as more of the damaged Gulf Coast infrastructure comes online. Price movement is usually driven by the effects of weather conditions, availability of supply, and changes in demand and storage inventories. Currently, neither CG&E’s nor ULH&P’s gas delivery operations profit from changes in the cost of natural gas because natural gas purchase costs are passed directly to the customer dollar-for-dollar under the gas cost recovery mechanism that is mandated under state law.
Revenue Data and Customer Base
Regulated’s revenue is derived from the sale of gas and power to its customers, which are primarily retail. The percent of retail operating revenues derived from full service electricity and gas sales and transportation for each of the three years ended December 31 were as follows:
Electric and gas sales are seasonal. Electricity usage in our service territory peaks during the summer and gas usage peaks during the winter. Air conditioning increases electricity demand and heating increases electricity and gas demand.
The service territory of CG&E and its utility subsidiaries, including ULH&P, is heavily populated and is characterized by a stable residential customer base and a diverse mix of industrial customers. The territory served by PSI is composed of residential, agricultural, and widely diversified industrial customers. No single retail customer provides more than 10 percent of total operating revenues (electric or gas) for Regulated.
Commercial
Commercial manages our wholesale generation and energy marketing and trading activities. Commercial’s wholesale generation consists of CG&E’s electric generation in Ohio due to Ohio’s transition to deregulation of electric generation and a competitive retail service market. See “Electric Industry - Ohio” in “Item 7. MD&A - Future Expectations/Trends” for further detail of key elements of Ohio deregulation. Commercial also performs energy risk management activities, provides customized energy solutions and is responsible for our limited international operations. See “Item 7. MD&A - Market Risk Sensitive Instruments” for information on risks associated with these activities.
Detail of Commercial’s operations can be found in the following sections:
• Generation - Fuel Supply and Emission Allowances - Describes Commercial’s generation capacity, sources of fuel, and various cost recovery mechanisms;
• Portfolio Optimization - Describes Commercial’s efforts to optimize its non-regulated generation portfolio;
• Trading Operations and Risk Management - Describes Commercial’s energy marketing and trading activities in the United States and Canada;
• CG&E Electric Rate Stabilization Plan - Describes CG&E’s RSP as approved by the PUCO in 2004;
• Energy Services - Describes Commercial’s operations consulting services and its operation of a synthetic fuel production facility;
• International - Describes Commercial’s operations outside of the United States;
• Competition - Describes the key competitors to Commercial’s various business operations; and
• Revenue Data and Customer Base - Describes the primary revenue sources for the various business operations of Commercial.
Generation - Fuel Supply and Emission Allowances
As of December 31, 2005, the total winter electric capacity (including our portion of the total capacity for the jointly-owned plants) of Commercial’s domestic generating plants was 6,276 MW. Approximately 67 percent of this generation portfolio is coal-fired. See “Item 2. Properties” for further discussion of the generating facilities.
Each year CG&E purchases over 10 million tons of coal to generate electricity, primarily from mines located in Indiana, West Virginia, Ohio, Kentucky, Pennsylvania, Illinois, Wyoming, and Colorado. In 2005 CG&E began purchasing low-sulfur coal produced in Wyoming’s Powder River Basin to reduce fuel costs and further reduce sulfur dioxide emissions compared to other coal sources. The price of coal has increased significantly in 2005 and 2004 as compared to prior years. Contributing to the rise in the price of coal are (1) increases in demand for electricity, (2) high and volatile gas prices and limited gas supply, which has increased reliance on coal-fired generation, (3) environmental regulation, and (4) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, we have a general practice to procure a substantial portion of coal through fixed-price contracts of varying length. We hold fixed-price contracts that will source substantially all of our expected 2006 coal requirements. We evaluate the appropriate amount of contract coal and length of contracts based on market conditions, including pricing trends, volatility and supplier reliability. See “Contractual Cash Obligations” in “Item 7. MD&A - Liquidity and Capital Resources” for further detail on CG&E’s total commitment under fixed-price coal contracts.
Commercial has natural gas-fired peaking plants that have a capacity of 1,766 MW. The fuel for these units is primarily obtained through the natural gas spot market as it is difficult to forecast the natural gas requirements for these plants. For further information on the risk of purchasing natural gas, see “Item 7. MD&A - Market Risk Sensitive Instruments.”
Commercial monitors alternative sources of coal and natural gas to assure a continuing availability of economical fuel supplies. As such, it will maintain its practice of purchasing a portion of coal and natural gas requirements on the open market and will continue to investigate least-cost coal options to comply with new and existing environmental requirements. Cinergy and CG&E believe that they can continue to obtain enough coal and natural gas to meet future needs. However, future environmental requirements may significantly impact the availability and price of these fuels.
At times, Commercial purchases power to meet the energy needs of its customers. Factors that could cause Commercial to purchase power for its customers include generating plant outages, extreme weather conditions, summer reliability, growth, and price. We believe we can obtain enough purchased power to meet future needs. However, during periods of excessive demand, the price and availability of these purchases may be significantly impacted.
Commercial emits SO2 and NOX in the generation of electricity and maintains emission allowances to offset their emissions in order to comply with SO2 and NOX emission reduction requirements. In 2005, the average market prices of SO2 allowances rose more than 100 percent from 2004 and more than 400 percent from 2003. Cinergy is continually evaluating market conditions and managing our overall cost structure through the addition of pollution control equipment, where economically feasible, and the use of emission allowance markets to help manage our emissions costs.
Under CG&E’s RSP, retail fuel and emission allowance costs are recovered through a cost recovery mechanism that recovers costs that exceed the amount originally included in the rates frozen in CG&E’s earlier transition plan. CG&E will recover retail fuel and emission allowance costs consumed in serving retail load and collect a Provider of Last Resort (POLR) charge from non-residential customers from 2005 through 2008 and from residential customers from 2006 through 2008. See “CG&E Electric Rate Stabilization Plan” as previously discussed.
The KPSC has approved a long-term electric supply plan for ULH&P that will replace the current contract with CG&E. Under this new plan, CG&E transferred ownership of approximately 1,100 MWs of electric generating capacity to ULH&P in January 2006, which was previously part of CG&E’s capacity used to service ULH&P under the previous power supply contract. The assets were acquired at net book value.
Portfolio Optimization
Commercial attempts to optimize the value of its non-regulated generation portfolio, which includes generation assets (power and capacity), fuel, and emission allowances. The portfolio is managed through a mix of real-time and forward sales of power and the corresponding purchase of fuel (primarily coal) and emission allowances.
When power is sold forward, we typically purchase the fuel and emission allowances required to produce the power, thereby locking in our eventual margin at the time of delivery. The market values of these commodities change independently over time. At times, the value of the fuel and emission allowances becomes greater than that of the output of electricity. In these instances, we will purchase forward power to be used to deliver against forward power sales, and in turn sell the fuel and/or emission allowances.
Emission allowances and the majority of fuel contracts typically follow the accrual method of accounting. However, generally accepted accounting principles (GAAP) requires that certain forward purchases of coal and forward sales of power (those classified as derivatives) use the mark-to-market (MTM) method of accounting. This differing accounting treatment for the various components of the generation portfolio can lead to volatility in reported earnings. Based on projected generation, we have sufficient fuel and emission allowances to meet our
non-retail forward power sales commitments over the next several years, and we will continue to evaluate and optimize our generation resources to produce the best economic returns for these assets.
Trading Operations and Risk Management
Commercial’s energy marketing and trading activities principally consist of Marketing & Trading’s natural gas marketing and trading operations and CG&E’s power marketing and trading operations.
Our domestic operations market and trade over-the-counter (an informal market where the buying/selling of commodities occurs) contracts for the purchase and sale of electricity, natural gas, and other energy-related products, including coal and emission allowances. Our natural gas domestic operations provide services that manage storage, transportation, gathering, and processing activities. In addition, our domestic operations also market and trade natural gas and other energy-related products on the New York Mercantile Exchange.
Marketing & Trading’s natural gas marketing and trading operations also extend to Canada where natural gas marketing and management services are provided to producers and industrial customers. Our Canadian operations also sell and purchase natural gas at wholesale and engage in the trading of derivative commodity instruments.
Marketing & Trading also enters into contracts to store natural gas and deliver in future periods with higher prices (typically winter). These contracts follow the accrual method of accounting, however, the derivative contracts hedging the gas are required, under GAAP, to be accounted for under the MTM method of accounting. These differing accounting treatments can lead to volatility in reported earnings.
See “Item 7. MD&A - Market Risk Sensitive Instruments” for information on risks associated with these activities.
CG&E Electric Rate Stabilization Plan
CG&E operates under a RSP which was approved by the PUCO in November 2004, and which expires December 31, 2008. The major features of the RSP are as follows:
• POLR Charge: CG&E collects a POLR charge from non-residential customers effective January 1, 2005, and from residential customers effective January 1, 2006. The POLR charge consists of the following discrete charges:
• Annually Adjusted Component - intended to provide cost recovery primarily for environmental compliance expenditures. Approximately $16 million was collected in 2005 and approximately $54 million is anticipated for 2006 collections.
• Infrastructure Maintenance Fund Charge - intended to compensate CG&E for committing its physical capacity. Approximately $20 million was collected in 2005 and approximately $33 million is anticipated for 2006.
• System Reliability Tracker - intended to provide actual cost recovery for capacity purchases, purchased power, reserve capacity, and related market costs for purchases to meet capacity needs.
• Generation Rates and Fuel Recovery: A market rate has been established for generation service. A component of the market rate is a fuel cost recovery mechanism that is adjusted quarterly for fuel, emission allowances, and certain purchased power costs, that exceed the amount originally included in the rates frozen in the CG&E transition plan. These new rates were applied to non-residential customers beginning January 1, 2005 and to residential customers beginning January 1, 2006. See “CG&E Electric Rate Filing” in “Item 7. MD&A - Future Expectations/Trends” for more information.
• Transmission Cost Recovery: A transmission cost recovery mechanism was established beginning January 1, 2005 for non-residential customers and beginning January 1, 2006 for residential customers. The transmission cost recovery mechanism is designed to permit CG&E to recover Midwest ISO charges, all FERC approved transmission costs, and all congestion costs allocable to retail ratepayers that are provided service by CG&E.
Energy Services
Commercial, through Cinergy Solutions Holding Company, Inc., is an on-site energy solutions and utility services provider. Primarily through joint ventures, we provide utility systems construction, operation and maintenance of utility facilities, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of usable energy from a single fuel source.
Commercial, through Cinergy Capital & Trading, Inc. (Capital & Trading), owns coal-based synthetic fuel production facilities which convert coal feedstock into synthetic fuel for sale to third parties. As of December 31, 2005, Cinergy has produced and sold approximately 12 million tons of synthetic fuel at these facilities. The synthetic fuel produced at these facilities qualifies for tax credits (through 2007) in accordance with the Internal Revenue Code Section 29/45K if certain requirements are satisfied. The three key requirements are that (a) the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel, (b) the fuel produced is sold to an unrelated entity and (c) the fuel was produced from a facility that was placed in service before July 1, 1998. For further information on the tax credit qualifications see “Synthetic Fuel Production” in “Future Expectations/Trends.”
International
As of December 31, 2005, we had minority ownership interests in (1) a generation asset located in Kenya capable of producing approximately 18 MW of electricity and 460 MW equivalents of steam; and (2) approximately 1,200 miles of gas and electric transmission and distribution systems through jointly-owned investments in Greece and Zambia, through which we serve approximately 8,500 transmission and distribution customers. These assets serve retail and wholesale customers by providing utility services including generation of electricity and heat as well as the distribution of gas and electric commodities.
Competition
Commercial primarily competes for wholesale contracts for the purchase and sale of electricity and natural gas. Commercial’s main competitors include public utilities, power and natural gas marketers and traders, and independent power producers.
Revenue Data and Customer Base
Commercial primarily recognizes revenues from generation provided to customers in CG&E’s service territory who have not switched to an alternative generation supplier under Ohio’s electric deregulation market. While generation rates remained frozen for residential customers in 2005, non-residential customers began paying generation rates and charges established in CG&E’s RSP. Under the RSP, CG&E’s non-residential retail customers that choose to receive their electric generation from another certified supplier may avoid CG&E generation and fuel charges, as well as a number of the discrete riders that comprise its POLR charge. The percentage of customers switching to other electric suppliers and the related volume by customer class was as follows:
(1) Represents the summation of each switched customer’s peak demand during the past year.
(2) Megawatt hours (MWhs) are total CG&E MWhs transported for all customers.
(3) The residential switching percentage is based on annual energy consumption and the non-residential switching percentages are based on average monthly peak demand. The decreases in switching percentages represent returning customers.
Commercial’s operating revenue is also derived by selling excess generation to wholesale customers in the midwest region of the United States. In addition, Commercial markets and trades electricity and natural gas primarily to customers across the United States. The majority of these customers are public utilities, power and natural gas marketers and traders, and independent power producers.
Energy services operating revenues are derived primarily by providing steam, electricity, and operation and maintenance services to large industrial customers.
No single Commercial customer provides more than 10 percent of total operating revenues.
Power Technology and Infrastructure
Power Technology and Infrastructure primarily manages Cinergy Ventures, LLC (Ventures), Cinergy’s venture capital subsidiary. Ventures identifies, invests in, and integrates new energy technologies into Cinergy’s existing businesses, focused primarily on operational efficiencies and clean energy technologies. In addition, Power Technology and Infrastructure manages our investments in other energy infrastructure and telecommunication service providers, including offering broadband over power line services.
MIDWEST ISO
The Midwest ISO is a regional transmission organization established in 1998 as a non-profit organization which maintains functional control over the combined transmission systems of its members, including Cinergy. In March 2004, the Midwest ISO filed with the FERC proposed changes to its existing transmission tariff to add terms and conditions to implement a centralized economic dispatch platform supported by a Day-Ahead and Real-Time Energy Market design, including LMP and Financial Transmission Rights (FTRs) (Energy Markets Tariff). The FERC has issued orders that, among other things, approved the start-up of the Energy Markets Tariff which occurred April 1, 2005. The FERC issued orders in response to requests for rehearing on certain matters in the FERC’s original orders. Cinergy has appealed the FERC orders to a Federal appeals court.
Specifically, the Energy Markets Tariff manages system reliability through the use of a market-based congestion management system and includes a centralized dispatch platform, the intent of which is to dispatch the most economic resources to meet load requirements reliably and efficiently in the Midwest ISO region, which covers a large portion of 15 midwestern states and one Canadian province. The Energy Markets Tariff uses LMP (i.e., the energy price for the next MW may vary throughout the Midwest ISO market based on transmission congestion and energy losses), and the allocation or auction of FTRs, which are instruments that hedge against congestion costs occurring in the Day-Ahead market. The Energy Markets Tariff also includes market monitoring and mitigation measures as well as a resource adequacy proposal, that proposes both an interim solution for participants providing and having access to adequate generation resources and a proposal to develop a long-term solution to resource adequacy concerns. The Midwest ISO performs a day-ahead unit commitment and dispatch forecast for all resources in its market and also performs the real-time resource dispatch for resources under its control on a five minute basis. CG&E and PSI are recovering costs that they incur related to the Energy Markets Tariff through various cost recovery mechanisms. ULH&P is currently under a rate freeze and cannot recover incremental costs attributable to its participation in the Midwest ISO in 2006; however, ULH&P is under an order from the KPSC to file a rate case in 2006 and will request, among other things, recovery of Midwest ISO related costs beginning in January 2007. We continue to work with the Midwest ISO to monitor the implementation of the new market and at this time we do not believe it will have a material impact on our results of operations or financial position.
EMPLOYEES
We have collective bargaining agreements with the International Brotherhood of Electrical Workers (IBEW), the United Steelworkers of America (USWA), the Utility Workers Union of America (UWUA), and various international union organizations.
The following table indicates the number of employees by classification at January 31, 2006:
(1) IBEW #1347 contract will expire on April 1, 2006, IBEW #1393 contract expired on April 30, 2005 and was renegotiated and is now set to expire on April 30, 2010 and IBEW #352 contract expired on February 5, 2005 and was renegotiated and is now set to expire on February 5, 2008.
(2) USWA #12049 and #5541-06 contracts will expire on May 15, 2007.
(3) UWUA, IUU Local 600 Contract expired on March 31, 2005 and was replaced with a new contract set to expire on April 1, 2008.
(4) CG&E and subsidiaries excluding ULH&P.
(5) Includes 2,990 Services’ employees who provide services to our operating utilities and other non-regulated companies. In conjunction with the pending merger, there is an anticipated reduction of approximately 1,500 employees of the combined company’s approximate 29,350 employees, as of the May 2005 merger announcement, in various departments leading up to and following consummation of the merger.
ENVIRONMENTAL MATTERS
Cinergy is currently affected by several different issues which involve compliance with federal and state regulations regarding the protection of the environment including, but not limited to, reductions in mercury, NOX, and SO2 emissions. Cinergy is able to recover certain costs of this environmental compliance through various trackers set up with Cinergy’s respective state regulatory agencies. In 2005, the Environmental Protection Agency (EPA) issued the Clean Air Interstate Rule and the Clean Air Mercury Rule, which will require additional environmental compliance costs. See the “Environmental Issues” section in “Item 7. MD&A - Liquidity and Capital Resources” for a discussion of these environmental issues and the estimated capital expenditures.
FUTURE EXPECTATIONS/TRENDS
See the information appearing under the same caption in “Item 7. MD&A - Future Expectations/Trends” for the following discussions:
• Regulatory Outlook and Significant Rate Developments;
• FERC;
• Gas Industry; and
• Other Matters.
RISK FACTORS
ITEM 1A.
ITEM 1A. RISK FACTORS
RISK FACTORS
The risk factors described below should be carefully considered.
Risks Relating to Our Business
Our Regulated’s revenues, earnings, and results are dependent on state legislation and regulation that affect electric generation, distribution, and related activities, which may limit our ability to recover costs.
Our Regulated business unit is regulated on a cost-of-service/rate-of-return basis subject to the statutes and regulatory commission rules and procedures of Kentucky, Indiana, and Ohio. If our earnings exceed the returns established by our state regulatory commissions, our retail electric rates may be subject to review by the commissions and possible reduction, which may decrease our future earnings.
Our sales may decrease if we are unable to gain adequate, reliable, and affordable access to transmission and distribution assets.
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we sell to the wholesale market, as well as the natural gas we purchase to supply to our gas customers. FERC’s power transmission regulations require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis; however, not all markets are as open and accessible as needed. If transmission is disrupted, or if transmission capacity is inadequate, our ability to sell and deliver products may be hindered. Such disruptions could also hinder our providing electricity or natural gas to our retail electric and gas customers and may materially adversely affect our business.
The different regional power markets have changing regulatory structures, which could affect our growth and performance in these regions. In addition, the independent system operators who oversee the transmission systems in regional power markets, such as California, have imposed in the past, and may impose in the future, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the profitability of our wholesale power marketing and trading business.
Competition in the unregulated markets in which we operate may adversely affect the growth and profitability of our business.
We may not be able to respond in a timely or effective manner to the many changes designed to increase competition in the electric industry. To the extent competitive pressures increase, the economics of our business may come under long-term pressure.
In addition, regulatory changes have been proposed to increase access to electricity transmission grids by utility and non-utility purchasers and sellers of electricity. These changes could continue the disaggregation of many vertically integrated utilities into separate generation, transmission, distribution, and retail businesses. As a result, a
significant number of additional competitors could become active in the wholesale power generation segment of our industry.
We may also face competition from new competitors that have greater financial resources than we do, seeking attractive opportunities to acquire or develop energy assets or energy trading operations in the United States. These new competitors may include sophisticated financial institutions, some of which are already entering the energy trading and marketing sector, and international energy players, which may enter regulated or unregulated energy businesses. This competition may adversely affect our ability to make investments or acquisitions.
We rely on access to short-term money markets and longer-term capital markets to finance our capital requirements and support our liquidity needs, and our access to those markets can be adversely affected by a number of conditions, many of which are beyond our control.
Our business is financed to a large degree through debt and the maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from our assets. Accordingly, we rely on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from our operations and to fund investments originally financed through debt instruments with disparate maturities. If we are not able to access capital at competitive rates, our ability to finance our operations and implement our strategy will be adversely affected.
Market disruptions may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include: economic downturns; the bankruptcy of an unrelated energy company; capital market conditions generally; market prices for electricity, gas, and natural gas liquids; terrorist attacks or threatened attacks on our facilities or unrelated energy companies; or the overall health of the energy industry. Restrictions on our ability to access financial markets may also affect our ability to execute our business plan as scheduled. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for future growth.
We maintain revolving credit facilities to provide back-up for commercial paper programs and/or letters of credit at various entities. These facilities typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital for the specific entity. Failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility and could require other of our affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements.
We will be exposed to market risk and may incur losses from the trading operations and/or activities we take to mitigate our commodity exposure.
We have trading operations that primarily consist of contracts to buy and sell commodities, including contracts for electricity, natural gas, and other commodities that are settled by the delivery of the commodity or cash. Our trading portfolios also include financial derivatives, including swaps, futures, and options. If the values of these contracts or derivatives change in a direction or manner that we do not anticipate, we could realize material losses from our trading activities.
In order to manage our financial exposure related to commodity price fluctuations, primarily with respect to power and natural gas, coal, and emission allowances, our risk management operations routinely enter into contracts to hedge the value of our assets and operations, including fixed-price, forward, physical purchase and sales contracts, futures, financial swaps, and option contracts traded in over-the-counter markets or on exchanges.
Our risk management systems, however, may not always be implemented properly or may not always function as planned. In particular, if prices of commodities significantly deviate from historical prices or if the price volatility or distribution of those changes deviates from historical norms, our risk management systems may not protect us from significant losses. To the extent we have unhedged positions or our hedging strategies do not work as planned, fluctuating commodity prices could cause our sales, purchases, and net income to be volatile. In
addition, certain types of economic hedging activity may not qualify for hedge accounting under generally accepted accounting principles, resulting in increased volatility in net income.
We are exposed to credit risk of counterparties with whom we do business.
Adverse economic conditions affecting, or financial difficulties of, counterparties we do business with could impair the ability of these counterparties to pay for our services or fulfill their contractual obligations, or cause them to delay such payments or obligations. We depend on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect our cash flows, financial condition, or results of operations.
Poor investment performance of pension plan holdings and other factors impacting pension plan costs could unfavorably impact our liquidity and results of operations.
Our costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and our required or voluntary contributions made to the plans. While we comply with the funding requirements under the Employee Retirement Income Security Act of 1974, as of September 30, 2005, the latest valuation date for our pension plan obligations exceeded the value of plan assets by approximately $582 million. See “Pension and Other Postretirement Benefits” in “Item 7. MD&A - Liquidity and Capital Resources” and Note 11 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information. Without sustained growth in the pension investments over time to increase the value of our plan assets and depending upon the other factors impacting our costs as listed above, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material impact on our liquidity by reducing our cash flows and could negatively affect our results of operations.
Under Cinergy’s holding company structure, the payment of dividends to shareholders is subject to the ability of its subsidiaries to pay dividends to it.
Cinergy is a holding company with no material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Cinergy’s ability to pay dividends on its common stock will depend on the payment to it of dividends by its operating subsidiaries. These subsidiaries’ payments of dividends, in turn, depend on their results of operations, cash flows, and federal and state regulatory constraints. In addition, until consummation or termination of the merger with Duke, Cinergy is prohibited from paying dividends in excess of its historical levels without the prior consent of Duke.
We could incur a significant tax liability and our results of operations and cash flows may be negatively affected if the Internal Revenue Service denies or otherwise makes unusable certain tax credits related to our coal and synthetic fuel business or if such credits are phased out based on crude oil prices.
Cinergy’s sale of synthetic fuel intended to qualify for tax credits in accordance with Section 29/45K of the Internal Revenue Code has generated $339 million in tax credits through December 31, 2005. The Internal Revenue Service (IRS) is currently auditing Cinergy for the 2002, 2003 and 2004 tax years. If the IRS were to successfully challenge Cinergy’s Section 29/45K tax credits related to synthetic fuel, and such challenges are successful, this could result in the disallowance of up to all $339 million in previously claimed Section 29/45K tax credits and a loss of our ability to claim future Section 29/45K tax credits for synthetic fuel produced by such facilities.
Section 29/45K also provides for a phase-out of the credit based on the average price of crude oil during a calendar year. The phase-out is based on a prescribed calculation and definition of crude oil prices. Based on current
estimates of crude oil prices and the recent volatility of such prices, we believe that for 2006 and 2007 the amount of the tax credits could be reduced.
We are currently involved in litigation with the United States and several states and environmental groups regarding certain environmental matters.
Cinergy is currently involved in litigation in which the Environmental Protection Agency (EPA) is alleging various violations of the Clean Air Act (CAA). Specifically, the lawsuit against Cinergy alleges that Cinergy violated the CAA by not obtaining permits for various projects at its owned and co-owned generating stations. Additionally, the Cinergy suit claims that Cinergy violated an Administrative Consent Order entered into in 1998 between the EPA and Cinergy relating to alleged violations of Ohio’s state implementation plan provisions governing particulate matter at one of its generating stations. Three northeast states and two environmental groups have intervened in the Cinergy case. In August 2005, the district court issued a ruling regarding the emissions test that it will apply to Cinergy at the trial of the case. Contrary to Cinergy’s argument, the district court ruled that in determining whether a project was projected to increase annual emissions, it would not hold hours of operation constant. However, the district court subsequently certified the matter for interlocutory appeal to the Seventh Circuit Court of Appeals, which has accepted the appeal and set a briefing schedule. As a result, the district court has removed the trial from the calendar and will reset a trial date, if necessary, after the Seventh Circuit rules. There are a number of other legal issues currently before the district court judge, and the case is currently in discovery. A second lawsuit being defended by one of Cinergy’s co-owners involves similar allegations and is also pending.
We are subject to numerous environmental laws and regulations that require significant capital expenditures, increase our cost of operations, and which may impact or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions (such as controlling greenhouse-gas emissions), water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations, and litigation may arise the outcome of which we cannot predict.
For example, the EPA recently issued the Clean Air Interstate Rule, formerly the Interstate Air Quality Rule, which requires reductions in SO2 and NOX emissions in order to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards and established a two-phase, regional cap and trade program for SO2 and NOX and issued the Clean Air Mercury Rule, which requires reductions in mercury emissions from coal-fired power plants through a similar two phase cap and trade program. Over the 2006-2010 time period, Cinergy expects to spend approximately $1.4 billion to reduce mercury, SO2, and NOX emissions. These projected expenditures include estimated costs to comply at plants that we own but do not operate and could change when taking into consideration compliance plans of co-owners or operators involved. Although we believe that we are legally entitled to recover these costs, if we cannot recover these costs in a timely manner, or in an amount sufficient to cover our actual costs, our financial conditions and results of operations could be materially and adversely impacted. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.
Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect our financial condition, results of operations, or cash flows and our utilities’ businesses.
Increased competition resulting from deregulation or restructuring efforts, including from the recently enacted Energy Policy Act of 2005, could have a significant adverse financial impact on us and our utility subsidiaries and consequently on our results of operations and cash flows. Increased competition could also result in increased pressure to lower costs, including the cost of electricity. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on us and our subsidiaries due to an impairment of assets, a loss of retail customers, lower profit margins, or increased costs of capital. We cannot predict the extent and timing of entry by additional competitors into the electric markets. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial condition, results of operations, or cash flows.
Ohio has enacted electric generation deregulation legislation. Our Ohio residential and non-residential customers are served under a recently approved RSP, that runs through December 31, 2008. At this time, it is difficult to predict how the regulatory environment will look after the RSP ends.
Efforts associated with completing the merger with Duke are complex and may divert management’s focus and resources from other strategic opportunities.
The pending merger between Duke and Cinergy presents significant challenges. The integration of the two companies will be complex and time-consuming, due to the size and complexity of each organization. The principal challenges will be integrating the combined regulated electric utility operations and combining the unregulated wholesale power generation businesses. All of these businesses are complex, and some of the business units are dispersed. Such efforts could also divert management’s focus and resources from other strategic opportunities during the integration process.
Risks Related to the Industry
Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities, all of which are beyond our control.
Sustained downturns or sluggishness in the economy generally affect the markets in which we operate and negatively influence our energy operations. Declines in demand for electricity and gas as a result of economic downturns in our franchised electric and gas service territories will reduce overall electricity and gas sales and lessen our cash flows, especially as our industrial customers reduce production and, therefore, consumption of electricity and gas. Although Regulated’s business is subject to regulated allowable rates of return and recovery of fuel and emission allowance costs, and our gas transmission business is subject to mandated tariff rates, overall declines in electricity sold or the volume of gas shipped as a result of economic downturn or recession could reduce revenues and cash flows, thus diminishing results of operations.
We also sell electricity into the wholesale market under both short-term and long-term contracts and enter into contracts to purchase and sell electricity, natural gas, and natural gas liquids as part of our energy marketing and trading operations. With respect to such transactions, we are not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power, natural gas, coal, and emission allowances in our regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time and could reduce our revenues and margins and thereby diminish our results of operations.
Lower demand for the electricity we sell and varying prices for electricity, natural gas, coal, and emission allowances result from multiple factors that affect the markets where we sell electricity including:
• weather conditions, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively;
• supply of and demand for energy commodities;
• illiquid markets including reductions in trading volumes, which result in lower revenues and earnings;
• general economic conditions which impact energy consumption particularly in which sales to industrial or large commercial customers comprise a significant portion of total sales;
• transmission or transportation constraints or inefficiencies, which impact our merchant energy operations;
• availability of competitively-priced alternative energy sources, which are preferred by some customers over electricity produced from coal or gas plants, and of energy-efficient equipment which reduces energy demand;
• electric generation capacity surpluses which cause our merchant energy plants to generate and sell less electricity at lower prices and may cause some plants to become non-economical to operate;
• capacity and transmission service into, or out of, our markets;
• natural disasters, acts of terrorism, wars, embargoes, and other catastrophic events to the extent they affect our operations and markets; and
• federal and state energy and environmental regulation and legislation.
Our business is subject to extensive regulation that will affect our operations and costs.
We are subject to regulation by FERC, by federal, state, and local authorities under environmental laws and by state public utility commissions under laws regulating our businesses. Regulation affects almost every aspect of our businesses, including, among other things, our ability to: take fundamental business management actions; determine the terms and rates of our transmission and distribution businesses’ services; make acquisitions; issue equity or debt securities; engage in transactions between our utilities and other subsidiaries and affiliates; and pay dividends. Changes to these regulations are ongoing, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on our business. However,
changes in regulation (including re-regulating previously deregulated markets) can cause delays in or affect business planning and transactions and can substantially increase our costs.
Certain events in the energy markets beyond our control have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets which could have a negative impact on our financial condition or results of operations or access to capital.
Due to certain events in the energy markets, regulated energy companies have been under increased scrutiny by regulatory bodies, capital markets, and credit rating agencies. This increased scrutiny could lead to substantial changes in laws and regulations affecting us, including new accounting standards that could change the way we are required to record revenues, expenses, assets, and liabilities. These types of regulations could have a negative impact on our financial condition or results of operations or access to capital.
Potential terrorist activities or military or other actions could adversely affect our business.
The continued threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic, and financial market instability and volatility in prices for natural gas and oil which could affect the market for our gas operations and may materially adversely affect us in ways we cannot predict at this time. In addition, future acts of terrorism and any possible reprisals as a consequence of action by the United States and its allies could be directed against companies in our industry operating in the United States.
Increased environmental regulation and liabilities could subject us to significant compliance and remediation costs that adversely affect our results of operations.
Our operations are subject to extensive environmental regulation pursuant to a variety of United States, and other federal, provincial, state, and municipal laws and regulations. Such environmental regulation imposes, among other things, restrictions, liabilities, obligations, and potential enforcement in connection with the generation, handling, use, storage, transportation, treatment, and disposal of hazardous substances and waste, and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that our facilities, sites, and other properties associated with our operations be operated, maintained, and reclaimed to the satisfaction of applicable regulatory authorities.
Compliance with environmental regulations can require significant expenditures, including expenditures for cleanup costs and damages arising out of contaminated properties, and failure to comply with environmental regulations may result in the imposition of fines and penalties. The steps we take to ensure our facilities are in compliance could be prohibitively expensive, and we may be required to shut down or alter the operation of our facilities, which may cause us to incur losses. Further, our regulatory rate structure and our contracts with clients may not necessarily allow us to recover capital costs we incur to comply with new environmental regulations. Also, we may not be able to obtain or maintain, from time to time, all required environmental regulatory approvals for our development projects. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain and comply with them, or if environmental regulations change and become more stringent, the operation of our facilities or the development of new facilities could be prevented, delayed, or become subject to additional costs. Should we fail to comply with all applicable environmental laws, we may be subject to penalties and fines imposed against us by regulatory authorities. Although it is not expected that the costs of complying with current environmental regulations will have a material adverse effect on our financial condition or results of operations, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect.
In addition, we are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of our power generation facilities and natural gas assets which we have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with some acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against some environmental liabilities. If we incur a material liability, or the other party to a transaction fails to meet its indemnification obligations to us, we could suffer material losses.
UNRESOLVED STAFF COMMENTS
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
PROPERTIES
ITEM 2.
ITEM 2. PROPERTIES
REGULATED
Electric
Domestic Power Generation
Regulated’s domestic power generating stations’ total capacity, reflected in MW’s, as of December 31, 2005, is shown in the table that follows. The electric generating plants are located in Indiana and Ohio and are wholly-owned or jointly-owned facilities.
(1) This table includes only our portion of the total capacity for the jointly-owned plants and does not include certain generating capacity transferred from CG&E to ULH&P in January 2006 as discussed in “Electric Industry - Kentucky” in “Item 7. MD&A - Future Expectations/Trends.” The transferred generating assets became Regulated assets upon transfer.
During 2005, Regulated’s electric generating plants, including those that we own but do not operate, performed reliably, as evidenced by our annual capacity factor of 75 percent and a utilization factor of 86 percent (excluding natural gas and fuel oil peaking stations) and an equivalent availability factor of 88 percent. A capacity factor is a percentage that indicates how much of a power plant’s capacity is used over time. A utilization factor is a percentage that indicates how much of a power plant’s capacity is used while being available. An equivalent availability factor is a percentage that indicates how much of a unit is available to generate compared to its potential maximum generation.
Below is a geographical map showing the locations of Regulated’s generation plants.
(1) This map does not include certain generating assets that were transferred from CG&E to ULH&P in January 2006 as discussed in “Electric Industry - Kentucky” in “Item 7. MD&A - Future Expectations/Trends.”
Transmission and Distribution
Relevant information for our utility operating companies’ electric transmission and distribution systems located in Ohio, Kentucky, and Indiana is as follows:
(1) Circuit Miles include only our proportionate share for the jointly-owned lines.
(2) Kilovolt-amperes (1,000 volt-amperes) are a broad measure of our substation transformer capacity.
(3) Prior to 2005, PSI did not include secondary lines as part of their Distribution System Circuit Miles. As of December 31, 2005, 8,317 circuit miles of secondary lines were included consistent with other registrants.
At the end of 2005, our utility operating companies’ electric systems were interconnected with 14 other utilities. Our electric transmission and distribution systems are designed and constructed to further the goal of providing reliable service to our customers. Every effort is made to ensure that sufficient facilities are in service to meet this goal without installing facilities beyond what is required to operate reliably and within the designed parameters. Through our ongoing review of these systems, enhancements are developed and constructed to meet our planning, loading, and reliability guidelines. This process allows us to prudently invest in capacity additions only when and where they are required. The Midwest ISO holds functional control of Regulated’s transmission systems.
Gas
As of December 31, 2005, the natural gas transmission and distribution systems of Cinergy and CG&E and its subsidiaries had approximately 10,062 miles of mains and service lines located in southwestern Ohio and northern Kentucky. Cinergy and CG&E and its subsidiaries also jointly own three underground caverns with a total storage capacity of approximately 23 million gallons of liquid propane (of which 18.7 million gallons belong to CG&E, including 7.5 million gallons belonging to ULH&P). As of December 31, 2005, Cinergy had 15.1 million gallons of liquid propane in storage (of which 12.4 million gallons belong to CG&E, including 5.4 million gallons belonging to ULH&P). This liquid propane is used in the three propane/air peak shaving plants located in Ohio and Kentucky. Propane/air peak shaving plants store propane and, when needed, vaporize the propane and mix with natural gas to supplement the natural gas supply during peak demand periods and emergencies.
COMMERCIAL
Electric
Domestic Power Generation
Commercial’s domestic power generating stations’ total electric capacity, reflected in MW, as of December 31, 2005, is shown in the table that follows. Commercial’s electric generating plants are primarily located in Ohio and Kentucky and are wholly-owned or jointly-owned facilities.
(1) This table includes only our portion of the total capacity for the jointly-owned plants. The table also includes certain generating capacity transferred from CG&E to ULH&P in January 2006 as discussed in “Electric Industry - Kentucky” in “Item 7. MD&A - Future Expectations/Trends.” The transferred generating assets became Regulated assets upon transfer.
(2) Represents natural gas peaking plants located in Tennessee and Mississippi, owned by Investments, that sell electricity on the wholesale market.
During 2005, Commercial’s electric generating plants, including those that we own but do not operate, performed reliably, as evidenced by our annual capacity factor of 72 percent and a utilization factor of 86 percent (excluding natural gas and fuel oil peaking stations) and an equivalent availability factor of 85 percent. A capacity factor is a percentage that indicates how much of a power plant’s capacity is used over time. A utilization factor is a percentage that indicates how much of a power plant’s capacity is used while being available. An equivalent availability factor is a percentage that indicates how much of a unit is available to generate compared to its potential maximum generation.
Below is a geographical map showing the locations of Commercial’s generation plants.
(1)
Commercial’s generation plant not included in the map is located in Caledonia, Mississippi.
(2)
All of Woodsdale and East Bend and a portion of Miami Fort (163 MW) were transferred to Regulated in January 2006. See “Electric Industry - Kentucky” in “Item 7. MD&A - Future Expectations/Trends.”
Cogeneration
As of December 31, 2005, Cinergy had ownership interests in and/or operated 28 domestic cogeneration facilities capable of producing 5,335 MW of electricity, 4,117 MW equivalents of steam and 297 MW equivalents of chilled water. Cogeneration is the simultaneous production of two or more forms of useable energy from a single fuel source.
Synthetic Fuel
Capital & Trading owns two coal-based synthetic fuel production facilities, which convert coal into synthetic fuel for sale to a third party. See “Other Matters - Synthetic Fuel Production” in “Item 7. MD&A - Future Expectations/Trends” for additional information regarding this business initiative.
International
As of December 31, 2005, we had minority ownership interests in (1) a generation asset located in Kenya capable of producing approximately 18 MW of electricity and 460 MW equivalents of steam; and (2) approximately 1,200 miles of gas and electric transmission and distribution systems through jointly-owned investments in Greece and Zambia, through which we serve approximately 8,500 transmission and distribution customers. These assets serve retail and wholesale customers by providing utility services including generation of electricity and heat as well as the distribution of gas and electric commodities.
PEAK LOAD
In July 2005, we experienced record peak loads of 12,001 MW, 5,607 MW, and 6,409 MW for Cinergy, CG&E, and PSI, respectively.
LEGAL PROCEEDINGS
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
CLEAN AIR ACT LAWSUIT
In November 1999, and through subsequent amendments, the United States brought a lawsuit in the United States Federal District Court for the Southern District of Indiana against Cinergy, CG&E, and PSI alleging various violations of the CAA. Specifically, the lawsuit alleges that we violated the CAA by not obtaining Prevention of Significant Deterioration (PSD), Non-Attainment New Source Review (NSR), and Ohio and Indiana State Implementation Plan (SIP) permits for various projects at our owned and co-owned generating stations. Additionally, the suit claims that we violated an Administrative Consent Order entered into in 1998 between the EPA and Cinergy relating to alleged violations of Ohio’s SIP provisions governing particulate matter at Unit 1 at CG&E’s W.C. Beckjord Station. The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s W.C. Beckjord and Miami Fort Stations, and PSI’s Cayuga, Gallagher, Wabash River, and Gibson Stations, and (2) civil penalties in amounts of up to $27,500 per day for each violation. In addition, three northeast states and two environmental groups have intervened in the case. In August 2005, the district court issued a ruling regarding the emissions test that it will apply to Cinergy at the trial of the case. Contrary to Cinergy’s argument, the district court ruled that in determining whether a project was projected to increase annual emissions, it would not hold hours of operation constant. However, the district court subsequently certified the matter for interlocutory appeal to the Seventh Circuit Court of Appeals, which has accepted the appeal and set oral arguments for May 2006. In February 2006, the district court ruled that in carrying its burden of proof, the defendant can look to industry practice in proving a particular project was routine. The district court has removed the trial from the calendar and will reset a trial date, if necessary, after the Seventh Circuit rules. Not withstanding the appeal, there are a number of other legal issues currently before the district court judge.
In March 2000, the United States also filed in the United States District Court for the Southern District of Ohio an amended complaint in a separate lawsuit alleging violations of the CAA relating to PSD, NSR, and Ohio SIP requirements regarding various generating stations, including a generating station operated by Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company (DP&L), and CG&E. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP. In April 2001, the United States District Court for the Southern District of Ohio in that case ruled that the Government and the intervening plaintiff environmental groups cannot seek monetary damages for alleged violations that occurred prior to November 3, 1994; however, they are entitled to seek injunctive relief for such alleged violations. Neither party appealed that decision. This matter was heard in trial in July 2005. A decision is pending.
In addition, Cinergy and CG&E have been informed by DP&L that in June 2000, the EPA issued a Notice of Violation (NOV) to DP&L for alleged violations of PSD, NSR, and Ohio SIP requirements at a station operated by DP&L and jointly-owned by DP&L, CSP, and CG&E. The NOV indicated the EPA may (1) issue an order requiring compliance with the requirements of the Ohio SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. In September 2004, Marilyn Wall and the Sierra Club brought a lawsuit against CG&E, DP&L and CSP for alleged violations of the CAA at this same generating station. This case is currently in discovery in front of the same judge who has the CSP case.
We are unable to predict whether resolution of these matters would have a material effect on our financial position or results of operations. We intend to vigorously defend against these allegations.
CARBON DIOXIDE LAWSUIT
In July 2004, the states of Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin, and the City of New York brought a lawsuit in the United States District Court for the Southern District of New York against Cinergy, American Electric Power Company, Inc., American Electric Power Service Corporation, The Southern Company, Tennessee Valley Authority, and Xcel Energy Inc. That same day, a similar lawsuit was filed in the United States District Court for the Southern District of New York against the same companies by Open Space Institute, Inc., Open Space Conservancy, Inc., and The Audubon Society of New Hampshire. These lawsuits allege that the defendants’ emissions of CO2 from the combustion of fossil fuels at electric generating facilities contribute to global warming and amount to a public nuisance. The complaints also
allege that the defendants could generate the same amount of electricity while emitting significantly less CO2. The plaintiffs are seeking an injunction requiring each defendant to cap its CO2 emissions and then reduce them by a specified percentage each year for at least a decade. In September 2005, the district court granted the defendants’ motion to dismiss the lawsuit. The plaintiffs have appealed this ruling to the Second Circuit Court of Appeals. We are not able to predict whether resolution of these matters would have a material effect on our financial position or results of operations.
SELECTIVE CATALYTIC REDUCTION UNITS (SCR) AT GIBSON GENERATING STATION
In May 2004, SCRs and other pollution control equipment became operational at Units 4 and 5 of PSI’s Gibson Station in accordance with compliance deadlines under the NOX SIP Call. In June and July 2004, Gibson Station temporarily shut down the equipment on these units due to a concern that portions of the plume from those units’ stacks appeared to break apart and descend to ground level, at certain times, under certain weather conditions. After we developed a protocol with several other parties regarding the use of control equipment, one of the parties sought a court preliminary injunction to enforce the protocol. The court initially granted the preliminary injunction, but on appeal the preliminary injunction was dissolved and the case was dismissed.
In April 2005, we completed the installation of a permanent control system to address this issue. The new control system will support all five Gibson Station generating units. We will seek recovery of any related capital as well as increased emission allowance expenditures through the regulatory process. We do not believe costs related to resolving this matter will have a material impact on our financial position or results of operations.
ZIMMER GENERATING STATION (ZIMMER STATION) LAWSUIT
In November 2004, a citizen of the Village of Moscow, Ohio, the town adjacent to CG&E’s Zimmer Station, brought a purported class action in the United States District Court for the Southern District of Ohio seeking monetary damages and injunctive relief against CG&E for alleged violations of the CAA, the Ohio SIP, and Ohio laws against nuisance and common law nuisance. The plaintiffs have filed a number of additional notices of intent to sue and two lawsuits raising claims similar to those in the original claim. One lawsuit was dismissed on procedural grounds and the remaining two have been consolidated. The plaintiff filed a motion for class certification, which is fully briefed and pending decision. At this time, we cannot predict whether the outcome of this matter will have a material impact on our financial position or results of operations. We intend to defend this lawsuit vigorously in court.
MANUFACTURED GAS PLANT (MGP) SITES
Coal tar residues, related hydrocarbons, and various metals have been found in at least 22 sites that PSI or its predecessors previously owned and sold in a series of transactions with Northern Indiana Public Service Company (NIPSCO) and Indiana Gas Company, Inc. (IGC). The 22 sites are in the process of being studied and will be remediated, if necessary. In 1998 NIPSCO, IGC, and PSI entered into Site Participation and Cost Sharing Agreements to allocate liability and responsibilities between them. Thus far, PSI has primary responsibility for investigating, monitoring and, if necessary, remediating nine of these sites. In December 2003, PSI entered into a voluntary remediation plan with the state of Indiana, providing a formal framework for the investigation and cleanup of the nine sites. The Indiana Department of Environmental Management oversees investigation and cleanup of all of these sites.
In April 1998, PSI filed suit in Hendricks County in the state of Indiana against its general liability insurance carriers. PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims against PSI and compensate PSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites; or (2) pay PSI’s cost of defense. PSI settled, in principle, its claims with all but one of the insurance carriers in January 2005 prior to commencement of the trial. With respect to the lone insurance carrier, a jury returned a verdict against PSI in February 2005. PSI has appealed this decision. At the present time, PSI cannot predict the outcome of this litigation, including the outcome of the appeal.
PSI has accrued costs related to investigation, remediation, and groundwater monitoring for those sites where such costs are probable and can be reasonably estimated. We will continue to investigate and remediate the sites as outlined in the voluntary remediation plan. As additional facts become known and investigation is completed, we will assess whether the likelihood of incurring additional costs becomes probable. Until all investigation and
remediation is complete, we are unable to determine the overall impact on our financial position or results of operations.
CG&E and ULH&P have performed site assessments on certain of their sites where we believe MGP activities have occurred at some point in the past and have found no imminent risk to the environment. At the present time, CG&E and ULH&P cannot predict whether investigation and/or remediation will be required in the future at any of these sites.
ASBESTOS CLAIMS LITIGATION
PSI and CG&E have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 130 pending lawsuits (the majority of which are PSI cases). In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work as outside contractors in the construction and maintenance of CG&E and PSI generating stations. The plaintiffs further claim that as the property owner of the generating stations, CG&E and PSI should be held liable for their injuries and illnesses based on an alleged duty to warn and protect them from any asbestos exposure. The impact on CG&E’s and PSI’s financial position or results of operations of these cases to date has not been material.
Of these lawsuits, one case filed against PSI has been tried to verdict. The jury returned a verdict against PSI on a negligence claim and a verdict for PSI on punitive damages. PSI appealed this decision up to the Indiana Supreme Court. In October 2005, the Indiana Supreme Court upheld the jury’s verdict. PSI paid the judgment of approximately $630,000 in the fourth quarter. In addition, PSI has settled over 150 other claims for amounts, which neither individually nor in the aggregate, are material to PSI’s financial position or results of operations. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of PSI generating plants; (ii) the possible incidence of various illnesses among exposed workers, and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, PSI estimates that the range of reasonably possible exposure in existing and future suits over the next 50 years could range from an immaterial amount to approximately $60 million, exclusive of costs to defend these cases. This estimated range of exposure may change as additional settlements occur and claims are made in Indiana and more case law is established.
CG&E has been named in fewer than 10 cases and as a result has virtually no settlement history for asbestos cases. Thus, CG&E is not able to reasonably estimate the range of potential loss from current or future lawsuits. However, potential judgments or settlements of existing or future claims could be material to CG&E.
DUNAVAN WASTE SUPERFUND SITE
In July and October 2005, PSI received notices from the EPA that it has been identified as a de minimus potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act at the Dunavan Waste Oil Site in Oakwood, Vermilion County, Illinois. At this time, PSI does not have any further information regarding the scope of potential liability associated with this matter.
MERGER LAWSUIT
In May 2005, a purported shareholder class action was filed in the Court of Common Pleas in Hamilton County, Ohio against Cinergy and each of the members of the Board of Directors. The lawsuit alleged that the defendants breached their duties of due care and loyalty to shareholders by agreeing to the merger agreement between Duke and Cinergy and was seeking to either enjoin or amend the terms of the merger. Cinergy and the individual defendants filed a motion to dismiss this lawsuit in July 2005, which was granted in November of 2005. An appeal was not filed by the plaintiffs and the case is closed.
OHIO EPA PENALTY ON CINERGY POWER GENERATION SERVICES
In October 2005, the Ohio EPA proposed a civil penalty of $102,000 on Cinergy Power Generation Services to settle multiple, unrelated alleged violations occurring at multiple CG&E generating stations over the past several years. In December 2005, CG&E settled these allegations for an aggregate of $53,000.
ONTARIO, CANADA LAWSUIT
We understand through newspaper reports that a class action lawsuit was filed in Superior Court in Ontario, Canada against us and approximately 20 other utility and power generation companies alleging various claims relating to environmental emissions from coal-fired power generation facilities in the United States and Canada and damages of approximately $50 billion, with continuing damages in the amount of approximately $4 billion annually. We understand that the lawsuit also claims entitlement to punitive and exemplary damages in the amount of $1 billion. We have not yet been served in this lawsuit, however, if served, we intend to defend this lawsuit vigorously in court. We are not able to predict whether resolution of this matter would have a material effect on our financial position or results of operations.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders of Cinergy, The Cincinnati Gas & Electric Company, or PSI Energy, Inc. during the fourth quarter of 2005.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Cinergy Corp.’s common stock is listed on the New York Stock Exchange. The high and low stock prices for each quarter for the past two years are indicated below:
Cinergy Corp. holds all outstanding common stock of The Cincinnati Gas & Electric Company (CG&E) and PSI Energy, Inc. (PSI), and CG&E holds all of the common stock of The Union Light, Heat and Power Company (ULH&P). Therefore, no public trading market exists for the common stock of CG&E, PSI, and ULH&P.
As of January 31, 2006, Cinergy Corp. had 42,705 shareholders of record.
Cinergy Corp. declared dividends on its common stock of $.48 and $.47 per share for each quarter of 2005 and 2004, respectively. The quarterly dividends paid to Cinergy Corp. by CG&E and PSI, and to CG&E by ULH&P for the past two years were as follows:
On January 16, 2006, the Board of Directors of Cinergy Corp. declared dividends on its common stock of $.48 per share, payable February 15, 2006, to shareholders of record at the close of business on February 1, 2006.
See “Dividend Restrictions” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” for a brief description of the registrants’ common stock dividend restrictions.
The number of shares (or units) provided in the table below represent shares exchanged in connection with employee option exercises and shares purchased by the plan trustee on behalf of the 401(k) Excess Plan.
SELECTED FINANCIAL DATA
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(1)
The results of Cinergy also include amounts related to non-registrants.
(2)
See Note 16 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further explanation.
(3)
In 2005, Cinergy recognized a gain/(loss) on cumulative effect of a change in accounting principal of $(3) million (net of tax) as a result of the recognition of conditional asset retirement obligations. In 2003, Cinergy recognized a gain/(loss) on cumulative effect of changes in accounting principles of $39 million (net of tax) and $(13) million (net of tax) as a result of the reversal of accrued cost of removal for non-regulated generating assets and the change in accounting of certain energy related contracts from fair value to accrual. In 2002, Cinergy recognized a cumulative effect of a change in accounting principle of $(4) million (net of tax) as a result of an impairment charge for goodwill related to certain of our international assets.
(4)
In 2005, CG&E recognized a gain/(loss) on cumulative effect of a change in accounting principle of $(3) million (net of tax) as a result of the recognition of conditional asset retirement obligations. In 2003, CG&E recognized a gain/(loss) on cumulative effect of changes in accounting principles of $39 million (net of tax) and $(8) million (net of tax) as a result of the reversal of accrued cost of removal for non-regulated generating assets and the change in accounting of certain energy related contracts from fair value to accrual.
(5)
In 2003, PSI recognized a loss on cumulative effect of a change in accounting principle of $(1) million (net of tax) as a result of a change in accounting of certain energy related contracts from fair value to accrual.
MD&A - EXECUTIVE SUMMARY
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
In this report, Cinergy (which includes Cinergy Corp. and all of its regulated and non-regulated subsidiaries) is, at times, referred to in the first person as “we,” “our,” or “us.”
The following discussion should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this report. We have reclassified certain prior-year amounts in the financial statements of Cinergy, The Cincinnati Gas & Electric Company (CG&E), PSI Energy, Inc. (PSI), and The Union Light, Heat and Power Company (ULH&P) to conform to current presentation. The following discussions of results are not necessarily indicative of the results to be expected in any future period.
EXECUTIVE SUMMARY
In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), we explain our general operating environment, as well as our results of operations, liquidity, capital resources, future expectations/trends, market risk sensitive instruments, and accounting matters. Specifically, we discuss the following:
• factors affecting current and future operations;
• why results changed from period to period;
• potential sources of cash for future capital expenditures; and
• how these items affect our overall financial condition.
Financial Highlights
Net income for Cinergy for the years ended December 31, 2005, and 2004 was as follows:
The increase in net income was primarily due to the following factors:
• Increased gross margins resulting from PSI’s May 2004 base retail electric rate increase and the implementation of CG&E’s rate stabilization plan (RSP) in January 2005;
• Increased non-retail gross margins related to our generation portfolio, including the sale of emission allowances;
• Increased gross margins due to warmer weather, primarily in the third quarter of 2005, as compared to 2004; and
• Increased Miscellaneous Income (Expense) - Net primarily due to impairment and disposal charges recognized in 2004 on certain investments in the Power Technology and Infrastructure Services Business Unit (Power Technology and Infrastructure).
These increases were partially offset by:
• Increased fuel, emission allowance, and purchased power costs attributable to CG&E’s fixed price residential customers;
• Timing differences in revenue recognition between certain components of our generation portfolio;
• Decreases in Commercial gas gross margins, primarily due to trading results in the second quarter of 2005;
• Increased Operation and maintenance expense primarily due to regulatory asset amortization, synthetic fuel production costs, and expenses associated with the pending Duke Energy Corporation (Duke)-Cinergy merger; and
• Increased Depreciation expense due to increased depreciation rates and the addition of depreciable plant.
For further information, see “2005 Results of Operations - Cinergy”.
Forward-looking Challenges and Risks
Merger Challenges and Risks
The pending merger between Duke and Cinergy presents significant challenges. The integration of the two companies will be complex and time-consuming, due to the size and complexity of each organization. The principal challenges will be integrating the combined regulated electric utility operations and combining the unregulated wholesale power generation businesses. All of these businesses are complex, and some of the business units are dispersed. Such efforts could also divert management’s focus and resources from other strategic opportunities during the integration process. The pending merger is subject to approvals of numerous governmental agencies and approval of the shareholders of both companies, all of which are discussed in more detail in “Item 1. Business - Pending Merger.” The approval process could delay consummation of the pending merger, impose conditions that could materially impact the combined company, or cause the merger to be abandoned. Both companies will incur significant transaction and merger-related integration costs. Additionally, we will be subject to business uncertainties and contractual restrictions while the merger is pending which could adversely affect our businesses. Although both companies are taking steps to reduce any adverse effects, these uncertainties may impair our ability to attract and retain key personnel until the merger is consummated and for a period of time thereafter, and could cause customers, suppliers, and others to seek to change their existing business relationships with us.
Environmental Challenges
Cinergy faces many uncertainties with regard to future environmental legislation and the impact of this legislation on our generating assets and our decisions to construct new assets. In March 2005, the Environmental Protection Agency (EPA) finalized two rulemakings that will require significant reductions in sulfur dioxide (SO2), nitrogen oxides (NOX), and mercury emissions from power plants. Numerous states, environmental organizations, industry groups, including some of which Cinergy is a member, and individual companies have challenged various portions of both rules. Additionally, multi-emissions reductions legislation is still being discussed in the Senate, although the outcome of these discussions is still highly uncertain at this time. Presently, greenhouse gas (GHG) emissions, which principally consist of carbon dioxide (CO2), are not regulated, and while several legislative proposals have been introduced in Congress to reduce utility GHG emissions, none have been passed. Nevertheless, we anticipate a mandatory program to reduce GHG emissions will exist in the future. In 2004, Cinergy’s utility operating companies began an environmental construction program to reduce overall plant regulated emissions that is estimated to cost approximately $1.8 billion over five years. We believe that our construction program optimally balances these uncertainties and provides a level of emission reduction that will be required and/or economical to Cinergy under a variety of possible regulatory outcomes. See “Environmental Issues” in “Liquidity and Capital Resources” for further information.
Rising Coal and Emission Allowance Prices
The prices of coal and SO2 emission allowances increased dramatically in 2004, as compared to 2003, and have continued to increase in 2005. Contributing to the increases in coal and SO2 prices have been (1) increases in demand for electricity, (2) high and volatile gas prices and limited gas supply, (3) environmental regulation, and (4) decreases in the number of suppliers of coal from prior years. CG&E’s RSP allows for recovery of fuel and emission allowance expenses effective January 1, 2005 for retail non-residential customers in Ohio and January 1, 2006 for residential customers. We continue to recover these costs from PSI retail customers through previously established rate recovery mechanisms. ULH&P’s rates are frozen through January 1, 2007, the date at which new rates are expected to be implemented. To the extent that these increased fuel and SO2 prices are not offset by regulatory recovery or increases in the market price of power for wholesale transactions, they will negatively impact
ongoing earnings for Cinergy’s utility companies. The impact of these price increases on earnings is discussed in more detail in “2005 Results of Operations” and “2004 Results of Operations.”
Synthetic Fuel
Cinergy produces synthetic fuel that qualifies for tax credits (through 2007) in accordance with Section 29/45K of the Internal Revenue Code (IRC) if certain requirements are satisfied. Cinergy currently faces two major uncertainties that could impact our ability to continue to recognize the previous and/or future credits. The Internal Revenue Service (IRS) is currently auditing Cinergy for the 2002, 2003, and 2004 tax years and could challenge Cinergy’s credits. If the IRS were to successfully challenge our credits, this could result in the disallowance of up to all previously claimed and future Section 29/45K tax credits for Cinergy’s facilities. We believe that we operate in conformity with all the necessary requirements to qualify for tax credits under Section 29/45K.
Section 29/45K also provides for a phase-out of the credit based on the average price of crude oil during a calendar year. The phase-out is based on a prescribed calculation and definition of crude oil prices. Based on current crude oil prices and the recent volatility of such prices, we believe that for 2006 and 2007, the amount of the tax credits could be reduced. If oil prices are high enough, we will idle the plants, as the value of the credits would not exceed the net costs to produce the synthetic fuel. Net income related to these facilities for the twelve months ended December 31, 2005 was approximately $58 million. The net book value of our plants at December 31, 2005 was approximately $47 million.
MD&A - 2005 RESULTS OF OPERATIONS - CINERGY
2005 RESULTS OF OPERATIONS - CINERGY
Given the dynamics of our business, which include regulatory revenues with directly offsetting expenses and commodity trading operations for which results are primarily reported on a net basis, we have concluded that a discussion of our results on a gross margin basis is most appropriate. Electric gross margins represent electric operating revenues less the related direct costs of fuel, emission allowances, and purchased power. Gas gross margins represent gas operating revenues less the related direct cost of gas purchased. Within each of these areas, we will discuss the key drivers of our results. Gross margins for Cinergy for the Regulated Business Unit (Regulated) and the Commercial Business Unit (Commercial) for the years ended December 31, 2005, and 2004 were as follows:
(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.
(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact weather has on results of operations. Cooling degree days and heating degree days in Cinergy’s service territory for the years ended December 31, 2005, and 2004 were as follows:
(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.
(2) Heating degree days are the differences between the average temperature for each day and 59 degrees, assuming the average temperature is less than 59 degrees.
(3) Beginning in January 2005, we modified our heating degree days base temperature from 65 degrees to 59 degrees to more accurately reflect current consumer behavior. Prior year amounts have been updated to reflect this change.
Regulated
Gross Margins
The nine percent increase in Regulated’s electric gross margins was primarily due to the following factors:
• A $71 million increase resulting from a higher price received per megawatt hour (MWh), primarily due to PSI’s May 2004 base retail electric rate increase;
• A $45 million increase resulting from warmer weather, primarily in the third quarter of 2005, as compared to 2004; and
• A $30 million increase due to growth in non-weather related demand.
These increases were partially offset by a decline of $18 million reflecting rate reductions associated with a property tax adjustment for PSI.
Commercial
Gross Margins
The 18 percent increase in Commercial’s electric gross margins was primarily due to:
• A $46 million increase in margins from power marketing and trading contracts, primarily due to an increase in margins within the midwest market.
• Higher retail margins of $37 million reflecting:
• A $77 million increase in rate tariff adjustments resulting from implementation of CG&E’s RSP in January 2005 (a portion of the total CG&E RSP rate tariff adjustments is reflected in Regulated gross margins);
• A $12 million increase resulting from growth in non-weather related demand, due in part to the return of certain CG&E retail customers to full electric service; and
• A $9 million increase resulting from warmer weather, primarily in the third quarter of 2005, as compared to 2004.
Partially offsetting these increases was a $53 million increase in fuel, emission allowance, and purchased power costs attributable to CG&E’s fixed price residential customers.
• A $26 million increase in non-retail margins reflecting:
• A $121 million increase resulting from selling emission allowances which were no longer needed to meet our non-retail forward power sales commitments. This gain reflects significant increases in prices of SO2 emission allowances throughout much of 2004 and 2005.
• A $45 million decrease due to timing differences in revenue recognition between certain components of our generation portfolio. Our gross margins reflect $54 million of losses in 2005 and $9 million of losses in 2004 (representing a $45 million change period to period) as a result of forward purchases of coal and forward sales of power and the use of mark-to-market (MTM) accounting. A substantial portion of these losses is expected to reverse in the first quarter of 2006.
• A $33 million decrease due to higher fuel prices.
The 57 percent decrease in Commercial’s gas gross margins was primarily due to the following factors:
• A $41 million decline in financial trading margins, primarily from trading results in the second quarter of 2005; and
• A $23 million decrease due to timing differences in revenue recognition between physical storage activities and the associated derivative contracts that hedge the physical storage. Our year-to-date gross margins reflect $8 million of losses in 2005 and $15 million of gains in 2004 (representing a $23 million change period to period) as a result of derivative contracts and the use of MTM accounting.
Partially offsetting these decreases was a $15 million increase in physical trading margins, primarily from trading results in the third quarter of 2005.
Other Operating Revenues and Costs of Fuel Resold
The 56 percent increase in Other Operating Revenues was primarily due to the following factors:
• A $129 million increase in Commercial’s revenues from coal origination resulting from increases in coal prices and tons of coal sold; and
• A $64 million increase in Commercial’s revenues from the sale of synthetic fuel, primarily reflecting revenues from a new facility purchased in the second quarter of 2005.
Costs of fuel resold include Commercial’s costs of coal origination activities and the production of synthetic fuel. These costs have increased in 2005, which is consistent with the increases in the associated revenues as previously discussed.
The following explanations correspond with the line items on the Statements of Income for Cinergy. However, only the line items that varied significantly from prior periods are discussed.
Other Operating Expenses
Operation and Maintenance
The 10 percent increase in Operation and maintenance expense was primarily due to the following factors:
• Increased regulatory asset amortization of $45 million related to CG&E’s Regulatory Transition Charge (RTC). This increase reflects accelerated recovery of the regulatory asset due to both (a) the cessation of deferrals for non-residential customers due to the end of the market development period for those customers at the end of 2004 and (b) a reduction in revenues lost from switched customers, which is also recovered through the RTC;
• An increase of $31 million in costs at our synthetic fuel facilities, primarily related to production costs at a new facility purchased in the second quarter of 2005;
• Increased costs of $19 million, primarily associated with the sales of accounts receivable to an unconsolidated affiliate primarily due to increased fees charged by the buyer of the receivables and an increase in the volume of receivables sold;
• Expenses of $12 million related to outside services costs for the pending Duke-Cinergy merger; and
• Increased labor costs, primarily due to severance payments of $14 million and merger related employee retention incentives of $5 million.
These increases were partially offset by decreased outside service and labor costs totaling $13 million related to our continuous improvement initiative in 2004 and decreased employee incentive costs of $6 million.
Depreciation
The 12 percent increase in Depreciation expense was primarily due to (a) higher depreciation rates, as a result of changes in useful lives of production assets and an increased rate for cost of removal, (b) recovery of deferred depreciation costs, and (c) the addition of depreciable plant for pollution control equipment, all of which are recovered from ratepayers.
Taxes Other Than Income Taxes
The seven percent increase in Taxes other than income taxes was primarily due to a $10 million increase in property taxes, $5 million increase in other state taxes, and a $4 million increase in gross receipts tax.
Equity in Earnings of Unconsolidated Subsidiaries
The 30 percent decrease in Equity in Earnings of Unconsolidated Subsidiaries is primarily due to a gain recognized in 2004 relating to the sale of most of the assets by a company in which Power Technology and Infrastructure held an investment interest.
Miscellaneous Income (Expense) - Net
The increase in Miscellaneous Income (Expense) - Net was primarily due to $56 million in impairment and disposal charges recognized in 2004 on certain investments in Power Technology and Infrastructure.
Income Taxes
The effective income tax rate decreased for 2005, as compared to 2004. The decrease was primarily a result of an increase in tax credits associated with the production and sale of synthetic fuel. Cinergy’s 2005 effective tax rate is approximately 16 percent.
Discontinued Operations
During 2005, Cinergy completed the sale of a wholly-owned subsidiary in the Czech Republic that was engaged in the generation and sale of heat and electricity. Cinergy also began taking steps to sell its wholly owned North American energy management and energy performance contracting business. Pursuant to Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-lived Assets (Statement 144), these investments have been classified as discontinued operations in our financial statements. See Note 16 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.
MD&A - 2005 RESULTS OF OPERATIONS - CG&E
2005 RESULTS OF OPERATIONS - CG&E
Summary of Results
Net income for CG&E for the years ended December 31, 2005, and 2004 was as follows:
The increase in net income was primarily due to the following factors:
• Increased non-retail gross margins related to our generation portfolio, including the sale of emission allowances;
• Increased rate tariff adjustments resulting from implementation of the RSP in January 2005; and
• Increased gross margins due to warmer weather, primarily in the third quarter of 2005, as compared to 2004.
These increases were partially offset by:
• Increased fuel, emission allowance, and purchased power costs attributable to fixed price residential customers;
• Timing differences in revenue recognition between certain components of our generation portfolio; and
• Increased Operation and maintenance expense primarily due to regulatory asset amortization, incentive and severance labor costs, and costs associated with the sales of accounts receivable.
Gross Margins
Gross margins for CG&E for the years ended December 31, 2005, and 2004 were as follows:
(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Condensed Consolidated Statements of Income.
(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Condensed Consolidated Statements of Income.
Cooling degree days and heating degree days in CG&E’s service territory for the years ended December 31, 2005, and 2004 were as follows:
(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.
(2) Heating degree days are the differences between the average temperature for each day and 59 degrees, assuming the average temperature is less than 59 degrees.
(3) Beginning in January 2005, we modified our heating degree days base temperature from 65 degrees to 59 degrees to more accurately reflect current consumer behavior. Prior year amounts have been updated to reflect this change.
Electric Gross Margins
The 15 percent increase in CG&E’s electric gross margins was primarily due to:
• Higher retail margins of $92 million reflecting:
• A $79 million increase in rate tariff adjustments resulting from implementation of the RSP in January 2005;
• A $30 million increase resulting from warmer weather, primarily in the third quarter of 2005, as compared to 2004; and
• A $24 million increase resulting from growth in non-weather related demand, due in part to the return of certain retail customers to full electric service.
Partially offsetting these increases was a $53 million increase in fuel, emission allowance, and purchased power costs attributable to fixed price residential customers.
• A $45 million increase in margins from power marketing and trading contracts, primarily due to an increase in margins within the midwest market.
• A $37 million increase in non-retail margins reflecting:
• A $121 million increase resulting from selling emission allowances which were no longer needed to meet our non-retail forward power sales commitments. This gain reflects significant increases in prices of SO2 emission allowances throughout much of 2004 and 2005.
• A $45 million decrease due to timing differences in revenue recognition between certain components of our generation portfolio. Our gross margins reflect $54 million of losses in 2005 and $9 million of losses in 2004 (representing a $45 million change period to period) as a result of forward purchases of coal and forward sales of power and the use of MTM accounting. A substantial portion of these losses is expected to reverse in the first quarter of 2006.
• A $33 million decrease due to higher fuel prices.
Other Operating Revenues and Costs of Fuel Resold
The increase in Other Operating Revenues was due to a $108 million increase in revenues from coal origination resulting from increases in coal prices and tons of coal sold.
Costs of fuel resold represents the costs of coal origination activities. These costs have increased in 2005, which is consistent with the increase in the associated revenues as previously discussed.
The following explanations correspond with the line items on the Statements of Income for CG&E. However, only the line items that varied significantly from prior periods are discussed.
Other Operating Expenses
Operation and Maintenance
The 17 percent increase in Operation and maintenance expense was primarily due to the following factors:
• Increased regulatory asset amortization of $45 million related to CG&E’s RTC. This increase reflects accelerated recovery of the regulatory asset due to both (a) the cessation of deferrals for non-residential customers due to the end of the market development period for those customers at the end of 2004 and (b) a reduction in revenues lost from switched customers, which is also recovered through the RTC;
• Increased labor expenses of $18 million, primarily resulting from employee incentive costs and severance payments;
• Increased costs of $14 million, primarily associated with the sales of accounts receivable to an unconsolidated affiliate primarily related to increased fees charged by the buyer of the receivables and an increase in the volume of receivables sold; and
• Expenses of $6 million related to outside service costs for the pending Duke-Cinergy merger.
These increases were partially offset by a decrease in outside service costs of $5 million related to our continuous improvement initiative in 2004.
Taxes Other Than Income Taxes
The eight percent increase in Taxes other than income taxes was primarily due to a $7 million increase in property taxes and a $6 million increase in gross receipts tax.
Interest Expense
The nine percent increase in Interest Expense was primarily due to an increase in average short-term and long-term debt outstanding and an increase in interest rates for our variable rate debt.
MD&A - 2005 RESULTS OF OPERATIONS - PSI
2005 RESULTS OF OPERATIONS - PSI
Summary of Results
Net income for PSI for the years ended December 31, 2005, and 2004 was as follows:
The increase in net income was primarily due to the impact of PSI’s May 2004 base retail electric rate increase and increased gross margins due to warmer weather, primarily in the third quarter of 2005, as compared to 2004.
These increases were partially offset by an increase in Depreciation expense due to increased depreciation rates and the addition of depreciable plant.
Electric Gross Margins
Gross margins for PSI for the years ended December 31, 2005, and 2004 were as follows:
(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Condensed Consolidated Statements of Income.
Cooling degree days and heating degree days in PSI’s service territory for the years ended December 31, 2005, and 2004 were as follows:
(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.
(2) Heating degree days are the differences between the average temperature for each day and 59 degrees, assuming the average temperature is less than 59 degrees.
(3) Beginning in January 2005, we modified our heating degree days base temperature from 65 degrees to 59 degrees to more accurately reflect current consumer behavior. Prior year amounts have been updated to reflect this change.
The 10 percent increase in PSI’s electric gross margins was primarily due to the following factors:
• A $71 million increase resulting from a higher price received per MWh, primarily due to PSI’s May 2004 base retail electric rate increase;
• A $24 million increase resulting from warmer weather, primarily in the third quarter of 2005, as compared to 2004; and
• An $18 million increase due to growth in non-weather related demand.
These increases were partially offset by a decline of $18 million reflecting rate reductions associated with a property tax adjustment.
The following explanations correspond with the line items on the Statements of Income for PSI. However, only the line items that varied significantly from prior periods are discussed.
Other Operating Expenses
Operation and Maintenance
The one percent increase in Operation and maintenance expense was primarily due to various increases in operating costs and increased distribution system maintenance costs. Operating costs increased due to increased costs associated with the sales of accounts receivables to an unconsolidated affiliate and increased outside service costs. These increases were offset by a decrease in labor expense, primarily resulting from employee incentive costs, which were partially offset by merger and severance costs.
Depreciation
The 20 percent increase in Depreciation expense was primarily due to (a) higher depreciation rates, as a result of changes in useful lives of production assets and an increased rate for cost of removal, (b) recovery of deferred depreciation costs, and (c) the addition of depreciable plant for pollution control equipment, all of which are recovered from ratepayers.
Miscellaneous Income - Net
The increase in Miscellaneous Income - Net was primarily due to an increase in interest income on restricted deposits and an increase in the rate for allowance for funds used during construction.
Interest Expense
The 20 percent increase in Interest Expense was primarily due to an increase in average long-term debt outstanding and an increase in interest rates for our variable rate debt. This expense was partially offset by interest income received on restricted deposits obtained through these incremental borrowings, which was recorded in Miscellaneous Income - Net associated with the additional debt outstanding.
MD&A - 2005 RESULTS OF OPERATIONS - ULH&P
2005 RESULTS OF OPERATIONS - ULH&P
Summary of Results
The Results of Operations discussion for ULH&P is presented only for the year ended December 31, 2005, in accordance with General Instruction I(2)(a).
Electric and gas gross margins and net income for ULH&P for the years ended December 31, 2005, and 2004 were as follows:
(1) Electric gross margin is calculated as Electric operating revenues less Electricity purchased from parent company for resale expense from the Statements of Income.
(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
The six percent increase in electric gross margins was primarily due to increased demand caused by warmer weather in the third quarter of 2005, as compared to 2004. The seven percent increase in gas gross margins was primarily due to a base rate increase implemented in October 2005. Also contributing to gas gross margins was an increase in rate tariff adjustments associated with the gas main replacement program and the demand-side management program, which encourages efficient customer gas usage.
The 21 percent decrease in net income was partially due to higher Operation and maintenance costs associated with various increases in operating expenses including the transmission of electricity and increased costs associated with sales of accounts receivables to an unconsolidated affiliate. Also contributing to the decrease in net income were increased property taxes. There were also increases in Interest Expense related to an increase in average long-term debt outstanding. These decreases were partially offset by the increases in electric and gas gross margins as previously discussed.
MD&A - 2004 RESULTS OF OPERATIONS - CINERGY
2004 RESULTS OF OPERATIONS - CINERGY
Given the dynamics of our business, which include regulatory revenues with directly offsetting expenses and commodity trading operations for which results are primarily reported on a net basis, we have concluded that a discussion of our results on a gross margin basis is most appropriate. Electric gross margins represent electric operating revenues less the related direct costs of fuel, emission allowances, and purchased power. Gas gross margins represent gas operating revenues less the related direct cost of gas purchased. Within each of these areas, we will discuss the key drivers of our results. Gross margins for Cinergy for Regulated and Commercial for the years ended December 31, 2004, and 2003 were as follows:
(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.
(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact weather has on results of operations. Cooling degree days and heating degree days in Cinergy’s service territory for the years ended December 31, 2004, and 2003 were as follows:
(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.
(2) Heating degree days are the differences between the average temperature for each day and 59 degrees, assuming the average temperature is less than 59 degrees.
(3) Beginning in January 2005, we modified our heating degree days base temperature from 65 degrees to 59 degrees to more accurately reflect current consumer behavior. Prior year amounts have been updated to reflect this change.
The change in cooling degree days and heating degree days did not have a material effect on Cinergy’s gross margins for the year ended December 31, 2004, as compared to 2003.
Regulated
Gross Margins
The 11 percent increase in Regulated’s electric gross margins was primarily due to the following factors:
• An $80 million increase resulting from a higher price received per MWh due to PSI’s base retail electric rate increase in May 2004; and
• A $32 million increase due to growth in non-weather related demand.
The eight percent increase in Regulated’s gas gross margins was primarily due to a $16 million increase in tariff adjustments mainly associated with the gas main replacement program. Partially offsetting this increase was a $7 million decrease reflecting a decline in non-weather related demand.
Commercial
Gross Margins
The eight percent decrease in Commercial’s electric gross margins was primarily due to the following factors:
• A $51 million increase in CG&E’s average price of fuel without a matching increase in the price of power charged to customers (the majority of which were under fixed price contracts); and
• A $62 million increase in emission allowance costs, primarily due to increases in SO2 emission allowance market prices, without a matching increase in the price of power charged to customers. The number of SO2 emission allowances used also increased in 2004.
Partially offsetting these decreases were:
• A $24 million increase in gross margins on power marketing, trading, and origination contracts attributable to higher margins on physical and financial trading, primarily related to regional spreads between the mideast and midwest markets; and
• A $15 million increase due to growth in non-weather related demand.
Other Operating Revenues and Costs of Fuel Resold
The 45 percent increase in Other Operating Revenues was primarily due to the following factors:
• A $67 million increase in Commercial’s revenues from coal origination resulting from increases in coal prices and the number of coal origination contracts; and
• A $28 million increase in Commercial’s revenues from the sale of synthetic fuel.
Costs of fuel resold includes Commercial’s costs of coal origination activities and the production of synthetic fuel. These costs have increased in 2004, which is consistent with the increases in the associated revenues as previously discussed.
The following explanations correspond with the line items on the Statements of Income for Cinergy. However, only the line items that varied significantly from prior periods are discussed.
Other Operating Expenses
Operation and Maintenance
The 14 percent increase in Operation and maintenance expense was primarily due to the following factors:
• Costs primarily associated with employee labor and benefits increased $50 million. Labor and benefit costs increased approximately six percent;
• Maintenance expenses, primarily production related, were higher by $26 million;
• Costs of $20 million incurred in 2004 related to a continuous improvement initiative;
• Higher transmission costs of $15 million. This increase was due, in part, to refunds received in 2003, which offset a portion of the costs for that year; and
• A $14 million increase in operation expenses for non-regulated service subsidiaries that started operations, or became fully consolidated, after the second quarter of 2003.
These increases were partially offset by:
• The recognition of $14 million of costs associated with voluntary early retirement programs and employee severance programs in 2003; and
• Costs of $12 million incurred in 2003 associated with the bankruptcy of Enron Corp.
Depreciation
The 16 percent increase in Depreciation expense was primarily due to the following factors:
• A $36 million increase due to the addition of depreciable plant, primarily for pollution control equipment, and the accelerated gas main replacement program; and
• A $27 million increase resulting from (a) higher depreciation rates, as a result of changes in useful lives of production assets and an increased rate for cost of removal and (b) recovery of deferred depreciation costs, both of which were approved in PSI’s latest retail rate case.
These increases were partially offset by $15 million due to longer estimated useful lives of CG&E’s generation assets resulting from a depreciation study completed during the third quarter of 2003.
Equity in Earnings of Unconsolidated Subsidiaries
The increase in Equity in Earnings of Unconsolidated Subsidiaries was primarily due to a gain of $21 million relating to the sale of most of the assets by a company in which Power Technology and Infrastructure holds an investment. See Note 17(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
Miscellaneous Income (Expense) - Net
The decrease in Miscellaneous Income (Expense) - Net was primarily due to the recognition of $56 million in impairment and disposal charges in 2004 primarily associated with certain investments in the Power Technology and Infrastructure portfolio. The values of these investments reflect our estimates and judgments about the future performance of these investments, for which actual results may differ. A substantial portion of these charges relate to a company, in which Cinergy holds a non-controlling interest that sold its major assets in 2004. This company is involved in the development and sale of outage management software.
This decrease was partially offset by interest income of $9 million on the notes receivable of two subsidiaries consolidated in the third quarter of 2003.
Interest Expense
The two percent increase in Interest Expense was primarily due to the following factors:
• A $12 million increase due to Cinergy’s recognition of a note payable to a trust; and
• A $9 million increase related to additional debt recorded in accordance with the consolidation of two new entities.
The note payable and additional debt were both recorded in July 2003 resulting from the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46, Consolidation of Variable Interest Entities (Interpretation 46).
These increases were partially offset by:
• A decline in average long-term debt; and
• Charges recorded during 2003 associated with CG&E’s refinancing of certain debt.
Preferred Dividend Requirement of Subsidiary Trust
The decrease in Preferred Dividend Requirement of Subsidiary Trust was a result of the implementation of Interpretation 46. Effective July 1, 2003, the preferred trust securities and the related dividends are no longer reported in Cinergy’s financial statements. However, interest expense is still being incurred on a note payable to this trust as previously discussed.
Income Taxes
Cinergy’s 2004 effective tax rate was approximately 21 percent, a decrease of four percent from 2003, resulting from a greater amount of tax credits associated with the production and sale of synthetic fuel and the successful resolution of certain tax matters.
Discontinued Operations
During 2003, Cinergy completed the disposal of its gas distribution operation in South Africa, sold its remaining wind assets in the United States, and substantially sold or liquidated the assets of its energy trading operation in the Czech Republic. The 2004 and 2003 Discontinued Operations have been restated for 2005 discontinued operations, as previously discussed in “MD&A - 2005 Results of Operations - Cinergy”. Pursuant to Statement 144, these investments have been classified as discontinued operations in our financial statements. See Note 16 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.
Cumulative Effect of Changes in Accounting Principles
In 2003, Cinergy recognized a Cumulative effect of changes in accounting principles, net of tax gain of $26 million. The cumulative effect of changes in accounting principles was a result of the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations (Statement 143) and the rescission of Emerging Issues Task Force Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). See Note 1(s)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
MD&A - 2004 RESULTS OF OPERATIONS - CG&E
2004 RESULTS OF OPERATIONS - CG&E
Summary of Results
Net income for CG&E for the years ended December 31, 2004, and 2003 were as follows:
The decrease in net income was primarily due to the following factors:
• Higher operating costs due, in part, to increases in costs for employee labor and benefits;
• Lower margins from the sale of electricity primarily due to higher fuel and emission allowance costs; and
• A net gain recognized in 2003 resulting from the implementation of certain accounting changes.
These decreases were partially offset by:
• Growth in non-weather related demand for electricity; and
• An increase in gross margins on power marketing, trading, and origination contracts.
Gross Margins
Gross margins for CG&E for the years ended December 31, 2004, and 2003 were as follows:
(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.
(2) Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
Cooling degree days and heating degree days in CG&E’s service territory for the years ended December 31, 2004, and 2003 were as follows:
(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.
(2) Heating degree days are the differences between the average temperature for each day and 59 degrees, assuming the average temperature is less than 59 degrees.
(3) Beginning in January 2005, we modified our heating degree days base temperature from 65 degrees to 59 degrees to more accurately reflect current consumer behavior. Prior year amounts have been updated to reflect this change.
The change in cooling degree days and heating degree days did not have a material effect on CG&E’s gross margins for the period.
Electric Gross Margins
The two percent decrease in CG&E’s electric gross margins was primarily due to the following factors:
• A $51 million increase in the average price of fuel without a matching increase in the price of power charged to customers (the majority of which were under fixed price contracts); and
• A $32 million increase in emission allowance costs, primarily due to an increase in SO2 emission allowance market prices, without a matching increase in the price of power charged to customers.
These decreases were partially offset by:
• A $31 million increase in margins from retail customers due to growth in non-weather related demand; and
• A $29 million increase in gross margins on power marketing, trading, and origination contracts attributable to higher margins on physical and financial trading, primarily related to regional spreads between the mideast and midwest markets.
Gas Gross Margins
The seven percent increase in CG&E’s gas gross margins was primarily due to a $16 million increase in tariff adjustments mainly associated with the gas main replacement program. Partially offsetting this increase was a $7 million decrease reflecting a decline in non-weather related demand.
Other Operating Revenues and Costs of Fuel Resold
The increase in Other Operating Revenues was due to a $67 million increase in revenues from coal origination resulting from increases in coal prices and the number of coal origination contracts.
Costs of fuel resold represents the costs of coal origination activities. These costs have increased in 2004, which is consistent with the increase in the associated revenues as previously discussed.
The following explanations correspond with the line items on the Statements of Income for CG&E. However, only the line items that varied significantly from prior periods are discussed.
Other Operating Expenses
Operation and Maintenance
The 19 percent increase in Operation and maintenance expense was primarily due to the following factors:
• Costs primarily associated with employee labor and benefits increased $28 million;
• Maintenance expenses, primarily production and distribution related, were higher by $21 million;
• A $9 million of costs incurred in 2004 related to a continuous improvement initiative; and
• Higher transmission costs of $9 million. This increase was due, in part, to refunds received in 2003, which offset a portion of the costs for that year.
Partially offsetting these increases was the recognition of $4 million of costs associated with voluntary early retirement programs and employee severance programs in 2003.
Depreciation
The four percent decrease in Depreciation expense was primarily due to longer estimated useful lives of CG&E’s generation assets resulting from a depreciation study completed during the third quarter of 2003, which resulted in a decrease of $15 million. This decrease was partially offset by an $8 million increase due to the addition of depreciable plant primarily for pollution control equipment and the accelerated gas main replacement program.
Miscellaneous Income - Net
The 47 percent decrease in Miscellaneous Income - Net was primarily due to the following factors:
• A final reconciliation recorded in 2003 between CG&E and PSI due to a previous demutualization of a medical insurance carrier used by both companies; and
• A decline in the allowance for equity funds used during construction resulting from certain assets being placed into service and a decrease in the equity rate applied.
Interest Expense
The 21 percent decrease in Interest Expense was primarily due to a decline in average long-term debt and charges recorded during 2003 associated with the refinancing of certain debt.
Cumulative Effect of Changes in Accounting Principles
In 2003, CG&E recognized a Cumulative effect of changes in accounting principles, net of tax gain of approximately $31 million as a result of the adoption of Statement 143 and the rescission of EITF 98-10. See Note 1(s)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
MD&A 2004 RESULTS OF OPERATIONS - PSI
2004 RESULTS OF OPERATIONS - PSI
Summary of Results
Net income for PSI for the years ended December 31, 2004, and 2003 were as follows:
The increase in net income was primarily due to the impact of the PSI base retail electric rate increase in May 2004 and growth in non-weather related demand.
These increases were partially offset by higher operating costs due, in part, to increases in costs for employee labor and benefits.
Electric Gross Margins
Gross margins for PSI for the years ended December 31, 2004, and 2003 were as follows:
(1) Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.
Cooling degree days and heating degree days in PSI’s service territory for the years ended December 31, 2004, and 2003 were as follows:
(1) Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.
(2) Heating degree days are the differences between the average temperature for each day and 59 degrees, assuming the average temperature is less than 59 degrees.
(3) Beginning in January 2005, we modified our heating degree days base temperature from 65 degrees to 59 degrees to more accurately reflect current consumer behavior. Prior year amounts have been updated to reflect this change.
The change in degree days did not have a material effect on electric gross margins for the period. The 13 percent increase in PSI’s electric gross margins was primarily due to the following factors:
• An $80 million increase resulting from a higher price received per MWh due to PSI’s base retail electric rate increase in May 2004; and
• A $16 million increase due to growth in non-weather related demand.
The following explanations correspond with the line items on the Statements of Income for PSI. However, only the line items that varied significantly from prior periods are discussed.
Other Operating Expenses
Operation and Maintenance
The six percent increase in Operation and maintenance expense was primarily due to the following factors:
• Costs primarily associated with employee labor and benefits increased $14 million;
• Costs of $8 million incurred in 2004 related to a continuous improvement initiative;
• An increase in production related maintenance expense of $7 million; and
• Higher transmission costs of $6 million. This increase was due, in part, to refunds received in 2003, which offset a portion of the costs for that year.
Partially offsetting these increases was the recognition of $4 million of costs associated with voluntary early retirement programs and employee severance programs in 2003.
Depreciation
The 35 percent increase in Depreciation expense was primarily due to the following factors:
• A $27 million increase due to the addition of depreciable plant primarily for pollution control equipment; and
• A $27 million increase resulting from (a) higher depreciation rates, as a result of changes in useful lives of production assets and an increased rate for cost of removal and (b) recovery of deferred depreciation costs, both of which were approved in PSI’s latest retail rate case.
Interest Expense
The seven percent increase in Interest Expense was primarily due to an increase in the effective interest rate on short-term debt and an increase in the average amount of short-term debt outstanding.
MD&A - LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY AND CAPITAL RESOURCES
Historical Cash Flow Analysis From Continuing Operations
Operating Activities from Continuing Operations
For the years ended December 31, 2005, 2004, and 2003, our cash flows from operating activities from continuing operations were as follows:
Net Cash Provided by Operating Activities from Continuing Operations
(1) The results of Cinergy also include amounts related to non-registrants.
The tariff-based gross margins of our utility operating companies continue to be the principal source of cash from operating activities. The diversified retail customer mix of residential, commercial, and industrial classes and a commodity mix of gas and electric services provide a reasonably predictable gross cash flow.
For the year ended December 31, 2005, Cinergy’s and PSI’s decrease in net cash provided by operating activities was primarily due to unfavorable working capital fluctuations, including the build up of fuel and emission allowances inventory. Cinergy’s and PSI’s decrease was also attributable to increased expenditures associated with fuel and purchased power that have not yet been expensed, until recovered from ratepayers. CG&E’s increase in net cash provided by operating activities was due to favorable working capital fluctuations, including increased net cash received as collateral associated with power transactions. ULH&P’s net cash provided by operating activities was comparable to 2004.
For the year ended December 31, 2004, Cinergy’s and CG&E’s decrease in net cash provided by operating activities was primarily due to unfavorable working capital fluctuations, including the build up of fuel and emission allowances inventory. PSI’s increase was due to an increase in earnings (after adjusting for non-cash items) and a difference in the timing of payables and income tax payments. ULH&P’s increase in net cash provided by operating activities was attributable to favorable working capital fluctuations.
Financing Activities from Continuing Operations
For the years ended December 31, 2005, 2004, and 2003, our cash flows from financing activities from continuing operations were as follows:
Net Cash Provided by (Used in) Financing Activities from Continuing Operations
(1) The results of Cinergy also include amounts related to non-registrants.
For the year ended December 31, 2005, Cinergy’s increase in net cash provided by financing activities was primarily attributable to the increased issuance of long-term debt and common stock and the decrease in redemptions of long-term debt in 2005. CG&E’s increase in net cash used in financing activities was primarily due to the repayment of short-term debt. PSI’s increase in net cash provided by financing activities was attributable to
the issuance of long-term debt and capital contributions received from Cinergy Corp. ULH&P’s decrease in net cash used in financing activities was due to an increase in short-term debt.
For the year ended December 31, 2004, CG&E’s decrease in net cash used in financing activities was primarily due to a decrease in redemptions of long-term debt. PSI’s increase in net cash used in financing activities was attributable to the repayment of short-term debt in 2004 and capital contributions from Cinergy Corp. that were made in 2003. ULH&P’s increase in net cash used in financing activities was due to an increase in dividends on common stock. Cinergy’s net cash used in financing activities in 2004 was comparable to 2003.
Investing Activities from Continuing Operations
For the years ended December 31, 2005, 2004, and 2003, our cash flows used in investing activities from continuing operations were as follows:
Net Cash Used in Investing Activities from Continuing Operations
(1) The results of Cinergy also include amounts related to non-registrants.
For the year ended December 31, 2005, Cinergy’s, CG&E’s, and PSI’s increase in net cash used in investing activities was primarily due to increases in capital expenditures for ongoing environmental compliance programs and normal construction activity. Cinergy’s and PSI’s increase was also attributable to the acquisition of the Wheatland generating facility in May 2005. ULH&P’s increase in net cash used in investing activities was primarily due to increased capital expenditures related to normal construction activity.
For the year ended December 31, 2004, Cinergy’s decrease in net cash used in investing activities was primarily due to decreases in capital expenditures related to energy-related investments. CG&E’s decrease in net cash used in investing activities was primarily due to a decrease in capital expenditures for ongoing environmental compliance programs and normal construction activity. PSI’s and ULH&P’s net cash used in investing activities in 2004 was comparable to 2003.
Capital Requirements
Environmental Issues
Environmental Protection Agency Regulations
In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR) which would require states to revise their State Implementation Plan (SIP) by September 2006 to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards for ozone and fine particulate matter. The rule established a two-phase, regional cap and trade program for SO2 and NOX, affecting 28 states, including Ohio, Indiana, and Kentucky, and requires SO2 and NOX emissions to be cut 70 percent and 65 percent, respectively, by 2015. At the same time, the EPA issued the Clean Air Mercury Rule (CAMR) which requires national reductions in mercury emissions from coal-fired power plants beginning in 2010. Accompanying the CAMR publication in the Federal Register was the EPA’s determination that it was not appropriate and necessary to regulate mercury emissions from utilities under Section 112 of the Clean Air Act (CAA), requiring maximum achievable control technology, so that it would be possible to regulate those emissions under Section 111 of the CAA with the CAMR. The final regulation also adopts a two-phase cap and trade approach that requires mercury emissions to be cut by 70 percent by 2018. SIPs must comply with the prescribed reduction levels under CAIR and CAMR; however, the states have the ability to introduce more stringent requirements if desired. Under both CAIR and CAMR, companies have flexible
compliance options including installation of pollution controls on large plants where such controls are particularly efficient and utilization of emission allowances for smaller plants where controls are not cost effective.
In August 2005, the EPA proposed a Federal Implementation Plan (FIP), which would implement phase 1 of CAIR by 2009 and 2010 for NOX and SO2, respectively, for any state that does not develop a CAIR SIP in a timely manner. Numerous states, environmental organizations, industry groups, including some of which Cinergy is a member, and individual companies have challenged various portions of both rules. Those challenges are currently pending in the Federal Circuit Court for the District of Columbia. On October 21, 2005, the EPA agreed to reconsider certain aspects of the CAMR as well as the determination not to regulate mercury under Section 112 of the CAA. In December 2005 and again in January 2006, the EPA reconsidered portions of the CAIR, but did not propose any regulatory changes. At this time we cannot predict the outcome of these matters.
Over the 2006-2010 time period, we expect to spend approximately $1.4 billion to reduce mercury, SO2, and NOX emissions. These projected expenditures include estimated costs to comply at plants that we own but do not operate and could change when taking into consideration compliance plans of co-owners or operators involved. Moreover, as market conditions change, additional compliance options may become available and our plans will be adjusted accordingly. Approximately 53 percent of these estimated environmental costs would be incurred at PSI’s coal-fired plants, for which recovery would be pursued in accordance with regulatory statutes governing environmental cost recovery. See (b)(ii) for more details. CG&E receives partial recovery of depreciation and financing costs related to environmental compliance projects for 2005-2008 through its RSP. See (b)(iii) for more details.
The EPA made final state non-attainment area designations to implement the revised ozone standard and to implement the new fine particulate standard in June 2004 and April 2005, respectively. Several counties in which we operate have been designated as being in non-attainment with the new ozone standard and/or fine particulate standard. States with counties that are designated as being in non-attainment with the new ozone and/or fine particulate standards are required to develop a plan of compliance by June 2007 and April 2008, respectively. Industrial sources in or near those counties are potentially subject to requirements for installation of additional pollution controls. In March 2005, various states, local governments, environmental groups, and industry groups, including some of which Cinergy is a member, filed petitions for review in the United States Court of Appeals for the D.C. Circuit to challenge the EPA’s particulate matter non-attainment designations. Although the EPA has attempted to structure CAIR to resolve purported utility contributions to ozone and fine particulate non-attainment, at this time, Cinergy cannot predict the effect of current or future non-attainment designations on its financial position or results of operations.
Energy Policy Act of 2005
A comprehensive energy bill (the Energy Policy Act of 2005) passed Congress in July 2005 and was signed by President Bush on August 8, 2005. The bill, among other things:
• Repealed the Public Utility Holding Company Act of 1935 (PUHCA 1935) and enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005) effective six months after the bill’s enactment (i.e., February 8, 2006);
• Amended certain provisions of the Federal Power Act, including new provisions related to consumer protection and enforcement and an expansion of the Federal Energy Regulatory Commission’s (FERC) authority to impose civil and criminal penalties for, among other things, reliability infractions and power trading irregularities;
• Revised the Public Utility Regulatory Policies Act of 1978, including the removal of restrictions on ownership by electric utilities of qualifying facilities and the removal of the utility’s requirement to purchase power from facilities under certain circumstances;
• Provided FERC with expanded authority in the electric industry to review mergers, acquisitions and asset dispositions, effective six months after the bill’s enactment;
• Provided FERC with authority to oversee and enforce, through the creation of a new Electric Reliability Organization, reliability standards, and promotes rules that provide incentives to enhance transmission facilities;
• Included tax incentives for the development of wind and other renewable technologies;
• Included tax incentives for integrated coal gasification combined cycle (IGCC) facilities; and
• Accelerated the tax depreciation rates for pollution control equipment on power plants built after 1975.
Under terms of the Energy Policy Act of 2005, Cinergy’s pending merger with Duke is grandfathered under existing FERC authority. In addition, the bill authorized a significant number of programs and grants that may be of help in, among other things, lowering the cost of adding IGCC facilities and furthering carbon sequestration activities. However, those authorizations must be appropriated by Congress in 2006. It is too early to determine if any of the programs will be appropriated dollars in order to carry them out, or if Cinergy will be a direct beneficiary of those programs. As noted, the Energy Policy Act of 2005, among other provisions, repealed the PUHCA 1935 and replaced it with the PUHCA 2005, effective February 8, 2006. See “FERC Public Utility Holding Company Act of 2005” in “MD&A Future Expectations/Trends” for additional information on the PUHCA 2005. At this time, it is too early to predict the overall impact the Energy Policy Act of 2005 will have on our financial position or results of operations.
Lawsuits
We are currently involved in the following lawsuits which are discussed in more detail in “Item 3. Legal Proceedings.” An unfavorable outcome of any of these lawsuits could have a material impact on our liquidity and capital resources.
• Clean Air Act Lawsuit
• Carbon Dioxide Lawsuit
• Selective Catalytic Reduction Units at Gibson Generating Station
• Zimmer Generating Station Lawsuit
• Manufactured Gas Plant Sites
• Asbestos Claims Litigation
Capital and Investment Expenditures
Actual construction and other committed expenditures for 2005 and forecasted construction and other committed expenditures for 2006 and for the five-year period 2006-2010 (in nominal dollars) are presented in the table below:
Capital and Investment Expenditures
(1) The results of Cinergy also include amounts related to non-registrants.
In 2005, we spent $462 million for NOX and other environmental compliance projects. Forecasted expenditures for environmental compliance projects (in nominal dollars) are approximately $679 million for 2006 and $1.5 billion for the 2006-2010 period. The majority of this forecast includes our estimate of the total cost to comply with regulations requiring reductions in mercury, NOX, and SO2 emissions, assuming a cap and trade approach to mercury emissions. Approximately 60 percent of these estimated environmental costs would be incurred at PSI’s regulated coal-fired plants. See “Environmental Issues” for further discussion.
Contractual Cash Obligations
The following table presents Cinergy’s, CG&E’s, PSI’s, and ULH&P’s significant contractual cash obligations:
(1) Excludes notes payable and other short-term obligations.
(2) Includes amounts related to non-registrants.
(3) Amounts do not include interest payments. See the Consolidated Statements of Capitalization in “Item 8. Financial Statements and Supplementary Data” for disclosure of interest rates for interest payments.
(4) We have significantly more coal under contract; however, these contracts contain price re-opener provisions effectively making them variable contracts after certain dates. Contract coal after the price re-opener date is therefore excluded from this table.
(5) Includes long-term contracts accounted for on an accrual basis. See the Fair Value of Contracts maturity table in “Market Risk Sensitive Instruments” for disclosure of contracts that are accounted for at fair value.
Pension and Other Postretirement Benefits
Cinergy maintains qualified defined benefit pension plans covering substantially all United States employees meeting certain minimum age and service requirements. Plan assets consist of investments in equity and debt securities. Funding for the qualified defined benefit pension plans is based on actuarially determined contributions, the maximum of which is generally the amount deductible for tax purposes and the minimum being that required by the Employee Retirement Income Security Act of 1974, as amended (ERISA). On January 1, 2003, Cinergy adopted a funding plan to reduce, or eliminate, the unfunded “Funding Liability” initially measured as of that date. This unfunded obligation is the difference between the “Funding Liability” determined actuarially on an ERISA basis and the market value of plan assets and is less than the unfunded pension obligation calculated for accounting purposes and disclosed in Note 11 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data.” The unfunded obligation is recalculated as of January 1 of each year to identify adjustments required to meet the funding plan.
Cinergy’s minimum required contribution in calendar year 2005 was zero, as compared to $16 million in calendar year 2004. Actual contributions during calendar year 2005 and 2004 totaled $102 million and $117 million, reflecting additional discretionary contributions of $102 million and $101 million, respectively, under the aforementioned funding plan. Due to the significant 2005 and 2004 calendar year contributions, Cinergy’s minimum required contribution in calendar year 2006 is expected to be zero. Should Cinergy continue funding under the funding plan, discretionary contributions are expected to be approximately $120 million in 2006. Cinergy may consider making discretionary contributions in 2007 and future periods; however, at this time, we are unable to determine the amount of those contributions. Estimated contributions fluctuate based on changes in market performance of plan assets and actuarial assumptions. Absent the occurrence of interim events that could materially impact these targets, we will update our expected target contributions annually as the actuarial funding valuations are completed and make decisions about future contributions at that time.
In April 2004, the Pension Funding Equity Act of 2004 (PFEA) was issued. PFEA specified temporary funding regulations for plan years 2004 and 2005. Absent an extension of PFEA for plan years beginning January 1, 2006, Cinergy’s near-term contributions will increase significantly. In addition, legislative proposals that would permanently revise current pension funding regulations have been developed by the Bush Administration, the House of Representatives, and the Senate. While the exact form, timing and impact of any final legislation is not currently known, preliminary indications are that any final legislation based on the three proposals will substantially increase near-term contributions. A failure to extend PFEA or the enactment of any proposed permanent funding legislation will require Cinergy to revise its aforementioned funding strategy. Cinergy will be closely monitoring developments regarding these legislative items and adjustments to its funding strategy will be made when appropriate.
Cinergy sponsors non-qualified pension plans that cover officers, certain key employees, and non-employee directors. Cinergy’s payments for these non-qualified pension plans are expected to be approximately $10 million in 2006.
We provide certain health care and life insurance benefits to retired United States employees and their eligible dependents. Cinergy’s payments for these postretirement benefits in 2006 are expected to be approximately $25 million. See Note 11 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information about our pension and other postretirement benefit plans.
Other Investing Activities
Our ability to invest in growth initiatives was previously limited by certain legal and regulatory requirements, including the PUHCA 1935. The PUHCA 1935 limited the types of non-utility businesses in which Cinergy and other registered holding companies under the PUHCA 1935 could invest as well as the amount of capital that could be invested in permissible non-utility businesses. Pursuant to the Energy Policy Act of 2005, the PUHCA 1935 was repealed effective February 8, 2006 and was replaced with the PUHCA 2005 and other provisions of the Energy Policy Act of 2005 under the jurisdiction of the FERC. Upon the repeal of the PUHCA 1935, the investment restrictions were terminated. For a discussion of the PUHCA 1935 repeal, see “Energy Policy Act of 2005” in “Liquidity and Capital Resources” and “FERC Public Utility Holding Company Act of 2005” in “Future Expectations/Trends.”
Guarantees
As of December 31, 2005, Cinergy Corp. had guaranteed approximately $1.4 billion of obligations recognized on the balance sheets of its consolidated subsidiaries. This amount does not reflect guarantees related to unconsolidated subsidiaries which are disclosed separately pursuant to FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (Interpretation 45). Interpretation 45 requires disclosure of maximum potential liabilities for guarantees issued on behalf of unconsolidated subsidiaries and joint ventures and under indemnification clauses in various contracts. See Note 13(c)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further discussion of guarantees.
Our ability to provide guarantees was previously limited by the PUHCA 1935. Pursuant to the Energy Policy Act of 2005, the PUHCA 1935 was repealed effective February 8, 2006 and was replaced with the PUHCA 2005 and other provisions of the Energy Policy Act of 2005, under the jurisdiction of the FERC. Upon the repeal of the PUHCA 1935, the guarantee restrictions were terminated. For a discussion of the PUHCA 1935 repeal, see “Energy Policy Act of 2005” in “Liquidity and Capital Resources” and “FERC Public Utility Holding Company Act of 2005” in “Future Expectations/Trends.”
Marketing & Trading Liquidity Risks
Cinergy has certain contracts in place, primarily with trading counterparties, that require the issuance of collateral in the event our debt ratings are downgraded below investment grade. Based upon our December 31, 2005 trading portfolio, if such an event were to occur, Cinergy would be required, based on contractual provisions, to post up to $530 million in additional collateral related to its gas and power trading operations, of which $106 million is related to CG&E.
As a consequence of rising commodity prices, as of December 31, 2005, Cinergy has posted $168 million in total cash collateral, of which $54 million is related to CG&E, and received total cash collateral of $143 million, of which $80 million is related to CG&E. Also, Cinergy has posted non-cash collateral in the form of letters of credit totaling $358 million, of which $353 million is related to CG&E, and received letters of credit totaling $503 million, of which $186 million is related to CG&E.
Capital Resources
Cinergy, CG&E, PSI, and ULH&P meet their current and future capital requirements through a combination of funding sources including, but not limited to, internally generated cash flows, tax-exempt bond issuances, capital lease and operating lease structures, the securitization of certain asset classes, short-term bank borrowings, issuance of commercial paper, and issuances of long-term debt and equity. Funding decisions are based on market conditions, market access, relative pricing information, borrowing duration and current versus forecasted cash needs. Cinergy, CG&E, PSI, and ULH&P are committed to maintaining balance sheet health, responsibly managing capitalization, and maintaining adequate credit ratings. Cinergy, CG&E, PSI, and ULH&P believe that they have adequate financial resources to meet their future needs.
Sale of Accounts Receivable
CG&E, PSI, and ULH&P have an agreement with Cinergy Receivables Company, LLC (Cinergy Receivables), an affiliate, to sell, on a revolving basis, nearly all of the retail accounts receivable and related collections of CG&E, PSI, and ULH&P. Cinergy Receivables funds its purchases with borrowings from commercial paper conduits that obtain a security interest in the receivables. This program accelerates the collection of cash for CG&E, PSI, and ULH&P related to these retail receivables. Cinergy Corp. does not consolidate Cinergy Receivables because it meets the requirements to be accounted for as a qualifying special purpose entity (SPE). See Note 5(c) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.
Notes Payable and Other Short-term Obligations
As a result of the February 8, 2006 repeal of the PUHCA 1935, pursuant to the Energy Policy Act of 2005 (discussed previously in “Energy Policy Act of 2005”), we are no longer required to obtain regulatory authorization from the Securities and Exchange Commission (SEC) in order for Cinergy Corp., PSI, and ULH&P to issue short-term debt. However, in accordance with provisions of the Federal Power Act and the PUHCA 2005 rules issued by the FERC in December 2005, pursuant to the Energy Policy Act of 2005, PSI and ULH&P must seek such authorization exclusively from the FERC but are permitted, as a transitional matter through December 31, 2007, to continue to issue short-term debt under an SEC order in effect prior to the repeal of the PUHCA 1935. The Public Utilities Commission of Ohio (PUCO) has regulatory jurisdiction over the issuance of short-term debt by CG&E. With the repeal of the PUHCA 1935, no federal or state commission regulates the issuance of short-term debt by Cinergy Corp.
At December 31, 2005, the SEC’s short-term debt authority for PSI and ULH&P, under the PUHCA 1935, and CG&E’s short-term debt authority under the PUCO was as follows:
For the purposes of quantifying regulatory authority, short-term debt includes revolving credit line borrowings, uncommitted credit line borrowings, intercompany money pool obligations, and commercial paper.
Cinergy Corp.’s short-term borrowing consists primarily of unsecured revolving lines of credit and the sale of commercial paper. Cinergy Corp.’s revolving credit facility and commercial paper program also support the short-term borrowing needs of CG&E, PSI, and ULH&P. In addition, Cinergy Corp., CG&E, and PSI maintain uncommitted lines of credit. These facilities are not firm sources of capital but rather informal agreements to lend money, subject to availability, with pricing determined at the time of advance. The following table summarizes our Notes payable and other short-term obligations and Notes payable to affiliated companies:
(1) Standby liquidity is reserved against the revolving line of credit to support the commercial paper program and outstanding letters of credit (currently $515 million and $358 million, respectively).
(2) Consists of a five-year facility which was entered into in September 2005, matures in September 2010, and contains $500 million sublimits each for CG&E and PSI, and a $100 million sublimit for ULH&P (which was increased from $65 million in conjunction with its transaction with CG&E in which ULH&P acquired interests in three of CG&E’s electric generating stations. See “Kentucky” in “Future Expectations/Trends” for further information regarding this transaction.)
(3) Cinergy Corp.’s commercial paper program limit is $1.5 billion. The commercial paper program is supported by Cinergy Corp.’s revolving line of credit.
(4) Of the $162 million, $150 million relates to a three-year senior revolving credit facility that Cinergy Canada, Inc. entered into in December 2004 and that matures in December 2007.
Short-term Notes
In September 2005, Cinergy Corp., CG&E, PSI, and ULH&P entered into a five-year revolving credit facility with a termination date of September 2010 which can be extended twice, each extension for an additional one-year period. The new credit agreement replaces two existing credit agreements, one dated April 2004 and one dated December 2004.
The new credit agreement provides that the pending merger between Duke and Cinergy Corp. will not be considered a fundamental change or a “Change of Control” for purposes of the credit agreement.
For purposes of making borrowings, the new credit agreement does not require certain environmental, legal, or material adverse change representations and warranties that were in the credit agreements it replaced.
In our credit facility, Cinergy Corp. has covenanted to maintain:
• a consolidated net worth of $2 billion; and
• a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.
As part of CG&E’s $500 million sublimit under the $2 billion five-year credit facility, CG&E has covenanted to maintain:
• a consolidated net worth of $1 billion; and
• a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.
As part of PSI’s $500 million sublimit under the $2 billion five-year credit facility, PSI has covenanted to maintain:
• a consolidated net worth of $900 million; and
• a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.
As part of ULH&P’s $100 million sublimit under the $2 billion five-year credit facility, ULH&P has covenanted to maintain:
• a consolidated net worth of $200 million; and
• a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.
A breach of these covenants could result in the termination of the credit facility and the acceleration of the related indebtedness. In addition to breaches of covenants, certain other events that could result in the termination of the available credit and acceleration of the related indebtedness include:
• bankruptcy;
• defaults in the payment of other indebtedness; and
• judgments against the company that are not paid or insured.
The latter two events, however, are subject to dollar-based materiality thresholds. In no event shall a default on the part of CG&E, PSI, or ULH&P result solely from a default on the part of any other borrower, including Cinergy. As of December 31, 2005, Cinergy, CG&E, PSI, and ULH&P are in compliance with all of their debt covenants.
Variable Rate Pollution Control Notes
CG&E and PSI have issued certain variable rate pollution control notes (tax-exempt notes obtained to finance equipment or land development for pollution control purposes). Because the holders of these notes have the right to have their notes redeemed on a daily, weekly, or monthly basis, they are reflected in Notes payable and other short-term obligations on the Balance Sheets of Cinergy, CG&E, and PSI. At December 31, 2005, Cinergy, CG&E and PSI had $323 million, $112 million and $186 million, respectively, outstanding in variable rate pollution control notes, classified as short-term debt. ULH&P had no outstanding short-term pollution control notes. Any short-term
pollution control note borrowings outstanding do not reduce the unused and available short-term debt regulatory authority of CG&E, PSI, and ULH&P. See Note 7 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary data”.
Commercial Paper
Cinergy Corp.’s commercial paper program is supported by Cinergy Corp.’s $2 billion revolving credit facility. The commercial paper program supports, in part, the short-term borrowing needs of CG&E and PSI and eliminates their need for separate commercial paper programs. In September 2004, Cinergy Corp. expanded its commercial paper program from $800 million to a maximum outstanding principal amount of $1.5 billion. As of December 31, 2005, Cinergy Corp. had $515 million in commercial paper outstanding.
Money Pool
Cinergy Corp., Services, and our utility operating companies participate in a money pool arrangement to better manage cash and working capital requirements. Under this arrangement, those companies with surplus short-term funds provide short-term loans to affiliates (other than Cinergy Corp.) participating under this arrangement. This surplus cash may be from internal or external sources. The amounts outstanding under this money pool arrangement are shown as a component of Notes receivable from affiliated companies and/or Notes payable to affiliated companies on the Balance Sheets of CG&E, PSI, and ULH&P. Any money pool borrowings outstanding reduce the unused and available short-term debt regulatory authority of CG&E, PSI, and ULH&P.
Operating Leases
We have entered into operating lease agreements for various facilities and properties such as computer, communication and transportation equipment, and office space. See Note 8(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information regarding operating leases.
Capital Leases
Our utility operating companies are able to enter into capital leases subject to the authorization limitations of the applicable state utility commissions. New financing authority is subject to the approval of the respective commissions. PSI and CG&E have each filed an application with their respective utility commission requesting authority to enter into an additional $100 million of capital leases. An order from the PUCO is expected some time in February 2006, while an order from the Indiana Utility Regulatory Commission (IURC) is not expected until the second quarter of 2006. The following table presents further information related to the capital lease authorizations of CG&E, PSI, and ULH&P at December 31, 2005.
See Note 8(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information regarding capital leases.
Long-term Debt
We are required to secure authority to issue long-term debt from the state utility commissions of Ohio, Kentucky, and Indiana. The respective state utility commissions regulate the issuance of long-term debt by our utility operating companies.
PSI and CG&E have each filed an application with their respective utility commission requesting authority to issue up to $500 million of first mortgage bonds and senior and junior unsecured, up to $200 million of preferred securities, and up to $250 million of tax-exempt pollution control debt. We received an order from the PUCO approving our request in February 2006, while an order from the IURC is not expected until the second quarter of 2006.
A summary of our long-term debt authorizations at December 31, 2005, was as follows:
(1) Cinergy’s ability to issue long-term debt was previously limited by the PUHCA 1935. Pursuant to the Energy Policy Act of 2005, the PUHCA 1935 was repealed effective February 8, 2006 and was replaced with the PUHCA 2005 and other provisions of the Energy Policy Act of 2005 under the jurisdiction of the FERC. Upon the repeal of the PUHCA 1935, the long-term debt restrictions were terminated. For a discussion of the PUHCA 1935 repeal, see “Energy Policy Act of 2005” in “Liquidity and Capital Resources” and “FERC Public Utility Holding Company Act of 2005” in “Future Expectations/Trends.”
(2) Includes amounts for ULH&P.
(3) In October 2005, PSI issued $350 million principal amount of its 6.12% Debentures due October 15, 2035.
(4) In June 2005, the IURC granted PSI financing authority to borrow the proceeds from the issuance and sale of up to $250 million principal amount of tax-exempt securities through December 31, 2005. In October 2005, PSI borrowed the proceeds from the Indiana Finance Authority’s issuance of its $100 million principal amount of its Environmental Revenue Bonds.
(5) In April 2005, the Kentucky Public Service Commission (KPSC) granted ULH&P financing authority to issue and sell up to $500 million principal amount of secured and unsecured debt; enter into inter-company promissory notes up to an aggregate principal amount of $200 million; and borrow up to a maximum of $200 million aggregate principal amount of tax-exempt debt through December 31, 2006. This authority was predicated, in part, upon the completion of its transaction with CG&E in which ULH&P acquired interests in three of CG&E’s electric generating stations. See “Kentucky” in “Future Expectations/Trends” for further information regarding this transaction.
Cinergy Corp. has an effective shelf registration statement with the SEC relating to the issuance of up to $750 million in any combination of common stock, preferred stock, stock purchase contracts or unsecured debt securities, of which approximately $323 million remains available for issuance. CG&E has an effective shelf registration statement with the SEC relating to the issuance of up to $800 million in any combination of unsecured debt securities, first mortgage bonds, or preferred stock, all of which remains available for issuance. PSI has an effective shelf registration statement with the SEC relating to the issuance of up to $800 million in any combination of unsecured debt securities, first mortgage bonds, or preferred stock, of which $450 million remains available for issuance. We have filed a post effective amendment to deregister ULH&P’s securities.
Off-Balance Sheet Arrangements
Cinergy uses off-balance sheet arrangements from time to time to facilitate financing of various projects. Off-balance sheet arrangements are often created for a single specified purpose, for example, to facilitate securitization, leasing, hedging, or other transactions or arrangements. The following describes our major off-balance sheet arrangements excluding the investments Cinergy holds in various unconsolidated subsidiaries which are accounted for under the equity method. See Note 1(d)(ii) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information on the accounting for equity method investments.
(i) Guarantees
Cinergy has entered into various contracts that are classified as guarantees under Interpretation 45. For further information, see Note 13(c)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
(ii) Retained Interest in Assets Transferred to an Unconsolidated Entity
CG&E, PSI, and ULH&P have an agreement to sell certain of their accounts receivable and related collections. Cinergy Corp. formed Cinergy Receivables to purchase, on a revolving basis, nearly all of the retail accounts receivable and related collections of CG&E, PSI, and ULH&P. Cinergy Corp. does not consolidate Cinergy Receivables since it meets the requirements to be accounted for as a qualifying SPE. CG&E, PSI, and ULH&P each retain an interest in the receivables transferred to Cinergy Receivables. The transfer of receivables are accounted for as sales, pursuant to SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. For a more detailed discussion of our sales of accounts receivable, see Note 5(c) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
(iii) Derivative Instruments that are Classified as Equity
In 2001, Cinergy Corp. issued approximately $316 million notional amounts of combined securities, a component of which was stock purchase contracts. These contracts obligated the holder to purchase common shares of Cinergy Corp. stock by February 2005. Since the stock purchase contracts were detachable and classified in equity, the change in their fair value was not recorded in equity or earnings and therefore the stock purchase contracts were considered off-balance sheet arrangements. In January and February 2005, the stock purchase contracts were settled, resulting in the issuance of common stock that is recorded on Cinergy’s Balance Sheets as Common Stock Equity. For further information see Note 5(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
(iv) Variable Interest Entities (VIE)
Cinergy holds interests in VIEs, consolidated and unconsolidated, as defined by Interpretation 46. For further information, see
Note 5(d) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
Securities Ratings
As of January 31, 2006, the major credit rating agencies rated our securities as follows:
(1) Fitch Ratings (Fitch)
(2) Moody’s Investors Service (Moody’s)
(3) Standard & Poor’s Ratings Services (S&P)
The highest investment grade credit rating for Fitch is AAA, Moody’s is Aaal, and S&P is AAA.
The lowest investment grade credit rating for Fitch is BBB-, Moody’s is Baa3, and S&P is BBB-.
On May 10, 2005, S&P placed its ratings of Cinergy Corp. and its subsidiaries on CreditWatch with negative implications. This action was in response to the announcement of the pending merger of Duke and Cinergy and the uncertainty around the final details of the transaction. Fitch affirmed its existing ratings, noting that it anticipates the combined entity to achieve a credit profile similar to that of Cinergy. Moody’s has also affirmed its ratings, anticipating that no incremental debt will be issued as a result of the merger. See “Item 1. Business - Pending Merger” for a further discussion of the transaction.
In December 2005, Fitch elected to change the ratings methodology used to evaluate Cinergy Corp. as well as other companies. The result of this change in methodology was a one level decrease in the ratings of Cinergy Corp. This methodology change was not characterized by Fitch as a downgrade and was not caused by any change in the credit fundamentals of Cinergy.
A security rating is not a recommendation to buy, sell, or hold securities. These securities ratings may be revised or withdrawn at any time, and each rating should be evaluated independently of any other rating.
Equity
With the repeal of the PUHCA 1935, Cinergy is no longer subject to the SEC PUHCA 1935 capitalization limitations. See “Energy Policy Act of 2005” as previously discussed and “FERC Public Utility Holding Company Act of 2005” in “MD&A - Future Expectations/Trends.”
Cinergy issues new Cinergy Corp. common stock shares to satisfy obligations under certain of its employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan. Cinergy Corp. issued approximately 3.0 million shares in 2005 and approximately 3.9 million shares in 2004 to satisfy its obligations under these plans.
In December 2004, Cinergy Corp. issued 6.1 million shares of common stock under its January 2003 $750 million registration statement with the SEC. The net proceeds of $247 million were used to reduce short-term indebtedness.
In January and February 2005, Cinergy Corp. issued a total of 9.2 million shares of common stock pursuant to certain stock purchase contracts that were issued as a component of combined securities in December 2001. Net proceeds from the transaction of $316 million were used to reduce short-term debt. See Note 5(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further discussion of the securities.
In June 2005, Cinergy Corp. contributed $200 million in capital to PSI. The capital contribution was used to repay short-term indebtedness and is consistent with supporting PSI’s current credit ratings.
In January 2006, CG&E contributed approximately $140 million in capital to ULH&P in conjunction with the transfer of certain generating assets to ULH&P. See Note 22 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.
Cinergy Corp. owns all of the common stock of CG&E and PSI. All of ULH&P’s common stock is held by CG&E.
Dividend Restrictions
Cinergy Corp.’s ability to pay dividends to holders of its common stock is principally dependent on the ability of CG&E and PSI to pay Cinergy Corp. dividends on their common stock. Cinergy Corp., CG&E, and PSI cannot pay dividends on their common stock if their respective preferred stock dividends or preferred trust dividends are in arrears. The amount of common stock dividends that each company can pay is also limited by certain capitalization and earnings requirements under CG&E’s and PSI’s credit instruments. Currently, these requirements do not impact the ability of either company to pay dividends on its common stock. In addition, until consummation or termination of the merger with Duke, Cinergy is prohibited from paying dividends in excess of its historical levels without prior consent of Duke.
Other
Where subject to rate regulations, our utility operating companies have the ability to timely recover certain cash outlays through various regulatory mechanisms.
As opportunities arise, we will continue to monetize certain non-core investments, which would include our international assets and other technology investments.
MD&A - future expectations/trends
FUTURE EXPECTATIONS/TRENDS
In the “Future Expectations/Trends” section, we discuss developments in the electric and gas industry and other matters. Each of these discussions will address the current status and potential future impact on our financial position or results of operations.
Electric Industry
Regulatory Outlook and Significant Rate Developments
Currently, regulatory and legislative initiatives shaping the transition to a competitive retail market are the responsibilities of the individual states. Many states, including Ohio, have enacted electric utility deregulation legislation. In general, these initiatives have sought to separate the electric utility service into its basic components (generation, transmission, and distribution) and offer each component separately for sale. This separation is referred to as unbundling of the integrated services. Under the customer choice initiative in Ohio, we continue to transmit and distribute electricity; however, the customer can purchase electricity from any certified supplier. The following sections further discuss the current status of deregulation legislation and other significant regulatory developments in the states of Ohio, Indiana, and Kentucky, which encompass our utility service territories.
Ohio
Transfer of Duke Generating Assets
The merger agreement also provides that Duke and Cinergy will use their reasonable best efforts to transfer five generating stations located in the midwest from Duke to CG&E. This transfer will require regulatory approval by the FERC and, with respect to one plant located in Indiana the IURC. The FERC approved this transaction in December 2005. CG&E and the Duke affiliate that owns the interest in the Indiana plant filed an application with the IURC requesting approval for the transfer (as well as the declination by the IURC of jurisdiction over CG&E following the transfer) in October 2005. A final order approving the transfer and the IURC’s declination of jurisdiction over CG&E was received in February 2006. Duke and Cinergy intend to effectuate the transfer as an equity infusion into CG&E at book value. In conjunction with the transfer, Duke Capital LLC, a subsidiary of Duke, and CG&E intend to enter into a financial arrangement covering a multi-year period, to eliminate any potential cash shortfalls that may result from CG&E owning and operating the five stations. At this time, we cannot predict the outcome of this matter.
CG&E Electric Rate Filing
CG&E operates under an RSP which was approved by the PUCO in November 2004, and which expires December 31, 2008.
In March 2005, the Ohio Consumers’ Counsel appealed the Commission’s approval of the RSP to the Supreme Court of Ohio. We expect the court to decide the case in 2006. CG&E cannot predict the outcome of this matter.
CG&E has also filed a distribution rate case to recover certain distribution costs with rates becoming effective on January 1, 2006 and CG&E has deferred certain costs in 2004 and 2005 pursuant to its RSP. The parties to the proceeding agreed upon and filed a settlement setting the recommended annual revenue increase at approximately $51 million. In December 2005, the PUCO issued an order approving the settlement agreement.
The RSP provides for rate recovery through December 31, 2008. Although it is difficult to predict, it is likely that any one of three scenarios could exist after the rate stabilization period ends in 2008:
• The legislation could be repealed or revised to establish a return to regulation of electric generation;
• Deregulation and a competitive retail electric service market with market-based rates for all customer classes; or
• A hybrid of regulation and deregulation.
Although we cannot predict the regulatory outcome, we believe any of these scenarios could have a material impact on our financial position and results of operations. However, we believe that a return to regulation of electric generation would provide the least volatility in ongoing results, although likely accompanied by less opportunity for growth in earnings. See “CG&E Electric Rate Stabilization Plan” in “Item 1 - Business” for further discussion on RSP.
In December 2004, CG&E filed an application with the PUCO requesting recovery of future costs of additional generating facilities in Ohio, for either construction of new electric generating facilities or the purchase of existing assets currently owned by others. CG&E would seek recovery of these costs over the lives of the assets. These investments are needed to meet ongoing load growth by customers receiving generation service from CG&E and would enable the company to reliably meet its obligation as the provider of last resort for customers returning to CG&E from alternate suppliers. To maintain flexibility in providing electric service at the lowest cost, CG&E is also seeking the authority to purchase existing capacity and power from other suppliers and to earn a return commensurate with the risk from these agreements.
Indiana
We are not aware of any current plans for electric deregulation in Indiana.
Wheatland Generating Facility Acquisition
In August 2005, PSI acquired 100 percent of the 488 megawatts (MW) Wheatland Generating Facility from Allegheny Energy, Inc. for approximately $100 million. The Wheatland facility, located in Knox County, Indiana, has four natural gas-fired simple cycle combustion turbines and is directly connected to the Cinergy transmission system. The facility’s output will be used to bolster the reserve margins on the PSI system.
Integrated Coal Gasification Combined Cycle
Cinergy is studying the feasibility of constructing an IGCC generating station to help meet increased demand over the next decade. PSI would be a majority owner of the facility and operate it. An IGCC plant turns coal to gas, removing most of the SO2 and other emissions before the gas is used to fuel a combustion turbine generator. The technology uses less water and has fewer emissions than a conventional coal-fired plant with currently required pollution control equipment. Another benefit is the potential to remove mercury and carbon dioxide upstream of the combustion process at a lower cost than conventional plants. In August 2005, PSI and Vectren Energy Delivery of Indiana, Inc. filed a joint petition at the IURC seeking cost recovery of the feasibility study as well as engineering and preconstruction costs associated with the consideration and exploration of constructing an IGCC plant. If a decision is reached to move forward with constructing such a plant, PSI would seek approval from the IURC to begin construction. If approved, we would anticipate the IURC’s subsequent approval to include the assets in PSI’s rate base.
PSI Environmental Compliance Case
In November 2004, PSI filed a compliance plan case with the IURC seeking approval of PSI’s plan for complying with SO2, NOX, and mercury emission reduction requirements as discussed in Note 13(a)(i) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data", including approval of cost recovery and an overall rate of return of eight percent related to certain projects. PSI requested approval to recover the financing, depreciation, and operation and maintenance costs, among others, related to $1.08 billion in capital projects designed to reduce emissions of SO2, NOX, and mercury at PSI’s coal-burning generating stations. An evidentiary hearing was held in May 2005. In December 2005, PSI, the Indiana Office of the Utility Consumer Counselor, and the PSI Industrial Group filed a settlement agreement providing for approval of PSI’s compliance plan, and approval of financing, depreciation, and operation and maintenance cost recovery. The settlement agreement provides for 20-year depreciation in lieu of PSI’s originally requested 18-year depreciation, the use of PSI’s then weighted cost of capital to determine the overall rate of return rather than eight percent as originally requested, caps the amount of cost recovery for the Gallagher Generating Station baghouse projects, and removes
the Activated Carbon Injection component of those projects. A final IURC Order is expected in the first half of 2006.
Kentucky
We are not aware of any current plans for electric deregulation in Kentucky.
In January 2006, ULH&P completed the transfer from CG&E of CG&E’s approximately 69 percent ownership interest in the East Bend Station, located in Boone County, Kentucky, the Woodsdale Station, located in Butler County, Ohio, and one generating unit at the four-unit Miami Fort Station, located in Hamilton County, Ohio, and associated transactions. The transaction was effective as of January 1, 2006 at net book value. The final required regulatory approval was received in November 2005 from the SEC under the PUHCA of 1935. The KPSC and the FERC had earlier issued orders approving aspects of the transaction. The transaction will not affect current retail electric rates for ULH&P’s customers. Updated rates are expected to be implemented January 1, 2007 pursuant to a rate case to be filed in 2006 that incorporates the value of these assets into ULH&P’s rate base.
In connection with the transfer of these assets, ULH&P accepted a capital contribution from CG&E and assumed certain liabilities of CG&E. In particular, ULH&P agreed to assume from CG&E all payment, performance, and other obligations of CG&E, with respect to (i) certain tax-exempt pollution control debt currently shown on the balance sheet of CG&E, (ii) certain of CG&E’s outstanding Accounts payable to affiliated companies, and (iii) certain deferred tax liabilities related to the assets. ULH&P intends to repay the tax-exempt obligations with the proceeds from the issuance of tax-exempt debt at ULH&P. The accounts payable obligations will be repaid initially with the proceeds from short-term borrowings and eventually through the issuance of long-term senior unsecured debentures. The following table summarizes this transaction for ULH&P:
As part of this transaction, CG&E and ULH&P terminated the long-term wholesale power contract under which CG&E had previously supplied power to ULH&P. Further, CG&E also proposed to supply and ULH&P agreed to purchase back-up power from CG&E for planned and unplanned outages of the three generating plants through December 31, 2009 pursuant to a draft contract. The parties never executed this draft contract and ULH&P currently purchases backup power, when needed, through the Midwest ISO energy markets. Given changes in circumstances, including the implementation of the Midwest ISO Energy Markets Tariff, CG&E and ULH&P are planning to propose an alternative arrangement for supplying back-up power to ULH&P. At this time, whether and the conditions under which the KPSC may allow ULH&P to recover any increased costs for an alternative arrangement for the supply of back-up power are unknown and CG&E and ULH&P cannot determine the magnitude of any potential increased costs for back-up power.
ULH&P retail generation rates, including fuel cost recovery, are frozen until January 1, 2007. During 2006, fluctuation in fuel costs will cause volatility in ULH&P’s earnings.
FERC
The FERC has issued several notices of proposed rulemakings and inquiry on a variety of matters to implement provisions of the Energy Bill, among other things. In certain of the rulemaking proceedings, FERC has issued final rules. At this time, we cannot predict the outcome of these matters and whether they will have a material effect on our financial position or results of operations.
FERC Public Utility Holding Company Act of 2005
The Energy Policy Act of 2005, among other provisions, repealed the PUHCA 1935 and replaced it with the PUHCA 2005, effective February 8, 2006. The net effect of these legislative changes was to abolish the regulatory regime imposed under the PUHCA 1935, while at the same time enhancing FERC’s authority over mergers, acquisitions and dispositions, together with, pursuant to the provisions of the PUHCA 2005, FERC’s authority over books and records of holding companies, in order to assist the FERC and state utility regulators in protecting customers of regulated utilities. Among other provisions, the PUHCA 2005 grants FERC increased access to books
and records of holding companies and their affiliates and provides that, upon the request of a holding company system or state commission, the FERC will review and authorize the allocation of costs for non-power goods and services by centralized service companies to affiliates within holding company systems. In December 2005, the FERC adopted final rules further implementing the provisions of the PUHCA 2005. Among other things, these rules imposed certain limited filing and reporting obligations on holding companies such as Cinergy. See “Energy Policy Act of 2005” in “Liquidity and Capital Resources” for additional information on the Energy Policy Act of 2005.
FERC’s Market Screen Orders
In April 2004, the FERC issued an order establishing a new, interim set of market power screens for use in evaluating sales of wholesale power at market-based rates. In July 2004, the FERC issued an order generally affirming that order. In April 2004, the FERC also commenced a rulemaking to evaluate whether its overall test for market-based rates should be continued, and to determine a permanent market power test to replace the interim test. That rulemaking process remains pending. Under FERC’s currently effective generation market power screen, in a November 2005 order approving market-based rate tariffs for PSI, ULH&P, and Cinergy Marketing and Trading, LP (Marketing & Trading), FERC found that its generation market power standard was satisfied for approval of market-based rate authority. Should it ever be determined that Cinergy has market power in generation, and we are unable to successfully challenge this conclusion, it could result in the loss of market-based rate authority in certain regions of the wholesale market. Assuming such loss of market-based rate authority, Cinergy would be required to charge certain wholesale customers cost-based rates for wholesale sales of electricity. In February 2005, the FERC issued final rules that could require FERC review of previously granted authorization to sell at existing market-based rates. At this time, we cannot predict the outcome of these matters and whether they will have a material effect on our financial position or results of operations.
Global Climate Change
Presently, GHG emissions, which principally consist of CO2, are not regulated, and while several legislative proposals have been introduced in Congress to reduce utility GHG emissions, none have been passed. Nevertheless, we anticipate a mandatory program to reduce GHG emissions will exist in the future. We expect that any regulation of GHGs will impose costs on Cinergy. Depending on the details, any GHG regulation could mean:
• Increased capital expenditures associated with investments to improve plant efficiency or install CO2 emission reduction technology (to the extent that such technology exists) or construction of alternatives to coal generation;
• Increased operation and maintenance expense;
• Our older, more expensive generating stations may operate fewer hours each year because the addition of CO2 costs could cause their generation to be less economic; and
• Increased expenses associated with the purchase of CO2 emission allowances, should such an emission allowances market be created.
We would plan to seek recovery of the costs associated with a GHG program in rate regulated states where cost recovery is permitted.
In September 2003, Cinergy announced a voluntary GHG management commitment to reduce its GHG emissions during the period from 2010 through 2012 by five percent below our 2000 level, maintaining those levels through 2012. Cinergy expects to spend $21 million between 2004 and 2010 on projects to reduce or offset its GHG emissions. Cinergy is committed to supporting the President’s voluntary initiative, addressing shareholder interest in the issue, and building internal expertise in GHG management and GHG markets. Our voluntary commitment includes the following:
• Measuring and inventorying company-related sources of GHG emissions;
• Identifying and pursuing cost-effective GHG emission reduction and offsetting activities;
• Funding research of more efficient and alternative electric generating technologies;
• Funding research to better understand the causes and consequences of climate change;
• Encouraging a global discussion of the issues and how best to manage them; and
• Participating in discussions to help shape the policy debate.
Cinergy is also studying the feasibility of constructing a commercial IGCC generating station which would be “carbon capture ready” or have the potential to capture CO2 and then potentially sequester it underground. See “Integrated Coal Gasification Combined Cycle” discussed previously for more information.
Gas Industry
Significant Rate Developments
ULH&P Gas Rate Case
In 2002, the KPSC approved ULH&P’s gas base rate case requesting, among other things, recovery of costs associated with an accelerated gas main replacement program of up to $112 million over ten years. The approval allowed the costs to be recovered through a tracking mechanism for an initial three-year period expiring on September 30, 2005, with the possibility of renewal for up to ten years. The tracking mechanism allows ULH&P to recover depreciation costs and rate of return annually over the life of the assets. As of December 31, 2005, we have capitalized $61 million in costs associated with the accelerated gas main replacement program through this tracking mechanism, of which ULH&P has recovered $8.9 million. The Kentucky Attorney General has appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism and the tracking mechanism rates. In October 2005, both the Company and the KPSC filed with the Franklin Circuit Court, requesting dismissal of the case for failure to prosecute by the Kentucky Attorney General. At the present time, ULH&P cannot predict the timing or outcome of this litigation.
In February 2005, ULH&P filed a gas base rate case with the KPSC requesting approval to continue the tracking mechanism in addition to its request for a $14 million annual increase in base rates. A portion of the increase is attributable to including recovery of the current cost of the accelerated main replacement program in base rates. The KPSC did not rule on the base rate case request or the request to continue the tracking mechanism by October 1, 2005; consequently the initial tracking mechanism expired on September 30, 2005. In accordance with Kentucky law, ULH&P implemented the full amount of the requested rate increase on October 1, 2005. In December 2005, the KPSC approved an annual rate increase of $8.1 million and reapproved the tracking mechanism through 2011. Pursuant to the KPSC’s order, ULH&P filed a refund plan in January 2006 for the excess revenues collected since October 1, 2005. In February 2006, the KPSC issued an additional order responding to a rehearing request made by the Attorney General. Its rehearing order approved the Company’s refund plan which will result in refunds being provided to customers beginning in March 2006.
Gas Prices and Supply
Natural gas prices remained in the $8 - $9 per thousand cubic feet (Mcf) range through most of the summer due primarily to the warmer than normal summer and the increased use of gas to fire electric generation peaking units. Extensive damage to the natural gas infrastructure along the Gulf Coast caused by Hurricanes Katrina and Rita pushed the price of natural gas into the $12 - $14 per Mcf range by late September. Natural gas prices remained in the $12 per Mcf range for the remainder of 2005. Winter delivery prices for early 2006 remained in the $11 - $12 per Mcf range in the midwest or about 40 percent greater than last winter. Forward prices for the remainder of 2006 have now fallen below $10 per Mcf as more of the damaged Gulf Coast infrastructure comes online. Price movement is usually driven by the effects of weather conditions, availability of supply, and changes in demand and storage inventories. Currently, neither CG&E’s nor ULH&P’s gas delivery operations profit from changes in the cost of natural gas because natural gas purchase costs are passed directly to the customer dollar-for-dollar under the gas cost recovery mechanism that is mandated under state law.
ULH&P utilizes a price mitigation program designed to mitigate the effects of gas price volatility on customers, which the KPSC has approved through April 2008. The program allows the pre-arranging of between 20-75 percent of winter heating season base load gas requirements and up to 50 percent of summer season base load gas requirements. CG&E similarly mitigates its gas procurement costs; however, CG&E’s gas price mitigation program has not been pre-approved by the PUCO but rather it is subject to PUCO review as part of the normal gas cost recovery process.
CG&E and ULH&P use primarily long-term fixed price contracts and contracts with a ceiling and floor on the price. These contracts employ the normal purchases and sales scope exception, and do not involve hedge accounting under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133).
Inflation
We believe that the recent inflation rates do not materially impact our financial condition. However, under existing regulatory practice for all of PSI, ULH&P, and the non-generating portion of CG&E, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical plant costs may not be adequate to replace plant in future years.
Other Matters
Synthetic Fuel Production
Cinergy produces synthetic fuel from two facilities that qualify for tax credits (through 2007) in accordance with Section 29/45K of the IRC if certain requirements are satisfied. Cinergy’s sale of synthetic fuel has generated $339 million in tax credits through December 31, 2005. The IRS is currently auditing Cinergy for the 2002, 2003 and 2004 tax years. We expect the IRS will evaluate the various key requirements for claiming our Section 29/45K credits related to synthetic fuel. If the IRS challenges our Section 29/45K tax credits related to synthetic fuel, and such challenges are successful, this could result in the disallowance of up to all $339 million in previously claimed Section 29/45K tax credits for synthetic fuel produced by the applicable Cinergy facilities and a loss of our ability to claim future Section 29/45K tax credits for synthetic fuel produced by such facilities. We believe that we operate in conformity with all the necessary requirements to be allowed such tax credits under Section 29/45K.
Section 29/45K also provides for a phase-out of the credit based on the average price of crude oil during a calendar year. The phase-out is based on a prescribed calculation and definition of crude oil prices. Based on current crude oil prices and the recent volatility of such prices, we believe that for 2006 and 2007, the amount of the tax credits could be reduced. If oil prices are high enough, we will idle the plants, as the value of the credits would not exceed the net costs to produce the synthetic fuel. Net income related to these facilities for the twelve months ended December 31, 2005 was approximately $58 million. The net book value of our plants at December 31, 2005 was approximately $47 million.
Consolidation of Cinergy’s Power and Gas Marketing and Trading Businesses
Cinergy intends to consolidate CG&E’s power marketing and trading business into Marketing & Trading, its affiliate that primarily conducts gas marketing and trading. Counterparties will have a single set of contacts for credit, contracting, scheduling and settlements, as well as the ability to offset positions between natural gas and power. The consolidation should be largely complete by the end of the third quarter of 2006. In 2005, power marketing and trading comprised approximately 15 percent of CG&E’s net income.
Workforce Issues
Between 2006 and 2013, 43 percent of our workforce will be eligible for retirement. The loss of these employees could have a negative impact on Cinergy’s overall operations. Cinergy is preparing for this loss by (a) understanding our current employee profile (demographics), (b) identifying critical positions (considered core to our business and that have licensing or lengthy apprenticeship requirements associated with them), and (c) preparing an action plan. The action plan involves long-term staffing plans including such things as detailed recruitment plans, the utilization of co-ops and interns, identification of key employees, and strong succession planning. We will also use senior and phased retirement programs that allow new employees to train and consult with experienced highly-skilled employees post- and pre-retirement. In addition, we are exploring ways of accelerating and enhancing our training programs through collaboration with area educational institutions and other third party providers.
In conjunction with the pending merger, there is an anticipated reduction of approximately 1,500 employees of the combined company, from the May 2005 merger announcement, in various departments following consummation of
the merger. In February 2006, Cinergy adopted a severance benefits plan that will be binding on Duke Energy Holding Corp. after the consummation of Cinergy’s merger with Duke. The purpose of the plan is to provide certain benefits to qualifying employees of Cinergy whose employment is terminated in connection with the merger. This plan included a Voluntary Severance Program to targeted groups of employees with an election window from February 1 - 21, 2006 and is contingent on the successful consummation of the merger. At this time, we cannot predict the number of employees that will be voluntarily severed.
MD&A - MARKET RISK SENSITIVE INSTRUMENTS
MARKET RISK SENSITIVE INSTRUMENTS
Energy Commodities Sensitivity
The transactions associated with Commercial’s energy marketing and trading activities and substantial investment in generation assets give rise to various risks, including price risk. Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. As Commercial continues to develop its energy marketing and trading business, its exposure to movements in the price of electricity and other energy commodities may become greater. As a result, we may be subject to increased future earnings volatility.
Commercial’s energy marketing and trading activities principally consist of Marketing & Trading’s natural gas marketing and trading operations and CG&E’s power marketing and trading operations. See “Consolidation of Cinergy’s Power and Gas Marketing and Trading Business” in “Future Expectations/Trends - Other Matters.”
Our domestic operations market and trade over-the-counter (an informal market where the buying/selling of commodities occurs) contracts for the purchase and sale of electricity (primarily in the midwest region of the United States), natural gas, and other energy-related products, including coal and emission allowances. Our natural gas domestic operations provide services that manage storage, transportation, gathering and processing activities. In addition, our domestic operations also market and trade natural gas and other energy-related products on the New York Mercantile Exchange.
Marketing & Trading’s natural gas marketing and trading operations also extend to Canada where natural gas marketing and management services are provided to producers and industrial customers. Our Canadian operations also market and trade over-the-counter contracts as well as energy-related products on the New York Mercantile Exchange.
Many of these energy commodity contracts commit us to purchase or sell electricity, natural gas, and other energy-related products at fixed prices in the future. The majority of the contracts in the natural gas and other energy-related product portfolios are financially settled contracts (i.e., there is no physical delivery related with these items). In addition, Commercial also markets and trades over-the-counter option contracts. The use of these types of commodity instruments is designed to allow Commercial to:
• manage and economically hedge contractual commitments;
• reduce exposure relative to the volatility of cash market prices;
• take advantage of selected arbitrage opportunities; and
• originate customized transactions with municipalities and end-use customers.
Commercial structures and modifies its net position to capture the following:
• expected changes in future demand;
• seasonal market pricing characteristics;
• overall market sentiment; and
• price relationships between different time periods and trading regions.
At times, a net open position is created or is allowed to continue when Commercial believes future changes in prices and market conditions may possibly result in profitable positions. Position imbalances can also occur due to the basic lack of liquidity in the wholesale power market. The existence of net open positions can potentially result in an adverse impact on our financial condition or results of operations. This potential adverse impact could be realized if the market price of electric power does not react in the manner or direction expected. Cinergy’s Risk Management Control Policy contains limits associated with the overall size of net open positions for each trading operation.
Trading Portfolio Risks
Commercial measures the market risk inherent in the trading portfolio employing value at risk (VaR) analysis and other methodologies, which utilize forward price curves in electric power and natural gas markets to quantify estimates of the magnitude and probability of future value changes related to open contract positions. VaR is a statistical measure used to quantify the potential change in fair value of the trading portfolio over a particular period of time, with a specified likelihood of occurrence, due to market movement. Commercial, through some of our non-regulated subsidiaries, markets physical natural gas and electricity and trades derivative commodity instruments which are usually settled in cash including: forwards, futures, swaps, and options.
Any proprietary trading transaction, whether settled physically or financially, is included in the VaR calculation.
Our VaR is reported based on a 95 percent confidence interval, utilizing a one-day holding period. This means that on a given day (one-day holding period) there is a 95 percent chance (confidence level) that our trading portfolio will not lose more than the stated amount. We calculate VaR using a Monte Carlo simulation methodology using implied forward-looking volatilities and historical correlations.
The VaR for Cinergy’s and CG&E’s trading portfolio is presented in the table below:
Changes in Fair Value
The changes in fair value of the energy risk management assets and liabilities for Cinergy and CG&E for the years ended December 31, 2005 and 2004 are presented in the table below. PSI has not originated new power marketing and trading contracts since April of 2002 and therefore we have not presented PSI separately in the fair value tables below.
(1) The results of Cinergy also include amounts related to non-registrants.
(2) Represents changes in fair value recognized in income, caused by changes in assumptions used in calculating fair value or changes in modeling techniques.
(3) Represents changes in fair value recognized in income, primarily attributable to fluctuations in price. This amount includes both realized and unrealized gains on energy trading contracts.
(4) Represents a gas sales contract acquired at fair market value.
The following are the balances at December 31, 2005 and 2004 of our energy risk management assets and liabilities:
(1) The results of Cinergy also include amounts related to non-registrants.
The following table presents the expected maturity of the energy risk management assets and liabilities as of December 31, 2005 for Cinergy and CG&E:
(1) While liquidity varies by trading regions, prices actively quoted includes periods and locations for which quotes are regularly received from at least one source. This includes both exchange traded positions as well as over-the-counter positions quoted by brokers. Non-standard transactions are classified based on the extent, if any, of modeling used in determining fair value. Long-term transactions can have portions in both categories depending on the length.
(2) The results of Cinergy also include amounts related to non-registrants.
Generation Portfolio Risks
Cinergy optimizes the value of its non-regulated portfolio. The portfolio includes generation assets (power and capacity), fuel, and emission allowances and we manage all of these components as a portfolio. We use models that forecast future generation output, fuel requirements, and emission allowance requirements based on forward power, fuel and emission allowance markets. The component pieces of the portfolio are bought and sold based on this model in order to manage the economic value of the portfolio. With the issuance of SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (Statement 149), most forward power transactions and certain coal transactions from management of the portfolio are accounted for at fair value. The other component pieces of the portfolio are typically not subject to Statement 149 and are accounted for using the accrual method, where changes in fair value are not recognized. As a result, we are subject to earnings volatility via mark-to-market gains or losses from changes in the value of the contracts accounted for using fair value. A hypothetical $1.00 per MWh change consistently applied to all forward power prices would have resulted in a change in fair value of these contracts of approximately $4.8 million as of December 31, 2005. A hypothetical $1.00 per ton change consistently applied to all forward coal prices would have resulted in a change in fair value of these contracts of approximately $2.7 million as of December 31, 2005.
Cinergy is exposed to risk from changes in the market prices of fuel (primarily coal) and emission allowances to the extent the risk is not mitigated by regulatory recovery mechanisms in Ohio and Indiana. To the extent we must purchase fuel or emission allowances in a rising price environment, increased cost of electricity production could result without a corresponding increase in revenue. Cinergy manages this risk through the use of long-term fixed price fuel contracts and acquisitions of emission allowances. These risks at CG&E were partially mitigated in 2005 and are significantly mitigated from 2006 through 2008 by a retail fuel cost recovery mechanism established in Ohio as part of the RSP for non-residential customers beginning January 1, 2005 and for residential customers beginning January 1, 2006. This mechanism recovers costs for fuel and emission allowances that exceed the amount originally included in the rates frozen in the CG&E transition plan through December 31, 2008. PSI continues to be protected against market price changes of fuel and emission allowances costs incurred for its retail customers by the use of cost tracking and recovery mechanisms in the state of Indiana. In conjunction with the transfer of assets from CG&E to ULH&P, the transaction will not affect electric rates for ULH&P in 2006. Updated rates are expected to be implemented January 1, 2007 pursuant to a rate case to be filed in 2006 that incorporates these assets. Fluctuations in coal and emission allowance prices could impact ULH&P’s 2006 risks. See “Future Expectations/Trends - Kentucky” for additional information.
Credit Risk
Credit risk is the exposure to economic loss that would occur as a result of nonperformance by counterparties, pursuant to the terms of their contractual obligations. Specific components of credit risk include counterparty default risk, collateral risk, concentration risk, and settlement risk.
Trade Receivables and Physical Power Portfolio
Our concentration of credit risk with respect to trade accounts receivable from electric and gas retail customers is limited. The large number of customers and diversified customer base of residential, commercial, and industrial customers significantly reduces our credit risk. Contracts within the physical portfolio of power marketing and trading operations are primarily with traditional electric cooperatives and municipalities and other investor-owned utilities. At December 31, 2005, we believe the likelihood of significant losses associated with credit risk in our trade accounts receivable or physical power portfolio is remote.
Energy Trading Credit Risk
Cinergy’s extension of credit for energy marketing and trading is governed by a Corporate Credit Policy. Written guidelines approved by Cinergy’s Risk Policy Committee document the management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation procedures. Cinergy analyzes net credit exposure and establishes credit reserves based on the counterparties’ credit rating, payment history, and length of the outstanding obligation. Exposures to credit risks are monitored daily by the Corporate Credit Risk function, which is independent of all trading operations. Energy commodity prices can be extremely volatile and the market can, at times, lack liquidity. Because of these issues, credit risk for energy commodities is generally greater than with other commodity trading.
The following tables provide information regarding Cinergy’s and CG&E’s exposure on energy trading contracts as well as the expected maturities of those exposures as of December 31, 2005. The tables include accounts receivable and energy risk management assets, which are net of accounts payable and energy risk management liabilities with the same counterparties when we have the right of offset. The credit collateral shown in the following tables includes cash and letters of credit. As previously discussed, PSI’s remaining contracts are not material; therefore, we have not presented PSI separately in the credit risk tables below.
(1) Includes amounts related to non-registrants.
(2) Includes counterparties rated Investment Grade or the counterparties’ obligations are guaranteed or secured by an Investment Grade entity.
(3) Counterparties include a variety of entities, including investor-owned utilities, privately held companies, cities and municipalities. Cinergy assigns internal credit ratings to all counterparties within our credit risk portfolio, applying fundamental analytical tools. Included in this analysis is a review of (but not limited to) counterparty financial statements with consideration given to off-balance sheet obligations and assets, specific business environment, access to capital, and indicators from debt and equity capital markets.
(4) Exposures, positive or negative, with counterparties that are related to one another are not aggregated when no right of offset exists and as a result, credit is extended and evaluated on a separate basis.
(1) Includes counterparties rated Investment Grade or the counterparties’ obligations are guaranteed or secured by an Investment Grade entity.
(2) Counterparties include various cities and municipalities.
(3) Exposures, positive or negative, with counterparties that are related to one another are not aggregated when no right of offset exists and as a result, credit is extended and evaluated on a separate basis.
Financial Derivatives
Potential exposure to credit risk also exists from our use of financial derivatives such as interest rate swaps and treasury locks. Because these financial instruments are transacted with highly rated financial institutions, we do not anticipate nonperformance by any of the counterparties.
Risk Management
We manage, on a portfolio basis, the market risks in our energy marketing and trading transactions subject to parameters established by our Risk Policy Committee. Our market and credit risks are monitored by the Global Risk Management function to ensure compliance with stated risk management policies and procedures. The Global Risk Management function operates independently from the business units, which originate and actively manage the market risk exposures. Policies and procedures are periodically reviewed to assess their responsiveness to changing market and business conditions. Credit risk mitigation practices include requiring parent company guarantees, various forms of collateral, and the use of mutual netting/closeout agreements.
Exchange Rate Sensitivity
Cinergy has exposure to fluctuations in exchange rates between the United States dollar and the currencies of foreign countries where we have investments. When it is appropriate we will hedge our exposure to cash flow transactions.
Interest Rate Sensitivity
Our net exposure to changes in interest rates primarily consists of short-term debt instruments (including net money pool borrowings) and variable-rate pollution control debt. The following table reflects the different instruments used and the method of benchmarking interest rates, as of December 31, 2005:
(1) 30-day Federal Reserve “AA” Industrial Commercial Paper Composite Rate
(2) London Inter-Bank Offered Rate
The weighted-average interest rates on the previously discussed instruments at December 31, were as follows:
At December 31, 2005, forward yield curves project an increase in applicable short-term interest rates over the next five years.
The following table presents principal cash repayments, by maturity date and other selected information, for each registrant’s long-term debt, other debt, and capital lease obligations as of December 31, 2005:
(1) Includes amounts related to non-registrants.
(2) Long-term Debt includes amounts reflected as Long-term debt due within one year.
(3) The weighted-average interest rate is calculated as follows: (1) for Long-term Debt and Other, the weighted-average interest rate is based on the interest rates at December 31, 2005 of the debt that is maturing in the year reported and includes the effects of an interest rate swap that fixes the interest payments differently from the stated rate; and (2) for Capital Leases, the weighted-average interest rate is based on the average interest rate of the lease payments made during the year reported.
(4) Promissory notes and long-term notes payable related to investments under Cinergy Global Resources, Inc., Cinergy Investments, Inc., and debt related to CC Funding Trust. See Note 5(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for a discussion of the debt associated with the CC Funding Trust.
Our current policy in managing exposure to fluctuations in interest rates is to maintain approximately 30 percent of the total amount of outstanding debt in variable interest rate debt instruments. In maintaining this level of exposure, we use interest rate swaps. Under the swaps, we agree with other parties to exchange, at specified intervals, the difference between fixed-rate and variable-rate interest amounts calculated on an agreed upon notional amount. In the future, we will continually monitor market conditions to evaluate whether to modify our level of exposure to fluctuations in interest rates.
CG&E has an outstanding interest rate swap agreement that decreased the percentage of variable-rate debt. See Note 9(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information on financial derivatives.
MD&A - ACCOUNTING MATTERS
ACCOUNTING MATTERS
Critical Accounting Estimates
Preparation of financial statements and related disclosures in compliance with general accepted accounting principles (GAAP) requires the use of assumptions and estimates regarding future events, including the likelihood of success of particular investments or initiatives, estimates of future prices or rates, legal and regulatory challenges, and anticipated recovery of costs. Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions. We consider an accounting estimate to be critical if: (1) the accounting estimate requires us to make assumptions about matters that were reasonably uncertain at the time the accounting estimate was made, and (2) changes in the estimate are reasonably likely to occur from period to period.
These critical accounting estimates should be read in conjunction with the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”. We have other accounting policies that we consider to be significant; however, these policies do not meet the definition of critical accounting estimates, because they generally do not require us to make estimates or judgments that are particularly difficult or subjective.
Fair Value Accounting for Energy Marketing and Trading
We use fair value accounting for energy trading contracts, which is required, with certain exceptions, by Statement 133. Short-term contracts used in our trading activities are generally priced using exchange-based or over-the-counter price quotes. Long-term contracts typically must be valued using less actively quoted prices or valuation models. Use of model pricing requires estimating surrounding factors such as volatility and price curves beyond what is actively quoted in the market. In addition, some contracts do not have fixed notional amounts and therefore must be valued using estimates of volumes to be consumed by the counterparty. See “Changes in Fair Value” in “Market Risk Sensitive Instruments” for additional information.
We measure these risks by using complex analytical tools, both external and proprietary. These models are dynamic and are continuously updated with the most recent data to improve assessments of potential future outcomes. We measure risks for contracts that do not contain fixed notional amounts by obtaining historical data and projecting expected consumption. These models incorporate expectations surrounding the impacts that weather may play in future consumption. The results of these measures assist us in managing such risks within our portfolio. We also have a Global Risk Management function within Cinergy that is independent of the marketing and trading function and is under the oversight of a Risk Policy Committee comprised primarily of senior company executives. This group provides an independent evaluation of both forward price curves and the valuation of energy contracts. See “Trading Portfolio Risks” in “Market Risk Sensitive Instruments” for additional information.
There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Fair value accounting has risk, including its application to short-term contracts, as gains and losses recorded through its use are not yet realized. Therefore, it is possible that results in future periods may be materially different as contracts are ultimately settled. We monitor potential losses using VaR analysis. As previously discussed, our one-day VaR at December 31, 2005, assuming a 95 percent confidence level, was approximately $2.7 million, which means there is a 95 percent statistical chance (based on market implied volatilities) that any adverse moves in the value of our portfolio over one day will be less than the reported amount. In addition, our five-day VaR at December 31, 2005, assuming the same 95 percent confidence level, was approximately $6.1 million.
For financial reporting purposes, assets and liabilities associated with energy trading transactions accounted for using fair value are reflected on the Balance Sheets as Energy risk management assets current and non-current and Energy risk management liabilities current and non-current, classified as current or non-current pursuant to each contract’s length. Net gains and losses resulting from revaluation of contracts during the period are recognized currently in the Statements of Income.
Regulatory Accounting
CG&E, PSI, and ULH&P are regulated utility companies. Except with respect to the electric generation-related assets and liabilities of CG&E, the companies apply the provisions of SFAS No. 71, Accounting for the Effects of
Certain Types of Regulation (Statement 71). In accordance with Statement 71, regulatory actions may result in accounting treatment different from that of non-rate regulated companies. The deferral of costs (as regulatory assets) or amounts provided in current rates to cover costs to be incurred in the future (as regulatory liabilities) may be appropriate when the future recovery or refunding of such costs is probable. In assessing probability, we consider such factors as regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be recognized in current period earnings. Our calculations under the fuel adjustment and emission allowance cost recovery mechanisms at PSI (and CG&E for non-residential retail customers beginning in 2005 and residential retail customers in 2006) involve the use of estimates. Fuel costs (including purchased power when economically displacing fuel) and emission allowance costs must be allocated between PSI’s retail customers and wholesale customers, with the lowest costs allocated to retail customers. This process is complex and involves the use of estimates that when finalized in future periods may result in adjustments to amounts deferred and collected from customers.
At December 31, 2005, regulatory assets totaled $556 million for CG&E (including $8 million for ULH&P) and $514 million for PSI. Current rates include the recovery of $554 million for CG&E (including $6 million for ULH&P) and $465 million for PSI. In addition to the regulatory assets, CG&E and PSI have regulatory liabilities totaling $152 million (including $29 million for ULH&P) and $394 million at December 31, 2005, respectively. See Note 1(e) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional detail regarding regulatory assets and regulatory liabilities.
Income Taxes
Management judgment is required in developing our provision for income taxes, including the determination of deferred tax assets, deferred tax liabilities, and any valuation allowances recorded against the deferred tax assets. We evaluate quarterly the realizability of our deferred tax assets by assessing our valuation allowance and adjusting the amount of such allowance, if necessary. The factors used to assess the likelihood of realization are our forecast of future taxable income and the availability of tax planning strategies that can be implemented to realize deferred tax assets. These tax planning strategies include the utilization of Section 29/45K tax credits associated with our production of synthetic fuel.
Contingencies
When it is probable that an environmental, tax, or other legal liability has been incurred, a loss is recognized when the amount of the loss can be reasonably estimated. Estimates of the probability and the amount of loss are often made based on currently available facts, present laws and regulations, and consultation with third party experts. Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential liability. Management’s assessment of Cinergy’s exposure to contingencies could change to the extent there are additional future developments, administrative actions, or as more information becomes available. If actual obligations incurred are different from our estimates, the recognition of the actual amounts may have a material impact on Cinergy’s financial position and results of operations.
Impairment of Long-lived Assets
Current accounting standards require long-lived assets be measured for impairment whenever indicators of impairment exist. If deemed impaired under the standards, assets are written down to fair value with a charge to current period earnings. As a producer of electricity, Cinergy, CG&E, and PSI are owners of generating plants, which are largely coal-fired. At December 31, 2005, the carrying value of these generating plants is $5 billion for Cinergy, $2 billion for CG&E and $3 billion for PSI. As a result of the various emissions and by-products of coal consumption, the companies are subject to extensive environmental regulations and are currently subject to a number of environmental contingencies. See Note 13(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information. While we cannot predict the potential effect the resolution of these matters will have on the recoverability of our coal-fired generating assets, we believe that the carrying values of these assets are recoverable. When impairment indicators exist, management must make its best estimate of the price of wholesale electricity in the region, anticipated demand, and the cost of coal, natural gas, and emissions compliance. At PSI, we also consider the expected ability to recover through the regulatory process any additional investments in environmental compliance expenditures.
For the natural gas-fired peaking plants that Cinergy owns that are not subject to cost-of-service-based ratemaking, the recoverability will be dependent on many factors, but primarily the price of power compared to the cost of natural gas, often referred to as the spark spread, over the life of the plants. Given that power and gas prices are generally not observable beyond three to five years, management must make estimates of future commodity prices for a significant portion of the life of the plants, which is lengthy given that these plants are reasonably new. Cinergy uses macro-economic fundamental modeling to estimate these future values. While we currently believe these assets are recoverable on a nominal basis, changes in the estimates and assumptions used (primarily power and gas prices along with their related volatilities) in evaluating these assets over their useful life could result in a material impairment in the future. At December 31, 2005, the carrying value of these gas-fired peaking plants is approximately $400 million. GAAP does not require us to estimate the fair value of these assets because they are recoverable on a nominal basis. However, we believe the fair value of these plants to be substantially below their carrying value.
We will continue to evaluate these assets for impairment when events or circumstances indicate the carrying value may not be recoverable.
Impairment of Unconsolidated Investments
We evaluate the recoverability of investments in unconsolidated subsidiaries when events or changes in circumstances indicate the carrying amount of the asset is other than temporarily impaired. An investment is considered impaired if the fair value of the investment is less than its carrying value. We only recognize an impairment loss when an impairment is considered to be other than temporary. We consider an impairment to be other than temporary when a forecasted recovery up to the investment’s carrying value is not expected for a reasonable period of time. We evaluate several factors, including but not limited to our intent and ability to hold the investment, the severity of the impairment, the duration of the impairment and the entity’s historical and projected financial performance, when determining whether or not impairment is other than temporary.
Fair value is determined by quoted market prices, when available, however in most instances we rely on valuations based on discounted cash flows and market multiples. There are many significant assumptions involved in performing such valuations, including but not limited to forecasted financial performance, discount rates, earnings multiples and terminal value considerations. Variations in any one or a combination of these assumptions could result in different conclusions regarding impairment.
Once an investment is considered other than temporarily impaired and an impairment loss is recognized, the carrying value of the investment is not adjusted for any subsequent recoveries in fair value. As of December 31, 2005, we do not have any material unrealized losses that are deemed to be temporary in nature. See Note 17(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for the amount of impairment charges incurred during the year.
Accounting Changes
Asset Retirement Obligations
In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement 143 (Interpretation 47). Statement 143 requires recognition of legal obligations associated with the retirement or removal of long-lived assets at the time the obligations are incurred. Interpretation 47 clarifies that a conditional asset retirement obligation (which occurs when the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity) is a legal obligation within the scope of Statement 143. As such, the fair value of a conditional asset retirement obligation must be recognized as a liability when incurred if the liability’s fair value can be reasonably estimated. Interpretation 47 also clarifies when sufficient information exists to reasonably estimate the fair value of an asset retirement obligation.
We adopted Interpretation 47 on December 31, 2005 and recorded multiple asset retirement obligations as a result. These asset retirement obligations primarily related to obligations associated with retiring gas mains, recorded by
Cinergy, CG&E, and ULH&P, and future asbestos abatement at certain generating stations, recorded by Cinergy, CG&E, and PSI.
Cinergy and CG&E recognized a loss of approximately $3 million (net of tax) for the cumulative effect of this change in accounting principle. The cumulative effect resulted from asset retirement obligations primarily associated with our non-regulated generating assets. See (s)(iv) for a summary of cumulative effect adjustments. The effect of adoption for Cinergy, CG&E, PSI, and ULH&P included balance sheet reclassifications of approximately $35 million, $27 million, $8 million, and $5 million, respectively, from Regulatory liabilities. See discussion of Regulatory liabilities previously disclosed in (e). The increases in asset retirement obligations from adopting Interpretation 47 were $51 million, $39 million, $12 million and $6 million for Cinergy, CG&E, PSI, and ULH&P, respectively.
Pro-forma results as if Interpretation 47 was applied retroactively for the years ended December 31, 2005, 2004, and 2003 are not materially different from reported results. The December 31, 2004 and December 31, 2003 pro-forma liabilities for asset retirement obligations recorded as a result of the adoption of Interpretation 47 are not materially different than the December 31, 2005 balances.
Share-Based Payment
In December 2004, the FASB issued a replacement of SFAS No. 123, Accounting for Stock-Based Compensation (Statement 123), SFAS No. 123 (revised 2004), Share-Based Payment (Statement 123R). This standard will require, among other things, accounting for all stock-based compensation arrangements under the fair value method. The standard also requires compensation awards that involve the achievement of a certain company stock price (or similar measure) to have the likelihood of reaching those targets incorporated into the fair value of the award. The number of awards paid out under Cinergy’s performance-based share awards under the Cinergy Corp. 1996 Long-Term Incentive Compensation Plan (LTIP) is based on Cinergy’s expected total shareholder return (TSR) as measured against a pre-defined peer group. Therefore, these awards are required to be re-valued at fair value upon adoption.
We adopted Statement 123R on January 1, 2006 using the modified prospective application. Cinergy recognized an immaterial loss for the cumulative effect of this change in accounting principle. The cumulative effect is due to the use of a new model that incorporates the expected TSR into the fair value of Cinergy’s performance-based share awards under the LTIP. This model is used to value all grants of future performance-based share awards under the LTIP, beginning January 1, 2006.
In 2003, we prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of Statement 123, as amended by SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123, for all employee awards granted or with terms modified on or after January 1, 2003. Therefore, the impact of implementation of Statement 123R on stock options and remaining awards, other than the aforementioned performance-based share awards, within our stock-based compensation plans was not material. See additional detail regarding Cinergy’s stock-based compensation plans in Note 3(c).
Income Taxes
In October 2004, the American Jobs Creation Act (AJCA) was signed into law. The AJCA includes a one-time deduction of 85 percent of certain foreign earnings that are repatriated, as defined in the AJCA. The repatriation of foreign earnings pursuant to this provision did not have a material impact on our financial position or results of operations.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to the “Market Risk Sensitive Instruments” section of “Item 7. MD&A.”
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
The information required to be submitted in schedules other than those indicated previously, have been included in the Balance Sheets, the Statements of Income, related schedules, the notes thereto, or omitted as not required by the Rules of Regulation S-X.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Cinergy Corp.
Cincinnati, Ohio
We have audited the accompanying consolidated balance sheets and statements of capitalization of Cinergy Corp. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule included in Item 15 of this Annual Report. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Cinergy Corp. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the financial statements, in 2005, Cinergy Corp. adopted Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” In 2003, Cinergy Corp. adopted Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations;” Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities;” and the fair value recognition provisions of SFAS No. 123 “Accounting for Stock-Based Compensation.”
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 17, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Cincinnati, Ohio
February 17,
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of The Cincinnati Gas & Electric Company
Cincinnati, Ohio
We have audited the accompanying consolidated balance sheets and statements of capitalization of The Cincinnati Gas & Electric Company and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule included in Item 15 of this Annual Report. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Cincinnati Gas & Electric Company and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the financial statements, in 2005, The Cincinnati Gas & Electric Company adopted Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” In 2003, The Cincinnati Gas & Electric Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Cincinnati, Ohio
February 17,
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of PSI Energy, Inc.
Plainfield, IN
We have audited the accompanying consolidated balance sheets and statements of capitalization of PSI Energy, Inc. and subsidiary as of December 31, 2005 and 2004, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule included in Item 15 of this Annual Report. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of PSI Energy, Inc. and subsidiary as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the financial statements, in 2005, PSI Energy, Inc. adopted Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” In 2003, PSI Energy, Inc. adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Cincinnati, Ohio
February 17,
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of The Union Light, Heat and Power Company
Cincinnati, Ohio
We have audited the accompanying balance sheets and statements of capitalization of The Union Light, Heat and Power Company as of December 31, 2005 and 2004, and the related statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule included in Item 15 of this Annual Report. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Union Light, Heat and Power Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the financial statements, in 2005, The Union Light, Heat and Power Company adopted Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” In 2003, The Union Light, Heat and Power Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Cincinnati, Ohio
February 17,
CINERGY CORP.
AND SUBSIDIARY COMPANIES
CINERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
THE CINCINNATI GAS &
ELECTRIC COMPANY
AND SUBSIDIARY COMPANIES
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
AND SUBSIDIARY COMPANY
PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
psi energy, inc.
consolidated statements of capitalization
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
THE UNION LIGHT, HEAT
AND POWER COMPANY
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF INCOME
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CASH FLOWS
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CAPITALIZATION
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
NOTES TO FINANCIAL STATEMENTS
In this report Cinergy (which includes Cinergy Corp. and all of our regulated and non-regulated subsidiaries) is, at times, referred to in the first person as “we,” “our,” or “us.” In addition, when discussing Cinergy’s financial information, it necessarily includes the results of The Cincinnati Gas & Electric Company (CG&E), PSI Energy, Inc. (PSI), The Union Light, Heat and Power Company (ULH&P) and all of Cinergy’s other consolidated subsidiaries. When discussing CG&E’s financial information, it necessarily includes the results of ULH&P and all of CG&E’s other consolidated subsidiaries.
1. Organization and Summary of Significant Accounting Policies
(a) Pending Merger
On May 8, 2005, Cinergy Corp. entered into an agreement and plan of merger with Duke Energy Corporation (Duke), a North Carolina corporation, whereby Cinergy Corp. will be merged with Duke. Under the merger agreement, each share of Cinergy Corp. common stock will be converted into 1.56 shares of common stock of the newly formed company, Duke Energy Holding Corp. (Duke Energy Holding).
The merger agreement has been approved by both companies’ Boards of Directors. Consummation of the merger is subject to customary conditions, including, among others, the approval of the shareholders of both companies and the approvals of various regulatory authorities. See Note 2 for further information regarding the pending merger.
(b) Nature of Operations
Cinergy Corp., a Delaware corporation organized in 1993, owns all outstanding common stock of CG&E and PSI, both of which are public utilities, as well as Cinergy Investments, Inc. (Investments), its non-regulated investment holding company.
CG&E, an Ohio corporation organized in 1837, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through ULH&P, in nearby areas of Kentucky. CG&E is responsible for the majority of our power marketing and trading activity. CG&E’s principal subsidiary, ULH&P, a Kentucky corporation organized in 1901, provides electric and gas service in northern Kentucky.
PSI, an Indiana corporation organized in 1942, is a vertically integrated and regulated electric utility that provides service in north central, central, and southern Indiana.
The following table presents further information related to the operations of our domestic utility companies CG&E, PSI, and ULH&P (our utility operating companies):
Principal Line(s) of Business
CG&E and subsidiaries
• Generation, transmission, and distribution of electricity
• Sale and/or transportation of natural gas
• Electric commodity marketing and trading operations
PSI
• Generation, transmission, and distribution of electricity
ULH&P(1)
• Transmission and distribution of electricity
• Sale and transportation of natural gas
(1)
See Note 22 for further discussion of the transfer of certain generation assets in January 2006. Following the transfer, ULH&P has generation as a principal line of business.
The following table presents further information related to the operations of our other principal subsidiaries, Cinergy Services, Inc. (Services) and Investments:
Principal Services and
Line(s) of Business
Services(1)
• Administrative services
• Management services
• Support services
Investments
• Cogeneration and energy efficiency investments
• Natural gas marketing and trading operations(2)
(1)
Services provides the noted services to our subsidiaries.
(2)
Natural gas marketing and trading operations are primarily conducted through Cinergy Marketing & Trading, LP (Marketing & Trading), one of its subsidiaries.
We conduct operations through our subsidiaries and manage our businesses through the following three reportable segments:
• Regulated Business Unit (Regulated);
• Commercial Business Unit (Commercial); and
• Power Technology and Infrastructure Services Business Unit (Power Technology and Infrastructure).
See Note 18 for further discussion of our reportable segments.
(c) Repeal of the Public Utility Holding Company Act of 1935 (PUHCA 1935) and Establishment of the Federal Energy Regulatory Commission (FERC) Public Utility Holding Company Act of 2005 (PUHCA 2005)
Because Cinergy is a utility holding company, we are registered with the Securities and Exchange Commission (SEC) and were subject to regulation under the PUHCA 1935. The Energy Policy Act of 2005, among other provisions, repealed the PUHCA 1935 and replaced it with the PUHCA 2005, under the jurisdiction of the FERC, effective February 8, 2006. The net effect of these legislative changes was to abolish the regulatory regime imposed under the PUHCA 1935, while at the same time, enhancing the FERC’s authority over books and records of holding companies, in order to assist the FERC and state utility regulators in protecting customers of regulated utilities. In December 2005, the FERC adopted final rules further implementing the provisions of the PUHCA 2005. Among other things, these rules impose certain limited filing and reporting obligations on holding companies such as Cinergy. At this time, it is too early to predict the overall impact that the Energy Policy Act of 2005 will have on our financial position or results of operations.
(d) Presentation
Management makes estimates and assumptions when preparing financial statements under generally accepted accounting principles (GAAP). Actual results could differ, as these estimates and assumptions involve judgment about future events or performance. These estimates and assumptions affect various matters, including:
• the reported amounts of assets and liabilities in our Balance Sheets at the dates of the financial statements;
• the disclosure of contingent assets and liabilities at the dates of the financial statements; and
• the reported amounts of revenues and expenses in our Statements of Income during the reporting periods.
We have restated certain prior-year amounts in Cinergy’s financial statements, including cash flows to reflect the impact of discontinued operations in 2005. For a further discussion of discontinued operations, see Note 16. Additionally, we have reclassified certain prior-year amounts in the financial statements of Cinergy, CG&E, PSI, and ULH&P to conform to current presentation.
We use three different methods to report investments in subsidiaries or other companies: the consolidation method; the equity method; and the cost method.
(i) Consolidation Method
For traditional operating entities, we use the consolidation method when we own a majority of the voting stock of or have the ability to control a subsidiary. For variable interest entities (VIE) (discussed further in Note 5), we use the consolidation method when we anticipate absorbing a majority of the losses or receiving a majority of the returns of an entity, should they occur. We eliminate all significant intercompany transactions when we consolidate these accounts. Our consolidated financial statements include the accounts of Cinergy, CG&E, and PSI, and their wholly-owned subsidiaries.
(ii) Equity Method
We use the equity method to report investments, joint ventures, partnerships, subsidiaries, and affiliated companies in which we do not have control, but have the ability to exercise influence over operating and financial policies (generally, 20 percent to 50 percent ownership). Under the equity method we report:
• our investment in the entity as Investments in unconsolidated subsidiaries in our Balance Sheets; and
• our percentage share of the earnings from the entity as Equity in earnings of unconsolidated subsidiaries in our Statements of Income.
(iii) Cost Method
We use the cost method to report investments, joint ventures, partnerships, subsidiaries, and affiliated companies in which we do not have control and are unable to exercise significant influence over operating and financial policies (generally, up to 20 percent ownership). Under the cost method, we report our investments in the entity as Other investments in our Balance Sheets.
(e) Regulation
Our utility operating companies and certain of our non-utility subsidiaries must comply with the rules prescribed by the SEC under the PUHCA 1935, through February 8, 2006. The PUHCA 1935 was replaced with the PUHCA 2005, under the FERC’s jurisdiction, as previously discussed in (c). Our utility operating companies must also comply with the other rules prescribed by the FERC and the applicable state utility commissions of Ohio, Indiana, and Kentucky.
Our utility operating companies use the same accounting policies and practices for financial reporting purposes as non-regulated companies under GAAP. However, sometimes actions by the FERC and the state utility commissions result in accounting treatment different from that used by non-regulated companies. When this occurs, we apply the provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (Statement 71). In accordance with Statement 71, we record regulatory assets and liabilities (expenses deferred for future recovery from customers or amounts provided in current rates to cover costs to be incurred in the future, respectively) on our Balance Sheets.
The state of Ohio passed comprehensive electric deregulation legislation in 1999, and in 2000, the Public Utilities Commission of Ohio (PUCO) approved a stipulation agreement relating to CG&E’s transition plan creating a Regulatory Transition Charge (RTC) designed to recover CG&E’s generation-related regulatory assets and transition costs over a ten-year period beginning January 1, 2001. Accordingly, application of Statement 71 was discontinued for the generation portion of CG&E’s business.
In November 2004, the PUCO approved CG&E’s Electric Rate Stabilization Plan (RSP) which expires December 31, 2008. The features of the RSP were applied to non-residential customers beginning January 1, 2005 and January 1, 2006 for residential customers. The major features of the RSP are:
• A Provider of Last Resort (POLR) charge which consists of:
• An Annually Adjusted Component intended to provide cost recovery primarily for environmental compliance expenditures;
• An Infrastructure Maintenance Fund charge intended to compensate CG&E for committing its physical capacity; and
• A System Reliability Tracker intended to provide actual cost recovery for capacity purchases, purchased power, reserve capacity, and related market costs for purchases to meet capacity needs.
• Generation rates and fuel recovery which consists of the establishment of market rates for generation service and a fuel cost recovery mechanism. See Note 13(b)(iii) for more information; and
• Transmission cost recovery which permits CG&E to recover Midwest Independent Transmission System Operator, Inc. (Midwest ISO) charges, all FERC approved transmission costs, and all congestion costs allocable to retail ratepayers that receive services from CG&E.
Excluding CG&E’s deregulated generation-related assets and liabilities, as of December 31, 2005, CG&E, PSI, and ULH&P continue to meet the criteria to apply Statement 71. If Indiana or Kentucky were to implement deregulation legislation, the application of Statement 71 would need to be reviewed. Based on our utility operating companies’ current regulatory orders and the regulatory environment in which they currently operate, the recovery of regulatory assets recognized in the accompanying Balance Sheets, as of December 31, 2005, is probable. For a further discussion of CG&E’s regulatory developments, see Note 13(b)(iii). For a further discussion of PSI’s regulatory developments, see Notes 13(b)(i) and 13(b)(ii).
Our regulatory assets, liabilities, and amounts authorized for recovery through regulatory orders at December 31, 2005 and 2004, were as follows:
(1)
Includes $8 million at December 31, 2005, and $10 million at December 31, 2004, related to ULH&P’s regulatory assets. Of these amounts, $6 million at December 31, 2005, and $9 million at December 31, 2004, have been authorized for recovery. Includes $(29) million and $(30) million of regulatory liabilities at December 31, 2005 and 2004, respectively, related to ULH&P.
(2)
The various regulatory commissions overseeing the regulated business operations of our utility operating companies regulate income tax provisions reflected in customer rates. In accordance with the provisions of Statement 71, we have recorded net regulatory assets for CG&E, PSI, and ULH&P.
(3)
PSI reached an agreement with Dynegy, Inc. to purchase the remainder of its 25-year contract for coal gasification services. In accordance with an order from the Indiana Utility Regulatory Commission (IURC), PSI began recovering this asset over an 18-year period that commenced upon the termination of the gas services agreement in 2000.
(4)
Regulatory assets earning a return at December 31, 2005.
(5)
For PSI, this amount includes $35 million that is authorized for recovery but is not earning a return and $42 million that is not yet authorized for recovery and is not earning a return at December 31, 2005.
(6)
In August 2000, CG&E’s deregulation transition plan was approved. Effective January 1, 2001, a RTC went into effect and provides for recovery of all then existing generation-related regulatory assets and various transition costs over a ten-year period. Because a separate charge provides for recovery, these assets were aggregated and are included as a single amount in this presentation. The classification of all transmission and distribution related regulatory assets has remained the same.
(7)
In November 2004, CG&E’s RSP was approved by the PUCO. CG&E had the ability to defer certain capital-related distribution costs from July 1, 2004 through December 31, 2005 with recovery from non-residential customers to be provided through a rider from January 1, 2006 through December 31, 2010.
(8)
Represents authorized recoverable expenses and/or returnable revenues that will be billed and collected or returned at a future date, in connection with PSI’s fuel cost recovery mechanism and Midwest ISO cost recovery mechanism.
(9)
At December 31, 2005, these amounts were being recovered through rates charged to customers over remaining periods ranging from 1 to 60 years for CG&E, 1 to 36 years for PSI, and 1 to 15 years for ULH&P.
(10)
Represents amounts received for anticipated future removal and retirement costs of regulated property, plant, and equipment that do not represent legal obligations pursuant to SFAS No. 143, Accounting for Asset Retirement Obligations (Statement 143). See Note 1(l) for a further discussion of Statement 143.
(f) Revenue Recognition
(i) Utility Revenues
Our utility operating companies record Operating Revenues for electric and gas service when delivered to customers. Customers are billed throughout the month as both gas and electric meters are read. We recognize revenues for retail energy sales that have not yet been billed, but where gas or electricity has been consumed. This is termed “unbilled revenues” and is a widely recognized and accepted practice for utilities. In making our estimates of unbilled revenues, we use systems that consider various factors, including weather, in our calculation of retail customer consumption at the end of each month. Given the use of these systems and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when these amounts are subsequently billed.
Unbilled revenues for Cinergy, CG&E, PSI, and ULH&P as of December 31, 2005, 2004, and 2003 were as follows:
(ii) Energy Marketing and Trading Revenues
We market and trade electricity, natural gas, and other energy-related products. Many of the contracts associated with these products qualify as derivatives in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133), further discussed in (m)(i). We designate derivative transactions as either trading or non-trading at the time they are originated in accordance with Emerging Issues Task Force (EITF) Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3).
1. Net Reporting
Net reporting requires presentation of realized and unrealized gains and losses on trading derivatives on a net basis in Operating Revenues pursuant to the requirements of EITF 02-3, regardless of whether the transactions were settled physically. Energy derivatives involving frequent buying and selling with the objective of generating profits from differences in price are classified as trading and reported net.
2. Gross Reporting
Gross reporting requires presentation of sales contracts in Operating Revenues and purchase contracts in Fuel, emission allowances, and purchased power expense or Gas purchased expense. Non-trading derivatives typically involve physical delivery of the underlying commodity and are therefore generally presented on a gross basis.
Derivatives are classified as non-trading only when (a) the contracts involve the purchase of gas or electricity to serve our native load requirements (end-use customers within our utility operating companies’ franchise service territories), or (b) the contracts involve the sale of gas or electricity and we have the intent and projected ability to fulfill the majority of the obligations from company-owned assets, which generally is limited to the sale of generation to third parties when it is not required to meet native load requirements.
(iii) Other Operating Revenues
Cinergy and CG&E recognize revenue from coal origination, which represents marketing of physical coal. These revenues are included in Other Operating Revenues on the Statements of Income. Other Operating Revenues for Cinergy also includes sales of synthetic fuel.
(g) Energy Purchases and Fuel Costs
The expenses associated with electric and gas services include:
• fuel used to generate electricity and the associated transportation costs;
• costs of emission allowances;
• electricity purchased from others; and
• natural gas purchased from others and the associated transportation costs.
These expenses are shown in the Statements of Income of Cinergy, CG&E, and PSI as Fuel, emission allowances, and purchased power expense and Gas purchased expense. These expenses are shown in ULH&P’s Statements of Income as Electricity purchased from parent company for resale expense and Gas purchased expense.
PSI utilizes a cost tracking recovery mechanism (commonly referred to as a fuel adjustment clause) that recovers retail and a portion of its wholesale fuel costs from customers. Indiana law limits the amount of fuel costs that PSI can recover to an amount that will not result in earning a return in excess of that allowed by the IURC. The fuel adjustment clause is calculated based on the estimated cost of fuel in the next three-month period, and is trued up after actual costs are known. PSI records any under-recovery or over-recovery resulting from the differences between estimated and actual costs as a regulatory asset or liability until it is billed or refunded to its customers, at which point it is adjusted through fuel expense.
In addition to the fuel adjustment clause, PSI utilizes a purchased power tracking mechanism approved by the IURC for the recovery of costs related to certain specified purchases of power necessary to meet native load peak demand requirements to the extent such costs are not recovered through the existing fuel adjustment clause.
As part of the PUCO’s November 2004 approval of CG&E’s RSP, a cost tracking recovery mechanism was established to recover costs of retail fuel and emission allowances that exceed the amount originally included in the rates frozen in the CG&E transition plan. This mechanism was effective January 1, 2005 for non-residential customers and January 1, 2006 for residential customers. CG&E began utilizing a tracking mechanism approved by the PUCO for the recovery of system reliability capacity costs related to certain specified purchases of power. This mechanism was effective January 1, 2005 for non-residential customers and January 1, 2006 for residential customers. Because CG&E does not apply Statement 71 to its generation operations, differences between fuel costs billed and costs incurred are not recorded as regulatory assets or liabilities.
(h) Cash and Cash Equivalents
We define Cash and cash equivalents on our Balance Sheets and Statements of Cash Flows as investments with maturities of three months or less when acquired.
(i) Fuel, Emission Allowances, and Supplies
We maintain coal inventories for use in the production of electricity, emission allowances inventories for regulatory compliance purposes due to the production of electricity, and gas inventories both as part of Investments’ trading business as well as for CG&E’s gas distribution business. These inventories are accounted for at the lower of cost or market, with cost being determined using the weighted-average method.
Materials and supplies inventory is accounted for on a weighted-average cost basis.
(j) Property, Plant, and Equipment
Property, Plant, and Equipment includes the utility and non-regulated business property and equipment that is in use, being held for future use, or under construction. We report our Property, Plant, and Equipment at its original cost, which includes:
• materials;
• contractor fees;
• salaries;
• payroll taxes;
• fringe benefits;
• financing costs of funds used during construction (described in (ii) and (iii)); and
• other miscellaneous amounts.
We capitalize costs for regulated property, plant, and equipment that are associated with the replacement or the addition of equipment that is considered a property unit. Property units are intended to describe an item or group of
items. The cost of normal repairs and maintenance is expensed as incurred. On an annual basis, we perform major pre-planned maintenance activities on our generating units. These pre-planned activities are expensed when incurred. When regulated property, plant, and equipment is retired, Cinergy charges the original cost, less salvage, to Accumulated depreciation and the cost of removal to Regulatory liabilities, which is consistent with the composite method of depreciation. See (l) for further information on accrued cost of removal. A gain or loss is recorded on the sale of regulated property, plant, and equipment if an entire operating unit, as defined by the FERC, is sold. A gain or loss is recorded on non-regulated property, plant, and equipment whenever there is a related sale or retirement.
(i) Depreciation
We determine the provisions for depreciation expense using the straight-line method. The depreciation rates are based on periodic studies of the estimated useful lives and the net cost to remove the properties. Inclusion of cost of removal in depreciation rates was discontinued for all non-regulated property beginning in 2003, as a result of adopting Statement 143. Our utility operating companies use composite depreciation rates. These rates are approved by the respective state utility commissions with respect to regulated property. The average depreciation rates for Property, Plant, and Equipment are presented in the following table.
(1)
The results of Cinergy also include amounts related to non-registrants.
In June 2004, PSI implemented new depreciation rates, as a result of changes in useful lives of production assets and an increased rate for cost of removal, that were approved in PSI’s latest retail rate case. The impact of this change in accounting estimate was an increase of approximately $30 million and $18 million in Cinergy’s and PSI’s Depreciation expense for 2005 and 2004, respectively.
(ii) Allowance for Funds Used During Construction (AFUDC)
Our utility operating companies finance construction projects with borrowed funds and equity funds. Regulatory authorities allow us to record the costs of these funds as part of the cost of construction projects. AFUDC is calculated using a methodology authorized by the regulatory authorities.
The equity component of AFUDC, which is credited to Miscellaneous Income (Expense) - Net, for the years ended December 31, 2005, 2004, and 2003, was as follows:
The borrowed funds component of AFUDC, which is recorded on a pre-tax basis and is credited to Interest Expense, for the years ended December 31, 2005, 2004, and 2003, was as follows:
With the deregulation of CG&E’s generation assets, the AFUDC method is no longer used to capitalize the cost of funds used during generation-related construction at CG&E. See (iii) for a discussion of capitalized interest. The majority of PSI’s projects are being recovered through a construction work in progress (CWIP) tracker. Once CWIP projects are approved and included in the CWIP tracking mechanism, the costs of funds are no longer accrued on the project.
(iii) Capitalized Interest
Cinergy capitalizes interest costs for non-regulated construction projects in accordance with SFAS No. 34, Capitalization of Interest Cost (Statement 34). The primary differences from AFUDC are that the Statement 34 methodology does not include a component for equity funds and does not emphasize short-term borrowings over long-term borrowings. Capitalized interest costs, which are recorded on a pre-tax basis, for the years ended December 31, 2005, 2004, and 2003, were as follows:
(1)
The results of Cinergy also include amounts related to non-registrants.
(k) Impairments
(i) Long-Lived Assets
In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. So long as an asset or group of assets is not held for sale, the determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows (including related tax effects) attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for an impairment loss if the carrying value is greater than the fair value. Once assets are classified as held for sale, the comparison of undiscounted cash flows to carrying value is disregarded and an impairment loss is recognized for any amount by which the carrying value exceeds the fair value of the assets less cost to sell.
At December 31, 2005, the carrying value of gas-fired peaking plants that are not subject to cost-of-service-based ratemaking is approximately $400 million. GAAP does not require us to estimate the fair value of these assets since they are recoverable on a nominal basis. However, we believe the fair value of these plants to be substantially below their carrying value.
(ii) Unconsolidated Investments
We evaluate the recoverability of investments in unconsolidated subsidiaries when events or changes in circumstances indicate that the carrying amount of the asset is other than temporarily impaired. An investment is
considered impaired if the fair value of the investment is less than its carrying value. We only recognize an impairment loss when an impairment is considered to be other than temporary. We consider an impairment to be other than temporary when a forecasted recovery up to the investment’s carrying value is not expected for a reasonable period of time. We evaluate several factors, including, but not limited to, our intent and ability to hold the investment, the severity of the impairment, the duration of the impairment and the entity’s historical and projected financial performance, when determining whether or not an impairment is other than temporary. Once an investment is considered other than temporarily impaired and an impairment loss is recognized (as Miscellaneous Income (Expense) - Net), the carrying value of the investment is not adjusted for any subsequent recoveries in fair value. As of December 31, 2005 and 2004, we do not have any material unrealized losses that are deemed to be temporary in nature. We have not incurred any material impairment charges on unconsolidated investments during 2005. See Note 17(a) for the amount of impairment charges recorded during 2004.
(l) Asset Retirement Obligations and Accrued Cost of Removal
In accordance with Statement 143, we recognize the fair value of legal obligations associated with the retirement or removal of long-lived assets at the time the obligations are incurred and can be reasonably estimated. The initial recognition of this liability is accompanied by a corresponding increase in property, plant, and equipment. Subsequent to the initial recognition, the liability is adjusted for any revisions to the expected value of the retirement obligation (with corresponding adjustments to property, plant, and equipment), and for accretion of the liability due to the passage of time (recognized as Operation and maintenance expense). Additional depreciation expense is recorded prospectively for any property, plant, and equipment increases.
See (s)(iv) for a summary of cumulative effect adjustments, which includes our adoption of Statement 143, and (s)(i) for a discussion of our December 31, 2005 adoption of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (Interpretation 47), an interpretation of Statement 143.
CG&E’s transmission and distribution business, PSI, and ULH&P ratably accrue the estimated retirement and removal cost of rate regulated property, plant, and equipment when removal of the asset is considered likely, in accordance with established regulatory practices. The accrued, but not incurred, balance for these costs is classified as Regulatory liabilities, under Statement 71. We do not accrue the estimated cost of removal when no legal obligation associated with retirement or removal exists for any of our non-regulated assets (including CG&E’s generation assets).
Approximately $2 million of asset retirement obligations were transferred to ULH&P from CG&E in January 2006 in conjunction with the transfer of generating assets. See (s)(i) for additional information.
(m) Derivatives
We account for derivatives under Statement 133, which requires all derivatives, subject to certain exemptions, to be accounted for at fair value. Changes in a derivative’s fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivatives that qualify as hedges can (a) offset related fair value changes on the hedged item in the Statements of Income for fair value hedges; or (b) be recorded in other comprehensive income for cash flow hedges. To qualify for hedge accounting, derivatives must be designated as a hedge (for example, an offset of interest rate risks) and must be effective at reducing the risk associated with the hedged item. Accordingly, changes in the fair values or cash flows of instruments designated as hedges must be highly correlated with changes in the fair values or cash flows of the related hedged items.
(i) Energy Marketing and Trading
We account for all energy trading derivatives at fair value. These derivatives are shown in our Balance Sheets as Energy risk management assets and Energy risk management liabilities. Changes in a derivative’s fair value represent unrealized gains and losses and are recognized as revenues in our Statements of Income unless specific hedge accounting criteria are met.
Non-derivatives involve the physical delivery of energy and are accounted for as accrual contracts. Accrual contracts are not adjusted for changes in fair value.
Although we intend to settle accrual contracts with company-owned assets, occasionally we settle these contracts with purchases on the open trading markets. The cost of these purchases could be in excess of the associated revenues. We recognize the gains or losses on these transactions as delivery occurs. Open market purchases may occur for the following reasons:
• generating station outages;
• least-cost alternative;
• native load requirements; and
• extreme weather.
We value derivatives using end-of-the-period fair values, utilizing the following factors (as applicable):
• closing exchange prices (that is, closing prices for standardized electricity and natural gas products traded on an organized exchange, such as the New York Mercantile Exchange);
• broker-dealer and over-the-counter price quotations; and
• model pricing (which considers time value and historical volatility factors of electricity and natural gas).
In October 2002, the EITF reached a consensus in EITF 02-3 to rescind EITF Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). EITF 98-10 permitted non-derivative contracts to be accounted for at fair value if certain criteria were met. Effective with the adoption of EITF 02-3 on January 1, 2003, non-derivative contracts and natural gas held in storage that were previously accounted for at fair value were required to be accounted for on an accrual basis, with gains and losses on the transactions being recognized at the time the contract was settled. See (s)(iv) for a summary of cumulative effect adjustments.
Cinergy designates derivatives as fair value hedges for certain volumes of our natural gas held in storage. Under this accounting election, changes in the fair value of both the derivative as well as the hedged item (the specified gas held in storage) are included in Gas Operating Revenues in Cinergy’s Statements of Income. We assess the effectiveness of the derivatives in offsetting the change in fair value of the gas held in storage on a quarterly basis. Selected information on Cinergy’s hedge accounting activities was as follows:
(ii) Financial
In addition to energy derivatives, we use derivative financial instruments to manage exposure to fluctuations in interest rates. We use interest rate swaps (an agreement by two parties to exchange fixed-interest rate cash flows for variable-interest rate cash flows) and treasury locks (an agreement that fixes the yield or price on a specific treasury security for a specific period, which we sometimes use in connection with the issuance of fixed rate debt). We account for such derivatives at fair value and assess the effectiveness of any such derivative used in hedging activities.
At December 31, 2005, the ineffectiveness of instruments that we have classified as cash flow hedges of variable-rate debt instruments was not material. Reclassification of unrealized gains or losses on cash flow hedges of debt instruments from Accumulated other comprehensive income (loss) occurs as interest is accrued on the hedged debt
instrument. The unrealized losses that will be reclassified as a charge to Interest Expense during the twelve-month period ending December 31, 2006 are not expected to be material.
(n) Intangible Assets
Under the provisions of SFAS No. 142, Goodwill and Other Intangible Assets (Statement 142), goodwill and other intangible assets with indefinite lives are not amortized. Statement 142 requires that goodwill is assessed annually, or when circumstances indicate that the fair value of a reporting unit has declined significantly, by applying a fair-value-based test. This test is applied at the reporting unit level, which is not broader than the current business segments discussed in Note 18. Acquired intangible assets are separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of intent to do so.
(o) Income Taxes
Cinergy and its subsidiaries file a consolidated federal income tax return and combined/consolidated state and local tax returns in certain jurisdictions. Cinergy and its subsidiaries have an income tax allocation agreement; the corporate taxable income method is used to allocate tax benefits to the subsidiaries whose investments or results of operations provide those tax benefits. Any tax liability not directly attributable to a specific subsidiary is allocated proportionately among the subsidiaries as required by the agreement.
SFAS No. 109, Accounting for Income Taxes, requires an asset and liability approach for financial accounting and reporting of income taxes. The tax effects of differences between the financial reporting and tax basis of accounting are reported as Deferred income tax assets or liabilities in our Balance Sheets and are based on currently enacted income tax rates. We evaluate quarterly the realizability of our deferred tax assets by assessing our valuation allowance and adjusting the amount of such allowance, if necessary.
Investment tax credits, which have been used to reduce our federal income taxes payable, have been deferred for financial reporting purposes. These deferred investment tax credits are being amortized over the useful lives of the property to which they are related. For a further discussion of income taxes, see Note 12.
(p) Contingencies
In the normal course of business, Cinergy, CG&E, PSI, and ULH&P are subject to various regulatory actions, proceedings, and lawsuits related to environmental, tax, or other legal matters. We reserve for these potential contingencies when they are deemed probable and reasonably estimable liabilities. However, these amounts are estimates based upon assumptions involving judgment and therefore actual results could differ. For further discussion of contingencies, see Note 13.
(q) Pension and Other Postretirement Benefits
Cinergy provides benefits to retirees in the form of pension and other postretirement benefits. Our reported costs of providing these pension and other postretirement benefits are developed by actuarial valuations and are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Changes made to the provisions of the plans may impact current and future pension costs. Pension costs associated with Cinergy’s defined benefit plans are impacted by employee demographics, the level of contributions we make to the plan, and earnings on plan assets. These pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation. Changes in pension obligations associated with the previously discussed factors are not immediately recognized as pension costs on the Statements of Income but are deferred and amortized in the future over the average remaining service period of active plan participants to the extent they exceed certain thresholds prescribed by SFAS No. 87, Employers’ Accounting for Pensions (Statement 87).
Other postretirement benefit costs are impacted by employee demographics, per capita claims costs, and health care cost trend rates and may also be affected by changes in key actuarial assumptions, including the discount rate used in determining the accumulated postretirement benefit obligation (APBO). Changes in postretirement benefit
obligations associated with these factors are not immediately recognized as postretirement benefit costs but are deferred and amortized in the future over the average remaining service period of active plan participants to the extent they exceed certain thresholds prescribed by SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (Statement 106).
Cinergy reviews and updates its actuarial assumptions for its pension and postretirement benefit plans on an annual basis, unless plan amendments or other significant events require earlier remeasurement at an interim period. For additional information on pension and other postretirement benefits, see Note 11.
(r) Stock-Based Compensation
In 2003, we prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation (Statement 123), as amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure (Statement 148), for all employee awards granted or with terms modified on or after January 1, 2003. Prior to 2003, we had accounted for our stock-based compensation plans using the intrinsic value method under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. See Note 3(c) for further information on our stock-based compensation plans. The impact on our Net Income and earnings per common share (EPS) if the fair-value based method had been applied to all outstanding and unvested awards in each period was not material. In December 2004, the FASB issued a revision of Statement 123 entitled Share-Based Payment. See (s)(ii) for further information.
(s) Accounting Changes
(i) Asset Retirement Obligations
In March 2005, the FASB issued Interpretation No. 47, an interpretation of Statement 143. Statement 143 requires recognition of legal obligations associated with the retirement or removal of long-lived assets at the time the obligations are incurred. Interpretation 47 clarifies that a conditional asset retirement obligation (which occurs when the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity) is a legal obligation within the scope of Statement 143. As such, the fair value of a conditional asset retirement obligation must be recognized as a liability when incurred if the liability’s fair value can be reasonably estimated. Interpretation 47 also clarifies when sufficient information exists to reasonably estimate the fair value of an asset retirement obligation.
We adopted Interpretation 47 on December 31, 2005 and recorded multiple asset retirement obligations as a result. These asset retirement obligations primarily related to obligations associated with retiring gas mains, recorded by Cinergy, CG&E, and ULH&P, and future asbestos abatement at certain generating stations, recorded by Cinergy, CG&E, and PSI.
Cinergy and CG&E recognized a loss of approximately $3 million (net of tax) for the cumulative effect of this change in accounting principle. The cumulative effect resulted from asset retirement obligations primarily associated with our non-regulated generating assets. See (s)(iv) for a summary of cumulative effect adjustments. The effect of adoption for Cinergy, CG&E, PSI, and ULH&P included balance sheet reclassifications of approximately $35 million, $27 million, $8 million, and $5 million, respectively, from Regulatory liabilities. See discussion of Regulatory liabilities previously disclosed in (e). The increases in asset retirement obligations from adopting Interpretation 47 were $51 million, $39 million, $12 million and $6 million for Cinergy, CG&E, PSI, and ULH&P, respectively.
Pro-forma results as if Interpretation 47 was applied retroactively for the years ended December 31, 2005, 2004, and 2003 are not materially different from reported results. The December 31, 2004 and December 31, 2003 pro-forma liabilities for asset retirement obligations recorded as a result of the adoption of Interpretation 47 are not materially different than the December 31, 2005 balances.
(ii) Share-Based Payment
In December 2004, the FASB issued a replacement of Statement 123, SFAS No. 123 (revised 2004), Share-Based Payment (Statement 123R). This standard will require, among other things, accounting for all stock-based compensation arrangements under the fair value method. The standard also requires compensation awards that involve the achievement of a certain company stock price (or similar measure) to have the likelihood of reaching those targets incorporated into the fair value of the award. The number of awards paid out under Cinergy’s performance-based share awards under the Cinergy Corp. 1996 Long-Term Incentive Compensation Plan (LTIP) is based on Cinergy’s expected total shareholder return (TSR) as measured against a pre-defined peer group. Therefore, these awards are required to be re-valued at fair value upon adoption.
We adopted Statement 123R on January 1, 2006 using the modified prospective application. Cinergy recognized an immaterial loss for the cumulative effect of this change in accounting principle. The cumulative effect is due to the use of a new model that incorporates the expected TSR into the fair value of Cinergy’s performance-based share awards under the LTIP. This model is used to value all grants of future performance-based share awards under the LTIP, beginning January 1, 2006.
In 2003, we prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of Statement 123, as amended by Statement 148, for all employee awards granted or with terms modified on or after January 1, 2003. Therefore, the impact of implementation of Statement 123R on stock options and remaining awards, other than the aforementioned performance-based share awards, within our stock-based compensation plans was not material. See additional detail regarding Cinergy’s stock-based compensation plans in Note 3(c).
(iii) Income Taxes
In October 2004, the American Jobs Creation Act (AJCA) was signed into law. The AJCA includes a one-time deduction of 85 percent of certain foreign earnings that are repatriated, as defined in the AJCA. The repatriation of foreign earnings pursuant to this provision did not have a material impact on our financial position or results of operations.
(iv) Cumulative Effect of Changes in Accounting Principles, Net of Tax
In 2005, Cinergy recognized a Cumulative effect of a change in accounting principle, net of tax as a result of the recognition of conditional asset retirement obligations in conjunction with the adoption of Interpretation 47. In 2003, Cinergy, CG&E, and PSI recognized Cumulative effect of changes in accounting principles, net of tax as a result of the reversal of accrued cost of removal for non-regulated generating assets in conjunction with the adoption of Statement 143 and the change in accounting for certain energy related contracts from fair value to accrual in accordance with the rescission of EITF 98-10. There were no cumulative effect adjustments in 2004. The following table summarizes these cumulative effect adjustments and their related tax effects.
(1)
The results of Cinergy also include amounts related to non-registrants.
(t) Translation of Foreign Currency
We translate the assets and liabilities of foreign subsidiaries, whose functional currency (generally, the local currency of the country in which the subsidiary is located) is not the United States dollar, using the appropriate exchange rate as of the end of the year. We translate income and expense items using the average exchange rate prevailing during the month the respective transaction occurs. We record translation gains and losses in Accumulated other comprehensive income (loss), which is a component of common stock equity. When a foreign subsidiary is sold, the cumulative translation gain or loss as of the date of sale is removed from Accumulated other comprehensive income (loss) and is recognized as a component of the gain or loss on the sale of the subsidiary in our Statements of Income.
(u) Related Party Transactions
CG&E, PSI, and ULH&P engage in related party transactions. These transactions, which are eliminated upon consolidation, are generally performed at cost and in accordance with the SEC regulations under the PUHCA 1935 and the applicable state and federal commission regulations. See (c) for a further discussion of the repeal of the PUHCA 1935 and the implementation of the FERC’s PUHCA 2005. The Balance Sheets of our utility operating companies reflect amounts payable to and/or receivable from related parties as Accounts payable to affiliated companies and Accounts receivable from affiliated companies. The significant related party transactions are disclosed below.
(i) Services
Services provides our regulated and non-regulated subsidiaries with a variety of centralized administrative, management, and support services in accordance with agreements approved by the SEC under the PUHCA 1935.
The costs of these services are charged to our companies on a direct basis, or for general costs which cannot be directly attributed, based on predetermined allocation factors, including the following ratios:
• sales;
• electric peak load;
• number of employees;
• number of customers; and
• construction expenditures.
These costs were as follows for the years ended December 31, 2005, 2004, and 2003:
During 2003, Cinergy Power Generation Services, LLC (Generation Services) supplied electric production-related construction, operation and maintenance services to certain of our subsidiaries pursuant to agreements approved by the SEC under the PUHCA 1935. CG&E and its subsidiaries received services from Generation Services in the amount of $96 million for the year ended December 31, 2003. PSI received services in the amount of $55 million for the year ended December 31, 2003. Effective January 1, 2004, these services are now provided by Services and/or directly by CG&E and PSI as all Generation Services employees were transferred to other affiliated corporations.
(ii) Purchased Energy
Through December 31, 2005 ULH&P purchased energy from CG&E pursuant to a contract effective January 1, 2002, which was approved by the FERC and the Kentucky Public Service Commission (KPSC). This five-year agreement is a negotiated fixed rate contract with CG&E. ULH&P purchased energy from CG&E for resale in the amounts of $168 million, $162 million, and $155 million for the years ended December 31, 2005, 2004, and 2003, respectively. These amounts are reflected in the Statements of Income for ULH&P as Electricity purchased from parent company for resale. This contract was terminated effective December 31, 2005 in connection with the transfer of generating assets from CG&E to ULH&P. For information on the transfer of generating assets to ULH&P on January 1, 2006, see Note 22.
PSI and CG&E purchased energy from each other under a federal and state approved joint operating agreement. These sales and purchases are reflected in the Statements of Income of PSI and CG&E as Electric operating revenues and Fuel, emission allowances, and purchased power expense and were as follows for the years ended December 31, 2005, 2004, and 2003:
(1)
Includes intercompany purchases that are presented net in accordance with EITF 02-3.
Effective January 1, 2006, the joint operating agreement was terminated. With the implementation of Midwest ISO’s structured Day-Ahead and Real-Time Energy Market, Midwest ISO took over the responsibility of dispatching generation units in its footprint, including PSI and CG&E generation units, and it was no longer necessary to have a joint operating agreement between PSI and CG&E.
CG&E and PSI had an agreement with Marketing & Trading to purchase gas for certain gas-fired peaking plants. Purchases under this agreement were approximately $26 million, $4 million, and $6 million for CG&E and $130 million, $37 million, and $20 million for PSI for the years ended December 31, 2005, 2004, and 2003, respectively. The amounts are reflected in the Statements of Income of CG&E and PSI as Fuel, emission allowances, and purchased power expense.
During 2005, PSI terminated the agreement with Marketing & Trading to purchase gas, and on December 29, 2005, PSI and ULH&P entered into separate agreements with an unrelated third party to supply all of the natural gas to be used as fuel for certain gas-fired peaking plants.
(iii) Other
CG&E and ULH&P enter into various agreements with Marketing & Trading to manage their interstate pipeline transportation, storage capacity, and gas supply contracts. Under the terms of these agreements, Marketing & Trading is obligated to deliver natural gas to meet CG&E’s and ULH&P’s requirements. Payments under these agreements for the years ended December 31, 2005, 2004, and 2003 were approximately $726 million, $480 million, and $413 million for CG&E and its subsidiaries and $102 million, $79 million, and $78 million for ULH&P. These amounts are recorded in the Statements of Income for CG&E and ULH&P as Gas purchased expense. Certain of these amounts for CG&E and ULH&P have been deferred for future recovery. In addition, certain of these amounts for CG&E are presented net in Gas operating revenues in accordance with EITF 02-3.
ULH&P terminated its agreement with Marketing & Trading, and on December 29, 2005, entered into an agreement with an unrelated third party to manage their interstate pipeline transportation, storage capacity, and gas supply contracts.
During 2004 and 2005, CG&E served as the purchase and sales agent for PSI with respect to emission allowances. As of December 31, 2005, CG&E’s affiliated receivables and PSI’s affiliated payables totaled approximately $3 million. All other amounts were immaterial. There were no emission allowance transactions between CG&E and PSI in 2003.
Cinergy Corp., Services, and our utility operating companies participate in a money pool arrangement to better manage cash and working capital requirements. These amounts are reflected in Notes payable to affiliated companies and Notes receivable from affiliated companies on the Balance Sheets of our utility operating companies. For a further discussion of the money pool agreement, see Note 7.
2. Pending Merger
On May 8, 2005, Cinergy Corp. entered into an agreement and plan of merger with Duke, a North Carolina corporation, whereby Cinergy Corp. will be merged with Duke. Under the merger agreement, each share of Cinergy Corp. common stock will be converted into 1.56 shares of the newly formed company, Duke Energy Holding.
The merger agreement has been approved by both companies’ Boards of Directors. Consummation of the merger is subject to customary conditions, including, among others, the approval of the shareholders of both companies and the approvals of various regulatory authorities.
Immediately following consummation of the merger, former Cinergy shareholders will own approximately 24 percent of Duke Energy Holding’s common stock. Paul Anderson, Duke’s CEO and Chairman of the Board will remain Chairman of the combined company and Jim Rogers, Cinergy’s CEO and Chairman of the Board, will become the President and CEO of the combined company. The new Duke Energy Holding board will be comprised of 10 members appointed by Duke and five members appointed by Cinergy.
The merger will be recorded using the purchase method of accounting whereby the total purchase price of approximately $9 billion will be allocated to Cinergy’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of the closing of the merger.
The merger is expected to close in the first half of 2006. However, the actual timing is contingent on the receipt of several approvals including: FERC, Federal Communications Commission (FCC), Nuclear Regulatory Commission (NRC), state regulatory commissions of Ohio, Indiana, Kentucky, North Carolina, and South Carolina, and shareholders of each company. The status of these matters is as follows:
Completed:
• On August 11, 2005, the United States Department of Justice and the Federal Trade Commission granted early termination of the waiting period imposed by the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
• In November 2005, the KPSC approved Duke’s and Cinergy’s application seeking approval of a transfer and acquisition of control of ULH&P.
• In November 2005, the state utility regulatory agency in South Carolina approved Duke’s application requesting authorization to enter into a business combination.
• In December 2005, the PUCO approved Cinergy’s application of a change in control with respect to CG&E. The PUCO affirmed the approval in February 2006.
• In December 2005, the FERC approved Duke’s and Cinergy’s application requesting approval of the merger and the subsequent internal restructuring and consolidation of the merged company.
• In February 2006, the NRC approved Duke’s application requesting approval of the merger.
• The FCC has approved assignment of all eight Cinergy wireless telecommunications licenses.
• In light of the repeal of the PUHCA 1935, as amended, effective February 2006, the merger will no longer require SEC authorization under the PUHCA 1935.
Pending:
• In June 2005, PSI filed a petition with the IURC concerning, among other things, certain merger-related affiliate agreements, the sharing of merger-related benefits with customers, and deferred accounting of certain merger-related costs. On December 15, 2005, PSI filed with the IURC a settlement agreement reached with the staff of the IURC, the Indiana Office of Utilities Consumer Counsel and the PSI Industrial Group. Settlement hearings were held in January 2006 and a final order is expected in March 2006.
• In July 2005, Duke filed an application with the state utility regulatory agency in North Carolina. The application requests both the authorization to enter into a business combination transaction and the approval of various affiliate agreements. Hearings were held in January 2006 and a final order is expected in March 2006.
• Special meetings of shareholders of both companies for the purpose of voting on the merger will be held on March 10, 2006.
The merger agreement also provides that Duke and Cinergy will use their reasonable best efforts to transfer five generating stations located in the midwest from Duke to CG&E. This transfer will require regulatory approval by the FERC and, with respect to one plant located in Indiana the IURC. The FERC approved this transaction in December 2005. CG&E and the Duke affiliate that owns the interest in the Indiana plant filed an application with
the IURC requesting approval for the transfer (as well as the declination by the IURC of jurisdiction over CG&E following the transfer) in October 2005. A final order approving the transfer and the IURC’s declination of jurisdiction over CG&E was received in February 2006. Duke and Cinergy intend to effectuate the transfer as an equity infusion into CG&E at book value. In conjunction with the transfer, Duke Capital LLC, a subsidiary of Duke, and CG&E intend to enter into a financial arrangement covering a multi-year period, to eliminate any potential cash shortfalls that may result from CG&E owning and operating the five stations. At this time, we cannot predict the outcome of this matter.
The merger agreement contains certain termination rights for both Duke and Cinergy, and further provides that, upon termination of the merger agreement under specified circumstances, a party would be required to pay the other party’s fees and expenses in an amount not to exceed $35 million and/or a termination fee of $300 million in the case of a fee payable by Cinergy to Duke or a termination fee of $500 million in the case of a fee payable by Duke to Cinergy. Any termination fee would be reduced by the amount of any fees and expenses previously reimbursed by the party required to pay the termination fee.
In May 2005, a purported shareholder class action was filed in the Court of Common Pleas in Hamilton County, Ohio against Cinergy and each of the members of the Board of Directors. The lawsuit alleged that the defendants breached their duties of due care and loyalty to shareholders by agreeing to the merger agreement between Duke and Cinergy and was seeking to either enjoin or amend the terms of the merger. Cinergy and the individual defendants filed a motion to dismiss this lawsuit in July 2005, which was granted in November of 2005. An appeal was not filed by the plaintiffs and the case is closed.
Although Management believes that the merger should close in the first half of 2006, the actual timing of the transaction could be delayed or the merger could be abandoned by the parties in the event of the inability to obtain one or more of the required regulatory approvals on acceptable terms.
3. Common Stock
(a) Changes In Common Stock Outstanding
The following table reflects information related to shares of Cinergy Corp. common stock issued for stock-based plans.
(1) Plan does not contain an authorization limit. The number of shares presented reflects amounts registered with the SEC as of December 31, 2005.
(2) Shares available exclude the number of shares to be issued upon exercise of outstanding options, warrants, and rights.
We retired 111,544 shares of common stock in 2005, 829,575 shares in 2004, and 519,976 shares in 2003, mainly representing shares tendered as payment for the exercise of previously granted stock options.
Cinergy issues new Cinergy Corp. common stock shares to satisfy obligations under certain of its employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan. Cinergy Corp. issued approximately 3.0 million shares in 2005 and approximately 3.9 million shares in 2004 to satisfy its obligations under these plans.
In December 2004, Cinergy Corp. issued 6.1 million shares of common stock under its January 2003 $750 million registration statement with the SEC. The net proceeds of $247 million were used to reduce short-term indebtedness.
In January and February 2005, Cinergy Corp. issued a total of 9.2 million shares of common stock pursuant to certain stock purchase contracts that were issued as a component of combined securities in December 2001. Net proceeds from the transaction of $316 million were used to reduce short-term debt. See Note 5(b) for further discussion of the securities.
In June 2005, Cinergy Corp. contributed $200 million in capital to PSI. The capital contribution was used to repay short-term indebtedness and is consistent with supporting PSI’s current credit ratings.
In January 2006, CG&E contributed approximately $140 million in capital to ULH&P in conjunction with the transfer of certain generating assets to ULH&P. See Note 22 for additional information.
Cinergy Corp. owns all of the common stock of CG&E and PSI. All of ULH&P’s common stock is held by CG&E.
(b) Dividend Restrictions
Cinergy Corp.’s ability to pay dividends to holders of its common stock is principally dependent on the ability of CG&E and PSI to pay Cinergy Corp. dividends on their common stock. Cinergy Corp., CG&E, and PSI cannot pay dividends on their common stock if their respective preferred stock dividends or preferred trust dividends are in arrears. The amount of common stock dividends that each company can pay is also limited by certain capitalization and earnings requirements under CG&E’s and PSI’s credit instruments. Currently, these requirements do not impact the ability of either company to pay dividends on its common stock. In addition, until consummation or termination of the merger with Duke, Cinergy is prohibited from paying dividends in excess of its historical levels without prior consent of Duke.
(c) Stock-based Compensation Plans
We currently have the following stock-based compensation plans:
• LTIP;
• SOP;
• Employee Stock Purchase and Savings Plan;
• UK Sharesave Scheme;
• Retirement Plan for Directors;
• Directors’ Equity Compensation Plan;
• Directors’ Deferred Compensation Plan;
• 401(k) Plans; and
• 401(k) Excess Plan.
The LTIP, the SOP, the Employee Stock Purchase and Savings Plan, 401(k) Plans, and the 401(k) Excess Plan are discussed below. The activity in 2005, 2004, and 2003 for the remaining stock-based compensation plans was not significant.
In 2003, we prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of Statement 123, as amended by Statement 148, for all employee awards granted or with terms modified on or after January 1, 2003. See Note 1(s)(ii) for additional information on costs we recognized related to stock-based compensation plans. Effective January 1, 2006, Cinergy adopted Statement 123R. See Note 1(r) for additional information regarding this new accounting standard.
(i) LTIP
Under this plan, certain key employees may be granted incentive and non-qualified stock options, stock appreciation rights (SARs), restricted stock, dividend equivalents, phantom stock, the opportunity to earn performance-based shares and certain other stock-based awards. Stock options are granted to participants with an option price equal to or greater than the fair market value on the grant date, and generally with a vesting period of three years. The vesting period begins on the grant date and all options expire within 10 years from that date.
From 2003 through 2005, performance-based share awards were paid with 50 percent in common stock and 50 percent in cash. As of December 31, 2005, all performance shares were classified as liabilities as management intends to pay all outstanding awards in cash. As a result, the expected cash payout portion of the performance shares were reported in Current Liabilities - Other and Non-Current Liabilities - Other.
Entitlement to performance-based shares is based on Cinergy’s TSR over designated Cycles as measured against a pre-defined peer group. Target grants of performance-based shares were made for the following Cycles:
Participants may earn more or less performance shares if Cinergy’s TSR ranks above or below the 55th percentile of the TSR of its peer group. For the three-year performance period ended December 31, 2005 (Cycle VII), approximately 109,000 shares (including dividend equivalent shares) were earned, based on our relative TSR.
(ii) SOP
The SOP was designed to align executive compensation with shareholder interests. Under the SOP, incentive and non-qualified stock options, SARs, and SARs in tandem with stock options could have been granted to key employees, officers, and outside directors. The activity under this plan predominantly consisted of the grant of stock options. Options were granted with an option price equal to the fair market value of the shares on the grant date. Options generally vested over five years at a rate of 20 percent per year, beginning on the grant date, and expiring 10 years from the grant date. As of October 2004, no additional incentive stock options may be granted under the plan.
(iii) Employee Stock Purchase and Savings Plan
The Employee Stock Purchase and Savings Plan allowed essentially all full-time, regular employees to purchase shares of common stock pursuant to a stock option feature. The last offering period began May 1, 2001, and ended June 30, 2003, with 168,101 shares purchased and the remaining cash distributed to the respective participants. The purchase price for all shares under this offering was $32.78.
Stock option activity for 2005, 2004, and 2003 for the LTIP, SOP, and Employee Stock Purchase and Savings Plan is summarized as follows:
(1) Shares were not offered after June 30, 2003.
(2) Options were not granted under the SOP during 2005, 2004, or 2003.
The weighted average fair value of options granted under the LTIP was $5.64 in 2005, $5.65 in 2004, and $4.96 in 2003. The fair values of options granted were estimated as of the grant date using the Black-Scholes option-pricing model and the following assumptions:
Price ranges, along with certain other information, for options outstanding under the combined LTIP and SOP plans at December 31, 2005, were as follows:
(iv) 401(k) Plans
We sponsor 401(k) employee retirement plans that cover substantially all United States employees. Employees can contribute up to 50 percent of pre-tax base salary (subject to Internal Revenue Service (IRS) limits) and up to 15 percent of after-tax base salary. We make matching contributions to these plans in the form of Cinergy Corp. common stock, contributing 100 percent of the first three percent of an employee’s pre-tax contributions plus 50 percent of the next two percent of an employee’s pre-tax contributions, and we have the discretion to make incentive
matching contributions based on Cinergy’s net income. Employees are immediately vested in both their contributions and our matching contributions.
Cinergy’s, CG&E’s, and PSI’s matching contributions for the years ended December 31, 2005, 2004, and 2003 were as follows:
(1) The results of Cinergy also include amounts related to non-registrants.
Effective January 1, 2003, each Cinergy employee whose pension benefit is determined using a cash balance formula is also eligible to receive an annual deferred profit sharing contribution, calculated as a percentage of that employee’s total pension eligible earnings. The deferred profit sharing contribution made by Cinergy is based on the corporate net income performance level for the year, and is made to the 401(k) plans in the form of Cinergy Corp. common stock. Employees vest in their benefit upon reaching three years of service, or immediately upon reaching age 65 while employed. Cinergy has recorded approximately $4.7 million and $2.4 million, respectively, of profit sharing contribution costs for the years ended December 31, 2005 and December 31, 2004.
(v) 401(k) Excess Plan
The 401(k) Excess Plan is a non-qualified deferred compensation plan for a select group of Cinergy management and other highly compensated employees. It is a means by which these employees can defer additional compensation, and receive company matching contributions, provided they have already contributed the maximum amount (pursuant to the anti-discrimination rules for highly compensated employees) under the qualified 401(k) Plans. All funds deferred are held in a rabbi trust administered by an independent trustee.
(vi) Merger-Related Obligations
Several of the company’s benefit plans contain “change-in-control” clauses that provide enhanced, and/or accelerate the payment of, benefits to management level employees in the event of a qualifying transaction such as would occur upon the consummation of the proposed merger with Duke as discussed in Note 2. These include benefits paid pursuant to the LTIP and certain payments under Cinergy’s Annual Incentive Plan. Certain employees will also be entitled to additional severance and benefits in the event they are involuntarily terminated without “cause” or voluntarily terminate for “good reason” (as such terms are defined in their employment agreements) in connection with or following the merger.
On December 30, 2005, Cinergy entered into agreements with 28 employees to accelerate the payment of a portion of the amounts discussed above, otherwise expected to be paid after December 31, 2005, in order to mitigate the Company’s taxes and related expenses. Payments totaling $70 million were made in December pursuant to these agreements. The agreements amend the employees’ employment agreements, and benefit plans in which they participate, to accelerate into 2005 the payment of certain amounts that they have previously earned or are expected to earn after December 31, 2005. Among other things, the Company prepaid performance shares under the LTIP and severance payments for certain individuals. In the event an employee who received such amounts voluntarily terminates his employment prior to the closing of the merger, the employee is obligated to repay all of the payments, and if the merger does not close on or prior to December 15, 2006, the employee is obligated to repay half of the payments, to reflect his or her estimated tax liability upon receipt of the accelerated payments; in each case, less any amounts that the employee has already earned through such date. By accelerating these payments, the Company will mitigate taxes and related expenses that it would otherwise incur if it had waited until after 2005 to make these payments.
The majority of these payments have been recorded as prepaid compensation in Prepayments and other. Approximately half of these payments are being accounted for as a retention bonus and will be expensed over the period between January 1, 2006 and the estimated closing of the pending merger with Duke. The remainder, representing the half that executives must repay if the merger is never consummated, will remain in Prepayments and other until the merger closes.
In addition to payments made in December, based upon certain assumptions and using our current best estimates, the Company’s remaining contractual obligations that will be triggered upon merger consummation, and due shortly thereafter, including severance payments for those executives that have indicated their intention to terminate for “good reason”, is expected to be approximately $73 million. These amounts will be accounted for when the merger closes. This estimate only includes amounts payable pursuant to existing benefit arrangements and employment contracts and does not include the value of accelerated stock options, retirement benefits earned prior to the merger, and amounts payable under severance plans that Duke and Cinergy are considering to reduce redundant positions after the merger closes.
4. Cumulative Preferred Stock
In August 2005, PSI redeemed all of its $31.075 million notional amount 6.875% Cumulative Preferred Stock.
In February 2006, CG&E notified holders of its $16.98 million notional amount 4% Cumulative Preferred Stock, and holders of its $3.5 million notional amount 4.75% Cumulative Preferred Stock that it intends to redeem all outstanding shares on March 10 at a price of $108 per share and $101 per share, respectively, plus accrued and unpaid dividends.
5. Variable Interest Entities
(a) Power Sale Special Purpose Entities (SPEs)
In accordance with FASB Interpretation No. 46, Consolidation of Variable Interest Entities, we consolidate two SPEs that have individual power sale agreements with Central Maine Power Company (CMP) for approximately 45 megawatts (MW) of capacity, ending in 2009, and 35 MW of capacity, ending in 2016. In addition, these SPEs have individual power purchase agreements with Cinergy Capital & Trading, Inc. (Capital & Trading) to supply the power. Capital & Trading also provides various services, including certain credit support facilities. Upon the initial consolidation of these two SPEs on July 1, 2003, approximately $239 million of notes receivable, $225 million of non-recourse debt, and miscellaneous other assets and liabilities were included on Cinergy’s Balance Sheets. The debt was incurred by the SPEs to finance the buyout of the existing power contracts that CMP held with the former suppliers. The cash flows from the notes receivable are designed to repay the debt. Note 10 provides additional information regarding the debt and the notes receivable, respectively.
(b) Preferred Trust Securities
In December 2001, Cinergy Corp. issued approximately $316 million notional amount of combined securities consisting of (a) 6.9 percent preferred trust securities, due February 2007, and (b) stock purchase contracts obligating the holders to purchase between 9.2 and 10.8 million shares of Cinergy Corp. common stock by February 2005. A $50 preferred trust security and stock purchase contract were sold together as a single security unit (Unit). The preferred trust securities were issued through a trust whose common stock was 100 percent owned by Cinergy Corp. The stock purchase contracts were issued directly by Cinergy Corp. The trust loaned the proceeds from the issuance of the securities to Cinergy Corp. in exchange for a note payable to the trust that was eliminated in consolidation. The proceeds of $306 million, which was net of approximately $10 million of issuance costs, were used to pay down Cinergy Corp.’s short-term indebtedness. In January and February 2005, certain holders settled the stock purchase contracts early and elected to remove the units from the remarketing. In February 2005, the remaining preferred trust securities were successfully remarketed and the dividend rate was reset at 6.9 percent. The preferred trust securities will mature in February 2007. To settle the stock purchase contracts, Cinergy Corp. issued 9.2 million shares of common stock at the ceiling price of $34.40 per share as the market price of the stock exceeded the ceiling price of the contract. Net proceeds of approximately $316 million were used to repay short-term indebtedness.
Each Unit continues to receive quarterly cash payments of 6.9 percent per annum of the notional amount, which represents a preferred trust security dividend. The trust’s ability to pay dividends on the preferred trust securities is solely dependent on its receipt of interest payments from Cinergy Corp. on the note payable. However, Cinergy Corp. has fully and unconditionally guaranteed the preferred trust securities.
As of July 1, 2003, we no longer consolidate the trust that was established to issue the preferred trust securities. The preferred trust securities are no longer included in Cinergy Corp.’s Balance Sheets. In addition, the note payable owed to the trust, which has a current carrying value of $324 million, is included in Long-term debt.
(c) Sales of Accounts Receivable
In February 2002, CG&E, PSI, and ULH&P entered into an agreement to sell certain of their accounts receivable and related collections. Cinergy Corp. formed Cinergy Receivables Company, LLC (Cinergy Receivables) to purchase, on a revolving basis, nearly all of the retail accounts receivable and related collections of CG&E, PSI, and ULH&P. Cinergy Corp. does not consolidate Cinergy Receivables since it meets the requirements to be accounted for as a qualifying SPE. The transfers of receivables are accounted for as sales, pursuant to Statement 140.
The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from Cinergy Receivables for a portion of the purchase price (typically approximates 25 percent of the total proceeds). The note is subordinate to senior loans that Cinergy Receivables obtains from commercial paper conduits controlled by unrelated financial institutions. Cinergy Receivables provides credit enhancement related to senior loans in the form of over-collateralization of the purchased receivables. However, the over-collateralization is calculated monthly and does not extend to the entire pool of receivables held by Cinergy Receivables at any point in time. As such, these senior loans do not have recourse to all assets of Cinergy Receivables. These loans provide the cash portion of the proceeds paid to CG&E, PSI, and ULH&P.
This subordinated note is a retained interest (right to receive a specified portion of cash flows from the sold assets) under SFAS No. 140, Accounting for Transfer and Servicing of Financial Assets and Extinguishments of Liabilities - a replacement of FASB Statement No. 125 (Statement 140) and is classified within Notes receivable from affiliated companies in the accompanying Balance Sheets of CG&E, PSI, and ULH&P and is classified within Notes receivable on Cinergy Corp.’s Balance Sheets. In addition, Cinergy Corp.’s investment in Cinergy Receivables constitutes a purchased beneficial interest (purchased right to receive specified cash flows, in our case residual cash flows), which is subordinate to the retained interests held by CG&E, PSI, and ULH&P. The carrying values of the retained interests are determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions in estimating fair value are credit losses and selection of discount rates. Because (a) the receivables generally turn in less than two months, (b) credit losses are reasonably predictable due to each company’s broad customer base and lack of significant concentration, and (c) the purchased beneficial interest is subordinate to all retained interests and thus would absorb losses first, the allocated bases of the subordinated notes are not materially different than their face value. Interest accrues to CG&E, PSI, and ULH&P on the retained interests using the accretable yield method, which generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent. Cinergy Corp. records income from Cinergy Receivables in a similar manner. We record an impairment charge against the carrying value of both the retained interests and purchased beneficial interest whenever we determine that an other-than-temporary impairment has occurred (which is unlikely unless credit losses on the receivables far exceed the anticipated level).
The key assumptions used in measuring the retained interests are as follows (all amounts are averages of the assumptions used in sales during the period):
(1) Receivables at each month-end divided by annualized sales for the month.
The hypothetical effect on the fair value of the retained interests assuming both a 10 percent and 20 percent unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history.
CG&E retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables. However, Cinergy Receivables assumes the risk of collection on the purchased receivables without recourse to CG&E, PSI, and ULH&P in the event of a loss. While no direct recourse to CG&E, PSI, and ULH&P exists, these entities risk loss in the event collections are not sufficient to allow for full recovery of their retained interests. No servicing asset or liability is recorded since the servicing fee paid to CG&E approximates a market rate.
The following table shows the gross and net receivables sold, retained interests, purchased beneficial interest, sales, and cash flows during the periods ending December 31, 2005 and 2004.
(d) Other
Cinergy also holds interests in several joint ventures, primarily engaged in cogeneration and energy efficiency operations, that are considered VIEs which do not require consolidation. Our exposure to loss from our involvement with these entities is not material.
6. Long-Term Debt
Refer to the Statements of Capitalization for detailed information for Cinergy’s, CG&E’s, PSI’s, and ULH&P’s long-term debt.
In February 2004, CG&E repaid at maturity $110 million of its 6.45% First Mortgage Bonds.
In April 2004, Cinergy Corp. repaid at maturity $200 million of its 6.125% Debentures.
In September 2004, Cinergy Corp. repaid at maturity $500 million of its 6.25% Debentures.
In November 2004, CG&E borrowed the proceeds from the Ohio Air Quality Development Authority’s issuance of $47 million principal amount of its State of Ohio Air Quality Development Revenue Bonds 2004 Series A and $47 million principal amount of its State of Ohio Air Quality Development Revenue Bonds 2004 Series B (for loans totaling $94 million), both due November 1, 2039. Payment of principal and interest on the Bonds when due is insured by separate bond insurance policies issued by XL Capital Assurance. The initial interest rate for both Series A and Series B was 1.92%. The interest rates on Series A and Series B were initially reset on January 5, 2005 and January 12, 2005, respectively, and then every 35 days by auction thereafter. Because the holders cannot tender the Bonds for purchase by the issuer while the Bonds are in the auction rate mode, these debt obligations are classified as Long-term debt. CG&E is using the proceeds from these borrowings to assist in financing its portion of the costs of acquiring, constructing and installing certain solid waste disposal facilities comprising air quality facilities at Units 7 and 8 at CG&E’s majority-owned Miami Fort Generating Station (Miami Fort Station).
In December 2004, PSI borrowed the proceeds from the Indiana Development Finance Authority’s issuance of $77 million principal amount of its Environmental Revenue Bonds, Series 2004B and $77 million principal amount of its Environmental Revenue Bonds, Series 2004C, both due December 1, 2039 (for loans totaling $154 million). Payment of principal and interest on the Bonds when due is insured by separate bond insurance policies issued by XL Capital Assurance. The initial interest rate for Series 2004B was 1.80% and for Series 2004C was 1.85%. The interest rates on both Series 2004B and Series 2004C were initially reset on January 11, 2005 and then every 35 days by auction thereafter. Because the holders cannot tender the Bonds for purchase by the issuer while the Bonds are in the auction rate mode, these debt obligations are classified as Long-term debt. PSI is using the proceeds from these
borrowings to assist in the acquisition and construction of solid waste disposal facilities located at various generating stations in Indiana.
Also, in December 2004, ULH&P issued $40 million principal amount of its 5.00% Debentures due December 15, 2014 (effective interest rate of 5.26%). Proceeds from this issuance were used for general corporate purposes and the repayment of outstanding indebtedness.
In August 2005, PSI redeemed all of its $50 million 6.50% Synthetic Putable Yield Securities due August 1, 2026 through the exercise of call provisions within the securities.
Also in August 2005, PSI redeemed all of its $50 million principal amount Series ZZ First Mortgage secured 5 ¾% Series 1993B Environmental Revenue Refunding Bonds, due February 15, 2028. PSI redeemed these bonds with the proceeds from the issuance by the Indiana Finance Authority of $50 million principal amount of its Environmental Revenue Refunding Bonds, Series 2005A, due July 1, 2035. The bonds bear a fixed rate of interest through 2035 of 4.50 percent.
In September 2005, PSI redeemed all of its $30 million principal amount 7.125% Series AAA First Mortgage Bonds, due 2024.
In October 2005, PSI borrowed the proceeds from the Indiana Finance Authority’s issuance of $50 million principal amount of its Environmental Revenue Bonds, Series 2005C, due October 1, 2040. The initial interest rate for Series 2005C Bonds was 2.75%. This rate initially reset on December 2, 2005 and then every 35 days by auction thereafter. Because the holders cannot tender the Series 2005C Bonds for purchase by the issuer while the Series 2005C Bonds are in the auction rate mode, these debt obligations are classified as Long-term debt. PSI is using the proceeds from these borrowings to assist in the acquisition and construction of solid waste disposal facilities located at various generating stations in Indiana.
Also in October 2005, PSI issued $350 million principal amount of its 6.12% Debentures due October 15, 2035. Proceeds from this issuance were used for general corporate purposes and the repayment of outstanding short-term indebtedness.
In January 2006, ULH&P assumed responsibility for principal and interest payments on $61 million of CG&E’s long-term pollution control bonds in conjunction with the transfer of certain generating assets to ULH&P. The bonds will still remain on CG&E’s balance sheet and ULH&P’s obligation will be reflected as an intercompany note payable from ULH&P to CG&E. See Note 22 for additional information.
The following table reflects the long-term debt maturities excluding any redemptions due to the exercise of call provisions or capital lease obligations. Callable means we have the right to buy back a given security from the holder at a specified price before maturity.
Long-term Debt Maturities
(1) The results of Cinergy also include amounts related to non-registrants.
Maintenance and replacement fund provisions contained in PSI’s first mortgage bond indenture require: (1) cash payments, (2) bond retirements, or (3) pledges of unfunded property additions each year based on an amount related to PSI’s net revenues.
CG&E’s transmission and distribution assets of approximately $2.9 billion are subject to the lien of its first mortgage bond indenture. The utility property of PSI is also subject to the lien of its first mortgage bond indenture.
As discussed previously, CG&E and PSI periodically borrowed proceeds from the issuance of tax-exempt bonds for the purpose of funding the acquisition and construction of solid waste disposal facilities located at various generating stations in Indiana and Ohio. Because some of these facilities have not commenced construction and others are not yet complete, proceeds from the borrowings have been placed in escrow with a trustee and may be drawn upon only as facilities are built and qualified costs incurred. In the event any of the proceeds are not drawn, CG&E and PSI would eventually be required to return the unused proceeds to bondholders. CG&E and PSI expect to draw down all of the proceeds over the next two years.
7. Notes Payable and Other Short-term Obligations
Short-term obligations may include:
• short-term notes;
• variable rate pollution control notes;
• commercial paper; and
• money pool.
Cinergy Corp.’s short-term borrowings consist primarily of unsecured revolving lines of credit and the sale of commercial paper. Cinergy Corp.’s revolving credit facility and commercial paper program also support the short-term borrowing needs of CG&E, PSI, and ULH&P. In addition, Cinergy Corp., CG&E, and PSI maintain uncommitted lines of credit. These facilities are not firm sources of capital but rather informal agreements to lend money, subject to availability, with pricing determined at the time of advance. The following table summarizes our Notes payable and other short-term obligations and Notes payable to affiliated companies:
(1) Consists of a five-year facility which was entered into in September 2005, matures in September 2010, and contains $500 million sublimits each for CG&E and PSI, and a $100 million sublimit for ULH&P (which was increased from $65 million in conjunction with its transaction with CG&E in which ULH&P acquired interests in three of CG&E’s electric generating stations. See Note 22 for further information regarding this transaction.)
(2) Cinergy Corp.’s commercial paper program limit is $1.5 billion. The commercial paper program is supported by Cinergy Corp.’s revolving line of credit.
(3) Of the $162 million and $158 million, in 2005 and 2004, respectively, $150 million relates to a three-year senior revolving credit facility that Cinergy Canada, Inc. entered into in December 2004 that matures in December 2007.
(a) Short-term Notes
Short-term borrowings mature within one year from the date of issuance. We primarily use an unsecured revolving line of credit and the sale of commercial paper for short-term borrowings. A portion of Cinergy Corp.’s revolving line is used to provide credit support for commercial paper and letters of credit. When the revolving line is reserved for commercial paper or backing letters of credit, it is not available for additional borrowings. The fees paid to secure short-term borrowings were immaterial during each of the years ended December 31, 2005, 2004, and 2003.
In September 2005, Cinergy Corp., CG&E, PSI, and ULH&P entered into a five-year revolving credit facility with a termination date of September 2010, which can be extended twice, each extension for an additional one-year
period. The new credit agreement replaces two existing credit agreements, one dated April 2004 and one dated December 2004.
The new credit agreement provides that the pending merger between Duke and Cinergy Corp. will not be considered a fundamental change or a “Change of Control” for purposes of the credit agreement.
For purposes of making borrowings the new credit agreement does not require certain environmental, legal or material adverse change representations and warranties that were in the credit agreements it replaced.
At December 31, 2005, Cinergy Corp. had $1.1 billion remaining unused and available capacity relating to its $2 billion revolving credit facility. This revolving credit facility includes the following:
(1) In September 2005, Cinergy Corp. successfully placed a $2 billion senior unsecured revolving credit facility which replaced the $1 billion three-year facility, set to expire in April 2007, and the $1 billion five-year facility, set to expire in December 2009. CG&E and PSI each have $500 million borrowing sublimits on this facility, and ULH&P has a $100 million borrowing sublimit on this facility (which was increased from $65 million in conjunction with its transaction with CG&E in which ULH&P acquired interests in three of CG&E’s electric generating stations. See Note 22 for further information regarding this transaction.)
In addition to the revolving credit facility, Cinergy Corp., CG&E, and PSI also maintain uncommitted lines of credit. These facilities are not guaranteed sources of capital and represent an informal agreement to lend money, subject to availability, with pricing to be determined at the time of advance. Cinergy Corp., CG&E, and PSI have established uncommitted lines of $40 million, $15 million, and $60 million, respectively, all of which remained unused as of December 31, 2005.
In our credit facility, Cinergy Corp. has covenanted to maintain:
• a consolidated net worth of $2 billion; and
• a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.
As part of CG&E’s $500 million sublimit under the $2 billion five-year credit facility, CG&E has covenanted to maintain:
• a consolidated net worth of $1 billion; and
• a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.
As part of PSI’s $500 million sublimit under the $2 billion five-year credit facility, PSI has covenanted to maintain:
• a consolidated net worth of $900 million; and
• a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.
As part of ULH&P’s $100 million sublimit under the $2 billion five-year credit facility, ULH&P has covenanted to maintain:
• a consolidated net worth of $200 million; and
• a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.
A breach of these covenants could result in the termination of the credit facility and the acceleration of the related indebtedness. In addition to breaches of covenants, certain other events that could result in the termination of the available credit and acceleration of the related indebtedness include:
• bankruptcy;
• defaults in the payment of other indebtedness; and
• judgments against the company that are not paid or insured.
The latter two events, however, are subject to dollar-based materiality thresholds. In no event shall a default on the part of CG&E, PSI, or ULH&P result solely from a default on the part of any other borrower, including Cinergy. As of December 31, 2005, Cinergy, CG&E, PSI, and ULH&P are in compliance with all of their debt covenants.
(b) Variable Rate Pollution Control Notes
CG&E and PSI have issued certain variable rate pollution control notes (tax-exempt notes obtained to finance equipment or land development for pollution control purposes). Because the holders of these notes have the right to have their notes redeemed on a daily, weekly, or monthly basis, they are reflected in Notes payable and other short-term obligations on the Balance Sheets of Cinergy, CG&E, and PSI. At December 31, 2005, Cinergy, CG&E and PSI had $323 million, $112 million and $186 million, respectively, outstanding in variable rate pollution control notes, classified as short-term debt. ULH&P had no outstanding short-term pollution control notes. Any short-term pollution control note borrowings outstanding do not reduce the unused and available short-term debt regulatory authority of CG&E, PSI, and ULH&P.
In August 2004, PSI borrowed the proceeds from the issuance by the Indiana Development Finance Authority of $55 million principal amount of its Environmental Revenue Bonds, Series 2004A, due August 2039. The initial interest rate for the bonds was 1.13% and is reset weekly. Proceeds from the borrowing will be used for the acquisition and construction of various solid waste disposal facilities located at various generating stations in Indiana. The funds are being held in escrow by an independent trustee and will be drawn upon as facilities are built. Holders of these notes are entitled to credit enhancement in the form of a standby letter of credit which, if drawn upon, provides for the payment of both interest and principal on the notes. Because the holders of these notes have the right to have their notes redeemed on a weekly basis, they are reflected in Notes payable and other short-term obligations on Cinergy’s and PSI’s Balance Sheets.
In October 2005, PSI borrowed the proceeds from the Indiana Finance Authority’s issuance of $50 million principal amount of its Environmental Revenue Bonds, Series 2005B, due October 1, 2040. Holders of the Series 2005B Bonds are entitled to credit enhancement in the form of a standby letter of credit, which if drawn upon, provides for the payment of both interest and principal on the Series 2005B Bonds. The initial interest rate for the Series 2005B Bonds was 2.75% and is reset weekly. Because the holders have the right to have their Bonds redeemed on a weekly basis, they are classified as Notes payable and other short-term obligations on Cinergy’s and PSI’s Balance Sheets. PSI is using the proceeds from these borrowings to assist in the acquisition and construction of solid waste disposal facilities located at various generating stations in Indiana.
In January 2006, ULH&P assumed responsibility for principal and interest payments on $16 million of CG&E’s redeemable variable rate pollution control bonds in conjunction with the transfer of certain generating assets to ULH&P. The bonds will still remain on CG&E’s balance sheet and ULH&P’s obligation will be reflected as an intercompany note payable from ULH&P to CG&E. See Note 22 for additional information.
(c) Commercial Paper
Cinergy Corp.’s commercial paper program is supported by Cinergy Corp.’s $2 billion revolving credit facility. The commercial paper program supports, in part, the short-term borrowing needs of CG&E and PSI and eliminates their need for separate commercial paper programs. In September 2004, Cinergy Corp. expanded its commercial paper program from $800 million to a maximum outstanding principal amount of $1.5 billion. As of December 31, 2005, Cinergy Corp. had $515 million in commercial paper outstanding.
(d) Money Pool
Cinergy Corp., Services, and our utility operating companies participate in a money pool arrangement to better manage cash and working capital requirements. Under this arrangement, those companies with surplus short-term funds provide short-term loans to affiliates (other than Cinergy Corp.) participating under this arrangement. This surplus cash may be from internal or external sources. The amounts outstanding under this money pool arrangement are shown as a component of Notes receivable from affiliated companies and/or Notes payable to affiliated companies on the Balance Sheets of CG&E, PSI, and ULH&P. Any money pool borrowings outstanding reduce the unused and available short-term debt regulatory authority of CG&E, PSI, and ULH&P.
8. Leases
(a) Operating Leases
We have entered into operating lease agreements for various facilities and properties such as computer, communication and transportation equipment, and office space. Total rental payments on operating leases for each of the past three years are detailed in the following table. This table also shows future minimum lease payments required for operating leases with remaining non-cancelable lease terms in excess of one year as of December 31, 2005:
(1) The results of Cinergy also include amounts related to non-registrants.
(b) Capital Leases
In each of the years 1999 through 2005, CG&E, PSI, and ULH&P entered into capital lease agreements to fund the purchase of gas and electric meters, and associated equipment. The lease terms are for 120 months commencing with the date of purchase and contain buyout options ranging from 105 to 108 months. The first buyout will occur in December 2008 and each year thereafter. It is our objective to own the meters and associated equipment indefinitely and the operating companies plan to exercise the buyout option at month 105. As of December 31, 2005, Cinergy’s effective interest rate on capital lease obligations outstanding was 5.5 percent. The meters and associated equipment are depreciated at the same rate as if owned by the operating companies. CG&E, PSI, and ULH&P each recorded a capital lease obligation, included in Non-Current Liabilities-Other.
The total minimum lease payments and the present values for these capital lease items are shown below:
(1) Annual minimum lease payments are immaterial.
9. Financial Instruments
(a) Financial Derivatives
We have entered into financial derivative contracts for the purpose of managing financial instrument risk.
Our current policy of managing exposure to fluctuations in interest rates is to maintain approximately 30 percent of the total amount of outstanding debt in variable interest rate debt instruments. In maintaining this level of exposure, we use interest rate swaps. Under the swaps, we agree with other parties to exchange, at specified intervals, the difference between fixed rate and variable rate interest amounts calculated on an agreed notional amount.
CG&E has an outstanding interest rate swap agreement that decreased the percentage of variable rate debt. Under the provisions of the swap, which has a notional amount of $100 million, CG&E pays a fixed rate and receives a variable rate through October 2007. This swap qualifies as a cash flow hedge under the provisions of Statement 133. As the terms of the swap agreement mirror the terms of the debt agreement that it is hedging, we anticipate that this swap will continue to be effective as a hedge. Changes in fair value of this swap are recorded in Accumulated other comprehensive income (loss).
In June 2005, PSI executed two forward starting swaps with a combined notional amount of $325 million. The forward starting swaps effectively fix the benchmark interest rate of an anticipated issuance of fixed rate debt from June 2005 through June 2006, the expected date of issuance of the debt securities. Both forward starting swaps have been designated as cash flow hedges under the provisions of Statement 133. As the terms of these swap agreements mirror the terms of the forecasted debt issuance, we anticipate that they will be highly effective hedges. Changes in the fair value of these swaps are recorded in Accumulated other comprehensive income (loss).
See Note 1(m)(ii) for additional information on financial derivatives. In the future, we will continually monitor market conditions to evaluate whether to modify our use of financial derivative contracts to manage financial instrument risk.
(b) Fair Value of Other Financial Instruments
The estimated fair values of other financial instruments were as follows (this information does not claim to be a valuation of the companies as a whole):
(1) The results of Cinergy also include amounts related to non-registrants.
(2) Includes amounts reflected as Long-term debt due within one year.
The following methods and assumptions were used to estimate the fair values of each major class of instruments:
(i) Cash and cash equivalents, Restricted deposits, and Notes payable and other short-term obligations
Due to the short period to maturity, the carrying amounts reflected on the Balance Sheets approximate fair values.
(ii) Long-term debt
The fair values of long-term debt issues were estimated based on the latest quoted market prices or, if not listed on the New York Stock Exchange, on the present value of future cash flows. The discount rates used approximate the incremental borrowing costs for similar instruments.
(c) Credit Risk
Credit risk is the exposure to economic loss that would occur as a result of nonperformance by counterparties, pursuant to the terms of their contractual obligations. Specific components of credit risk include counterparty default risk, collateral risk, concentration risk, and settlement risk.
(i) Trade Receivables and Physical Power Portfolio
Our concentration of credit risk with respect to trade accounts receivable from electric and gas retail customers is limited. The large number of customers and diversified customer base of residential, commercial, and industrial customers significantly reduces our credit risk. Contracts within the physical portfolio of power marketing and trading operations are primarily with traditional electric cooperatives and municipalities and other investor-owned utilities. At December 31, 2005, we believe the likelihood of significant losses associated with credit risk in our trade accounts receivable or physical power portfolio is remote.
(ii) Energy Trading Credit Risk
Cinergy’s extension of credit for energy marketing and trading is governed by a Corporate Credit Policy. Written guidelines approved by Cinergy’s Risk Policy Committee document the management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation procedures. Exposures to credit risks are monitored daily by the Corporate Credit Risk function, which is independent of all trading operations. As of December 31, 2005, 95 percent of Cinergy’s credit exposure and 89 percent of CG&E’s credit exposure, net of credit collateral, related to energy trading and marketing activity was with counterparties rated investment grade or the counterparties’ obligations were guaranteed or secured by an investment grade entity. The majority of these investment grade counterparties are externally rated. If a counterparty has an external rating, the lower of Standard & Poor’s or Moody’s Investors Service is used; otherwise, Cinergy’s internal rating of the counterparty is used. Cinergy’s remaining five percent represents credit exposure of $74 million and CG&E’s remaining 11 percent represents credit exposure of $38 million with counterparties rated non-investment grade.
As of December 31, 2005, CG&E had a concentration of trading credit exposure of $62 million with one counterparty accounting for greater than 10 percent of CG&E’s total trading credit exposure. This counterparty is rated investment grade.
Energy commodity prices can be extremely volatile and the market can, at times, lack liquidity. Because of these issues, credit risk for energy commodities is generally greater than with other commodity trading.
We continually review and monitor our credit exposure to all counterparties and secondary counterparties. If appropriate, we adjust our credit reserves to attempt to compensate for increased credit risk within the industry. Counterparty credit limits may be adjusted on a daily basis in response to changes in a counterparty’s financial status or public debt ratings.
(iii) Financial Derivatives
Potential exposure to credit risk also exists from our use of financial derivatives such as interest rate swaps and treasury locks. Because these financial instruments are transacted with highly rated financial institutions, we do not anticipate nonperformance by any of the counterparties.
10. Notes Receivable
Cinergy has approximately $194 million and $214 million of notes receivable as of December 31, 2005 and 2004, respectively, comprised of two separate notes with one counterparty. The credit rating of the counterparty is BBB.
The first note, with a December 31, 2005 balance of $82 million and a December 31, 2004 balance of $101 million, bears an effective interest rate of 7.81 percent and matures in August 2009. The second note, with a balance of $112 million as of December 31, 2005 and $113 million as of December 31, 2004, bears an effective interest rate of 9.23 percent and matures in December 2016.
The following table reflects the maturities of these notes as of December 31, 2005.
11. Pension and Other Postretirement Benefits
Cinergy Corp. sponsors both pension and other postretirement benefit plans.
Our qualified defined benefit pension plans cover substantially all United States employees meeting certain minimum age and service requirements. During 2002, eligible Cinergy employees were offered the opportunity to make a one-time election, effective January 1, 2003, to either continue to have their pension benefit determined by the traditional defined benefit pension formula or to have their benefit determined using a cash balance formula. A similar election was provided to certain union employees at a later time.
The traditional defined benefit program utilizes a final average pay formula to determine pension benefits. These benefits are based on:
• years of participation;
• age at retirement; and
• the applicable average Social Security wage base.
Benefits are accrued under the cash balance formula based upon a percentage of pension eligible earnings plus interest. In addition, participants with the cash balance formula may request a lump-sum cash payment upon termination of their employment, which may result in increased cash requirements from pension plan assets. At the effective time of the election, benefits ceased accruing under the traditional defined benefit pension formula for employees who elected the cash balance formula. There was no change to retirement benefits earned prior to the effective time of the election. The pension benefits of all non-union and certain union employees hired after
December 31, 2002 are calculated using the cash balance formula. At December 31, 2005, approximately 81 percent of Cinergy’s employees remain in the traditional defined benefit program.
The introduction of the cash balance features to our defined benefit plans did not have a material effect on our financial position or results of operations.
Funding for the qualified defined benefit pension plans is based on actuarially determined contributions, the maximum of which is generally the amount deductible for tax purposes and the minimum being that required by the Employee Retirement Income Security Act of 1974, as amended. The pension plans’ assets consist of investments in equity and debt securities.
Cinergy’s investment strategy with respect to pension assets is designed to achieve a moderate level of overall portfolio risk in keeping with our desired risk objective, which is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The portfolio’s target asset allocation is 60 percent equity and 40 percent debt with specified allowable ranges around these targets. Within the equity segment, we are broadly diversified across domestic, developed international and emerging market equities, with the largest concentration being domestic. Further diversification is achieved through allocations to growth/value and small-, mid-, and large-cap equities. Within the debt segment, we principally maintain separate “core plus” and “core” portfolios. The “core plus” portfolio makes tactical use of the “plus” sectors (e.g., high yield, developed international, emerging markets, etc.) while the “core” portfolio is a domestic, investment grade portfolio. In late 2004, Cinergy commenced the implementation of alternative investment strategies in its investment program. The initial allocation incorporated an investment in a hedge fund of funds in conjunction with an S&P 500 swaps and futures overlay program and is classified as part of our large-cap United States equity allocation. In 2005, a commitment was made to a private equity fund of funds with funding expected to occur over an approximate three-year period. Fund of funds are limited partnership vehicles that allocate invested capital to underlying funds (e.g. hedge funds or private equity) that pursue various investment strategies. Other than the hedge fund of funds strategy, the use of derivatives is currently limited to collateralized mortgage obligations and asset-backed securities. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
Cinergy uses a September 30 measurement date for its defined benefit pension plans. The asset allocation at September 30, 2005 and 2004 by asset category was as follows:
(1) The portfolio’s target asset allocation is 60 percent equity with an allowable range of 50 percent to 70 percent.
(2) The portfolio’s target asset allocation is 40 percent debt with an allowable range of 30 percent to 50 percent.
In addition, Cinergy Corp. sponsors non-qualified pension plans (plans that do not meet the criteria for certain tax benefits) that cover officers, certain other key employees, and non-employee directors. We began funding certain of these non-qualified plans through a rabbi trust in 1999. This trust, which consists of equity (64 percent) and debt (36 percent) securities at December 31, 2005, is not restricted to the payment of plan benefits and therefore, not considered plan assets under Statement 87. Trust assets were approximately $10 million, for both the years ended December 31, 2005 and 2004, and are reflected in Cinergy’s Balance Sheets as Other investments.
Cinergy Corp. provides certain health care and life insurance benefits to retired United States employees and their eligible dependents. These benefits are subject to minimum age and service requirements. The health care benefits include medical coverage, dental coverage, and prescription drugs and are subject to certain limitations, such as deductibles and co-payments. Neither CG&E nor ULH&P pre-fund their obligations for these postretirement benefits. In 1999, PSI began pre-funding its obligations through a grantor trust as authorized by the IURC. This trust, which consists of equity (65 percent) and debt (35 percent) securities at December 31, 2005, is not restricted to
the payment of plan benefits and therefore, not considered plan assets under Statement 106. At December 31, 2005 and 2004, trust assets were approximately $74 million and $71 million, respectively, and are reflected in Cinergy’s Balance Sheets as Other investments.
Qualified pension benefit contributions for 2005 were $102 million. Based on preliminary estimates, we expect 2006 contributions of approximately $120 million for qualified pension benefits. As discussed previously, we do not hold “plan assets” as defined by Statement 87 and Statement 106 for our non-qualified pension plans and other postretirement benefit costs, and therefore contributions are equal to the benefit payments presented in the following table.
The following estimated benefits payments, which reflect future service, are expected to be paid:
Our benefit plans’ costs for the past three years included the following components:
(1) SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits (Statement 88).
The net periodic benefit cost by registrant was as follows:
(1) The results of Cinergy also include amounts related to non-registrants.
The following table provides a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for 2005 and 2004, and a statement of the funded status for both years. Cinergy uses a September 30 measurement date for its defined benefit pension plans and other postretirement benefit plans.
The accumulated benefit obligation for the qualified defined benefit pension plans was approximately $1,535 million and approximately $1,387 million for 2005 and 2004, respectively. The accumulated benefit obligation for the non-qualified defined benefit pension plans was approximately $132 million and $111 million for 2005 and 2004, respectively.
The weighted-average assumptions used to determine benefit obligations were as follows:
The weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31, 2005, 2004, and 2003 were as follows:
Our discount rate is determined by matching the anticipated payouts under our pension and postretirement plans to the rates from a hypothetical spot rate yield curve. The curve is created by deriving the rates for hypothetical zero coupon bonds from high-yield double A coupon bonds of varying maturities. Non-callable bonds and outliers (defined as bonds with yields outside of two standard deviations from the mean) are excluded in computing the yield curve.
The calculation of Cinergy’s expected long-term rate of return is a two-step process. Capital market assumptions (e.g., forecasts) are first developed for various asset classes based on underlying fundamental and economic drivers of performance. Such drivers for equity and debt instruments include profit margins, dividend yields, and interest paid for use of capital. Risk premiums for each asset class are then developed based on factors such as expected liquidity, credit spreads, inflation uncertainty and country/currency risk. Current valuation factors such as present interest and inflation rate levels underpin this process.
The assumptions are then modeled via a probability based multi-factor capital market methodology. Through this modeling process, a range of possible 10-year annualized returns are generated for each strategic asset class. Those returns falling at the 50th percentile are utilized in the calculation of Cinergy’s expected long-term rate of return.
The assumed health care cost trend rates were as follows:
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. Our health care cost trend is calculated using healthcare inflation rates, Gross Domestic Product growth, Medicare integration, allowances for plan design variables, and other cost drivers. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduced a prescription drug benefit to retirees as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is actuarially equivalent to the benefit provided by Medicare. We believe that our coverage for prescription drugs is at least actuarially equivalent to the benefits provided by Medicare for most current retirees because our benefits for that group substantially exceed the benefits provided by Medicare, thereby allowing us to qualify for the subsidy. We have accounted for the subsidy as a reduction of our APBO. The APBO was reduced by approximately $17 million and will be amortized as an actuarial gain over future periods, thus reducing future benefit costs. The impact on our 2004 and 2005 net periodic benefit cost was not material. Our accounting treatment for the subsidy is consistent
with FASB Staff Position No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
In January 2004, Cinergy announced to employees the creation of a new retiree Health Reimbursement Account (HRA) option, which will impact the postretirement healthcare benefits provided by Cinergy. HRAs are bookkeeping accounts that can be used to pay for qualified medical expenses after retirement. The majority of employees had the opportunity during the Fall of 2004 to make a one-time election to remain in Cinergy’s current retiree healthcare program or to move to the new HRA option. Approximately 40 percent of Cinergy’s employees elected the new HRA option. The HRA option has no effect on current retirees receiving postretirement benefits from Cinergy. As is the case under the current retiree health program, employees who participate in the HRA option, generally, will become eligible to receive their HRA benefit only upon retirement on or after the age of 50 with at least five years of service. We expect that the impact of the new HRA option will not be material to our other postretirement benefit costs.
12. Income Taxes
The following table shows the significant components of Cinergy’s, CG&E’s, PSI’s, and ULH&P’s net deferred income tax liabilities as of December 31:
(1) The results of Cinergy also include amounts related to non-registrants.
Cinergy and its subsidiaries file a consolidated federal income tax return and combined/consolidated state and local tax returns in certain jurisdictions. The corporate taxable income method is used to allocate tax benefits to the subsidiaries whose investments or results of operations provide those tax benefits. Any tax liability not directly attributable to a specific subsidiary is allocated proportionately among the subsidiaries as required by the agreement.
The following table summarizes federal and state income taxes charged (credited) to income for Cinergy, CG&E, PSI, and ULH&P:
(1) The results of Cinergy also include amounts related to non-registrants.
Internal Revenue Code (IRC) Section 29/45K provides a tax credit (nonconventional fuel source credit) for qualified fuels produced and sold by a taxpayer to an unrelated person during the taxable year. The nonconventional fuel source credit reduced current federal income tax expense approximately $124 million, $98 million, and $84 million for 2005, 2004, and 2003, respectively. See Note
13(c)(ii) for further information on this tax credit.
The following table presents a reconciliation of federal income taxes (which are calculated by multiplying the statutory federal income tax rate by book income before federal income tax) to the federal income tax expense reported in the Statements of Income for Cinergy, CG&E, PSI, and ULH&P.
(1) The results of Cinergy also include amounts related to non-registrants.
In January 2006, ULH&P completed the acquisition of certain generating assets of CG&E. The asset transfer, which occurred at net book value, will increase the net deferred income tax liabilities related to these assets by
approximately $7.4 million over the net deferred tax liabilities recognized by CG&E as the result of the change in tax jurisdictions. See Note 22 for additional information on the transfer.
13. Commitments and Contingencies
(a) Environmental
(i) Emission Reduction Rulemakings
In October 1998, the Environmental Protection Agency (EPA) finalized its ozone transport rule, also known as the nitrogen oxides (NOX) State Implementation Plan (SIP) Call, which addresses wind-blown ozone and ozone precursors that impact air quality in downwind states. The EPA’s final rule, which applies to 22 states in the eastern United States including the three states in which our electric utilities operate, required states to develop rules to reduce NOX emissions from utility and industrial sources. In a related matter, in response to petitions filed by several states alleging air quality impacts from upwind sources located in other states, the EPA issued a rule pursuant to Section 126 of the Clean Air Act (CAA) that required reductions similar to those required under the NOX SIP Call. Various states and industry groups challenged the final rules in the Court of Appeals for the District of Columbia Circuit, but the court upheld the key provisions of the rules.
The EPA has proposed withdrawal of the Section 126 rule in states with approved rules under the final NOX SIP Call, which includes Indiana, Kentucky, and Ohio. All three states have adopted a cap and trade program as the mechanism to achieve the required reductions. Cinergy, CG&E, and PSI have installed selective catalytic reduction units (SCR) and other pollution controls and implemented certain combustion improvements at various generating stations to comply with the NOX SIP Call. Cinergy also utilizes the NOX emission allowance market to buy or sell NOX emission allowances as appropriate. As of December 31, 2005, we have incurred approximately $822 million in capital costs to comply with this program and do not anticipate significant additional costs.
In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR) which would require states to revise their SIP by September 2006 to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards for ozone and fine particulate matter. The rule established a two-phase, regional cap and trade program for sulfur dioxide (SO2) and NOX, affecting 28 states, including Ohio, Indiana, and Kentucky, and requires SO2 and NOX emissions to be cut 70 percent and 65 percent, respectively, by 2015. At the same time, the EPA issued the Clean Air Mercury Rule (CAMR) which requires national reductions in mercury emissions from coal-fired power plants beginning in 2010. Accompanying the CAMR publication in the Federal Register was the EPA’s determination that it was not appropriate and necessary to regulate mercury emissions from utilities under Section 112 of the CAA, requiring maximum achievable control technology, so that it would be possible to regulate those emissions under Section 111 of the CAA with the CAMR. The final regulation also adopts a two-phase cap and trade approach that requires mercury emissions to be cut by 70 percent by 2018. SIPs must comply with the prescribed reduction levels under CAIR and CAMR; however, the states have the ability to introduce more stringent requirements if desired. Under both CAIR and CAMR, companies have flexible compliance options including installation of pollution controls on large plants where such controls are particularly efficient and utilization of emission allowances for smaller plants where controls are not cost effective.
In August 2005, the EPA proposed a Federal Implementation Plan (FIP), which would implement phase 1 of CAIR by 2009 and 2010 for NOX and SO2, respectively, for any state that does not develop a CAIR SIP in a timely manner. Numerous states, environmental organizations, industry groups, including some of which Cinergy is a member, and individual companies have challenged various portions of both rules. Those challenges are currently pending in the Federal Circuit Court for the District of Columbia. On October 21, 2005, the EPA agreed to reconsider certain aspects of the CAMR as well as the determination not to regulate mercury under Section 112 of the CAA. In December 2005 and again in January 2006, the EPA reconsidered portions of the CAIR, but did not propose any regulatory changes. At this time we cannot predict the outcome of these matters.
Over the 2006-2010 time period, we expect to spend approximately $1.4 billion to reduce mercury, SO2, and NOX emissions. These projected expenditures include estimated costs to comply at plants that we own but do not operate and could change when taking into consideration compliance plans of co-owners or operators involved. Moreover, as market conditions change, additional compliance options may become available and our plans will be adjusted
accordingly. Approximately 53 percent of these estimated environmental costs would be incurred at PSI’s coal-fired plants, for which recovery would be pursued in accordance with regulatory statutes governing environmental cost recovery. See (b)(ii) for more details. CG&E receives partial recovery of depreciation and financing costs related to environmental compliance projects for 2005-2008 through its RSP. See (b)(iii) for more details.
The EPA made final state non-attainment area designations to implement the revised ozone standard and to implement the new fine particulate standard in June 2004 and April 2005, respectively. Several counties in which we operate have been designated as being in non-attainment with the new ozone standard and/or fine particulate standard. States with counties that are designated as being in non-attainment with the new ozone and/or fine particulate standards are required to develop a plan of compliance by June 2007 and April 2008, respectively. Industrial sources in or near those counties are potentially subject to requirements for installation of additional pollution controls. In March 2005, various states, local governments, environmental groups, and industry groups, including some of which Cinergy is a member, filed petitions for review in the United States Court of Appeals for the D.C. Circuit to challenge the EPA’s particulate matter non-attainment designations. Although the EPA has attempted to structure CAIR to resolve purported utility contributions to ozone and fine particulate non-attainment, at this time, Cinergy cannot predict the effect of current or future non-attainment designations on its financial position or results of operations.
In July 2005, the EPA issued its final regional haze rules and implementing guidelines in response to a 2002 judicial ruling overturning key provisions of the original program. The regional haze program is aimed at reducing certain emissions impacting visibility in national parks and wilderness areas. The EPA has announced that it can foresee no circumstances where the requirements of the regional haze rule would require utility controls beyond those required under CAIR. The EPA also found that states participating in the CAIR cap and trade program need not require electric generating units to adhere to best available retrofit technology requirements. The states have until December 2007 to finalize their SIPs addressing compliance with EPA regulations. The states may choose to implement more stringent guidelines than promulgated by the EPA, and therefore it is not possible to predict whether the regional haze rule will have a material effect on our financial position or results of operations.
(ii) Section 126 Petitions
In March 2004, the state of North Carolina filed a petition under Section 126 of the CAA in which it alleges that sources in 13 upwind states including Ohio, Indiana, and Kentucky, significantly contribute to North Carolina’s non-attainment with certain ambient air quality standards. In August 2005, the EPA issued a proposed response to the petition. The EPA proposed to deny the ozone portion of the petition based upon a lack of contribution to air quality by the named states. The EPA also proposed to deny the particulate matter portion of the petition based upon the CAIR FIP, described earlier, that would address the air quality concerns from neighboring states. We expect a final FIP and ruling from the EPA on this matter by March 2006. It is unclear at this time whether any additional reductions would be necessary beyond those required under the CAIR.
(iii) Clean Air Act Lawsuit
In November 1999, and through subsequent amendments, the United States brought a lawsuit in the United States Federal District Court for the Southern District of Indiana against Cinergy, CG&E, and PSI alleging various violations of the CAA. Specifically, the lawsuit alleges that we violated the CAA by not obtaining Prevention of Significant Deterioration (PSD), Non-Attainment New Source Review (NSR), and Ohio and Indiana SIP permits for various projects at our owned and co-owned generating stations. Additionally, the suit claims that we violated an Administrative Consent Order entered into in 1998 between the EPA and Cinergy relating to alleged violations of Ohio’s SIP provisions governing particulate matter at Unit 1 at CG&E’s W.C. Beckjord Station. The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s W.C. Beckjord and Miami Fort Stations, and PSI’s Cayuga, Gallagher, Wabash River, and Gibson Stations, and (2) civil penalties in amounts of up to $27,500 per day for each violation. In addition, three northeast states and two environmental groups have intervened in the case. In August 2005, the district court issued a ruling regarding the emissions test that it will apply to Cinergy at the trial of the case. Contrary to Cinergy’s argument, the district court ruled that in determining whether a project was projected to increase annual emissions, it would not hold hours of operation constant. However, the district court subsequently certified the matter for interlocutory appeal to the Seventh Circuit Court of Appeals, which has accepted the appeal and set oral arguments for May 2006. In February 2006, the district court ruled that in carrying its burden of proof, the defendant can look to industry practice in proving a particular project was routine. The district
court has removed the trial from the calendar and will reset a trial date, if necessary, after the Seventh Circuit rules. Notwithstanding the appeal, there are a number of other legal issues currently before the district court judge.
In March 2000, the United States also filed in the United States District Court for the Southern District of Ohio an amended complaint in a separate lawsuit alleging violations of the CAA relating to PSD, NSR, and Ohio SIP requirements regarding various generating stations, including a generating station operated by Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company (DP&L), and CG&E. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP. In April 2001, the United States District Court for the Southern District of Ohio in that case ruled that the Government and the intervening plaintiff environmental groups cannot seek monetary damages for alleged violations that occurred prior to November 3, 1994; however, they are entitled to seek injunctive relief for such alleged violations. Neither party appealed that decision. This matter was heard in trial in July 2005. A decision is pending.
In addition, Cinergy and CG&E have been informed by DP&L that in June 2000, the EPA issued a Notice of Violation (NOV) to DP&L for alleged violations of PSD, NSR, and Ohio SIP requirements at a station operated by DP&L and jointly-owned by DP&L, CSP, and CG&E. The NOV indicated the EPA may (1) issue an order requiring compliance with the requirements of the Ohio SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. In September 2004, Marilyn Wall and the Sierra Club brought a lawsuit against CG&E, DP&L and CSP for alleged violations of the CAA at this same generating station. This case is currently in discovery in front of the same judge who has the CSP case.
We are unable to predict whether resolution of these matters would have a material effect on our financial position or results of operations. We intend to vigorously defend against these allegations.
(iv) Carbon Dioxide (CO2) Lawsuit
In July 2004, the states of Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin, and the City of New York brought a lawsuit in the United States District Court for the Southern District of New York against Cinergy, American Electric Power Company, Inc., American Electric Power Service Corporation, The Southern Company, Tennessee Valley Authority, and Xcel Energy Inc. That same day, a similar lawsuit was filed in the United States District Court for the Southern District of New York against the same companies by Open Space Institute, Inc., Open Space Conservancy, Inc., and The Audubon Society of New Hampshire. These lawsuits allege that the defendants’ emissions of CO2 from the combustion of fossil fuels at electric generating facilities contribute to global warming and amount to a public nuisance. The complaints also allege that the defendants could generate the same amount of electricity while emitting significantly less CO2. The plaintiffs are seeking an injunction requiring each defendant to cap its CO2 emissions and then reduce them by a specified percentage each year for at least a decade. In September 2005, the district court granted the defendants’ motion to dismiss the lawsuit. The plaintiffs have appealed this ruling to the Second Circuit Court of Appeals. We are not able to predict whether resolution of these matters would have a material effect on our financial position or results of operations.
(v) Selective Catalytic Reduction Units at Gibson Generating Station (Gibson Station)
In May 2004, SCRs and other pollution control equipment became operational at Units 4 and 5 of PSI’s Gibson Station in accordance with compliance deadlines under the NOX SIP Call. In June and July 2004, Gibson Station temporarily shut down the equipment on these units due to a concern that portions of the plume from those units’ stacks appeared to break apart and descend to ground level, at certain times, under certain weather conditions. After we developed a protocol with several other parties regarding the use of control equipment, one of the parties sought a court preliminary injunction to enforce the protocol. The court initially granted the preliminary injunction, but on appeal the preliminary injunction was dissolved and the case was dismissed.
In April 2005, we completed the installation of a permanent control system to address this issue. The new control system will support all five Gibson Station generating units. We will seek recovery of any related capital as well as increased emission allowance expenditures through the regulatory process. We do not believe costs related to resolving this matter will have a material impact on our financial position or results of operations.
(vi) Zimmer Generating Station (Zimmer Station) Lawsuit
In November 2004, a citizen of the Village of Moscow, Ohio, the town adjacent to CG&E’s Zimmer Station, brought a purported class action in the United States District Court for the Southern District of Ohio seeking monetary damages and injunctive relief against CG&E for alleged violations of the CAA, the Ohio SIP, and Ohio laws against nuisance and common law nuisance. The plaintiffs have filed a number of additional notices of intent to sue and two lawsuits raising claims similar to those in the original claim. One lawsuit was dismissed on procedural grounds and the remaining two have been consolidated. The plaintiff filed a motion for class certification, which is fully briefed and pending decision. At this time, we cannot predict whether the outcome of this matter will have a material impact on our financial position or results of operations. We intend to defend this lawsuit vigorously in court.
(vii) Manufactured Gas Plant (MGP) Sites
Coal tar residues, related hydrocarbons, and various metals have been found in at least 22 sites that PSI or its predecessors previously owned and sold in a series of transactions with Northern Indiana Public Service Company (NIPSCO) and Indiana Gas Company, Inc. (IGC). The 22 sites are in the process of being studied and will be remediated, if necessary. In 1998 NIPSCO, IGC, and PSI entered into Site Participation and Cost Sharing Agreements to allocate liability and responsibilities between them. Thus far, PSI has primary responsibility for investigating, monitoring and, if necessary, remediating nine of these sites. In December 2003, PSI entered into a voluntary remediation plan with the state of Indiana, providing a formal framework for the investigation and cleanup of the nine sites. The Indiana Department of Environmental Management oversees investigation and cleanup of all of these sites.
In April 1998, PSI filed suit in Hendricks County in the state of Indiana against its general liability insurance carriers. PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims against PSI and compensate PSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites; or (2) pay PSI’s cost of defense. PSI settled, in principle, its claims with all but one of the insurance carriers in January 2005 prior to commencement of the trial. With respect to the lone insurance carrier, a jury returned a verdict against PSI in February 2005. PSI has appealed this decision. At the present time, PSI cannot predict the outcome of this litigation, including the outcome of the appeal.
PSI has accrued costs related to investigation, remediation, and groundwater monitoring for those sites where such costs are probable and can be reasonably estimated. We will continue to investigate and remediate the sites as outlined in the voluntary remediation plan. As additional facts become known and investigation is completed, we will assess whether the likelihood of incurring additional costs becomes probable. Until all investigation and remediation is complete, we are unable to determine the overall impact on our financial position or results of operations.
CG&E and ULH&P have performed site assessments on certain of their sites where we believe MGP activities have occurred at some point in the past and have found no imminent risk to the environment. At the present time, CG&E and ULH&P cannot predict whether investigation and/or remediation will be required in the future at any of these sites.
(viii) Asbestos Claims Litigation
PSI and CG&E have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 130 pending lawsuits (the majority of which are PSI cases). In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work as outside contractors in the construction and maintenance of CG&E and PSI generating stations. The plaintiffs further claim that as the property owner of the generating stations, CG&E and PSI should be held liable for their injuries and illnesses based on an alleged duty to warn and protect them from any asbestos exposure. The impact on CG&E’s and PSI’s financial position or results of operations of these cases to date has not been material.
Of these lawsuits, one case filed against PSI has been tried to verdict. The jury returned a verdict against PSI on a negligence claim and a verdict for PSI on punitive damages. PSI appealed
this decision up to the Indiana Supreme Court. In October 2005, the Indiana Supreme Court upheld the jury’s verdict. PSI paid the judgment of approximately $630,000 in the fourth quarter. In addition, PSI has settled over 150 other claims for amounts, which neither individually nor in the aggregate, are material to PSI’s financial position or results of operations. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of contractors potentially exposed to asbestos during construction or maintenance of PSI generating plants; (ii) the possible incidence of various illnesses among exposed workers, and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, PSI estimates that the range of reasonably possible exposure in existing and future suits over the next 50 years could range from an immaterial amount to approximately $60 million, exclusive of costs to defend these cases. This estimated range of exposure may change as additional settlements occur and claims are made in Indiana and more case law is established.
CG&E has been named in fewer than 10 cases and as a result has virtually no settlement history for asbestos cases. Thus, CG&E is not able to reasonably estimate the range of potential loss from current or future lawsuits. However, potential judgments or settlements of existing or future claims could be material to CG&E.
(ix) Dunavan Waste Superfund Site
In July and October 2005, PSI received notices from the EPA that it has been identified as a de minimus potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act at the Dunavan Waste Oil Site in Oakwood, Vermilion County, Illinois. At this time, PSI does not have any further information regarding the scope of potential liability associated with this matter.
(x) Ontario, Canada Lawsuit
We understand through newspaper reports that a class action lawsuit was filed in Superior Court in Ontario, Canada against us and approximately 20 other utility and power generation companies alleging various claims relating to environmental emissions from coal-fired power generation facilities in the United States and Canada and damages of approximately $50 billion, with continuing damages in the amount of approximately $4 billion annually. We understand that the lawsuit also claims entitlement to punitive and exemplary damages in the amount of $1 billion. We have not yet been served in this lawsuit, however, if served, we intend to defend this lawsuit vigorously in court. We are not able to predict whether resolution of this matter would have a material effect on our financial position or results of operations.
(b) Regulatory
(i) PSI Retail Electric Rate Case
In May 2004, the IURC issued an order approving PSI’s base retail electric rate case, and PSI implemented base retail electric rate changes to its tariffs. When combined with revenue increases attributable to PSI’s environmental construction-work-in-progress tracking mechanism, the order resulted in an approximate $140 million increase in annual revenues, and an overall 7.3 percent return, including a 10.5 percent return on equity. In addition, the IURC’s order provided PSI the continuation of a purchased power tracker and the establishment of new trackers for future NOX emission allowance costs and certain costs related to the Midwest ISO.
(ii) PSI Environmental Compliance Case
In November 2004, PSI filed a compliance plan case with the IURC seeking approval of PSI’s plan for complying with SO2, NOX, and mercury emission reduction requirements discussed previously in (a)(i), including approval of cost recovery and an overall rate of return of eight percent related to certain projects. PSI requested approval to recover the financing, depreciation, and operation and maintenance costs, among others, related to $1.08 billion in capital projects designed to reduce emissions of SO2, NOX, and mercury at PSI’s coal-burning generating stations. An evidentiary hearing was held in May 2005. In December 2005, PSI, the Indiana Office of the Utility Consumer Counselor, and the PSI Industrial Group filed a settlement agreement providing for approval of PSI’s compliance plan, and approval of financing, depreciation, and operation and maintenance cost recovery. The settlement agreement provides for 20-year depreciation in lieu of PSI’s originally requested 18-year depreciation, the use of PSI’s then weighted cost of capital to determine the overall rate of return rather than eight percent as originally requested, caps the amount of cost recovery for the Gallagher Generating Station baghouse projects, and removes the Activated Carbon Injection component of those projects. A final IURC Order is expected in the first half of 2006.
(iii) CG&E Electric Rate Filings
CG&E operates under an RSP which was approved by the PUCO in November 2004, and which expires December 31, 2008.
One of the components of CG&E’s RSP is a fuel clause recovery mechanism, which was recently audited by the PUCO’s auditor. The auditor recommended alternate methodologies for administration of the fuel clause recovery mechanism that varies from CG&E’s current practice. A hearing before PUCO examiners was held in early November at which the PUCO staff took positions contrary to CG&E’s current practice. CG&E officials also testified at the hearing concerning our current practices. In January 2006, CG&E signed a settlement on the RSP with the PUCO staff. The two intervening parties have agreed not to oppose the settlement.
In February 2006, the PUCO issued an order approving the settlement agreement. We do not expect the agreement to have a material impact on CG&E’s or Cinergy’s results of operations.
In March 2005, the Ohio Consumers’ Counsel appealed the Commission’s approval of the RSP to the Supreme Court of Ohio. We expect the court to decide the case in 2006. CG&E cannot predict the outcome of this matter.
CG&E has also filed a distribution rate case to recover certain distribution costs with rates becoming effective on January 1, 2006 and CG&E has deferred certain costs in 2004 and 2005 pursuant to its RSP. The parties to the proceeding agreed upon and filed a settlement setting the recommended annual revenue increase at approximately $51 million. In December 2005, the PUCO issued an order approving the settlement agreement.
(iv) ULH&P Gas Rate Case
In 2002, the KPSC approved ULH&P’s gas base rate case requesting, among other things, recovery of costs associated with an accelerated gas main replacement program of up to $112 million over ten years. The approval allowed the costs to be recovered through a tracking mechanism for an initial three-year period expiring on September 30, 2005, with the possibility of renewal for up to ten years. The tracking mechanism allows ULH&P to recover depreciation costs and rate of return annually over the life of the assets. As of December 31, 2005, we have capitalized $61 million in costs associated with the accelerated gas main replacement program through this tracking mechanism, of which ULH&P has recovered $8.9 million. The Kentucky Attorney General has appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism and the tracking mechanism rates. In October 2005, both the Company and the KPSC filed with the Franklin Circuit Court, requesting dismissal of the case for failure to prosecute by the Kentucky Attorney General. At the present time, ULH&P cannot predict the timing or outcome of this litigation.
In February 2005, ULH&P filed a gas base rate case with the KPSC requesting approval to continue the tracking mechanism in addition to its request for a $14 million annual increase in base rates. A portion of the increase is attributable to including recovery of the current cost of the accelerated main replacement program in base rates. The KPSC did not rule on the base rate case request or the request to continue the tracking mechanism by October 1, 2005; consequently the initial tracking mechanism expired on September 30, 2005. In accordance with Kentucky law, ULH&P implemented the full amount of the requested rate increase on October 1, 2005. In December 2005, the KPSC approved an annual rate increase of $8.1 million and reapproved the tracking mechanism through 2011. Pursuant to the KPSC’s order, ULH&P filed a refund plan in January 2006 for the excess revenues collected since October 1, 2005. In February 2006, the KPSC issued an additional order responding to a rehearing request made by the Attorney General. Its rehearing order approved the Company’s refund plan which will result in refunds being provided to customers beginning in March 2006. In February 2006, the Attorney General appealed the KPSC’s order to the Franklin Circuit Court, claiming that the order improperly allows ULH&P to increase its rates for gas main replacement costs in between general rate cases, and also claiming that the order improperly allows ULH&P to earn a return on investment for costs recovered under the tracking mechanism which permits ULH&P to recover its gas main replacement costs. At this time, ULH&P cannot predict the outcome of this litigation.
(v) Gas Distribution Plant
In June 2003, the PUCO approved an amended settlement agreement between CG&E and the PUCO staff in a gas distribution safety case arising out of a gas leak at a service head-adapter (SHA) style riser on CG&E’s distribution system. The amended settlement agreement required CG&E to expend a minimum of $700,000 to replace SHA risers by December 31, 2003, and to file a comprehensive plan addressing all SHA risers on its distribution system. CG&E filed a comprehensive plan with the PUCO in December 2004 providing for replacement of approximately
5,000 risers in 2005 with continued monitoring thereafter. CG&E estimates the replacement cost of these risers will not be material. In April 2005, the PUCO issued an order closing this case. The PUCO issued a separate order opening a statewide investigation into riser leaks in gas pipeline systems throughout Ohio. At this time, Cinergy and CG&E cannot predict the outcome or the impact of the statewide investigation.
(c) Other
(i) Energy Market Investigations
In August 2003, Cinergy, along with Marketing & Trading and 37 other companies, were named as defendants in civil litigation filed as a purported class action on behalf of all persons who purchased and/or sold New York Mercantile Exchange natural gas futures and options contracts between January 1, 2000 and December 31, 2002. The complaint alleges that improper price reporting caused damages to the class. Two similar lawsuits have subsequently been filed, and these three lawsuits have been consolidated for pretrial purposes. The plaintiffs filed a consolidated class action complaint in January 2004. Cinergy’s motion to dismiss was granted in September 2004 leaving only Marketing & Trading in the lawsuit. Marketing & Trading has reached an agreement in principle to settle this suit for an immaterial amount.
At this time, we do not believe the outcome of these investigations and litigation will have a material impact on Cinergy’s financial position or results of operations.
(ii) Synthetic Fuel Production
Cinergy produces synthetic fuel from two facilities that qualify for tax credits (through 2007) in accordance with Section 29/45K of the IRC if certain requirements are satisfied. Cinergy’s sale of synthetic fuel has generated $339 million in tax credits through December 31, 2005. The IRS is currently auditing Cinergy for the 2002, 2003 and 2004 tax years. We expect the IRS will evaluate the various key requirements for claiming our Section 29/45K credits related to synthetic fuel. If the IRS challenges our Section 29/45K tax credits related to synthetic fuel, and such challenges are successful, this could result in the disallowance of up to all $339 million in previously claimed Section 29/45K tax credits for synthetic fuel produced by the applicable Cinergy facilities and a loss of our ability to claim future Section 29/45K tax credits for synthetic fuel produced by such facilities. We believe that we operate in conformity with all the necessary requirements to be allowed such tax credits under Section 29/45K.
Section 29/45K also provides for a phase-out of the credit based on the average price of crude oil during a calendar year. The phase-out is based on a prescribed calculation and definition of crude oil prices. Based on current crude oil prices and the recent volatility of such prices, we believe that for 2006 and 2007, the amount of the tax credits could be reduced. If oil prices are high enough, we will idle the plants, as the value of the credits would not exceed the net costs to produce the synthetic fuel. Net income related to these facilities for the twelve months ended December 31, 2005 was approximately $58 million. The net book value of our plants at December 31, 2005 was approximately $47 million.
(iii) FirstEnergy Lawsuit
FirstEnergy has filed a lawsuit in the Court of Common Pleas in Summit County, Ohio against Cinergy with respect to a transaction between Cinergy and a subsidiary of FirstEnergy, relating to a joint venture company, Avon Energy Partners Holdings (Avon). In 1999, the FirstEnergy subsidiary acquired Cinergy’s share of Avon which it subsequently sold to a third party. The original transaction documents included an indemnity by Cinergy with respect to a certain investment owned by Avon. FirstEnergy claims that this indemnity was triggered by its sale of Avon to a third party, and is seeking to recover $15 million from Cinergy. Both parties have filed motions for summary judgment, for which hearings began in February 2006. Cinergy intends to defend this lawsuit vigorously in court. At this time, we cannot predict the outcome of this matter.
(iv) Guarantees
In the ordinary course of business, Cinergy enters into various agreements providing financial or performance assurances to third parties on behalf of certain unconsolidated subsidiaries and joint ventures. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to these entities on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish their intended commercial purposes. The guarantees have various termination dates, from short-term (less than one year) to open-ended.
In many cases, the maximum potential amount of an outstanding guarantee is an express term, set forth in the guarantee agreement, representing the maximum potential obligation of Cinergy under that guarantee (excluding, at times, certain legal fees to which a guaranty beneficiary may be entitled). In those cases where there is no maximum potential amount expressly set forth in the guarantee agreement, we calculate the maximum potential amount by considering the terms of the guaranteed transactions, to the extent such amount is estimable.
Cinergy had guaranteed borrowings by individuals under the Director, Officer, and Key Employee Stock Purchase Program. Under these guarantees, Cinergy would have been obligated to pay the debt’s principal and any related interest in the event of an unexcused breach of a guaranteed payment obligation by certain directors, officers, and key employees. This program terminated pursuant to its terms during the first quarter of 2005 and as of March 31, 2005, all borrowings had been repaid by the participants.
Cinergy Corp. has also provided performance guarantees on behalf of certain unconsolidated subsidiaries and joint ventures. These guarantees support performance under various agreements and instruments (such as construction contracts, operation and maintenance agreements, and energy service agreements). Cinergy Corp. may be liable in the event of an unexcused breach of a guaranteed performance obligation by an unconsolidated subsidiary. Cinergy Corp. has estimated its maximum potential liability to be $52 million under these guarantees as of December 31, 2005. Cinergy Corp. may also have recourse to third parties for claims required to be paid under certain of these guarantees. The majority of these guarantees expire at the completion of the underlying performance agreement, the majority of which expire from 2016 to 2019.
Cinergy has entered into contracts that include indemnification provisions as a routine part of its business activities. Examples of these contracts include purchase and sale agreements and operating agreements. In general, these provisions indemnify the counterparty for matters such as breaches of representations and warranties and covenants contained in the contract. In some cases, particularly with respect to purchase and sale agreements, the potential liability for certain indemnification obligations is capped, in whole or in part (generally at an aggregate amount not exceeding the sale price), and subject to a deductible amount before any payments would become due. In other cases (such as indemnifications for willful misconduct of employees in a joint venture), the maximum potential liability is not estimable given that the magnitude of any claims under those indemnifications would be a function of the extent of damages actually incurred. Cinergy has estimated the maximum potential liability, where estimable, to be $138 million under these indemnification provisions. The termination period for the majority of matters provided by indemnification provisions in these types of agreements generally ranges from 2006 to 2009.
We believe the likelihood that Cinergy would be required to perform or otherwise incur any significant losses associated with any or all of the guarantees described in the preceding paragraphs is remote.
(v) Construction and Other Commitments
Forecasted construction and other committed expenditures for the year 2006 and for the five-year period 2006-2010 (in nominal dollars) are presented in the table below:
(1) The results of Cinergy also include amounts related to non-registrants.
This forecast includes an estimate of expenditures in accordance with the companies’ plans regarding environmental compliance.
14. Jointly-Owned Plant
CG&E, CSP, and DP&L jointly own electric generating units and related transmission facilities. PSI is a joint-owner of Gibson Station Unit No. 5 with Wabash Valley Power Association, Inc. (WVPA), and Indiana Municipal Power Agency (IMPA). Additionally, PSI is a joint-owner with WVPA and IMPA of certain transmission property and local facilities. These facilities constitute part of the integrated transmission and distribution systems, which are operated and maintained by PSI. The Statements of Income reflect CG&E’s and PSI’s portions of all operating costs associated with the jointly-owned facilities.
As of December 31, 2005, CG&E’s and PSI’s investments in jointly-owned plant or facilities were as follows:
(1) Station is not operated by CG&E.
(2) See Note 22 for further discussion of the transfer of generation assets in January 2006.
15. Quarterly Financial Data (unaudited)
(1) The results of Cinergy also include amounts related to non-registrants.
16. Discontinued Operations
During 2003, Cinergy completed the disposal of its gas distribution operation in South Africa, sold its remaining wind assets in the United States, and substantially sold or liquidated the assets of its energy marketing business in the Czech Republic.
As a result of the 2003 transactions, assets of approximately $140 million were sold or converted into cash and liabilities of approximately $100 million were assumed by buyers or liquidated. The net, after-tax, gain from these disposal and liquidation transactions was approximately $9 million (including a net, after-tax, cumulative currency translation gain of approximately $6 million).
In December 2005, Cinergy completed the sale of a wholly-owned subsidiary in the Czech Republic that was engaged in the generation and sale of heat and electricity. At the time of the sale, the subsidiary had assets of approximately $113 million and liabilities of approximately $12 million. The net, after-tax, gain from the sale was approximately $18 million (including a net, after-tax, cumulative currency translation gain of approximately $24 million).
In December 2005, Cinergy began taking steps to sell its wholly owned North American energy management and energy performance contracting business. As of December 31, 2005, this subsidiary had assets of approximately $34 million and liabilities of approximately $29 million. In 2005, Cinergy recognized a $17 million impairment charge to value this business to its estimated fair value less cost to sell in accordance with being deemed held for sale.
The three consolidated entities above have been presented as Discontinued operations, net of tax in Cinergy’s Consolidated Statements of Income and as Assets/Liabilities of Discontinued Operations in Cinergy’s Consolidated
Balance Sheets. The accompanying financial statements and prior year financial statements have been reclassified to account for these entities as such.
The following table reflects the assets and liabilities, the results of operations, and the income (loss) on disposal related to investments accounted for as discontinued operations for the years ended December 31, 2005, 2004, and 2003.
(1) Presented for informational purposes only. All results of operations are reported net in our Statements of Income.
17. Investment Activity
(a) Investment Impairment
Cinergy holds a portfolio of direct and indirect investments in Power Technology and Infrastructure (discussed further in Note 18). During 2004, Cinergy recognized approximately $56 million in impairment and disposal charges primarily associated with this portfolio. A substantial portion of these charges relate to a company in which Cinergy holds a non-controlling interest, that sold its major assets. This company is involved in the development and sale of outage management software. Based on the terms of the transaction, Cinergy concluded that this cost method investment was other-than-temporarily impaired. These impairment charges are included in Miscellaneous Income (Expense) - Net in Cinergy’s Statements of Income.
(b) Sale of Investment
Power Technology and Infrastructure holds an investment in a company that develops, owns and operates wireless communication towers. In July 2004, this company agreed to sell the majority of its assets. Most of the assets contemplated in the purchase/sale agreement were sold in the fourth quarter of 2004 and we recorded a gain of $21 million in 2004 relating to this sale. These earnings are reflected in Equity in Earnings of Unconsolidated Subsidiaries in Cinergy’s Statements of Income.
18. Financial Information by Business Segment
We conduct operations through our subsidiaries and manage our businesses through the following three reportable segments:
• Regulated;
• Commercial; and
• Power Technology and Infrastructure.
Regulated consists of PSI’s regulated generation and transmission and distribution operations, and CG&E and its subsidiaries’ regulated electric and gas transmission and distribution systems. Regulated plans, constructs, operates, and maintains Cinergy’s transmission and distribution systems and delivers gas and electric energy to consumers. Regulated also earns revenues from wholesale customers primarily by these customers transmitting electric power through Cinergy’s transmission system. These businesses are subject to cost of service rate making where rates to be charged to customers are based on prudently incurred costs over a test period plus a reasonable rate of return.
Commercial manages our wholesale generation and energy marketing and trading activities. Commercial also performs energy risk management activities, provides customized energy solutions and is responsible for all of our international operations.
Power Technology and Infrastructure primarily manages Cinergy Ventures, LLC (Ventures), Cinergy’s venture capital subsidiary. Ventures identifies, invests in, and integrates new energy technologies into Cinergy’s existing businesses, focused primarily on operational efficiencies and clean energy technologies. In addition, Power Technology and Infrastructure manages our investments in other energy infrastructure and telecommunication service providers.
Following are the financial results by business unit. Certain prior year amounts have been reclassified to conform to the current presentation.
Financial results by business unit for the years ended December 31, 2005, 2004, and 2003, are as indicated below:
Business Units
(1) The Reconciling Eliminations category eliminates the intersegment revenues of Commercial and Regulated.
(2) Electric gross margins are calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.
(3) Gas gross margins are calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
(4) Interest income is deemed immaterial.
(5) For further information, see Note 16.
(6) For further information, see Note 1(s)(iv).
(1) The Reconciling Eliminations category eliminates the intersegment revenues of Commercial and Regulated.
(2) Electric gross margins are calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.
(3) Gas gross margins are calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
(4) Interest income is deemed immaterial.
(5) The reduction in income taxes in 2004, as compared to 2003, primarily reflects lower business unit taxable income and also includes an increase in the annual tax credits associated with the production and sale of synthetic fuel. For further information, see Note 13(c)(ii).
(6) For further information, see Note 16.
(1) The Reconciling Eliminations column eliminates the intersegment revenues of Commercial and Regulated.
(2) Electric gross margins are calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.
(3) Gas gross margins are calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
(4) Interest income is deemed immaterial.
(5) For further information, see Note 16.
(6) For further information, see Note 1(s)(iv).
Products and Services
(in millions)
Geographic Areas and Long-Lived Assets
Revenues
(in millions)
19. Earnings Per Common Share
A reconciliation of EPS - basic to EPS - diluted is presented below for the years ended December 31, 2005, 2004, and 2003:
Options to purchase shares of common stock are excluded from the calculation of EPS - diluted, if they are considered to be anti-dilutive. For the years ended December 31, 2005, 2004, and 2003, approximately 0.8 million, 0.9 million, and 1.6 million shares, respectively, were excluded from the EPS - diluted calculation.
Also excluded from the EPS - diluted calculation for the years ended December 31, 2004 and 2003 are up to 9.7 million and 10.6 million shares, respectively, issuable pursuant to the stock purchase contracts issued by Cinergy Corp. in December 2001 associated with the preferred trust securities transaction. In January and February 2005, the stock purchase contracts were settled and holders purchased a total of 9.2 million shares of Cinergy Corp. common stock.
20. Comprehensive Income
Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. The major components include net income, foreign currency translation adjustments, minimum pension liability adjustments, unrealized gains and losses on investment trusts and the effects of certain hedging activities.
We translate the assets and liabilities of foreign subsidiaries, whose functional currency (generally, the local currency of the country in which the subsidiary is located) is not the United States dollar, using the appropriate exchange rate as of the end of the year. Foreign currency translation adjustments are unrealized gains and losses on the difference in foreign country currency compared to the value of the United States dollar. The gains and losses are accumulated in comprehensive income. When a foreign subsidiary is substantially liquidated, the cumulative translation gain or loss is removed from comprehensive income and is recognized as a component of the gain or loss on the sale of the subsidiary in our Statements of Income.
We record a minimum pension liability adjustment associated with our defined benefit pension plans when the unfunded accumulated benefit obligation is in excess of our accrued pension liabilities and the unrecognized prior service costs recorded as an intangible asset. The corresponding offset is recorded on the Balance Sheets in Accrued pension and other postretirement benefit costs. Details of the pension plans’ assets and obligations are explained further in Note 11.
We record unrealized gains and losses on equity investments in trusts we have established for our benefit plans, primarily by PSI. See Note 11 for further details.
The changes in fair value of derivatives that qualify as hedges, under Statement 133, are recorded in comprehensive income. The specific hedge accounting and the derivatives that qualify are explained in greater detail in Note 9(a).
The elements of Comprehensive income and their related tax effects for the years ended December 31, 2005, 2004, and 2003 are as follows:
(1) The results of Cinergy also include amounts related to non-registrants.
(2) Individual amounts for ULH&P are immaterial.
The after-tax components of Accumulated other comprehensive income (loss) as of December 31, 2005, 2004, and 2003 are as follows:
(1) The results of Cinergy also include amounts related to non-registrants.
(2) Individual amounts for ULH&P are immaterial.
21. Acquisition of Wheatland Generating Assets
In August 2005, PSI acquired 100 percent of the 488 MW Wheatland Generating Facility from Allegheny Energy, Inc. for approximately $100 million. The Wheatland facility, located in Knox County, Indiana, has four natural gas-fired simple cycle combustion turbines and is directly connected to the Cinergy transmission system. The facility’s output will be used to bolster the reserve margins on the PSI system.
22. Subsequent Event
In January 2006, ULH&P completed the transfer from CG&E of CG&E's approximately 69 percent ownership interest in the East Bend Station, located in Boone County, Kentucky, the Woodsdale Station, located in Butler County, Ohio, and one generating unit at the four-unit Miami Fort Station, located in Hamilton County, Ohio, and associated transactions. The transaction was effective as of January 1, 2006 at net book value. The final required regulatory approval was received in November 2005 from the SEC under the PUHCA of 1935. The KPSC and the FERC had earlier issued orders approving aspects of the transaction. The transaction will not affect current retail electric rates for ULH&P’s customers. Updated rates are expected to be implemented January 1, 2007 pursuant to a rate case to be filed in 2006 that incorporates the value of these assets into ULH&P’s rate base.
In connection with the transfer of these assets, ULH&P accepted a capital contribution from CG&E and assumed certain liabilities of CG&E. In particular, ULH&P agreed to assume from CG&E all payment, performance, and other obligations of CG&E, with respect to (i) certain tax-exempt pollution control debt currently shown on the balance sheet of CG&E, (ii) certain of CG&E’s outstanding Accounts payable to affiliated companies, and (iii) certain deferred tax liabilities related to the assets. ULH&P intends to repay the tax-exempt obligations with the proceeds from the issuance of tax-exempt debt at ULH&P. The accounts payable obligations will be repaid initially with the proceeds from short-term borrowings and eventually through the issuance of long-term senior unsecured debentures. The following table summarizes this transaction for ULH&P:
As part of this transaction, CG&E and ULH&P terminated the long-term wholesale power contract under which CG&E had previously supplied power to ULH&P. Further, CG&E also proposed to supply and ULH&P agreed to purchase back-up power from CG&E for planned and unplanned outages of the three generating plants through December 31, 2009 pursuant to a draft contract. The parties never executed this draft contract and ULH&P currently purchases backup power, when needed, through the Midwest ISO energy markets. Given changes in circumstances, including the implementation of the Midwest ISO Energy Markets Tariff, CG&E and ULH&P are planning to propose an alternative arrangement for supplying back-up power to ULH&P. At this time, whether and the conditions under which the KPSC may allow ULH&P to recover any increased costs for an alternative arrangement for the supply of back-up power are unknown and CG&E and ULH&P cannot determine the magnitude of any potential increased costs for back-up power.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure controls and procedures are our controls and other procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported, within the time periods specified in the Securities and Exchange Commission’s (SEC) rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we have evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2005, and, based upon this evaluation, our chief executive officer and chief financial officer have concluded that these controls and procedures are effective in providing reasonable assurance that information requiring disclosure is recorded, processed, summarized, and reported within the timeframe specified by the SEC’s rules and forms.
Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we have evaluated any change in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter ended December 31, 2005 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management Report on Internal Control over Financial Reporting
Management of Cinergy Corp. (the Company) is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is 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.
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 Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Based on our assessment and those criteria, management believes that the internal control over financial reporting maintained by the Company, as of December 31, 2005, was effective.
The Company’s independent registered public accounting firm has issued an attestation report on management’s assessment of the Company’s internal control over financial reporting. That report follows.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Cinergy Corp.
Cincinnati, Ohio
We have audited management’s assessment, included in the accompanying Management Report on Internal Control over Financial Reporting, that Cinergy Corp. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, 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 generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2005 of the Company and our report dated February 17, 2006 expressed an unqualified opinion on those financial statements and financial statement schedule and contained an explanatory paragraph regarding the Company’s adoption of a new accounting standard in 2005 for conditional asset retirement obligations.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Cincinnati, Ohio
February 17, 2006
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
BOARD OF DIRECTORS
Cinergy
The names and ages of the directors of Cinergy, and all persons nominated or chosen to become directors of Cinergy; the positions and offices of Cinergy they hold; their term of office and period during which they have served; their principal occupation and business experience for at least the past five years is included in the chart below. Mr. Rogers is the only director who is an employee of Cinergy Services, Inc. (Services), an affiliate of Cinergy.
Cinergy Corp. has a separately-designated standing audit committee established in accordance with section 3(a)(58)(A) of the Exchange Act. During 2005, the Audit Committee members were Ms. Mary L. Schapiro (Chair), and Messrs. Thomas E. Petry, John J. Schiff, Jr. and Philip R. Sharp. Each of its members is an “independent” director within the meaning of Sections 303.01(B)(2)(a), 303.01(B)(3) and 303A.02 of the New York Stock Exchange’s (NYSE) listing standards and Rule 10A-3 of the Exchange Act. This Audit Committee selects and retains a firm of independent public accountants to conduct audits of the accounts of Cinergy and its subsidiaries. It also reviews with the independent public accountants the scope and results of their audits, as well as the accounting procedures, internal controls, and accounting and financial reporting policies and practices of Cinergy and its subsidiaries, and makes reports and recommendations to the Board as it deems appropriate. The Audit Committee is responsible for approving all audit and permissible non-audit services provided to Cinergy by its independent auditors.
Cinergy’s Board has determined that Ms. Mary L. Schapiro is an “audit committee financial expert” as such term is defined in Item 401(h) of Regulation S-K. See above for a description of Ms. Schapiro’s business experience.
Shareholders can communicate with our Chairman, Mr. Rogers, and Co-Lead Directors, Messrs. Browning and Taft, by email at lead.directors@cinergy.com. Messrs. Browning and Taft also preside over non-management executive sessions of our directors. You may also write to any of the committee Chairs or to the outside directors as a group c/o Julia S. Janson, Corporate Secretary and Chief Compliance Officer at Cinergy Corp., 139 East Fourth Street, Cincinnati, Ohio 45202.
Communications are distributed to the Board, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication. In that regard, the Cinergy Board has requested that certain items that are unrelated to the duties and responsibilities of the Board be excluded, such as: spam; junk mail and mass mailings; service complaints; resumes and other forms of job inquiries; surveys; and business solicitations or advertisements. In addition, material that is unduly hostile, threatening, obscene or similarly unsuitable will be excluded, with the provision that any communication that is filtered out is made available to any director upon request.
The Cincinnati Gas & Electric Company (CG&E)
The directors of CG&E at January 31, 2006, are as follows:
Gregory C. Ficke - Mr. Ficke, age 53, is President of CG&E, a position he has held since October 1, 2001. He has served as a director of CG&E since June 2005. His current term as director expires May 31, 2006.
James E. Rogers - Mr. Rogers, age 58, is Chairman of the Board and Chief Executive Officer of Cinergy Corp. and CG&E. He has served as a director of CG&E since 1994. His current term as director expires May 2, 2006.
James L. Turner - Mr. Turner, age 46, is Executive Vice President of CG&E, a position he has held since July 2000. He served as a director of CG&E from February 15, 1999 to April 30, 2001 and was re-elected, effective October 1, 2001. Mr. Turner’s current term as director expires May 2, 2006.
Additional information on each of the directors of CG&E is presented in the following “Executive Officers” section.
PSI
The directors of PSI at January 31, 2006, are as follows:
Michael G. Browning - Mr. Browning, age 59, is Chairman and President of Browning Investments, Inc., which is engaged in real estate development. He is a director of Cinergy Corp. and Standard Management Corporation. He also serves as owner, general partner or managing member of various real estate entities. He has served on the Board of PSI since 1990.
James E. Rogers - Mr. Rogers, age 58, is Chairman of the Board and Chief Executive Officer of Cinergy Corp. and PSI. Previously, he served as Vice Chairman, President and Chief Executive Officer of Cinergy Corp., and as Vice Chairman and Chief Executive Officer of PSI. Mr. Rogers also holds, or has held, similar executive officer positions with Cinergy’s principal subsidiaries. He is a director of Cinergy Corp. and Fifth Third Bancorp. He has served on the Board of PSI since 1988.
Kay E. Pashos - Ms. Pashos, age 46, has served as President of PSI since December 2004. Prior to that, since 1995, Ms. Pashos served in various legal capacities for Cinergy’s Regulated Business Unit including as its General Counsel from 2003 to 2004. She has served on the Board of PSI since 2004.
Mr. Rogers and Ms. Pashos are employees of Cinergy Services, Inc., an affiliate of PSI. Additional information on each of Mr. Rogers and Ms. Pashos is presented in the following “Executive Officers” section.
EXECUTIVE OFFICERS
The names and ages of the executive officers of Cinergy, CG&E, and PSI and the positions they hold, held, or have been elected to (as of January 31, 2006), and their business experience during the past five years is included in the chart below.
None of the officers are related in any manner. Our executive officers hold the offices set opposite their names until the next annual meeting of the Board of Directors and until their successors have been elected and qualified.
(1) On December 30, 2005, Mr. Cyrus informed the Company that he does not expect to continue his employment with the Company following completion of the merger.
(2) Prior to joining Cinergy, Ms. Good was a partner with the international accounting firm Deloitte & Touche LLP in Cincinnati, Ohio since May 2002. Prior to that, she was a partner with the international accounting firm Arthur Andersen LLP from 1992 to May 2002. While at Arthur Andersen LLP, she had regional energy responsibilities for risk consulting and internal audit practices.
(3) Prior to joining Cinergy, Mr. Manly was Managing Director, Law and Governmental Affairs, General Counsel and Corporate Secretary of NewPower Holdings, Inc. (a non-affiliate of Cinergy) from April 2000 to August 2002. On June 11, 2002, NewPower Holdings, Inc. and its affiliates, TNPC Holdings, Inc. and the NewPower Company, filed a petition for relief under Chapter 11 of The United States Bankruptcy Code.
(4) Prior to joining Cinergy, Mr. Murphy was Vice President and Chief Risk Officer of Enron Europe, Ltd. (a non-affiliate of Cinergy) from January 2001 to July 2002. Prior to that, he was Vice President of Market Risk of Enron Corp. (a non-affiliate of Cinergy) from March 1997 to December 2000.
(5) Prior to joining Cinergy, Mr. Newton was Senior Vice President, Chief Administrative Officer of LG&E (a non-affiliate of Cinergy) from January 1999 to May 2002.
(6) Mr. Turner served as Vice President of Customer Services from January 2000 until July 2000.
Cinergy Corp. has adopted both a code of business conduct and ethics applicable to all of its directors, officers, and employees as well as corporate governance guidelines. Both of these documents are available on Cinergy’s website
at www.cinergy.com. In addition, any amendments to or waivers from the code of business conduct and ethics will be posted on the website. Any such amendment or waiver would require the prior consent of the Board of Directors or an applicable committee thereof.
NYSE CEO Certification
Cinergy Corp. has filed the certification of its chief executive officer and chief financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 as exhibits to this Annual Report on Form 10-K for the year ended December 31, 2005. In May 2005, Cinergy Corp.’s chief executive officer, as required by Section 303A.12(a) of the NYSE Listed Company Manual, certified to the NYSE that he was not aware of any violation by Cinergy Corp. of the NYSE’s corporate governance listing standards.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires Cinergy’s directors and executive officers, and any persons owning more than ten percent of Cinergy’s common stock, to file with the SEC initial reports of beneficial ownership and certain changes in that beneficial ownership, with respect to the equity securities of Cinergy. We prepare and file these reports on behalf of our directors and executive officers. During 2005 one Form 4 for each of Messrs. Browning and Cox was filed after its due date. To our knowledge, all other Section 16(a) reporting requirements applicable to our directors and executive officers were complied with during 2005.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Compensation Committee Report on Executive Compensation
The executive compensation-related responsibilities of the Compensation Committee include:
• reviewing, approving and overseeing the process and substance of Cinergy’s executive compensation policy;
• reviewing and approving compensation for Cinergy’s Chief Executive Officer and other executive officers; and
• reviewing and approving the executive compensation plans and the administration thereof.
Compensation Policy
Our executive compensation program is designed to promote the delivery of sustained superior performance for all of Cinergy’s stakeholders by attracting, retaining and motivating high quality executives. From a financial perspective, superior performance is defined as ranking in the top quartile for total shareholder return (TSR), calculated based on stock price appreciation and dividends, compared to those companies that comprise the S&P Electric Supercomposite Index. Furthermore, in an effort to strengthen the alignment of executive and shareholder interests, our strategy is to compensate executives using, whenever possible, stock-based compensation. The Committee has engaged an independent compensation consultant, reporting directly to the Committee, in order to ensure that our executive compensation program and the individual components thereof are consistent with these policies and competitive with the market.
The Committee, with the assistance of its independent compensation consultant, establishes different components of compensation using information relating to several peer groups in addition to the S&P Electric Supercomposite Index. Compensation for Cinergy’s executive officers primarily consists of the following components, as well as benefits under the other programs described herein:
• Base salary;
• Annual incentives; and
• Long-Term incentives.
The Committee believes that applying benchmarks relating to different peer groups is the most appropriate method of analyzing these different components of compensation, as below described:
The significant components of our compensation program are below discussed.
Base Salaries. Base salaries for the executive officers are reviewed annually and are targeted at the 50th - 75th percentile of the applicable peer group, as above described.
Annual and Long-Term Incentives. As discussed below, our annual and long-term incentive plans are intended to complement base salary and provide executive officers with total compensation targeted at the 50th percentile of the applicable peer group. The Committee believes that annual and long-term incentive opportunities assist in motivating the behavior necessary to manage short- and long-term corporate goals successfully. This pay for performance emphasis results in a compensation mix in which targeted annual and long-term incentives, in the aggregate, make up, on average, at least 50 percent of the total annual compensation opportunity of the Chief Executive Officer and other executive officers. See “Annual Incentive Compensation” and “Long-Term Incentive Compensation” for a description of the annual and long-term incentive plans in which the named executive officers participate.
Total Compensation. We provide executive officers a combination of fixed and variable pay, using base salary, short-term incentives and long-term incentives. These components, in the aggregate, are targeted to deliver total compensation at the 50th percentile of the applicable peer group. However, if Cinergy delivers superior performance, our compensation program is designed to provide total compensation at the 75th percentile of the applicable peer group, and, conversely, if Cinergy’s performance should decline, its executive officers’ total compensation is designed to decline to a level commensurate with such performance. The Committee monitors each component of executive compensation and regularly compares pay to the performance of Cinergy’s executive officers using the peer group data described above and the advice of its independent compensation consultant.
Stock Ownership and Retention Requirements. In a further effort to align the interests of the shareholders, the directors, the Chief Executive Officer and the other executive officers, Cinergy maintains a minimum stock ownership policy. Under this policy, the Chief Executive Officer and the other executive officers are required to maintain a minimum ownership interest in Cinergy equal to five times and three times their annual base salaries, respectively, and directors are required to maintain a minimum ownership interest in Cinergy equal to two times their annual retainer. The Chief Executive Officer and directors are in compliance with this requirement. The other executive officers have a transition period within which to comply, and Cinergy monitors their progress toward the requirement. Cinergy also has a policy under which the directors, the Chief Executive Officer and the other executive officers are prohibited from disposing of any shares of Cinergy common stock acquired by virtue of the exercise of stock options (except to the extent necessary to pay the exercise price and/or any accompanying tax obligations) until 90 days after their termination from employment or other service with Cinergy.
Annual Incentive Compensation
Approximately 350 employees, including all executive officers, participated in Cinergy’s Annual Incentive Plan (“AIP”) in 2005. To advance our pay for performance emphasis, participants are eligible to receive annual incentives (i.e., bonuses) under the AIP only to the extent that certain pre-determined corporate, business unit and individual goals are achieved.
Achievement levels for goals under the AIP are based on a scale from 0.0 to 3.0, with target being 2.0. In 2005, the corporate goal was based on the attainment of certain levels of net income. For corporate center and shared services employees, which includes all of the executive officers, the corporate net income goal and the aggregate individual goals were each weighted at 50 percent of the total possible award. For all other employees, the corporate net income goal was weighted at 50 percent of the total possible award, with business unit specific goals and individual goals weighted at 25 percent each. Thus, if, for example, Cinergy were to earn a 2.5 for the corporate net income goal and a corporate center employee earned a 1.5 for her aggregate individual goals, the employee’s overall score would be a 2.0 and the award would pay out at target. Pursuant to the terms of the AIP as approved by shareholders, in the event of a change in control (as defined in the AIP), all relevant performance criteria would be deemed satisfied at the maximum.
For 2005, target awards ranged from 10 percent to 75 percent of an employee’s annual base salary, depending upon the employee’s position within Cinergy. The target and maximum annual incentive opportunity was 75 percent and 130 percent, respectively, for the Chief Executive Officer and 60 percent and 105 percent, respectively, for each of the other named executive officers. For purposes of this calculation, $1,850,004 was used as the Chief Executive Officer’s annual base salary because his employment agreement requires that $600,000 of his performance- based phantom stock award be included in his 2005 AIP award calculation. See “Employment Agreements” for a description of this performance-based phantom stock award.
Cinergy earned an achievement level of 2.1 for the 2005 corporate goal. Payouts to the named executive officers for the individual goal component of their 2005 AIP bonuses corresponded to an achievement level of 3.0. The individual goals included a supplier diversity goal, a workforce diversity goal and a corporate governance goal. In connection with Ms. Good’s promotion to Executive Vice President and Chief Financial Officer, her annual incentive opportunity was increased from 45 percent to 60 percent effective September 1, 2005, and she was awarded an additional $250,000 bonus.
For 2006, the AIP will be based on a corporate net income goal, business unit goals and individual goals. For the named executive officers, the corporate net income goal and aggregate individual goals are equally weighted. The 2006 annual incentive bonus for other participants in the AIP will be determined based on the corporate net income goal, business unit specific goals and individual goals as appropriate.
Long-Term Incentive Compensation
Cinergy has a long-term incentive compensation program under the terms of the Cinergy Corp. 1996 Long-Term Incentive Compensation Plan (“LTIP”). The LTIP is designed to align the long-term interests of our shareholders and management by providing incentives to increase TSR. The LTIP ties a large portion of the participants’ potential total compensation to long-term performance. This pay for performance approach provides an upside potential for outperforming peer companies, and downside risk for underperforming. The LTIP performance period is three years with a new LTIP cycle beginning each January 1st. Our most senior management, consisting of approximately 150 employees, including all executive officers, participated in the LTIP in 2005.
For the LTIP cycle that commenced on January 1, 2005, target awards ranged from 20 percent to 160 percent of the participant’s annual base salary, depending on his or her position within Cinergy. The target LTIP award opportunities were 160 percent for the Chief Executive Officer and 90 percent for each of the other named executive officers, except Ms. Good, whose target LTIP award opportunity was 75 percent in 2005 (Ms. Good’s target LTIP award opportunity increased to 90 percent for the cycle that commenced January 1, 2006). For purposes of this calculation, $1,850,004 was used as the Chief Executive Officer’s annual base salary because his employment agreement requires that $600,000 of his performance based phantom stock award be included in his 2005 LTIP annual calculation. See “Employment Agreements” for a description of this performance-based phantom stock award.
Of the target award, stock options comprise 25 percent of the total award value under the cycles that are currently outstanding and performance shares comprise the other 75 percent. A performance share represents the right to receive a share of common stock if certain performance criteria are met. It follows that the number of performance shares that are received depends on Cinergy’s performance. As discussed in more detail below, our performance criterion is our comparative TSR over the LTIP’s three-year period. Earned performance shares are paid in cash or shares of Cinergy common stock, as determined annually by Cinergy.
For the cycle that ended December 31, 2005, stock options were valued at $4.26 per option using the Black Scholes valuation methodology; performance shares were valued at $23.724 per share using the Hewitt risk assessment methodology. Thus, an LTIP participant with a base salary of $100,000 and a target award of 20 percent would receive a target award with a value of $20,000. Twenty-five percent of this value, or $5,000, would be provided in the form of stock options and 75 percent of the value, or $15,000, would be provided in the form of performance shares.
The stock options have a ten-year life and vest three years form the date of grant. As stated above, the performance shares generally are earned only to the extent that Cinergy’s TSR targets for the cycle are met as compared with the TSR of a peer group of companies. The peer group for purposes of the TSR calculation under the LTIP consists of the companies in the S&P Electric Supercomposite Index as of the first day of the cycle, adjusted for certain specifically enumerated events that occur during the cycle of the type that could distort the index (e.g., bankruptcies and transactions or potential transactions involving companies included in the index group). The following table illustrates how the performance share payouts directly align participants’ pay to Cinergy’s performance:
Pursuant to the terms of the LTIP as approved by shareholders, in the event of a change in control (as defined in the LTIP), stock options generally would vest, and the payment of performance shares would accelerate (without proration) with all relevant performance criteria deemed satisfied at the maximum. However, stock options granted after May 5, 2005 vest in accordance with their regular schedule regardless of the occurrence of a change in control, and, although the payment of performance shares granted after this date accelerates upon a change in control, the payment is prorated (except in the event of certain terminations of employment) and is calculated based on the greater of actual or target performance with respect to all applicable performance criteria.
Cinergy’s TSR performance percentile for the LTIP cycle that ended December 31, 2005 was 36.3, which corresponds to a payout equal to 25.2% of the target grant of performance shares.
Additional Awards
The Committee may grant additional short-term or long-term awards to recognize increased responsibilities or special contributions, to attract new hires to Cinergy, to retain executives, or to recognize other special circumstances. In 2005, certain performance-based restricted stock awards were granted to the named executive officers as shown in the Summary Compensation Table.
Other Programs
Cinergy also provides its executive officers with life and medical insurance, pension, savings and compensation deferral programs, perquisites and other benefits that are competitive with market practices. The Committee considers all benefits when reviewing the total compensation of the executive officers.
On December 30, 2005, Cinergy entered into agreements with certain executive officers, including Mr. Cyrus, Mr. Turner, Mr. Manly and Ms. Good, to accelerate the payment of a portion of the executive’s benefits, otherwise expected to be paid following the closing of the merger by and among Cinergy and Duke Energy Corporation (Duke), in order to mitigate Cinergy’s taxes and related expenses. The new agreements amend the executive officers’ employment agreements, and the benefit plans in which they participate, to provide that Cinergy will accelerate (into 2005) the payment of certain amounts that they have previously earned or are expected to earn following the closing of the merger. Pursuant to these agreements, Cinergy prepaid Mr. Cyrus $9,223,445, Mr. Turner $589,680, Mr. Manly $1,403,664 and Ms. Good $973,137, and the other executive officers as a group $21,877,316 in connection with some or all of the following benefits: (i) performance shares under Cinergy’s long-term incentive plan, (ii) expected 2006 bonus payment, (iii) estimated severance benefits, (iv) expected and/or earned supplemental executive retirement benefits and (v) restricted stock awards. In the event the executive voluntarily terminates his or her employment prior to the closing of the merger, the executive is obligated to repay all of the payments, and if the merger does not close on or prior to a specified date, the executive is obligated to repay half of the payments, to reflect his or her estimated tax liability upon receipt of the accelerated payments; in each case, less any amounts that the executive has already earned through such date. The balance of the prepaid amounts will reduce the amounts described above that are payable as a result of the closing of the merger. By accelerating these payments, Cinergy will mitigate its taxes and related expenses that it would otherwise incur if it had waited until after 2005 to make these payments.
Chief Executive Officer
Philosophy. The Committee’s objective with respect to CEO compensation is to motivate and retain a chief executive officer who is committed to delivering sustained superior performance for all of Cinergy’s stakeholders. We attempt to compensate the Chief Executive Officer using, whenever possible, stock-based compensation so as to strengthen his alignment with shareholder interest in stock price appreciation and dividend yield. The Chief Executive Officer is also provided perquisites and retirement benefits commensurate with those provided to chief executive officers of comparably-sized general industry companies.
Consistent with our compensation philosophy described above, in early 2004, the Committee approved a new compensation package for Mr. Rogers, including a restated employment agreement. See “Employment Agreements” for a description of Mr. Rogers’ restated employment agreement. Mr. Rogers has served as Chairman, and CEO of PSI Energy, Inc. since 1988, as CEO of Cinergy Corp. since 1995, and as Chairman since 2000. The Committee determined that the new compensation package was appropriate, and continues to be appropriate, based upon the long-term performance of Mr. Rogers.
Base Salary. In 2005, Mr. Rogers did not receive an increase to his base salary.
Annual Incentive Compensation. For 2005, Mr. Rogers received a cash award under the Annual Incentive Plan in the amount of $1,947,129. The award was based on the corporate goal achievement discussed above, and a 3.0 with respect to his objective individual goals, which included a customer satisfaction goal, supplier diversity goal, workforce diversity goal, workforce engagement goal and a corporate governance goal.
Long-Term Incentive Compensation. Mr. Roger’s payout for the performance cycle of the LTIP that ended December 31, 2005, was $959,499.
As stated above, the Committee emphasizes pay for performance. In this regard, approximately 65.0 percent of Mr. Rogers’ 2005 compensation listed in the Summary Compensation Table was performance-based.
Code Section 162(m)
Internal Revenue Code Section 162(m) generally limits Cinergy’s annual federal income tax deduction to one million dollars for compensation paid to each of the named executive officers. However, qualifying performance-based compensation is exempted from the deduction limit under certain conditions. The Committee attempts to qualify the named executive officers’ compensation for full corporate deductibility, including awards under the shareholder-approved AIP and LTIP; however, in an effort to remain competitive and attract and retain key management employees, certain compensation awarded in 2005 may not qualify for exemption from the deduction limit under Section 162(m) of the Internal Revenue Code.
Compensation Committee
Michael G. Browning, Chair
George C. Juilfs
Thomas E. Petry
John J. Schiff, Jr.
Summary Compensation Table
Included in the following table is, for the past three years, the compensation paid to our Chief Executive Officer and the other four most highly compensated executive officers in 2005. These amounts include payments for services in all capacities to Cinergy and its subsidiaries. We sometimes refer to the persons listed below as the “named executive officers.”
(1)
The aggregate value of all restricted stock holdings for Messrs. Rogers, Cyrus, Turner and Manly and Ms. Good, respectively, as of December 31, 2005 are $0, $187,970, $911,871, $610,363 and $338,491. With respect to a portion of the restricted stock, dividends are payable upon vesting and with respect to the remaining portion of the restricted stock, dividends are payable on a current basis in accordance with Cinergy’s applicable dividend policy.
(2)
Amounts appearing in this column reflect payouts relating to the Cinergy Corp. 1996 Long-Term Incentive Plan.
(3)
Amounts appearing in this column for 2005 include for Messrs. Rogers, Cyrus, Turner and Manly and Ms. Good, respectively: (i) employer matching contributions under the 401(k) Plan and related 401(k) Excess Plan of $58,719, $30,306, $25,243, $24,155 and $14,441; (ii) insurance premiums paid with respect to executive/group-term life insurance of $637, $3,699, $3,654, $3,086 and $2,189 and (iii) accelerated payments made in order to mitigate Cinergy's taxes and related expenses of $0, $9,223,445, $589,680, $1,403,664 and $973,137. For Mr. Rogers, the amount also includes above market interest of $179,136 earned on portions of his base salary deferred from 1992 to 2001 under his Deferred Compensation Agreement. For Mr. Cyrus and Ms. Good, the amount also includes $18,299 and $22,943 of profit sharing contributions under the 401(k) Plan and related Excess Profit Sharing Plan.
(4)
This amount includes approximately $17,550 after tax cost to the Company related to a car allowance and approximately $25,682 after tax cost to the Company related to legal expenses.
(5)
Ms. Good began employment with Cinergy Corp. on May 1, 2003.
Option/SAR Grants Table
Included in the following table are individual grants of options to purchase Cinergy common stock made to the named executive officers during 2005. On January 1, 2003, we began expensing new stock option grants. The fair value of a stock option is expensed over the option’s stated vesting period, except for retirement eligible employees for which the grants are expensed immediately because vesting accelerates upon retirement. In 2005, we granted 766,100 stock options with an average fair value of $5.64 per option. In 2005, we recognized approximately $6 million of expense related to stock options granted since January 1, 2003.
(1) Options were granted pursuant to the LTIP effective January 1, 2005 and become exercisable on January 1, 2008, the third anniversary of the grant. In the case of a change-in-control of Cinergy, including the pending merger with Duke or the retirement or death of the executive, all stock options become immediately exercisable.
(2) Options were granted on December 14, 2005 and do not vest upon the closing of the pending merger with Duke.
(3) The amounts shown represent hypothetical potential appreciation of Cinergy common stock and do not represent either historical performance or, expected future levels of appreciation. The actual values which may be realized, if any, upon the exercise of stock options will depend on the future market price of Cinergy common stock, which cannot be forecast with reasonable accuracy.
Aggregated Option/SAR Exercises and Year End Option/SAR Values Table
Included in the following table is, for each named executive officer, information concerning (i) stock options exercised during 2005, including the value realized (i.e., the spread between the exercise price and the market price on the date of exercise), and (ii) the number of shares covered by options held on December 31, 2005 and the value of the officer’s “in the money” options. “In-the-money” value is the positive spread between the closing market price of Cinergy common stock on December 31, 2005 ($42.46 per share) and an option’s exercise price per share.
LTIP Awards Table
Both stock option grants and target awards of performance shares were made for the three-year LTIP performance cycle that began January 1, 2005. The stock option grants are reported on the “Option/SAR Grants Table”. Included in the following table are potential payouts of performance shares awarded to the named executive officers during 2005.
(1) See “Option/SAR Grants Table.”
(2) Payouts of performance shares are tied to Cinergy’s TSR targets for a cycle as compared with the TSR of a peer group consisting of the companies comprising the Standard & Poor’s Electric Supercomposite Index as of the first day of the cycle, adjusted for certain specifically enumerated events that occur during the cycle of the type that could distort the index (e.g., bankruptcies and transactions or potential transactions involving companies included in the index group). If Cinergy does not exceed the threshold level of performance equal to the 30th percentile of the peer group’s TSR, no performance shares are earned. The target and maximum amounts are earned if Cinergy’s TSR meets the 55th and meets or exceeds the 85th percentiles, respectively, of the peer group’s TSR. Except in the case of a change in control, disability, death or retirement on or after age 50 during the cycle, a participant must be employed on the last day of a cycle to receive an earned award. See “Summary Compensation Table” above for payouts related to the cycle ended December 31, 2005. Performance awards are paid out at the maximum amount in the case of a change-in-control of Cinergy, including the pending merger with Duke.
Pension Benefits
Substantially all non-union employees, including our named executive officers, are entitled to benefits under our Non-Union Employees’ Pension Plan (Pension Plan). In addition, eligible employees, including our named executive officers, will receive benefits under our Supplemental Executive Retirement Plan (SERP) and Excess Pension Plan at retirement, and each named executive officer may receive an additional retirement benefit under his or her employment agreement (described below). These plans, which are described in more detail below, are defined benefit pension plans to which the participants do not contribute.
Pension Plan and Excess Pension Plan
At the end of 2002, each active participant in the Pension Plan, including our named executive officers, was provided a one-time election to continue to have his or her pension benefit calculated under a traditional final average pay formula or to earn future benefits under one of two new cash balance programs. All employees hired on or after January 1, 2003 may elect to earn benefits under one of the two cash balance programs but not the traditional final average pay formula. Messrs. Rogers, Turner and Manly elected to continue to earn benefits under the traditional final average pay formula, which calculates pension benefits based on a participant’s “highest average earnings” and years of plan participation. Mr. Cyrus elected to participate in the Balanced Program and Ms. Good, who was hired in 2003, elected to participate in the Investor Program. The Excess Pension Plan, which covers employees with eligible earnings in excess of certain tax code limitations, including the named executive officers, is designed primarily to provide those benefits which cannot be paid from the Pension Plan by reason of certain tax code limitations applicable to qualified plan benefits. The following table shows the estimated annual pension benefits payable as a straight-life annuity under the final average pay formula of our Pension Plan and Excess Pension Plan to participants who retire at age 62.
For pension purposes, a participant’s “highest average earnings” is generally the employee’s average annual earnings (including short-term incentive compensation and, with respect to the Excess Pension Plan, certain non-elective contributions to the 401(k) Excess Plan) during a three consecutive year period within the ten years immediately preceding retirement, that produces the highest average. For purposes of the table, the estimated credited years of service at age 62 for the named executive officers are as follows: Mr. Rogers, 20 years; Mr. Turner, 26 years; and Mr. Manly, 11 years. For purposes of this table, Mr. Rogers’ current highest average earnings is $3,518,250. The benefits are not subject to any deduction for social security or other offset amounts.
As stated above, Mr. Cyrus elected to earn benefits under the Balanced Program and Ms. Good elected to receive benefits under the Investor Program, each of which are cash balance programs. The Investor Program provides an annual pay credit equal to two percent of eligible annual earnings to a hypothetical account established for the participant, and the Balanced Program provides an annual pay credit equal to three percent, four percent or five percent (depending on the participant’s years of service) of eligible annual earnings to a hypothetical account established for the participant. Each participant’s account is also credited with interest credits that are currently based on the 30-year Treasury bond rate. The estimated annual benefit payable upon retirement at age 62 for Mr. Cyrus and Ms. Good, respectively, under the Pension Plan and the Excess Pension Plan is $143,947 and $28,371. These estimates are based on the assumption that: (i) the executive remains employed until age 62; (ii) the executive’s compensation increases at an annual rate of three percent; (iii) the executive receives a target annual bonus each year; and (iv) current interest rates remain constant. Participants in the Balanced and Investor Programs also are entitled to receive profit sharing contributions to their accounts under Cinergy’s 401(k) Plan and Excess Profit Sharing Plan, in an aggregate amount of up to 15 percent of eligible earnings in any one year, based on Cinergy’s corporate performance.
SERP
Our SERP provides selected executive officers, including the named executive officers, with an opportunity to earn a pension benefit that will replace up to 60 percent of their “final average earnings”. Benefits payable under the SERP are reduced by the benefits provided under our Pension Plan and Excess Pension Plan, and further reduced by 50 percent of the employee’s age 62 social security benefit. Under the SERP, each participant accrues a retirement income replacement percentage at the rate of four percent (Mr. Manly’s employment agreement provides for a SERP enhancement equal to the incremental benefit he would receive if his retirement income replacement percentage accrued at a rate of five percent rather than four percent) per year from the date the participant is first classified as a “senior executive employee,” up to a maximum of 15 years. For this purpose, “final average earnings” is the greater of (i) the employee’s highest average earnings (as defined in our Excess Pension Plan) or (ii) the final 12 months of base pay plus short-term incentive compensation and certain non-elective contributions under the 401(k) Excess Plan. Based on the SERP and applicable employment agreements (discussed below), the estimated retirement income replacement percentage is 65 percent for Mr. Rogers and approximately 60 percent for the other named executive officers, assuming each other named executive officer remains employed until age 62.
Supplemental Retirement Benefits Under Employment Agreements
Each named executive officer (other than Ms. Good) has entered into an employment agreement that provides that if he retires after age 55 (age 62 for Mr. Manly), he will be entitled to a supplemental retirement benefit equal to the excess of the maximum potential SERP benefit over his actual total benefit under our Pension Plan, Excess Pension Plan and SERP. The supplemental retirement benefit is payable to the named executive officer’s surviving spouse, if any, if the named executive officer dies while employed by Cinergy after reaching age 55. Any benefit payable to the surviving spouse will be actuarially adjusted, consistent with the applicable joint and survivorship provisions contained in the Pension Plan. The supplemental retirement benefit provided to Mr. Rogers under his employment agreement differs in two ways: (i) upon attaining age 58, his benefit was increased to 65 percent of his “highest average earnings”; and (ii) his “highest average earnings” includes certain portions of the performance award below discussed. The employment agreements are described below in more detail.
The named executive officers generally may elect to receive the actuarial equivalent of their entire supplemental retirement benefit, and their benefits under the Excess Pension Plan and SERP, in a lump sum if they terminate employment prior to the second anniversary of a change in control. In the absence of a change in control, participants may elect to receive one-half of such benefits in the form of a lump sum payable following their termination of employment.
Cinergy’s Executive Supplemental Life Insurance Program provides key management personnel, including the named executive officers, with additional life insurance during employment and with post-retirement deferred compensation. If the participant retires after attaining age 50, the life insurance coverage is canceled and, instead, the participant receives the value of the coverage in the form of deferred compensation, payable in ten equal annual installments of $15,000 per year. Mr. Turner, Mr. Manly and Ms. Good also have elected to participate in our Executive Life Insurance Plan, under which Cinergy pays the premiums with respect to a whole life insurance policy owned by each executive that provides life insurance coverage in an amount equal to the amount of his or her annual base salary and target annual bonus.
The American Jobs Creation Act of 2004, which was enacted on October 22, 2004, made substantial changes to the administration, design and taxation of deferred compensation arrangements. Cinergy’s compensation plans will be revised, as necessary, to comply with the new laws.
Employment Agreements
We have entered into an employment agreement with each of our named executive officers. The term of the employment agreements expire on December 31, 2008 (December 31, 2007 for Ms. Good). On December 31, 2006, and each year thereafter, the term is automatically extended for one additional year absent notice of earlier termination by either party. The named executive officers will receive the following annual salaries in 2006: $1,250,004 for Mr. Rogers, $666,576 for Mr. Cyrus, $561,600 for Mr. Turner, $537,204 for Mr. Manly and $390,000 for Ms. Good. Each named executive officer is entitled to receive the same perquisites as are provided to other senior executives of Cinergy and to participate in the same benefit and retirement plans offered to our other executive officers, including the SERP, Excess Pension Plan, Annual Incentive Plan (AIP) and LTIP, with the target and maximum incentive awards under those plans to be not less than as specified in the employment agreements. We also will reimburse the named executive officers for taxes applicable to certain benefits they receive. The employment agreements (with the exception of Ms. Good’s agreement) also provide the supplemental retirement benefits above described.
If we terminate a named executive officer’s employment for cause (as defined in the agreement), or if the executive terminates his or her employment other than for good reason (as defined in the agreement), then he or she will be entitled to receive under his or her employment agreement only his or her “accrued benefits,” which consist of earned but unpaid compensation and benefits, including a pro rata portion of the executive’s projected bonus under the AIP.
Outside the change in control context (i.e., prior to or more than twenty-four months after a change in control), if we terminate a named executive officer’s employment without cause or the executive terminates his or her employment
for good reason, then, in addition to his or her accrued benefits, the executive will be entitled to receive the following severance benefits:
• three times (two times for Ms. Good) the sum of his or her annual base salary plus the higher of his or her prior year annual bonus or his or her current year projected bonus (but not less than target); and
• continued medical and welfare benefits through the end of the stated term of the employment agreement or a cash equivalent (reduced by coverage obtained from subsequent employers).
In the change in control context (i.e., within twenty-four months after a change in control), if we terminate a named executive officer’s employment without cause or the executive terminates his or her employment for good reason, then the executive will be entitled to receive, in addition to his or her accrued benefits, the following severance benefits:
• three times the sum of the higher of his or her annual base salary and target annual bonus or his or her annual base salary in effect immediately prior to the change in control and annual bonus (based on the higher of his or her prior year annual bonus, his or her annual bonus for the year prior to the change in control, or his or her current year projected bonus (but not less than target));
• the present value of any benefits under our Executive Supplemental Life Program;
• full vesting of his or her accrued benefits under our Pension Plan, Excess Pension Plan and SERP;
• three additional years of age and service credit for purposes of calculating the supplemental retirement benefit and benefits under our Pension Plan, Excess Pension Plan and SERP;
• welfare benefits for a 36-month period following termination of service or a cash equivalent (reduced by coverage obtained from subsequent employers);
• a payment of $50,000 ($35,000 for Ms. Good) in lieu of additional automobile benefits; and
• miscellaneous benefits, including outplacement services.
If the employment of a named executive officer is terminated other than by death, the executive generally will be entitled to reimbursement for reasonable relocation costs (reduced by relocation benefits obtained from subsequent employers). Cinergy will pay legal fees incurred by each named executive officer as a result of successfully disputing a termination of employment that entitles him to benefits under his or her employment agreement. In the event any payment made to a named executive officer results in the imposition of the golden parachute excise tax, Cinergy must make an additional payment to cover all such excise taxes and any taxes on the additional payments.
Any stock options or stock appreciation rights held by the executives and granted prior to May 8, 2005 become immediately exercisable upon a change in control to the extent not otherwise provided in the applicable documents. If an executive terminates employment for any reason within twenty-four months following the change in control, his or her stock options and stock appreciation rights remain exercisable for at least three months following termination of employment.
Under his employment agreement, Mr. Rogers received a $5 million performance-based phantom stock award that will be credited to his account under the 401(k) Excess Plan on December 31, 2006, provided that performance measures established by the Compensation Committee have been satisfied as of that date. The credit to Mr. Rogers’ account will be accelerated (without regard to the achievement of the performance measures) in the event he dies or becomes disabled, we terminate his employment without cause, he terminates his employment for good reason or in the event of a change in control. In order to further align the interests of Mr. Rogers and our shareholders, the credit, if any, to Mr. Rogers’ account under the 401(k) Excess Plan will remain invested in phantom shares of Cinergy common stock until distributed, in cash, upon his retirement from the Company. Mr. Rogers is paid dividend equivalents on the $5 million potential award on a current basis; and $600,000 of the potential award will be included in Mr. Rogers’ annual base salary for purposes of calculating his LTIP awards, annual bonus and supplemental retirement benefit during 2005 and 2006.
Mr. Rogers is entitled to certain severance benefits in addition to those above described. In particular, in the event that we terminate Mr. Rogers’ employment without cause or he terminates his employment for good reason, then Mr. Rogers also will be entitled to (i) a payment of $60,000 (rather than the benefit provided to the other named executive officers) in lieu of additional automobile benefits, and (ii) in the event such termination occurs outside the
change in control context, the aggregate amount that he would have received had he remained employed through the end of the employment term under the performance share awards that he holds on the date of his termination of employment.
Deferred Compensation Agreement
In 1992, PSI entered into a deferred compensation agreement with Mr. Rogers. Except for earnings on amounts previously deferred, Mr. Rogers is not accruing any additional benefits under this agreement. The agreement provides that upon termination of his employment, for any reason other than death, Mr. Rogers will receive two 15-year annual cash benefits beginning the first January thereafter. Payment of the first annual cash benefit will commence no later than January 2010 and will range from $341,000 if payment begins in January 2007 to $554,000 if payment begins in January 2010. Payment of the second annual cash benefit will commence no earlier than January 2008 and no later than January 2010 and will range from $179,000 to $247,000. Comparable amounts are payable if Mr. Rogers dies before these payments begin.
Compensation of Cinergy Directors
In 2005, the fees paid to our non-employee directors consisted of:
In addition, when a non-employee director is first elected to the Board, he or she is granted a non-qualified stock option to purchase 12,500 shares of Cinergy common stock. All such options have exercise prices at least equal to 100 percent of the fair market value of Cinergy common stock on the date of the grant, vest at the rate of 20 percent per year over a five-year period and may be exercised over a 10-year term. Cinergy also reimburses all non-employee directors for expenses incurred to attend and participate at Board and committee meetings, including the annual off-site strategic retreat. Directors who are employees of Cinergy receive no compensation for their service as directors.
The portion of each non-employee director’s annual retainer that is payable in cash is paid quarterly in arrears. The portion of each non-employee director’s annual retainer that is payable in Cinergy common stock, unless voluntarily deferred, is delivered to the director as soon as practicable after January 1 each year. If voluntarily deferred, the shares, along with reinvested dividends, are credited to an individual bookkeeping account maintained by Cinergy on behalf of the non-employee director and must remain in the account until he or she ceases to be a director, at which time the units will be distributed to the director.
Under our Directors’ Deferred Compensation Plan, each non-employee director of Cinergy may choose to defer the portion of his or her fees that is otherwise payable in cash into a bookkeeping account denominated in either cash or units representing shares of Cinergy common stock, or in a combination of cash and units. If deferred in units, additional units are credited to the director’s account at the same time and rate as dividends are paid to holders of Cinergy common stock. Amounts deferred into a cash bookkeeping account earn interest at the annual rate (adjusted quarterly) equal to the interest rate on a one-year certificate of deposit for $100,000 (as quoted in The Wall Street Journal) on the first business day of the calendar quarter. Deferred units are distributed as shares of Cinergy common stock, and accrued cash accounts are paid in cash, generally commencing in the year immediately following the year in which the director ceases to be a director.
As described in the table above, under Cinergy’s Directors’ Equity Compensation Plan, each non-employee director receives an annual award on December 31 equal to 450 shares of Cinergy common stock. Each such award is credited, along with reinvested dividends, to a bookkeeping account maintained on behalf of the non-employee director and is paid beginning when he or she ceases to be a director or upon a change in control. The accrual of future benefits under our
Retirement Plan for Directors was eliminated effective January 1, 1999. Each of our currently serving non-employee directors who had an accrued cash benefit under such plan prior to 1999 converted the benefit to units representing shares of Cinergy common stock. These units are payable, along with reinvested dividends, after the director ceases to be a director or upon a change in control.
For 2006, the Board approved the advance payment of the cash portion of the annual retainer as well as the committee meeting fees to those non-employee directors who will not continue to serve on the Board of Directors of the combined company of Cinergy and Duke after the closing of the merger.
Compensation of PSI Directors
Each non-employee director of PSI is eligible to receive an annual retainer fee of $8,000 plus a fee of $1,000 for each Board meeting attended. However, any non-employee director of PSI who also serves as a non-employee director of Cinergy or any of its affiliates shall not receive the annual retainer fee, or any compensation for attendance at any Board meeting that is held concurrently or consecutively with a meeting of Cinergy’s Board of Directors. Mr. Browning, a non-employee director of PSI, is currently also a non-employee director of Cinergy. Directors who are employees of Cinergy or any of its subsidiaries (Mr. Rogers and Ms. Pashos) receive no compensation for their services as directors. These cash fees are eligible to be deferred under the Directors’ Deferred Compensation Plan above described.
As described above, the accrual of future benefits under Cinergy’s Retirement Plan for Directors was eliminated effective January 1, 1999. Mr. Browning converted his accrued cash benefit under the plan on that date to units representing shares of Cinergy common stock, payable commencing at the time of his retirement from both PSI’s and Cinergy’s boards.
All CG&E directors currently are employees of Cinergy and receive no compensation for their services as directors.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners and Management
Listed on the following table are the owners of five percent or more of Cinergy’s outstanding shares of common stock, as of December 31, 2005. This information is based on the most recently available reports filed with the SEC and provided to us by the companies listed.
(1) This information was obtained from the beneficial owner’s Schedule 13G/A filed with the SEC on February 15, 2006.
(2) This information was obtained from the beneficial owner’s Schedule 13G/A filed with the SEC on February 7, 2006.
Listed on the following table is the number of shares of Cinergy common stock beneficially owned by each director, each executive officer named in the Summary Compensation Table and all directors and executive officers as a group, as of January 31, 2006.
* Represents less than 1%.
(1) Includes shares that there is a right to acquire within 60 days of January 31, 2006 in the following amounts: Mr. Browning - 13,386; Mr. Cox - 13,386; Mr. Cyrus - 173,099; Ms. Good - 0; Mr. Juilfs - 13,386; Mr. Manly - 96,300; Mr. Petry - 13,386; Mr. Rogers - 1,115,800; Ms. Schapiro - 25,035; Mr. Schiff - 3,604; Mr. Sharp - 3,386; Mr. Taft - 10,000; Mr. Turner - 120,826; and all directors and executive officers as a group - 1,739,994.
Cinergy Corp. owns all outstanding shares of common stock of CG&E, CG&E’s only voting security.
CG&E’s directors and executive officers did not beneficially own any shares of any class of equity security of CG&E as of January 31, 2006. The beneficial ownership of Cinergy Corp. common stock by each director and named executive officer of CG&E as of January 31, 2006, is set forth in the following table:
* Less than 1 percent
(1) Includes shares which there is a right to acquire within 60 days of January 31, 2006 in the following amounts: Mr. Cyrus - 173,099; Mr. Ficke - 31,800; Ms. Good - 0; Mr. Manly - 96,300; Mr. Rogers - 1,115,800; Mr. Turner - 120,826 and all directors and executive officers as a group - 1,667,825.
Security Ownership of Certain Beneficial Owners and Management
The following table lists the sole owner of five percent or more of PSI’s outstanding shares of common stock as of January 31, 2006.
Based on the most recently available reports filed with the SEC, to our knowledge there were no owners of five percent or more of PSI’s outstanding shares of cumulative preferred stock as of December 31, 2005.
Listed on the following table is the number of shares of Cinergy common stock beneficially owned by each of PSI’s director and executive officers named in the Summary Compensation Table, and by all directors and executive officers as a group, as of January 31, 2006. PSI’s director and named executive officers did not beneficially own any shares of PSI cumulative preferred stock as of January 31, 2006.
* Represents less than 1%.
(1) Includes shares that there is a right to acquire within 60 days of January 31, 2006 pursuant to the exercise of stock options in the following amounts: Mr. Browning - 13,386; Mr. Cyrus - 173,099; Ms. Good - 0; Mr. Manly - 96,300; Ms. Pashos - 14,100; Mr. Rogers - 1,115,800; Mr. Turner - 120,826; and all directors and executive officers as a group - 1,663,511.
The following table reflects Cinergy’s equity compensation plan information as of December 31, 2005:
Equity Compensation Plan Information
The following information describes the equity compensation plans that have not been approved by shareholders.
Cinergy Corp. UK Sharesave Scheme
The Cinergy Corp. UK Sharesave Scheme allows United Kingdom employees working a minimum of 25 hours per week to purchase shares of common stock pursuant to a stock option feature. Under the Cinergy Corp. UK Sharesave Scheme, after-tax funds are withheld from a participant’s compensation during a 36-month or 60-month offering period, at the election of the participants, and are deposited in an account. At the end of the offering period, participants may apply amounts deposited in the account toward the purchase of shares of common stock. The purchase price cannot be less than 80 percent of the average market price at date of grant or shortly prior to the grant. Any funds not applied toward the purchase of shares are returned to the participant. No individuals currently participate in the UK Sharesave Scheme and Cinergy has no current intention to permit future participation in this scheme.
Cinergy Corp. 401(k) Excess Plan
The Cinergy Corp. 401(k) Excess Plan is a non-qualified deferred compensation plan for a select group of Cinergy management and other highly compensated employees. It is a means by which these employees can defer additional compensation, and receive additional company matching contributions, when they have already contributed the maximum amount (pursuant to the anti-discrimination rules for highly compensated employees) under the 401(k) Plan. Cinergy can also make non-elective contributions to this plan. All funds deferred are held in a rabbi trust administered by an independent trustee.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Certain Relationships and Related Transactions
Mr. Benjamin C. Rogers, age 34, is the son of our Chairman and Chief Executive Officer and an employee of Cinergy Services, Inc., a subsidiary of Cinergy. For 2005, Mr. Benjamin Rogers received an aggregate of approximately $181,842 in base salary and bonus.
Mr. Schiff serves as an executive officer of certain entities from which Cinergy or its affiliates purchase, at competitive rates, certain bond and/or insurance coverage in connection with the Company’s or its affiliates’ ordinary business needs. In 2005, entities of which Mr. Schiff served as an executive officer received, in the aggregate, approximately $34,407 related to these services.
Mr. Cox serves as chief executive officer of Cox Financial Corporation, a company that acts as a broker with respect to the Company’s executive life insurance program. In 2005, Cox Financial Corporation received approximately $28,925 related to these services.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Independent Public Accountants
Information on fees billed by Deloitte & Touche LLP for services rendered during 2004 and 2005 follows.
(1)
The Audit-Related Services included audits of our benefit plans and certain types of consultation. The Tax Services included international, federal and state preparations and compliance, as well as tax consultation. Tax compliance services accounted for approximately $320,000 of all Tax Services.
The Audit Committee is responsible for approving all audit and permissible non-audit services provided to Cinergy by its independent auditors. Pursuant to this responsibility, the Audit Committee adopted the Auditor Independence Pre-Approval Policy which provides that the Audit Committee will annually establish detailed services and related fee levels that may be provided by the independent auditors. Under the Policy, detailed audit services, audit-related services and tax services have been specifically pre-approved up to certain fee limits. In the event that the cost of any of these services may exceed the pre-approved limits, the Audit Committee must pre-approve the service. All other services that are not prohibited pursuant to the SEC’s or other applicable regulatory bodies’ rules or regulations must be specifically pre-approved by the Audit Committee. Any request for services that requires Audit Committee pre-approval will be submitted to the Audit Committee by the Chief Financial Officer or Controller and a representative of Cinergy’s Legal Department. The request must include a joint statement, in writing, (a) describing (i) the scope of the service, the fee structure for the engagement, and any side letter or other amendment to the engagement letter, or any other agreement (whether oral, written, or otherwise) between the independent auditor and the Company, relating to the service; and (ii) any compensation arrangement or other agreement, such as a referral agreement, a referral fee or fee-sharing arrangement, between the independent auditor (or an affiliate of the independent auditor) and any person (other than the Company) with respect to the promoting, marketing, or recommending of a transaction covered by the service; and (b) discussing the potential effects of the services on the independence of the independent auditor. Under the Policy, the Audit Committee may delegate specific pre-approval authority to one or more of its members but it may not delegate its responsibilities to pre-approve services performed by the independent auditors to management. The Auditor Independence Pre-Approval Policy is available on our website at www.cinergy.com/governance.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
FINANCIAL STATEMENTS AND SCHEDULES
Refer to the page captioned “Index to Financial Statements and Financial Statement Schedules” for an index of the financial statements and financial statement schedules included in this report.
EXHIBITS
The documents listed below are being filed or have previously been filed on behalf of Cinergy Corp., CG&E, PSI, and The Union Light, Heat and Power Company (ULH&P) and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith:
(1) Regulation S-K 229.10(d) requires Registrants to identify the physical location, by SEC file number reference, of all documents that are incorporated by reference and have been on file with the SEC for more than five years. The SEC file number references for Cinergy and its subsidiaries, which are registrants are provided below:
Cinergy Corp. in file number 1-11377
CG&E in file number 1-1232
PSI in file number 1-3543
ULH&P in file number 2-7793
* Denotes a management contract or compensatory plan or arrangement.
Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not previously listed.
FINANCIAL STATEMENT SCHEDULES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2005
(in thousands)
(1) The beginning balance for 2005 is not equal to the ending balance for 2004 due to the 2005 reclassification of the provision related to discontinued operations. See Note 16 in “Item 8. Notes to Financial Statements - Discontinued Operations.”
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company each has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Exchange Act, this report has been signed by the following persons on behalf of the indicated registrants and in the capacities and on the dates indicated:
* The undersigned, by signing his or her name hereto, does hereby execute this Form 10-K on behalf of the officers and directors of the registrant previously indicated by asterisks, pursuant to powers of attorney duly executed by such officers and directors and incorporated by reference as an exhibit to this Form 10-K.