Transmission System Interconnections
The following map illustrates the interconnections between our electric systems and other electric systems.
14
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20032004
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number |
| Registrant, State of Incorporation, Address and Telephone Number |
| I.R.S. Employer Identification No. |
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1-11377 |
| CINERGY CORP. (A Delaware Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500 |
| 31-1385023 |
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1-1232 |
| THE CINCINNATI GAS & ELECTRIC COMPANY (An Ohio Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500 |
| 31-0240030 |
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1-3543 |
| PSI ENERGY, INC. (An Indiana Corporation) 1000 East Main Street Plainfield, Indiana 46168 (513) 421-9500 |
| 35-0594457 |
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2-7793 |
| THE UNION LIGHT, HEAT AND POWER COMPANY (A Kentucky Corporation) 139 East Fourth Street Cincinnati, Ohio 45202 (513) 421-9500 |
| 31-0473080 |
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Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is registered on the New York Stock Exchange:
Registrant |
| Title of each class | |||
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Cinergy Corp. |
| Common Stock |
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The Cincinnati Gas & Electric Company |
| Cumulative Preferred Stock | 4 | % | |
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PSI Energy, Inc. |
| Cumulative Preferred Stock | 4.32 | % | |
| Cumulative Preferred Stock | 4.16 | % | ||
| Cumulative Preferred Stock | 6-7/8 | % | ||
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The Union Light, Heat and Power Company |
| None |
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that such registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ý No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ýo
Requirements pursuant to Item 405 of Regulation S-K are not applicable for The Union Light, Heat and Power Company.
The Union Light, Heat and Power Company meets the conditions set forth in General Instruction I (1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I (2) of Form 10-K.
Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
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Cinergy Corp. | Yes | ý | No | o | |||||
The Cincinnati Gas & Electric Company | Yes | o | No | ý | |||||
PSI Energy, Inc. | Yes | o | No | ý | |||||
The Union Light, Heat and Power Company | Yes | o | No | ý |
As of June 30, 2003,2004, the aggregate market value of the common equity of Cinergy Corp. held by non-affiliates (shareholders who are not directors or executive officers) was $6.5$6.8 billion. All of the common stock of The Cincinnati Gas & Electric Company and PSI Energy, Inc. is owned by Cinergy Corp., and all of the common stock of The Union Light, Heat and Power Company is owned by The Cincinnati Gas & Electric Company. As of January 31, 2004,2005, each registrant had the following shares of common stock outstanding:
Registrant | Description | Shares | |||
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Cinergy Corp. |
| Par value $.01 per share |
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The Cincinnati Gas & Electric Company |
| Par value $8.50 per share |
| 89,663,086 | |
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PSI Energy, Inc. |
| Without par value, stated value $.01 per share |
| 53,913,701 | |
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The Union Light, Heat and Power Company |
| Par value $15.00 per share |
| 585,333 | |
2
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement of Cinergy Corp. and the Information Statement of PSI Energy, Inc. to be filed with the Securities and Exchange Commission in 20042005 are incorporated by reference into Part III of this report.
This combined Form 10-K is separately filed by Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to registrants other than itself.
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4
CAUTIONARY 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 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”.
This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as “anticipate”, “believe”, “intend”, “estimate”, “expect”, “continue”, “should”, “could”, “may”, “plan”, “project”, “predict”, “will”, and similar expressions.
Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
• Factors affecting operations, such as:
(1) unanticipated weather conditions;
(2) unscheduled generation outages;
(3) unusual maintenance or repairs;
(4) unanticipated changes in costs;
(5) environmental incidents, including costs of compliance with existing and future environmental requirements;incidents; and
(6) electric transmission or gas pipeline system constraints.
• Legislative and regulatory initiatives.
initiatives and legal developments.
• Additional competition in electric or gas markets and continued industry consolidation.
• Financial or regulatory accounting principles.
• Political, legal,principles including costs of compliance with existing and economic conditions and developments in the countries in which we have a presence.
future environmental requirements.
• Changing market conditions and other factors related to physical energy and financial trading activities.
• The performance of projects undertaken by our non-regulated businesses and the success of efforts to invest in and develop new opportunities.
• Availability of, or cost of, capital.
• Employee workforce factors.
• Delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures.
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• Costs and effects of legal and administrative proceedings, settlements, investigations, and claims. Examples can be found in Note 11 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
We undertake no obligation to update the information contained herein.
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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 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).
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 a result of this ownership, we are considered a utility holding company. Because we are a holding company with material utility subsidiaries operating in multiple states, we are registered with and are subject to regulation by the SEC under the Public Utility Holding Company Act of 1935, as amended. Our other principal subsidiaries are:
•are Cinergy Services, Inc. (Services);
• and Cinergy Investments, Inc. (Investments); and
•. Cinergy Wholesale Energy, Inc. (Wholesale Energy).
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 its subsidiaries,The Union Light, Heat and Power Company (ULH&P), in nearby areas of Kentucky and Indiana.Kentucky. CG&E is responsible for the majority of our power marketing and trading activity. CG&E’s principal subsidiary, The Union Light, Heat and Power Company (ULH&P), is a Kentucky corporation organized in 1901, that provides electric and gas service in northern Kentucky.CG&E’s other subsidiaries are insignificant to its results of operations.
In 2001, CG&E began is in a transition to electric deregulationmarket development period for residential customers and customer choice. Currently,in the competitive retail electric market in Ohio isfor non-residential customers, 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 stage.(frozen rate) period that began January 1, 2001, ended December 31, 2004 for non-residential customers and is scheduled to end December 31, 2005 for residential customers. At the end of these market development periods, CG&E is recovering itswill not implement market rates, but rather a rate stabilization plan (RSP) approved by the Public Utilities Commission of Ohio (PUCO) approved costs and retail electric rates are frozen during this market development period. In January 2003, CG&E filed an application withthat covers the PUCO for approval of a methodology to establish how market-based rates for non-residential customers will be determined whenperiod after the market development period ends. In December 2003, the PUCO requested that CG&E proposethrough 2008. The RSP, among other things, increases rates for environmental costs and capacity reserves and provides for a rate stabilization plan. In January 2004, CG&E complied with the PUCO requestfuel and filed an electric reliability and rate stabilization plan.emission allowance tracker through 2008. See the “Retail Market Developments” section“Electric Industry” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”Operations (MD&A)” for the various filings that led to the PUCO’s approval of CG&E’s RSP, further details of the plan, and a discussion of key elements of Ohio deregulation.
PSI, an Indiana corporation organized in 1942, is a vertically integrated and regulated electric
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utility that provides service in north central, central, and southern Indiana.
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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 | Major Cities Served | Approximate | |||||
CG&E and subsidiaries |
| •Generation, transmission, distribution, and sale of electricity • Sale and/or transportation of natural gas • Electric commodity marketing and trading operations |
| Cincinnati, OH |
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2,064,000 |
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PSI |
| •Generation, transmission, distribution, and sale of electricity |
| Bloomington, IN |
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ULH&P(1) |
| •Transmission, distribution, and sale of electricity • Sale and transportation of natural gas |
| Covington, KY |
| 345,000 | |
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(1) See Note 19 ofSee “Generation — Fuel Supply and Emission Allowances” under the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”“Regulated” section for further discussion of the possible transfer of generation assets.
Services is a service company that provides our subsidiaries with a variety of centralized administrative, management, and support services. Investments holds most of our domestic non-regulated, energy-related businesses and investments, including natural gas marketing and trading operations.operations (which are primarily conducted through Cinergy Marketing and Trading, LP (Marketing & Trading), one of its subsidiaries).
We conduct operations through our subsidiaries and manage our businesses through the following three reportable segments:
Wholesale •Commercial Business Unit (Commercial);
•Regulated Business Unit (Regulated); 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, 2004.
See Note 16 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for financial information by business segment.
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” in “Item 7. MD&A” for further detail of key elements of Ohio deregulation. Commercial also performs energy risk management activities, provides
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customized energy solutions and is responsible for all of our international operations. See the “Market Risk Sensitive Instruments” section of “Item 7. MD&A” 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 its various cost recovery mechanisms;
•Trading Operations and Risk Management — Describes Commercial’s energy marketing and trading activities in the United States and Canada;
•Competition — Describes the key competitors to Commercial’s various business operations;
•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; and
•Revenue Data and Customer Base — Describes the primary revenue generators for the various business operations of Commercial.
As of December 31, 2004, 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 megawatts (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, and Colorado. The price of coal has increased dramatically in 2004 as compared to 2003. Contributing to the rise in the price of coal are (1) increases in demand for electricity, (2) environmental regulation, and (3) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, Cinergy has 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 a substantial portion of our expected 2005 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” 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 the “Market Risk Sensitive Instruments” section of “Item 7. MD&A”.
A joint operating agreement, effective in April 2002, allows Cinergy to jointly dispatch the regulated generating assets of PSI in conjunction with the deregulated generating assets of CG&E. Under this agreement, transfers of power between PSI and CG&E are generally priced at market rates.
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.
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Commercial emits sulfur dioxide (SO2) and nitrogen oxides (NOX) in the generation of electricity and maintains emission allowances to offset their emissions in order to comply with NOX and SO2 emission reduction requirements. In 2004, the market prices of SO2 allowances rose more than 200 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 new RSP, retail fuel and emission allowance costs will be recovered through a wholly-owned subsidiary,cost tracking mechanism that recovers costs that exceed the amount originally included in the rates frozen in CG&E’s earlier transition plan. CG&E willrecover retail fuel and emission allowance costs consumed in serving retail load and collect a Provider of Last Resort charge from non-residential customers from 2005 through 2008 and from residential customers from 2006 through 2008. See “Electric Industry” in “Item 7. MD&A” for further detail of CG&E’s RSP.
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. In April 2002, CG&E and PSI executed a new joint operating agreement whereby new power marketing and trading contracts since April 2002 are originated on behalf of CG&E only. Historically, such contracts were executed on behalf of CG&E and PSI jointly.
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.
See the “Market Risk Sensitive Instruments” section of “Item 7. MD&A” for information on risks associated with these activities.
Competition
Commercial 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.
Commercial, through Cinergy Power Generation Services, LLC (Generation Services)Solutions Holding Company, Inc., is an on-site energy solutions and utility services provider. We provide utility systems construction, operation and maintenance of utility facilities, energy efficiencies and conservation consulting services, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of useable energy from a single fuel source.
Commercial, through Cinergy Capital & Trading, Inc., owns a coal-based synthetic fuel production facility which converts coal feedstock into synthetic fuel for sale to a third party. As of December 31, 2004, Cinergy has produced and sold approximately 7.8 million tons of synthetic fuel at this facility. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with the Internal Revenue Code Section 29 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
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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 Note 11(c)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
As of December 31, 2004, we had ownership interests in (1) generation assets located in three countries capable of producing approximately 150 MW of electricity and 700 MW equivalents of steam; and (2) approximately 1,200 miles of gas and electric transmission and distribution systems through jointly-owned investments in two countries, 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.
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. Because rates are frozen during the market development period in Ohio, the majority of these revenues are under a fixed-price tariff. Under the Ohio customer choice program, CG&E’s retail customers may choose their electric supplier. The percentage of customers switching to other electric suppliers and the related volume by customer class was as follows:
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| MW Hours For the |
| Switching |
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| MW at December 31 |
| Years Ended December 31 |
| Percentage at December 31(1) |
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Revenue Class |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
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Residential |
| 75 |
| 92 |
| 334,224 |
| 283,477 |
| 4.07 | % | 5.17 | % |
Commercial |
| 339 |
| 374 |
| 1,722,822 |
| 1,654,061 |
| 19.17 | % | 21.55 | % |
Industrial |
| 226 |
| 295 |
| 1,376,210 |
| 1,591,345 |
| 17.89 | % | 23.60 | % |
Other Public Authorities |
| 89 |
| 91 |
| 284,214 |
| 265,039 |
| 19.09 | % | 19.95 | % |
Total |
| 729 |
| 852 |
| 3,717,470 |
| 3,793,922 |
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(1) The residential switching percentage is based on annual energy consumption and the non-residential switching percentages are based on average monthly peak demand.
Customer switching reduces retail revenues by the generation component of rates and shopping incentives. CG&E still collects transmission and distribution revenues from the delivery of electricity to switched customers (see Regulated section for further information). During the market development period, the reduction in revenues due to customer switching is mitigated by wholesale power sales from the freed-up generation capacity. For further discussion on Ohio deregulation and the recently approved RSP see “Electric Industry” in “Item 7. MD&A”.
Commercial’s operating revenue is also derived by providing electricity at wholesale and trading electricity primarily in the midwest region of the United States. In addition, Commercial provides electric production-related construction,and trades natural gas primarily to wholesale 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 certain affiliates and non-affiliated third parties.large industrial customers.
9No single Commercial customer provides more than 10 percent of total operating revenues.
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
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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. Regulated operated approximately 48,000 circuit miles (the total length in miles of separate circuits) of electric lines to provide regulated transmission and distribution service to approximately 1.5 million customers as of December 31, 2004. Regulated operated approximately 9,226 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 500,000 customers as of December 31, 2004. 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 their responsibility; and
•Revenue Data and Customer Base — Describes the primary revenue generators for the various business operations of Regulated.
As of December 31, 2004, the total winter electric capacity (including our portion of the total capacity for the jointly-owned plants) of Regulated’s generating plants was 7,055 MW. Approximately 78 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, Pennsylvania, and Illinois. The price of coal has increased dramatically in 2004 as compared to 2003. The primary driving forces behind the increase in coal prices are (1) increases in demand for electricity, (2) environmental regulation, and (3) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, Cinergy has 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 a substantial portion of our expected 2005 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” 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 1,263 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 the “Market Risk Sensitive Instruments” section of “Item 7. MD&A”.
A joint operating agreement, effective in April 2002, allows Cinergy to jointly dispatch the regulated generating assets of PSI in conjunction with the deregulated generating assets of CG&E. Under this agreement, transfers of power between PSI and CG&E are generally priced at market rates.
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 Federal Energy Regulatory Commission (FERC) and the Kentucky Public Service Commission (KPSC). This five-year agreement is a negotiated fixed-rate contract with CG&E.
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The KPSC has conditionally approved a long-term electric supply plan for ULH&P that will replace the current contract with CG&E as previously discussed. Under this new plan, CG&E will transfer ownership of approximately 1,100 MW of electric generating capacity to ULH&P. The capacity is currently part of CG&E’s generating assets used to service ULH&P under a multi-year wholesale power supply contract as previously discussed. ULH&P is currently seeking approval of the transaction from the SEC, wherein the Ohio Consumers Counsel has intervened in opposition, and the FERC. The transfer, which will be paid for at net book value, will not affect current electric rates for ULH&P’s customers, as power will be provided under the same terms as under the current wholesale power contract with CG&E through December 31, 2006. Assuming receipt of regulatory approvals, we would anticipate the transfer to take place in the second quarter of 2005.
Cinergy is studying the feasibility of constructing a commercial integrated coal gasification combined cycle (IGCC) generating station to help meet increased demand over the next decade. PSI would own all or part of the facility and operate it. Cinergy will partner with Bechtel Corporation and General Electric Company to complete this study. 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 (CO2) upstream of the combustion process at a lower cost than conventional plants. If a decision is reached to move forward with constructing such a plant, PSI would seek approval from the Indiana Utility Regulatory Commission (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 tracking 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 NOX in the generation of electricity and maintains emission allowances to offset their emissions in order to comply with NOX and SO2 emission reduction requirements. In 2004, the market prices of SO2 allowances rose more than 200 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.
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 provides for reliability of regional bulk power supply.
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.
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
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transmission facilities. The Midwest ISO also will administer energy markets utilizing Locational Marginal Pricing (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. ECAR will maintain the responsibility for establishing the level of operating reserves for those utilities participating in the ECAR Agreement and the operation of the Automatic Reserve Sharing system upon the Midwest ISO’s implementation of its Energy Markets Tariff. See “Electric Industry” in “Item 7. MD&A” for further detail regarding the Midwest ISO energy markets.
Transmission and Distribution Cost Recovery
Transmission cost recovery mechanisms will be established under CG&E’s new RSP to, among other things, permit CG&E to recover Midwest ISO charges. CG&E also plans to file a distribution rate case to recover certain distribution costs with rates to become effective January 1, 2006 and has deferred certain costs in 2004 and will defer costs in 2005 pursuant to its RSP. See “Electric Industry” in “Item 7. MD&A” for further detail of CG&E’s RSP.
PSI has received IURC approval for the recovery of Midwest ISO costs and is currently seeking IURC approval that would further define the mechanisms for recovery of such costs.
13
Transmission System Interconnections
The following map illustrates the interconnections between our electric systems and other electric systems.
14
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. In 2004, firm supply purchase commitment agreements provided approximately 63 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 20-75 percent of winter heating season base load gas requirements and up to 50 percent of summer season base load requirements. 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, 2004, CG&E and ULH&P, combined, had hedged approximately 60 percent of their winter 2004/2005 base load requirements. See the “Gas Industry” section of “Item 7. MD&A” 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.
Regulated’s generation revenue is derived from the fulfillment of its native load requirements. 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:
|
| Operating Revenues |
| ||||||||||
Registrant |
| 2004 |
| 2003 |
| 2002 |
| ||||||
|
| Electric |
| Gas |
| Electric |
| Gas |
| Electric |
| Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy |
| 76 | % | 24 | % | 76 | % | 24 | % | 81 | % | 19 | % |
CG&E and subsidiaries |
| 45 |
| 55 |
| 46 |
| 54 |
| 56 |
| 44 |
|
PSI |
| 100 |
| — |
| 100 |
| — |
| 100 |
| — |
|
ULH&P |
| 65 |
| 35 |
| 67 |
| 33 |
| 74 |
| 26 |
|
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.
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
15
Technology and Infrastructure manages our investments in other energy infrastructure and telecommunication service providers.
In March 2004, Cinergy announced that it would begin offering broadband over power line (BPL) services in the Cincinnati, Ohio area. BPL utilizes the low and medium voltage distribution lines of Cinergy to transmit high speed data and other digital information to and from the internet via home electrical outlets and can be used for monitoring utility infrastructure. These services are being offered through joint ventures created by Ventures and Current Communications Group LLC, marketing to Cinergy service territory and municipal and co-op utilities throughout the United States. Ventures has invested approximately $18 million to date.
Commercial’s energy marketing and trading activities principally consist of Marketing & Trading’s natural gas marketing and trading operations and EMPLOYEESCG&E’s
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), power marketing and various international union organizations.
The following table indicates the number of employees by classification at December 31, 2003:
|
| Regulated |
| Non-Regulated |
| ||||||||||||
Classification |
| CG&E(4) |
| PSI |
| ULH&P |
| Total |
| Domestic(5)(6) |
| International |
| Total Non- |
| Cinergy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
IBEW(1) |
| 508 |
| 1,236 |
| 57 |
| 1,801 |
| 827 |
| — |
| 827 |
| 2,628 |
|
USWA(2) |
| 274 |
| — |
| 82 |
| 356 |
| 19 |
| — |
| 19 |
| 375 |
|
UWUA(3) |
| 375 |
| — |
| 59 |
| 434 |
| 347 |
| — |
| 347 |
| 781 |
|
Various Union Organizations |
| — |
| — |
| — |
| — |
| 133 |
| 224 |
| 357 |
| 357 |
|
Non-Bargaining |
| 193 |
| 347 |
| 20 |
| 560 |
| 2,829 |
| 163 |
| 2,992 |
| 3,552 |
|
|
| 1,350 |
| 1,583 |
| 218 |
| 3,151 |
| 4,155 |
| 387 |
| 4,542 |
| 7,693 |
|
(1) IBEW #1347 contract will expire ontrading operations. In April 1, 2006, IBEW #1393 contract will expire on May 1, 2005, and IBEW #352 contract will expire on February 5, 2005.
(2) USWA #12049 and #5541-06 contracts will expire on May 15, 2007.
(3) Contract will expire on March 31, 2005.
(4)2002, CG&E and subsidiaries excluding ULH&PPSI.
(5) Includes 2,406 Services’ employees, who provide services to both regulated executed a new joint operating agreement whereby new power marketing and non-regulated operations.
(6) Includes 1,267 Generation Services’ employees who provide services to certain affiliates and non-affiliated third parties. Effective January 1, 2004, Generation Services’ employees will be transferred to other affiliated corporations as follows: 524 totrading contracts since April 2002 are originated on behalf of CG&E; 21 to only. Historically, such contracts were executed on behalf of CG&E and PSI; 708 to Services; and 14 to other non-regulated corporations. jointly.
CURRENT TRENDSOur 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.
Two issues have been discussed prominently in regards to our industry during the past year. Transmission system reliability has been a significant focus, including participation in Regional Transmission Organizations (RTOs). In addition, significant discussion has occurred regarding the ability to address environmental issues for coal-fired generating units via a multi-pollutant approach.
Transmission system reliability has attracted a great deal of attention since the August 2003 blackout. Federal legislation has been proposed requiring mandatory reliability standards developed by an independent reliability organization with enforcement authority given to Federal Energy Regulatory Commission (FERC). However, it is unclear at this point whether federal reliability legislation will be enacted in the near future. Also, the North American Reliability Council (NERC) and the FERC are moving ahead with their own initiatives to introduce more stringent reliability standards with a focus on mandatory compliance. In the past, compliance with NERC reliability standards and guidelines has largely been voluntary. It is clear that transmission owners and operators will be subjected to increasing pressure to improve reliability and will incur additional costs as a result.
10
RTOs oversee the operation of multiple transmission systems and allow for improved coordination of transmission flow and planning. They provide a single rate for transmission of power between any two points within the RTO footprint. There are RTOs at various levels of development around the country, with the Midwest Independent System Operator (Midwest ISO), of which we are a member, being the largest. The FERC is a strong proponent of transmission owners joining RTOs, but at this point is not requiring entities to do so, nor is it requiring entities in the same geographic area to necessarily join the same RTO. This is particularly a concern in the Midwest, where some companies have yet to join RTOs, and where proposed RTO boundaries between the Midwest ISO and its Eastern neighbor, PJM Interconnection (PJM) are intermixed. The FERC has ordered that the Midwest ISO and PJM work to eliminate potential operational issues created by the intermixed boundary, but at this point, concerns remain as to how these entities will work to achieve the FERC’s objective. In addition, the Midwest ISO has indicated its intent to create a financial market, similar to the market currently in place in PJM, before the end of 2004. The development of this market could significantly impact the way power is bought and sold within and outside the Midwest ISO. Among other things, it is intended to increase market transparency and assign a market price to use of congested transmission facilities. The Midwest ISO had originally proposed a plan for such a market via a filing with the FERC in July 2003, but it was subsequently withdrawn in October 2003 due to concerns expressed by the entities that would be affected by that proposal. The Midwest ISO is expected to revise its model and proceed with a new filing in the near future, but at this point it is not clear how this model would differ from what was originally proposed, nor how it might affect participants in the Midwest ISO market.
The power sector, particularly coal-fired generation, has long been subject to a complex set of air emission requirements, with often overlapping and unclear rules. Many in the industry have expressed a view that a comprehensive, multi-pollutant approach to addressing emissions is the most reasonable and cost effective way to achieve increased emission reduction goals across a broader group of pollutants. During 2003, President Bush’s “Clear Skies Initiative” (Clear Skies) was a multi-pollutant, legislative proposal designed to achieve this goal. At the same time, the Environmental Protection Agency (EPA) was, under court order, drafting proposed regulations controlling mercury emissions via maximum achievable control technology (Mercury MACT) that were published in December 2003 and will become effective December 15, 2004. Passage of Clear Skies in 2003 would have rendered EPA rulemaking on mercury unnecessary, since mercury controls were a part of the proposed legislation. Although several hearings were held, Congress did not vote on the legislation in 2003 and its future prospects are uncertain. As part of the Mercury MACT draft regulations published in December, alternate approaches were proposed for dealing with mercury. One alternative would include a cap and trade approach to mercury (similar to proposals in Clear Skies). The other would be a source specific reduction in emissions, without a cap and trade approach. The cap and trade approach would provide a longer compliance horizon and provide more flexible compliance options for coal-fired generators.
11
The different alternatives proposed under the draft mercury regulations would result in substantially different requirements for compliance, both in terms of cost and timelines.
We conduct operations through our subsidiaries and manage our businesses through the following three reportable segments:
• Commercial Business Unit (Commercial), formerly named the Energy Merchant Business Unit;
• Regulated Businesses Business Unit (Regulated Businesses); and
• Power Technology and Infrastructure Services Business Unit (Power Technology).
The following section describes the activities of our business units as of December 31, 2003.
See Note 15 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for financial information by business segment.
Commercial manages, operates and/or maintains our generation and theMarketing & Trading’s natural gas marketing and trading of energy commodities, primarilyoperations also extend to Canada where natural gas and electricity. The marketing and trading of energy commodities includes energy risk management activities, trading activities,services are provided to producers and customized energy solutions. industrial customers. Our Canadian operations also market and trade over-the-counter contracts.
See the “Market Risk Sensitive Instruments and Positions”Instruments” section of “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A” for information on risks associated with these activities. In addition, Commercial is also an on-site energy solutions and utility services provider.
Competition
Commercial 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.
Commercial, through Cinergy Solutions Holding Company, Inc., is an on-site energy solutions and utility services provider. We provide utility systems construction, operation and maintenance of utility facilities, energy efficiencies and conservation consulting services, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of useable energy from a single fuel source.
Commercial, through Cinergy Capital & Trading, Inc., owns a coal-based synthetic fuel production facility which converts coal feedstock into synthetic fuel for sale to a third party. As of December 31, 2004, Cinergy has produced and sold approximately 7.8 million tons of synthetic fuel at this facility. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with the Internal Revenue Code Section 29 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
9
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 Note 11(c)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
As of December 31, 2003,2004, we had ownership interests in (1) generation assets located in three countries capable of producing approximately 150 MW of electricity and 700 MW equivalents of steam; and (2) approximately 1,200 miles of gas and electric transmission and distribution systems through jointly-owned investments in two countries, 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.
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. Because rates are frozen during the market development period in Ohio, the majority of these revenues are under a fixed-price tariff. Under the Ohio customer choice program, CG&E’s retail customers may choose their electric supplier. The percentage of customers switching to other electric suppliers and the related volume by customer class was as follows:
|
|
|
|
|
| MW Hours For the |
| Switching |
| ||||
|
| MW at December 31 |
| Years Ended December 31 |
| Percentage at December 31(1) |
| ||||||
Revenue Class |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
| 75 |
| 92 |
| 334,224 |
| 283,477 |
| 4.07 | % | 5.17 | % |
Commercial |
| 339 |
| 374 |
| 1,722,822 |
| 1,654,061 |
| 19.17 | % | 21.55 | % |
Industrial |
| 226 |
| 295 |
| 1,376,210 |
| 1,591,345 |
| 17.89 | % | 23.60 | % |
Other Public Authorities |
| 89 |
| 91 |
| 284,214 |
| 265,039 |
| 19.09 | % | 19.95 | % |
Total |
| 729 |
| 852 |
| 3,717,470 |
| 3,793,922 |
|
|
|
|
|
(1) The residential switching percentage is based on annual energy consumption and the non-residential switching percentages are based on average monthly peak demand.
Customer switching reduces retail revenues by the generation component of rates and shopping incentives. CG&E still collects transmission and distribution revenues from the delivery of electricity to switched customers (see Regulated section for further information). During the market development period, the reduction in revenues due to customer switching is mitigated by wholesale power sales from the freed-up generation capacity. For further discussion on Ohio deregulation and the recently approved RSP see “Electric Industry” in “Item 7. MD&A”.
Commercial’s operating revenue is also derived by providing electricity at wholesale and trading electricity primarily in the midwest region of the United States. In addition, Commercial provides and trades natural gas primarily to wholesale 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.
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
10
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. Regulated operated approximately 48,000 circuit miles (the total length in miles of separate circuits) of electric lines to provide regulated transmission and distribution service to approximately 1.5 million customers as of December 31, 2004. Regulated operated approximately 9,226 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 500,000 customers as of December 31, 2004. 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 their responsibility; and
•Revenue Data and Customer Base — Describes the primary revenue generators for the various business operations of Regulated.
As of December 31, 2004, the total winter electric capabilitycapacity (including our portion of the total capacity for the jointly-owned plants) of our domesticRegulated’s generating plants was 13,331 megawatts (MW).7,055 MW. Approximately 7378 percent of this generation portfolio is coal-fired. See “Item 2. Properties” for a further discussion of the generating facilities. Included in these generating plants are plants that are operated by Commercial on behalf of Regulated Businesses. The results of operations of these generating plants operated by Commercial are managed by and therefore reported under Regulated Businesses.
Each year through CG&E and PSI, we purchasepurchases over 2515 million tons of coal to generate electricity, primarily from mines located in Indiana, West Virginia, Ohio, Kentucky, Pennsylvania, and Illinois. OurThe price of coal has increased dramatically in 2004 as compared to 2003. The primary driving forces behind the increase in coal prices are (1) increases in demand for electricity, (2) environmental regulation, and (3) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, Cinergy has a general practice is to procure a substantial portion of coal through fixed-price contracts of varying tenors.length. We hold fixed pricefixed-price contracts that will source a substantial portion of our expected 20042005 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” for further detail on PSI’s total commitment under fixed-price coal contracts.
12
We receive our coal supply primarily from mines located in Indiana, West Virginia, Ohio, Kentucky, Pennsylvania, and Illinois.
Cinergy has a fleet of natural gas-fired peaking plants that have a capacity of 3,0291,263 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 the “Market Risk Sensitive Instruments and Positions”Instruments” section of “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A”. For further information on these agreements with Cinergy Marketing and Trading, LP (Marketing & Trading), see Note 1(s) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
CommercialA joint operating agreement, effective in April 2002, allows Cinergy to jointly dispatch the regulated generating assets of PSI in conjunction with the deregulated generating assets of CG&E. Under this agreement, transfers of power between PSI and CG&E are generally priced at market rates.
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 Federal Energy Regulatory Commission (FERC) and the Kentucky Public Service Commission (KPSC). This five-year agreement is a negotiated fixed-rate contract with CG&E.
11
The KPSC has conditionally approved a long-term electric supply plan for ULH&P that will replace the current contract with CG&E as previously discussed. Under this new plan, CG&E will transfer ownership of approximately 1,100 MW of electric generating capacity to ULH&P. The capacity is currently part of CG&E’s generating assets used to service ULH&P under a multi-year wholesale power supply contract as previously discussed. ULH&P is currently seeking approval of the transaction from the SEC, wherein the Ohio Consumers Counsel has intervened in opposition, and the FERC. The transfer, which will be paid for at net book value, will not affect current electric rates for ULH&P’s customers, as power will be provided under the same terms as under the current wholesale power contract with CG&E through December 31, 2006. Assuming receipt of regulatory approvals, we would anticipate the transfer to take place in the second quarter of 2005.
Cinergy is studying the feasibility of constructing a commercial integrated coal gasification combined cycle (IGCC) generating station to help meet increased demand over the next decade. PSI would own all or part of the facility and operate it. Cinergy will partner with Bechtel Corporation and General Electric Company to complete this study. 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 (CO2) upstream of the combustion process at a lower cost than conventional plants. If a decision is reached to move forward with constructing such a plant, PSI would seek approval from the Indiana Utility Regulatory Commission (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, CG&E, 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 tracking recovery mechanism (commonly referred to as a fuel adjustment clause). In addition withto the continuing emphasis on environmental regulation Cinergy, CG&E, andfuel adjustment clause, PSI maintainutilizes a portfoliopurchased power tracking mechanism approved by the IURC for the recovery of sulfur dioxide (SO2) and nitrogen oxide (NOX)emission allowances. These allowances permit uscosts related to continuecertain specified purchases of power necessary to obtain and burn high sulfur coal in compliance with environmental regulations. Cinergy, CG&E, and PSI believe that they can obtainmeet native load peak demand requirements to the necessaryextent such costs are not recovered through the existing fuel adjustment clause.
Regulated emits SO2 and NOX in the generation of electricity and maintains emission allowances to continue this practice.offset their emissions in order to comply with NOX and SO2 emission reduction requirements. In 2004, the market prices of SO2 allowances rose more than 200 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.
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 provides for reliability of regional bulk power supply.
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.
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
12
transmission facilities. The Midwest ISO also will administer energy markets utilizing Locational Marginal Pricing (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. ECAR will maintain the responsibility for establishing the level of operating reserves for those utilities participating in the ECAR Agreement and the operation of the Automatic Reserve Sharing system upon the Midwest ISO’s implementation of its Energy Markets Tariff. See “Electric Industry” in “Item 7. MD&A” for further detail regarding the Midwest ISO energy markets.
Transmission and Distribution Cost Recovery
Transmission cost recovery mechanisms will be established under CG&E’s new RSP to, among other things, permit CG&E to recover Midwest ISO charges. CG&E also plans to file a distribution rate case to recover certain distribution costs with rates to become effective January 1, 2006 and has deferred certain costs in 2004 and will defer costs in 2005 pursuant to its RSP. See “Electric Industry” in “Item 7. MD&A” for further detail of CG&E’s RSP.
PSI has received IURC approval for the recovery of Midwest ISO costs and is currently seeking IURC approval that would further define the mechanisms for recovery of such costs.
13
Transmission System Interconnections
The following map illustrates the interconnections between our electric systems and other electric systems.
14
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. In 2004, firm supply purchase commitment agreements provided approximately 63 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 20-75 percent of winter heating season base load gas requirements and up to 50 percent of summer season base load requirements. 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, 2004, CG&E and ULH&P, combined, had hedged approximately 60 percent of their winter 2004/2005 base load requirements. See the “Gas Industry” section of “Item 7. MD&A” 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.
Regulated’s generation revenue is derived from the fulfillment of its native load requirements. 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:
|
| Operating Revenues |
| ||||||||||
Registrant |
| 2004 |
| 2003 |
| 2002 |
| ||||||
|
| Electric |
| Gas |
| Electric |
| Gas |
| Electric |
| Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy |
| 76 | % | 24 | % | 76 | % | 24 | % | 81 | % | 19 | % |
CG&E and subsidiaries |
| 45 |
| 55 |
| 46 |
| 54 |
| 56 |
| 44 |
|
PSI |
| 100 |
| — |
| 100 |
| — |
| 100 |
| — |
|
ULH&P |
| 65 |
| 35 |
| 67 |
| 33 |
| 74 |
| 26 |
|
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.
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
15
Technology and Infrastructure manages our investments in other energy infrastructure and telecommunication service providers.
In March 2004, Cinergy announced that it would begin offering broadband over power line (BPL) services in the Cincinnati, Ohio area. BPL utilizes the low and medium voltage distribution lines of Cinergy to transmit high speed data and other digital information to and from the internet via home electrical outlets and can be used for monitoring utility infrastructure. These services are being offered through joint ventures created by Ventures and Current Communications Group LLC, marketing to Cinergy service territory and municipal and co-op utilities throughout the United States. Ventures has invested approximately $18 million to date.
TheCommercial’s energy marketing and trading activities of Commercial principally consistsconsist of Marketing & Trading’s natural gas marketing and trading operations and CG&E’s power marketing and trading operations, and Cinergy Global Trading Limited’s (Global Trading) natural gas and power trading operations in the United Kingdom.operations. In April 2002, CG&E and PSI executed a new joint operating agreement whereby new power marketing and trading contracts since April 2002 are originated on behalf of CG&E only. Historically, such contracts were executed on behalf of PSICG&E and CG&EPSI jointly.
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 Midwestmidwest region of the United States), natural gas, and other energy-related products.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. Global
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 for the purchase and sale of natural gas and electricity (both primarily in the United Kingdom). Global Trading also trades natural gas on the International Petroleum Exchange. contracts.
See the “Market Risk Sensitive Instruments and Positions”
13
Instruments” section of “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A” for information on risks associated with these activities.
Purchased PowerCompetition
At times, we
Commercial competes for wholesale contracts for the purchase and sale of electricity and natural gas. Commercial’s main competitors include public utilities, power to meet the energy needs of our wholesale customers and to meet the requirements of our retail native load customers (end-use customers within our operating companies’ franchise territory). Factors that could cause Cinergy to purchasenatural gas marketers and traders, and independent power for retail native load customers include generating plant outages, extreme weather conditions, summer reliability, and growth. 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, through its Cinergy Solutions Holding Company, Inc. subsidiary,, is an on-site energy solutions and utility services provider. We provide utility systems construction, operation and maintenance of utility systems,facilities, energy efficiencies and conservation consulting services, as well as cogeneration. Cogeneration is the simultaneous production of two or more forms of useable energy from a single fuel source.
Commercial, through Cinergy Capital & Trading, Inc., owns a coal-based synthetic fuel production facility which converts coal feedstock into synthetic fuel for sale to a third party. As of December 31, 2004, Cinergy has produced and sold approximately 7.8 million tons of synthetic fuel at this facility. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with the Internal Revenue Code Section 29 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
9
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 Note 11(c)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
As of December 31, 2003,2004, we had ownership interests in energy-related(1) generation assets located in five different countries.three countries capable of producing approximately 150 MW of electricity and 700 MW equivalents of steam; and (2) approximately 1,200 miles of gas and electric transmission and distribution systems through jointly-owned investments in two countries, 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.
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. Because rates are frozen during the market development period in Ohio, the majority of these revenues are under a fixed-price tariff. Under the Ohio customer choice program, CG&E’s retail customers may choose their electric supplier. The percentage of customers switching to other electric suppliers and the related volume by customer class was as follows:
|
|
|
|
|
| MW Hours For the |
| Switching |
| ||||
|
| MW at December 31 |
| Years Ended December 31 |
| Percentage at December 31(1) |
| ||||||
Revenue Class |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
| 75 |
| 92 |
| 334,224 |
| 283,477 |
| 4.07 | % | 5.17 | % |
Commercial |
| 339 |
| 374 |
| 1,722,822 |
| 1,654,061 |
| 19.17 | % | 21.55 | % |
Industrial |
| 226 |
| 295 |
| 1,376,210 |
| 1,591,345 |
| 17.89 | % | 23.60 | % |
Other Public Authorities |
| 89 |
| 91 |
| 284,214 |
| 265,039 |
| 19.09 | % | 19.95 | % |
Total |
| 729 |
| 852 |
| 3,717,470 |
| 3,793,922 |
|
|
|
|
|
(1) The residential switching percentage is based on annual energy consumption and the non-residential switching percentages are based on average monthly peak demand.
Customer switching reduces retail revenues by the generation component of rates and shopping incentives. CG&E still collects transmission and distribution revenues from the delivery of electricity to switched customers (see Regulated section for further information). During the market development period, the reduction in revenues due to customer switching is mitigated by wholesale power sales from the freed-up generation capacity. For further discussion on Ohio deregulation and the recently approved RSP see “Electric Industry” in “Item 7. MD&A”.
Commercial’s operating revenue is also derived primarily by providing electricity at wholesale and trading electricity primarily in the Midwestmidwest region of the United States (U.S.).States. In addition, Commercial provides and trades natural gas primarily to wholesale customers across the U.S.United States. The majority of Commercial’sthese 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.
Regulated Businesses 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 Businesses plans, constructs, operates, and maintains Cinergy’s transmission and distribution systems and delivers gas and electric energy to consumers. Regulated Businesses also earns revenues from wholesale customers primarily by these customers transmitting electric power
10
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. Regulated Businesses operated approximately 47,00048,000 circuit miles (the total length in miles of separate circuits) of electric lines to provide regulated transmission and distribution service to approximately 1.5 million customers as of December 31, 2003.
14
2004. Regulated Businesses operated approximately 13,4009,226 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 500,000 customers as of December 31, 2003.2004. 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:
Electric Operations•
Regulated Businesses (through our operating companies)Generation - - Fuel Supply and other non-affiliatedEmission 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 in a nine-state region are parties to the East Central Area Reliability Council Agreement (ECAR Agreement). The ECAR Agreement coordinatesand regional transmission organization (RTO) that coordinate the planning and operation of generation and transmission facilities which providesand 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 their responsibility; and
•Revenue Data and Customer Base — Describes the primary revenue generators for reliabilitythe various business operations of regional bulk power supply.
15
The following map illustrates the interconnections between our electric systems and other electric systems.Regulated.
As of December 31, 2004, the total winter electric capacity (including our portion of the total capacity for the jointly-owned plants) of Regulated’s generating plants was 7,055 MW. Approximately 78 percent of this generation portfolio is coal-fired. See “Item 2. Properties” for a further discussion of the generating facilities.
16
Each year Midwest ISOPSI
purchases over 15 million tons of coal to generate electricity, primarily from mines located in Indiana, Pennsylvania, and Illinois. The Midwest ISO was establishedprice of coal has increased dramatically in 2004 as compared to 2003. The primary driving forces behind the increase in coal prices are (1) increases in demand for electricity, (2) environmental regulation, and (3) decreases in the number of suppliers of coal from prior years. To help mitigate the price fluctuation of coal, Cinergy has a non-profit organizationgeneral practice to maintain functional control overprocure a substantial portion of coal through fixed-price contracts of varying length. We hold fixed-price contracts that will source a substantial portion of our expected 2005 coal requirements. We evaluate the combined transmission systemsappropriate amount of its members.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” 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 1,263 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 Midwest ISO,risk of purchasing natural gas see the “FERC and Midwest ISO”“Market Risk Sensitive Instruments” section of “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A”.
A joint operating agreement, effective in April 2002, allows Cinergy to jointly dispatch the regulated generating assets of PSI in conjunction with the deregulated generating assets of CG&E. Under this agreement, transfers of power between PSI and CG&E are generally priced at market rates.
WithAt times, Regulated purchases power to meet the implementationenergy needs of electric deregulation in Ohio, effective January 1, 2001,its customers. Factors that could cause Regulated Businesses continues, through a market development period, to acquirepurchase power for its electricity requirements from Commercial for those retail customers who do not switch suppliers.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 FERCFederal Energy Regulatory Commission (FERC) and the Kentucky Public Service Commission (KPSC). This five-year agreement is a negotiated fixed-rate contract with CG&E and replaces the previous cost of service based contract, which expired on December 31, 2001..
11
In December 2003, theThe KPSC has conditionally approved a long-term electric supply plan for ULH&P that will replace the current contract with CG&E listed above.as previously discussed. Under this new plan, CG&E will transfer ownership of approximately 1,100 MW of electric generating capacity to ULH&P. The capacity is currently part of CG&E’s generating assets used to service ULH&P under a multi-year wholesale power supply contract as described above.previously discussed. ULH&P will also seek regulatoryis currently seeking approval for aspects of thisthe transaction from the FERCSEC, wherein the Ohio Consumers Counsel has intervened in opposition, and SEC. Atthe FERC. The transfer, which will be paid for at net book value, will not affect current electric rates for ULH&P’s customers, as power will be provided under the same terms as under the current wholesale power contract with CG&E through December 31, 2006. Assuming receipt of regulatory approvals, we would anticipate the transfer to take place in the second quarter of 2005.
Cinergy is studying the feasibility of constructing a commercial integrated coal gasification combined cycle (IGCC) generating station to help meet increased demand over the next decade. PSI would own all or part of the facility and operate it. Cinergy will partner with Bechtel Corporation and General Electric Company to complete this time,study. 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 (CO2) upstream of the combustion process at a lower cost than conventional plants. If a decision is reached to move forward with constructing such a plant, ULH&PPSI is unablewould seek approval from the Indiana Utility Regulatory Commission (IURC) to predictbegin construction. If approved, we would anticipate the outcome of this matter.IURC’s subsequent approval to include the assets in PSI’s rate base.
For further detailsRegulated 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 electricity supply ofthe open market and will continue to investigate least-cost coal options to comply with new and existing environmental requirements. CG&ECinergy ,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.
ULH&PPSI , referrecovers retail and a portion of its wholesale fuel costs from customers on a dollar-for-dollar basis through a cost tracking recovery mechanism (commonly referred to as a fuel adjustment clause). In addition to the “Retail Market Developments” sectionfuel adjustment clause, PSI utilizes a purchased power tracking mechanism approved by the IURC for the recovery of “Item 7. Management’s Discussioncosts 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 AnalysisNOX in the generation of Financial Conditionelectricity and Resultsmaintains emission allowances to offset their emissions in order to comply with NOX and SO2 emission reduction requirements. In 2004, the market prices of Operations”.SO2 allowances rose more than 200 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.
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 provides for reliability of regional bulk power supply.
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.
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
12
transmission facilities. The Midwest ISO also will administer energy markets utilizing Locational Marginal Pricing (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. ECAR will maintain the responsibility for establishing the level of operating reserves for those utilities participating in the ECAR Agreement and the operation of the Automatic Reserve Sharing system upon the Midwest ISO’s implementation of its Energy Markets Tariff. See “Electric Industry” in “Item 7. MD&A” for further detail regarding the Midwest ISO energy markets.
Transmission and Distribution Cost Recovery
Transmission cost recovery mechanisms will be established under CG&E’s new RSP to, among other things, permit CG&E to recover Midwest ISO charges. CG&E also plans to file a distribution rate case to recover certain distribution costs with rates to become effective January 1, 2006 and has deferred certain costs in 2004 and will defer costs in 2005 pursuant to its RSP. See “Electric Industry” in “Item 7. MD&A” for further detail of CG&E’s RSP.
PSI has received IURC approval for the recovery of Midwest ISO costs and is currently seeking IURC approval that would further define the mechanisms for recovery of such costs.
13
Transmission System Interconnections
The following map illustrates the interconnections between our electric systems and other electric systems.
14
Regulated Businesses is responsible for the purchase and the subsequent delivery of natural gas to native load customers. Regulated Businesses’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 Businesses to assure reliable natural gas supply for its high priority (non-curtailable) firm customers during peak winter conditions and provides Regulated Businesses the flexibility to reduce its contract commitments if firm customers choose alternate gas suppliers under the
17
Regulated Businesses’Regulated’s customer choice/gas transportation programs. In 2003,2004, firm supply purchase commitment agreements provided approximately 8563 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 Businesses manages natural gas procurement-hedgingprocurement-price volatility mitigation programs for CG&E and ULH&P. These programs pre-arrange between 20-75 percent of winter heating season base load gas requirements and up to 50 percent of summer season base load requirements. CG&E and ULH&P use primarily fixed pricefixed-price forward 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 hedges under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activity. As of December 31, 2003,2004, CG&E and ULH&P, combined, had hedged approximately 6660 percent of their winter 2003/20042004/2005 base load requirements. See the “Gas Industry” section of “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A” 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.
Regulated Businesses expects the natural gas market will remain competitive in future years. While natural gas prices spiked at the beginning of 2003, prices moderated throughout the spring and summer but are still expected to remain higher than previous years into 2004. Price movement will be driven by the effects of weather conditions, availability of supply, and changes in demand and storage inventories. Currently, neither CG&E nor ULH&P profit from changes in the cost of natural gas since 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.
In November 2003, CG&E and ULH&P entered into a one-year asset management agreement with Marketing & Trading, a non-regulated affiliate of CG&E and ULH&P, to manage theirinterstate pipeline transportation and storage capacity and gas supply contracts. Under the terms of this agreement, Marketing & Trading is obligated to deliver natural gas to meet CG&E’s and ULH&P’s firm requirements. ULH&P received an order from the KPSC in October 2003, approving the affiliate asset management agreement with Marketing & Trading. No other regulatory approvals were required.
18
Regulated’s generation revenue is derived from the fulfillment of its native load requirements. The percent of retail operating revenues derived from full service electricity and gas sales and transportation from switched customers for each of the three years ended December 31 were as follows:
|
| Retail Operating Revenues |
|
| Operating Revenues |
| ||||||||||||||||||||
Registrant |
| 2003 |
| 2002 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
| ||||||||||||
|
| Electric % |
| Gas % |
| Electric % |
| Gas % |
| Electric % |
| Gas % |
|
| Electric |
| Gas |
| Electric |
| Gas |
| Electric |
| Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy |
| 81 |
| 19 |
| 87 |
| 13 |
| 82 |
| 18 |
|
| 76 | % | 24 | % | 76 | % | 24 | % | 81 | % | 19 | % |
CG&E and subsidiaries |
| 68 |
| 32 |
| 77 |
| 23 |
| 71 |
| 29 |
|
| 45 |
| 55 |
| 46 |
| 54 |
| 56 |
| 44 |
|
PSI |
| 100 |
| — |
| 100 |
| — |
| 100 |
| — |
|
| 100 |
| — |
| 100 |
| — |
| 100 |
| — |
|
ULH&P |
| 67 |
| 33 |
| 73 |
| 27 |
| 68 |
| 32 |
|
| 65 |
| 35 |
| 67 |
| 33 |
| 74 |
| 26 |
|
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 any of our operating companies.
Under the Ohio customer choice program, CG&E’s retail customers may choose their electric supplier. As of December 31, 2003 and 2002, the percentage of customers switching to other electric suppliers and the related volume by customer class was as follows:
|
| MW |
| Annual |
| Switching |
| ||||||
Revenue Class |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
| 92 |
| 68 |
| 283,477 |
| 98,528 |
| 5.17 | % | 3.84 | % |
Commercial |
| 374 |
| 347 |
| 1,654,061 |
| 1,235,077 |
| 21.55 | % | 21.54 | % |
Industrial |
| 295 |
| 293 |
| 1,591,345 |
| 1,053,677 |
| 23.60 | % | 24.60 | % |
Other Public Authorities |
| 91 |
| 84 |
| 265,039 |
| 204,855 |
| 19.95 | % | 21.51 | % |
Total |
| 852 |
| 792 |
| 3,793,922 |
| 2,592,137 |
|
|
|
|
|
(1) The residential switching percentage is based on annual energy consumption and the non-residential switching percentages are based on average monthly peak demand.
Customer switching reduces retail revenues by the generation component of rates and shopping incentives. CG&E still collects transmission and distribution revenues from the delivery of electricity to switched customers. During the market development period, the reduction in revenues due to customer switching is mitigated by wholesale power sales from the freed-up
19
generation capacity and recoveries of lost revenues and shopping incentives through the Regulatory Transition Charge (RTC). The RTC is a mechanism through which CG&E recovers its previous generation related regulatory assets and other transition costs. For further discussion on Ohio deregulation see “Ohio” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”.Regulated.
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
15
Technology and Infrastructure manages our investments in other energy infrastructure and telecommunication service providers.
In March 2004, Cinergy announced that it would begin offering broadband over power line (BPL) services in the Cincinnati, Ohio area. BPL utilizes the low and medium voltage distribution lines of Cinergy to transmit high speed data and other digital information to and from the internet via home electrical outlets and can be used for monitoring utility infrastructure. These services are being offered through joint ventures created by Ventures and Current Communications Group LLC, marketing to Cinergy service territory and municipal and co-op utilities throughout the United States. Ventures has invested approximately $18 million to date.
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, 2005:
Classification |
| CG&E(4) |
| PSI |
| ULH&P |
| Cinergy(5) |
|
|
|
|
|
|
|
|
|
|
|
IBEW(1) |
| 1,018 |
| 1,218 |
| 60 |
| 2,546 |
|
USWA(2) |
| 280 |
| — |
| 79 |
| 398 |
|
UWUA(3) |
| 387 |
| — |
| 58 |
| 768 |
|
Various Union Organizations |
| — |
| — |
| — |
| 355 |
|
Non-Bargaining |
| 198 |
| 354 |
| 19 |
| 3,775 |
|
|
| 1,883 |
| 1,572 |
| 216 |
| 7,842 |
|
(1) IBEW #1347 contract will expire on April 1, 2006, IBEW #1393 contract will expire on May 1, 2005, and IBEW #352 contract expired on February 5, 2005 and was replaced with a new contract set to expire on February 5, 2008.
(2) USWA #12049 and #5541-06 contracts will expire on May 15, 2007.
(3) Contract will expire on March 31, 2005.
(4) CG&E and subsidiaries excluding ULH&P.
(5) Includes 3,154 Services’ employees who provide services to our operating utilities and other non-regulated companies.
Cinergy is currently affected by several different issues which involve compliance with federal and state regulations regarding the protection of the environment.environment including, but not limited to, reductions in mercury, NOX, and SO2 emissions. Cinergy is able to recover certain costs of this environmental compliance equipment through various trackers set up with Cinergy’s respective state regulatory agencies. See Note 11 of the “Notes to Financial Statements”“Environmental Issues” section in “Item 8. Financial Statements and Supplementary Data”7. MD&A” for a discussion of these environmental issues and the estimated capital expenditures.
See the information appearing under the same caption in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A” for the following discussions:
• Retail MarketRegulatory Outlook and Significant Rate Developments;
• FERC and Midwest ISO;
• Significant Rate Developments;Gas Industry; and
• Gas Industry; and
•Other Matters.
2016
PROPERTIES
OurCommercial’s domestic power generating stations’ total winter electric capabilities,capacity, reflected in MW,megawatts (MW), as of December 31, 2003,2004, are shown in the table that follows. OurCommercial’s electric generating plants which are operated by Commercial, areprimarily located in Ohio Kentucky, and IndianaKentucky and are wholly-owned or jointly-owned facilities.
Subsidiary(1) |
| Stations |
| Coal |
| Natural |
| Oil |
| Hydro |
| Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CG&E |
| 9 |
| 4,186 |
| 736 |
| 324 |
| — |
| 5,246 |
|
PSI(2) |
| 11 |
| 5,488 |
| 1,263 |
| 259 |
| 45 |
| 7,055 |
|
Investments(3) |
| 2 |
| — |
| 1,030 |
| — |
| — |
| 1,030 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
| 22 |
| 9,674 |
| 3,029 |
| 583 |
| 45 |
| 13,331 |
|
|
|
|
|
|
| Natural |
|
|
|
|
|
|
|
|
| Coal |
| Gas |
| Oil |
| Total |
|
Commercial(1) |
| Stations |
| MW |
| MW |
| MW |
| MW |
|
|
|
|
|
|
|
|
|
|
|
|
|
The Cincinnati Gas & Electric Company (CG&E) |
| 9 |
| 4,186 |
| 736 |
| 324 |
| 5,246 |
|
Cinergy Investments, Inc. (Investments)(2) |
| 2 |
| — |
| 1,030 |
| — |
| 1,030 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
| 11 |
| 4,186 |
| 1,766 |
| 324 |
| 6,276 |
|
|
| |
|
| |
| (1) This table includes only our portion of the total capacity for the jointly-owned plants. (2) Represents natural gas peaking plants located in Tennessee and Mississippi, owned by Investments, that sell electricity on the wholesale market. |
During 2003,2004, Commercial’s electric generating plants, including those that we own but do not operate, performed reliably, as evidenced by our annual capacity factor of 7168 percent and a utilization factor of 8483 percent (excluding natural gas and fuel oil peaking stations) and an equivalent availability factor of 8684 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.
As17
Below is a geographical map showing the locations of December 31, 2003, we had ownership interestsCommercial’s generation plants.
Legend |
| ||||||
Number |
| Generation Plant |
| Fuel Type |
| MW Capacity |
|
|
|
|
|
|
|
|
|
1 |
| Dick’s Creek |
| Gas |
| 172 |
|
2 |
| Woodsdale |
| Gas |
| 564 |
|
3 |
| Miami Fort |
| Coal/Oil |
| 962 |
|
4 |
| East Bend |
| Coal |
| 414 |
|
5 |
| Beckjord |
| Coal/Oil |
| 1,107 |
|
6 |
| Wm. Zimmer |
| Coal |
| 604 |
|
7 |
| J.M. Stuart |
| Coal |
| 913 |
|
8 |
| Killen |
| Coal |
| 198 |
|
9 |
| Conesville |
| Coal |
| 312 |
|
10 |
| Brownsville |
| Gas |
| 480 |
|
|
| Caledonia(1) |
| Gas |
| 550 |
|
|
|
|
| Total |
| 6,276 |
|
(1) Commercial’s generation plant not included in five countries including generation assetsthe map is located in three countries and approximately 1,200 miles of gas and electric transmission and distribution systems through jointly-owned investments in two countries. We serve approximately 8,500 transmission and distribution customers.Caledonia, Mississippi.
As of December 31, 2003, 2004, CinergyCinergy had ownership interests in and/or operated 1927 domestic cogeneration facilities capable of producing 6575,357 MW of electricity, 3,5214,303 MW equivalents of steam and 325236 MW equivalents of chilled water. Cogeneration is the simultaneous production of two or more forms of useable energy from a single fuel source. During 2004, Cinergy212005, Cinergyanticipates completion of an expansion at one of our existing cogeneration facilities, which is expected to provide an additional
70570 MW equivalents of electric capacity.
In the third quartersteam and 42 MW equivalents of 2002, chilled water.
18
Cinergy Capital & Trading, Inc. completed an acquisition ofowns a coal-based synthetic fuel production facility, which converts coal into synthetic fuel for sale to a third party. The synthetic fuel replaces coalSee “Synthetic Fuel Production” in the generation of electricity. See the “Results of Operations - Future” section of “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A” for additional information regarding this business initiative.
As of December 31, 2004, we had ownership interests in (1) generation assets located in three countries capable of producing approximately 150 MW of electricity and 700 MW equivalents of steam; and (2) approximately 1,200 miles of gas and electric transmission and distribution systems through jointly-owned investments in two countries, 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.
Regulated’s domestic power generating stations’ total winter electric capacity, reflected in MW, as of December 31, 2004, are shown in the table that follows. The electric generating plants are located in Indiana and Ohio and are wholly-owned or jointly-owned facilities.
|
|
|
|
|
| Natural |
|
|
|
|
|
|
|
|
|
|
| Coal |
| Gas |
| Oil |
| Hydro |
| Total |
|
Regulated(1) |
| Stations |
| MW |
| MW |
| MW |
| MW |
| MW |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PSI |
| 11 |
| 5,488 |
| 1,263 |
| 259 |
| 45 |
| 7,055 |
|
(1) This table includes only our portion of the total capacity for the jointly-owned plants.
During 2004, Regulated’s electric generating plants, including those that we own but do not operate, performed reliably, as evidenced by our annual capacity factor of 74 percent and a utilization factor of 85 percent (excluding natural gas and fuel oil peaking stations) and an equivalent availability factor of 89 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.
19
Below is a geographical map showing the locations of Regulated’s generation plants.
Legend |
| ||||||
Number |
| Generation Plant |
| Fuel Type |
| MW Capacity |
|
|
|
|
|
|
|
|
|
1 |
| Cayuga |
| Coal/Gas/Oil |
| 1,135 |
|
2 |
| Wabash River |
| Coal/Oil |
| 966 |
|
3 |
| Edwardsport |
| Coal/Oil |
| 160 |
|
4 |
| Gibson |
| Coal |
| 2,844 |
|
5 |
| Miami Wabash |
| Oil |
| 104 |
|
6 |
| Noblesville |
| Gas |
| 310 |
|
7 |
| Henry County |
| Gas |
| 129 |
|
8 |
| Connersville |
| Oil |
| 98 |
|
9 |
| Gallagher |
| Coal |
| 560 |
|
10 |
| Markland |
| Hydro |
| 45 |
|
11 |
| Madison |
| Gas |
| 704 |
|
|
|
|
| Total |
| 7,055 |
|
20
Relevant information for our utility operating companies’ electric transmission and distribution systems located in Ohio, Kentucky, and Indiana is as follows:
|
| Electric |
| Electric |
| Substation |
| |||||||
|
| Transmission |
| Distribution |
| Combined |
| |||||||
Registrant |
| Electric |
| Electric |
| Substation |
|
| Systems |
| Systems |
| Capacity |
|
|
| (circuit miles) |
| (circuit miles) |
| (kilovolt-amperes)(1) |
|
| (circuit miles) |
| (circuit miles) |
| (kilovolt-amperes)(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CG&E and subsidiaries |
|
|
|
|
|
|
| |||||||
CG&E |
| 1,662 |
| 15,983 |
| 21,132,488 |
|
| 1,561 |
| 16,743 |
| 21,121,288 |
|
ULH&P |
| 106 |
| 2,773 |
| 1,384,198 |
| |||||||
The Union Light, Heat and Power Company (ULH&P) |
| 106 |
| 2,883 |
| 1,419,878 |
| |||||||
Other subsidiaries |
| 40 |
| — |
| — |
|
| 40 |
| — |
| — |
|
CG&E and subsidiaries |
| 1,808 |
| 18,756 |
| 22,516,686 |
| |||||||
PSI |
| 5,352 |
| 21,058 |
| 30,471,584 |
| |||||||
Total CG&E and subsidiaries |
| 1,707 |
| 19,626 |
| 22,541,166 |
| |||||||
PSI Energy, Inc. (PSI) |
| 5,354 |
| 20,917 |
| 30,569,289 |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
| 7,160 |
| 39,814 |
| 52,988,270 |
|
| 7,061 |
| 40,543 |
| 53,110,455 |
|
(1) Kilovolt-amperes (1,000 volt-amperes) are a broad measure of our substation transformer capacity.
At the end of 2003,2004, our utility operating companies’ electric systems were interconnected with 1514 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 design or 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.
22
In August 2003, we experienced peak loads of 11,077 MW, 5,104 MW, and 5,990 MW for Cinergy, CG&E, and PSI, respectively. At times, we purchase power to meet the energy needs of our wholesale customers and to meet the requirements of our retail native load customers. Factors that could cause Cinergy to purchase power for retail native load customers include outages, extreme weather conditions, growth, economics, and other factors associated with supplying full requirements electricity. We believe we can obtain enough purchased power to meet future needs.
In February 2002, the The Midwest ISO assumedIndependent Transmission System Operator, Inc. (Midwest ISO) holds functional control of Regulated Businesses’Regulated’s transmission systems. Although the Midwest ISO continues to develop, modify, and change its various operating practices, it does handle substantially all transmission tariff administration.
In February 2003, the FERC issued an order approving PSI’s acquisition of the Butler County, Ohio and the Henry County, Indiana peaking plants under the terms and conditions contained in a settlement agreement with PSI, the Indiana Utility Regulatory Commission Testimonial Staff and the Indiana Office of the Utility Consumer Counselor. This action was the final regulatory approval needed for the transfer, which occurred in February 2003. Subsequently, in April 2003, the FERC issued a tolling order allowing additional time to consider a request for rehearing filed in response to the February 2003 FERC order. At this time, we cannot predict the outcome of this matter. See “Transfer of Generating Assets to PSI” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information.
In July 2003, ULH&P filed an application with the KPSC requesting a certificate of public convenience and necessity to acquire CG&E’s 68.9 percent ownership interests in the East Bend Generating Station, located in Boone County, Kentucky, the Woodsdale Generating Station, located in Butler County, Ohio, and one generating unit at the four-unit Miami Fort Generating Station (Miami Fort Station) located in Hamilton County, Ohio. In December 2003, the KPSC conditionally approved the order. The transfer will be made at net book value. ULH&P will also seek regulatory approval for aspects of this transaction from the FERC and the SEC. At this time, ULH&P is unable to predict the outcome of this matter. See the “Electricity Supply” section of “Item 1. Business” for further information.
As of December 31, 2003,2004, the natural gas transmission and distribution systems of Cinergy and CG&E and its subsidiaries had approximately 13,4009,226 miles of mains and service lines located in southwestern Ohio southeastern Indiana, 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 belongs to CG&E, including 7.5 million gallons belonging to ULH&P). As of December 31, 2003,2004, Cinergy had 16.116.6 million gallons of liquid propane in storage (of which 15.014.4 million gallons belongs to CG&E, including 5.75.8 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.
23
In November 2003,July 2004, we experienced peak loads for the year of 10,911 MW, 4,998 MW,and 6,000 MW for Cinergy, CG&E, and ULH&PPSI, respectively. Cinergy entered into a one-year asset management agreement with Marketing & Trading, a non-regulated affiliate ofand CG&E set record peak loads of 11,305 MW and 5,311 MW in August 2002, respectively, while ULH&PPSI , to manage theirinterstate pipeline transportation and storage capacity and natural gas supply contracts. Under the termsset a record peak load of this agreement, Marketing & Trading is obligated to deliver natural gas to meet CG&E’s and ULH&P’s firm requirements. ULH&P received an order from the KPSC6,088 MW in October 2003, approving the affiliate asset management agreement with Marketing & Trading. No other regulatory approvals were required.July 2002.
2421
LEGAL PROCEEDINGS
In November 1999, and through subsequent amendments, the United States brought a lawsuit in the United States Federal District Court (District Court) for the Southern District of Indiana (District Court) against Cinergy, CG&E, and PSI alleging various violations of the CAA. Specifically, the lawsuit alleges that the Companywe violated the CAA by not obtaining Prevention of Significant Deterioration (PSD), Non-Attainment New Source Review (NSR), and Ohio and Indiana State Implementation PlanPlans (SIP) permits for various projects at our owned orand co-owned generating stations. Additionally, the suit claims that the Company haswe violated an Administrative Consent Order entered into in 1998 between the EPAEnvironmental Protection Agency (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 Generating Station (Beckjord Station). The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s Beckjord Station and Miami Fort Station, and PSI’s Cayuga Generating Station, Gallagher Generating Station, Wabash River Generating Station, and Gibson Generating Station (Gibson Station), 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. The case is currently in discovery, and the courtDistrict Court has set the case for trial by jury commencing in August 2005.February 2006.
In March 2000, the United States also filed in the District Court 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 the Columbus Southern Power Company (CSP) and jointly-owned by CSP, theThe 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 District Court in that case ruled that the Government and the intervening plaintiff environmental groups couldcannot seek injunctive reliefmonetary damages for alleged violations that occurred more than five years before the filing of the complaint only. Thus, if the plaintiffs prevail in their claims, any calculation for penalties will not start on the date of the alleged violations, unless those alleged violations occurred afterprior to November 3, 1994, but CSP would be forced1994; however, they are entitled to install the controls required under the CAA.seek injunctive relief for such alleged violations. Neither party appealed that decision.
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 generating station operated by DP&L and jointly-owned by 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 Cinergy, DP&L and CSP for alleged violations of the CAA at this same generating station.
In December 2000, Cinergy, CG&E, and PSI reached an agreement in principle with the plaintiffs regarding the above matters. The complete resolution of these issues was contingent upon establishing a final agreement with the EPA and other parties. Although we have continued to negotiate with the plaintiffs to achieve a final agreement, the plaintiffs have insisted on commitments from us which go beyond those contained in the agreement in principle. At this
25
time we believe it is unlikely that a final settlement agreement will be reached on these terms. If a final settlement agreement is not reached, we intend to defend against the allegations, discussed above, vigorously in court. In such an event it is not possibleWe 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.
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. 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. Cinergy intends to defend these lawsuits vigorously in court and filed motions to dismiss with the other defendants in September 2004. We are not able to predict whether resolution of these matters would have a material effect on our financial position or results of operations.
22
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 over an acid aerosol mist haze (plume) sometimes occurring in areas near the plant. Portions of the plume from those units’ stacks appeared to break apart and descend to ground level at certain times under certain weather conditions. As a result, and, working with the City of Mt. Carmel, Illinois, Illinois EPA, Indiana Department of Environmental Management (IDEM), EPA, and the State of Illinois, we developed a protocol regarding the use of the SCRs while we explored alternatives to address this issue. After the protocol was finalized, the Illinois Attorney General brought an action in Wabash County Circuit Court against PSI seeking a preliminary injunction to enforce the protocol. In August 2004, the court granted that preliminary injunction. PSI is appealing that decision to the Fifth District Appellate Court, but we cannot predict the ultimate outcome of that appeal or of the underlying action by the Illinois Attorney General.
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.
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, Ohio laws against nuisance and common law nuisance. CG&E filed a motion to dismiss the lawsuit on primarily procedural grounds and we intend to defend against these claims vigorously. At this time, we cannot predict whether the outcome of this matter will have a material impact on our financial position or result of operations.
Prior to the 1950s, gas was produced at MGP sites through a process that involved the heating of coal and/or oil. The gas produced from this process was sold for residential, commercial, and industrial uses.
Coal tar residues, related hydrocarbons, and various metals have been found at former MGP sites in Indiana, including 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).
In a combination of lawsuits (filed in November 1999 in Hendricks County in the state of Indiana) and NOVs (brought by the U.S. EPA from November 1999 to January 2000), the 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. The Indiana Department of Environmental Management (IDEM)IDEM oversees investigation and cleanup of all of these sites. 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 sites for which PSI has primary responsibility.sites.
PSI notified its insurance carriers of the claims related to MGP sites raised by IDEM and costs included in the Site Participation and Cost Sharing Agreements. 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 sitessites; or (2) pay PSI’s cost of defense. The trial court issued a variety of rulings with respect to the claims and defenses in the litigation. PSI appealed certain adverse rulings to the Indiana Court of Appeals and the appellate court has remanded the case to the trial court. A new trial date has yetPSI settled its claims with all but one of the insurance carriers in January 2005 prior to be scheduled.commencement of the trial. With respect to the lone insurance carrier, a jury returned a verdict against PSI in February 2005. PSI is considering whether to appeal this decision. At the present time, PSIcannot predict the outcome of this litigation includingif it were to appeal the outcome of the appeals.decision.
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 ifwhether 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.
26
CG&E has and ULH&P have performed site assessments on itscertain 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.
In August 2003, Cornerstone Propane Partners L.P. filed suit against Cinergy and 38 other companies in At the Southern District of New York. The suit is 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. The plaintiffs are seeking unspecified damages. Two similar lawsuits have subsequently been filed, one naming Cinergy and one not. These three lawsuits have been consolidated for pretrial purposes as In Re: Natural Gas Commodity Litigation. Plaintiffs filed a consolidated class action complaint in January 2004. We believe this action is without merit and intend to defend this lawsuit vigorously; however, we cannot predict the outcome of this matter at this time.present time,
23
CG&E and ULH&P cannot predict whether investigation and/or remediation will be required in the future at any of these sites.
Ronald A. Katz Technology Licensing, L.P. (RAKTL) has offered us a license to a portfolio of patents claiming that the patents may be infringed by certain productsCG&E and services utilized by us. The patents purportedly relate to various aspects of telephone call processing in Cinergy PSIcall centers. As of this date, no legal proceedings have been institutednamed as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 100 pending lawsuits. In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work at the 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. A majority of the lawsuits to date have been brought against us,PSI. 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 in the amount of approximately $500,000 on a negligence claim and a verdict for PSI on punitive damages. PSI received an adverse ruling in its initial appeal of the negligence claim verdict, but if the RAKTL patentsIndiana Supreme Court accepted the transfer of the case and heard oral argument in June 2004. In addition, PSI has settled a number of other lawsuits for amounts, which neither individually nor in the aggregate, are valid, enforceablematerial to PSI’s financial position or results of operations.
At this time, CG&E and applyPSI are not able to our business, we could be required to seek a license from RAKTLpredict the ultimate outcome of these lawsuits or to discontinue certain activities. We are currently considering this matter, but lack sufficient information to assess the potential outcome at this time.impact on CG&E’s and PSI’s financial position or results of operations.
We currently, and from time to time, are involved in lawsuits, claims, and complaints incidental to the conduct of our business. In the opinion of management, no such proceeding is likely to have a material adverse effect on us.
See Note 11 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information regarding our commitments and contingencies.
2724
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders of Cinergy, CG&E,The Cincinnati Gas & Electric Company, or PSIPSIEnergy, Inc. during the fourth quarter of 2003.2004.
2825
MARKET FOR REGISTRANT’S COMMON EQUITY, AND 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:
|
| High |
| Low |
| |||||||||
2004 |
|
|
|
|
| |||||||||
First Quarter |
| $ | 41.10 |
| $ | 37.17 |
| |||||||
Second Quarter |
| 41.04 |
| 34.92 |
| |||||||||
Third Quarter |
| 40.75 |
| 36.95 |
| |||||||||
Fourth Quarter |
| 42.63 |
| 38.08 |
| |||||||||
|
| High |
| Low |
|
|
|
|
|
| ||||
2003 |
|
|
|
|
|
|
|
|
|
| ||||
First Quarter |
| $ | 35.87 |
| $ | 29.77 |
|
| $ | 35.87 |
| $ | 29.77 |
|
Second Quarter |
| 38.75 |
| 33.25 |
|
| 38.75 |
| 33.25 |
| ||||
Third Quarter |
| 36.99 |
| 33.14 |
|
| 36.99 |
| 33.14 |
| ||||
Fourth Quarter |
| 38.86 |
| 35.19 |
|
| 38.86 |
| 35.19 |
| ||||
|
|
|
|
|
| |||||||||
2002 |
|
|
|
|
| |||||||||
First Quarter |
| $ | 35.75 |
| $ | 31.00 |
| |||||||
Second Quarter |
| 37.19 |
| 34.25 |
| |||||||||
Third Quarter |
| 36.21 |
| 25.40 |
| |||||||||
Fourth Quarter |
| 34.19 |
| 28.25 |
| |||||||||
Cinergy Corp. holds all outstanding common stock of The Cincinnati Gas & Electric Company CG&E(CG&E) and PSI Energy, Inc. PSI(PSI) common stock,, and CG&E holds all of the common stock of The Union Light, Heat and Power Company ULH&P(ULH&P) common stock.. Therefore, no public trading market exists for the common stock of CG&E, PSI, and ULH&P.
As of January 31, 2004,2005, Cinergy Corp. had 52,50645,628 shareholders of record.
Cinergy Corp. declared dividends on its common stock of $.46$.47 and $.45$.46 per share for each quarter of 20032004 and 2002,2003, 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:
Registrant |
| Quarter |
| 2003 |
| 2002 |
|
| Quarter |
| 2004 |
| 2003 |
| ||||
|
|
|
| (in thousands) |
|
|
|
| (in thousands) |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
CG&E |
| First |
| $ | 47,082 |
| $ | 44,787 |
|
| First |
| $ | 54,926 |
| $ | 47,082 |
|
|
| Second |
| 63,100 |
| 46,866 |
|
| Second |
| 55,612 |
| 63,100 |
| ||||
|
| Third |
| 56,473 |
| 47,059 |
|
| Third |
| 57,971 |
| 56,473 |
| ||||
|
| Fourth |
| 61,208 |
| 47,197 |
|
| Fourth |
| 67,249 |
| 61,208 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
PSI |
| First |
| $ | 30,503 |
| $ | 26,944 |
|
| First |
| $ | 28,957 |
| $ | 30,503 |
|
|
| Second |
| 17,837 |
| 28,194 |
|
| Second |
| 28,913 |
| 17,837 |
| ||||
|
| Third |
| 24,984 |
| 28,310 |
|
| Third |
| 26,839 |
| 24,984 |
| ||||
|
| Fourth |
| 20,626 |
| 28,394 |
|
| Fourth |
| 17,879 |
| 20,626 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
ULH&P |
| First |
| $ | — |
| $ | — |
|
| First |
| $ | — |
| $ | — |
|
|
| Second |
| 6,305 |
| 2,675 |
|
| Second |
| — |
| 6,305 |
| ||||
|
| Third |
| — |
| — |
|
| Third |
| — |
| — |
| ||||
|
| Fourth |
| — |
| 6,995 |
|
| Fourth |
| 14,600 |
| — |
| ||||
On January 15, 2004,14, 2005, the Board of Directors of Cinergy Corp. declared dividends on its common stock of $.47$.48 per share, payable February 15, 2004,2005, to shareholders of record at the close of business on January 30, 2004.February 1, 2005.
See Note 2(b)“Dividend Restrictions” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a brief description of the “Notes to Financial Statements” in “Item 8. Financial Statements andregistrants’ common stock dividend restrictions.
2926
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.
Period |
| (a) Total Number of Shares (or Units) Purchased |
| (b) Average Price Paid per Share (or Unit) |
| (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs |
| (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs |
| |
|
|
|
|
|
|
|
|
|
| |
October 1 — October 31 |
| 4,580 |
| $ | 39.67 |
| N/A |
| N/A |
|
November 1 — November 30 |
| 2,288 |
| $ | 39.45 |
| N/A |
| N/A |
|
December 1 — December 31 |
| — |
| $ | — |
| N/A |
| N/A |
|
27
SELECTED FINANCIAL DATA
Supplementary Data” for a brief description of the registrants’ common stock dividend restrictions.
|
| 2003 |
| 2002 |
| 2001 |
| 2000 |
| 1999 |
|
| 2004 |
| 2003 |
| 2002 |
| 2001 |
| 2000 |
| ||||||||||
|
| (in millions, except per share amounts) |
| (in millions, except per share amounts) |
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Cinergy(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Operating revenues(2) |
| $ | 4,416 |
| $ | 4,059 |
| $ | 3,950 |
| $ | 3,752 |
| $ | 3,427 |
| ||||||||||||||||
Operating revenues |
| $ | 4,688 |
| $ | 4,416 |
| $ | 4,059 |
| $ | 3,950 |
| $ | 3,752 |
| ||||||||||||||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| 435 |
| 397 |
| 457 |
| 400 |
| 402 |
|
| 401 |
| 435 |
| 397 |
| 457 |
| 400 |
| ||||||||||
Discontinued operations, net of tax |
| 9 |
| (25 | ) | (15 | ) | (1 | ) | 2 |
|
| — |
| 9 |
| (25 | ) | (15 | ) | (1 | ) | ||||||||||
Cumulative effect of changes in accounting principles, net of tax |
| 26 |
| (11 | ) | — |
| — |
| — |
|
| — |
| 26 |
| (11 | ) | — |
| — |
| ||||||||||
Net income |
| 470 |
| 361 |
| 442 |
| 399 |
| 404 |
|
| 401 |
| 470 |
| 361 |
| 442 |
| 399 |
| ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Per Share Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Earnings per common share (EPS) |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Earnings per common share (EPS) - basic: |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| 2.46 |
| 2.37 |
| 2.87 |
| 2.52 |
| 2.53 |
|
| 2.22 |
| 2.46 |
| 2.37 |
| 2.87 |
| 2.52 |
| ||||||||||
Discontinued operations, net of tax |
| 0.05 |
| (0.15 | ) | (0.09 | ) | (0.01 | ) | 0.01 |
|
| — |
| 0.05 |
| (0.15 | ) | (0.09 | ) | (0.01 | ) | ||||||||||
Cumulative effect of changes in accounting principles, net of tax |
| 0.15 |
| (0.06 | ) | — |
| — |
| — |
|
| — |
| 0.15 |
| (0.06 | ) | — |
| — |
| ||||||||||
Net income |
| 2.66 |
| 2.16 |
| 2.78 |
| 2.51 |
| 2.54 |
|
| 2.22 |
| 2.66 |
| 2.16 |
| 2.78 |
| 2.51 |
| ||||||||||
EPS - assuming dilution |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
EPS - diluted: |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| 2.43 |
| 2.34 |
| 2.84 |
| 2.51 |
| 2.52 |
|
| 2.18 |
| 2.43 |
| 2.34 |
| 2.84 |
| 2.51 |
| ||||||||||
Discontinued operations, net of tax |
| 0.05 |
| (0.15 | ) | (0.09 | ) | (0.01 | ) | 0.01 |
|
| — |
| 0.05 |
| (0.15 | ) | (0.09 | ) | (0.01 | ) | ||||||||||
Cumulative effect of changes in accounting principles, net of tax |
| 0.15 |
| (0.06 | ) | — |
| — |
| — |
|
| — |
| 0.15 |
| (0.06 | ) | — |
| — |
| ||||||||||
Net income |
| 2.63 |
| 2.13 |
| 2.75 |
| 2.50 |
| 2.53 |
|
| 2.18 |
| 2.63 |
| 2.13 |
| 2.75 |
| 2.50 |
| ||||||||||
Dividends declared per share |
| 1.84 |
| 1.80 |
| 1.80 |
| 1.80 |
| 1.80 |
| |||||||||||||||||||||
Cash dividends declared per share |
| 1.88 |
| 1.84 |
| 1.80 |
| 1.80 |
| 1.80 |
| |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Balance Sheet Data (at end of period): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Total assets from continuing operations |
| 14,114 |
| 13,685 |
| 12,558 |
| 12,604 |
| 9,963 |
|
| 14,982 |
| 14,114 |
| 13,685 |
| 12,558 |
| 12,604 |
| ||||||||||
Total assets from discontinued operations |
| 5 |
| 147 |
| 234 |
| 197 |
| 88 |
|
| — |
| 5 |
| 147 |
| 234 |
| 197 |
| ||||||||||
|
| 14,119 |
| 13,832 |
| 12,792 |
| 12,801 |
| 10,051 |
|
| 14,982 |
| 14,119 |
| 13,832 |
| 12,792 |
| 12,801 |
| ||||||||||
Long-term debt (including amounts due in one year) |
| 4,971 |
| 4,188 |
| 3,656 |
| 2,868 |
| 2,998 |
| |||||||||||||||||||||
Long-term debt (including amounts due within one year) |
| 4,448 |
| 4,971 |
| 4,188 |
| 3,656 |
| 2,868 |
| |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
CG&E |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
The Cincinnati Gas & Electric Company (CG&E) |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Operating revenues |
| $ | 2,382 |
| $ | 2,137 |
| $ | 2,247 |
| $ | 2,101 |
| $ | 1,914 |
|
| $ | 2,511 |
| $ | 2,382 |
| $ | 2,137 |
| $ | 2,247 |
| $ | 2,101 |
|
Income before cumulative effect of changes in accounting principles |
| 300 |
| 264 |
| 327 |
| 267 |
| 234 |
|
| 257 |
| 300 |
| 264 |
| 327 |
| 267 |
| ||||||||||
Cumulative effect of changes in accounting principles, net of tax |
| 31 |
| — |
| — |
| — |
| — |
|
| — |
| 31 |
| — |
| — |
| — |
| ||||||||||
Net income |
| 331 |
| 264 |
| 327 |
| 267 |
| 234 |
|
| 257 |
| 331 |
| 264 |
| 327 |
| 267 |
| ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Balance Sheet Data (at end of period): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Total assets |
| 5,809 |
| 5,751 |
| 5,559 |
| 6,182 |
| 5,099 |
|
| 6,232 |
| 5,809 |
| 5,751 |
| 5,559 |
| 6,182 |
| ||||||||||
Long-term debt (including amounts due in one year) |
| 1,569 |
| 1,690 |
| 1,205 |
| 1,206 |
| 1,206 |
| |||||||||||||||||||||
Long-term debt (including amounts due within one year) |
| 1,594 |
| 1,569 |
| 1,690 |
| 1,205 |
| 1,206 |
| |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
PSI |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
PSI Energy, Inc. (PSI) |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Operating revenues(2) |
| $ | 1,603 |
| $ | 1,611 |
| $ | 1,574 |
| $ | 1,512 |
| $ | 1,449 |
| ||||||||||||||||
Operating revenues |
| $ | 1,754 |
| $ | 1,603 |
| $ | 1,611 |
| $ | 1,574 |
| $ | 1,512 |
| ||||||||||||||||
Income before cumulative effect of a change in accounting principle |
| 134 |
| 214 |
| 162 |
| 135 |
| 117 |
|
| 165 |
| 134 |
| 214 |
| 162 |
| 135 |
| ||||||||||
Cumulative effect of a change in accounting principle, net of tax |
| (1 | ) | — |
| — |
| — |
| — |
|
| — |
| (1 | ) | — |
| — |
| — |
| ||||||||||
Net income |
| 133 |
| 214 |
| 162 |
| 135 |
| 117 |
|
| 165 |
| 133 |
| 214 |
| 162 |
| 135 |
| ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Balance Sheet Data (at end of period): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Total assets |
| 5,140 |
| 4,539 |
| 4,864 |
| 4,906 |
| 4,087 |
|
| 5,450 |
| 5,140 |
| 4,539 |
| 4,864 |
| 4,906 |
| ||||||||||
Long-term debt (including amounts due in one year) |
| 1,720 |
| 1,372 |
| 1,348 |
| 1,113 |
| 1,243 |
| |||||||||||||||||||||
Long-term debt (including amounts due within one year) |
| 1,874 |
| 1,720 |
| 1,372 |
| 1,348 |
| 1,113 |
| |||||||||||||||||||||
(1) The results of Cinergy also include amounts related to non-registrants.
30
(2) Emerging Issues Task Force Issue 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities required that all gains and losses on energy trading derivatives be presented on a net basis beginning January 1, 2003. All periods presented have been reclassified for this change in accounting principle. This resulted in substantial reductions in reported Operating Revenues, Fuel and purchased and exchanged power expense, and Gas purchased expense. However, Operating Income and Net Income were not affected by this change. For further information see Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
(3) See Note 14 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further explanation.
(4)(3) 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 $(11) million (net of tax) as a result of an impairment charge for goodwill related to certain of our international assets.
(5)(4) 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.
(6)(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.
3128
MD&A - - LIQUIDITY AND CAPITAL RESOURCESEXECUTIVE SUMMARY
In this report, Cinergy (which includes Cinergy Corp. and all of ourits 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 discussed below are not necessarily indicative of the results to be expected in any future periods.period.
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 results of operations.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
• why revenues and expenses changed from period to period; and
•how the abovethese items affect our overall financial condition.
Net income for Cinergy for the years ended December 31, 2004, and 2003 was as follows:
|
| Cinergy |
| |||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 401 |
| $ | 470 |
| $ | (69 | ) | (15 | )% |
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, production maintenance, and the implementation of a continuous improvement initiative;
•Lower margins from the sale of electricity in the Commercial Business Unit (Commercial) primarily due to higher fuel and emission allowance costs;
•Impairment and disposal charges on certain investments primarily in the Power Technology and Infrastructure Services Business Unit (Power Technology and Infrastructure); and
•Net gains recognized in 2003 resulting from the implementation of certain accounting changes and the disposal of discontinued operations.
These decreases were partially offset by:
•A higher price received per megawatt hour (MWh) resulting from the Indiana Utility Regulatory Commission’s (IURC) approval of PSI’s base retail electric rate increase in May 2004;
•Growth in non-weather related demand for electricity;
•An increase in gross margins on power marketing, trading, and origination contracts; and
•A gain related to a Power Technology and Infrastructure investment.
For further information, see “2004 Results of Operations — Cinergy”.
29
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 two separate rulemakings, the Environmental Protection Agency (EPA) has proposed significant reductions in sulfur dioxide (SO2), nitrogen oxides (NOX) and mercury emissions from power plants, neither of which have been finalized. Additionally, multi-emissions reductions legislation could be passed in 2005 that may take the place of these proposed rulemakings. In 2004, Cinergy’s utility operating companies began an environmental construction program to reduce overall plant emissions that is estimated to cost approximately $1.8 billion over the next 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.
Ohio has enacted electric generation deregulation legislation. CG&E’s residential customers are in a market development period through 2005, during which prices are fixed, while non-residential customers are under a recently approved rate stabilization plan (RSP) that runs through December 31, 2008. Residential customers will be under the RSP beginning in 2006, also ending in 2008. At this time, it is difficult to predict how the regulatory environment will look after the rate stabilization period ends. To date, deregulation in Ohio has not progressed as originally anticipated and the Ohio General Assembly may consider re-regulation laws as early as 2005. However, the possibility of deregulation or a hybrid of both deregulation and regulation still exists. These regulatory uncertainties are particularly challenging as we attempt to address short-term and long-term generation capacity needs as well as environmental requirements previously discussed. See “Regulatory Outlook and Significant Rate Developments” in “Future Expectations/Trends” for further discussion of these risks and uncertainties.
The projected implementation date is April 1, 2005 for the Midwest ISO to begin operating under the Energy Markets Tariff (sometimes referred to as a Locational Marginal Pricing (LMP) market or MISO Day 2 market). The implementation of an LMP market will introduce new scheduling requirements, new products for mitigating transmission congestion risks, and new pricing points for the purchase and sale of power. Cinergy is in the process of preparing for the implementation and the Midwest ISO is currently conducting market trials and testing of the Energy Markets. This is a significant undertaking by the Midwest ISO and its stakeholders and testing is not yet complete. See “Midwest ISO Energy Markets” in “Future Expectations/Trends” for further details regarding these new markets.
The prices of coal and SO2 allowances have increased dramatically in 2004, as compared to 2003. Contributing to the increases in coal and SO2 prices have been (1) increases in demand for electricity, (2) environmental regulation, and (3) decreases in the number of suppliers of coal from prior years. Since rates have been frozen for non-residential customers through 2004 and residential customers through 2005, pursuant to Ohio deregulation, these increases in coal and emission allowance prices could not be recovered through rates. The impact of these price increases on earnings is discussed in more detail in “Results of Operations”. See “Generation Portfolio Risks”in “Market Risk Sensitive Instruments” for information on how we plan to mitigate these risks going forward.
30
MD&A - - 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 the Regulated Business Unit (Regulated) and Commercial for the years ended December 31, 2004, and 2003 were as follows:
|
| Cinergy |
| ||||||||||||||||||||
|
| Regulated |
| Commercial |
| ||||||||||||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| 2004 |
| 2003 |
| Change |
| % Change |
| ||||||
|
| (in millions) |
| ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Electric gross margin(1) |
| $ | 1,656 |
| $ | 1,469 |
| $ | 187 |
| 13 | % | $ | 637 |
| $ | 714 |
| $ | (77 | ) | (11 | )% |
Gas gross margin(2) |
| 263 |
| 244 |
| 19 |
| 8 |
| 92 |
| 88 |
| 4 |
| 5 |
| ||||||
Total gross margin |
| $ | 1,919 |
| $ | 1,713 |
| $ | 206 |
| 12 |
| $ | 729 |
| $ | 802 |
| $ | (73 | ) | (9 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
(1)Electric gross margin is calculated as Electric operating revenues less Fuel, emission allowances, and purchasedpower expense from the Statements of Income.
(2)Gas gross margin is calculated as Gas operating revenues less Gas purchased expense from the Statements ofIncome.
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:
|
| Cinergy |
| ||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
|
|
|
|
|
|
|
|
|
|
|
Cooling degree days(1) |
| 882 |
| 831 |
| 51 |
| 6 | % |
Heating degree days(2) |
| 5,006 |
| 5,316 |
| (310 | ) | (6 | ) |
|
|
|
|
|
|
|
|
|
|
(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 65 degrees, assuming the average temperature is less than 65 degrees.
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.
The 13 percent increase in Regulated’s electric gross margins was primarily due to the following factors:
•An approximate $80 million increase resulting from a higher price received per MWh due to PSI’s base retail electric rate increase in May 2004; and
•An approximate $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 an approximate $16 million increase in tariff adjustments mainly associated with the gas main replacement program. Partially offsetting this increase was an approximate $7 million decrease reflecting a decline in non-weather related demand.
31
Gross Margins
The 11 percent decrease in Commercial’s electric gross margins was primarily due to the following factors:
•An approximate $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
•An approximate $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:
•An approximate $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
•An approximate $15 million increase due to growth in non-weather related demand.
Commercial’s gas gross margins under generally accepted accounting principles (GAAP) and Commercial’s adjusted gas gross margins were relatively flat in 2004, as compared to 2003, although volatility during 2004 was significant due to timing differences in revenue recognition between physical storage activities and the associated derivative contracts that hedge the physical storage. We evaluate the results of our gas marketing and trading business on an economic basis, which we term “adjusted gas gross margins”.
Our gas marketing and trading business regularly hedges its price exposure of natural gas held in storage by selling derivative contracts for winter month delivery. The majority of the gas held in storage is designated as being hedged under Statement of Financial Accounting Standards No. 133’s, Accounting for Derivative Instruments and Hedging Activities (Statement 133), fair value hedge accounting model, which allows the gas to be accounted for at its fair value (based on spot prices). Under GAAP, the derivative contracts hedging the gas are accounted for at fair value (based on forward winter prices). Conversely, the agreements with pipelines to store this natural gas until the winter periods are not derivatives and are not adjusted for changes in fair value (see footnote 1 in the table below).
For a more complete understanding of our gas marketing and trading results, we have prepared the following table, which reconciles the gas margins under GAAP, the impact of adjusting these margins for the fair value of pipeline agreements and certain gas held in storage, and the resulting adjusted gas gross margins:
|
| 2004 |
| 2003 |
| Change |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
Gas margins, as reported (GAAP) |
| $ | 92 |
| $ | 88 |
| $ | 4 |
|
|
|
|
|
|
|
|
| |||
Fair value adjustments not recognized under GAAP(1) |
| (7 | ) | (5 | ) | (2 | ) | |||
|
|
|
|
|
|
|
| |||
Adjusted gas gross margins |
| $ | 85 |
| $ | 83 |
| $ | 2 |
|
(1)Relates to fair value of storage agreements. The value of a storage agreement is the ability to store and optimize gas between periods of lower prices (typically summer) and periods of higher prices (typically winter). A large component of the fair value is therefore the differences between winter prices and spot prices. As this spread gets wider, the value of a storage agreement increases.
32
Other Operating Revenues and Costs of Fuel Resold
The 41 percent increase in Other Operating Revenues was primarily due to the following factors:
•An approximate $67 million increase in Commercial’s revenues from coal origination resulting from increases in coal prices and the number of coal origination contracts. Coal origination includes contract structuring and marketing of physical coal; and
•An approximate $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.
|
| Cinergy |
| |||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Operation and maintenance |
| $ | 1,282 |
| $ | 1,119 |
| $ | 163 |
| 15 | % |
Depreciation |
| 460 |
| 399 |
| 61 |
| 15 |
| |||
Taxes other than income taxes |
| 254 |
| 250 |
| 4 |
| 2 |
| |||
Total |
| $ | 1,996 |
| $ | 1,768 |
| $ | 228 |
| 13 |
|
The 15 percent increase in Operation and maintenance expense was primarily due to the following factors:
•Costs primarily associated with employee labor and benefits increased approximately $50 million. Labor and benefit costs increased approximately six percent;
•Maintenance expenses, primarily production related, were higher by approximately $26 million;
•An approximate $20 million of costs incurred in 2004 related to a continuous improvement initiative;
•Higher transmission costs of approximately $15 million. This increase was due, in part, to refunds received in 2003, which offset a portion of the costs for that year; and
•An approximate $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 approximately $14 million of costs associated with voluntary early retirement programs and employee severance programs in 2003; and
•An approximate $12 million for costs incurred in 2003 associated with the bankruptcy of Enron Corp.
The 15 percent increase in Depreciation expense was primarily due to the following factors:
•An approximate $36 million increase due to the addition of depreciable plant, primarily for pollution control equipment, and the accelerated gas main replacement program; and
•An approximate $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.
33
These increases were partially offset by approximately $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.
The increase in Equity in Earnings of Unconsolidated Subsidiaries was primarily due to a gain of approximately $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 15(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
The decrease in Miscellaneous Income (Expense) — Net was primarily due to the recognition of approximately $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 approximately $9 million on the notes receivable of two subsidiaries consolidated in the third quarter of 2003.
The two percent increase in Interest Expense was primarily due to the following factors:
•An approximate $12 million increase due to Cinergy’s recognition of a note payable to a trust; and
•An approximate $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 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.
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. See Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details.
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.
34
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. Pursuant to Statement of Financial Accounting Standards 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 14 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.
In 2003, Cinergy recognized a Cumulative effect of changes in accounting principles, net of tax gain of approximately $26 million. The cumulative effect of changes in accounting principles was a result of the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (Statement 143) and the rescission of Emerging Issues Task Force (EITF) Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). See Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
35
MD&A - 2004 RESULTS OF OPERATIONS – CG&E
Net income for CG&E for the years ended December 31, 2004, and 2003 were as follows:
|
| CG&E and subsidiaries |
| |||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 257 |
| $ | 331 |
| $ | (74 | ) | (22 | )% |
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 for CG&E for the years ended December 31, 2004, and 2003 were as follows:
|
| CG&E and subsidiaries |
| |||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Electric gross margin(1) |
| $ | 1,168 |
| $ | 1,195 |
| $ | (27 | ) | (2 | )% |
Gas gross margin(2) |
| 263 |
| 245 |
| 18 |
| 7 |
| |||
(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:
|
| CG&E and subsidiaries |
| ||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
|
|
|
|
|
|
|
|
|
|
|
Cooling degree days(1) |
| 876 |
| 812 |
| 64 |
| 8 | % |
Heating degree days(2) |
| 4,881 |
| 5,119 |
| (238 | ) | (5 | ) |
(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 65 degrees, assuming the average temperature is less than 65 degrees.
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.
36
The two percent decrease in CG&E’s electric gross margins was primarily due to the following factors:
•An approximate $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
•An approximate $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:
•An approximate $31 million increase in margins from retail customers due to growth in non-weather related demand; and
•An approximate $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.
The seven percent increase in CG&E’s gas gross margins was primarily due to an approximate $16 million increase in tariff adjustments mainly associated with the gas main replacement program. Partially offsetting this increase was an approximate $7 million decrease reflecting a decline in non-weather related demand.
The increase in Other Operating Revenues was due to an approximate $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.
|
| CG&E and subsidiaries |
| |||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Operation and maintenance |
| $ | 594 |
| $ | 500 |
| $ | 94 |
| 19 | % |
Depreciation |
| 179 |
| 187 |
| (8 | ) | (4 | ) | |||
Taxes other than income taxes |
| 198 |
| 200 |
| (2 | ) | (1 | ) | |||
Total |
| $ | 971 |
| $ | 887 |
| $ | 84 |
| 9 |
|
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 approximately $28 million;
•Maintenance expenses, primarily production and distribution related, were higher by approximately $21 million;
•An approximate $9 million of costs incurred in 2004 related to a continuous improvement initiative; and
37
•Higher transmission costs of approximately $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 approximately $4 million of costs associated with voluntary early retirement programs and employee severance programs in 2003.
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 approximately $15 million. This decrease was partially offset by an approximate $8 million increase due to the addition of depreciable plant primarily for pollution control equipment and the accelerated gas main replacement program.
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.
The 21 percent decrease in Interest Expense was primarily due to the following factors:
•A decline in average long-term debt; and
•Charges recorded during 2003 associated with the refinancing of certain debt.
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(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
38
MD&A - - 2004 RESULTS OF OPERATIONS – PSI
Net income for PSI for the years ended December 31, 2004, and 2003 were as follows:
|
| PSI |
| |||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 165 |
| $ | 133 |
| $ | 32 |
| 24 | % |
The increase in net income was primarily due to the following factors:
•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.
Gross margins for PSI for the years ended December 31, 2004, and 2003 were as follows:
|
| PSI |
| |||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Electric gross margin(1) |
| $ | 1,103 |
| $ | 973 |
| $ | 130 |
| 13 | % |
(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:
|
| PSI |
| ||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
|
|
|
|
|
|
|
|
|
|
|
Cooling degree days(1) |
| 887 |
| 850 |
| 37 |
| 4 | % |
Heating degree days(2) |
| 5,128 |
| 5,512 |
| (384 | ) | (7 | ) |
(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 65 degrees, assuming the average temperature is less than 65 degrees.
39
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 approximate $80 million increase resulting from a higher price received per MWh due to PSI’s base retail electric rate increase in May 2004; and
•An approximate $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.
|
| PSI |
| |||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Operation and maintenance |
| $ | 475 |
| $ | 449 |
| $ | 26 |
| 6 | % |
Depreciation |
| 222 |
| 164 |
| 58 |
| 35 |
| |||
Taxes other than income taxes |
| 47 |
| 46 |
| 1 |
| 2 |
| |||
Total |
| $ | 744 |
| $ | 659 |
| $ | 85 |
| 13 |
|
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 approximately $14 million;
•An approximate $8 million of costs incurred in 2004 related to a continuous improvement initiative;
•An increase in production related maintenance expense of approximately $7 million; and
•Higher transmission costs of approximately $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 approximately $4 million of costs associated with voluntary early retirement programs and employee severance programs in 2003.
The 35 percent increase in Depreciation expense was primarily due to the following factors:
•An approximate $27 million increase due to the addition of depreciable plant primarily for pollution control equipment; and
•An approximate $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.
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.
40
MD&A - 2004 RESULTS OF OPERATIONS – ULH&P
The Results of Operations discussion for ULH&P is presented only for the year ended December 31, 2004, 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, 2004 and 2003, were as follows:
|
| ULH&P |
| |||||||||
|
| 2004 |
| 2003 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Electric gross margin(1) |
| $ | 68 |
| $ | 68 |
| $ | — |
| — | % |
Gas gross margin(2) |
| 45 |
| 40 |
| 5 |
| 13 |
| |||
Net income |
| 19 |
| 19 |
| — |
| — |
| |||
(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.
Electric gross margins for ULH&P remained flat as growth in non-weather related demand was offset by the cost of increased electricity purchases to meet that demand. The 13 percent increase in gas gross margins was due, in part, to an approximate $3 million increase in rate tariff adjustments associated with the gas main replacement program and the demand-side management program, which encourages efficient customer gas usage.
Net income remained flat as an approximate $2 million increase in operating costs, primarily related to increased transmission and distribution expenses, was partially offset by an approximate $1 million reduction in property taxes during 2004.
41
MD&A - - 2003 RESULTS OF OPERATIONS - CINERGY
Net income for Cinergy for the years ended December 31, 2003, and 2002 was as follows:
|
| Cinergy |
| |||||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 470 |
| $ | 361 |
| $ | 109 |
| 30 | % |
Cinergy’s increase in net income was primarily due to the following factors:
•Increases in gas gross margins as a result of an increase in base rates for Ohio customers, colder weather and increased volatility in gas prices in the first quarter of 2003, as compared to 2002, and an increase in natural gas sold from storage;
•Lower operating costs primarily resulting from the recognition of higher costs in 2002 associated with employee severance programs;
•Lower property taxes, primarily resulting from the change in property value assessment in the state of Indiana in 2003;
•The 2002 write-off of certain investments;
•A net gain recognized in 2003 resulting from the implementation of certain accounting changes;
•Gains realized in 2003 and losses incurred in 2002 from the disposal of discontinued operations; and
•Lower income taxes resulting primarily from tax credits associated with the production of synthetic fuel, which began in July 2002.
These increases were partially offset by:
•A decrease in electric gross margins primarily due to milder weather in 2003; and
•A decline in electric gross margins associated with Cinergy’s natural gas peaking assets.
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 Commercialfor the years ended December 31, 2003, and 2002 were as follows:
|
| Cinergy |
| |||||||||||||||||||||||||||
|
| Regulated |
| Commercial |
| |||||||||||||||||||||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
| 2003 |
| 2002 |
| Change |
| % Change |
| |||||||||||||
|
| (in millions) |
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Electric gross margin(1) |
| $ | 1,469 |
| $ | 1,571 |
| $ | (102 | ) | (6 | )% | $ | 714 |
| $ | 735 |
| $ | (21 | ) | (3 | )% | |||||||
Gas gross margin(2) |
| 244 |
| 203 |
| 41 |
| 20 |
| 88 |
| 77 |
| 11 |
| 14 |
| |||||||||||||
Total gross margin |
| $ | 1,713 |
| $ | 1,774 |
| $ | (61 | ) | (3 | ) | $ | 802 |
| $ | 812 |
| $ | (10 | ) | 1 |
| |||||||
(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.
42
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, 2003, and 2002 were as follows:
|
| Cinergy |
| ||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
|
|
|
|
|
|
|
|
|
|
|
Cooling degree days(1) |
| 831 |
| 1,357 |
| (526 | ) | (39 | )% |
Heating degree days(2) |
| 5,316 |
| 5,093 |
| 223 |
| 4 |
|
(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 65 degrees, assuming the average temperature is less than 65 degrees.
The six percent decrease in Regulated’s electric gross margins was primarily due to a decline in retail electric margins mainly resulting from milder weather in 2003, compared to 2002. As noted in the table, cooling degree days were down 39 percent in Cinergy’s service territory. Partially offsetting this decrease was an increase in rate tariff adjustments associated with certain construction programs at PSI.
The 20 percent increase in Regulated’s gas gross margins was primarily due to the following factors:
•An increase in base rates, as approved by the Public Utilities Commission of Ohio (PUCO) in May 2002, and tariff adjustments associated with the gas main replacement program and Ohio excise taxes; and
•The colder weather in the first quarter of 2003, compared to 2002, which resulted in a greater amount of thousand cubic feet (mcf) delivered to customers.
Gross Margins
The three percent decrease in Commercial’s electric gross margins was primarily due to a decline in margins associated with Commercial’snatural gas peaking assets in 2003, as compared to 2002. Partially offsetting this decrease were higher margins from physical and financial trading primarily in and around the midwest.
The 14 percent increase in Commercial’s gas gross margins was primarily due to the following factors:
•An increase in the volatility of natural gas prices in the first quarter of 2003, as compared to the same period in 2002; and
•An increase in natural gas sold out of storage in 2003. Cinergy Marketing & Trading, LP (Marketing & Trading) began engaging in significant storage activities at the end of the second quarter of 2002.
Other Operating Revenues and Costs of Fuel Resold
The 22 percent increase in Other Operating Revenues was primarily due to an increase in Commercial’s revenues from the sale of synthetic fuel, which began in July 2002. This increase was partially offset by a decline in Commercial’s revenues from coal origination.
Costs of fuel resold includes Commercial’s costs of coal origination activities and the production of synthetic fuel. In 2003, the costs of producing synthetic fuel increased and the costs of coal origination activities decreased, both of which are consistent with the changes in the associated revenues as previously discussed.
43
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.
|
| Cinergy |
| ||||||||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
| ||||||
|
| (in millions) |
| ||||||||||||
|
|
|
|
|
|
|
|
|
| ||||||
Operation and maintenance |
| $ | 1,119 |
| $ | 1,202 |
| $ | (83 | ) | (7 | )% | |||
Depreciation |
| 399 |
| 404 |
| (5 | ) | (1 | ) | ||||||
Taxes other than income taxes |
| 250 |
| 263 |
| (13 | ) | (5 | ) | ||||||
Total |
| $ | 1,768 |
| $ | 1,869 |
| $ | (101 | ) | (5 | ) | |||
The seven percent decrease in Operation and maintenance expense was primarily due to the following factors:
•The recognition of higher costs associated with employee severance programs in 2002;
•Decreased transmission costs, largely the result of changes in the Midwest ISO operations; and
•A decrease in employee incentive costs.
These decreases were partially offset by:
•The charges associated with our resolution of claims with respect to the bankruptcy of Enron Corp.; and
•An increase in maintenance expense for our generating units and overhead lines.
The one percent decrease in Depreciation expense was primarily due to the following factors:
•An increase in estimated useful lives of CG&E’s generation assets resulting from a depreciation study completed during the third quarter of 2003; and
•CG&E’s discontinuance of accruing costs of removal for generating assets (which was previously included as part of Depreciation expense) as a result of the adoption of Statement 143. See Note 1(j) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details. Prior periods were not restated for the adoption of Statement 143.
Partially offsetting these decreases was the addition of depreciable plant primarily including pollution control equipment, accelerated gas main replacement program assets, and equipment associated with the production of synthetic fuel.
The five percent decrease in Taxes other than income taxes expense was primarily due to lower property taxes, which were partially offset by increased excise taxes. This decrease was primarily a result of a change in property value assessments in the state of Indiana in 2003.
44
The increase in Miscellaneous Income (Expense) - Net was primarily due to the following factors:
•2002 write-offs of certain equipment and technology investments and costs accrued related to the termination of a contract for the construction of combustion turbines; and
•Interest income on the notes receivable of two newly consolidated subsidiaries in 2003. See Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details.
Partially offsetting these increases were net gains realized in 2002 from the sale of equity investments in certain renewable energy projects.
The 11 percent increase in InterestExpense was primarily due to the following factors:
•An increase in average long-term debt outstanding during the year ended December 31, 2003;
•Charges during 2003 associated with the re-financing of certain debt; and
•Additional debt recorded in July 2003 with the consolidation of two new entities and the recognition of a note payable to a trust resulting from the adoption of Interpretation 46. See Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
Theseincreases were partially offset by a decrease in short-term interest rates.
The 50 percent 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. See Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details.
The decrease in the effective income tax rate was primarily due to tax credits associated with the production and sale of synthetic fuel, which began in July 2002. Cinergy’s effective tax rate for 2003 was approximately 25 percent.
In 2002, Cinergy sold and/or classified as held for sale, several non-core investments, including renewable and international investments. 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. Pursuant to Statement 144, these investments have been classified as discontinued operations in our financial statements. See Note 14 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.
The increase in discontinued operations in 2003 as compared to 2002 was due to the recognition of losses on disposal of foreign investments in 2002 and the recognition of gains on disposal in 2003.
In 2003, Cinergy recognized a Cumulative effect of changes in accounting principles, net of tax gain of approximately $26 million. The cumulative effect of changes in accounting principles was a result of the adoption of Statement 143 and the rescission of EITF 98-10.
45
In 2002, Cinergy recognized a Cumulative effect of a change in accounting principle, net of tax loss of approximately $11 million as a result of implementation of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. See Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
46
MD&A - 2003 RESULTS OF OPERATIONS – CG&E
2003 RESULTS OF OPERATIONS - CG&E
Net income for CG&E for the years ended December 31, 2003, and 2002 were as follows:
|
| CG&E and subsidiaries |
| |||||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 331 |
| $ | 264 |
| $ | 67 |
| 25 | % |
CG&E’s increase in net income was primarily due to the following factors:
•Increases in gas gross margins due to an increase in base rates, as approved by the PUCO in May 2002, and colder weather in the first quarter of 2003 as compared to 2002;
•Lower operating costs primarily resulting from the recognition of higher costs in 2002 associated with employee severance programs; and
•A net gain recognized in 2003 resulting from the implementation of certain accounting changes.
Offsetting these increases was a decrease in electric gross margins primarily due to milder weather in 2003, as compared to 2002.
Gross margins for CG&E for the years ended December 31, 2003, and 2002 were as follows:
|
| CG&E and subsidiaries |
| |||||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Electric gross margin(1) |
| $ | 1,195 |
| $ | 1,205 |
| $ | (10 | ) | (1 | )% |
Gas gross margin(2) |
| 245 |
| 205 |
| 40 |
| 20 |
| |||
(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, 2003, and 2002 were as follows:
|
| CG&E and subsidiaries |
| ||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
|
|
|
|
|
|
|
|
|
|
|
Cooling degree days(1) |
| 812 |
| 1,353 |
| (541 | ) | (40 | )% |
Heating degree days(2) |
| 5,119 |
| 4,926 |
| 193 |
| 4 |
|
(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 65 degrees, assuming the average temperature is less than 65 degrees.
47
The one percent decrease in CG&E’s electric gross margins was primarily due to a decline in retail electric margins mainly resulting from milder weather in 2003 as compared to 2002. As noted in the table, cooling degree days were down 40 percent in CG&E’s service territory. Higher margins from physical and financial trading partially offset this decrease.
The 20 percent increase in CG&E’s gas gross margins was primarily due to the following factors:
•An increase in base rates, as approved by the PUCO in May 2002, and tariff adjustments associated with the gas main replacement program and Ohio excise taxes; and
•The colder weather in the first quarter of 2003, compared to 2002, which resulted in a greater amount of mcf delivered to customers.
The 23 percent decrease in Other Operating Revenues was due to a decrease in revenues from coal origination.
Costs of fuel resold represents the costs of coal origination activities. These costs decreased in 2003, which is consistent with the decline 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.
|
| CG&E and subsidiaries |
| |||||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Operation and maintenance |
| $ | 500 |
| $ | 531 |
| $ | (31 | ) | (6 | )% |
Depreciation |
| 187 |
| 197 |
| (10 | ) | (5 | ) | |||
Taxes other than income taxes |
| 200 |
| 198 |
| 2 |
| 1 |
| |||
Total |
| $ | 887 |
| $ | 926 |
| $ | (39 | ) | (4 | ) |
The six percent decrease in Operation and maintenance expense was primarily due to the following factors:
•Decreased transmission costs largely the result of changes in the Midwest ISO operations;
•The recognition of higher costs associated with employee severance programs in 2002; and
•A decrease in employee incentive costs.
These decreases were partially offset by an increase in maintenance expense for our generating units and overhead lines.
48
The five percent decrease in Depreciation expense was primarily due to the following factors:
•An increase in the estimated useful lives of CG&E’s generation assets resulting from a depreciation study completed during the third quarter of 2003; and
•The discontinuance of accruing costs of removal for generating assets (which was previously included as part of Depreciation expense) as a result of the adoption of Statement 143. See Note 1(j) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details. Prior periods were not restated for the adoption of Statement 143.
The increase in Miscellaneous Income - Net was due, in part, to a final reconciliation with PSI of a previous demutualization of a medical insurance carrier used by both companies which was recorded in 2003.
The 20 percent increase in InterestExpense was primarily due to the following factors:
•An increase in average long-term debt outstanding; and
•Charges during 2003 associated with the re-financing of certain debt.
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(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
49
MD&A - - 2003 RESULTS OF OPERATIONS – PSI
Net income for PSI for the years ended December 31, 2003, and 2002 was as follows:
|
| PSI |
| |||||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 133 |
| $ | 214 |
| $ | (81 | ) | (38 | )% |
PSI’s decrease in net income was primarily attributable to decreases in electric gross margins due to milder weather in 2003, as compared to 2002. This decrease was partially offset by the following factors:
•The recognition of higher operating costs in 2002 associated with employee severance programs; and
•Lower property taxes, primarily resulting from the change in property value assessment in the state of Indiana in 2003.
Gross margins for PSI for the years ended December 31, 2003, and 2002 were as follows:
|
| PSI |
| |||||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Electric gross margin(1) |
| $ | 973 |
| $ | 1,064 |
| $ | (91 | ) | (9 | )% |
(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, 2003, and 2002 were as follows:
|
| PSI |
| ||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
|
|
|
|
|
|
|
|
|
|
|
Cooling degree days(1) |
| 850 |
| 1,360 |
| (510 | ) | (38 | )% |
Heating degree days(2) |
| 5,512 |
| 5,260 |
| 252 |
| 5 |
|
(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 65 degrees, assuming the average temperature is less than 65 degrees.
The nine percent decrease in PSI’s electric gross margins was primarily due to a decline in retail electric margins resulting from milder weather in 2003, compared to 2002. As noted in the table, cooling degree days were down 38 percent in PSI’s service territory. An increase in rate tariff adjustments associated with certain construction programs partially offset these decreases.
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.
50
|
| PSI |
| |||||||||
|
| 2003 |
| 2002 |
| Change |
| % Change |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Operation and maintenance |
| $ | 449 |
| $ | 470 |
| $ | (21 | ) | (4 | )% |
Depreciation |
| 164 |
| 155 |
| 9 |
| 6 |
| |||
Taxes other than income taxes |
| 46 |
| 57 |
| (11 | ) | (19 | ) | |||
Total |
| $ | 659 |
| $ | 682 |
| $ | (23 | ) | (3 | ) |
The four percent decrease in Operation and maintenance expense was primarily due to the following factors:
•Recognition of higher costs associated with employee severance programs in 2002;
•Decreased transmission costs, largely the result of changes in the Midwest ISO operations; and
•A decrease in employee incentive costs.
These decreases were partially offset by an increase in maintenance expense for our generating units and overhead lines.
The six percent increase in Depreciation expense was primarily due to the following factors:
•The addition of depreciable plant resulting from PSI’s December 2002 purchase of two gas-fired peaking plants from non-regulated affiliates. See Note 19 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for more information; and
•The addition of other depreciable plant primarily reflecting pollution control equipment and the repowering of Noblesville Station.
The 19 percent decrease in Taxes other than income taxes expense was primarily due to lower property taxes, which were partially offset by increased excise taxes. This decrease was primarily a result of a change in property value assessments in the state of Indiana in 2003.
The 69 percent decrease in Miscellaneous Income - Net was primarily a result of a final reconciliation with CG&E of a previous demutualization of a medical insurance carrier used by both companies which was recorded in 2003.
The 16 percent increase in InterestExpense was primarily a result of an increase in average long-term debt outstanding during the year ended December 31, 2003. Thisincrease was partially offset by a decrease in short-term interest rates.
The increase in the effective income tax rate was primarily due to an increase in the Indiana state income tax rate.
51
MD&A – LIQUIDITY AND CAPITAL RESOURCES
For each of the years ended December 31, 2004, 2003, 2002, and 2001,2002, our cash flows from operating activities from continuing operations were as follows:
Net Cash Provided by (Used in) Operating Activities from Continuing Operations
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Cinergy(1) |
| $ | 945,673 |
| $ | 955,802 |
| $ | 723,690 |
|
The Cincinnati Gas & Electric Company (CG&E) and subsidiaries |
| 557,761 |
| 653,029 |
| 343,118 |
| |||
PSI Energy, Inc. (PSI) |
| 246,735 |
| 499,047 |
| 401,911 |
| |||
The Union Light, Heat and Power Company (ULH&P) |
| 33,061 |
| 60,707 |
| 47,766 |
| |||
Net Cash Provided by Operating Activities from Continuing Operations |
| ||||||||||
|
|
|
|
|
|
|
| ||||
|
| 2004 |
| 2003 |
| 2002 |
| ||||
|
| (in thousands) |
| ||||||||
|
|
|
|
|
|
|
| ||||
Cinergy(1) |
| $ | 833,004 |
| $ | 945,673 |
| $ | 955,802 |
| |
CG&E and subsidiaries |
| 445,621 |
| 557,761 |
| 653,029 |
| ||||
PSI |
| 483,463 |
| 246,735 |
| 499,047 |
| ||||
ULH&P |
| 45,381 |
| 33,061 |
| 60,707 |
| ||||
(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, 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.
For the year ended December 31, 2003, CG&E’s, PSI’s, and ULH&P’s net cash provided by
32
operating activities from continuing operations decreased, as compared to 2002. CG&E’s decrease iswas primarily due to unfavorable working capital fluctuations. PSI’s decrease iswas largely due to a decrease in net income afterearnings (after adjusting for non-cash items such as depreciationitems) and a decrease in receivables sold under the receivables sale facility. A significant portion of ULH&P’s decrease iswas due to unfavorable working capital fluctuations and an increase in deferred costs under the gas cost recovery mechanism. Cinergy’s change in net cash provided by operating activities for the year ended December 31,in 2003 was comparable to 2002.
For2002, comprised of the year ended December 31, 2002,decreases at Cinergy’sCG&E , CG&E’s, PSI’s, and ULH&P’sPSI netdiscussed above offset by improved operating cash provided by operating activities from continuing operations increased, as compared to 2001, primarily due to increases in net income after adjusting for non-cash items such as depreciation; favorable working capital fluctuations; and deferred income taxes. The increase in deferred income taxes, in part, reflects a change in accounting methodology for tax purposes related to capitalized costs, which increased current tax deductions. Cinergy’s current tax obligations were also reduced by increases in tax credits associated with the production and sale of synthetic fuel.flows at our non-regulated subsidiaries.
For each of the years ended December 31, 2004, 2003, 2002, and 2001,2002, our cash flows from financing activities from continuing operations were as follows:
Net Cash Provided by (Used in) Financing Activities from Continuing Operations
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Cinergy(1) |
| $ | (245,128 | ) | $ | 42,689 |
| $ | 827,758 |
|
CG&E and subsidiaries |
| (263,296 | ) | (293,445 | ) | 16,841 |
| |||
PSI |
| 90,070 |
| (43,817 | ) | 34,723 |
| |||
ULH&P |
| 4,852 |
| (22,026 | ) | (14,678 | ) | |||
|
| 2004 |
| 2003 |
| 2002 |
| |||
|
| (in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Cinergy(1) |
| $ | (233,881 | ) | $ | (245,128 | ) | $ | 42,689 |
|
CG&E and subsidiaries |
| (172,782 | ) | (263,296 | ) | (293,445 | ) | |||
PSI |
| (164,141 | ) | 90,070 |
| (43,817 | ) | |||
ULH&P |
| (9,226 | ) | 4,852 |
| (22,026 | ) | |||
(1) The results of Cinergy also include amounts related to non-registrants.
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.
52
For the year ended December 31, 2003, Cinergy’s net cash used in financing activities from continuing operations increased, as compared to 2002, primarily due to increases in redemptions of long-term debt and the establishment of funds on deposit from the issuance of debt securities.
debt. CG&E’s net cash used in financing activities from continuing operations decreased during 2003, as compared to 2002, primarily due to a net increase in short-term debt financing.
PSI’s and ULH&P’s net cash provided by financing activities from continuing operations increased during 2003, as compared to 2002. PSI’s increase was primarily due to capital contributions from Cinergy Corp. ULH&P’s increase was primarily attributable to increases in short-term debt.
For the year ended December 31, 2002, Cinergy’s net cash provided by financing activities from continuing operations decreased, as compared to 2001. This decrease was primarily due to the
33
net proceeds received in 2001 from the issuance of Preferred Trust Securities and from new debt issuances, which were used to fund the purchase of new peaking generation facilities and environmental compliance expenditures. The repayment of both long-term and short-term debt reduced cash proceeds recognized in 2002 from the issuances of common stock and new long-term debt.
CG&E’s, PSI’s,and ULH&P’s net cash used in financing activities from continuing operations increased during 2002, as compared to 2001. CG&E’s increase reflects a net reduction in debt financing, partially offset by a decrease in dividends paid on common stock. PSI’s increase primarily reflects the payment of approximately $112 million in common stock dividends in 2002, as compared to 2001, when no common dividends were paid. ULH&P’s increase primarily reflects the repayment of short-term debt in 2002.
For each of the years ended December 31, 2004, 2003, 2002, and 2001,2002, our cash flows used in investing activities from continuing operations were as follows:
Net Cash Provided by (Used in)Used in Investing Activities from Continuing Operations
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Cinergy(1) |
| $ | (731,537 | ) | $ | (885,636 | ) | $ | (1,534,526 | ) |
CG&E and subsidiaries |
| (323,959 | ) | (323,322 | ) | (371,522 | ) | |||
PSI |
| (332,247 | ) | (454,810 | ) | (436,358 | ) | |||
ULH&P |
| (39,940 | ) | (38,854 | ) | (35,449 | ) | |||
|
| 2004 |
| 2003 |
| 2002 |
| |||
|
| (in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Cinergy(1) |
| $ | (603,702 | ) | $ | (731,537 | ) | $ | (885,636 | ) |
CG&E and subsidiaries |
| (284,527 | ) | (323,959 | ) | (323,322 | ) | |||
PSI |
| (315,093 | ) | (332,247 | ) | (454,810 | ) | |||
ULH&P |
| (33,857 | ) | (39,940 | ) | (38,854 | ) | |||
(1) The results of Cinergy also include amounts related to non-registrants.
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.
For the year ended December 31, 2003, Cinergy’s net cash used in investing activities from continuing operations decreased, as compared to 2002, primarily due to decreases in capital expenditures related to environmental compliance programs and other energy-related investments. Cinergy also purchased a synthetic fuel production facility during 2002.
PSI’s decrease was primarily due to decreases in capital expenditures for ongoing environmental compliance programs and other construction projects.
CG&E’s and ULH&P’s net cash used in 2003 investing activities from continuing operations was comparable to 2002, reflecting CG&E’s ongoing capital expenditures for environmental compliance programs, the gas main replacement program, and normal construction activity, and ULH&P’s ongoing capital expenditures for the gas main replacement program and normal construction activity.
For the year ended December 31, 2002, Cinergy’s net cash used in investing activities from continuing operations decreased, as compared to 2001. This decrease was primarily the result of Cinergy’s 2001 acquisition of peaking generation facilities, increased capital expenditures related to environmental compliance programs, and other non-core investments.2002.
34
CG&E’s, PSI’s, and ULH&P’s net cash used in 2002 investing activities from continuing operations were comparable to 2001, reflecting ongoing construction expenditures.
35
Actual construction and other committed expenditures (including capitalized financing costs) for 2003 and forecasted construction and other committed expenditures for the year 2004 and for the five-year period 2004-2008 (in nominal dollars) are presented in the table below:
Capital and Investment Expenditures
|
| Actual |
| Forecasted |
| |||||
2004 |
| 2004-2008 | ||||||||
|
|
|
| (in millions) |
|
|
| |||
|
|
|
|
|
|
|
| |||
Cinergy(1) |
| $ | 800 |
| $ | 756 |
| $ | 4,133 |
|
CG&E and subsidiaries |
| 327 |
| 302 |
| 1,591 |
| |||
PSI(2) |
| 337 |
| 336 |
| 1,978 |
| |||
ULH&P |
| 40 |
| 39 |
| 212 |
| |||
(1)The results of Cinergy also include amounts related to non-registrants.
(2)Excludes intercompany purchase of peaking plants from non-regulated affiliates.
This forecast includes an estimate of expenditures to comply with draft regulations requiring reductions in mercury, NOx, and SO2 emissions. In 2003, we spent $160 million for NOx and other environmental compliance projects. Forecasted expenditures for environmental compliance projects (in nominal dollars) are approximately $168 million for 2004 and $1.2 billion for the 2004-2008 period. Approximately 75 percent of these estimated environmental costs would be incurred at regulated coal-fired plants. See “Air Toxics and Ambient Air Standards” for further discussion.
Manufactured Gas Plant (MGP) SitesProposed Environmental Protection Agency Regulations
In November 1998, PSI entered into a Site Participation and Cost Sharing Agreement with Northern Indiana Public Service Company and Indiana Gas Company, Inc. related to contamination at MGP sites, which PSI or its predecessors previously owned. Until investigation and remediation activities have been completed onDecember 2003, the sites, we are unable to reasonably estimate the total cost and impact on our financial position or results of operations. In relation to the MGP claims, PSI also filed suit against its general liability insurance carriers. Subsequently, PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims against PSI, or (2) pay PSI’s costs of defense and compensate PSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites. At the present time, PSI cannot predict the outcome of this litigation. See Note 11(a)(iii) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information on MGP Sites.
36
Regional Haze
The United States (U.S.) Environmental Protection Agency (EPA) publishedEPA proposed the final regional haze rule in July 1999. This rule established planning and emission reduction timelines forClean Air Interstate Rule (CAIR), formerly the Interstate Air Quality Rule, which would require states to userevise their State Implementation Plans (SIP) to improve visibility in national parks throughoutaddress alleged contributions to downwind non-attainment with the U.S.revised National Ambient Air Quality Standards for ozone and fine particulate matter. The ultimate effect of the newproposed rule would establish a two-phase, regional haze rule could be requirementscap and trade program for (1) newerSO2 and cleaner technologiesNOX, affecting approximately 30 states, including Ohio, Indiana, and additional controls on particulates emissions,Kentucky, and (2) reductions in sulfur dioxide (SOwould require SO2) and NOX emissions from utility sources. If more utility emissions reductions are required, the compliance cost couldto be significant. In August 1999, several industry groups (some of which we are a member) filed a challenge to the regional haze rules with the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals). In May 2002, the Court of Appeals set aside a portion of the EPA’s rule, holding that the rule improperly forced states to require emissions controls without adequate consideration of an individual source’s impact on visibility impairment. We currently cannot predict the timing or outcome of the EPA’s response to the Court of Appeals’ ruling.
In July 2001, thecut approximately 70 percent and 65 percent, respectively, by 2015. The EPA proposed guidance to implement portions of the regional haze rule. This guidance recommends that states require widespread installation of scrubbers to reduce SO2 emissions. We currently cannot determine whether or how the EPA will modify the scope of this guidance, or whether the states in which we operate will adopt the EPA’s proposed guidance.
Air Toxics and Ambient Air Standards
In December 2003, the EPAalso issued draft regulations regarding required reductions in mercury emissions from coal-fired power plants.plants (Clean Air Mercury Rule). The draft regulations include two possible alternatives to addressachieve emissions reductions. One alternative would includereductions: a mercury cap and trade approach to mercury. The other would be aprogram or source specific reduction in emissions, withoutreductions achieved through a capcommand and tradecontrol approach. The cap and trade approach would provide a longer compliance horizon and provide more flexible compliance options for coal-fired generators.generators, including the purchase of allowances in lieu of further capital expenditures with respect to these investments. This approach would require a reduction of approximately 30 percent by 2010 and 70 percent by 2018. The source specific reduction approach would require a reduction of approximately 30 percent by 2008. The EPA is expected to issue final rules on CAIR and the Clean Air Mercury Rule by December 2004.
In December 2003, the EPA also proposed Interstate Air Quality Rules that would require states to revise their State Implementation Plans to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards (NAAQS) for ozone and fine particulate matter. The proposed rule would establish a two-phase, regional cap and trade program for SO2 and NOx. The proposed rule would affect approximately 30 states, including Ohio, Indiana, and Kentucky. The proposed rule would require SO2 emissions to be cut approximately 70 percent by 2015 and NOx emissions to be cut approximately 65 percent by 2015. The EPA is expected to issue final rules by December 2004.March 2005.
We currently estimateOver the 2005-2009 time period, estimated capital costs associated with reducing mercury, SO2, and NOX in compliance with the currently proposed CAIR and Clean Air Mercury Rule are not expected to exceed approximately
53
$1.72 billion if the EPA approves the mercury cap and trade approach and approximately $2.15 billion if the EPA approves the source specific reduction approach without a cap and trade program. These estimates include estimated costs to mercury, SO2comply at plants that we own but do not operate and NOx emissions reductions tocould 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 approximately $1.2 billion over the next five years. These costs have been included in our forecasted capital expenditures discussed previously in “Capital Requirements”.adjusted accordingly. Approximately 7560 percent of these estimated environmental costs would be incurred at regulatedPSI’s coal-fired plants, for which recovery would be pursued in accordance with regulatory statutes governing environmental cost recovery. Costs associated with the source specific approachCG&E would receive partial recovery of depreciation and financing costs related to mercury emissions reductions may be higher, depending on the type of program the EPA finalizes and the stringency and timingenvironmental compliance projects for 2005-2008 through its recently approved RSP. See Note 11(b)(iii) of the ultimate requirements. Due“Notes to these uncertainties, we are unable to predict the magnitude of those costs at this time.Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for more details.
In 1997,June 2004, the EPA revised the NAAQS for ozone and fine particulate matter. The EPA is under a court-ordered deadline to makemade final state ozone non-attainment area designations by April 15, 2004, andto implement the revised ozone standard. In January 2005, the EPA made final state non-attainment area designations to implement the new fine particulate area designations by December 15, 2004.standard. Several counties in which we operate have been tentatively designated (by their respective states) as being in non-attainment with the new ozone standard and severaland/or fine particulate standard. States with counties that are likely to be designated as being in non-attainment with the new ozone and/or fine particulate standard.standards are required to develop a plan of compliance. Although the EPA has attempted to structure the CAIR to resolve purported utility contributions to ozone and fine particulate non-attainment, at this time, Cinergy cannot predict the timing or effect of the ozonecurrent or future non-attainment designations at this time.
37
Global Climate Change
In September 2003, Cinergy announced an internal voluntary greenhouse gas (GHG) management goal to reduceon its GHG emissions by 2010. Cinergy expects to spend $21 million between 2004 and 2010 on projects to reduce or offset its GHG emissions. Cinergy’s goal is to support the President’s voluntary initiative, to address shareholder interest in the issue, and to build internal expertise in GHG management and GHG markets.
Our plan for managing the potential risk and uncertainty of regulations relating to climate change includes the following:
• implementing an internal voluntary goal to reduce Cinergy’s GHG emissions five percent below Cinergy’s 2000 baseline emission levels by 2010 and maintaining those levels through 2012;
• 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; and
• encouraging a global discussion of the issues and how best to manage them.
Asbestos Claims Litigation
CG&E and PSI have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 80 pending lawsuits. In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work at the 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. A majority of the lawsuits to date have been brought against PSI. The impact on CG&E’s and PSI’s financial position or results of operationsoperations.
In May 2004, the EPA issued proposed revisions to its regional haze rules and implementing guidelines in response to a 2002 judicial ruling overturning key provisions of these casesthe original program. The regional haze program is aimed at reducing certain emissions impacting visibility in national parks and wilderness areas. The EPA is currently considering whether SO2 and NOX reductions under the CAIR regulation will also satisfy the reduction requirements under the regional haze rule. However, the regional haze rule, when finalized, could potentially require significant additional SO2 and NOX reductions necessitating the installation of pollution controls for certain generating units at Cinergy’s power plants. In light of the EPA’s ongoing rulemaking efforts and the fact that the states have yet to dateannounce how they will implement the final rule, at this time it is not possible to predict whether the regional haze rule will have a material effect on our financial position or results of operations.
Clear Skies Legislation
President Bush has proposed environmental legislation that would combine a series of Clean Air Act (CAA) requirements, including the recently proposed regulations for mercury and particulate matter for coal-fired power plants with a legislative solution that includes trading and specific emissions reductions and timelines to meet those reductions. The President’s “Clear Skies Initiative” would seek an overall 70 percent reduction in emissions from power plants over a phased-in reduction schedule beginning in 2010 and continuing through 2018. When the Clear Skies Initiative was stalled in Congress, the EPA proposed the CAIR regulations to accomplish Clear Skies’ goals within the existing framework of the CAA. Clear Skies has been reintroduced in the Senate and could be considered in Committee over the next several weeks. However, at this time, we cannot predict whether this or any multi-emissions bill will achieve approval.
Energy Bill
The United States House of Representatives (House) passed the Energy Policy Act in April 2003. The legislation, as passed in the House, included the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA), as well as tax incentives for gas and electric distribution lines, and combined heat and power and renewable energy projects. The United States Senate (Senate) Energy and Natural Resources Committee passed its version of comprehensive energy legislation in April 2003. A conference agreement which merged both the House and Senate versions passed in the House in October 2003, but failed to pass in the Senate. The legislation will be introduced again during the 109th Congress, however, it is anticipated that several changes will be made. At this time, it is not been material. Seepossible to predict whether a final energy bill will pass in 2005.
54
Environmental Lawsuits
We are currently involved in the following lawsuits which are discussed in more detail in Note 11(a)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”. An unfavorable outcome of any of these lawsuits could have a material impact on our liquidity and capital resources.
•CAA Lawsuit
•Carbon Dioxide (CO2) Lawsuit
•Selective Catalytic Reduction Units at Gibson Generating Station
•Zimmer Generating Station Lawsuit
•Manufactured Gas Plant Sites
•Asbestos Claims Litigation
Actual construction and other committed expenditures for 2004 and forecasted construction and other committed expenditures for 2005 and for the five-year period 2005-2009 (in nominal dollars) are presented in the table below:
Capital and Investment Expenditures
|
| Actual |
| Forecasted |
| |||||
|
| 2004 |
| 2005 |
| 2005-2009 |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
Cinergy(1) |
| $ | 701 |
| $ | 1,115 |
| $ | 5,430 |
|
CG&E and subsidiaries |
| 300 |
| 430 |
| 2,345 |
| |||
PSI |
| 340 |
| 620 |
| 2,645 |
| |||
ULH&P |
| 34 |
| 80 |
| 335 |
| |||
(1)The results of Cinergy also include amounts related to non-registrants.
In 2004, we spent $203 million for NOX and other environmental compliance projects. Forecasted expenditures for environmental compliance projects (in nominal dollars) are approximately $465 million for 2005 and $1.8 billion for the 2005-2009 period. The vast majority of this forecast includes our entire estimate of costs to comply with draft regulations requiring reductions in mercury, NOX, and SO2 emissions, assuming a discussioncap and trade approach to mercury emissions. Approximately 60 percent of asbestos claimsthese estimated environmental costs would be incurred at PSI’s regulated coal-fired plants. See “Environmental Issues” for further discussion.
55
The following table presents Cinergy’s, CG&E’s, PSI’s, and ULH&P’s significant contractual cash obligations:
|
| Payments Due |
| ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| There- |
|
|
| ||||||||||
Contractual Cash Obligations |
| 2005 |
| 2006 |
| 2007 |
| 2008 |
| 2009 |
| after |
| Total |
| ||||||||||
|
| (in millions) |
| ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Cinergy(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Capital leases |
| $ | 7 |
| $ | 7 |
| $ | 7 |
| $ | 10 |
| $ | 10 |
| $ | 24 |
| $ | 65 |
| |||
Operating leases |
| 43 |
| 36 |
| 28 |
| 18 |
| 14 |
| 27 |
| 166 |
| ||||||||||
Long-term debt(2) |
| 220 | (3)(4) | 355 |
| 726 |
| 551 |
| 270 |
| 2,376 |
| 4,498 |
| ||||||||||
Fuel purchase contracts(5) |
| 879 |
| 495 |
| 420 |
| 49 |
| — |
| — |
| 1,843 |
| ||||||||||
Other commodity purchase contracts(6) |
| 28 |
| 7 |
| 3 |
| 1 |
| — |
| — |
| 39 |
| ||||||||||
Total Cinergy |
| $ | 1,177 |
| $ | 900 |
| $ | 1,184 |
| $ | 629 |
| $ | 294 |
| $ | 2,427 |
| $ | 6,611 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Capital leases |
| $ | 4 |
| $ | 4 |
| $ | 4 |
| $ | 6 |
| $ | 6 |
| $ | 16 |
| $ | 40 |
| |||
Operating leases |
| 10 |
| 8 |
| 7 |
| 5 |
| 4 |
| 6 |
| 40 |
| ||||||||||
Long-term debt(2) |
| 150 | (4) | — |
| 100 |
| 120 |
| 20 |
| 1,240 |
| 1,630 |
| ||||||||||
Fuel purchase contracts(5) |
| 413 |
| 202 |
| 161 |
| — |
| — |
| — |
| 776 |
| ||||||||||
Other commodity purchase contracts(6) |
| 5 |
| 1 |
| — |
| 1 |
| — |
| — |
| 7 |
| ||||||||||
Total CG&E and subsidiaries |
| $ | 582 |
| $ | 215 |
| $ | 272 |
| $ | 132 |
| $ | 30 |
| $ | 1,262 |
| $ | 2,493 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Capital leases |
| $ | 3 |
| $ | 3 |
| $ | 3 |
| $ | 4 |
| $ | 4 |
| $ | 8 |
| $ | 25 |
| |||
Operating leases |
| 11 |
| 10 |
| 9 |
| 7 |
| 6 |
| 13 |
| 56 |
| ||||||||||
Long-term debt(2) |
| 50 | (3) | 326 |
| 266 |
| 43 |
| 223 |
| 976 |
| 1,884 |
| ||||||||||
Fuel purchase contracts(5) |
| 466 |
| 293 |
| 259 |
| 49 |
| — |
| — |
| 1,067 |
| ||||||||||
Total PSI |
| $ | 530 |
| $ | 632 |
| $ | 537 |
| $ | 103 |
| $ | 233 |
| $ | 997 |
| $ | 3,032 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
ULH&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Capital leases |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 2 |
| $ | 3 |
| $ | 9 |
| |||
Long-term debt(2) |
| — |
| — |
| — |
| 20 |
| 20 |
| 55 |
| 95 |
| ||||||||||
Total ULH&P |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 21 |
| $ | 22 |
| $ | 58 |
| $ | 104 |
| |||
(1)Includes amounts related cases.to non-registrants.
(2)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.
(3)Includes PSI’s 6.50% Debentures due August 1, 2026, reflected as maturing in 2005, as the interest rate is due to reset on August 1, 2005. If the interest rate does not reset, the bonds are subject to mandatory redemption by PSI.
(4)CG&E’s 6.90% Debentures due June 1, 2025, are putable to CG&E at the option of the holders on June 1, 2005. However, based upon current market conditions, we believe it is unlikely that the debentures will be put to CG&E on this date.
(5)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.
(6)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 energy trading contracts that are accounted for at fair value.
56
Cinergy maintains qualified defined benefit pension plans covering substantially all U.S.
38
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 income tax purposes and the minimum being that required by the Employee Retirement Income Security Act of 1974, as amended (ERISA). Although mitigated by strong performance in 2003 and 2004, ongoing retiree payments and the decline in market value of the investment portfolio in 2002 have reduced the assets held in trust to satisfy plan obligations. Additionally, decreases incontinuing low long-term interest rates have hadincreased the effect of increasing the liability used for funding purposes. As a result of these events, our near term funding targets have increased substantially. Cinergy has adopted a five-year plan to reduce, or eliminate, the unfunded pension obligation initially measured as of January 1, 2003. This unfunded obligation will be recalculated as of January 1 of each year in the five-year plan. SuchBecause this unfunded obligation was calculated asis the difference between the liability determined actuarially on an ERISA basis and the market value of plan assets as of January 1, 2003. The2003, the liability used indetermined by this calculation is different than the pension liability calculated for accounting purposes reported on Cinergy’s Balance Sheets.
Cinergy’s minimum required contribution in calendar year 2004 was $16 million, as compared to $11 million in calendar year 2003. Actual contributions during calendar year 2004 and 2003 totaled $117 million and $74 million, reflecting additional discretionary contributions of $101 million and $63 million, respectfully, under the aforementioned five-year plan. Due to the significant 2004 and 2003 calendar year contributions, Cinergy’s minimum required contributions in calendar year 2003 were $11 million, as compared to $4 million in calendar year 2002. Cinergy’s minimum required contributions in calendar year 20042005 are expected to be approximately $16 million. Actual contributions during calendar year 2003 totaled $74 million reflecting additional discretionary contributions of $63 million under the aforementioned five-year plan.zero. Should Cinergy continue funding under thisthe five-year plan, discretionary contributions in addition to the minimum funding requirements are expected to be $90$72 million in 2004.2005. Cinergy may consider making discretionary contributions in 20052006 and future periods,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.
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 $8$9 million in 2004.2005.
We provide certain health care and life insurance benefits to retired U.S.United States employees and their eligible dependents. Cinergy’s payments for these postretirement benefits in 20042005 are expected to be approximately $27$25 million. See Note 9 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.
Long-term debt due within one year for Cinergy increased $663 million from December 31, 2002 to December 31, 2003. The primary cause of the increase was the reclassification of Cinergy Corp.’s $200 million 6.125% Debentures due April 15, 2004 and $500 million 6.25% Debentures due September 1, 2004 from Long-term debt to Long-term debt due within one year.
As discussed in Note 4 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”, in September 2003, PSI issued $400 million principal amount of its 5.00% Debentures largely using the proceeds from this issuance for the early redemption of two
39
subordinated promissory notes to Cinergy Corp. totaling $376 million. Cinergy Corp. plans to use the proceeds to partially fund the maturity of the 6.125% and 6.25% debentures discussed above. In the interim, Cinergy Corp. has used the proceeds to repay short-term indebtedness.
Cinergy plans to meet its remaining future debt obligations from the issuance of debt and/or equity securities and internally-generated funds.
Our ability to invest in growth initiatives is limited by certain legal and regulatory requirements, including the Public Utility Holding Company Act of 1935, as amended (PUHCA).PUHCA. The PUHCA limits the types of non-utility businesses in which Cinergy and other registered holding companies under the PUHCA can invest as well as the amount of capital that can be invested in permissible non-utility businesses. Also, the timing and amount of investments in the non-utility businesses is dependent on the development and favorable evaluations of opportunities. Under the PUHCA restrictions, we are allowed to invest, or commit to invest, in certain non-utility businesses, including:
• Exempt Wholesale Generators (EWG) and Foreign Utility Companies (FUCO)
An EWG is an entity, certified by the Federal Energy Regulatory Commission (FERC), devoted exclusively to owning and/or operating, and selling power from one or more electric generating facilities. An EWG whose generating facilities are located in the U.S.United States is limited to making only wholesale sales of electricity. An entity claiming status as an EWG must provide notification thereof to the SEC under the PUHCA.
57
A FUCO is a company all of whose utility assets and operations are located outside the U.S.United States and which are used for the generation, transmission, or distribution of electric energy for sale at retail or wholesale, or the distribution of gas at retail. A FUCO may not derive any income, directly or indirectly, from the generation, transmission, or distribution of electric energy for sale or the distribution of gas at retail within the U.S.United States. An entity claiming status as a FUCO must provide notification thereof to the Securities and Exchange Commission (SEC)SEC under the PUHCA.
Cinergy has been granted SEC authority under the PUHCA to invest (including by way of guarantees) an aggregate amount in EWGs and FUCOs equal to the sum of (1) our average consolidated retained earnings from time to time plus (2) $2 billion.billion through June 30, 2005. As of December 31, 2003,2004, we had invested or committed to invest approximately $0.8 billion in EWGs and FUCOs, leaving available investment capacity under the order of $2.7approximately $2.8 billion. In February 2005, Cinergy filed an application with the SEC under the PUHCA requesting an extension of this authority through December 31, 2008. At this time, we are unable to predict whether the SEC will approve this request.
• Qualifying Facilities and Energy-Related Non-utility Entities
SEC regulations under the PUHCA permit Cinergy and other registered holding companies to invest and/or guarantee an amount equal to 15 percent of consolidated capitalization (consolidated capitalization is the sum of Notes payable and other
40
short-term obligations,, Long-term debt (including(including amounts due within one year), Preferred Trust Securities, Cumulative Preferred Stock of Subsidiaries, and total Common Stock Equity) in domestic qualifying cogeneration and small power production plants (qualifying facilities) and certain other domestic energy-related non-utility entities. At December 31, 2003,2004, we had invested and/or guaranteed approximately $0.9$1.1 billion of the $1.4 billion available. In August 2004, Cinergy filed an application with the SEC requesting authority under the PUHCA to increase its investment and/or guarantee authority by $2 billion above the current authorized amount. At this time, we are unable to predict whether the SEC will approve this request.
• Energy-Related Assets
Cinergy has been granted SEC authority under the PUHCA to invest up to $1 billion in non-utility Energy-Related Assets within the U.S.,United States, Canada, and Mexico. Energy-Related Assets include natural gas exploration, development, production, gathering, processing, storage and transportation facilities and equipment, liquid oil reserves and storage facilities, and associated assets, facilities and equipment, but would exclude any assets, facilities, or equipment that would cause the owner or operator thereof to be deemed a public utility company. As of December 31, 2003,2004, we did not have any investments in these Energy-Related Assets.
• Infrastructure Services Companies
Cinergy has been granted SEC authority under the PUHCA to invest up to $500 million in companies that derive or will derive substantially all of their operating revenues from the sale of Infrastructure Services including:
• Design, construction, retrofit, and maintenance of utility transmission and distribution systems;
• Installation and maintenance of natural gas pipelines, water and sewer pipelines, and underground and overhead telecommunications networks; and
• Installation and servicing of meter reading devices and related communications networks, including fiber optic cable.
At December 31, 2003,2004, we had invested approximately $26$30 million in these Infrastructure Services companies. In February 2005, Cinergy filed an application with the SEC under PUHCA requesting authority to invest up to $100 million in Infrastructure Services companies through December 31,
4158
The following table presents2008, which is a $400 million reduction in Cinergy’s, CG&E’s, PSI’s, and ULH&P’s significant contractual cash obligations: current authority. At this time, we are unable to predict whether the SEC will approve this request.
|
| Payments Due | ||||||||||||||||||||||||||||
Contractual Cash Obligations |
| 2004 |
| 2005 |
| 2006 |
| 2007 |
| 2008 |
| There- |
| Total |
| |||||||||||||||
|
| (in millions) | ||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Cinergy(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Capital leases |
| $ | 5 |
| $ | 6 |
| $ | 6 |
| $ | 6 |
| $ | 8 |
| $ | 24 |
| $ | 55 |
| ||||||||
Operating leases |
| 41 |
| 33 |
| 26 |
| 21 |
| 13 |
| 37 |
| 171 |
| |||||||||||||||
Long-term debt (including amounts due within one year) |
| 835 |
| 222 | (2)(3) | 354 |
| 727 |
| 550 |
| 2,333 |
| 5,021 |
| |||||||||||||||
Fuel purchase contracts(4)(7) |
| 671 |
| 569 |
| 471 |
| 465 |
| 336 |
| 1,374 |
| 3,886 |
| |||||||||||||||
Other commodity purchase contracts(5) |
| 21 |
| 2 |
| — |
| — |
| — |
| — |
| 23 |
| |||||||||||||||
Qualified Pension Plans(6) |
| 16 |
| — |
| — |
| — |
| — |
| — |
| 16 |
| |||||||||||||||
Total Cinergy |
| $ | 1,589 |
| $ | 832 |
| $ | 857 |
| $ | 1,219 |
| $ | 907 |
| $ | 3,768 |
| $ | 9,172 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Capital leases |
| $ | 3 |
| $ | 3 |
| $ | 3 |
| $ | 4 |
| $ | 5 |
| $ | 15 |
| $ | 33 |
| ||||||||
Operating leases |
| 9 |
| 8 |
| 7 |
| 5 |
| 4 |
| 9 |
| 42 |
| |||||||||||||||
Long-term debt (including amounts due within one year) |
| 110 |
| 150 | (3) | — |
| 100 |
| 120 |
| 1,126 |
| 1,606 |
| |||||||||||||||
Fuel purchase contracts(4)(7) |
| 297 |
| 217 |
| 113 |
| 98 |
| — |
| — |
| 725 |
| |||||||||||||||
Other commodity purchase contracts(5) |
| 5 |
| — |
| — |
| — |
| — |
| — |
| 5 |
| |||||||||||||||
Total CG&E and subsidiaries |
| $ | 424 |
| $ | 378 |
| $ | 123 |
| $ | 207 |
| $ | 129 |
| $ | 1,150 |
| $ | 2,411 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Capital leases |
| $ | 2 |
| $ | 2 |
| $ | 2 |
| $ | 3 |
| $ | 4 |
| $ | 9 |
| $ | 22 |
| ||||||||
Operating leases |
| 10 |
| 9 |
| 9 |
| 8 |
| 7 |
| 17 |
| 60 |
| |||||||||||||||
Long-term debt (including amounts due within one year) |
| — |
| 52 | (2) | 326 |
| 266 |
| 44 |
| 1,043 |
| 1,731 |
| |||||||||||||||
Fuel purchase contracts(4)(7) |
| 356 |
| 352 |
| 358 |
| 367 |
| 336 |
| 1,374 |
| 3,143 |
| |||||||||||||||
Total PSI |
| $ | 368 |
| $ | 415 |
| $ | 695 |
| $ | 644 |
| $ | 391 |
| $ | 2,443 |
| $ | 4,956 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
ULH&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Capital leases |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 3 |
| $ | 8 |
| ||||||||
Long-term debt (including amounts due within one year) |
| — |
| — |
| — |
| — |
| 20 |
| 35 |
| 55 |
| |||||||||||||||
Total ULH&P |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 21 |
| $ | 38 |
| $ | 63 |
| ||||||||
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
|
| 2004 |
| 2005 |
| 2006 |
| 2007 |
|
CG&E |
| 11 |
| 41 |
| 27 |
| 28 |
|
PSI |
| 22 |
| 20 |
| 19 |
| 20 |
|
Cinergy |
| 33 |
| 61 |
| 46 |
| 48 |
|
42
We are subject to an SEC order under the PUHCA, which limits the amounts Cinergy Corp. can have outstanding under guarantees at any one time to $2 billion. As of December 31, 2003,2004, we had $693approximately $877 million outstanding under the guarantees issued, of which approximately 9096 percent represents guarantees of obligations reflected on Cinergy’s Balance Sheets. The amount outstanding represents Cinergy Corp.’s guarantees of liabilities and commitments of its consolidated subsidiaries, unconsolidated subsidiaries, and joint ventures. In February 2005, Cinergy filed an application with the SEC under the PUHCA requesting authority to have an aggregate amount of guarantees outstanding at any point in time not to exceed $3 billion. At this time, we are unable to predict whether the SEC will approve this request.
See Note 11(c)(viiv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for a discussion of guarantees in accordance with Financial Accounting Standards Board (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. The Interpretation 45 disclosure differs from the PUHCA restrictions in that it requires a calculation of maximum potential liability, rather than actual amounts outstanding; it excludes guarantees issued on behalf of consolidated subsidiaries; and it includes potential liabilities under indemnification clauses.
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, 20032004 trading portfolio, if such an event were to occur, Cinergy would be required to issue up to approximately $73$310 million in collateral related to its gas and power trading operations, of which $32$69 million is related to CG&E.
Cinergy,CG&E,PSI, and ULH&P meet their current and future capital requirements through:
•through a combination of funding sources including, but not limited to, internally generated funds;
•cash flows, tax-exempt bond issuances, capital lease and cash equivalents on hand;
•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 securities;
• bank financing under newequity. Funding decisions are based on market conditions, market access, relative pricing information, borrowing duration and existing facilities; and
• monetization of assets.
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.
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). A decline in the long-term senior unsecured credit ratings of CG&E, PSI, and ULH&P below investment grade would result in the termination of the sale program and discontinuance of future sales of receivables.
4359
We are required to secure authority to issue short-term debt from the SEC under the PUHCA and from the Public Utilities Commission of Ohio (PUCO).PUCO. The SEC under the PUHCA regulates the issuance of short-term debt by Cinergy Corp., PSI, and ULH&P. The PUCO has regulatory jurisdiction over the issuance of short-term debt by CG&E.
|
| Short-term Regulatory Authority |
| ||||
|
| (in millions) |
| ||||
|
| Authority |
| Outstanding |
| ||
|
|
|
|
|
| ||
Cinergy Corp. |
| $ | 5,000 | (1) | $ | 146 |
|
CG&E and subsidiaries |
| 671 |
| 49 |
| ||
PSI |
| 600 |
| 188 |
| ||
ULH&P |
| 65 |
| 45 |
| ||
|
| Short-term Regulatory Authority |
| ||||
|
| (in millions) |
| ||||
|
|
|
|
|
| ||
|
| Authority |
| Outstanding |
| ||
|
|
|
|
|
| ||
Cinergy Corp. |
| $ | 5,000 | (1) | $ | 676 |
|
CG&E and subsidiaries |
| 665 | (2) | 180 |
| ||
PSI |
| 600 |
| 131 |
| ||
ULH&P |
| 65 | (2) | 11 |
| ||
(1)Cinergy Corp., under the PUHCA, was granted approval to increase total capitalization (excluding retained earnings and accumulated other comprehensive income (loss)), which may be any combination of debt and equity securities, by $5 billion. Outside this requirement, Cinergy Corp. is not subject to specific regulatory debt authorizations.
(2) In December 2004, Cinergy and ULH&P requested approval from the SEC for an increase in ULH&P’s authority from $65 million to $150 million to coincide with the completion of its pending transaction with CG&E in which ULH&P will acquire interests in three of CG&E’s electric generating stations. At this time, we are unable to predict whether the SEC will approve this request.
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.
4460
Cinergy Corp.’s short-term borrowing consists primarily of unsecured revolving lines of credit and the sale of commercial paper. Cinergy Corp.’s $1$2 billion revolving credit facilities and $800 million$1.5 billion 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 is a summary of outstanding short-term borrowings for Cinergy, CG&E, PSI, and ULH&P, including variable rate pollution control notes:
|
| Short-term Borrowings |
| |||||||||||||
|
| Established |
| Outstanding |
| Unused |
| Standby |
| Available |
| |||||
|
|
|
|
|
| (in millions) |
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cinergy |
|
|
|
|
|
|
|
|
|
|
| |||||
Cinergy Corp. |
|
|
|
|
|
|
|
|
|
|
| |||||
Revolving lines |
| $ | 1,000 |
| $ | — |
| $ | 1,000 |
| $ | 159 |
| $ | 841 |
|
Uncommitted lines(1) |
| 40 |
| — |
| 40 |
|
|
|
|
| |||||
Commercial paper(2) |
|
|
| 146 |
| 654 |
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Operating companies |
|
|
|
|
|
|
|
|
|
|
| |||||
Uncommitted lines(1) |
| 75 |
| — |
| 75 |
|
|
|
|
| |||||
Pollution control notes |
|
|
| 193 |
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Non-regulated subsidiaries |
|
|
|
|
|
|
|
|
|
|
| |||||
Revolving lines |
| 19 |
| 10 |
| 9 |
|
|
| 9 |
| |||||
Short-term debt |
|
|
| 2 |
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cinergy Total |
|
|
| $ | 351 |
|
|
|
|
| $ | 850 |
| |||
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
| |||||
Uncommitted lines(1) |
| $ | 15 |
| $ | — |
| $ | 15 |
|
|
|
|
| ||
Pollution control notes |
|
|
| 112 |
|
|
|
|
|
|
| |||||
Money pool |
|
|
| 49 |
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E Total |
|
|
| $ | 161 |
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
PSI |
|
|
|
|
|
|
|
|
|
|
| |||||
Uncommitted lines(1) |
| $ | 60 |
| $ | — |
| $ | 60 |
|
|
|
|
| ||
Pollution control notes |
|
|
| 81 |
|
|
|
|
|
|
| |||||
Money pool |
|
|
| 188 |
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
PSI Total |
|
|
| $ | 269 |
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
ULH&P |
|
|
|
|
|
|
|
|
|
|
| |||||
Money pool |
|
|
| $ | 45 |
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
ULH&P Total |
|
|
| $ | 45 |
|
|
|
|
|
|
| ||||
45
|
| Short-term Borrowings |
| |||||||||||||
|
| December 31, 2004 |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
| Available |
| |||||
|
|
|
|
|
|
|
|
|
| Revolving |
| |||||
|
| Established |
|
|
|
|
| Standby |
| Lines of |
| |||||
|
| Lines |
| Outstanding |
| Unused |
| Liquidity(1) |
| Credit |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cinergy |
|
|
|
|
|
|
|
|
|
|
| |||||
Cinergy Corp. |
|
|
|
|
|
|
|
|
|
|
| |||||
Revolving lines(2) |
| $ | 2,000 |
| $ | — |
| $ | 2,000 |
| $ | 688 |
| $ | 1,312 |
|
Uncommitted lines(3) |
| 40 |
| — |
| 40 |
|
|
|
|
| |||||
Commercial paper(4) |
|
|
| 676 |
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Utility operating companies |
|
|
|
|
|
|
|
|
|
|
| |||||
Uncommitted lines(3) |
| 75 |
| — |
| 75 |
|
|
|
|
| |||||
Pollution control notes |
|
|
| 248 |
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Non-regulated subsidiaries |
|
|
|
|
|
|
|
|
|
|
| |||||
Revolving lines(5) |
| 158 |
| 8 |
| 150 |
| — |
| 150 |
| |||||
Short-term debt |
|
|
| 2 |
|
|
|
|
|
|
| |||||
Pollution control notes |
|
|
| 25 |
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cinergy Total |
|
|
| $ | 959 |
|
|
|
|
| $ | 1,462 |
| |||
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
| |||||
Uncommitted lines(3) |
| $ | 15 |
| $ | — |
| $ | 15 |
|
|
|
|
| ||
Pollution control notes |
|
|
| 112 |
|
|
|
|
|
|
| |||||
Money pool |
|
|
| 180 |
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E Total |
|
|
| $ | 292 |
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
PSI |
|
|
|
|
|
|
|
|
|
|
| |||||
Uncommitted lines(3) |
| $ | 60 |
| $ | — |
| $ | 60 |
|
|
|
|
| ||
Pollution control notes |
|
|
| 136 |
|
|
|
|
|
|
| |||||
Money pool |
|
|
| 130 |
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
PSI Total |
|
|
| $ | 266 |
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
ULH&P |
|
|
|
|
|
|
|
|
|
|
| |||||
Money pool |
|
|
| $ | 11 |
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
ULH&P Total |
|
|
| $ | 11 |
|
|
|
|
|
|
| ||||
(1)Outstanding amounts may be greater than established lines as uncommitted lenders are, at times, willing to loan funds in excess of the established lines.
(2)The commercial paper program is limited to $800 million and is supported by Cinergy Corp.’s revolving lines of credit.
(3) Standby liquidity is reserved against the revolving lines of credit to support the commercial paper program and outstanding letters of credit (currently $146$676 million and $13$12 million, respectively).
(2)Consists of a three-year $1 billion facility and a five-year $1 billion facility. The five-year facility contains $500 million sublimits each for CG&E and PSI.
46(3)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.
(4)In September 2004, Cinergy Corp. increased its commercial paper program limit from $800 million to $1.5 billion. The commercial paper program is supported by Cinergy Corp.’s revolving lines of credit.
(5)In December 2004, Cinergy Canada, Inc. successfully placed a $150 million three-year senior revolving credit facility.
61
At December 31, 2003,2004, Cinergy Corp. had $841 millionapproximately $1.3 billion remaining unused and available capacity relating to its $1$2 billion revolving credit facilities. These revolving credit facilities include the following:
Credit Facility |
| Expiration |
| Established |
| Outstanding |
| Unused and |
| ||||
|
|
|
|
|
| (in millions) |
|
|
| ||||
|
|
|
|
|
|
|
|
|
| ||||
364-day senior revolving(1) |
| April 2004 |
|
|
|
|
|
|
| ||||
Direct borrowing |
|
|
| $ |
|
| $ | — |
| $ |
|
| |
Commercial paper support |
|
|
|
|
| 146 |
|
|
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Total 364-day facility |
|
|
| 600 |
| 146 |
| 454 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Three-year senior revolving(1) |
| May 2004 |
|
|
|
|
|
|
| ||||
Direct borrowing |
|
|
|
|
| — |
|
|
| ||||
Commercial paper support |
|
|
|
|
| — |
|
|
| ||||
Letter of credit support |
|
|
|
|
| 13 |
|
|
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Total Three-year facility |
|
|
| 400 |
| 13 |
| 387 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Total Credit Facilities |
|
|
| $ | 1,000 |
| $ | 159 |
| $ | 841 |
| |
|
|
| Outstanding |
| ||||||||
Credit Facility |
| Expiration |
| Established Lines |
| and Committed |
| Unused and Available |
| |||
|
|
| (in millions) |
| ||||||||
|
|
|
|
|
|
|
|
|
| |||
Five-year senior revolving |
| December 2009 |
|
|
|
|
|
|
| |||
Direct borrowing |
|
|
| $ |
|
| $ | — |
| $ |
|
|
Commercial paper support |
|
|
|
|
| — |
|
|
| |||
|
|
|
|
|
|
|
|
|
| |||
Total five-year facility(1) |
|
|
| 1,000 |
| — |
| 1,000 |
| |||
|
|
|
|
|
|
|
|
|
| |||
Three-year senior revolving |
| April 2007 |
|
|
|
|
|
|
| |||
Direct borrowing |
|
|
|
|
| — |
|
|
| |||
Commercial paper support |
|
|
|
|
| 676 |
|
|
| |||
Letter of credit support |
|
|
|
|
| 12 |
|
|
| |||
|
|
|
|
|
|
|
|
|
| |||
Total three-year facility(2) |
|
|
| 1,000 |
| 688 |
| 312 |
| |||
|
|
|
|
|
|
|
|
|
| |||
Total Credit Facilities |
|
|
| $ | 2,000 |
| $ | 688 |
| $ | 1,312 |
|
(1)Cinergy Corp. has historically followed the practice of renewing its credit facilities upon expiration.
In April 2003,2004, Cinergy Corp. successfully placed a $600$500 million 364-day senior unsecured revolving credit facility. This facility replaced the $600 million 364-day senior unsecured revolving credit facility that expired in April 30, 2003.2004. In December 2004, Cinergy Corp. successfully replaced the $500 million 364-day facility with a $1 billion five-year facility. CG&E and PSI each have $500 million borrowing sublimits on this facility.
(2)In April 2004, Cinergy Corp. successfully placed a $1 billion three-year senior unsecured revolving credit facility. This facility replaced the $400 million three-year senior unsecured revolving credit facility that was set to expire in May 2004.
In our credit facilities, 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 $1 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 $1 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.
A breach of these covenants could result in the termination of the credit facilities and the acceleration of the related indebtedness. In addition to breaches of covenants, certain other events that could result in the termination of 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.
As discussed in Note 1(q)(ivi) of the “Notes to Financial Statements” in “Item 8. Financial
47
Statements and Supplementary Data”, long-term debt increased in the third quarter of 2003 resulting from the adoption of FASB Interpretation No. 46, Consolidation of Variable Interest Entities (Interpretation 46).46. The debt which was recorded as a result of this new accounting pronouncement did not cause
62
Cinergy Corp. to be in breach of any covenants at the time of adoption. As of December 31, 2004, Cinergy, CG&E, and PSI are in compliance with all of their debt covenants.
48
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, 2003,2004, Cinergy, CG&E andPSI had $112.1$273 million, $112 million and $80.5$136 million, respectively, outstanding in variable rate pollution control notes, classified as short-term debt. ULH&Phad 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 65 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 facilities. The commercial paper program supports, in part, the short-term borrowing needs of CG&E and PSI and eliminates their need for additional information regarding pollution control notes.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, 2004, Cinergy Corp. had $676 million in commercial paper outstanding.
Money Pool
Cinergy Corp., Cinergy Services, Inc., 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.
We have entered into operating lease agreements for various facilities and properties such as computer, communication and transportation equipment, and office space. See Note 7(a)6(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information regarding operating leases.
|
| Capital Lease Authority |
| |||||||||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
|
| Authority |
| Outstanding |
| Remaining |
| Expiration Date |
| |||
CG&E and subsidiaries |
| $ | 60 |
| $ | 9 |
| $ | 51 |
| 12/31/2005 |
|
PSI |
| 100 |
| 4 |
| 96 |
| 12/31/2005 |
| |||
ULH&P |
| 25 |
| 2 |
| 23 |
| 12/31/2006 |
| |||
63
See Note 7(b)6(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional
49
information regarding capital leases.
50
We are required to secure authority to issue long-term debt from the SEC under the PUHCA and the state utility commissions of Ohio, Kentucky, and Indiana. The SEC under the PUHCA regulates the issuance of long-term debt by Cinergy Corp. The respective state utility commissions regulate the issuance of long-term debt by our utility operating companies.
A current summary of our long-term debt authorizations at December 31, 2003,2004, was as follows:
|
| Authorized |
| Used |
| Available |
| |||
|
|
|
| (in millions) |
|
|
| |||
|
|
|
|
|
|
|
| |||
Cinergy Corp. |
|
|
|
|
|
|
| |||
PUHCA total capitalization(1) |
| $ | 5,000 |
| $ | 1,561 |
| $ | 3,439 |
|
|
|
|
|
|
|
|
| |||
CG&E and subsidiaries(2)(3) |
|
|
|
|
|
|
| |||
State Public Utility Commissions |
| 575 |
| — |
| 575 |
| |||
|
|
|
|
|
|
|
| |||
PSI |
|
|
|
|
|
|
| |||
State Public Utility Commission(4) |
| 500 |
| 483 | (5) | 17 |
| |||
|
|
|
|
|
|
|
| |||
ULH&P |
|
|
|
|
|
|
| |||
State Public Utility Commission |
| 75 |
| — |
| 75 |
| |||
|
| Authorized |
| Used |
| Available |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
Cinergy Corp. |
|
|
|
|
|
|
| |||
PUHCA total capitalization(1)(2) |
| $ | 5,000 |
| $ | 1,747 |
| $ | 3,253 |
|
|
|
|
|
|
|
|
| |||
CG&E and subsidiaries(3) |
|
|
|
|
|
|
| |||
State Public Utility Commissions |
| $ | 575 |
| $ | — |
| $ | 575 |
|
State Public Utility Commission - Tax-Exempt |
| 250 |
| 94 |
| 156 |
| |||
|
|
|
|
|
|
|
| |||
PSI |
|
|
|
|
|
|
| |||
State Public Utility Commission |
| $ | 500 |
| $ | — |
| $ | 500 |
|
State Public Utility Commission - Tax-Exempt |
| 250 |
| 209 |
| 41 |
| |||
|
|
|
|
|
|
|
| |||
ULH&P |
|
|
|
|
|
|
| |||
State Public Utility Commission(4) |
| $ | 75 |
| $ | — |
| $ | 75 |
|
(1) Cinergy Corp., under the PUHCA, was granted approval to increase total capitalization (excluding retained earnings and accumulated other comprehensive income (loss)), which may be any combination of debt and equity securities, by $5 billion. Outside this requirement, Cinergy Corp. is not subject to specific regulatory debt authorizations.
(2) In February 2005, CG&ECinergy received authority from filed an application with the PUCO in December 2003SEC under the PUHCA to issue an additional long-term$5 billion in any combination of debt upand equity securities from time to $500 million.time through December 31, 2008. At this time, we are unable to predict whether the SEC will approve this request.
(3) Includes amounts for ULH&P.
(4) In January 2004,2005, PSIULH&P filed an application with the IURC requesting additional long-term debt issuanceKentucky Public Service Commission (KPSC) seeking financing authority ofto issue and sell up to $500 million. An IURC decision is expected in the first quartermillion principal amount of 2004.
(5)Usedsecured and unsecured debt; enter into inter-company promissory notes up to an aggregate principal amount represents issuances, net of redemptions, during the authorization period.$200 million; and borrow up to a maximum of $200 million aggregate principal amount of tax-exempt debt through December 31, 2006.
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 $574$323 million remains available for issuance. CG&E has an effective shelf registration statement with the SEC relating to the issuance of up to $500$800 million in any combination of unsecured debt securities, first mortgage bonds, or preferred stock, all of which $100 million remains available for issuance. PSI has an effective shelf registration statement with the SEC relating to the issuance of up to $700$800 million in any combination of unsecured debt securities, first mortgage bonds, or preferred stock, all of which $300 million remains available for issuance. In February 2004, CG&E and PSI filed with the SEC to increase the available capacity under their shelf registration statements to $800 million for each company. ULH&P has an effective shelf registration statementsstatement with the SEC for the issuance of up to $75 million in unsecured debt securities, $35 million of which remains available for issuance. ULH&P also has an effective shelf registration statement with the SEC relating to the issuance of up to $50 million in unsecured debt securities and up to $40 million in first mortgage bonds, of which $30 million in unsecured debt securities and $20 million in first mortgage bonds remainremains available for issuance.
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
51
example, to facilitate securitization, leasing, hedging, research and development, and reinsurance, 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 (seemethod. See Note 1(b)(ii) of the “Notes to
64
Financial Statements” in “Item 8. Financial Statements and Supplementary Data”). for additional information on the accounting for equity method investments.
(i) Guarantees Guarantees
Cinergy has entered into various contracts that are classified as guarantees under Interpretation 45. For further information, see Note 11(c)(viiv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
(ii) Retained Interest in Assets Transferred to an Unconsolidated Entity
In February 2002, CG&E, PSI, and ULH&P replaced their existing 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 special purpose entity.SPE. CG&E, PSI, and ULH&P each retain an interest in the receivables transferred to Cinergy Receivables. The salestransfer of receivables are accounted for underas sales, pursuant to Statement of Financial Accounting Standards No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities (Statement 140). For a more detailed discussion of our sales of accounts receivable, see Note 3(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 obligateobligated the holder to purchase common shares of Cinergy Corp. stock inby February 2005. Since the stock purchasespurchase contracts arewere detachable and classified in equity, the change in their fair value iswas not recorded in equity or earnings. 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 3(b) of the “Notes to the 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 1(q)(ivi) and Note 3(a)3 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
5265
As of January 31, 2004,2005, the major credit rating agencies rated our securities as follows:
Fitch(1) | Moody’s(2) | S&P(3) | |||||
|
|
|
|
|
|
| |
Cinergy Corp. |
|
|
|
|
|
| |
Corporate Credit | BBB+ |
| Baa2 |
| BBB+ |
| |
Senior Unsecured Debt | BBB+ |
| Baa2 |
| BBB |
| |
Commercial Paper | F-2 |
| P-2 |
| A-2 |
| |
Preferred Trust Securities | BBB+ |
| Baa2 |
| BBB |
| |
|
|
|
|
|
|
| |
CG&E |
|
|
|
|
|
| |
Senior Secured Debt | A- |
| A3 |
| A- |
| |
Senior Unsecured Debt | BBB+ |
| Baa1 |
| BBB |
| |
Junior Unsecured Debt | BBB |
| Baa2 |
| BBB- |
| |
Preferred Stock | BBB |
| Baa3 |
| BBB- |
| |
Commercial Paper | F-2 |
| P-2 |
| Not Rated |
| |
|
|
|
|
|
|
| |
PSI |
|
|
|
|
|
| |
Senior Secured Debt | A- |
| A3 |
| A- |
| |
Senior Unsecured Debt | BBB+ |
| Baa1 |
| BBB |
| |
Junior Unsecured Debt | BBB |
| Baa2 |
| BBB- |
| |
Preferred Stock | BBB |
| Baa3 |
| BBB- |
| |
Commercial Paper | F-2 |
| P-2 |
| Not Rated |
| |
|
|
|
|
|
|
| |
ULH&P |
|
|
|
|
|
| |
Senior Unsecured Debt |
| BBB+ |
| Baa1 |
| BBB |
|
(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-.
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.
Under the SEC’s June 2000 Order, Cinergy Corp. is permitted to increase its total capitalization by $5 billion (as previously discussed). The proceeds from any new issuances will be used for general corporate purposes.
Cinergy Corp. issued approximately 3.9 million shares in 2004 and approximately 4.6 million shares in 2003 and approximately 3.2 million shares in 2002 to satisfy its obligations under its various employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan.
In February 2002, Cinergy Corp. issued 6.5 million shares of common stock with net proceeds of approximately $200 million.
In January 2003, Cinergy Corp. filed a shelf registration statement with the SEC with respect to the
53
issuance of common stock, preferred stock, and other securities in an aggregate offering amount of $750 million. In February 2003, Cinergy soldissued 5.7 million shares of common stock of Cinergy Corp. with net proceeds of approximately $175 million under this registration statement.
The net proceeds from this transaction were used to reduce short-term debt of Cinergy Corp. and for other general corporate purposes. In December 2004, Cinergy Corp. issued 6.1 million shares of common stock with net proceeds of approximately $247 million, which were used to reduce short-term debt.
In May and August of 2003, Cinergy Corp. contributed $200 million in capital to PSI in two separate $100 million capital contributions in the second and third quarters of 2003, respectively. These capital contributions were made to support PSI’s current credit ratings.
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 approximately $316 million were used to reduce short-term debt. See
66
Note 3(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further discussion of the securities.
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 dividends.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.
Where subject to rate regulations, our utility operating companies have the ability to timely recover certain cash outlays through various regulatory mechanisms such as fuel adjustment clause, purchased power tracker (Tracker), gas cost recovery, and construction work in progress (CWIP) ratemaking. For further discussion see “Electric Industry” and “Gas Industry”.mechanisms.
As opportunities arise, we will continue to monetize certain non-core investments, which would include our international assets and other technology investments.
5467
MD&A - 2003 RESULTS OF OPERATIONS - HISTORICAL
The Results of Operations discussions for Cinergy, CG&E, and PSI are combined within this section.
Electric and gas gross margins and net income for Cinergy, CG&E, and PSI for the years ended December 31, 2003 and 2002 were as follows:
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ||||||||||||
|
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| ||||||
|
| (in thousands) | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Electric gross margin |
| $ | 2,224,936 |
| $ | 2,348,369 |
| $ | 1,214,960 |
| $ | 1,228,005 |
| $ | 994,785 |
| $ | 1,083,218 |
|
Gas gross margin |
| 331,673 |
| 280,488 |
| 245,410 |
| 204,534 |
| — |
| — |
| ||||||
Net income |
| 469,772 |
| 360,576 |
| 331,050 |
| 263,696 |
| 133,381 |
| 214,249 |
| ||||||
(1)The results of Cinergy also include amounts related to non-registrants.
Cinergy’s, CG&E’s, and PSI’s electric gross margins decreased for the year ended December 31, 2003 as compared to the same period last year. Milder weather in 2003 compared to 2002 contributed the most to decreased retail electric margins. In addition, electric gross margins associated with Cinergy’s natural gas peaking assets decreased in 2003 as compared to 2002. Partially offsetting these decreases were higher margins from physical and financial trading for Cinergy and CG&E and an increase in rate tariff adjustments associated with certain construction programs at PSI.
Cinergy’s and CG&E’s gas gross margins increased for the year ended December 31, 2003 as compared to the same period last year. CG&E’s increase resulted primarily from an increase in base rates, as approved by the PUCO in May 2002 and tariff adjustments associated with the gas main replacement program and Ohio excise taxes. The colder weather in the first quarter of 2003 compared to 2002 also contributed to CG&E’s increased gas margins. In addition, in the second quarter of 2002 Cinergy Marketing & Trading, LP (Marketing & Trading) began engaging in storage and transportation activities. Higher gas trading margins as discussed in “Gas Operating Revenues” also contributed to the increase.
Cinergy’s and CG&E’s net income increased for the year as a result of increases in gas gross margins as discussed above and lower Operation and Maintenance Expense primarily a result of the recognition of higher costs in 2002 associated with employee severance programs. In addition, lower property taxes, primarily resulting from the change in property value assessment in the state of Indiana in 2003, contributed to Cinergy’s increase. Also contributing to Cinergy’s increase was the 2002 write-off of certain investments. Cinergy’s and CG&E’s increased net income reflects a net gain resulting from the implementation of certain accounting changes which have been reflected as a cumulative effect of changes in accounting principles. Cinergy’s increased net income also reflects gains realized in 2003 and losses incurred in 2002 from the disposal of discontinued operations and lower income taxes resulting primarily from tax credits associated with the production of synthetic fuel, which began in July 2002. Offsetting these
55
increases were decreases in the electric gross margins of Cinergy and CG&E.
PSI’s net income decreased as a result of decreases in electric gross margins discussed above. Offsetting the decrease in electric gross margins was the recognition of higher costs in 2002 associated with employee severance programs. Partially offsetting PSI’s decrease in net income was lower property taxes as discussed above.
The explanations below follow the line items on the Statement of Income for Cinergy, CG&E, and PSI. However, only the line items that varied significantly from prior periods are discussed.
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ||||||||||||||||||
|
| 2003 |
| 2002 |
| % Change |
| 2003 |
| 2002 |
| % Change |
| 2003 |
| 2002 |
| % Change |
| ||||||
|
| (in millions) |
| ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Retail |
| $ | 2,702 |
| $ | 2,785 |
| (3 | ) | $ | 1,337 |
| $ | 1,425 |
| (6 | ) | $ | 1,365 |
| $ | 1,360 |
| — |
|
Wholesale |
| 560 |
| 395 |
| 42 |
| 310 |
| 150 |
| N/M |
| 209 |
| 211 |
| (1 | ) | ||||||
Other |
| 121 |
| 158 |
| (23 | ) | 107 |
| 125 |
| (14 | ) | 29 |
| 40 |
| (28 | ) | ||||||
Total |
| $ | 3,383 |
| $ | 3,338 |
| 1 |
| $ | 1,754 |
| $ | 1,700 |
| 3 |
| $ | 1,603 |
| $ | 1,611 |
| — |
|
(1)The results of Cinergy also include amounts related to non-registrants.
N/M Not meaningful to an understanding of the change.
Retail electric operating revenues decreased for Cinergy and CG&E mainly due to milder weather during the summer of 2003. Cooling degree days were down by 40 percent for CG&E compared to last year. In addition, Cinergy’s and CG&E’s retail revenues decreased due to migration of customers to a transportation-only tariff, in connection with the Ohio electric customer choice program.
PSI’s retail revenues were relatively flat for the year ended December 31, 2003, as compared to 2002. The price per megawatt hour (MWh) increased mainly due to increases in rate tariff adjustments associated with the fuel cost recovery program and certain construction programs. The cost of fuel for PSI’s retail customers is passed on dollar-for-dollar under the state mandated fuel cost recovery mechanism. Offsetting this increase was a decrease in MWh delivered due to a mild summer in 2003. Cooling degree days were down 38 percent for PSI compared to last year.
Electric wholesale revenues increased for Cinergy and CG&E primarily due to more Cinergy generation capacity that was available for wholesale transactions and lower retail demand. CG&E’s increase reflects the implementation of the joint operating agreement that allows all new wholesale transactions entered into since April 2002 to be originated on behalf of CG&E. In addition, Cinergy’s and CG&E’s increase reflects higher margins on physical and financial trading primarily in and around the Midwest. PSI’s wholesale revenues remained relatively flat mainly due to an increase in the amount of power sold to CG&E and a decline in wholesale third-party transactions due to the implementation of the joint operating agreement as discussed above. For a further explanation of the power transfers between PSI and CG&E, see Note 1(s)(ii) of the “Notes to Financial Statements” in “Item 8. Financial Statements and
56
Supplementary Data”.
Other Electric operating revenues for Cinergy, CG&E, and PSI decreased for the year ended December 31, 2003, as compared to 2002. Cinergy’s and CG&E’s decrease is due primarily to a reduction in third party coal sales. Cinergy’s, CG&E’s, and PSI’s decrease also reflects lower transmission revenues primarily as a result of changes in the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) operations.
|
| Cinergy(1) |
| CG&E and subsidiaries |
| ||||||||||||
|
| 2003 |
| 2002 |
| % Change |
| 2003 |
| 2002 |
| % Change |
| ||||
|
| (in millions) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Retail |
| $ | 623 |
| $ | 433 |
| 44 |
| $ | 623 |
| $ | 433 |
| 44 |
|
Wholesale |
| 71 |
| 68 |
| 4 |
| — |
| — |
| — |
| ||||
Storage and Transportation |
| 140 |
| 86 |
| 63 |
| — |
| — |
| — |
| ||||
Other |
| 2 |
| 3 |
| (33 | ) | 5 |
| 4 |
| 25 |
| ||||
Total |
| $ | 836 |
| $ | 590 |
| 42 |
| $ | 628 |
| $ | 437 |
| 44 |
|
(1)The results of Cinergy also include amounts related to non-registrants.
Cinergy’s and CG&E’s retail gas operating revenues increased primarily due to a higher price received per thousand cubic feet (mcf) delivered. The increase in price was primarily the result of the colder weather in the first quarter of 2003, as compared to the same period in 2002, which drove up the demand and the price of natural gas. CG&E’s wholesale gas commodity cost is passed directly to the retail customer dollar-for-dollar under the gas cost recovery mechanism mandated by state law. Additionally, the higher price per mcf reflects an increase in CG&E’s base rates, as approved by the PUCO in May 2002, and tariff adjustments associated with the gas main replacement program, gas cost recovery mechanism, and Ohio excise taxes. Additionally, the amount of mcf delivered to customers increased as a result of colder weather in the first quarter of 2003, as compared to 2002.
Cinergy’s wholesale gas operating revenues (which represent net gains and losses on energy trading derivatives) increased for the year ended December 31, 2003, as compared to 2002, primarily due to an increase in the volatility of natural gas prices in the first quarter of 2003, as compared to the same period in 2002.
Cinergy’s gas storage and transportation operating revenues increased for the year ended December 31, 2003, as compared to 2002, primarily due to an increase in natural gas sold out of storage in 2003. Marketing & Trading began engaging in significant storage activities at the end of the second quarter of 2002.
Other revenues for Cinergy increased for the year ended December 31, 2003, as compared to 2002. This increase was primarily due to the sale of synthetic fuel, which began in July 2002.
57
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ||||||||||||||||||
|
| 2003 |
| 2002 |
| % Change |
| 2003 |
| 2002 |
| % Change |
| 2003 |
| 2002 |
| % Change |
| ||||||
|
| (in millions) | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fuel |
| $ | 1,005 |
| $ | 886 |
| 13 |
| $ | 411 |
| $ | 410 |
| — |
| $ | 547 |
| $ | 443 |
| 23 |
|
Purchased and exchanged power |
| 153 |
| 104 |
| 47 |
| 128 |
| 62 |
| N/M |
| 61 |
| 84 |
| (27 | ) | ||||||
Gas purchased |
| 383 |
| 233 |
| 64 |
| 382 |
| 233 |
| 64 |
| — |
| — |
| — |
| ||||||
Gas storage and transportation |
| 121 |
| 77 |
| 57 |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||
Operation and maintenance |
| 1,276 |
| 1,292 |
| (1 | ) | 511 |
| 533 |
| (4 | ) | 453 |
| 489 |
| (7 | ) | ||||||
Depreciation |
| 419 |
| 405 |
| 3 |
| 187 |
| 196 |
| (5 | ) | 184 |
| 156 |
| 18 |
| ||||||
Taxes other than income taxes |
| 250 |
| 263 |
| (5 | ) | 200 |
| 198 |
| 1 |
| 46 |
| 57 |
| (19 | ) | ||||||
Total |
| $ | 3,607 |
| $ | 3,260 |
| 11 |
| $ | 1,819 |
| $ | 1,632 |
| 11 |
| $ | 1,291 |
| $ | 1,229 |
| 5 |
|
(1) The results of Cinergy also include amounts related to non-registrants.
N/M Not meaningful to an understanding of the change.
Fuel primarily represents the cost of coal, natural gas, and oil that is used to generate electricity. The following table details the changes to fuel expense from the year ended December 31, 2002, to the year ended December 31, 2003:
|
| Cinergy(1) |
| CG&E |
| PSI |
| |||
|
| (in millions) | ||||||||
|
|
|
|
|
|
|
| |||
Fuel Expense – December 31, 2002 |
| $ | 886 |
| $ | 410 |
| $ | 443 |
|
|
|
|
|
|
|
|
| |||
Increase (Decrease) due to changes in: |
|
|
|
|
|
|
| |||
Price of fuel |
| 23 |
| 7 |
| 16 |
| |||
Deferred fuel cost |
| 70 |
| — |
| 70 |
| |||
Fuel consumption |
| 18 |
| — |
| 18 |
| |||
Other(2) |
| 8 |
| (6 | ) | — |
| |||
|
|
|
|
|
|
|
| |||
Fuel Expense – December 31, 2003 |
| $ | 1,005 |
| $ | 411 |
| $ | 547 |
|
(1)The results of Cinergy also include amounts related to non-registrants.
(2)Includes costs of third party coal sales.
Deferred fuel cost represents changes in fuel expense associated with PSI’s fuel adjustment charge, which recovers retail fuel costs from customers on a dollar-for-dollar basis. The fuel adjustment charge is calculated based on the estimated cost of fuel in the next three-month period. PSI records any under-recovery or over-recovery resulting from these differences as a deferred asset or liability until it is billed or refunded to its customers, at which point it is adjusted through fuel expense.
Purchased and exchanged power expense increasedfor Cinergy and CG&E, and decreased for
58
PSI for the year ended December 31, 2003, as compared to 2002. The increases for Cinergy and CG&E were primarily the result of increases in price paid per MWh and a lower amount of deferred purchased power cost. PSI’s decrease is a result of more generation being available to serve PSI native load customers due to the repowering of PSI’s Noblesville station and the addition of two peaking plants as discussed in Note 19 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
Gas purchased expense increased for Cinergy and CG&E for the year ended December 31, 2003, as compared to 2002, primarily due to an increased average cost per mcf of gas purchased. In addition, CG&E’s gas customer usage increased approximately ten percent due to colder weather for the year ended December 31, 2003, as compared to the same period last year. CG&E’s wholesale commodity cost is passed directly to the retail customer dollar-for-dollar under the gas cost recovery mechanism mandated by state law.
Operation and maintenance expense decreased for Cinergy, CG&E, and PSI for the year ended December 31, 2003, as compared to 2002, primarily as a result of decreased transmission costs largely the result of changes in the Midwest ISO operations, the recognition of higher costs associated with employee severance programs in 2002, and a decrease in employee incentive costs. Cinergy’s decrease was partially offset by costs associated with the production of synthetic fuel, which began in July 2002, and the charges associated with our resolution of claims with respect to the bankruptcy of Enron Corp. Cinergy’s, CG&E’s, and PSI’s decrease was partially offset by an increase in maintenance expense for our generating units and overhead lines.
Depreciation expense increased for Cinergy and PSI, and decreased for CG&E for the year ended December 31, 2003, as compared to 2002. Cinergy’s and PSI’s increase was primarily due to the addition of depreciable plant. Also contributing to Cinergy’s increase was the addition of the depreciable equipment associated with the production of synthetic fuel. CG&E’s decrease was primarily attributable to an increase in the estimated useful lives of certain assets resulting from a new depreciation study completed during the third quarter of 2003. Also contributing to CG&E’s decrease was the discontinuance of accruing costs of removal for generating assets (which was previously included as part of Depreciation expense) as a result of the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset
59
Retirement Obligations (Statement 143). See Note 1(q)(iii) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details. Prior periods were not restated for the adoption of Statement 143.
Taxes other than income taxes expense decreased for Cinergy and PSI for the year ended December 31, 2003, as compared to 2002, primarily resulting from lower property taxes partially offset by increased excise taxes. This decrease is primarily a result of a change in property value assessments in the state of Indiana in 2003.
Miscellaneous Income - Net increased for Cinergy and CG&E,and decreased for PSI for the year ended December 31, 2003, as compared to 2002. Cinergy’s increase primarily reflects the 2002 write-offs of certain equipment and technology investments and costs accrued related to the termination of a contract for the construction of combustion turbines. Also contributing to the increase was the interest income on the notes receivable of two newly consolidated subsidiaries in 2003. See Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details. Partially offsetting these increases were net gains realized in 2002 from the sale of equity investments in certain renewable energy projects. Cinergy’s and CG&E’s increase also reflects a gain on the sale of non-utility property. In addition, CG&E’s increase and PSI’s decrease was a result of a final reconciliation between the two entities of a previous demutualization of a medical insurance carrier used by both companies which was recorded in 2003.
InterestExpense increased for Cinergy, CG&E, and PSI for the year ended December 31, 2003, as compared to 2002, primarily as a result of an increase in average long-term debt outstanding during the year ended December 31, 2003. Cinergy’s and CG&E’s increases also reflect charges during 2003 associated with the re-financing of certain debt. Cinergy’s, CG&E’s, and PSI’s increases were partially offset by a decrease in short-term interest rates. Cinergy’s increase also reflects the additional debt recorded with the consolidation of two new entities and the recognition of a note payable to a trust in accordance with the adoption of Interpretation 46. See Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
Preferred Dividend Requirement of Subsidiary Trust decreased for Cinergy for the year ended December 31, 2003, as compared to 2002, as 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 discussed above. See Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further details.
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The effective income tax rate decreased for Cinergy and increased for PSI forthe year ended December 31, 2003, as compared to 2002. CG&E’s effective income tax rate remained flat for the period. Cinergy’s decrease was primarily a result of the tax credits associated with the production and sale of synthetic fuel by a non-regulated subsidiary, which began in July 2002. Cinergy’s effective tax rate for 2003 was approximately 25 percent. PSI’s increase was primarily a result of the increase in the Indiana state income tax rate.
In 2002, Cinergy sold and/or classified as held for sale, several non-core investments, including renewable and international investments. During 2003, Cinergy completed the disposal of its gas distribution operation in South Africa, sold its remaining wind assets in the U.S., and substantially sold or liquidated the assets of its energy marketing business in the Czech Republic. Pursuant to Statement of Financial Accounting Standards No. 144, Accounting for the Impairment of Long-lived Assets (Statement 144), these investments have been classified as discontinued operations in our financial statements. See Note 14 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.
The increase in discontinued operations in 2003 as compared to 2002 is due to the recognition of losses on disposal of foreign investments in 2002 and the recognition of gains on disposal in 2003.
In 2003, Cinergy, CG&E, and PSI recognized Cumulative effect of changes in accounting principles, net of tax gain/(loss) of approximately $26 million, $31 million, and $(0.5) million, respectively. The cumulative effect of changes in accounting principles was a result of the adoption of Statement 143, and the rescission of Emerging Issues Task Force (EITF) Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10).
In 2002, Cinergy recognized a Cumulative effect of a change in accounting principle, net of tax loss of approximately $11 million as a result of implementation of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (Statement 142). See Note 1(q)(vi) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
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ULH&P
The Results of Operations discussion for ULH&P is presented only for the year ended December 31, 2003, in accordance with General Instruction I(2)(a).
Electric and gas gross margins and net income for ULH&P for the year ended December 31, 2003 and 2002, were as follows:
|
| ULH&P | |||||
|
| 2003 |
| 2002 |
| ||
|
| (in thousands) | |||||
|
|
|
|
|
| ||
Electric gross margin |
| $ | 67,509 |
| $ | 67,122 |
|
Gas gross margin |
| 40,298 |
| 34,820 |
| ||
Net income |
| 19,029 |
| 12,150 |
| ||
Electric gross margins for ULH&P remained flat for the twelve months ended December 31, 2003 compared to 2002. Gas gross margins increased for the same period. The majority of the increase is due to tariff adjustments associated with the gas main replacement program. The colder weather in the first quarter of 2003 also contributed to this increase.
The increase in net income for the year was primarily due to increased gas gross margins (discussed above). Also contributing to the increase in net income was the recognition of expenses in 2002 for previously deferred costs that were denied recovery in the final order on ULH&P’s gas rate case, decreases in transmission costs in 2003 (as a result of changes in Midwest ISO operations) and decreases in employee incentives in 2003. Partially offsetting this increase in net income was increased amortization of demand-side management program costs and increased maintenance costs of ULH&P’s overhead lines.
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MD&A - 2002 RESULTS OF OPERATIONS - HISTORICALFUTURE EXPECTATIONS/TRENDS
Electric and gas gross margins and net income for Cinergy, CG&E, and PSI for the years ended December 31, 2002 and 2001 were as follows:
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ||||||||||||
|
| 2002 |
| 2001 |
| 2002 |
| 2001 |
| 2002 |
| 2001 |
| ||||||
|
| (in thousands) | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Electric gross margin |
| $ | 2,348,369 |
| $ | 2,201,081 |
| $ | 1,228,005 |
| $ | 1,215,385 |
| $ | 1,083,218 |
| $ | 942,530 |
|
Gas gross margin |
| 280,488 |
| 258,368 |
| 204,534 |
| 199,665 |
| — |
| — |
| ||||||
Net income |
| 360,576 |
| 442,279 |
| 263,696 |
| 326,654 |
| 214,249 |
| 162,333 |
| ||||||
(1)The results of Cinergy also include amounts related to non-registrants.
Increased gross margins were offset by the recognition of costs associated with employee severance programs, charges related to the write-off of certain investments, and higher operating costs. Increased gross margins were also offset by a cumulative effect of a change in accounting principle related to the implementation of Statement 142.
The explanations below follow the line items on the Statements of Income for Cinergy, CG&E, and PSI. However, only the line items that varied significantly from prior periods are discussed.
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ||||||||||||||||||
|
| 2002 |
| 2001 |
| % Change |
| 2002 |
| 2001 |
| % Change |
| 2002 |
| 2001 |
| % Change |
| ||||||
|
| (in millions) | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Retail |
| $ | 2,785 |
| $ | 2,694 |
| 3 |
| $ | 1,425 |
| $ | 1,447 |
| (2 | ) | $ | 1,360 |
| $ | 1,247 |
| 9 |
|
Wholesale |
| 395 |
| 442 |
| (11 | ) | 150 |
| 140 |
| 7 |
| 211 |
| 301 |
| (30 | ) | ||||||
Other |
| 158 |
| 80 |
| 98 |
| 125 |
| 64 |
| 95 |
| 40 |
| 26 |
| 54 |
| ||||||
Total |
| $ | 3,338 |
| $ | 3,216 |
| 4 |
| $ | 1,700 |
| $ | 1,651 |
| 3 |
| $ | 1,611 |
| $ | 1,574 |
| 2 |
|
(1)The results of Cinergy also include amounts related to non-registrants.
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Retail electric operating revenues increased for Cinergy and PSI reflecting an increased price received per MWh sales due to the changes in rate tariff adjustments associated with demand-side management, Tracker, CWIP, and fuel cost recovery programs. The cost of fuel for PSI’s retail customers is passed on dollar-for-dollar under the state mandated fuel cost recovery mechanism. PSI also had increased MWh sales attributable to weather and increased customer usage. CG&E’s retail electric operating revenues decreased slightly for the year ended December 31, 2002, as compared to 2001. Increased residential sales, primarily attributable to weather, were offset by decreases in price received per MWh and revenue from commercial and industrial customers. This decrease reflects the migration of such customers to a transportation-only tariff, in connection with the Ohio electric customer choice program.
Cinergy’s wholesale electric operating revenues decrease primarily reflects a reduction in the average price per MWh realized on wholesale transactions related to CG&E’s and PSI’s energy marketing and trading activities. Additionally, CG&E’s increase and PSI’s decrease in wholesale electric operating revenues reflect the implementation of the new joint operating agreement effective April 2002. In connection with implementation of the new operating agreement, new wholesale sales transactions entered into since April 2002 were originated on behalf of CG&E.
Other electric operating revenues for Cinergy, CG&E, and PSI increased for the year ended December 31, 2002, as compared to 2001. Cinergy’s and CG&E’s increase is due primarily to third party coal sales. Cinergy’s, CG&E’s, and PSI’s increase also reflects transmission revenues associated with the Midwest ISO which began operations in early 2002.
|
| Cinergy(1) |
| CG&E and subsidiaries |
| ||||||||||||
|
| 2002 |
| 2001 |
| % Change |
| 2002 |
| 2001 |
| % Change |
| ||||
|
| (in millions) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Retail |
| $ | 433 |
| $ | 587 |
| (26 | ) | $ | 433 |
| $ | 587 |
| (26 | ) |
Wholesale |
| 68 |
| 61 |
| 11 |
| — |
| — |
| — |
| ||||
Storage and transportation |
| 86 |
| — |
| N/M |
| — |
| — |
| — |
| ||||
Other |
| 3 |
| 8 |
| (63 | ) | 4 |
| 9 |
| (56 | ) | ||||
Total |
| $ | 590 |
| $ | 656 |
| (10 | ) | $ | 437 |
| $ | 596 |
| (27 | ) |
(1)The results of Cinergy also include amounts related to non-registrants.
N/MNot meaningful to an understanding of this change.
CG&E’s retail gas operating revenues decreased primarily due to a lower price received per mcf delivered. The lower price reflects a substantial decrease in the wholesale gas commodity cost, which is passed directly to the retail customer dollar-for-dollar under the gas cost recovery mechanism that is mandated by state law. Partially offsetting this decrease in retail gas revenues was an increase in CG&E’s base rates approved by the PUCO in May 2002 (See “CG&E Gas Rate Case” in “Results of Operations - Future”).
Cinergy’s wholesale gas operating revenues (which represent net gains and losses on energy
64
trading derivatives) increased for the year ended December 31, 2002 as compared to 2001, primarily due to an increase in basis trading and the volatility of natural gas prices.
Gas storage and transportation operating revenues increased for the year ended December 31, 2002, as compared to 2001. Marketing & Trading began engaging in significant storage activities in the second quarter of 2002, resulting in increased revenues, which must be presented on a gross revenue basis.
Other revenues for Cinergy increased for the year ended December 31, 2002, as compared to 2001. This increase is primarily due to the sale of synthetic fuel, which began in July 2002.
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ||||||||||||||||||
|
| 2002 |
| 2001 |
| % Change |
| 2002 |
| 2001 |
| % Change |
| 2002 |
| 2001 |
| % Change |
| ||||||
|
| (in millions) | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fuel |
| $ | 886 |
| $ | 813 |
| 9 |
| $ | 410 |
| $ | 332 |
| 23 |
| $ | 443 |
| $ | 459 |
| (3 | ) |
Purchased and exchanged power |
| 104 |
| 201 |
| (48 | ) | 62 |
| 104 |
| (40 | ) | 84 |
| 173 |
| (51 | ) | ||||||
Gas purchased |
| 233 |
| 397 |
| (41 | ) | 233 |
| 397 |
| (41 | ) | — |
| — |
| — |
| ||||||
Gas storage and transportation |
| 77 |
| — |
| N/M |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||
Operation and maintenance |
| 1,292 |
| 1,008 |
| 28 |
| 533 |
| 442 |
| 21 |
| 489 |
| 413 |
| 18 |
| ||||||
Depreciation |
| 405 |
| 367 |
| 10 |
| 196 |
| 187 |
| 5 |
| 156 |
| 149 |
| 5 |
| ||||||
Taxes other than income taxes |
| 263 |
| 228 |
| 15 |
| 198 |
| 174 |
| 14 |
| 57 |
| 50 |
| 14 |
| ||||||
Total |
| $ | 3,260 |
| $ | 3,014 |
| 8 |
| $ | 1,632 |
| $ | 1,636 |
| — |
| $ | 1,229 |
| $ | 1,244 |
| (1 | ) |
(1)The results of Cinergy also include amounts related to non-registrants.
N/MNot meaningful to an understanding of this change.
65
Fuel
Fuel primarily represents the cost of coal, natural gas, and oil that is used to generate electricity. The following table details the changes to fuel expense from the year ended December 31, 2001, to the year ended December 31, 2002:
|
| Cinergy(1) |
| CG&E |
| PSI |
| |||
|
| (in millions) | ||||||||
|
|
|
|
|
|
|
| |||
Fuel Expense – December 31, 2001 |
| $ | 813 |
| $ | 332 |
| $ | 459 |
|
|
|
|
|
|
|
|
| |||
Increase (Decrease) due to changes in: |
|
|
|
|
|
|
| |||
Price of fuel |
| (8 | ) | (22 | ) | 14 |
| |||
Deferred fuel cost |
| (23 | ) | — |
| (23 | ) | |||
Fuel consumption |
| 23 |
| 30 |
| (7 | ) | |||
Other(2) |
| 81 |
| 70 |
| — |
| |||
|
|
|
|
|
|
|
| |||
Fuel Expense – December 31, 2002 |
| $ | 886 |
| $ | 410 |
| $ | 443 |
|
(1)The results of Cinergy also include amounts related to non-registrants.
(2)Includes costs of third party coal sales.
Deferred fuel cost represents changes in fuel expense associated with PSI’s fuel adjustment charge, which recovers retail fuel costs from customers on a dollar-for-dollar basis. The fuel adjustment charge is calculated based on the estimated cost of fuel in the next three-month period. PSI records any under-recovery or over-recovery resulting from these differences as a deferred asset or liability until it is billed or refunded to its customers, at which point it is adjusted through fuel expense.
Purchased and exchanged power expense decreasedfor Cinergy, CG&E, and PSI for the year ended December 31, 2002, as compared to 2001. Cinergy’s and CG&E’s decrease primarily reflects a reduction in the average price paid per MWh as wholesale electric on-peak commodity prices were approximately 23 percent lower, on average, as compared to 2001. CG&E’s and PSI’s Purchased and exchanged power expense also reflects the implementation of the new joint operating agreement which began in April 2002, which reduced the amount of intercompany purchases between CG&E and PSI.
Gas purchased expense decreased for Cinergy and CG&E for the year ended December 31, 2002, as compared to 2001, primarily due to a decrease in the average cost purchased per mcf for retail customer usage. Wholesale natural gas commodity spot prices were 16 percent lower on average for the year ended December 31, 2002, as compared to 2001. CG&E’s wholesale gas commodity cost is passed directly to the retail customer dollar-for-dollar under the gas cost recovery mechanism that is mandated by state law.
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Gas storage and transportation expense increased for Cinergy for the year ended December 31, 2002, as compared to 2001. As previously discussed in “Gas Operating Revenues”, Marketing & Trading began engaging in significant storage activities at the end of the second quarter of 2002. Gas storage expense is recognized on our Statements of Income as natural gas is sold from inventory.
Operation and maintenance expense increased for Cinergy, CG&E, and PSI for the year ended December 31, 2002, as compared to 2001. Cinergy’s, CG&E’s, and PSI’s increase reflects the recognition of costs associated with employee severance programs, which began in the second quarter of 2002. Also contributing to this increase were higher transmission costs, increased costs of employee compensation and benefit programs, and expenditures related to process improvement and performance measurement initiatives. Cinergy’s and PSI’s increase also reflects increased amortization of demand-side management expenditures. Additionally, Cinergy’s increase includes costs associated with the production of synthetic fuel, which began in July 2002 and increased operating costs for certain of our non-regulated investments.
Depreciation expense increased for Cinergy, CG&E, and PSI for the year ended December 31, 2002, as compared to 2001. This increase was primarily attributable to the addition of depreciable plant, including Cinergy’s acquisitions of non-regulated peaking generation in 2001 and a synthetic fuel project in 2002.
Taxes other than income taxes expense increased for Cinergy, CG&E, and PSI for the year ended December 31, 2002, as compared to 2001. This increase is primarily attributable to increased property taxes. Cinergy’s and CG&E’s increase also reflects other tax changes associated with deregulation in Ohio.
Equity in earnings (losses)of unconsolidated subsidiaries increased for the year ended December 31, 2002, as compared to 2001, primarily due to changes in the market valuation of certain investments and the dissolution and write-off of subsidiaries in 2001.
Miscellaneous Income - Net decreased for Cinergy for the year ended December 31, 2002, as compared to 2001, primarily reflecting the write-off of technology investments and costs accrued related to the termination of a contract for the construction of combustion turbines. Partially offsetting this decrease were net gains realized from the sale of equity investments in certain renewable energy projects.
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InterestExpense decreased for Cinergy, CG&E, and PSI for the year ended December 31, 2002, as compared to 2001, primarily as a result of lower interest rates.
Preferred dividend requirement of subsidiary trust relates to quarterly payments to be made to holders of Cinergy’s preferred trust securities, which were issued in December 2001.
The effective income tax rate for Cinergy and PSI decreasedfor the year ended December 31, 2002, as compared to 2001. Cinergy’s decrease was primarily a result of the tax credits associated with the production and sale of synthetic fuel, which began in July 2002. PSI’s variability in effective income tax rates was primarily attributable to changes in state and local income taxes. CG&E’s effective income tax rate remained relatively flat for the period.
In 2002, Cinergy sold and/or classified as held for sale, several non-core investments. Pursuant to Statement 144, these investments have been classified as discontinued operations in our financial statements. See Note 14 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information. The decrease in discontinued operations in 2002 as compared to 2001 is a result of losses recognized on the disposition of foreign investments in 2002.
Cinergy recognized a Cumulative effect of a change in accounting principle of approximately $11 million (net of tax) as a result of an impairment charge for goodwill related to the implementation of Statement 142. See Note 1(q)(vi) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
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MD&A - RESULTS OF OPERATIONS - FUTURE
In the “Future Expectations/Trends” section, we discuss developments in the electric and gas industry developments, market risk sensitive instruments and positions, and accountingother matters. Each of these discussions will address the current status and potential future impact on our financial position or results of operations and financial condition.operations.
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 available supplier, and we are compensated through a transportation charge.certified supplier. The following sections further discuss the current status of federalderegulation legislation and state energy policies and deregulation legislationother significant regulatory developments in the states of Ohio, Indiana, and Kentucky, each of which includes a portion ofencompass our utility service territory.territories.
Energy Bill
The U.S. House of Representatives (House) passed the Energy Policy Act in April 2003. The legislation, as passed in the House, included the repeal of the PUHCA, as well as tax incentives for gas and electric distribution lines, and combined heat and power and renewable energy projects. The U.S. Senate (Senate) Energy and Natural Resources Committee passed its version of comprehensive energy legislation in April 2003. A conference agreement which merged both the House and Senate versions passed in the House in October 2003, but failed to pass in the Senate. The legislation can be considered during this session of Congress, however many disputed issues remain and it is unclear whether or not legislation will pass this year.
Clear Skies Legislation
President Bush has proposed environmental legislation that would combine a series of Clean Air Act requirements, including the recently proposed regulations for mercury and particulate matter for coal-fired power plants with a legislative solution that includes trading and specific emissions reductions and timelines to meet those reductions. The President’s “Clear Skies Initiative” would seek an overall 70 percent reduction in emissions from power plants over a phased-in reduction schedule beginning in 2010 and continuing through 2018. The Senate Environment and Public Works Committee has held several hearings on the “Clear Skies Initiative” proposal. It is unclear whether or not this legislation will be considered in 2004.
69
CG&E is in a market development period for residential customers and in the competitive retail electric market for non-residential customers, transitioning to deregulation of electric generation and a competitive retail electric service market in the state of Ohio. The transition period is governed by the Amended Substitute Senate Bill No. 3 (Electric Restructuring Bill) and a stipulated transition plan adopted and approved by the PUCO. The Electric Restructuring Bill provides for a market development (frozen rate) period that began January 1, 2001, and ends no later thanended December 31, 2005.2004 for non-residential customers and is scheduled to end December 31, 2005 for residential customers.
The major featuresCG&E made multiple rate filings in 2003 with the PUCO seeking approval of CG&E’s transitionmethodology for establishing market-based rates for generation service at the end of the market development period and to recover investments made in the transmission and distribution system. The PUCO requested in these proceedings that CG&E propose a RSP to mitigate the potential for significant rate increases when the market development period comes to an end. In January 2004, CG&E filed its proposed RSP. In May 2004, CG&E entered into a settlement agreement with many of the parties to these proceedings requesting that the PUCO approve a modified version of the RSP. In September 2004, the PUCO issued an order seeking to modify several key provisions of this settlement and as a result of these modifications, CG&E filed a petition for rehearing in October 2004. The PUCO approved a modified version of the plan include:in November 2004, the major features of which are as follows:
• Residential customer rates are frozen through December 31, 2005;
• Residential customers received a five-percent reduction in the generation portionProvider of their electric rates, effective January 1, 2001;
•CG&E Last Resort (POLR) Charge:will provide $4 million from 2001 to 2005 in support of energy efficiency and weatherization services for low income customers;
• CG&E will begin to collect a POLR charge from non-residential customers effective January 1, 2005, and from residential customers effective January 1, 2006. The POLR charge includes several discrete charges, the most significant being an annually adjusted component (AAC) intended to provide shopping creditscost recovery primarily for environmental compliance expenditures; an infrastructure maintenance fund charge (IMF) intended to provide compensation to CG&E for committing its physical capacity to meet its POLR obligation; anda system reliability tracker (SRT) intended to provide cost recovery for capacity purchases, purchased power, reserve capacity, and related market costs for purchases to meet capacity needs. We anticipate the collection of the AAC and IMF will result in an approximate $36 million increase in revenues in 2005 and an additional $50 million in 2006. The SRT will be billed based on dollar-for-dollar costs incurred. A portion of these charges are avoidable by certain customers who switch to an alternative generation supplier. Therefore, these estimates are subject to change, depending on the level of switching customers;
that occurs in future periods. In 2007 and 2008, •CG&E The creation could seek additional increases in the AAC component of a Regulatory Transition Charge (RTC) designed to recoverthe POLR based on CG&E’s regulatory assets and other transitionactual net costs over a ten-year period;for the specified expenditures.
• AuthorityGeneration Rates and Fuel Recovery: A new rate has been established for generation service after the market development period ends. In addition, a fuel cost recovery mechanism will be established to recover costs 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 will apply to
68
non-residential customers beginning January 1, 2005 and to transfer its generation assets to one or more, non-regulated affiliates to provide flexibility to manage its generation asset portfolio in a manner that enhances opportunities in a competitive marketplace;
• Authority for CG&E to apply the proceeds of transition cost recovery to costs incurred during the transition period, including implementation costs and purchased power costs that may be incurred by CG&E to maintain an operating reserve margin sufficient to provide reliable service to its customers;
• Authority for CG&E to adjust the amortization of its regulatory assets and other transition costs to reflect the effects of any shopping incentives provided to customers; andresidential customers beginning January 1, 2006.
• CG&EGeneration Rate Reduction: will provide standard offer default supplier service (i.e., CG&E will be the supplier of last resort, so that no customer will be without an electric supplier).
UnderThe existing five percent generation rate reduction required by statute for residential customers implemented under CG&E’s transition2000 plan retail customers continue to receive transmission and distribution services fromwill end on December 31, 2005.
• CG&ETransmission Cost Recovery: , but may purchase electricity from another supplier. Retail customers that purchase electricity from another supplier receive shopping credits from CG&E. The shopping credits generally reflect the costs of electric generation included in CG&E’s frozen rates. However, shopping creditsTransmission cost recovery mechanisms will be established beginning January 1, 2005 for the first 20 percent of electricity usage in each customer class to switch suppliers are higher than shopping credits for subsequent switchers in order to stimulate the development of the competitive retail electric service market.
CG&E recovers its generation-related regulatory assets and certain other deferred transition costs through an RTC paid by all retail customers. As the RTC is collected from customers, CG&E amortizes the deferred balance of regulatory assets and other transition costs. A portion of the RTC collected from customers is recognized currently as a return on the deferred balance of regulatory assets and other transition costs and as reimbursement for the difference in the shopping credits provided to retailnon-residential customers and the wholesale revenues from generation made available by switchedJanuary 1, 2006 for residential customers. The ability oftransmission cost recovery mechanisms will permit CG&E to recover its regulatory assetsMidwest ISO charges, all FERC approved transmission costs, and other transitionall congestion costs is dependent on several factors, including, but not limitedallocable to retail ratepayers that are provided service by CG&E.
•Distribution Cost Recovery: CG&E will have the level ofability 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 beginning January 1, 2006 through December 31, 2010.
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CG&E’s&E had also filed an electric distribution base rate case for residential and non-residential customers to be effective January 1, 2005. Under the terms of the RSP described previously, CG&E electric sales, priceswithdrew this base rate case and, in the wholesale power markets, and theFebruary 2005, CG&E filed a new distribution base rate case with rates to become effective January 1, 2006. The requested amount of customers switchingthe increase is approximately $78 million.
The RSP provides for rate recovery through December 31, 2008. Although it is difficult to otherpredict, 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 suppliers.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.
In January 2003,December 2004, CG&E filed an application with the PUCO for approvalrequesting recovery of a methodology to establish how market-based rates for non-residential customers will be determined when the market development period ends. In the filing, CG&E seeks to establish a market-based standard service offer rate for non-residential customers that do not switch suppliers and a process for establishing the competitively-bid generation service option required by the Electric Restructuring Bill. As of December 31, 2002, more than 20 percent of the load of CG&E’s commercial and industrial customer classes had switched to other electric suppliers, and the other public authorities group was at 19.95 percent at December 31, 2003. Under its transition plan, CG&E may end the market development period for those classes of customers once 20 percent switching has been achieved; however, PUCO approval of the standard service offer rate and competitive bidding process is required before the market development period can be ended.
In December 2003, the PUCO issued an order that the CG&E application filed in January 2003 would proceed to a hearing and be consolidated with CG&E’s application to defer certain administrative transmission charges and the application to deferfuture costs of capital investments made to their transmission and distribution system duringadditional generating facilities in Ohio, for either construction of new electric generating facilities or the market development period. As partpurchase of this order, the PUCO requested that CG&E file a rate stabilization plan to mitigate the effects of market based pricing on retail customers while the competitive retail electric market continues to mature. In response to this request, on January 26, 2004, CG&E filed an offer of settlement, including an electric reliability and rate stabilization plan. In this proposal, CG&E has also asked to end the market development period for all customers effective December 31, 2004.
The major features of CG&E’s electric reliability and rate stabilization plan include:
• The market development period would end for all customers on December 31, 2004;
•existing assets currently owned by others. CG&E would beginseek recovery of these costs over the lives of the assets. These investments are needed to collect a non-bypassable Provider of Last Resort (POLR) chargemeet ongoing load growth by customers receiving generation service from all customers effective January 1, 2005. This charge could be increased by up to 10 percent of CG&E’s generation charge each year from 2005 through 2008;
• CG&E and would offerenable the company to reliably meet its current generation ratesobligation as its market based rates until December 31, 2008;
•the provider of last resort for customers returning to CG&E would request a transmission and distribution rate increase effective January 1, 2005;
•CG&E would begin charging RTC as an explicit wires charge;
• PUCO approval of previously requested transmission and distribution deferrals andfrom alternate suppliers. To maintain flexibility in providing electric service at the lowest cost, recovery riders (see “CG&E Transmission and Distribution Rate Filings”);
• The five percent generation rate reduction for residential customers would continue through 2008;
• Extend recovery of residential RTC from 2008 through 2010.
The POLR charge would allow for recovery of increased costs of fuel and purchased power, transmission congestion, environmental compliance, homeland security, taxes and maintaining
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an adequate reserve margin.
An evidentiary hearing addressing the issues described above is scheduled for the second quarter of 2004. At the current time CG&E is unablealso seeking the authority to predictpurchase existing capacity and power from other suppliers and to earn a return commensurate with the outcome of this proceeding or the effects it could have on its results of operations or financial condition.risk from these agreements.
In 2002, Indiana lawmakers anticipated the creationWe are not aware of an Indiana Energy Policy Commission to assist in the creation of a comprehensive energy plan. However, no such commission was formed and, as a result, there are noany current plans for electric deregulation in Indiana.
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 results in an approximate $140 million increase in annual revenues. PSI’s original request for an approximate $180 million annual revenue increase was reduced by approximately $20 million for a lower return on equity, approximately $15 million of assumed profits included in base rates related to off-system sales (subject to future adjustment through a tracking mechanism and a 50/50 sharing agreement), and approximately $5 million of additional items. The order authorizes full recovery of all requested regulatory assets and an overall 7.3 percent return, including a 10.5 percent return on equity. In addition, the IURC’s order provides 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.
Cinergy is studying the feasibility of constructing a commercial integrated coal gasification combined cycle (IGCC) generating station to
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help meet increased demand over the next decade. PSI would own all or part of the facility and operate it. Cinergy will partner with Bechtel Corporation and General Electric Company to complete this study. 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 CO2 upstream of the combustion process at a lower cost than conventional plants. 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.
In November 2004,PSI filed a compliance plan case with the IURC seeking approval of PSI’s plan for complying with pending SO2, NOX, and mercury emission reduction requirements, 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 operating and maintenance costs, among others, related to approximately $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 is scheduled for April 2005 and a final IURC Order is expected in the third quarter of 2005.
Throughout 1999, a special Kentucky Electricity Restructuring Task Force (Task Force), convened by the Kentucky legislature, studied the issuesWe are not aware of any current plans for electric deregulation. In January 2000, the Task Force issued a final report to former Kentucky Governor Paul Patton recommending that lawmakers wait until the 2002 General Assembly before considering any deregulation that would open the state’s electric industry to competition. The state legislature did not take any action in either 2002 or 2003 to move Kentucky towards electric deregulation.
At the end of 2000, approximately one half of the states and the District of Columbia had adopted deregulation plans. However, recent events are significantly influencing political and legislative activity. At the end of 2001, eight of the states decided to delay or suspend their deregulation activities. No additional states adopted deregulation plans during 2002 or 2003, and two states repealed their deregulation statutes during 2003.
In December 2002, the IURC approved a settlement agreement among PSI, the Indiana Office of the Utility Consumer Counselor, and the IURC Testimonial Staff authorizing PSI’s purchases of the Henry County, Indiana and Butler County, Ohio, gas-fired peaking plants from two non-regulated affiliates. In February 2003, the FERC issued an order under Section 203 of the Federal Power Act authorizing PSI’s acquisitions of the plants, which occurred on February 5, 2003. Subsequently, in April 2003, the FERC issued a tolling order allowing additional time to consider a request for rehearing filed in response to the February 2003 FERC order. At this time, the rehearing request is still pending before the FERC, and PSI cannot predict the outcome of this matter.Kentucky.
In July 2003,The KPSC has conditionally approved ULH&P&P’s filed an application with the KPSC requesting a certificateplanned acquisition of public convenience and necessity to acquire CG&E’s 68.9 percent ownership interest in the East Bend Generating Station, located in Boone County, Kentucky, the Woodsdale Generating Station, located in Butler County, Ohio, and one generating unit at the four-unit Miami Fort Station located in Hamilton County, Ohio. In December 2003,ULH&P is currently seeking approval of the KPSC conditionally approved this
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application.transaction from the SEC, wherein the Ohio Consumers Counsel has intervened in opposition, and the FERC. The transfer, which will be madepaid for at net book value, will not affect current electric rates for ULH&P’s customers, as power will be provided under the same terms as under the current wholesale power contract with CG&E through at least December 31, 2006. Assuming receipt of regulatory approvals, we would anticipate the transfer to take place in the second quarter of 2005. Once approved, ULH&Pwould be required to file a rate case with the KPSC to include these assets in rate base with rate increases to be effective January 1, 2007. Costs of fuel and emission allowances would be recovered through a fuel adjustment clause currently in existence in Kentucky, beginning January 1, 2007 when the assets are in rate base. Because the KPSC has already conditionally approved the transfer, we expect the regulatory process to result in a reasonable rate base valuation for these assets; however, at this time we cannot predict whether we will also seek regulatoryreceive approval for aspects of thisthe transaction from the FERC and SEC. At this time, ULH&P is unable to predict the outcome of this matter.
Under generally accepted accounting principles (GAAP), CG&E, PSI, and ULH&P apply the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (Statement 71) to the applicable rate-regulated portions of their businesses. The provisions of Statement 71 allow CG&E, PSI, and ULH&P to capitalize (record as a deferred asset) costs that would normally be charged to expense. These costs are classified as regulatory assets in the accompanying financial statements, and the majority have been approved by regulators for future recovery from customers through our rates. As of December 31, 2003, our operating companies have approximately $1 billion of net regulatory assets, of which approximately 90 percent has been approved for recovery.
Except with respect to the generation assets of CG&E, as of December 31, 2003, our operating companies continue to meet each of the criteria required for the application of Statement 71. However, to the extent other states implement deregulation legislation, the application of Statement 71 will need to be reviewed. Based on our operating companies’ current regulatory orders and the regulatory environment in which they currently operate, management believes the future recovery of regulatory assets recognized in the accompanying Balance Sheets as of December 31, 2003, is probable. See Note 1(c) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for a further discussion of our regulatory assets.
As part of the effort to create a competitive wholesale power marketplace, the FERC approved the formation of the Midwest ISO during 1998. In that same year, Cinergy agreed to join the Midwest ISO in preparation for meeting anticipated changes in the FERC regulations and future deregulation requirements. The Midwest ISO wasis a regional transmission organization established in 1998 as a non-profit organization to maintainwhich maintains functional control over the combined transmission systems of its members.
The FERC has also approved the formation of the PJM Interconnection, LLC (PJM) and has ordered the Midwest ISO, PJM, and various other parties to establish certain protocols in an attempt to create a structured, connected market among all utility companies.
The FERC issued an order in December 2001, in response to protests of the Midwest ISO’s proposed methodology related to the calculation of its administrative adder fees for the services it provides. Cinergy and a number of other parties filed protests to the proposed methodology, suggesting, among other things, that the methodology was inconsistent with the transmission
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owners’ prior agreement with the Midwest ISO and selectively allowed only independent transmission companies to choose which unbundled administrative adder services they wished to purchase from the Midwest ISO. A partial settlement was reached in the FERC proceeding, resolving the issues addressed by Cinergy’s protest in a manner satisfactory tomembers, including Cinergy. The settlement agreement was approved by the FERC in a February 2003 order with implementation initiated onIn March 1, 2003. The settlement resulted in approximately $25 million of administrative adder credits to be shared among the Midwest ISO transmission owners and customers responsible for administrative charges. Cinergy’s share was approximately $3 million.
The FERC issued a Notice of Proposed Rulemaking (NOPR) in 2002 on “Remedying Undue Discrimination through Open Access Transmission Service and SMD”. This NOPR would have required all public utilities with open access transmission tariffs to file modifications to their tariffs to implement FERC’s proposed standardized transmission services and standardized wholesale electric market design. The FERC has not taken action on this NOPR. In addition, because we are a member of the Midwest ISO and the Midwest ISO is actively moving forward in an attempt to create a structured market, it is unlikely that the FERC’s SMD NOPR will have a material, if any, effect on our financial position or results of operations.
In response to prior FERC orders, in July 2003,2004, 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 MarketsMarket design, including Locational Marginal Pricing and Financial Transmission Rights (Energy Markets Tariff). In October 2003, the FERC approved aThe Midwest ISO filing to withdraw thisis now in the final stages of market trials and testing of its Energy Markets Tariff. The FERC has issued orders that, among other things, conditionally approve the start-up of the Energy Markets Tariff. The projected implementation date is April 1, 2005. Requests for rehearing are pending before FERC, and FERC’s orders have also been appealed to a federal appeals court.
Specifically, the Energy Markets Tariff proposes to manage system reliability through the use of a market-based congestion management system. The proposal 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 Locational Marginal Pricing (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 Financial Transmission Rights, 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
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proposes both an interim solution for participants providing and having access to adequate generation resources as well as a proposal to develop a long-term solution to resource adequacy concerns. The Midwest ISO will perform a day-ahead unit commitment and dispatch forecast for all resources in its market. The Midwest ISO will also perform the real time resource dispatch for resources under its control on a five minute basis. The Cinergy anticipatesutility operating companies will seek to recover costs that they incur related to the Energy Markets Tariff. This is a significant undertaking by the Midwest ISO and its stakeholders and testing is not yet complete. At this time, we cannot predict the outcome of these matters and whether they will filehave a material effect on our financial position or results of operations.
In April 2004, the United States-Canada Power System Outage Task Force issued its Final Report on the August 14, 2003 Blackout in the United States and Canada. The report reviewed the causes of the Blackout and made 46 recommendations intended to minimize the likelihood and scope of similar events in the future. One of the recommendations is to make reliability standards mandatory and enforceable with penalties for noncompliance. In the past, compliance with North American Electric Reliability Council’s reliability standards and guidelines has largely been voluntary. At this time, we do not believe the recommendations of the Final Report, if implemented, will have a material impact on our financial position or results of operations.
In April 2004, the FERC issued an order establishing a new, Energy Markets Tariffinterim set of market power screens for use in evaluating sales of wholesale power at sometime inmarket-based rates. In July 2004, the future; however, at this time,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 interim generation market power analysis, as a member of the Midwest ISO, Cinergy could consider the Midwest ISO geographic market for purposes of FERC’s market power analysis once the Midwest ISO has a sufficient market structure and a single energy market. Cinergy does not believe it has market power in generation. However, if Cinergy were unable to establish that it does not have the ability to exercise market power in generation, it could result in the loss of market-based rate authority in certain regions of the wholesale market and, assuming such loss of market-based rate authority, would require Cinergy to charge certain wholesale customers cost-based rates for wholesale sales of electricity. In February, 2005, FERC issued final rules that may affect how and when circumstances have changed to an extent that requires FERC review of previously granted authorization to sell at existing market-based rates. At this time, we cannot predict the effect any such filingoutcome of these matters and whether they will have a material effect on itsour financial position or results of operations.
In December 2002, PSI filedPresently, 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 petition withmandatory program to reduce GHG emissions will exist in the IURC seeking approvalfuture. We expect that any regulation of a base retail electric rate increase. PSI has filed initial and rebuttal testimony in this case and the final set of hearings took place in November 2003. PSI filed its proposed order in December 2003. Based on updated testimony filed in October 2003 and the proposed order, PSI proposes an increase in annual revenues of approximately $180 million, or an average increase of approximately 14 percent over PSI’s retail electric rates in effect at the end of 2002. An IURC decision is anticipated by the end of the first quarter of 2004.
In June 2001, PSI filed a petition with the IURC requesting authority to recover $16 million in under billed deferred fuel costs incurred from March 2001 through May 2001. The IURC
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approved recovery of these costs subject to refund pending the findings of an investigative sub-docket. The sub-docket was opened to investigate the reasonableness of, and underlying reasons for, the under billed deferred fuel costs. A hearing was held in July 2002, and in March 2003 the IURC issued an order giving final approval to PSI’s recovery of the $16 million.
In April 2003, PSI filed an application with the IURC requesting that its CWIP rate adjustment mechanism be updated for expenditures through December 2002 related to NOX equipment currently being installed at certain PSI generation facilities. CWIP ratemaking treatment allows for the recovery of carryingGHGs will impose costs on certain pollution control equipment while and afterCinergy. Depending on the equipment is under construction. A final order was issued in September 2003. The order granted substantially all of PSI’s requested relief, leaving only the issue of whether certain specific equipment qualified for CWIP ratemaking treatment to be decided in the first half of 2004. This CWIP rate mechanism adjustment resulted in less than a one percent increase in customer rates.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 operating 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.
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In OctoberSeptember 2003, PSICinergy filed an application withannounced a voluntary GHG management commitment to reduce its GHG emissions during the IURC requesting thatperiod from 2010 through 2012 by five percent below our 2000 level, maintaining those levels through 2012. This was also published in our December 2004 Air Issues Report to Stakeholders. Cinergy expects to spend $21 million between 2004 and 2010 on projects to reduce or offset its CWIP rate adjustment mechanism be updated for additional expenditures through September 30, 2003, relatedGHG emissions. Cinergy is committed to NOX equipment currently being installed at certain PSI generation facilities. Ifsupporting the application is approved, it will resultPresident’s voluntary initiative, addressing shareholder interest in the recoveryissue, and building internal expertise in GHG management and GHG markets. Our voluntary commitment includes the following:
•measuring and inventorying company related sources of an additional $7 million. An order on this third CWIP update case is expectedGHG 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 first half of 2004.policy debate.
PSI’sCinergy initial CWIP rate mechanism adjustment (authorized in July 2002) resulted in an approximately one percent increase in customer rates. Under is also studying the IURC’s CWIP rules, PSI may update its CWIP tracker at six-month intervals.feasibility of constructing a commercial IGCC generating station. The first such updateIGCC plant would be expected to PSI’s CWIP rate mechanism occurred inrun more efficiently than traditionally constructed coal-fired generation and would thus contribute fewer CO2 tons per megawatt of electricity produced. See the first quarter of 2003. The IURC’s July 2002 order also authorized PSIprevious section “Indiana” for more details on the plans to defer, for subsequent recovery, post-in-service depreciation and to continueconstruct the accrual for allowance for funds used during construction (AFUDC). Pursuant to Statement of Financial Accounting Standards No. 92, Regulated Enterprises-Accounting for Phase-in Plans, the equity component of AFUDC will not be deferred for financial reporting after the related assets are placed in service.
In 2002, the Indiana General Assembly passed legislation that, among other things, encourages the deployment of advanced technologies that reduce regulated air emissions, while allowing the continued use of high sulfur Midwest coal in existing electric generating plants. The legislation authorizes the IURC to provide financial incentives to utilities that deploy such advanced technologies. PSI soughtIURC approval, under this new law, of a cost tracking mechanism for PSI’s NOX equipment-related depreciation and operation and maintenance costs, authority to use accelerated (18-year) depreciation for its NOX compliance equipment, and approval of a NOX emission allowance purchase and sales tracker. In October 2003, PSI reached a settlement with the other parties to this case that provides for the relief described above for most of PSI’s environmental compliance equipment. In December 2003, the IURC approved the settlement agreement. Previously, the majority of these costs (the post-in-service depreciation costs) were being deferred pursuant to the July 2002 CWIP order described above, and as a result, the settlement agreement did not have a material impact on PSI’s results of operations or financialIGCC facility.
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condition.
The Tracker was designed to provide for the recovery of costs related to certain specified purchases of power necessary to meet native load customers’ summer peak demand requirements to the extent such costs are not recovered through the existing fuel adjustment clause.
PSI is authorized to seek recovery of 90 percent of its purchased power expenses through the Tracker (net of the displaced energy portion recovered through the fuel recovery process and net of the mitigation credit portion), with the remaining 10 percent deferred for subsequent recovery in PSI’s general retail electric rate case. In March 2002, PSI filed a petition with the IURC seeking approval to extend the Tracker process beyond the summer of 2002. A hearing was held in January 2003, and in June 2003 the IURC approved the extension for up to an additional two years with the ultimate determination concerning PSI’s continued use of the Tracker process to be made in PSI’s pending retail electric rate case.
In June 2002, PSI also filed a petition with the IURC seeking approval of the recovery through the Tracker of its actual summer 2002 purchased power costs. In May 2003, the IURC approved PSI’s recovery of $18 million related to its summer 2002 purchased power costs, and also authorized $2 million of deferred costs sought for recovery in PSI’s general retail electric rate case.
In October 2003, CG&E filed an application with the PUCO seeking deferral of approximately $173 million, of which approximately $42 million has been incurred as of December 31, 2003, in depreciation, property taxes and carrying costs related to net additions to transmission and distribution utility plant in service from January 2001 through December 2005. Rates are frozen in Ohio under the state’s electric restructuring law from 2001 through the end of the market development period. CG&E has not deferred any of these costs as of December 31, 2003.
CG&E is proposing a mechanism to recover costs related to net additions to transmission and distribution utility plant in service after the end of the market development period. The mechanism would work in a similar manner to the monthly customer charge the PUCO approved for CG&E’s accelerated natural gas main replacement program, discussed belowin “CG&E Gas Rate Case”, which is adjusted annually based on expenditures in the previous year.
In the alternative electric reliability and rate stabilization proposal that CG&E filed in January 2004 with the PUCO, which is described in more detail in “Ohio” above, CG&E made an alternative proposal to seek deferrals of transmission and distribution utility plant in service from January 2003 through December 2004, for the PUCO to declare an end to the market development period effective December 31, 2004, and for CG&E to file a transmission and distribution base rate case in 2004 to be effective January 1, 2005. The alternative proposal also includes tracking mechanisms as described in the preceding paragraph, which would recover ongoing transmission and distribution costs.
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In the third quarter of 2001, CG&E filed a retail gas rate case with the PUCO seeking to increase base rates for natural gas distribution service and requesting recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with an estimated capital cost of $716 million over 10 years. An order was issued in May 2002, in which the PUCO authorized a base rate increase of approximately $15 million, or 3.3 percent overall, effective May 30, 2002. In addition, the PUCO authorized CG&E to implement the tracking mechanism to recover the costs of the accelerated gas main replacement program, subject to certain rate caps that increase in amount annually through May 2007, through the effective date of new rates in CG&E’s next retail gas rate case. In April 2003, CG&E received approval to increase its rates under the tracking mechanism by $6.5 million. This increase was effective in May 2003. CG&E filed another application in January 2004 to increase its rates by approximately $7 million under the tracking mechanism. CG&E expects that the PUCO will rule on this application in the second quarter of 2004.
In the second quarter of 2001, ULH&P filed a retail gas rate case with the KPSC seeking to increase base rates for natural gas distribution services and requesting, among other things, recovery through a tracking mechanism of the costs ofassociated with an accelerated gas main replacement program with an estimated capital cost of up to $112 million over 10ten years. The costs would be recovered through a tracking mechanism for an initial three year period, with the possibility of renewal up to ten years. The tracking mechanism allows ULH&P to recover depreciation costs and rate of return annually over the life of the deferred assets. Through December 31, 2003,2004, ULH&P has recovered approximately $1.4$5.1 million under this tracking mechanism. The Kentucky Attorney General has appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism and the KPSC’s orders approving the new tracking mechanism rates. At the present time, ULH&P cannot predict the timing or outcome of this litigation.
In June 2003, the PUCO approved an amended settlement agreement betweenFebruary 2005, 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. Cinergy has an estimated 190,000 SHA risers on its distribution system, of which 155,000 are in CG&E’s service area and 31,000 are in ULH&P’s service area. Further investigation as to whether any additional SHA risers will need maintenance or replacement is ongoing. If CG&E andULH&P determine that replacement of all SHA risers is appropriate, we currently estimate thatfiled a gas base rate case with the replacement cost could be up to approximately $70 million. KPSC.CG&E andULH&P would pursue recovery of this cost throughis requesting approval to continue the tracking mechanism in addition to its request for a $14 million increase in base rates, which is a seven percent increase in current retail gas rates. At this time, Cinergy, CG&E, and ULH&P cannot predict the outcome of this matter.
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Natural gas prices escalated dramatically during the fourth quarter of 2002 and peaked midway through the first quarter of 2003. These higherWhile natural gas prices moderated throughoutremained relatively high during the spring and summerfirst three quarters of 2003 but for 2004, are expected to remain higher than previous years.some moderation in prices was seen in the latter half of the fourth quarter. Price movement will beis usually driven by the effects of weather conditions, availability of supply, and changes in demand and storage inventories. Currently, neither CG&E nor ULH&P profit from changes in the cost of natural gas since 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. These higher natural gas prices could lead to decreases in the purchase price obtained on receivables sold to Cinergy Receivables due to an increased concern regarding realization of those receivables, however we believe the overall impact will be immaterial.
In July 2003, CG&E filed an application with the PUCO for approval to begin adjusting its gas cost adjustment rates on a monthly basis commencing in September 2003. In August 2003, the PUCO approved the change from quarterly to monthly. In September 2003, ULH&P filed utilizes a similar application with the KPSC for monthly gas cost adjustment rates. The KPSC approved this change and ULH&P began billing on a monthly basis in December 2003.
In May 2003, ULH&P filed an application with the KPSC requesting approval of a gas procurement-hedgingprice mitigation program designed to mitigate the effects of gas price volatility on customers. In June 2003,customers, which the KPSC has approved the hedging program through March 31, 2005. The program will allowallows 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 hedgesmitigates its gas procurement costs, however, CG&E’s gas procurement-hedgingprice 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.
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CG&E and ULH&P use primarily long-term fixed price forward 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 hedges under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities133. (Statement 133).
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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.
In July 2002, Cinergy Capital & Trading, Inc. acquired a coal-based synthetic fuel production facility. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with Internal Revenue Code (IRC) Section 29 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. In addition to the existing plant, we have recently exercised an option to buy an additional synthetic fuel plant.
During the third quarter of 2004, several unrelated entities announced that the Internal Revenue Service (IRS) had or threatened to challenge the placed in service dates of some of the entities’ synthetic fuel plants. A successful IRS challenge could result in disallowance of all credits previously claimed for fuel produced by the subject plants. Cinergy’s sale of synthetic fuel has generated approximately $219 million in tax credits through December 31, 2004, of which approximately $96 million were generated in 2004.
The IRS has not yet audited Cinergy for any tax year in which Cinergy has claimed Section 29 credits related to synthetic fuel. However, it is reasonable to anticipate that the IRS will evaluate the placed in service date and other key requirements for claiming the credit. We anticipate this audit to begin in the spring of 2005.
Cinergy received a private letter ruling from the IRS in connection with the acquisition of the facility that specifically addressed the significant chemical change requirement. Additionally, although not addressed in the letter ruling, we believe that our facility’s in service date meets the Section 29 requirements.
IRC Section 29 also provides for a phase-out of the credit based on the price of crude oil. The phase-out is based on a prescribed calculation and definition of crude oil prices. We do not expect any impact on our ability to utilize Section 29 credits in 2004. Future increases in crude oil prices above the price stipulated by the IRS could negatively impact our ability to utilize credits in subsequent years.
74
MD&A - MARKET RISK SENSITIVE INSTRUMENTS
The transactions associated with Commercial Business Units’ (Commercial) (formerly named the Energy Merchant Business Unit)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, (and due to its substantial investment in generation assets), 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 Cinergy Global Trading Limited’s (Global Trading) European natural gas and power trading operations, and CG&E’s and PSI’s power marketing and trading operations.
78
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 Midwestmidwest region of the U.S.)United States), natural gas, and other energy-related products.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. Global
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 for the purchase and sale of natural gas and electricity (both primarily in the United Kingdom). Global Trading also trades natural gas on the International Petroleum Exchange.contracts.
Many of thethese energy commodity contracts in both the accrual and trading portfolios 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 and for Cinergy in total.operation.
Value at RiskTrading Portfolio Risks (VaR)
Commercial measures the market risk inherent in the trading portfolio employing VaRvalue 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
75
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.
79
Any proprietary trading transaction, whether settled physically or financially, that is accounted for at fair value 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 changelose more than the stated amount. OurPrior to March 31, 2004, our VaR model usesused the Parametric variance-covariance statistical modeling technique and historical volatilities and correlations over the past 21-trading day period. The average VaR was calculated using an average of trading days over the entire year and the high and low VaR were based on an entire year of trading day calculations. The market prices used toBeginning with April 1, 2004, we calculate VaR are obtained from exchangesusing a Monte Carlo simulation methodology using implied forward-looking volatilities and over-the-counter markets when available, established pricing modelshistorical correlations. Comparisons indicated that the differences in VaR between the Monte Carlo and other factors includingParametric calculations were not material and were within expectations. The primary reason for changing to a Monte Carlo approach is that it offers a more scalable method for handling more complex derivative positions and provides a consistent platform for quantifying both market volatility, the time value of money, and location differentials. credit risk.
The VaR for Cinergy’s trading portfolio is presented in the table below:
VaR Associated with Energy Trading Contracts 2004 2003 Trading VaR Percentage of Operating Income Trading VaR Percentage of Operating Income (dollars in millions) 95% confidence level, one-day holding period, one-tailed December 31 2003 2002 Trading Percentage Trading VaR Percentage of (dollars in millions) 95% confidence level, one-day holding period, one-tailed December 31 $ 0.6 0.1 % $ 1.6 0.2 % Average for the twelve months ended December 31 1.3 0.2 2.1 0.3 High for the twelve months ended December 31 3.8 0.7 3.7 0.5 Low for the twelve months ended December 31 0.4 0.1 0.5 0.1 $ 1.9 0.3 % $ 0.6 % 2.4 0.3 1.3 0.2 High for the Change in Fair Value 2003 2002 Cinergy(1) CG&E PSI Cinergy(1) CG&E PSI (in millions) Fair value of contracts outstanding at the beginning of period $ 75 $ 42 $ — $ 18 $ 28 $ (7 ) Inception value of new contracts when entered(2) — — — 6 5 1 Changes in fair value attributable to changes in valuation techniques and assumptions(3) 1 1 — 14 6 9 Other changes in fair value(4) 127 53 2 89 26 5 Option premiums paid/(received) (3 ) 2 — 20 1 — Accounting Changes(5) Cumulative effect of changes in accounting principles (20 ) (13 ) (1 ) — — — Consolidation of previously unconsolidated entities 7 — — — — — Contract reclassification(6) — — — 14 18 5 Contract acquisitions(7) — — — (16 ) — — Contracts settled (146 ) (65 ) (4 ) (70 ) (42 ) (13 ) Fair value of contracts outstanding at end of period $ 41 $ 20 $ (3 ) $ 75 $ 42 $ — 5.8 0.8 3.8 0.1 0.4 2003 2002 Cinergy(1) CG&E PSI Cinergy(1) CG&E PSI (in millions) Energy risk management assets - current $ 305 $ 73 $ 8 $ 464 $ 58 $ 9 Energy risk management assets - non-current 97 37 7 163 65 16 Energy risk management liabilities - current (296 ) (78 ) (15 ) (408 ) (49 ) (8 ) Energy risk management liabilities - non-current (65 ) (12 ) (3 ) (144 ) (32 ) (17 ) $ 41 $ 20 $ (3 ) $ 75 $ 42 $ — 0.1 76
VaR
of
Operating
Income
Operating
Income800.1Changes in Fair ValueThe changes in fair value of the energy risk management assets and liabilities for Cinergy, CG&E, and PSIAverage for the yearstwelve months ended December 31 2003 and 2002 are presented intable below:twelve months ended December 31(1)The results of Cinergy also include amounts related to non-registrants.0.5(2)Represents fair value, recognized in income, attributable to long-term, structured contracts, primarily in power, which is recorded on the date a deal is signed. These contracts are primarily with end-use customers or municipalities that seek to limit their risk to power price volatility. While caps and floors often exist in such contracts, the amount of power supplied can vary from hour to hour to mirror the customers’ load volatility. See Note 1(q)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information regarding inception gains.(3)Represents changes in fair value recognized in income, caused by changes in assumptions used in calculating fair value or changes in modeling techniques.(4)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.(5)See Note 1(q)(iv) and Note 1(q)(vi) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.(6)Represents reclassifications of the settlement value of contracts that have been terminated as a result of counterparty non-performance to Non-Current Liabilities-Other. These contracts no longer have price risk and are therefore not considered energy trading contracts.(7)Cinergy Capital & Trading, Inc. (Capital & Trading) acquired a portfolio of gas contracts and inventory in July 2002. This amount represents the fair value of net Energy risk management liabilities assumed. There was no inception gain or loss recognized at the date of acquisition.81Low for the twelve months ended December 31The following are the balances at December 31, 2003 and 2002 of our energy risk management assets and liabilities:0.7
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, 2004 and 2003 are presented in the table below. In April 2002, CG&E and PSI executed a new joint operating agreement whereby we chose to originate all new power marketing and trading contracts since April 2002 on behalf of CG&E only. Historically, such contracts were executed on behalf of PSI and CG&E jointly. PSI’s remaining contracts, entered into prior to the new joint operating agreement, are not material. Therefore, we have not presented PSI separately in the fair value tables below.
|
| Change in Fair Value |
| ||||||||||
|
| 2004 |
| 2003 |
| ||||||||
|
| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
| ||||
|
| (in millions) |
| ||||||||||
Fair value of contracts outstanding at the beginning of period |
| $ | 41 |
| $ | 20 |
| $ | 75 |
| $ | 42 |
|
|
|
|
|
|
|
|
|
|
| ||||
Changes in fair value attributable to changes in valuation techniques and assumptions(2) |
| (5 | ) | (4 | ) | 1 |
| 1 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Other changes in fair value(3) |
| 185 |
| 70 |
| 127 |
| 53 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Option premiums paid/(received) |
| 5 |
| 6 |
| (3 | ) | 2 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Accounting Changes(4) |
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Consolidation of previously unconsolidated entities |
| — |
| — |
| 7 |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Cumulative effect of changes in accounting principles |
| — |
| — |
| (20 | ) | (13 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Contracts settled |
| (144 | ) | (56 | ) | (146 | ) | (65 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Fair value of contracts outstanding at end of period |
| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
|
(1)The results ofCinergyalso 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)See Note 1(q)(i) and Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
The following are the balances at December 31, 2004 and 2003 of our energy risk management assets and liabilities:
|
| 2004 |
| 2003 |
| ||||||||
|
| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
| ||||
|
| (in millions) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Energy risk management assets - current |
| $ | 381 |
| $ | 149 |
| $ | 305 |
| $ | 73 |
|
Energy risk management assets - non-current |
| 139 |
| 47 |
| 97 |
| 37 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Energy risk management liabilities - current |
| (311 | ) | (120 | ) | (296 | ) | (78 | ) | ||||
Energy risk management liabilities - non-current |
| (127 | ) | (40 | ) | (65 | ) | (12 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
|
| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
|
(1)The results of Cinergy also include amounts related to non-registrants.
77
The following table presents the expected maturity of the energy risk management assets and liabilities as of December 31, 2004 for Cinergy and CG&E:
|
| Fair Value of Contracts at December 31, 2004 |
| |||||||||||||
|
| Maturing |
|
|
| |||||||||||
Source of Fair Value(1) |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| Thereafter |
| Total Fair Value |
| |||||
|
| (in millions) |
| |||||||||||||
Cinergy(2) |
|
|
|
|
|
|
|
|
|
|
| |||||
Prices actively quoted |
| $ | 74 |
| $ | 18 |
| $ | — |
| $ | — |
| $ | 92 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Prices based on models and other valuation methods(3) |
| (4 | ) | (5 | ) | 2 |
| (3 | ) | (10 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 70 |
| $ | 13 |
| $ | 2 |
| $ | (3 | ) | $ | 82 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E |
|
|
|
|
|
|
|
|
|
|
| |||||
Prices actively quoted |
| $ | 25 |
| $ | 13 |
| $ | — |
| $ | — |
| $ | 38 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Prices based on models and other valuation methods(3) |
| 4 |
| (6 | ) | — |
| — |
| (2 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 29 |
| $ | 7 |
| $ | — |
| $ | — |
| $ | 36 |
|
(1) �� While liquidity varies by trading regions, active quotes are generally available for two years for standard electricity transactions and three years for standard gas transactions. 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.
(3)A substantial portion of these amounts include option values.
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 Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (Statement 149), most forward power 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 increase or decrease consistently applied to all forward power prices would have resulted in an increase or decrease in fair value of these contracts of approximately $3 million as of December 31, 2004.
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 are partially mitigated in 2005 and 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 will recover 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.
78
(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, 2003 for Cinergy, CG&E, and PSI:
|
| Fair Value of Contracts at December 31, 2003 |
| |||||||||||||
|
| Maturing |
| Total |
| |||||||||||
Source of Fair Value(1) |
| 2004 |
| 2005-2006 |
| 2007-2008 |
| Thereafter |
|
| ||||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cinergy(2) |
|
|
|
|
|
|
|
|
|
|
| |||||
Prices actively quoted |
| $ | (2 | ) | $ | 18 |
| $ | — |
| $ | — |
| $ | 16 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Prices based on models and other valuation methods(3) |
| 11 |
| 15 |
| 4 |
| (5 | ) | 25 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 9 |
| $ | 33 |
| $ | 4 |
| $ | (5 | ) | $ | 41 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E |
|
|
|
|
|
|
|
|
|
|
| |||||
Prices actively quoted |
| $ | (12 | ) | $ | 9 |
| $ | — |
| $ | — |
| $ | (3 | ) |
|
|
|
|
|
|
|
|
|
|
|
| |||||
Prices based on models and other valuation methods(3) |
| 7 |
| 14 |
| 2 |
| — |
| 23 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | (5 | ) | $ | 23 |
| $ | 2 |
| $ | — |
| $ | 20 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
PSI |
|
|
|
|
|
|
|
|
|
|
| |||||
Prices actively quoted |
| $ | (8 | ) | $ | 1 |
| $ | — |
| $ | — |
| $ | (7 | ) |
|
|
|
|
|
|
|
|
|
|
|
| |||||
Prices based on models and other valuation methods(3) |
| 1 |
| 2 |
| 1 |
| — |
| 4 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | (7 | ) | $ | 3 |
| $ | 1 |
| $ | — |
| $ | (3 | ) |
(1)While liquidity varies by trading regions, active quotes are generally available for two years for standard electricity transactions and three years for standard gas transactions. 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 tenor.
(2)The results of Cinergy also include amounts related to non-registrants.
82
(3)A substantial portion of these amounts include option values.
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, 2003,2004, 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 tenorlength 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.
8379
The following tables provide information regarding Cinergy’s, and CG&E’s, and PSI’s exposure on energy trading contracts as well as the expected maturities of those exposures.exposures as of December 31, 2004. 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.
Cinergy(1)
Rating |
| Total Exposure |
| Credit Collateral |
| Net Exposure |
| Percentage of |
| Number of |
| Net Exposure of |
| ||||
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(2) |
| $ | 737 |
| $ | 75 |
| $ | 662 |
| 84 | % | — |
| $ | — |
|
Internally Rated-Investment Grade(3) |
| 68 |
| 1 |
| 67 |
| 9 |
| — |
| — |
| ||||
Non-Investment Grade |
| 135 |
| 90 |
| 45 |
| 5 |
| — |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| 51 |
| 37 |
| 14 |
| 2 |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| — |
|
|
| ||||
Total |
| $ | 991 |
| $ | 203 |
| $ | 788 |
| 100 | % | — |
| $ | — |
|
Rating |
| Total |
| Credit |
| Net |
| Percentage of |
| Net Exposure of |
| ||||
|
| (in thousands) |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(2) |
| $ | 472,173 |
| $ | 30,545 |
| $ | 441,628 |
| 78 | % | $ | — |
|
Internally Rated-Investment Grade(3) |
| 108,312 |
| 4,546 |
| 103,766 |
| 19 |
| — |
| ||||
Non-Investment Grade |
| 43,178 |
| 38,690 |
| 4,488 |
| 1 |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| 48,944 |
| 35,671 |
| 13,273 |
| 2 |
| — |
| ||||
|
|
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 672,607 |
| $ | 109,452 |
| $ | 563,155 |
| 100 | % | $ | — |
|
|
| Maturity of Credit Risk Exposure |
| ||||||||||
Rating |
| Less than |
| 2-5 Years |
| Exposure |
| Total Exposure |
| ||||
|
| (in thousands) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(2) |
| $ | 425,675 |
| $ | 38,144 |
| $ | 8,354 |
| $ | 472,173 |
|
Internally Rated-Investment Grade(3) |
| 108,312 |
| — |
| — |
| 108,312 |
| ||||
Non-Investment Grade |
| 43,178 |
| — |
| — |
| 43,178 |
| ||||
Internally Rated-Non-Investment Grade |
| 48,796 |
| 148 |
| — |
| 48,944 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 625,961 |
| $ | 38,292 |
| $ | 8,354 |
| $ | 672,607 |
|
|
|
|
| Maturity of Credit Risk Exposure |
| |||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
| Exposure |
| Total Exposure |
| |||||
|
|
|
|
|
|
|
| Greater than |
| Before Credit |
| |||||
Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment Grade(2) |
| $ | 636 |
| $ | 74 |
| $ | 16 |
| $ | 11 |
| $ | 737 |
|
Internally Rated-Investment Grade(3) |
| 61 |
| 7 |
| — |
| — |
| 68 |
| |||||
Non-Investment Grade |
| 133 |
| 2 |
| — |
| — |
| 135 |
| |||||
Internally Rated-Non-Investment Grade |
| 50 |
| 1 |
| — |
| — |
| 51 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 880 |
| $ | 84 |
| $ | 16 |
| $ | 11 |
| $ | 991 |
|
(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.
80
CG&E
|
| Total Exposure Before Credit Collateral |
| Credit Collateral |
| Net Exposure |
| Percentage of Total Net Exposure |
| Number of Counterparties |
| Net Exposure of |
| |||||||||||||||||||
Rating |
| Total |
| Credit |
| Net |
| Percentage of |
| Net Exposure of |
|
|
|
|
|
| ||||||||||||||||
|
| (in thousands) |
|
| (in millions) |
| ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Investment Grade(1) |
| $ | 119,206 |
| $ | 20,000 |
| $ | 99,206 |
| 92 | % | $ | — |
|
| $ | 165 |
| $ | 21 |
| $ | 144 |
| 92 | % | 2 |
| $ | 45 |
|
Internally Rated-Investment Grade(2) |
| 8,077 |
| — |
| 8,077 |
| 8 |
| — |
|
| 8 |
| — |
| 8 |
| 5 |
| — |
| — |
| ||||||||
Non-Investment Grade |
| 11,640 |
| 11,457 |
| 183 |
| — |
| — |
|
| 18 |
| 15 |
| 3 |
| 2 |
| — |
| — |
| ||||||||
Internally Rated-Non-Investment Grade |
| 4,886 |
| 4,747 |
| 139 |
| — |
| — |
|
| 3 |
| 1 |
| 2 |
| 1 |
| — |
| — |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Total |
| $ | 143,809 |
| $ | 36,204 |
| $ | 107,605 |
| 100 | % | $ | — |
|
| $ | 194 |
| $ | 37 |
| $ | 157 |
| 100 | % | 2 |
| $ | 45 |
|
84
|
| Maturity of Credit Risk Exposure |
| ||||||||||
Rating |
| Less than |
| 2-5 Years |
| Exposure |
| Total Exposure |
| ||||
|
| (in thousands) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(1) |
| $ | 108,724 |
| $ | 10,482 |
| $ | — |
| $ | 119,206 |
|
Internally Rated-Investment Grade(2) |
| 8,077 |
| — |
| — |
| 8,077 |
| ||||
Non-Investment Grade |
| 11,640 |
| — |
| — |
| 11,640 |
| ||||
Internally Rated-Non-Investment Grade |
| 4,886 |
| — |
| — |
| 4,886 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 133,327 |
| $ | 10,482 |
| $ | — |
| $ | 143,809 |
|
|
| Maturity of Credit Risk Exposure |
| |||||||||||||
|
|
|
|
|
|
|
| Exposure |
| Total Exposure |
| |||||
|
|
|
|
|
|
|
| Greater than |
| Before Credit |
| |||||
Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment Grade(1) |
| $ | 156 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 165 |
|
Internally Rated-Investment Grade(2) |
| 8 |
| — |
| — |
| — |
| 8 |
| |||||
Non-Investment Grade |
| 18 |
| — |
| — |
| — |
| 18 |
| |||||
Internally Rated-Non-Investment Grade |
| 3 |
| — |
| — |
| — |
| 3 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 185 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 194 |
|
(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.
PSI(3)
Rating |
| Total |
| Credit |
| Net |
| Percentage of |
| Net Exposure of |
| ||||
|
| (in thousands) |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(1) |
| $ | 10,696 |
| $ | — |
| $ | 10,696 |
| 95 | % | $ | — |
|
Internally Rated-Investment Grade(2) |
| 3 |
| — |
| 3 |
| — |
| — |
| ||||
Non-Investment Grade |
| 1,864 |
| 1,324 |
| 540 |
| 5 |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| — |
| — |
| — |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 12,563 |
| $ | 1,324 |
| $ | 11,239 |
| 100 | % | $ | — |
|
|
| Maturity of Credit Risk Exposure |
| ||||||||||
Rating |
| Less than |
| 2-5 Years |
| Exposure |
| Total Exposure |
| ||||
|
| (in thousands) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(1) |
| $ | 7,983 |
| $ | 2,713 |
| $ | — |
| $ | 10,696 |
|
Internally Rated-Investment Grade(2) |
| 3 |
| — |
| — |
| 3 |
| ||||
Non-Investment Grade |
| 1,864 |
| — |
| — |
| 1,864 |
| ||||
Internally Rated-Non-Investment Grade |
| — |
| — |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 9,850 |
| $ | 2,713 |
| $ | — |
| $ | 12,563 |
|
(1)IncludesExposures, positive or negative, with counterparties rated Investment Grade or the counterparties’ obligationsthat are guaranteed or secured by an Investment Grade entity.
(2)Counterparties include various citiesrelated to one another are not aggregated when no right of offset exists and municipalities.as a result, credit is extended and evaluated on a separate basis.
85
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.
In July 2002, Cinergy Capital & Trading, Inc. acquired a coal-based synthetic fuel production facility. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with Internal Revenue Code (IRC) Section 29 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. In addition to the existing plant, we have recently exercised an option to buy an additional synthetic fuel plant.
Potential exposureDuring the third quarter of 2004, several unrelated entities announced that the Internal Revenue Service (IRS) had or threatened to credit risk also exists from our usechallenge the placed in service dates 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 anysome of the counterparties.entities’ synthetic fuel plants. A successful IRS challenge could result in disallowance of all credits previously claimed for fuel produced by the subject plants. Cinergy’s sale of synthetic fuel has generated approximately $219 million in tax credits through December 31, 2004, of which approximately $96 million were generated in 2004.
The IRS has not yet audited for any tax year in which Cinergy has claimed Section 29 credits related to synthetic fuel. However, it is reasonable to anticipate that the IRS will evaluate the placed in service date and other key requirements for claiming the credit. We Risk ManagementCinergymanage, on a portfolio basis,anticipate this audit to begin in 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 formsspring of collateral, and the use of mutual netting/closeout agreements.2005.
Cinergy has received a private letter ruling from the IRS in connection with the acquisition of the facility that specifically addressed the significant chemical change requirement. Additionally, although not addressed in the letter ruling, we believe that our facility’s in service date meets the Section 29 requirements.
IRC Section 29 also provides for a phase-out of the credit based on the price of crude oil. The phase-out is based on a prescribed calculation and definition of crude oil prices. We do not expect any impact on our ability to utilize Section 29 credits in 2004. Future increases in crude oil prices above the price stipulated by the IRS could negatively impact our ability to utilize credits in subsequent years.
74
MD&A - MARKET RISK SENSITIVE INSTRUMENTS
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 fluctuationsmovements in exchange rates between the U.S. dollarprice of electricity and the currencies of foreign countries whereother energy commodities may become greater. As a result, we have investments. When it is appropriate we will hedge our exposuremay be subject to cash flow transactions, such as a dividend payment by one of our foreign subsidiaries. increased future earnings volatility.
Commercial’s energy marketing and trading activities principally consist of Marketing & Trading’s natural gas marketing and trading operations and Interest Rate SensitivityCG&E’s power marketing and trading operations.
Our net exposure to changesdomestic 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 interest rates primarily consiststhe midwest region of short-term debt instruments (including net money pool borrowings)the United States), natural gas, and certain pollution control debt. The following table reflectsother 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 different instruments used and the method of benchmarking interest rates, as of December 31, 2003:New York Mercantile Exchange.
Interest Benchmark |
| 2003 |
| |||||
|
|
|
|
|
| (in millions) |
| |
|
|
|
|
|
|
|
| |
Short-term Bank Loans/Commercial Paper/Money |
| • Short-term Money Market |
| Cinergy |
| $ | 158 |
|
Pool |
| • Commercial Paper |
| CG&E and subsidiaries |
| 49 |
| |
|
| Composite Rate(2) |
| PSI |
| 188 |
| |
|
| • LIBOR(1) |
| ULH&P |
| 45 |
| |
|
|
|
|
|
|
|
| |
Pollution Control Debt |
| • Daily Market |
| Cinergy |
| 193 |
| |
|
| • Weekly Market |
| CG&E and subsidiaries |
| 112 |
| |
|
| • Auction Rate |
| PSI |
| 81 |
| |
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.
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:
(1)•London Inter-Bank Offered Rate (LIBOR)manage and economically hedge contractual commitments;
(2)•30-day Federal Reserve “AA” Industrial Commercial Paper Composite Ratereduce 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.
86
The weighted-average interest rates onCommercial structures and modifies its net position to capture the above instruments at December 31, were as follows:
| |||
|
|
| |
|
|
| |
|
|
| |
At December 31, 2003, forward yield curves project an increase in applicable short-term interest rates over the next five years.following:
87
The following table presents principal cash repayments, by maturity date and other selected information, for each registrant’s long-term fixed-rate debt, other debt, and capital lease obligations as of December 31, 2003:
|
| Expected Maturity Date |
| ||||||||||||||||||||||
Liabilities |
| 2004 |
| 2005 |
| 2006 |
| 2007 |
| 2008 |
| There- |
| Total |
| Fair |
| ||||||||
|
| (in millions) |
| ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Cinergy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Long-term Debt(1) |
| $ | 810 |
| $ | 202 | (4)(5) | $ | 326 |
| $ | 366 |
| $ | 364 |
| $ | 2,169 |
| $ | 4,237 |
| $ | 4,465 |
|
Weighted-average interest rate(2) |
| 6.3 | % | 6.8 | % | 6.7 | % | 7.6 | % | 6.5 | % | 5.5 | % | 6.0 | % |
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Other(3) |
| $ | 25 |
| $ | 20 |
| $ | 28 |
| $ | 361 |
| $ | 186 |
| $ | 164 |
| $ | 784 |
| $ | 882 |
|
Weighted-average interest rate(2) |
| 6.9 | % | 7.9 | % | 7.0 | % | 6.9 | % | 6.4 | % | 7.1 | % | 6.8 | % |
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Fixed-rate leases |
| $ | 5 |
| $ | 6 |
| $ | 6 |
| $ | 6 |
| $ | 8 |
| $ | 24 |
| $ | 55 |
| $ | 55 |
|
Interest rate(2) |
| 5.5 | % | 5.5 | % | 5.4 | % | 5.4 | % | 5.3 | % | 4.9 | % | 5.2 | % |
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Long-term Debt(1) |
| $ | 110 |
| $ | 150 | (5) | $ | — |
| $ | 100 |
| $ | 120 |
| $ | 1,126 |
| $ | 1,606 |
| $ | 1,620 |
|
Weighted-average interest rate(2) |
| 6.5 | % | 6.9 | % |
|
| 6.9 | % | 6.4 | % | 5.3 | % | 5.7 | % |
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Fixed-rate leases |
| $ | 3 |
| $ | 3 |
| $ | 3 |
| $ | 4 |
| $ | 5 |
| $ | 15 |
| $ | 33 |
| $ | 33 |
|
Interest rate(2) |
| 5.4 | % | 5.4 | % | 5.4 | % | 5.3 | % | 5.3 | % | 4.9 | % | 5.2 | % |
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Long-term Debt(1) |
| $ | — |
| $ | 52 | (4) | $ | 326 |
| $ | 266 |
| $ | 44 |
| $ | 1,043 |
| $ | 1,731 |
| $ | 1,871 |
|
Weighted-average interest rate(2) |
|
|
| 6.5 | % | 6.7 | % | 7.8 | % | 6.4 | % | 5.6 | % | 6.2 | % |
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Fixed-rate leases |
| $ | 2 |
| $ | 2 |
| $ | 2 |
| $ | 3 |
| $ | 4 |
| $ | 9 |
| $ | 22 |
| $ | 22 |
|
Interest rate(2) |
| 5.6 | % | 5.5 | % | 5.5 | % | 5.5 | % | 5.4 | % | 4.9 | % | 5.3 | % |
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
ULH&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Long-term Debt(1) |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 20 |
| $ | 35 |
| $ | 55 |
| $ | 61 |
|
Weighted-average interest rate(2) |
|
|
|
|
|
|
|
|
| 6.5 | % | 7.8 | % | 7.3 | % |
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Fixed-rate leases |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 3 |
| $ | 8 |
| $ | 8 |
|
Interest rate(2) |
| 5.6 | % | 5.6 | % | 5.5 | % | 5.5 | % | 5.4 | % | 5.0 | % | 5.3 | % |
|
| ||||||||
|
| ||
|
| ||
|
| ||
|
| ||
|
|
88
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 floating 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•seasonal market pricing characteristics;
•overall market sentiment; and
•price relationships between fixed-ratedifferent time periods and floating-rate interest amounts calculated on an agreed upon notional amount. CG&E has an outstanding interest rate swap agreement that decreased the percentage of floating-rate debt.trading regions.
UnderAt 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 provisionsbasic 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 swap, which hasmagnitude and probability of future value changes related to open contract positions. VaR is a notional amount of $100 million, CG&E pays a fixed-rate and receives a floating-rate through October 2007. This swap qualifies as a cash flow hedge under
75
statistical measure used to quantify 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. Changespotential change in fair value of this swap are recorded in Accumulated other comprehensive income (loss), beginning with our adoptionthe trading portfolio over a particular period of Statement 133 on January 1, 2001. Cinergy Corp. has three outstanding interest rate swapstime, with a combined notional amountspecified likelihood of $250 million. Underoccurrence, 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 provisionsVaR 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. Prior to March 31, 2004, our VaR model used the Parametric variance-covariance statistical modeling technique and historical volatilities and correlations over the past 21-trading day period. Beginning with April 1, 2004, we calculate VaR using a Monte Carlo simulation methodology using implied forward-looking volatilities and historical correlations. Comparisons indicated that the differences in VaR between the Monte Carlo and Parametric calculations were not material and were within expectations. The primary reason for changing to a Monte Carlo approach is that it offers a more scalable method for handling more complex derivative positions and provides a consistent platform for quantifying both market and credit risk.
The VaR for Cinergy’s trading portfolio is presented in the table below:
VaR Associated with Energy Trading Contracts |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||
|
| 2004 |
| 2003 |
| ||||||
|
| Trading VaR |
| Percentage of Operating Income |
| Trading VaR |
| Percentage of Operating Income |
| ||
|
| (dollars in millions) |
| ||||||||
|
|
|
|
|
|
|
|
|
| ||
95% confidence level, one-day holding period, one-tailed December 31 |
| $ | 1.9 |
| 0.3 | % | $ | 0.6 |
| 0.1 | % |
Average for the twelve months ended December 31 |
| 2.4 |
| 0.3 |
| 1.3 |
| 0.2 |
| ||
High for the twelve months ended December 31 |
| 5.8 |
| 0.8 |
| 3.8 |
| 0.5 |
| ||
Low for the twelve months ended December 31 |
| 0.7 |
| 0.1 |
| 0.4 |
| 0.1 |
| ||
76
Changes in Fair Value
The changes in fair value of the swaps,energy risk management assets and liabilities for Cinergy Corp. will receive fixed-rate interest payments and pay floating-rate interest payments through September 2004. These swaps qualify asCG&E for the years ended December 31, 2004 and 2003 are presented in the table below. In April 2002, CG&E and PSI executed a new joint operating agreement whereby we chose to originate all new power marketing and trading contracts since April 2002 on behalf of CG&E only. Historically, such contracts were executed on behalf of PSI and CG&E jointly. PSI’s remaining contracts, entered into prior to the new joint operating agreement, are not material. Therefore, we have not presented PSI separately in the fair value hedges under the provisionstables below.
|
| Change in Fair Value |
| ||||||||||
|
| 2004 |
| 2003 |
| ||||||||
|
| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
| ||||
|
| (in millions) |
| ||||||||||
Fair value of contracts outstanding at the beginning of period |
| $ | 41 |
| $ | 20 |
| $ | 75 |
| $ | 42 |
|
|
|
|
|
|
|
|
|
|
| ||||
Changes in fair value attributable to changes in valuation techniques and assumptions(2) |
| (5 | ) | (4 | ) | 1 |
| 1 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Other changes in fair value(3) |
| 185 |
| 70 |
| 127 |
| 53 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Option premiums paid/(received) |
| 5 |
| 6 |
| (3 | ) | 2 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Accounting Changes(4) |
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Consolidation of previously unconsolidated entities |
| — |
| — |
| 7 |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Cumulative effect of changes in accounting principles |
| — |
| — |
| (20 | ) | (13 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Contracts settled |
| (144 | ) | (56 | ) | (146 | ) | (65 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Fair value of contracts outstanding at end of period |
| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
|
(1)The results of Statement 133. We anticipate that these swaps will continueCinergyalso include amounts related to be effective as hedges. 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)See Note 1(k)1(q)(i) and Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional informationfurther information.
The following are the balances at December 31, 2004 and 2003 of our energy risk management assets and liabilities:
|
| 2004 |
| 2003 |
| ||||||||
|
| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
| ||||
|
| (in millions) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Energy risk management assets - current |
| $ | 381 |
| $ | 149 |
| $ | 305 |
| $ | 73 |
|
Energy risk management assets - non-current |
| 139 |
| 47 |
| 97 |
| 37 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Energy risk management liabilities - current |
| (311 | ) | (120 | ) | (296 | ) | (78 | ) | ||||
Energy risk management liabilities - non-current |
| (127 | ) | (40 | ) | (65 | ) | (12 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
|
| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
|
(1)The results of Cinergy also include amounts related to non-registrants.
77
The following table presents the expected maturity of the energy risk management assets and liabilities as of December 31, 2004 for Cinergy and CG&E:
|
| Fair Value of Contracts at December 31, 2004 |
| |||||||||||||
|
| Maturing |
|
|
| |||||||||||
Source of Fair Value(1) |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| Thereafter |
| Total Fair Value |
| |||||
|
| (in millions) |
| |||||||||||||
Cinergy(2) |
|
|
|
|
|
|
|
|
|
|
| |||||
Prices actively quoted |
| $ | 74 |
| $ | 18 |
| $ | — |
| $ | — |
| $ | 92 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Prices based on models and other valuation methods(3) |
| (4 | ) | (5 | ) | 2 |
| (3 | ) | (10 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 70 |
| $ | 13 |
| $ | 2 |
| $ | (3 | ) | $ | 82 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E |
|
|
|
|
|
|
|
|
|
|
| |||||
Prices actively quoted |
| $ | 25 |
| $ | 13 |
| $ | — |
| $ | — |
| $ | 38 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Prices based on models and other valuation methods(3) |
| 4 |
| (6 | ) | — |
| — |
| (2 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 29 |
| $ | 7 |
| $ | — |
| $ | — |
| $ | 36 |
|
(1) �� While liquidity varies by trading regions, active quotes are generally available for two years for standard electricity transactions and three years for standard gas transactions. Non-standard transactions are classified based on financial derivatives. In 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.
(3)A substantial portion of these amounts include option values.
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 Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (Statement 149), most forward power 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 increase or decrease consistently applied to all forward power prices would have resulted in an increase or decrease in fair value of these contracts of approximately $3 million as of December 31, 2004.
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 are partially mitigated in 2005 and 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 will continually monitorrecover 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 conditions to evaluate whether to modify our levelprice 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.
78
Credit risk is the exposure to fluctuationseconomic 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, 2004, we believe the likelihood of significant losses associated with credit risk in interest rates.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.
79
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, 2004. 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.
Cinergy(1)
Rating |
| Total Exposure |
| Credit Collateral |
| Net Exposure |
| Percentage of |
| Number of |
| Net Exposure of |
| ||||
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(2) |
| $ | 737 |
| $ | 75 |
| $ | 662 |
| 84 | % | — |
| $ | — |
|
Internally Rated-Investment Grade(3) |
| 68 |
| 1 |
| 67 |
| 9 |
| — |
| — |
| ||||
Non-Investment Grade |
| 135 |
| 90 |
| 45 |
| 5 |
| — |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| 51 |
| 37 |
| 14 |
| 2 |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| — |
|
|
| ||||
Total |
| $ | 991 |
| $ | 203 |
| $ | 788 |
| 100 | % | — |
| $ | — |
|
|
|
|
| Maturity of Credit Risk Exposure |
| |||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
| Exposure |
| Total Exposure |
| |||||
|
|
|
|
|
|
|
| Greater than |
| Before Credit |
| |||||
Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment Grade(2) |
| $ | 636 |
| $ | 74 |
| $ | 16 |
| $ | 11 |
| $ | 737 |
|
Internally Rated-Investment Grade(3) |
| 61 |
| 7 |
| — |
| — |
| 68 |
| |||||
Non-Investment Grade |
| 133 |
| 2 |
| — |
| — |
| 135 |
| |||||
Internally Rated-Non-Investment Grade |
| 50 |
| 1 |
| — |
| — |
| 51 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 880 |
| $ | 84 |
| $ | 16 |
| $ | 11 |
| $ | 991 |
|
(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.
80
CG&E
|
| Total Exposure Before Credit Collateral |
| Credit Collateral |
| Net Exposure |
| Percentage of Total Net Exposure |
| Number of Counterparties |
| Net Exposure of |
| ||||
Rating |
|
|
|
|
|
|
| ||||||||||
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(1) |
| $ | 165 |
| $ | 21 |
| $ | 144 |
| 92 | % | 2 |
| $ | 45 |
|
Internally Rated-Investment Grade(2) |
| 8 |
| — |
| 8 |
| 5 |
| — |
| — |
| ||||
Non-Investment Grade |
| 18 |
| 15 |
| 3 |
| 2 |
| — |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| 3 |
| 1 |
| 2 |
| 1 |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 194 |
| $ | 37 |
| $ | 157 |
| 100 | % | 2 |
| $ | 45 |
|
|
| Maturity of Credit Risk Exposure |
| |||||||||||||
|
|
|
|
|
|
|
| Exposure |
| Total Exposure |
| |||||
|
|
|
|
|
|
|
| Greater than |
| Before Credit |
| |||||
Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment Grade(1) |
| $ | 156 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 165 |
|
Internally Rated-Investment Grade(2) |
| 8 |
| — |
| — |
| — |
| 8 |
| |||||
Non-Investment Grade |
| 18 |
| — |
| — |
| — |
| 18 |
| |||||
Internally Rated-Non-Investment Grade |
| 3 |
| — |
| — |
| — |
| 3 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 185 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 194 |
|
(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.
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.
In July 2002, Cinergy Capital & Trading, Inc. acquired a coal-based synthetic fuel production facility. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with Internal Revenue Code (IRC) Section 29 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. In addition to the existing plant, we have recently exercised an option to buy an additional synthetic fuel plant.
During the third quarter of 2004, several unrelated entities announced that the Internal Revenue Service (IRS) had or threatened to challenge the placed in service dates of some of the entities’ synthetic fuel plants. A successful IRS challenge could result in disallowance of all credits previously claimed for fuel produced by the subject plants. Cinergy’s sale of synthetic fuel has generated approximately $219 million in tax credits through December 31, 2004, of which approximately $96 million were generated in 2004.
The IRS has not yet audited Cinergy for any tax year in which Cinergy has claimed Section 29 credits related to synthetic fuel. However, it is reasonable to anticipate that the IRS will evaluate the placed in service date and other key requirements for claiming the credit. We anticipate this audit to begin in the spring of 2005.
Cinergy received a private letter ruling from the IRS in connection with the acquisition of the facility that specifically addressed the significant chemical change requirement. Additionally, although not addressed in the letter ruling, we believe that our facility’s in service date meets the Section 29 requirements.
IRC Section 29 also provides for a phase-out of the credit based on the price of crude oil. The phase-out is based on a prescribed calculation and definition of crude oil prices. We do not expect any impact on our ability to utilize Section 29 credits in 2004. Future increases in crude oil prices above the price stipulated by the IRS could negatively impact our ability to utilize credits in subsequent years.
74
MD&A - MARKET RISK SENSITIVE INSTRUMENTS
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.
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.
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
75
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. Prior to March 31, 2004, our VaR model used the Parametric variance-covariance statistical modeling technique and historical volatilities and correlations over the past 21-trading day period. Beginning with April 1, 2004, we calculate VaR using a Monte Carlo simulation methodology using implied forward-looking volatilities and historical correlations. Comparisons indicated that the differences in VaR between the Monte Carlo and Parametric calculations were not material and were within expectations. The primary reason for changing to a Monte Carlo approach is that it offers a more scalable method for handling more complex derivative positions and provides a consistent platform for quantifying both market and credit risk.
The VaR for Cinergy’s trading portfolio is presented in the table below:
VaR Associated with Energy Trading Contracts |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||
|
| 2004 |
| 2003 |
| ||||||
|
| Trading VaR |
| Percentage of Operating Income |
| Trading VaR |
| Percentage of Operating Income |
| ||
|
| (dollars in millions) |
| ||||||||
|
|
|
|
|
|
|
|
|
| ||
95% confidence level, one-day holding period, one-tailed December 31 |
| $ | 1.9 |
| 0.3 | % | $ | 0.6 |
| 0.1 | % |
Average for the twelve months ended December 31 |
| 2.4 |
| 0.3 |
| 1.3 |
| 0.2 |
| ||
High for the twelve months ended December 31 |
| 5.8 |
| 0.8 |
| 3.8 |
| 0.5 |
| ||
Low for the twelve months ended December 31 |
| 0.7 |
| 0.1 |
| 0.4 |
| 0.1 |
| ||
76
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, 2004 and 2003 are presented in the table below. In April 2002, CG&E and PSI executed a new joint operating agreement whereby we chose to originate all new power marketing and trading contracts since April 2002 on behalf of CG&E only. Historically, such contracts were executed on behalf of PSI and CG&E jointly. PSI’s remaining contracts, entered into prior to the new joint operating agreement, are not material. Therefore, we have not presented PSI separately in the fair value tables below.
|
| Change in Fair Value |
| ||||||||||
|
| 2004 |
| 2003 |
| ||||||||
|
| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
| ||||
|
| (in millions) |
| ||||||||||
Fair value of contracts outstanding at the beginning of period |
| $ | 41 |
| $ | 20 |
| $ | 75 |
| $ | 42 |
|
|
|
|
|
|
|
|
|
|
| ||||
Changes in fair value attributable to changes in valuation techniques and assumptions(2) |
| (5 | ) | (4 | ) | 1 |
| 1 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Other changes in fair value(3) |
| 185 |
| 70 |
| 127 |
| 53 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Option premiums paid/(received) |
| 5 |
| 6 |
| (3 | ) | 2 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Accounting Changes(4) |
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Consolidation of previously unconsolidated entities |
| — |
| — |
| 7 |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Cumulative effect of changes in accounting principles |
| — |
| — |
| (20 | ) | (13 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Contracts settled |
| (144 | ) | (56 | ) | (146 | ) | (65 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Fair value of contracts outstanding at end of period |
| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
|
(1)The results ofCinergyalso 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)See Note 1(q)(i) and Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
The following are the balances at December 31, 2004 and 2003 of our energy risk management assets and liabilities:
|
| 2004 |
| 2003 |
| ||||||||
|
| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
| ||||
|
| (in millions) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Energy risk management assets - current |
| $ | 381 |
| $ | 149 |
| $ | 305 |
| $ | 73 |
|
Energy risk management assets - non-current |
| 139 |
| 47 |
| 97 |
| 37 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Energy risk management liabilities - current |
| (311 | ) | (120 | ) | (296 | ) | (78 | ) | ||||
Energy risk management liabilities - non-current |
| (127 | ) | (40 | ) | (65 | ) | (12 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
|
| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
|
(1)The results of Cinergy also include amounts related to non-registrants.
77
The following table presents the expected maturity of the energy risk management assets and liabilities as of December 31, 2004 for Cinergy and CG&E:
|
| Fair Value of Contracts at December 31, 2004 |
| |||||||||||||
|
| Maturing |
|
|
| |||||||||||
Source of Fair Value(1) |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| Thereafter |
| Total Fair Value |
| |||||
|
| (in millions) |
| |||||||||||||
Cinergy(2) |
|
|
|
|
|
|
|
|
|
|
| |||||
Prices actively quoted |
| $ | 74 |
| $ | 18 |
| $ | — |
| $ | — |
| $ | 92 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Prices based on models and other valuation methods(3) |
| (4 | ) | (5 | ) | 2 |
| (3 | ) | (10 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 70 |
| $ | 13 |
| $ | 2 |
| $ | (3 | ) | $ | 82 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E |
|
|
|
|
|
|
|
|
|
|
| |||||
Prices actively quoted |
| $ | 25 |
| $ | 13 |
| $ | — |
| $ | — |
| $ | 38 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Prices based on models and other valuation methods(3) |
| 4 |
| (6 | ) | — |
| — |
| (2 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 29 |
| $ | 7 |
| $ | — |
| $ | — |
| $ | 36 |
|
(1) �� While liquidity varies by trading regions, active quotes are generally available for two years for standard electricity transactions and three years for standard gas transactions. 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.
(3)A substantial portion of these amounts include option values.
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 Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (Statement 149), most forward power 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 increase or decrease consistently applied to all forward power prices would have resulted in an increase or decrease in fair value of these contracts of approximately $3 million as of December 31, 2004.
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 are partially mitigated in 2005 and 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 will recover 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.
78
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, 2004, 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.
79
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, 2004. 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.
Cinergy(1)
Rating |
| Total Exposure |
| Credit Collateral |
| Net Exposure |
| Percentage of |
| Number of |
| Net Exposure of |
| ||||
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(2) |
| $ | 737 |
| $ | 75 |
| $ | 662 |
| 84 | % | — |
| $ | — |
|
Internally Rated-Investment Grade(3) |
| 68 |
| 1 |
| 67 |
| 9 |
| — |
| — |
| ||||
Non-Investment Grade |
| 135 |
| 90 |
| 45 |
| 5 |
| — |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| 51 |
| 37 |
| 14 |
| 2 |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| — |
|
|
| ||||
Total |
| $ | 991 |
| $ | 203 |
| $ | 788 |
| 100 | % | — |
| $ | — |
|
|
|
|
| Maturity of Credit Risk Exposure |
| |||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
| Exposure |
| Total Exposure |
| |||||
|
|
|
|
|
|
|
| Greater than |
| Before Credit |
| |||||
Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment Grade(2) |
| $ | 636 |
| $ | 74 |
| $ | 16 |
| $ | 11 |
| $ | 737 |
|
Internally Rated-Investment Grade(3) |
| 61 |
| 7 |
| — |
| — |
| 68 |
| |||||
Non-Investment Grade |
| 133 |
| 2 |
| — |
| — |
| 135 |
| |||||
Internally Rated-Non-Investment Grade |
| 50 |
| 1 |
| — |
| — |
| 51 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 880 |
| $ | 84 |
| $ | 16 |
| $ | 11 |
| $ | 991 |
|
(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.
80
CG&E
|
| Total Exposure Before Credit Collateral |
| Credit Collateral |
| Net Exposure |
| Percentage of Total Net Exposure |
| Number of Counterparties |
| Net Exposure of |
| ||||
Rating |
|
|
|
|
|
|
| ||||||||||
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(1) |
| $ | 165 |
| $ | 21 |
| $ | 144 |
| 92 | % | 2 |
| $ | 45 |
|
Internally Rated-Investment Grade(2) |
| 8 |
| — |
| 8 |
| 5 |
| — |
| — |
| ||||
Non-Investment Grade |
| 18 |
| 15 |
| 3 |
| 2 |
| — |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| 3 |
| 1 |
| 2 |
| 1 |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 194 |
| $ | 37 |
| $ | 157 |
| 100 | % | 2 |
| $ | 45 |
|
|
| Maturity of Credit Risk Exposure |
| |||||||||||||
|
|
|
|
|
|
|
| Exposure |
| Total Exposure |
| |||||
|
|
|
|
|
|
|
| Greater than |
| Before Credit |
| |||||
Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment Grade(1) |
| $ | 156 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 165 |
|
Internally Rated-Investment Grade(2) |
| 8 |
| — |
| — |
| — |
| 8 |
| |||||
Non-Investment Grade |
| 18 |
| — |
| — |
| — |
| 18 |
| |||||
Internally Rated-Non-Investment Grade |
| 3 |
| — |
| — |
| — |
| 3 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 185 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 194 |
|
(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.
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.
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, such as a dividend payment by one of our foreign subsidiaries.
81
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, 2004:
Interest Benchmark |
| 2004 |
| |||||
|
|
|
|
|
| (in millions) |
| |
|
|
|
|
|
|
|
| |
Short-term Bank Loans/Commercial Paper/Money Pool |
| •Short-term Money Market |
| Cinergy |
| $ | 686 |
|
|
| •Commercial Paper |
| CG&E and subsidiaries |
| 180 |
| |
|
| Composite Rate(1) |
| PSI |
| 131 |
| |
|
| •LIBOR(2) |
| ULH&P |
| 11 |
| |
|
|
|
|
|
|
|
| |
Pollution Control Debt |
| •Daily Market |
| Cinergy |
| 741 |
| |
|
| •Weekly Market |
| CG&E and subsidiaries |
| 290 |
| |
|
| •Auction Rate |
| PSI |
| 426 |
| |
(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:
2004 | |||
Short-term Bank Loans/Commercial Paper | 2.5 | % | |
Money Pool | 2.4 | % | |
Pollution Control Debt | 2.3 | % | |
At December 31, 2004, forward yield curves project an increase in applicable short-term interest rates over the next five years.
82
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, 2004:
|
| Expected Maturity Date |
| |||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| There- |
|
|
| Fair |
| |||||||||||||||||||||||
Liabilities |
| 2005 |
| 2006 |
| 2007 |
| 2008 |
| 2009 |
| after |
| Total |
| Value |
| |||||||||||||||||||||||
|
| (in millions) |
| |||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Cinergy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt(1)(6) |
| $ | 200 | (4)(5) | $ | 326 |
| $ | 366 |
| $ | 513 |
| $ | 243 |
| $ | 2,223 |
| $ | 3,871 |
| $ | 4,074 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 6.8 | % | 6.6 | % | 7.6 | % | 6.4 | % | 7.4 | % | 7.1 | % | 7.0 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Other(3) |
| $ | 20 |
| $ | 29 |
| $ | 360 |
| $ | 38 |
| $ | 27 |
| $ | 153 |
| $ | 627 |
| $ | 687 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 7.9 | % | 6.8 | % | 6.9 | % | 6.9 | % | 6.7 | % | 6.9 | % | 6.9 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 7 |
| $ | 7 |
| $ | 7 |
| $ | 10 |
| $ | 10 |
| $ | 24 |
| $ | 65 |
| $ | 65 |
| |||||||||||||||
Interest rate(2) |
| 5.4 | % | 5.3 | % | 5.3 | % | 5.2 | % | 5.1 | % | 4.9 | % | 5.5 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt(1) |
| $ | 150 | (5) | $ | — |
| $ | 100 |
| $ | 120 |
| $ | 20 |
| $ | 1,240 |
| $ | 1,630 |
| $ | 1,677 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 6.9 | % | — | % | 6.9 | % | 6.4 | % | 7.9 | % | 5.1 | % | 5.5 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 4 |
| $ | 4 |
| $ | 4 |
| $ | 6 |
| $ | 6 |
| $ | 16 |
| $ | 40 |
| $ | 40 |
| |||||||||||||||
Interest rate(2) |
| 5.3 | % | 5.3 | % | 5.2 | % | 5.2 | % | 5.1 | % | 4.9 | % | 5.4 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt(1) |
| $ | 50 | (4) | $ | 326 |
| $ | 266 |
| $ | 43 |
| $ | 223 |
| $ | 976 |
| $ | 1,884 |
| $ | 2,009 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 6.5 | % | 6.6 | % | 7.8 | % | 6.4 | % | 7.3 | % | 9.6 | % | 8.4 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 3 |
| $ | 3 |
| $ | 3 |
| $ | 4 |
| $ | 4 |
| $ | 8 |
| $ | 25 |
| $ | 25 |
| |||||||||||||||
Interest rate(2) |
| 5.5 | % | 5.4 | % | 5.4 | % | 5.3 | % | 5.1 | % | 4.9 | % | 5.6 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
ULH&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt |
| $ | — |
| $ | — |
| $ | — |
| $ | 20 |
| $ | 20 |
| $ | 55 |
| $ | 95 |
| $ | 100 |
| |||||||||||||||
Weighted-average interest rate(2) |
| — | % | — | % | — | % | 6.5 | % | 7.9 | % | 5.7 | % | 6.3 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 2 |
| $ | 3 |
| $ | 9 |
| $ | 9 |
| |||||||||||||||
Interest rate(2) |
| 5.4 | % | 5.4 | % | 5.4 | % | 5.3 | % | 5.2 | % | 4.9 | % | 5.6 | % |
|
| |||||||||||||||||||||||
(1)Long-term Debt includes amounts reflected as Long-term debt due within one year.
(2)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, 2004 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.
(3)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 3(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.
(4)Includes PSI’s 6.50% Debentures due August 1, 2026, reflected as maturing in 2005, as the interest rate is due to reset on August 1, 2005. If the interest rate is not reset, the bonds are subject to mandatory redemption by PSI.
(5)CG&E’s 6.90% Debentures due June 1, 2025, are putable to CG&E at the option of the holders on June 1, 2005. However, based on current market conditions, we believe it is unlikely that the debentures will be put to CG&E on this date.
(6)Includes amounts related to non-registrants.
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.
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CG&E has an outstanding interest rate swap agreement that decreased the percentage of variable-rate debt. See Note 7(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information on financial derivatives.
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MD&A - - ACCOUNTING MATTERS
Preparation of financial statements and related disclosures in compliance with GAAP requires the use of assumptions and estimates. In certain instances, the application of GAAP requires judgmentsestimates 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. The following discusses relevantWe consider an accounting policiesestimate 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.
We use fair value accounting for energy trading contracts, which is required, with certain exceptions, by Statement 133. We designate these contracts as either trading or non-trading at the time they are originated in accordance with EITF Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading
89
and Risk Management Activities (EITF 02-3). 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 model pricing due to the lack of actively quoted prices. The period for whichless actively quoted prices are available varies by commodity and pricing point, but is generally shorter for electricity than gas.or valuation models. Use of model pricing requires estimationestimating surrounding factors such as volatility and future price expectationscurves beyond thewhat is actively quoted portion ofin the price curve.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” for additional information.
We measure these risks by using complex valuationanalytical tools, both external and proprietary, which allow us to model prices for periods for which active quotes are unavailable.proprietary. These models are dynamic and are continuously updated with the most recent data to improve estimatesassessments of potential future expectations.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 “Value at Risk”“Trading Portfolio Risks” 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. However, weWe monitor potential losses using VaR analysis. OurAs previously discussed, our one-day VaR at December 31, 20032004, assuming a 95 percent confidence level, was approximately $0.6$1.9 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 will be less than the reported amount. In addition, our five-day VaR at December 31, 2004, assuming the same 95 percent confidence level, was approximately $3.9 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 tenor.length. Net gains and losses resulting from revaluation of contracts during the period are recognized currently in the Statements of Income.
Our retail revenues include amounts that are not yet billed 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 complex 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 revenue is billed. Related receivables are sold under the accounts receivable sales agreement and therefore are not
9085
reflected on our Balance Sheets. See Note 1(d)(i) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information.
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The amount of unbilled revenues for Cinergy, CG&E, PSI, and ULH&P as of December 31, 2003, 2002, and 2001 were as follows:
|
| 2003 |
| 2002 |
| 2001 |
| |||
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| (in millions) |
| |||||||
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| |||||||
Cinergy |
| $ | 176 |
| $ | 153 |
| $ | 172 |
|
CG&E and subsidiaries |
| 112 |
| 89 |
| 104 |
| |||
PSI |
| 64 |
| 64 |
| 68 |
| |||
ULH&P |
| 20 |
| 15 |
| 18 |
| |||
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 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 deferralscalculations under the fuel adjustment clauseand emission allowance cost recovery mechanismmechanisms 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(including purchased power when economically displacing fuel,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, 2003,2004, regulatory assets totaled $595$609 million for CG&E (including $13$10 million for ULH&P) and $417$421 million for PSI. Current rates include the recovery of $587$602 million for CG&E (including $12$9 million for ULH&P) and $317$378 million for PSI. Of the $100 million not yet approved for recovery by PSI, $42 million relates to reorganization costs incurred in connection with the merger with CG&E. Deferral of these costs for inclusion in PSI’s current rate case was previously authorized by the IURC. PSI has requested recovery of these costs in its pending rate case and a decision by the IURC is expected to be made in the first quarter of 2004. Should the IURC deny recovery of those costs, a charge to current period earnings would be required. In addition to the regulatory assets, CG&E and PSI have regulatory liabilities totaling $155$165 million (including $27$30 million for ULH&P) and $336$392 million at December 31, 2003,2004, respectively. See Note 1(c) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional detail regarding regulatory assets and regulatory liabilities.
Cinergy’s reported costs of providing pension and other postretirement benefits (as described in Note 9 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
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Pension costs associated with Cinergy’s defined benefit pension plans, for example, are impacted by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plan, and earnings on plan assets. Changes made to the provisions of the plan may impact current and future pension costs. 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 and pension costs.
In accordance with Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions (Statement 87), changes in pension obligations associated with the above factors may not be immediately recognized as pension costs on the Statements of Income, but may be deferred and amortized in the future over the average remaining service period of active plan participants to the extent that Statement 87 recognition provisions are triggered. For the years ended December 31, 2003, 2002, and 2001, we recorded pension costs for our defined benefit pension plans (including early retirement program costs recognized in accordance with Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits (Statement 88)) of approximately $62 million, $68 million, and $32 million, respectively.
Cinergy’s pension plan assets are principally comprised of equity and debt investments. Differences between actual portfolio returns and expected returns may result in increased or decreased pension costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs.
In selecting our discount rate assumption, we considered rates of return on high-quality corporate debt instruments that are expected to be available through the maturity dates of the pension benefits. Our expected long-term rate of return on plan assets is based on a calculation provided by an independent investment-consulting firm. Our expected long-term rate of return on pension plan assets is based on our targeted asset allocation assumption of 60 percent equity investments and 40 percent debt investments. Our 60 percent equity investment target includes allocations to domestic, developed international, and emerging markets equities. Our asset allocation is designed to achieve a moderate level of overall portfolio risk in keeping with Cinergy’s desired risk objective. We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate.
We base our determination of pension cost on a market-related valuation of assets that reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual fair value of assets.
Based on our assumed long-term rate of return of 8.5 percent, discount rate of 6.25 percent, and various other assumptions, we estimate that our pension costs associated with our defined benefit pension plans will increase from $53 million (excluding Statement 88 costs) in 2003 to approximately $66 million in 2004. Modifying the expected long-term rate of return on our pension plan assets by .25 percent, and holding all other assumptions constant, would change
93
2004 pension costs by approximately $2 million. Lowering the discount rate assumption by .25 percent, and holding all other assumptions constant, would change 2004 pension costs by approximately $5 million.
Other postretirement benefit costs are impacted by employee demographics, per capita claims costs, and health care cost trend rates. Other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including the discount rates used in determining the accumulated postretirement benefit obligation and the postretirement benefit costs. In accordance with Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (Statement 106), changes in postretirement benefit obligations associated with these factors may not be immediately recognized as postretirement benefit costs but may be deferred and amortized in the future over the average remaining service period of active plan participants to the extent that Statement 106 recognition provisions are triggered. For the years ended December 31, 2003, 2002, and 2001, we recorded other postretirement benefit costs of approximately $35 million, $29 million, and $27 million, respectively, in accordance with the provisions of Statement 106. Based upon a discount rate of 6.25 percent and various other assumptions, we estimate that our other postretirement benefit costs will increase from $35 million in 2003 to approximately $38 million in 2004.
See Note 9 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for information on the effects of FASB Staff Position 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
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 tax credits associated with our production of synthetic fuel. Failure to achieve forecasted taxable income might affect our ability to utilize the Section 29 tax credits and the ultimate realization of deferred tax assets.
When it is probable that an environmental, tax, or other legal liability has been incurred, a loss is recognized assumingwhen 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 legal obligations incurred are materially different from our estimates, the recognition of the actual amounts may have a material impact on
94
Cinergy’s financial position and results of operations and financial position.operations.
In July 2002, Cinergy Capital & Trading, Inc. acquired a coal-based synthetic fuel production facility. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with Internal Revenue Code (IRC) Section 29 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. In addition to the existing plant, we have recently exercised an option to buy an additional synthetic fuel plant.
Current accounting standards require long-lived assets be measuredDuring the third quarter of 2004, several unrelated entities announced that the Internal Revenue Service (IRS) had or threatened to challenge the placed in service dates of some of the entities’ synthetic fuel plants. A successful IRS challenge could result in disallowance of all credits previously claimed for impairment whenever indicatorsfuel produced by the subject plants. Cinergy’s sale 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 producersynthetic fuel has generated approximately $219 million in tax credits through December 31, 2004, of electricity,which approximately $96 million were generated in 2004.
The IRS has not yet audited Cinergy for any tax year in which Cinergy has claimed Section 29 credits related to synthetic fuel. However, it is reasonable to anticipate that the IRS will evaluate the placed in service date and other key requirements for claiming the credit. We anticipate this audit to begin in the spring of 2005.
Cinergy received a private letter ruling from the IRS in connection with the acquisition of the facility that specifically addressed the significant chemical change requirement. Additionally, although not addressed in the letter ruling, we believe that our facility’s in service date meets the Section 29 requirements.
IRC Section 29 also provides for a phase-out of the credit based on the price of crude oil. The phase-out is based on a prescribed calculation and definition of crude oil prices. We do not expect any impact on our ability to utilize Section 29 credits in 2004. Future increases in crude oil prices above the price stipulated by the IRS could negatively impact our ability to utilize credits in subsequent years.
74
MD&A - MARKET RISK SENSITIVE INSTRUMENTS
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.
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.
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
75
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. Prior to March 31, 2004, our VaR model used the Parametric variance-covariance statistical modeling technique and historical volatilities and correlations over the past 21-trading day period. Beginning with April 1, 2004, we calculate VaR using a Monte Carlo simulation methodology using implied forward-looking volatilities and historical correlations. Comparisons indicated that the differences in VaR between the Monte Carlo and Parametric calculations were not material and were within expectations. The primary reason for changing to a Monte Carlo approach is that it offers a more scalable method for handling more complex derivative positions and provides a consistent platform for quantifying both market and credit risk.
The VaR for Cinergy’s trading portfolio is presented in the table below:
VaR Associated with Energy Trading Contracts |
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| 2004 |
| 2003 |
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| Trading VaR |
| Percentage of Operating Income |
| Trading VaR |
| Percentage of Operating Income |
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| (dollars in millions) |
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95% confidence level, one-day holding period, one-tailed December 31 |
| $ | 1.9 |
| 0.3 | % | $ | 0.6 |
| 0.1 | % |
Average for the twelve months ended December 31 |
| 2.4 |
| 0.3 |
| 1.3 |
| 0.2 |
| ||
High for the twelve months ended December 31 |
| 5.8 |
| 0.8 |
| 3.8 |
| 0.5 |
| ||
Low for the twelve months ended December 31 |
| 0.7 |
| 0.1 |
| 0.4 |
| 0.1 |
| ||
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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, 2004 and 2003 are presented in the table below. In April 2002, CG&E and PSI are ownersexecuted a new joint operating agreement whereby we chose to originate all new power marketing and trading contracts since April 2002 on behalf of generating plants, which are largely coal-fired. At December 31, 2003, the carrying value of these generating plants is $5 billion for Cinergy, $2 billion for CG&E and $2 billion foronly. Historically, such contracts were executed on behalf of PSI. As a result and CG&E jointly. PSI’s remaining contracts, entered into prior to the new joint operating agreement, are not material. Therefore, we have not presented PSI separately in the fair value tables below.
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| Change in Fair Value |
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| 2004 |
| 2003 |
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| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
| ||||
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| (in millions) |
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Fair value of contracts outstanding at the beginning of period |
| $ | 41 |
| $ | 20 |
| $ | 75 |
| $ | 42 |
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Changes in fair value attributable to changes in valuation techniques and assumptions(2) |
| (5 | ) | (4 | ) | 1 |
| 1 |
| ||||
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Other changes in fair value(3) |
| 185 |
| 70 |
| 127 |
| 53 |
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Option premiums paid/(received) |
| 5 |
| 6 |
| (3 | ) | 2 |
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Accounting Changes(4) |
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Consolidation of previously unconsolidated entities |
| — |
| — |
| 7 |
| — |
| ||||
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Cumulative effect of changes in accounting principles |
| — |
| — |
| (20 | ) | (13 | ) | ||||
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Contracts settled |
| (144 | ) | (56 | ) | (146 | ) | (65 | ) | ||||
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Fair value of contracts outstanding at end of period |
| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
|
(1)The results of the various emissionsCinergyalso 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 by-products of coal consumption, the companies are subject to extensive environmental regulations and are currently subject to a number of environmental contingencies. unrealized gains on energy trading contracts.
(4)See Note 1(i)1(q)(i) and Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additionalfurther information. While we cannot predict
The following are the potential affect the resolutionbalances at December 31, 2004 and 2003 of these matters will have on our financial position orenergy risk management assets and liabilities:
|
| 2004 |
| 2003 |
| ||||||||
|
| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
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| (in millions) |
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Energy risk management assets - current |
| $ | 381 |
| $ | 149 |
| $ | 305 |
| $ | 73 |
|
Energy risk management assets - non-current |
| 139 |
| 47 |
| 97 |
| 37 |
| ||||
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Energy risk management liabilities - current |
| (311 | ) | (120 | ) | (296 | ) | (78 | ) | ||||
Energy risk management liabilities - non-current |
| (127 | ) | (40 | ) | (65 | ) | (12 | ) | ||||
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| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
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(1)The results of operations, we believe that the carrying values of these assets are recoverable. In making this assessment, we consider such factors as the expected abilityCinergy also include amounts related to recover additional investment in environmental compliance expenditures, the relative pricing of wholesale electricity in the region, the anticipated demand, and the cost of fuel. We will continue to evaluate these assets for impairment when events or circumstances indicate the carrying value may not be recoverable.non-registrants.
77
In October 2002, the EITF reached consensus in EITF 02-3, to (a) rescind EITF 98-10, (b) generally preclude the recognition of gains at the inception of new derivatives, and (c) require all realized and unrealized gains and losses on energy trading derivatives to be presented net in the Statements of Income, whether or not settled physically.
The consensus to rescind EITF 98-10 required allfollowing table presents the expected maturity of the energy trading contracts that do not qualifyrisk management assets and liabilities as derivatives to be accounted for on an accrual basis, rather than at fair value. The consensus was immediately effective for all new contracts executed after October 25, 2002, and required a cumulative effect adjustment to income, net of tax, on January 1, 2003, for all contracts executed on or prior to October 25, 2002. The cumulative effect adjustment, on a net of tax basis, was a loss of approximately $13 millionDecember 31, 2004 for Cinergy and $8 million for CG&E, which primarily includes:
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| Fair Value of Contracts at December 31, 2004 |
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| Maturing |
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Source of Fair Value(1) |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| Thereafter |
| Total Fair Value |
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| (in millions) |
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Cinergy(2) |
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Prices actively quoted |
| $ | 74 |
| $ | 18 |
| $ | — |
| $ | — |
| $ | 92 |
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Prices based on models and other valuation methods(3) |
| (4 | ) | (5 | ) | 2 |
| (3 | ) | (10 | ) | |||||
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Total |
| $ | 70 |
| $ | 13 |
| $ | 2 |
| $ | (3 | ) | $ | 82 |
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CG&E |
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Prices actively quoted |
| $ | 25 |
| $ | 13 |
| $ | — |
| $ | — |
| $ | 38 |
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Prices based on models and other valuation methods(3) |
| 4 |
| (6 | ) | — |
| — |
| (2 | ) | |||||
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Total |
| $ | 29 |
| $ | 7 |
| $ | — |
| $ | — |
| $ | 36 |
|
(1) �� While liquidity varies by trading regions, active quotes are generally available for two years for standard electricity transactions and three years for standard gas transactions. Non-standard transactions are classified based on the impactextent, if any, of certain coal contracts, gas inventory, and certain gas contracts, which are accounted for atmodeling used in determining fair value. We expect this rescissionLong-term transactions can have portions in both categories depending on the length.
(2)The results of Cinergy also include amounts related to havenon-registrants.
(3)A substantial portion of these amounts include option values.
Generation Portfolio Risks
Cinergy optimizes the largest ongoing impact on our gas trading business, which uses financial contracts, physical contracts,value of its non-regulated portfolio. The portfolio includes generation assets (power and gas inventory to take advantage of various arbitrage opportunities. Prior to the rescission of EITF 98-10,capacity), fuel, and emission allowances and we manage all of these activities were accounted for at fair value. Under the revised guidance, only certain items are accounted for at fair value, which could increase inter-period volatility in reported results of operations. Ascomponents as a result, we began applying fair value hedge accounting in June 2003 to certain quantities of gas inventory (more fully discussed in Note 1(k)(i)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 “Notesportfolio are bought and sold based on this model in order to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”) and are further reviewing additional applications for hedge accounting.
The consensus to require all gains and losses on energy trading derivatives to be presented net in
95
manage the Statementseconomic value of Income was effective January 1, 2003, and required reclassification for all periods presented. This resulted in substantial reductions in reported Operating Revenues, Fuel and purchased and exchanged power expense, and Gas purchased expense. However, Operating Income and Net Income were not affected by this change.
In May 2003, the FASB issuedportfolio. With the issuance of Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (Statement 149). Statement 149 primarily amends Statement 133 to incorporate implementation conclusions previously cleared by, most forward power transactions from management of the FASB staff, to clarify the definition of a derivative and to require derivative instruments that include up-front cash payments to be classified as a financing activity in the Statements of Cash Flows. Implementation issues previously cleared by the FASB staff were effectiveportfolio are accounted for at the time they were cleared and new guidance was effective in the third quarter of 2003. In connection with our adoption, we reviewed certain power purchase or sale contracts to determine if they met the revised normal purchases and sales scope exception criteria in Statement 149. If these criteria were not met, the contract was adjusted to fair value. The impactother component pieces of adoptingthe portfolio are typically not subject to Statement 149 wasand are accounted for using the accrual method, where changes in fair value are not materialrecognized. As a result, we are subject to our financial positionearnings volatility via mark-to-market gains or results of operations.
In June 2003, the FASB issued final guidance on the use of broad market indices (e.g., consumer price index) in power purchases and sales contracts. This guidance clarifies that the normal purchases and sales scope exception is precluded if a contract contains a broad market index that is not clearly and closely related to the asset being sold or purchased (or a direct factorlosses from changes in the productionvalue of the asset soldcontracts accounted for using fair value. A hypothetical $1.00 per MWh increase or purchased). The guidance provides criteria that must be met for the indexdecrease consistently applied to be considered clearly and closely related. This guidance, which was effectiveall forward power prices would have resulted in the fourth quarter of 2003, was not material to our financial positionan increase or results of operations.
In July 2001, the FASB issued Statement 143, which requiresdecrease in fair value recognition beginning January 1, 2003, of legal obligations associated with the retirement or removalthese contracts of long-lived assets at the time the obligations are incurred. Statement 143 prohibits the accrualapproximately $3 million as of estimated retirement and removal costs unless resulting from legal obligations. Our accounting policy for such legal obligations and for accrued cost of removal for our rate regulated long-lived assets is described in Note 1 (j) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
We adopted Statement 143 on January 1, 2003, and Cinergy and CG&E both recognized a gain of $39 million (net of tax) for the cumulative effect of this change in accounting principle. Substantially all of this adjustment reflects the reversal of previously accrued cost of removal for CG&E’s generating assets, which do not apply the provisions of Statement 71. Accrued cost of removal at adoption included $316 million, $25 million, and $146 million of accumulated cost of removal related to PSI’s, ULH&P’s, and CG&E’s utility plant in service assets, respectively, which represent regulatory liabilities after adoption and were not included as part of the cumulative effect adjustment. The increases in assets and liabilities from adopting Statement 143 were not material to our financial position.
Pro-forma results as if Statement 143 was applied retroactively for the years ended December 31, 2002 and 2001, are not materially different from reported results.
96
Consolidation of VIEs
In January 2003, the FASB issued Interpretation 46, which significantly changes the consolidation requirements for traditional special purpose entities (SPE) and certain other entities subject to its scope. This interpretation defines a VIE as (a) an entity that does not have sufficient equity to support its activities without additional financial support or (b) an entity that has equity investors that do not have voting rights or do not absorb losses or receive returns. These entities must be consolidated when certain criteria are met. The interpretation was originally to be effective as of July 1, 2003 for Cinergy; however, the FASB subsequently permitted deferral of the effective date to December 31, 2003 for traditional SPEs and to March 31, 2004 for all other entities subject to the scope of Interpretation 46. During this deferral period, the FASB clarified and amended several provisions, much of which is intended to assist in the application of Interpretation 46 to operating entities. Clarifications were not needed for most traditional SPEs and we therefore elected to implement Interpretation 46 for such entities, as discussed below, in accordance with the original implementation date of July 1, 2003. Prior period financial statements were not restated for these changes.
Interpretation 46 required us to consolidate two SPEs that have individual power sale agreements to Central Maine Power Company. Further, we were no longer permitted to consolidate a trust that was established by Cinergy Corp. in 2001 to issue approximately $316 million of combined preferred trust securities and stock purchase contracts. For further information on the accounting for these entities see Note 3 of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.2004.
Cinergy has concluded 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 are partially mitigated in 2005 and 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 will recover 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.
78
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 sale facility, as discussedfrom 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, 2004, we believe the likelihood of significant losses associated with credit risk in Note 3(c)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 “Notesoutstanding obligation. Exposures to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”, will remain unconsolidated since it involves transfers of financial assets to a qualifying SPE,credit risks are monitored daily by the Corporate Credit Risk function, which is exempted from consolidation by Interpretation 46independent of all trading operations. Energy commodity prices can be extremely volatile and Statement 140.the market can, at times, lack liquidity. Because of these issues, credit risk for energy commodities is generally greater than with other commodity trading.
79
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, 2004. 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.
Cinergy(1)
Rating |
| Total Exposure |
| Credit Collateral |
| Net Exposure |
| Percentage of |
| Number of |
| Net Exposure of |
| ||||
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(2) |
| $ | 737 |
| $ | 75 |
| $ | 662 |
| 84 | % | — |
| $ | — |
|
Internally Rated-Investment Grade(3) |
| 68 |
| 1 |
| 67 |
| 9 |
| — |
| — |
| ||||
Non-Investment Grade |
| 135 |
| 90 |
| 45 |
| 5 |
| — |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| 51 |
| 37 |
| 14 |
| 2 |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| — |
|
|
| ||||
Total |
| $ | 991 |
| $ | 203 |
| $ | 788 |
| 100 | % | — |
| $ | — |
|
|
|
|
| Maturity of Credit Risk Exposure |
| |||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
| Exposure |
| Total Exposure |
| |||||
|
|
|
|
|
|
|
| Greater than |
| Before Credit |
| |||||
Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment Grade(2) |
| $ | 636 |
| $ | 74 |
| $ | 16 |
| $ | 11 |
| $ | 737 |
|
Internally Rated-Investment Grade(3) |
| 61 |
| 7 |
| — |
| — |
| 68 |
| |||||
Non-Investment Grade |
| 133 |
| 2 |
| — |
| — |
| 135 |
| |||||
Internally Rated-Non-Investment Grade |
| 50 |
| 1 |
| — |
| — |
| 51 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 880 |
| $ | 84 |
| $ | 16 |
| $ | 11 |
| $ | 991 |
|
(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 continuinga review of (but not limited to) counterparty financial statements with consideration given to evaluateoff-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.
80
CG&E
|
| Total Exposure Before Credit Collateral |
| Credit Collateral |
| Net Exposure |
| Percentage of Total Net Exposure |
| Number of Counterparties |
| Net Exposure of |
| ||||
Rating |
|
|
|
|
|
|
| ||||||||||
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(1) |
| $ | 165 |
| $ | 21 |
| $ | 144 |
| 92 | % | 2 |
| $ | 45 |
|
Internally Rated-Investment Grade(2) |
| 8 |
| — |
| 8 |
| 5 |
| — |
| — |
| ||||
Non-Investment Grade |
| 18 |
| 15 |
| 3 |
| 2 |
| — |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| 3 |
| 1 |
| 2 |
| 1 |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 194 |
| $ | 37 |
| $ | 157 |
| 100 | % | 2 |
| $ | 45 |
|
|
| Maturity of Credit Risk Exposure |
| |||||||||||||
|
|
|
|
|
|
|
| Exposure |
| Total Exposure |
| |||||
|
|
|
|
|
|
|
| Greater than |
| Before Credit |
| |||||
Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment Grade(1) |
| $ | 156 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 165 |
|
Internally Rated-Investment Grade(2) |
| 8 |
| — |
| — |
| — |
| 8 |
| |||||
Non-Investment Grade |
| 18 |
| — |
| — |
| — |
| 18 |
| |||||
Internally Rated-Non-Investment Grade |
| 3 |
| — |
| — |
| — |
| 3 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 185 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 194 |
|
(1) Includes counterparties rated Investment Grade or the impactcounterparties’ 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 Interpretation 46offset exists and as a result, credit is extended and evaluated on several operating joint ventures, primarily involved in cogenerationa separate basis.
Financial Derivatives
Potential exposure to credit risk also exists from our use of financial derivatives such as interest rate swaps and energy efficiency operations, thattreasury locks. Because these financial instruments are transacted with highly rated financial institutions, we currently do not consolidate. If all these entities were consolidated, their total assets of approximately $590 million (the majority of which is non-current) and total liabilities of approximately $210 million (which includes long-term debt of approximately $90 million) would be recognized on our Balance Sheets. Cinergy’s current investment in these entities is approximately $200 million. We also guarantee certain performance obligations of these entities with an estimated maximum potential exposure of approximately $40 million, as disclosed in Note 11(c)(vii)anticipate nonperformance by any of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”. If any of these entities are required to be consolidated, they will be included in the March 31, 2004 consolidated financial statements.counterparties.
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.
Cinergy has exposure to fluctuations in exchange rates between the FASB issued StatementUnited States dollar and the currencies of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristicsforeign countries where we have investments. When it is appropriate we will hedge our exposure to cash flow transactions, such as a dividend payment by one of Both Liabilities and Equity (Statement 150). Statement 150 establishes standards for how an issuer classifies and measuresour foreign subsidiaries.
9781
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, 2004:
Interest Benchmark |
| 2004 |
| |||||
|
|
|
|
|
| (in millions) |
| |
|
|
|
|
|
|
|
| |
Short-term Bank Loans/Commercial Paper/Money Pool |
| •Short-term Money Market |
| Cinergy |
| $ | 686 |
|
|
| •Commercial Paper |
| CG&E and subsidiaries |
| 180 |
| |
|
| Composite Rate(1) |
| PSI |
| 131 |
| |
|
| •LIBOR(2) |
| ULH&P |
| 11 |
| |
|
|
|
|
|
|
|
| |
Pollution Control Debt |
| •Daily Market |
| Cinergy |
| 741 |
| |
|
| •Weekly Market |
| CG&E and subsidiaries |
| 290 |
| |
|
| •Auction Rate |
| PSI |
| 426 |
| |
(1)30-day Federal Reserve “AA” Industrial Commercial Paper Composite Rate
(2)London Inter-Bank Offered Rate
certain financialThe weighted-average interest rates on the previously discussed instruments with characteristicsat December 31, were as follows:
2004 | |||
Short-term Bank Loans/Commercial Paper | 2.5 | % | |
Money Pool | 2.4 | % | |
Pollution Control Debt | 2.3 | % | |
At December 31, 2004, forward yield curves project an increase in applicable short-term interest rates over the next five years.
82
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 both liabilitiesDecember 31, 2004:
|
| Expected Maturity Date |
| |||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| There- |
|
|
| Fair |
| |||||||||||||||||||||||
Liabilities |
| 2005 |
| 2006 |
| 2007 |
| 2008 |
| 2009 |
| after |
| Total |
| Value |
| |||||||||||||||||||||||
|
| (in millions) |
| |||||||||||||||||||||||||||||||||||||
|
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|
|
|
|
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|
|
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|
|
|
|
|
|
|
| |||||||||||||||||||||||
Cinergy |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt(1)(6) |
| $ | 200 | (4)(5) | $ | 326 |
| $ | 366 |
| $ | 513 |
| $ | 243 |
| $ | 2,223 |
| $ | 3,871 |
| $ | 4,074 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 6.8 | % | 6.6 | % | 7.6 | % | 6.4 | % | 7.4 | % | 7.1 | % | 7.0 | % |
|
| |||||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Other(3) |
| $ | 20 |
| $ | 29 |
| $ | 360 |
| $ | 38 |
| $ | 27 |
| $ | 153 |
| $ | 627 |
| $ | 687 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 7.9 | % | 6.8 | % | 6.9 | % | 6.9 | % | 6.7 | % | 6.9 | % | 6.9 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 7 |
| $ | 7 |
| $ | 7 |
| $ | 10 |
| $ | 10 |
| $ | 24 |
| $ | 65 |
| $ | 65 |
| |||||||||||||||
Interest rate(2) |
| 5.4 | % | 5.3 | % | 5.3 | % | 5.2 | % | 5.1 | % | 4.9 | % | 5.5 | % |
|
| |||||||||||||||||||||||
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
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| |||||||||||||||||||||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt(1) |
| $ | 150 | (5) | $ | — |
| $ | 100 |
| $ | 120 |
| $ | 20 |
| $ | 1,240 |
| $ | 1,630 |
| $ | 1,677 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 6.9 | % | — | % | 6.9 | % | 6.4 | % | 7.9 | % | 5.1 | % | 5.5 | % |
|
| |||||||||||||||||||||||
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 4 |
| $ | 4 |
| $ | 4 |
| $ | 6 |
| $ | 6 |
| $ | 16 |
| $ | 40 |
| $ | 40 |
| |||||||||||||||
Interest rate(2) |
| 5.3 | % | 5.3 | % | 5.2 | % | 5.2 | % | 5.1 | % | 4.9 | % | 5.4 | % |
|
| |||||||||||||||||||||||
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| |||||||||||||||||||||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt(1) |
| $ | 50 | (4) | $ | 326 |
| $ | 266 |
| $ | 43 |
| $ | 223 |
| $ | 976 |
| $ | 1,884 |
| $ | 2,009 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 6.5 | % | 6.6 | % | 7.8 | % | 6.4 | % | 7.3 | % | 9.6 | % | 8.4 | % |
|
| |||||||||||||||||||||||
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|
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|
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|
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|
|
|
|
|
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| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 3 |
| $ | 3 |
| $ | 3 |
| $ | 4 |
| $ | 4 |
| $ | 8 |
| $ | 25 |
| $ | 25 |
| |||||||||||||||
Interest rate(2) |
| 5.5 | % | 5.4 | % | 5.4 | % | 5.3 | % | 5.1 | % | 4.9 | % | 5.6 | % |
|
| |||||||||||||||||||||||
|
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|
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|
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| |||||||||||||||||||||||
ULH&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt |
| $ | — |
| $ | — |
| $ | — |
| $ | 20 |
| $ | 20 |
| $ | 55 |
| $ | 95 |
| $ | 100 |
| |||||||||||||||
Weighted-average interest rate(2) |
| — | % | — | % | — | % | 6.5 | % | 7.9 | % | 5.7 | % | 6.3 | % |
|
| |||||||||||||||||||||||
|
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| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 2 |
| $ | 3 |
| $ | 9 |
| $ | 9 |
| |||||||||||||||
Interest rate(2) |
| 5.4 | % | 5.4 | % | 5.4 | % | 5.3 | % | 5.2 | % | 4.9 | % | 5.6 | % |
|
| |||||||||||||||||||||||
(1)Long-term Debt includes amounts reflected as Long-term debt due within one year.
(2)The weighted-average interest rate is calculated as follows: (1) for Long-term Debt and equity. This statement was effectiveOther, the weighted-average interest rate is based on the interest rates at December 31, 2004 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 financial instruments entered into or modified after May 31, 2003,Capital Leases, the weighted-average interest rate is based on the average interest rate of the lease payments made during the year reported.
(3)Promissory notes and was effective on July 1, 2003, for financial instruments held priorlong-term notes payable related to issuance of this statement. Statement 150 would have required investments under Cinergy Corp.’s preferred trust securitiesGlobal Resources, Inc., Cinergy Investments, Inc., and debt related to be reported as a liability; however, as described more fully inCC Funding Trust. See Note 3(b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”, for a discussion of the trust holding these securitiesdebt associated with the CC Funding Trust.
(4)Includes PSI’s 6.50% Debentures due August 1, 2026, reflected as maturing in 2005, as the interest rate is no longer permitteddue to reset on August 1, 2005. If the interest rate is not reset, the bonds are subject to mandatory redemption by PSI.
(5)CG&E’s 6.90% Debentures due June 1, 2025, are putable to CG&E at the option of the holders on June 1, 2005. However, based on current market conditions, we believe it is unlikely that the debentures will be consolidated and the preferred trust securities are no longer reportedput to CG&E on this date.
(6)Cinergy’s Includes amounts related to non-registrants.Balance Sheets. However, Cinergy’s note payable to the trust is recorded on the Balance Sheets as Long-term debt. As a result, the impact of adopting Statement 150 was not material to our financial position or results of operations.
As discussedOur 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.
83
CG&E has an outstanding interest rate swap agreement that decreased the percentage of variable-rate debt. See Note 3(b)7(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”, for additional information on financial derivatives.
84
Cinergy Corp.MD&A - - ACCOUNTING MATTERS issued forward stock sale contracts that require purchase by
Preparation of financial statements and related disclosures in compliance with GAAP requires the holderuse of a certain numberassumptions and estimates regarding future events, including the likelihood of Cinergy Corp. shares in February 2005 (stock contracts). The numbersuccess of sharesparticular 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 issued is contingent oncritical if: 1) the market price of Cinergy Corp. stock, but subjectaccounting estimate requires us to a predetermined ceilingmake assumptions about matters that were reasonably uncertain at the time the accounting estimate was made, and floor price. In October 2003, the FASB staff released an interpretation of Statement 150 that requires an evaluation of these stock contracts to determine whether they constitute a liability, with any2) changes in accounting required in January 2004. This interpretation did not have any impact on our current accounting.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.
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” for additional information.
AsWe 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 resultGlobal Risk Management function within Cinergy that is independent of the employees acceptingmarketing and trading function and is under the oversight of a VERPRisk 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” for additional information.
There is inherent risk in 2002, 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, 2004, assuming a 95 percent confidence level, was approximately $1.9 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 will be less than the reported amount. In addition, our five-day VaR at December 31, 2004, assuming the same 95 percent confidence level, was approximately $3.9 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 Energyrisk 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.
85
CinergyCG&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 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, 2004, regulatory assets totaled $609 million for CG&E (including $10 million for ULH&P) and $421 million for PSI. Current rates include the recovery of $602 million for CG&E (including $9 million for ULH&P) and $378 million for PSI. In addition to the regulatory assets, CG&Eand PSI recorded expenses of approximately $43 million, $19have regulatory liabilities totaling $165 million (including $3$30 million related tofor ULH&P), and $21$392 million at December 31, 2004, respectively.
During 2003, Cinergy offered a VERP and other severance benefits (Severance Programs) to certain non-union and union employees. As a result See Note 1(c) of the employees electing the Severance Programs, Cinergy recorded expenses of approximately $14 million during 2003.“Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional detail regarding regulatory assets and regulatory liabilities.
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 tax credits associated with our production of synthetic fuel. Failure to achieve forecasted taxable income might affect our ability to utilize the Section 29 tax credits and the ultimate realization of deferred tax assets.
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.
In July 2002, Cinergy Capital & Trading, Inc. acquired a coal-based synthetic fuel production facility. As of December 31, 2003, Capital & Trading’s net book value in this facility was approximately $60 million. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with Internal Revenue Code (IRC) Section 29 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. In addition to the existing plant, we have recently exercised an option to buy an additional synthetic fuel plant.
During the third quarter of 2004, several unrelated entities announced that the Internal Revenue Code. EligibilityService (IRS) had or threatened to challenge the placed in service dates of some of the entities’ synthetic fuel plants. A successful IRS challenge could result in disallowance of all credits previously claimed for thesefuel produced by the subject plants. Cinergy’s sale of synthetic fuel has generated approximately $219 million in tax credits expires after 2007.through December 31, 2004, of which approximately $96 million were generated in 2004.
The IRS has not yet audited Cinergy for any tax year in which Cinergy has claimed Section 29 credits related to synthetic fuel. However, it is reasonable to anticipate that the IRS will evaluate the placed in service date and other key requirements for claiming the credit. We anticipate this audit to begin in the spring of 2005.
Cinergy received a private letter ruling from the Internal Revenue Service (IRS)IRS in connection with the acquisition of the facility. Tofacility that specifically addressed the significant chemical change requirement. Additionally, although not addressed in the letter ruling, we believe that our facility’s in service date meets the Section 29 requirements.
IRC Section 29 also provides for a phase-out of the credit based on the price of crude oil. The phase-out is based on a prescribed calculation and definition of crude oil prices. We do not expect any impact on our ability to utilize Section 29 credits in 2004. Future increases in crude oil prices above the price stipulated by the IRS could negatively impact our ability to utilize credits in subsequent years.
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MD&A - MARKET RISK SENSITIVE INSTRUMENTS
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.
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.
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
75
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. Prior to March 31, 2004, our VaR model used the Parametric variance-covariance statistical modeling technique and historical volatilities and correlations over the past 21-trading day period. Beginning with April 1, 2004, we calculate VaR using a Monte Carlo simulation methodology using implied forward-looking volatilities and historical correlations. Comparisons indicated that the differences in VaR between the Monte Carlo and Parametric calculations were not material and were within expectations. The primary reason for changing to a Monte Carlo approach is that it offers a more scalable method for handling more complex derivative positions and provides a consistent platform for quantifying both market and credit risk.
The VaR for Cinergy’s trading portfolio is presented in the table below:
VaR Associated with Energy Trading Contracts |
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| 2004 |
| 2003 |
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| Trading VaR |
| Percentage of Operating Income |
| Trading VaR |
| Percentage of Operating Income |
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| (dollars in millions) |
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95% confidence level, one-day holding period, one-tailed December 31 |
| $ | 1.9 |
| 0.3 | % | $ | 0.6 |
| 0.1 | % |
Average for the twelve months ended December 31 |
| 2.4 |
| 0.3 |
| 1.3 |
| 0.2 |
| ||
High for the twelve months ended December 31 |
| 5.8 |
| 0.8 |
| 3.8 |
| 0.5 |
| ||
Low for the twelve months ended December 31 |
| 0.7 |
| 0.1 |
| 0.4 |
| 0.1 |
| ||
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Changes in Fair Value
The changes in fair value of the energy risk management assets and liabilities for Cinergy has producedand CG&E for the years ended December 31, 2004 and 2003 are presented in the table below. In April 2002, CG&E and PSI executed a new joint operating agreement whereby we chose to originate all new power marketing and trading contracts since April 2002 on behalf of CG&E only. Historically, such contracts were executed on behalf of PSI and CG&E jointly. PSI’s remaining contracts, entered into prior to the new joint operating agreement, are not material. Therefore, we have not presented PSI separately in the fair value tables below.
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| Change in Fair Value |
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| 2004 |
| 2003 |
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| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
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| (in millions) |
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Fair value of contracts outstanding at the beginning of period |
| $ | 41 |
| $ | 20 |
| $ | 75 |
| $ | 42 |
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Changes in fair value attributable to changes in valuation techniques and assumptions(2) |
| (5 | ) | (4 | ) | 1 |
| 1 |
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Other changes in fair value(3) |
| 185 |
| 70 |
| 127 |
| 53 |
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Option premiums paid/(received) |
| 5 |
| 6 |
| (3 | ) | 2 |
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Accounting Changes(4) |
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Consolidation of previously unconsolidated entities |
| — |
| — |
| 7 |
| — |
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Cumulative effect of changes in accounting principles |
| — |
| — |
| (20 | ) | (13 | ) | ||||
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Contracts settled |
| (144 | ) | (56 | ) | (146 | ) | (65 | ) | ||||
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Fair value of contracts outstanding at end of period |
| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
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(1)The results ofCinergyalso 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)See Note 1(q)(i) and Note 1(q)(iv) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for further information.
The following are the balances at December 31, 2004 and 2003 of our energy risk management assets and liabilities:
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| 2004 |
| 2003 |
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| Cinergy(1) |
| CG&E |
| Cinergy(1) |
| CG&E |
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Energy risk management assets - current |
| $ | 381 |
| $ | 149 |
| $ | 305 |
| $ | 73 |
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Energy risk management assets - non-current |
| 139 |
| 47 |
| 97 |
| 37 |
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Energy risk management liabilities - current |
| (311 | ) | (120 | ) | (296 | ) | (78 | ) | ||||
Energy risk management liabilities - non-current |
| (127 | ) | (40 | ) | (65 | ) | (12 | ) | ||||
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| $ | 82 |
| $ | 36 |
| $ | 41 |
| $ | 20 |
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(1)The results of Cinergy also include amounts related to non-registrants.
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The following table presents the expected maturity of the energy risk management assets and liabilities as of December 31, 2004 for Cinergy and CG&E:
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| Fair Value of Contracts at December 31, 2004 |
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| Maturing |
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Source of Fair Value(1) |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| Thereafter |
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Cinergy(2) |
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Prices actively quoted |
| $ | 74 |
| $ | 18 |
| $ | — |
| $ | — |
| $ | 92 |
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Prices based on models and other valuation methods(3) |
| (4 | ) | (5 | ) | 2 |
| (3 | ) | (10 | ) | |||||
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Total |
| $ | 70 |
| $ | 13 |
| $ | 2 |
| $ | (3 | ) | $ | 82 |
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CG&E |
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Prices actively quoted |
| $ | 25 |
| $ | 13 |
| $ | — |
| $ | — |
| $ | 38 |
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Prices based on models and other valuation methods(3) |
| 4 |
| (6 | ) | — |
| — |
| (2 | ) | |||||
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Total |
| $ | 29 |
| $ | 7 |
| $ | — |
| $ | — |
| $ | 36 |
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(1) �� While liquidity varies by trading regions, active quotes are generally available for two years for standard electricity transactions and three years for standard gas transactions. 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.
(3)A substantial portion of these amounts include option values.
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 Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (Statement 149), most forward power 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 increase or decrease consistently applied to all forward power prices would have resulted in an increase or decrease in fair value of these contracts of approximately 4.4$3 million tonsas of December 31, 2004.
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 are partially mitigated in 2005 and 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 will recover 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.
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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, 2004, 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.
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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, 2004. 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.
Cinergy(1)
Rating |
| Total Exposure |
| Credit Collateral |
| Net Exposure |
| Percentage of |
| Number of |
| Net Exposure of |
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Investment Grade(2) |
| $ | 737 |
| $ | 75 |
| $ | 662 |
| 84 | % | — |
| $ | — |
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Internally Rated-Investment Grade(3) |
| 68 |
| 1 |
| 67 |
| 9 |
| — |
| — |
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Non-Investment Grade |
| 135 |
| 90 |
| 45 |
| 5 |
| — |
| — |
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Internally Rated-Non-Investment Grade |
| 51 |
| 37 |
| 14 |
| 2 |
| — |
| — |
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| — |
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Total |
| $ | 991 |
| $ | 203 |
| $ | 788 |
| 100 | % | — |
| $ | — |
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| Maturity of Credit Risk Exposure |
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| Before Credit |
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Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
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Investment Grade(2) |
| $ | 636 |
| $ | 74 |
| $ | 16 |
| $ | 11 |
| $ | 737 |
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Internally Rated-Investment Grade(3) |
| 61 |
| 7 |
| — |
| — |
| 68 |
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Non-Investment Grade |
| 133 |
| 2 |
| — |
| — |
| 135 |
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Internally Rated-Non-Investment Grade |
| 50 |
| 1 |
| — |
| — |
| 51 |
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Total |
| $ | 880 |
| $ | 84 |
| $ | 16 |
| $ | 11 |
| $ | 991 |
|
(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.
80
CG&E
|
| Total Exposure Before Credit Collateral |
| Credit Collateral |
| Net Exposure |
| Percentage of Total Net Exposure |
| Number of Counterparties |
| Net Exposure of |
| ||||
Rating |
|
|
|
|
|
|
| ||||||||||
|
| (in millions) |
| ||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
| ||||
Investment Grade(1) |
| $ | 165 |
| $ | 21 |
| $ | 144 |
| 92 | % | 2 |
| $ | 45 |
|
Internally Rated-Investment Grade(2) |
| 8 |
| — |
| 8 |
| 5 |
| — |
| — |
| ||||
Non-Investment Grade |
| 18 |
| 15 |
| 3 |
| 2 |
| — |
| — |
| ||||
Internally Rated-Non-Investment Grade |
| 3 |
| 1 |
| 2 |
| 1 |
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 194 |
| $ | 37 |
| $ | 157 |
| 100 | % | 2 |
| $ | 45 |
|
|
| Maturity of Credit Risk Exposure |
| |||||||||||||
|
|
|
|
|
|
|
| Exposure |
| Total Exposure |
| |||||
|
|
|
|
|
|
|
| Greater than |
| Before Credit |
| |||||
Rating |
| 2005 |
| 2006-2007 |
| 2008-2009 |
| 5 Years |
| Collateral |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment Grade(1) |
| $ | 156 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 165 |
|
Internally Rated-Investment Grade(2) |
| 8 |
| — |
| — |
| — |
| 8 |
| |||||
Non-Investment Grade |
| 18 |
| — |
| — |
| — |
| 18 |
| |||||
Internally Rated-Non-Investment Grade |
| 3 |
| — |
| — |
| — |
| 3 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total |
| $ | 185 |
| $ | 8 |
| $ | 1 |
| $ | — |
| $ | 194 |
|
(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.
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.
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, such as a dividend payment by one of our foreign subsidiaries.
81
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, 2004:
Interest Benchmark |
| 2004 |
| |||||
|
|
|
|
|
| (in millions) |
| |
|
|
|
|
|
|
|
| |
Short-term Bank Loans/Commercial Paper/Money Pool |
| •Short-term Money Market |
| Cinergy |
| $ | 686 |
|
|
| •Commercial Paper |
| CG&E and subsidiaries |
| 180 |
| |
|
| Composite Rate(1) |
| PSI |
| 131 |
| |
|
| •LIBOR(2) |
| ULH&P |
| 11 |
| |
|
|
|
|
|
|
|
| |
Pollution Control Debt |
| •Daily Market |
| Cinergy |
| 741 |
| |
|
| •Weekly Market |
| CG&E and subsidiaries |
| 290 |
| |
|
| •Auction Rate |
| PSI |
| 426 |
| |
(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:
2004 | |||
Short-term Bank Loans/Commercial Paper | 2.5 | % | |
Money Pool | 2.4 | % | |
Pollution Control Debt | 2.3 | % | |
At December 31, 2004, forward yield curves project an increase in applicable short-term interest rates over the next five years.
82
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, 2004:
|
| Expected Maturity Date |
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| There- |
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| Fair |
| |||||||||||||||||||||||
Liabilities |
| 2005 |
| 2006 |
| 2007 |
| 2008 |
| 2009 |
| after |
| Total |
| Value |
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| (in millions) |
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Cinergy |
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| |||||||||||||||||||||||
Long-term Debt(1)(6) |
| $ | 200 | (4)(5) | $ | 326 |
| $ | 366 |
| $ | 513 |
| $ | 243 |
| $ | 2,223 |
| $ | 3,871 |
| $ | 4,074 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 6.8 | % | 6.6 | % | 7.6 | % | 6.4 | % | 7.4 | % | 7.1 | % | 7.0 | % |
|
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| |||||||||||||||||||||||
Other(3) |
| $ | 20 |
| $ | 29 |
| $ | 360 |
| $ | 38 |
| $ | 27 |
| $ | 153 |
| $ | 627 |
| $ | 687 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 7.9 | % | 6.8 | % | 6.9 | % | 6.9 | % | 6.7 | % | 6.9 | % | 6.9 | % |
|
| |||||||||||||||||||||||
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| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 7 |
| $ | 7 |
| $ | 7 |
| $ | 10 |
| $ | 10 |
| $ | 24 |
| $ | 65 |
| $ | 65 |
| |||||||||||||||
Interest rate(2) |
| 5.4 | % | 5.3 | % | 5.3 | % | 5.2 | % | 5.1 | % | 4.9 | % | 5.5 | % |
|
| |||||||||||||||||||||||
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|
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|
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| |||||||||||||||||||||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt(1) |
| $ | 150 | (5) | $ | — |
| $ | 100 |
| $ | 120 |
| $ | 20 |
| $ | 1,240 |
| $ | 1,630 |
| $ | 1,677 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 6.9 | % | — | % | 6.9 | % | 6.4 | % | 7.9 | % | 5.1 | % | 5.5 | % |
|
| |||||||||||||||||||||||
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 4 |
| $ | 4 |
| $ | 4 |
| $ | 6 |
| $ | 6 |
| $ | 16 |
| $ | 40 |
| $ | 40 |
| |||||||||||||||
Interest rate(2) |
| 5.3 | % | 5.3 | % | 5.2 | % | 5.2 | % | 5.1 | % | 4.9 | % | 5.4 | % |
|
| |||||||||||||||||||||||
|
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|
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| |||||||||||||||||||||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt(1) |
| $ | 50 | (4) | $ | 326 |
| $ | 266 |
| $ | 43 |
| $ | 223 |
| $ | 976 |
| $ | 1,884 |
| $ | 2,009 |
| |||||||||||||||
Weighted-average interest rate(2) |
| 6.5 | % | 6.6 | % | 7.8 | % | 6.4 | % | 7.3 | % | 9.6 | % | 8.4 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 3 |
| $ | 3 |
| $ | 3 |
| $ | 4 |
| $ | 4 |
| $ | 8 |
| $ | 25 |
| $ | 25 |
| |||||||||||||||
Interest rate(2) |
| 5.5 | % | 5.4 | % | 5.4 | % | 5.3 | % | 5.1 | % | 4.9 | % | 5.6 | % |
|
| |||||||||||||||||||||||
|
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|
|
|
|
|
|
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|
|
|
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|
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|
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| |||||||||||||||||||||||
ULH&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Long-term Debt |
| $ | — |
| $ | — |
| $ | — |
| $ | 20 |
| $ | 20 |
| $ | 55 |
| $ | 95 |
| $ | 100 |
| |||||||||||||||
Weighted-average interest rate(2) |
| — | % | — | % | — | % | 6.5 | % | 7.9 | % | 5.7 | % | 6.3 | % |
|
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Capital Leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Fixed-rate leases |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 1 |
| $ | 2 |
| $ | 3 |
| $ | 9 |
| $ | 9 |
| |||||||||||||||
Interest rate(2) |
| 5.4 | % | 5.4 | % | 5.4 | % | 5.3 | % | 5.2 | % | 4.9 | % | 5.6 | % |
|
| |||||||||||||||||||||||
(1)Long-term Debt includes amounts reflected as Long-term debt due within one year.
(2)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, 2004 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.
(3)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 3(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.
(4)Includes PSI’s 6.50% Debentures due August 1, 2026, reflected as maturing in 2005, as the interest rate is due to reset on August 1, 2005. If the interest rate is not reset, the bonds are subject to mandatory redemption by PSI.
(5)CG&E’s 6.90% Debentures due June 1, 2025, are putable to CG&E at the option of the holders on June 1, 2005. However, based on current market conditions, we believe it is unlikely that the debentures will be put to CG&E on this date.
(6)Includes amounts related to non-registrants.
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.
83
CG&E has an outstanding interest rate swap agreement that decreased the percentage of variable-rate debt. See Note 7(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information on financial derivatives.
84
MD&A - - ACCOUNTING MATTERS
Preparation of financial statements and related disclosures in compliance with 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.
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” 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” 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, 2004, assuming a 95 percent confidence level, was approximately $1.9 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 will be less than the reported amount. In addition, our five-day VaR at December 31, 2004, assuming the same 95 percent confidence level, was approximately $3.9 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 Energyrisk 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.
85
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 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, 2004, regulatory assets totaled $609 million for CG&E (including $10 million for ULH&P) and $421 million for PSI. Current rates include the recovery of $602 million for CG&E (including $9 million for ULH&P) and $378 million for PSI. In addition to the regulatory assets, CG&E and PSI have regulatory liabilities totaling $165 million (including $30 million for ULH&P) and $392 million at December 31, 2004, respectively. See Note 1(c) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional detail regarding regulatory assets and regulatory liabilities.
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 tax credits associated with our production of synthetic fuel at this facility, resulting in approximately $120 million infuel. Failure to achieve forecasted taxable income might affect our ability to utilize the Section 29 tax credits and the ultimate realization of deferred tax assets.
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.
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, 2004, the carrying value of these generating plants is $5 billion for Cinergy, $2 billion for CG&E and $2 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 11(a) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data” for additional information. While we cannot predict the potential
86
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. In making this assessment, we consider such factors as the expected ability to recover through the regulatory process any additional investments in environmental compliance expenditures for PSI, the relative pricing of wholesale electricity in the region, the anticipated demand, and the cost of coal.
For the 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. While we currently believe these assets are recoverable on a nominal basis (the basis required for evaluation under Statement 144 given our intent to continue operating these assets), 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 an impairment in the future. At December 31, 2004, the carrying value of these gas-fired peaking plants is approximately $441 million.
We will continue to evaluate these assets for impairment when events or circumstances indicate the carrying value may not be recoverable.
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 approximately $80 millionbut 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 2003.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, 2004, we do not have any material unrealized losses that are deemed to be temporary in nature. See Note 15(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.
Consolidation of VIEs
In January 2003, the FASB issued Interpretation 46, which significantly changed the consolidation requirements for traditional SPEs and certain other entities subject to its scope. This interpretation defines a VIE as (a) an entity that does not have sufficient equity to support its activities without additional financial support or (b) any entity that has equity investors that do not have substantive voting rights, do not absorb first dollar losses, or receive residual returns. These entities must be consolidated whenever Cinergy would be anticipated to absorb greater than 50 percent of the losses or receive greater than 50 percent of the returns.
In the second quarteraccordance with its two stage adoption guidance, we implemented Interpretation 46 for traditional SPEs on July 1, 2003, and for all other entities, including certain operating joint ventures, as of 2003, the IRS announced,March 31, 2004. The consolidation of certain operating joint ventures as a result of an audit of another taxpayer, that it had reason to question and was reviewing the scientific validity of test procedures and results that were presented as evidence the fuel underwent a significant chemical change. The IRS recently announced that it has finished its review and has determined that test procedures and
98
results used by taxpayers may be scientifically valid if the procedures are applied in a consistent and unbiased manner. The IRS also announced that it plans to impose new testing and record-keeping requirements on synthetic fuel producers and plans to issue guidance extending these requirements to taxpayers already holding private letter rulings on the issue of significant chemical change. Cinergy believes that any new testing or record-keeping requirements imposed by the IRS willMarch 31, 2004, did not have a material effectimpact on our financial position or results of operations.
87
On July 1, 2003, Interpretation 46 required us to consolidate two SPEs that have individual power sale agreements with Central Maine Power Company. Further, we were no longer permitted to consolidate a trust that was established by Cinergy Corp. in 2001 to issue approximately $316 million of combined preferred trust securities and stock purchase contracts. Prior period financial statements were not restated for these changes. For further information on the accounting for these entities see Notes 3(a) and (b) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”.
Cinergy has concluded that its accounts receivable sale facility, as discussed in Note 3(c) of the “Notes to Financial Statements” in “Item 8. Financial Statements and Supplementary Data”, will remain unconsolidated since it involves transfers of financial assets to a qualifying SPE, which is exempted from consolidation by Interpretation 46 and Statement of Financial Accounting Standards No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.
In December 2004, the FASB issued a replacement of Statement 123, Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment (Statement 123R). This standard will require accounting for all stock-based compensation arrangements under the fair value method in addition to other provisions.
Ronald A. Katz Technology Licensing, L.P. (RAKTL) has offered us a licenseIn 2003, we prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of Statement 123, as amended by Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, 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 within our stock-based compensation plans is not expected to a portfoliobe material. Statement 123R contains certain provisions that will modify the accounting for various stock-based compensation plans other than stock options. We are in the process of patents claiming thatevaluating the patents may be infringed by certain products and services utilized by us. The patents purportedly relate to various aspects of telephone call processing in Cinergy call centers. Asimpact of this date, no legal proceedings have been instituted against us, but if the RAKTL patents are valid, enforceable and apply to our business, we could be required to seek a license from RAKTL or to discontinue certain activities. We are currently considering this matter, but lack sufficient information to assess the potential outcome at this time.new standard on these plans. Cinergy will adopt Statement 123R on July 1, 2005.
In October 2002,2004, 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 resultAJCA. In December 2004, the FASB issued Staff Position 109-2, Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of financial problems experienced by certain public utility companies and2004. The staff position allows additional time for an entity to evaluate the existing stateeffect of the economy, the PUCO issued an order initiating a reviewlegislation on its plan for repatriation of and requesting comments with respect to, the financial conditionforeign earnings for purposes of the 19 large public utilities (gas, electric, and telecommunication) serving Ohio customers, including CG&E. The PUCO intends to identify available measures to ensure that the regulated operationsapplying Statement of the Ohio public utilities are not adversely impacted by the parent or affiliate companies’ non-regulated operations. CG&E filed comments stating that the PUCO has sufficient authority to adequately regulate the financial condition of public utilities. In January 2004, the PUCO staff filed their recommendations on the measures to be used to address the PUCO’s concerns, focusing on such areas as dividend distributions, cost of capital, and restrictions on non-regulated investments, loans, and guarantees. CG&E cannot predict the outcome of this matter at this time.
In July 2003,. Cinergy received a subpoena fromwill complete its evaluation of the Commodity Futures Trading Commission (CFTC). As has been previously reported byeffects of the press, the CFTC has served subpoenasprovision on numerous other energy companies. The CFTC request sought certain information regarding our trading activities, including price reporting to energy industry publications. The CFTC sought particular information concerning these mattersits plan for the period May 2000 through January 2001 as to onerepatriation of Cinergy’s employees. Based on an initial review of these matters, we placed that employee on administrative leave and have subsequently terminated his employment. Cinergy is continuing an investigation of these matters, including whether price reporting inconsistencies occurredforeign earnings in our operations, and has been cooperating fully with the CFTC.2005.
In August 2003, Cinergy, along with 38 other companies, was named as a defendant 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
9988
damages to the class. Two similar lawsuits have subsequently been filed, and these three lawsuits have been consolidated for pretrial purposes. Plaintiffs filed a consolidated class action complaint in January 2004. We believe this action is without merit and intend to defend this lawsuit vigorously; however, we cannot predict the outcome of this matter at this time.
In the second quarter of 2003, Cinergy received initial and follow-up third-party subpoenas from the SEC requesting information related to particular trading activity with one of its counterparties who was the target of an investigation by the SEC. Cinergy has fully cooperated with the SEC in connection with this matter. In January 2004, Cinergy received a grand jury subpoena from the Assistant United States Attorney in the Southern District of Texas for information relating to the same trading activities being investigated by the SEC. Specifically, the Assistant United States Attorney has requested information relating to communications between a former employee and another energy company. We understand that we are neither a target nor are we under investigation by the Department of Justice in relation to these communications.
At this time, it is not possible to predict the outcome of these investigations and litigation or their impact on Cinergy’s financial position or results of operations; although, in the opinion of management, they are not likely to have a material adverse effect on our financial position or results of operations.
Reference is made to the “Market Risk Sensitive Instruments and Positions”Instruments” section of “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”MD&A”.
10089
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
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| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
101FINANCIAL STATEMENTS
Cinergy Corp. and Subsidiaries
Consolidated Statements of Income for the three years ended December 31, 2004
Consolidated Balance Sheets at December 31, 2004 and 2003
Consolidated Statements of Cash Flows for the three years ended December 31, 2004
Consolidated Statements of Capitalization at December 31, 2004 and 2003
The Cincinnati Gas & Electric Company and Subsidiaries
Consolidated Statements of Income for the three years ended December 31, 2004
Consolidated Balance Sheets at December 31, 2004 and 2003
Consolidated Statements of Cash Flows for the three years ended December 31, 2004
Consolidated Statements of Capitalization at December 31, 2004 and 2003
PSI Energy, Inc. and Subsidiary
Consolidated Statements of Income for the three years ended December 31, 2004
Consolidated Balance Sheets at December 31, 2004 and 2003
Consolidated Statements of Cash Flows for the three years ended December 31, 2004
Consolidated Statements of Capitalization at December 31, 2004 and 2003
The Union Light, Heat and Power Company
Statements of Income for the three years ended December 31, 2004
Balance Sheets at December 31, 2004 and 2003
Statements of Changes in Common Stock Equity for the three years ended December 31, 2004
Statements of Cash Flows for the three years ended December 31, 2004
Statements of Capitalization at December 31, 2004 and 2003
Schedule II - Valuation and Qualifying Accounts
Cinergy Corp. and Subsidiaries
The Cincinnati Gas & Electric Company and Subsidiaries
PSI Energy, Inc. and Subsidiary
The Union Light, Heat and Power Company
The information required to be submitted in schedules other than those indicated above haspreviously, 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.
10290
ITEM 8.8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT AUDITORS’ REPORTREGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Cinergy Corp.:
We have audited the accompanying consolidated balance sheets and statements of capitalization of Cinergy Corp. and subsidiaries as of December 31, 20032004 and 2002,2003, 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, 2003.2004. 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 thethese financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditingthe standards generally accepted inof the United States of America.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, 20032004 and 20022003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003,2004, 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 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;” Emerging Issues Task Force Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities;” and the fair value recognition provisions of SFAS No. 123 “Accounting for Stock-Based Compensation.” In 2002, Cinergy Corp. adopted SFAS No. 142, “Goodwill and Other Intangible Assets.”
Deloitte & Touche LLP
Cincinnati, Ohio
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, 2004, 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 16, 200411, 2005 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 11, 2005 |
103
91
To the Board of Directors of The Cincinnati Gas & Electric Company:
We have audited the accompanying consolidated balance sheets and statements of capitalization of The Cincinnati Gas & Electric Company and subsidiaries as of December 31, 20032004 and 2002,2003, 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, 2003.2004. 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 thethese financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditingthe standards generally accepted inof the United States of America.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 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. An audit also includesstatements, 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, 20032004 and 20022003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003,2004, 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 2003, The Cincinnati Gas & Electric Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” and Emerging Issues Task Force Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.Obligations.”
/s/ Deloitte & Touche LLP
| |
Deloitte & Touche LLP | |
Cincinnati, Ohio | |
February 11, 2005 |
10492
To the Board of Directors of PSI Energy, Inc.:
We have audited the accompanying consolidated balance sheets and statements of capitalization of PSI Energy, Inc. and subsidiary as of December 31, 20032004 and 2002,2003, 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, 2003.2004. 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 thethese financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditingthe standards generally accepted inof the United States of America.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 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. An audit also includesstatements, 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, 20032004 and 20022003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003,2004, 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 2003, PSI Energy, Inc. adopted Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” and Emerging Issues Task Force Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.Obligations.”
/s/ Deloitte & Touche LLP
| |
Deloitte & Touche LLP | |
Cincinnati, Ohio | |
February 11, 2005 |
10593
To the Board of Directors of The Union Light, Heat and Power Company:
We have audited the accompanying balance sheets and statements of capitalization of The Union Light, Heat and Power Company as of December 31, 20032004 and 2002,2003, 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, 2003.2004. 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 thethese financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditingthe standards generally accepted inof the United States of America.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 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. An audit also includesstatements, 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, 20032004 and 20022003, and the results of itstheir operations and itstheir cash flows for each of the three years in the period ended December 31, 2003,2004, 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 2003, The Union Light, Heat and Power Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.”
/s/ Deloitte & Touche LLP
| |
Deloitte & Touche LLP | |
Cincinnati, Ohio | |
February 11, 2005 |
10694
CINERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
|
| 2003 |
| 2002 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
| ||||||
|
| (dollars in thousands, except per share amounts) |
|
| (in thousands, except per share amounts) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating Revenues (Note 1(q)(i)) |
|
|
|
|
|
|
| |||||||||||||
Operating Revenues (Note 1(d)) |
|
|
|
|
|
|
| |||||||||||||
Electric |
| $ | 3,383,132 |
| $ | 3,338,068 |
| $ | 3,215,652 |
|
| $ | 3,536,649 |
| $ | 3,320,256 |
| $ | 3,256,437 |
|
Gas |
| 835,507 |
| 590,471 |
| 655,678 |
|
| 783,316 |
| 835,507 |
| 590,471 |
| ||||||
Other |
| 197,238 |
| 130,813 |
| 78,246 |
| |||||||||||||
Other (Note 1(d)(iii)) |
| 367,985 |
| 260,114 |
| 212,444 |
| |||||||||||||
Total Operating Revenues |
| 4,415,877 |
| 4,059,352 |
| 3,949,576 |
|
| 4,687,950 |
| 4,415,877 |
| 4,059,352 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fuel and purchased and exchanged power (Note 1(q)(i)) |
| 1,158,196 |
| 989,699 |
| 1,014,571 |
| |||||||||||||
Gas purchased (Note 1(q)(i)) |
| 503,834 |
| 309,983 |
| 397,310 |
| |||||||||||||
Fuel, emission allowances, and purchased power |
| 1,244,027 |
| 1,136,950 |
| 950,463 |
| |||||||||||||
Gas purchased |
| 428,087 |
| 503,834 |
| 309,983 |
| |||||||||||||
Costs of fuel resold |
| 280,891 |
| 196,974 |
| 130,286 |
| |||||||||||||
Operation and maintenance |
| 1,276,453 |
| 1,291,589 |
| 1,008,133 |
|
| 1,282,278 |
| 1,118,680 |
| 1,201,564 |
| ||||||
Depreciation |
| 419,098 |
| 405,487 |
| 366,648 |
|
| 460,389 |
| 398,871 |
| 403,909 |
| ||||||
Taxes other than income taxes |
| 249,746 |
| 263,002 |
| 227,652 |
|
| 253,945 |
| 249,746 |
| 263,002 |
| ||||||
Total Operating Expenses |
| 3,607,327 |
| 3,259,760 |
| 3,014,314 |
|
| 3,949,617 |
| 3,605,055 |
| 3,259,207 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Operating Income |
| 808,550 |
| 799,592 |
| 935,262 |
|
| 738,333 |
| 810,822 |
| 800,145 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Equity in Earnings of Unconsolidated Subsidiaries |
| 15,201 |
| 15,261 |
| 1,494 |
|
| 48,249 |
| 15,201 |
| 15,261 |
| ||||||
Miscellaneous Income - Net |
| 38,156 |
| 12,402 |
| 40,404 |
| |||||||||||||
Miscellaneous Income (Expense) - Net |
| (3,213 | ) | 38,156 |
| 12,402 |
| |||||||||||||
Interest Expense |
| 268,602 |
| 243,099 |
| 258,723 |
|
| 275,238 |
| 270,874 |
| 243,652 |
| ||||||
Preferred Dividend Requirement of Subsidiary Trust (Note 3(b)) |
| 11,940 |
| 23,832 |
| 1,067 |
|
| — |
| 11,940 |
| 23,832 |
| ||||||
Preferred Dividend Requirements of Subsidiaries |
| 3,432 |
| 3,433 |
| 3,433 |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income Before Taxes |
| 581,365 |
| 560,324 |
| 717,370 |
|
| 504,699 |
| 577,932 |
| 556,891 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income Taxes (Note 10) |
| 143,508 |
| 160,255 |
| 257,308 |
|
| 103,831 |
| 143,508 |
| 160,255 |
| ||||||
Preferred Dividend Requirements of Subsidiaries |
| 3,433 |
| 3,433 |
| 3,433 |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income Before Discontinued Operations and Cumulative Effect of Changes in Accounting Principles |
| 434,424 |
| 396,636 |
| 456,629 |
|
| 400,868 |
| 434,424 |
| 396,636 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Discontinued operations, net of tax (Note 14) |
| 8,886 |
| (25,161 | ) | (14,350 | ) |
| — |
| 8,886 |
| (25,161 | ) | ||||||
Cumulative effect of changes in accounting principles, net of tax (Note 1(q)(vi)) |
| 26,462 |
| (10,899 | ) | — |
| |||||||||||||
Cumulative effect of changes in accounting principles, net of tax (Note 1(q)(iv)) |
| — |
| 26,462 |
| (10,899 | ) | |||||||||||||
Net Income |
| $ | 469,772 |
| $ | 360,576 |
| $ | 442,279 |
|
| $ | 400,868 |
| $ | 469,772 |
| $ | 360,576 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Average Common Shares Outstanding |
| 176,535 |
| 167,047 |
| 159,110 |
| |||||||||||||
Average Common Shares Outstanding - Basic |
| 180,965 |
| 176,535 |
| 167,047 |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Earnings Per Common Share (Note 16) |
|
|
|
|
|
|
| |||||||||||||
Income Before Discontinued Operations and Cumulative Effect of Changes in Accounting Principles |
| $ | 2.46 |
| $ | 2.37 |
| $ | 2.87 |
| ||||||||||
Discontinued operations, net of tax |
| 0.05 |
| (0.15 | ) | (0.09 | ) | |||||||||||||
Cumulative effect of changes in accounting principles, net of tax |
| 0.15 |
| (0.06 | ) | — |
| |||||||||||||
Earnings Per Common Share - Basic (Note 17) |
|
|
|
|
|
|
| |||||||||||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| $ | 2.22 |
| $ | 2.46 |
| $ | 2.37 |
| ||||||||||
Discontinued operations, net of tax (Note 14) |
| — |
| 0.05 |
| (0.15 | ) | |||||||||||||
Cumulative effect of changes in accounting principles, net of tax (Note 1(q)(iv)) |
| — |
| 0.15 |
| (0.06 | ) | |||||||||||||
Net Income |
| $ | 2.66 |
| $ | 2.16 |
| $ | 2.78 |
|
| $ | 2.22 |
| $ | 2.66 |
| $ | 2.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Earnings Per Common Share - Assuming Dilution (Note 16) |
|
|
|
|
|
|
| |||||||||||||
Income Before Discontinued Operations and Cumulative Effect of Changes in Accounting Principles |
| $ | 2.43 |
| $ | 2.34 |
| $ | 2.84 |
| ||||||||||
Discontinued operations, net of tax |
| 0.05 |
| (0.15 | ) | (0.09 | ) | |||||||||||||
Cumulative effect of changes in accounting principles, net of tax |
| 0.15 |
| (0.06 | ) | — |
| |||||||||||||
Average Common Shares Outstanding - Diluted |
| 183,531 |
| 178,473 |
| 169,052 |
| |||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Earnings Per Common Share - Diluted (Note 17) |
|
|
|
|
|
|
| |||||||||||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| $ | 2.18 |
| $ | 2.43 |
| $ | 2.34 |
| ||||||||||
Discontinued operations, net of tax (Note 14) |
| — |
| 0.05 |
| (0.15 | ) | |||||||||||||
Cumulative effect of changes in accounting principles, net of tax (Note 1(q)(iv)) |
| — |
| 0.15 |
| (0.06 | ) | |||||||||||||
Net Income |
| $ | 2.63 |
| $ | 2.13 |
| $ | 2.75 |
|
| $ | 2.18 |
| $ | 2.63 |
| $ | 2.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Dividends Declared Per Common Share |
| $ | 1.84 |
| $ | 1.80 |
| $ | 1.80 |
| ||||||||||
Cash Dividends Declared Per Common Share |
| $ | 1.88 |
| $ | 1.84 |
| $ | 1.80 |
| ||||||||||
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
10896
ASSETS |
|
|
|
|
| ||
|
| December 31 |
| ||||
|
| 2004 |
| 2003 |
| ||
|
| (dollars in thousands) |
| ||||
Current Assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 164,541 |
| $ | 169,120 |
|
Notes receivable, current |
| 214,513 |
| 189,854 |
| ||
Accounts receivable less accumulated provision for doubtful accounts of $5,514 at December 31, 2004, and $7,884 at December 31, 2003 (Note 3(c)) |
| 1,061,140 |
| 1,074,518 |
| ||
Fuel, emission allowances, and supplies (Note 1(g)) |
| 444,750 |
| 357,625 |
| ||
Energy risk management current assets (Note 1(k)(i)) |
| 381,146 |
| 305,058 |
| ||
Prepayments and other |
| 174,624 |
| 146,422 |
| ||
Total Current Assets |
| 2,440,714 |
| 2,242,597 |
| ||
|
|
|
|
|
| ||
Property, Plant, and Equipment - at Cost |
|
|
|
|
| ||
Utility plant in service (Note 19) |
| 10,076,468 |
| 9,732,123 |
| ||
Construction work in progress |
| 333,687 |
| 275,459 |
| ||
Total Utility Plant |
| 10,410,155 |
| 10,007,582 |
| ||
Non-regulated property, plant, and equipment (Note 19) |
| 4,700,009 |
| 4,527,943 |
| ||
Accumulated depreciation (Note 1(h)(i)) |
| 5,180,699 |
| 4,908,019 |
| ||
Net Property, Plant, and Equipment |
| 9,929,465 |
| 9,627,506 |
| ||
|
|
|
|
|
| ||
Other Assets |
|
|
|
|
| ||
Regulatory assets (Note 1(c)) |
| 1,030,333 |
| 1,029,242 |
| ||
Investments in unconsolidated subsidiaries |
| 513,675 |
| 494,520 |
| ||
Energy risk management non-current assets (Note 1(k)(i)) |
| 138,787 |
| 97,334 |
| ||
Notes receivable, non-current |
| 193,857 |
| 213,853 |
| ||
Other investments |
| 125,367 |
| 184,044 |
| ||
Goodwill and other intangible assets |
| 60,502 |
| 45,349 |
| ||
Restricted funds held in trust |
| 358,006 |
| — |
| ||
Other |
| 191,611 |
| 180,260 |
| ||
Total Other Assets |
| 2,612,138 |
| 2,244,602 |
| ||
|
|
|
|
|
| ||
Assets of Discontinued Operations (Note 14) |
| — |
| 4,501 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 14,982,317 |
| $ | 14,119,206 |
|
ASSETSThe accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
97
CONSOLIDATED BALANCE SHEETS
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
Current Assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 169,120 |
| $ | 200,112 |
|
Restricted deposits (Note 6) |
| 92,813 |
| 3,092 |
| ||
Notes receivable, current (Note 5) |
| 189,854 |
| 135,873 |
| ||
Accounts receivable less accumulated provision for doubtful accounts of $7,884 at December 31, 2003, and $16,368 at December 31, 2002 (Note 3(c)) |
| 1,074,518 |
| 1,280,810 |
| ||
Materials, supplies, and fuel (Note 1(g)) |
| 321,658 |
| 319,454 |
| ||
Energy risk management current assets (Note 1(k)(i)) |
| 305,058 |
| 464,028 |
| ||
Prepayments and other |
| 89,576 |
| 107,086 |
| ||
Total Current Assets |
| 2,242,597 |
| 2,510,455 |
| ||
|
|
|
|
|
| ||
Property, Plant, and Equipment - at Cost |
|
|
|
|
| ||
Utility plant in service (Note 19) |
| 9,732,123 |
| 8,669,045 |
| ||
Construction work in progress |
| 275,459 |
| 469,300 |
| ||
Total Utility Plant |
| 10,007,582 |
| 9,138,345 |
| ||
Non-regulated property, plant, and equipment (Note 19) |
| 4,527,943 |
| 4,667,940 |
| ||
Accumulated depreciation (Note 1(q)(iii)) |
| 4,908,019 |
| 4,639,713 |
| ||
Net Property, Plant, and Equipment |
| 9,627,506 |
| 9,166,572 |
| ||
|
|
|
|
|
| ||
Other Assets |
|
|
|
|
| ||
Regulatory assets (Note 1(c)) |
| 1,012,151 |
| 1,022,696 |
| ||
Investments in unconsolidated subsidiaries |
| 494,520 |
| 417,188 |
| ||
Energy risk management non-current assets (Note 1(k)(i)) |
| 97,334 |
| 162,773 |
| ||
Notes receivable, non-current (Note 5) |
| 213,853 |
| — |
| ||
Other investments |
| 184,044 |
| 163,851 |
| ||
Goodwill |
| 43,717 |
| 43,717 |
| ||
Other intangible assets |
| 1,632 |
| 2,059 |
| ||
Other |
| 197,351 |
| 195,867 |
| ||
Total Other Assets |
| 2,244,602 |
| 2,008,151 |
| ||
|
|
|
|
|
| ||
Assets of Discontinued Operations (Note 14) |
| 4,501 |
| 147,265 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 14,119,206 |
| $ | 13,832,443 |
|
LIABILITIES AND SHAREHOLDERS’ EQUITY |
|
|
|
|
| ||
|
| December 31 |
| ||||
|
| 2004 |
| 2003 |
| ||
|
| (dollars in thousands) |
| ||||
Current Liabilities |
|
|
|
|
| ||
Accounts payable |
| $ | 1,348,576 |
| $ | 1,240,423 |
|
Accrued taxes |
| 216,804 |
| 217,993 |
| ||
Accrued interest |
| 54,473 |
| 68,952 |
| ||
Notes payable and other short-term obligations (Note 5) |
| 958,910 |
| 351,412 |
| ||
Long-term debt due within one year |
| 219,967 |
| 839,103 |
| ||
Energy risk management current liabilities (Note 1(k)(i)) |
| 310,741 |
| 296,122 |
| ||
Other |
| 171,188 |
| 107,438 |
| ||
Total Current Liabilities |
| 3,280,659 |
| 3,121,443 |
| ||
|
|
|
|
|
| ||
Non-Current Liabilities |
|
|
|
|
| ||
Long-term debt (Note 4) |
| 4,227,741 |
| 4,131,909 |
| ||
Deferred income taxes (Note 10) |
| 1,597,120 |
| 1,557,981 |
| ||
Unamortized investment tax credits |
| 99,723 |
| 108,884 |
| ||
Accrued pension and other postretirement benefit costs (Note 9) |
| 688,277 |
| 662,834 |
| ||
Regulatory liabilities (Note 1(c)) |
| 557,419 |
| 490,856 |
| ||
Energy risk management non-current liabilities (Note 1(k)(i)) |
| 127,340 |
| 64,861 |
| ||
Other |
| 225,298 |
| 205,344 |
| ||
Total Non-Current Liabilities |
| 7,522,918 |
| 7,222,669 |
| ||
|
|
|
|
|
| ||
Liabilities of Discontinued Operations (Note 14) |
| — |
| 11,594 |
| ||
|
|
|
|
|
| ||
Commitments and Contingencies (Note 11) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Total Liabilities |
| 10,803,577 |
| 10,355,706 |
| ||
|
|
|
|
|
| ||
Cumulative Preferred Stock of Subsidiaries |
|
|
|
|
| ||
Not subject to mandatory redemption |
| 62,818 |
| 62,818 |
| ||
|
|
|
|
|
| ||
Common Stock Equity (Note 2) |
|
|
|
|
| ||
Common stock - $.01 par value; authorized shares - 600,000,000; issued shares - 187,653,506 at December 31, 2004, and |
| 1,877 |
| 1,784 |
| ||
Paid-in capital |
| 2,559,715 |
| 2,195,985 |
| ||
Retained earnings |
| 1,613,340 |
| 1,551,003 |
| ||
Treasury shares at cost - 129,277 shares at December 31, 2004, and 101,515 shares at December 31, 2003 |
| (4,336 | ) | (3,255 | ) | ||
Accumulated other comprehensive loss (Note 18) |
| (54,674 | ) | (44,835 | ) | ||
Total Common Stock Equity |
| 4,115,922 |
| 3,700,682 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Shareholders’ Equity |
| $ | 14,982,317 |
| $ | 14,119,206 |
|
|
|
|
|
|
| ||
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
10998
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
Current Liabilities |
|
|
|
|
| ||
Accounts payable |
| $ | 1,240,423 |
| $ | 1,318,379 |
|
Accrued taxes |
| 217,993 |
| 258,613 |
| ||
Accrued interest |
| 68,952 |
| 62,244 |
| ||
Notes payable and other short-term obligations (Note 6) |
| 351,412 |
| 667,973 |
| ||
Long-term debt due within one year |
| 839,103 |
| 176,000 |
| ||
Energy risk management current liabilities (Note 1(k)(i)) |
| 296,122 |
| 407,710 |
| ||
Other |
| 107,438 |
| 105,026 |
| ||
Total Current Liabilities |
| 3,121,443 |
| 2,995,945 |
| ||
|
|
|
|
|
| ||
Non-Current Liabilities |
|
|
|
|
| ||
Long-term debt (Note 4) |
| 4,131,909 |
| 4,011,568 |
| ||
Deferred income taxes (Note 10) |
| 1,557,981 |
| 1,458,171 |
| ||
Unamortized investment tax credits |
| 108,884 |
| 118,095 |
| ||
Accrued pension and other postretirement benefit costs (Note 9) |
| 662,834 |
| 626,167 |
| ||
Accrued cost of removal (Note 1(c)) |
| 490,856 |
| 525,415 |
| ||
Energy risk management non-current liabilities (Note 1(k)(i)) |
| 64,861 |
| 143,991 |
| ||
Other |
| 205,344 |
| 179,767 |
| ||
Total Non-Current Liabilities |
| 7,222,669 |
| 7,063,174 |
| ||
|
|
|
|
|
| ||
Liabilities of Discontinued Operations (Note 14) |
| 11,594 |
| 108,833 |
| ||
|
|
|
|
|
| ||
Commitments and Contingencies (Note 11) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Total Liabilities |
| 10,355,706 |
| 10,167,952 |
| ||
|
|
|
|
|
| ||
Preferred Trust Securities (Note 3(b)) |
|
|
|
|
| ||
Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company |
| — |
| 308,187 |
| ||
|
|
|
|
|
| ||
Cumulative Preferred Stock of Subsidiaries |
|
|
|
|
| ||
Not subject to mandatory redemption |
| 62,818 |
| 62,828 |
| ||
|
|
|
|
|
| ||
Common Stock Equity (Note 2) |
|
|
|
|
| ||
Common Stock - $.01 par value; authorized shares - 600,000,000; issued shares – 178,438,369 at December 31, 2003, and 168,663,115 at December 31, 2002; outstanding shares – 178,336,854 at December 31, 2003, and 168,663,115 at December 31, 2002 |
| 1,784 |
| 1,687 |
| ||
Paid-in capital |
| 2,195,985 |
| 1,918,136 |
| ||
Retained earnings |
| 1,551,003 |
| 1,403,453 |
| ||
Treasury shares at cost – 101,515 shares at December 31, 2003 |
| (3,255 | ) | — |
| ||
Accumulated other comprehensive income (loss) (Note 18) |
| (44,835 | ) | (29,800 | ) | ||
Total Common Stock Equity |
| 3,700,682 |
| 3,293,476 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Shareholders’ Equity |
| $ | 14,119,206 |
| $ | 13,832,443 |
|
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
110
CINERGY CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
|
| Common |
| Paid-in |
| Retained |
| Treasury |
| Accumulated |
| Total |
| ||||||
|
| (dollars in thousands) | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2001 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Beginning balance (158,967,661 shares) |
| $ | 1,590 |
| $ | 1,619,153 |
| $ | 1,179,113 |
| $ | — |
| $ | (10,895 | ) | $ | 2,788,961 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 442,279 |
|
|
|
|
| 442,279 |
| ||||||
Other comprehensive income (loss), net of tax effect of $1,454 (Note 18) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Foreign currency translation adjustment (Note 1(r)) |
|
|
|
|
|
|
|
|
| 1,641 |
| 1,641 |
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
|
|
| (1,555 | ) | (1,555 | ) | ||||||
Unrealized gain (loss) on investment trusts |
|
|
|
|
|
|
|
|
| (841 | ) | (841 | ) | ||||||
Cumulative effect of change in accounting principle |
|
|
|
|
|
|
|
|
| (2,500 | ) | (2,500 | ) | ||||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
|
|
| (2,779 | ) | (2,779 | ) | ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
| 436,245 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Issuance of common stock - net (435,178 shares) |
| 4 |
| 9,896 |
|
|
|
|
|
|
| 9,900 |
| ||||||
Treasury shares purchased (344,034 shares) |
|
|
| (10,015 | ) |
|
|
|
|
|
| (10,015 | ) | ||||||
Treasury shares reissued (344,034 shares) |
|
|
| 9,157 |
|
|
|
|
|
|
| 9,157 |
| ||||||
Dividends on common stock ($1.80 per share) |
|
|
|
|
| (286,289 | ) |
|
|
|
| (286,289 | ) | ||||||
Stock purchase contracts (Note 2(e)) |
|
|
| (23,200 | ) |
|
|
|
|
|
| (23,200 | ) | ||||||
Other |
|
|
| 14,668 |
| 2,032 |
|
|
|
|
| 16,700 |
| ||||||
Ending balance (159,402,839 shares) |
| $ | 1,594 |
| $ | 1,619,659 |
| $ | 1,337,135 |
| $ | — |
| $ | (16,929 | ) | $ | 2,941,459 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2002 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 360,576 |
|
|
|
|
| 360,576 |
| ||||||
Other comprehensive income (loss), net of tax effect of $11,509 (Note 18) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Foreign currency translation adjustment, net of reclassification adjustments (Note 1(r)) |
|
|
|
|
|
|
|
|
| 25,917 |
| 25,917 |
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
|
|
| (13,763 | ) | (13,763 | ) | ||||||
Unrealized gain (loss) on investment trusts |
|
|
|
|
|
|
|
|
| (5,277 | ) | (5,277 | ) | ||||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
|
|
| (19,748 | ) | (19,748 | ) | ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
| 347,705 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Issuance of common stock - net (9,260,276 shares) |
| 93 |
| 267,768 |
|
|
|
|
|
|
| 267,861 |
| ||||||
Dividends on common stock ($1.80 per share) |
|
|
|
|
| (298,292 | ) |
|
|
|
| (298,292 | ) | ||||||
Other |
|
|
| 30,709 |
| 4,034 |
|
|
|
|
| 34,743 |
| ||||||
Ending balance (168,663,115 shares) |
| $ | 1,687 |
| $ | 1,918,136 |
| $ | 1,403,453 |
| $ | — |
| $ | (29,800 | ) | $ | 3,293,476 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 469,772 |
|
|
|
|
| 469,772 |
| ||||||
Other comprehensive income (loss), net of tax effect of $11,700 (Note 18) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Foreign currency translation adjustment, net of reclassification adjustments (Note 1(r)) |
|
|
|
|
|
|
|
|
| 10,528 |
| 10,528 |
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
|
|
| (33,846 | ) | (33,846 | ) | ||||||
Unrealized gain (loss) on investment trusts |
|
|
|
|
|
|
|
|
| 6,757 |
| 6,757 |
| ||||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
|
|
| 1,526 |
| 1,526 |
| ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
| 454,737 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Issuance of common stock - net (9,775,254 shares) |
| 97 |
| 269,977 |
|
|
|
|
|
|
| 270,074 |
| ||||||
Treasury shares purchased (101,515 shares) |
|
|
|
|
|
|
| (3,255 | ) |
|
| (3,255 | ) | ||||||
Dividends on common stock ($1.84 per share) |
|
|
|
|
| (322,371 | ) |
|
|
|
| (322,371 | ) | ||||||
Other |
|
|
| 7,872 |
| 149 |
|
|
|
|
| 8,021 |
| ||||||
Ending balance (178,336,854 shares) |
| $ | 1,784 |
| $ | 2,195,985 |
| $ | 1,551,003 |
| $ | (3,255 | ) | $ | (44,835 | ) | $ | 3,700,682 |
|
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
111
CINERGY CORP.CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (dollars in thousands) | ||||||||
|
|
|
|
|
|
|
| |||
Cash Flows from Continuing Operations |
|
|
|
|
|
|
| |||
Operating Activities |
|
|
|
|
|
|
| |||
Net income |
| $ | 469,772 |
| $ | 360,576 |
| $ | 442,279 |
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |
|
|
|
|
|
|
| |||
Depreciation |
| 419,098 |
| 405,487 |
| 366,648 |
| |||
(Income) Loss of discontinued operations, net of tax |
| (8,886 | ) | 25,161 |
| 14,350 |
| |||
(Income) Loss on sale of investment in unconsolidated subsidiaries |
| (93 | ) | (16,518 | ) | — |
| |||
Cumulative effect of changes in accounting principles, net of tax |
| (26,462 | ) | 10,899 |
| — |
| |||
Change in net position of energy risk management activities |
| (11,723 | ) | (43,202 | ) | (96,850 | ) | |||
Deferred income taxes and investment tax credits - net |
| 85,108 |
| 148,069 |
| 118,544 |
| |||
Equity in (earnings) losses of unconsolidated subsidiaries |
| (15,201 | ) | (15,261 | ) | (1,494 | ) | |||
Allowance for equity funds used during construction |
| (7,532 | ) | (12,861 | ) | (8,628 | ) | |||
Regulatory assets deferrals |
| (83,228 | ) | (110,867 | ) | (141,324 | ) | |||
Regulatory assets amortization |
| 90,476 |
| 116,512 |
| 119,344 |
| |||
Accrued pension and other postretirement benefit costs |
| 36,667 |
| 127,366 |
| 34,246 |
| |||
Deferred cost under gas recovery mechanism |
| (19,335 | ) | (23,373 | ) | 53,374 |
| |||
Cost of removal |
| (16,598 | ) | — |
| — |
| |||
Changes in current assets and current liabilities: |
|
|
|
|
|
|
| |||
Restricted deposits |
| (9,382 | ) | 969 |
| (3,561 | ) | |||
Accounts and notes receivable |
| 123,504 |
| (235,437 | ) | 495,295 |
| |||
Materials, supplies, and fuel |
| (2,059 | ) | (83,585 | ) | (81,269 | ) | |||
Prepayments |
| 8,859 |
| (26,818 | ) | 13,507 |
| |||
Accounts payable |
| (89,149 | ) | 311,339 |
| (465,034 | ) | |||
Accrued taxes and interest |
| (35,510 | ) | 65,019 |
| (40,345 | ) | |||
Other assets |
| (13,157 | ) | (49,259 | ) | (19,925 | ) | |||
Other liabilities |
| 50,504 |
| 1,586 |
| (75,467 | ) | |||
Net cash provided by (used in) operating activities |
| 945,673 |
| 955,802 |
| 723,690 |
| |||
|
|
|
|
|
|
|
| |||
Financing Activities |
|
|
|
|
|
|
| |||
Change in short-term debt |
| (312,747 | ) | (442,469 | ) | 15,339 |
| |||
Issuance of long-term debt |
| 688,166 |
| 628,170 |
| 872,930 |
| |||
Issuance of preferred trust securities |
| — |
| — |
| 306,327 |
| |||
Redemption of long-term debt |
| (487,901 | ) | (112,578 | ) | (90,448 | ) | |||
Funds on deposit from issuance of debt securities |
| (80,339 | ) | — |
| — |
| |||
Retirement of preferred stock of subsidiaries |
| (10 | ) | (3 | ) | (1 | ) | |||
Issuance of common stock |
| 270,074 |
| 267,861 |
| 9,900 |
| |||
Dividends on common stock |
| (322,371 | ) | (298,292 | ) | (286,289 | ) | |||
Net cash provided by (used in) financing activities |
| (245,128 | ) | 42,689 |
| 827,758 |
| |||
|
|
|
|
|
|
|
| |||
Investing Activities |
|
|
|
|
|
|
| |||
Construction expenditures (less allowance for equity funds used during construction) |
| (704,117 | ) | (853,332 | ) | (832,693 | ) | |||
Proceeds from notes receivable |
| 9,187 |
| — |
| — |
| |||
Acquisitions and other investments |
| (87,859 | ) | (118,375 | ) | (701,833 | ) | |||
Proceeds from sale of subsidiaries and equity investments |
| 51,252 |
| 86,071 |
| — |
| |||
Net cash provided by (used in) investing activities |
| (731,537 | ) | (885,636 | ) | (1,534,526 | ) | |||
|
|
|
|
|
|
|
| |||
Net increase (decrease) in cash and cash equivalents from continuing operations |
| (30,992 | ) | 112,855 |
| 16,922 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents from continuing operations at beginning of period |
| 200,112 |
| 87,257 |
| 70,335 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents from continuing operations at end of period |
| $ | 169,120 |
| $ | 200,112 |
| $ | 87,257 |
|
|
|
|
|
|
|
|
| |||
Cash Flows from Discontinued Operations |
|
|
|
|
|
|
| |||
Operating activities |
| $ | (5,871 | ) | $ | 40,397 |
| $ | (5,841 | ) |
Financing activities |
| (14,898 | ) | (39,464 | ) | 39,505 |
| |||
Investing activities |
| (202 | ) | (3,772 | ) | (32,573 | ) | |||
|
|
|
|
|
|
|
| |||
Net increase (decrease) in cash and cash equivalents from discontinued operations |
| (20,971 | ) | (2,839 | ) | 1,091 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents from discontinued operations at beginning of period |
| 20,971 |
| 23,810 |
| 22,719 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents from discontinued operations at end of period |
| $ | — |
| $ | 20,971 |
| $ | 23,810 |
|
|
|
|
|
|
|
|
| |||
Supplemental Disclosure of Cash Flow Information |
|
|
|
|
|
|
| |||
Cash paid during the year for: |
|
|
|
|
|
|
| |||
Interest (net of amount capitalized) |
| $ | 263,228 |
| $ | 253,266 |
| $ | 271,323 |
|
Income taxes |
| $ | 92,175 |
| $ | 57,739 |
| $ | 153,092 |
|
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
112
CINERGY CORP.CONSOLIDATED STATEMENTS OF CAPITALIZATION
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
|
|
|
|
|
| ||
Long-term Debt (excludes current portion) |
|
|
|
|
| ||
Cinergy Corp. |
|
|
|
|
| ||
Other Long-term Debt: |
|
|
|
|
| ||
6.53% Debentures due December 16, 2008 |
| $ | 200,000 |
| $ | 200,000 |
|
6.125% Debentures due April 15, 2004 |
| — |
| 200,000 |
| ||
6.25% Debentures due September 1, 2004 (Executed interest rate swaps of $ 250 million set at London Inter-Bank Offered Rate (LIBOR) plus 2.44%) |
| — |
| 512,554 |
| ||
6.90% Note Payable due February 16, 2007 (Note 4) |
| 326,032 |
| — |
| ||
Total Other Long-term Debt |
| 526,032 |
| 912,554 |
| ||
Unamortized Premium and Discount - Net |
| (6,080 | ) | (165 | ) | ||
Total - Cinergy Corp. |
| 519,952 |
| 912,389 |
| ||
|
|
|
|
|
| ||
Cinergy Global Resources, Inc. |
|
|
|
|
| ||
Other Long-term Debt: |
|
|
|
|
| ||
6.20% Debentures due November 3, 2008 |
| 150,000 |
| 150,000 |
| ||
Variable interest rate of EURIBOR plus 1.2%, maturing November 2016 |
| 79,104 |
| 63,675 |
| ||
Total Other Long-term Debt |
| 229,104 |
| 213,675 |
| ||
Unamortized Premium and Discount - Net |
| (160 | ) | (193 | ) | ||
Total - Cinergy Global Resources, Inc. |
| 228,944 |
| 213,482 |
| ||
|
|
|
|
|
| ||
Cinergy Investments, Inc. |
|
|
|
|
| ||
Other Long-term Debt: |
|
|
|
|
| ||
9.23% Notes Payable, due November 5, 2016 (Note 4) |
| 107,142 |
| — |
| ||
7.81% Notes Payable, due June 1, 2009 (Note 4) |
| 93,041 |
| — |
| ||
Other |
| 3,547 |
| — |
| ||
Total - Cinergy Investments, Inc. |
| 203,730 |
| — |
| ||
|
|
|
|
|
| ||
Operating Companies |
|
|
|
|
| ||
The Cincinnati Gas & Electric Company (CG&E) and subsidiaries |
|
|
|
|
| ||
First Mortgage Bonds |
| 94,700 |
| 470,200 |
| ||
Other Long-term Debt |
| 1,401,721 |
| 1,101,721 |
| ||
Unamortized Premium and Discount - Net |
| (37,614 | ) | (2,208 | ) | ||
Total Long-term Debt |
| 1,458,807 |
| 1,569,713 |
| ||
PSI Energy, Inc. (PSI) |
|
|
|
|
| ||
First Mortgage Bonds |
| 620,720 |
| 620,720 |
| ||
Secured Medium-term Notes |
| 77,500 |
| 104,300 |
| ||
Other Long-term Debt |
| 1,032,663 |
| 598,700 |
| ||
Unamortized Premium and Discount - Net |
| (10,407 | ) | (7,736 | ) | ||
Total Long-term Debt |
| 1,720,476 |
| 1,315,984 |
| ||
|
|
|
|
|
| ||
Total Consolidated Long-term Debt |
| $ | 4,131,909 |
| $ | 4,011,568 |
|
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
113
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
|
|
|
|
|
| ||
Preferred Trust Securities |
|
|
|
|
| ||
Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company |
| $ | — |
| $ | 308,187 |
|
|
|
|
|
|
| ||
Cumulative Preferred Stock of Subsidiaries |
|
|
|
|
| ||
|
|
|
|
|
| ||
CG&E and subsidiaries |
| $ | 20,485 |
| $ | 20,485 |
|
PSI |
| 42,333 |
| 42,343 |
| ||
Total Cumulative Preferred Stock of Subsidiaries |
| $ | 62,818 |
| $ | 62,828 |
|
|
|
|
|
|
| ||
Common Stock Equity |
|
|
|
|
| ||
Common Stock - $0.01 par value; authorized shares - 600,000,000; issued shares - 178,438,369 at December 31, 2003, and 168,663,115 at December 31, 2002; outstanding shares - 178,336,854 at December 31, 2003 and 168,663,115 at December 31, 2002 |
| $ | 1,784 |
| $ | 1,687 |
|
Paid-in capital |
| 2,195,985 |
| 1,918,136 |
| ||
Retained earnings |
| 1,551,003 |
| 1,403,453 |
| ||
Treasury shares at cost - 101,515 shares at December 31, 2003 |
| (3,255 | ) | — |
| ||
Accumulated other comprehensive income (loss) |
| (44,835 | ) | (29,800 | ) | ||
Total Common Stock Equity |
| 3,700,682 |
| 3,293,476 |
| ||
|
|
|
|
|
| ||
Total Consolidated Capitalization |
| $ | 7,895,409 |
| $ | 7,676,059 |
|
|
|
|
|
|
|
|
|
|
| Accumulated |
| Total |
| ||||||
|
|
|
|
|
|
|
|
|
| Other |
| Common |
| ||||||
|
| Common |
| Paid-in |
| Retained |
| Treasury |
| Comprehensive |
| Stock |
| ||||||
|
| Stock |
| Capital |
| Earnings |
| Stock |
| Income (Loss) |
| Equity |
| ||||||
|
| (dollars in thousands, except per share amounts) |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2002 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Beginning balance (159,402,839 shares) |
| $ | 1,594 |
| $ | 1,619,659 |
| $ | 1,337,135 |
| $ | — |
| $ | (16,929 | ) | $ | 2,941,459 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 360,576 |
|
|
|
|
| 360,576 |
| ||||||
Other comprehensive income (loss), net of tax effect of $11,509 (Note 18) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Foreign currency translation adjustment, net of reclassification adjustments (Note 1(r)) |
|
|
|
|
|
|
|
|
| 25,917 |
| 25,917 |
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
|
|
| (13,763 | ) | (13,763 | ) | ||||||
Unrealized loss on investment trusts |
|
|
|
|
|
|
|
|
| (5,277 | ) | (5,277 | ) | ||||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
|
|
| (19,748 | ) | (19,748 | ) | ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
| 347,705 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Issuance of common stock - net (9,260,276 shares) |
| 93 |
| 267,768 |
|
|
|
|
|
|
| 267,861 |
| ||||||
Dividends on common stock ($1.80 per share) |
|
|
|
|
| (298,292 | ) |
|
|
|
| (298,292 | ) | ||||||
Other |
|
|
| 30,709 |
| 4,034 |
|
|
|
|
| 34,743 |
| ||||||
Ending balance (168,663,115 shares) |
| $ | 1,687 |
| $ | 1,918,136 |
| $ | 1,403,453 |
| $ | — |
| $ | (29,800 | ) | $ | 3,293,476 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 469,772 |
|
|
|
|
| 469,772 |
| ||||||
Other comprehensive income (loss), net of tax effect of $11,700 (Note 18) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Foreign currency translation adjustment, net of reclassification adjustments (Note 1(r)) |
|
|
|
|
|
|
|
|
| 10,528 |
| 10,528 |
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
|
|
| (33,846 | ) | (33,846 | ) | ||||||
Unrealized gain on investment trusts |
|
|
|
|
|
|
|
|
| 6,757 |
| 6,757 |
| ||||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
|
|
| 1,526 |
| 1,526 |
| ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
| 454,737 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Issuance of common stock - net (9,775,254 shares) |
| 97 |
| 269,977 |
|
|
|
|
|
|
| 270,074 |
| ||||||
Treasury shares purchased (101,515 shares) |
|
|
|
|
|
|
| (3,255 | ) |
|
| (3,255 | ) | ||||||
Dividends on common stock ($1.84 per share) |
|
|
|
|
| (322,371 | ) |
|
|
|
| (322,371 | ) | ||||||
Other |
|
|
| 7,872 |
| 149 |
|
|
|
|
| 8,021 |
| ||||||
Ending balance (178,336,854 shares) |
| $ | 1,784 |
| $ | 2,195,985 |
| $ | 1,551,003 |
| $ | (3,255 | ) | $ | (44,835 | ) | $ | 3,700,682 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 400,868 |
|
|
|
|
| 400,868 |
| ||||||
Other comprehensive income (loss), net of tax effect of $8,259 (Note 18) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Foreign currency translation adjustment (Note 1(r)) |
|
|
|
|
|
|
|
|
| 14,953 |
| 14,953 |
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
|
|
| (31,752 | ) | (31,752 | ) | ||||||
Unrealized gain on investment trusts |
|
|
|
|
|
|
|
|
| 2,418 |
| 2,418 |
| ||||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
|
|
| 4,542 |
| 4,542 |
| ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
| 391,029 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Issuance of common stock - net (9,215,137 shares) |
| 93 |
| 350,433 |
|
|
|
|
|
|
| 350,526 |
| ||||||
Treasury shares purchased (27,762 shares) |
|
|
|
|
|
|
| (1,081 | ) |
|
| (1,081 | ) | ||||||
Dividends on common stock ($1.88 per share) |
|
|
|
|
| (338,630 | ) |
|
|
|
| (338,630 | ) | ||||||
Other |
|
|
| 13,297 |
| 99 |
|
|
|
|
| 13,396 |
| ||||||
Ending balance (187,524,229 shares) |
| $ | 1,877 |
| $ | 2,559,715 |
| $ | 1,613,340 |
| $ | (4,336 | ) | $ | (54,674 | ) | $ | 4,115,922 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
11499
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| 2004 |
| 2003 |
| 2002 |
| |||
|
| (dollars in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Cash Flows from Continuing Operations |
|
|
|
|
|
|
| |||
Operating Activities |
|
|
|
|
|
|
| |||
Net income |
| $ | 400,868 |
| $ | 469,772 |
| $ | 360,576 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
| |||
Depreciation |
| 460,389 |
| 398,871 |
| 403,909 |
| |||
(Income) Loss of discontinued operations, net of tax |
| — |
| (8,886 | ) | 25,161 |
| |||
(Income) Loss on impairment or disposal of subsidiaries and investments, net |
| 48,144 |
| (93 | ) | (16,518 | ) | |||
Cumulative effect of changes in accounting principles, net of tax |
| — |
| (26,462 | ) | 10,899 |
| |||
Change in net position of energy risk management activities |
| (40,443 | ) | (11,723 | ) | (43,202 | ) | |||
Deferred income taxes and investment tax credits - net |
| (4,113 | ) | 85,108 |
| 148,069 |
| |||
Equity in earnings of unconsolidated subsidiaries |
| (48,249 | ) | (15,201 | ) | (15,261 | ) | |||
Allowance for equity funds used during construction |
| (2,269 | ) | (7,532 | ) | (12,861 | ) | |||
Regulatory asset/liability deferrals |
| (38,868 | ) | (81,791 | ) | (132,117 | ) | |||
Regulatory asset amortization |
| 92,422 |
| 89,931 |
| 115,967 |
| |||
Accrued pension and other postretirement benefit costs |
| 25,443 |
| 36,667 |
| 127,366 |
| |||
Cost of removal |
| (17,763 | ) | (16,598 | ) | — |
| |||
Changes in current assets and current liabilities: |
|
|
|
|
|
|
| |||
Accounts and notes receivable |
| (11,555 | ) | 123,504 |
| (235,437 | ) | |||
Fuel, emission allowances, and supplies |
| (89,699 | ) | 1,410 |
| (81,303 | ) | |||
Prepayments |
| (88,463 | ) | 8,859 |
| (26,818 | ) | |||
Accounts payable |
| 108,476 |
| (89,149 | ) | 311,339 |
| |||
Accrued taxes and interest |
| (15,360 | ) | (35,510 | ) | 65,019 |
| |||
Other assets |
| (50,234 | ) | (26,008 | ) | (50,572 | ) | |||
Other liabilities |
| 104,278 |
| 50,504 |
| 1,586 |
| |||
Net cash provided by operating activities |
| 833,004 |
| 945,673 |
| 955,802 |
| |||
|
|
|
|
|
|
|
| |||
Financing Activities |
|
|
|
|
|
|
| |||
Change in short-term debt |
| 545,405 |
| (393,096 | ) | (442,472 | ) | |||
Issuance of long-term debt |
| 39,361 |
| 688,166 |
| 628,170 |
| |||
Redemption of long-term debt |
| (830,543 | ) | (487,901 | ) | (112,578 | ) | |||
Issuance of common stock |
| 350,526 |
| 270,074 |
| 267,861 |
| |||
Dividends on common stock |
| (338,630 | ) | (322,371 | ) | (298,292 | ) | |||
Net cash provided by (used in) financing activities |
| (233,881 | ) | (245,128 | ) | 42,689 |
| |||
|
|
|
|
|
|
|
| |||
Investing Activities |
|
|
|
|
|
|
| |||
Construction expenditures (less allowance for equity funds used during construction) |
| (697,643 | ) | (704,117 | ) | (853,332 | ) | |||
Proceeds from notes receivable |
| 17,460 |
| 9,187 |
| — |
| |||
Withdrawal of restricted funds held in trust |
| 25,273 |
| — |
| — |
| |||
Acquisitions and other investments |
| (2,965 | ) | (87,859 | ) | (118,375 | ) | |||
Proceeds from distributions by investments and sale of investments and subsidiaries |
| 54,173 |
| 51,252 |
| 86,071 |
| |||
Net cash used in investing activities |
| (603,702 | ) | (731,537 | ) | (885,636 | ) | |||
|
|
|
|
|
|
|
| |||
Net increase (decrease) in cash and cash equivalents from continuing operations |
| (4,579 | ) | (30,992 | ) | 112,855 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents from continuing operations at beginning of period |
| 169,120 |
| 200,112 |
| 87,257 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents from continuing operations at end of period |
| $ | 164,541 |
| $ | 169,120 |
| $ | 200,112 |
|
|
|
|
|
|
|
|
| |||
Cash Flows from Discontinued Operations |
|
|
|
|
|
|
| |||
Operating activities |
| $ | (7,093 | ) | $ | (5,871 | ) | $ | 40,397 |
|
Financing activities |
| 7,093 |
| (14,898 | ) | (39,464 | ) | |||
Investing activities |
| — |
| (202 | ) | (3,772 | ) | |||
|
|
|
|
|
|
|
| |||
Net decrease in cash and cash equivalents from discontinued operations |
| — |
| (20,971 | ) | (2,839 | ) | |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents from discontinued operations at beginning of period |
| — |
| 20,971 |
| 23,810 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents from discontinued operations at end of period |
| $ | — |
| $ | — |
| $ | 20,971 |
|
|
|
|
|
|
|
|
| |||
Supplemental Disclosure of Cash Flow Information |
|
|
|
|
|
|
| |||
Cash paid during the year for: |
|
|
|
|
|
|
| |||
Interest (net of amount capitalized) |
| $ | 298,142 |
| $ | 263,228 |
| $ | 253,266 |
|
Income taxes |
| $ | 73,197 |
| $ | 92,175 |
| $ | 57,739 |
|
|
|
|
|
|
|
|
| |||
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
100
CONSOLIDATED STATEMENTS OF CAPITALIZATION
|
| December 31 |
| ||||||
|
| 2004 |
| 2003 |
| ||||
|
| (dollars in thousands) |
| ||||||
|
|
|
|
|
| ||||
Long-term Debt (excludes current portion) |
|
|
|
|
| ||||
Cinergy Corp. |
|
|
|
|
| ||||
Other Long-term Debt: |
|
|
|
|
| ||||
6.53% Debentures due December 16, 2008 |
| $ | 200,000 |
| $ | 200,000 |
| ||
6.90% Note Payable due February 16, 2007 |
| 326,032 |
| 326,032 |
| ||||
Total Other Long-term Debt |
| 526,032 |
| 526,032 |
| ||||
Unamortized Premium and Discount - Net |
| (3,980 | ) | (6,080 | ) | ||||
Total - Cinergy Corp. |
| 522,052 |
| 519,952 |
| ||||
|
|
|
|
|
| ||||
Cinergy Global Resources, Inc. |
|
|
|
|
| ||||
Other Long-term Debt: |
|
|
|
|
| ||||
6.20% Debentures due November 3, 2008 |
| 150,000 |
| 150,000 |
| ||||
Variable interest rate of Euro Inter-Bank Offered Rate plus 1.2%, maturing November 2016 |
| 89,391 |
| 79,104 |
| ||||
Total Other Long-term Debt |
| 239,391 |
| 229,104 |
| ||||
Unamortized Premium and Discount - Net |
| (126 | ) | (160 | ) | ||||
Total - Cinergy Global Resources, Inc. |
| 239,265 |
| 228,944 |
| ||||
|
|
|
|
|
| ||||
Cinergy Investments, Inc. |
|
|
|
|
| ||||
Other Long-term Debt: |
|
|
|
|
| ||||
9.23% Notes Payable, due November 5, 2016 |
| 105,834 |
| 107,142 |
| ||||
7.81% Notes Payable, due June 1, 2009 |
| 74,773 |
| 93,041 |
| ||||
Other |
| 17,930 |
| 3,547 |
| ||||
Total - Cinergy Investments, Inc. |
| 198,537 |
| 203,730 |
| ||||
|
|
|
|
|
| ||||
Operating Companies |
|
|
|
|
| ||||
The Cincinnati Gas & Electric Company (CG&E) and subsidiaries |
|
|
|
|
| ||||
First Mortgage Bonds |
| 94,700 |
| 94,700 |
| ||||
Other Long-term Debt |
| 1,385,721 |
| 1,401,721 |
| ||||
Unamortized Premium and Discount - Net |
| (36,753 | ) | (37,614 | ) | ||||
Total Long-term Debt |
| 1,443,668 |
| 1,458,807 |
| ||||
PSI Energy, Inc. (PSI) |
|
|
|
|
| ||||
First Mortgage Bonds |
| 620,720 |
| 620,720 |
| ||||
Secured Medium-term Notes |
| 77,500 |
| 77,500 |
| ||||
Other Long-term Debt |
| 1,135,813 |
| 1,032,663 |
| ||||
Unamortized Premium and Discount - Net |
| (9,814 | ) | (10,407 | ) | ||||
Total Long-term Debt |
| 1,824,219 |
| 1,720,476 |
| ||||
|
|
|
|
|
| ||||
Total Consolidated Long-term Debt |
| $ | 4,227,741 |
| $ | 4,131,909 |
| ||
|
|
|
|
|
| ||||
Cumulative Preferred Stock of Subsidiaries |
|
|
|
|
| ||||
|
|
|
|
|
| ||||
CG&E and subsidiaries |
| $ | 20,485 |
| $ | 20,485 |
| ||
PSI |
| 42,333 |
| 42,333 |
| ||||
Total Cumulative Preferred Stock of Subsidiaries |
| $ | 62,818 |
| $ | 62,818 |
| ||
|
|
|
|
|
| ||||
Common Stock Equity |
| $ | 4,115,922 |
| $ | 3,700,682 |
| ||
|
|
|
|
|
| ||||
Total Consolidated Capitalization |
| $ | 8,406,481 |
| $ | 7,895,409 |
| ||
|
|
|
|
|
|
|
| ||
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
101
THE CINCINNATI GAS & ELECTRIC COMPANY
|
| 2003 |
| 2002 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
| ||||||||
|
| (dollars in thousands) |
|
| (dollars in thousands) |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Operating Revenues (Note 1(q)(i)) |
|
|
|
|
|
|
| |||||||||||||||
Operating Revenues (Note 1(d)) |
|
|
|
|
|
|
| |||||||||||||||
Electric |
| $ | 1,754,229 |
| $ | 1,700,318 |
| $ | 1,651,041 |
|
| $ | 1,689,683 |
| $ | 1,691,353 |
| $ | 1,618,687 |
| ||
Gas |
| 627,720 |
| 437,092 |
| 596,429 |
|
| 690,675 |
| 627,720 |
| 437,092 |
| ||||||||
Other (Note 1(d)(iii)) |
| 130,365 |
| 62,876 |
| 81,631 |
| |||||||||||||||
Total Operating Revenues |
| 2,381,949 |
| 2,137,410 |
| 2,247,470 |
|
| 2,510,723 |
| 2,381,949 |
| 2,137,410 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Fuel and purchased and exchanged power (Note 1(q)(i)) |
| 539,269 |
| 472,313 |
| 435,656 |
| |||||||||||||||
Fuel, emission allowances, and purchased power |
| 521,959 |
| 496,041 |
| 413,406 |
| |||||||||||||||
Gas purchased |
| 382,310 |
| 232,558 |
| 396,764 |
|
| 427,585 |
| 382,310 |
| 232,558 |
| ||||||||
Costs of fuel resold |
| 98,898 |
| 54,661 |
| 60,674 |
| |||||||||||||||
Operation and maintenance |
| 511,011 |
| 533,255 |
| 442,173 |
|
| 594,381 |
| 499,556 |
| 531,482 |
| ||||||||
Depreciation |
| 186,819 |
| 196,539 |
| 186,986 |
|
| 179,487 |
| 186,819 |
| 196,539 |
| ||||||||
Taxes other than income taxes |
| 199,818 |
| 197,827 |
| 174,320 |
|
| 198,445 |
| 199,818 |
| 197,827 |
| ||||||||
Total Operating Expenses |
| 1,819,227 |
| 1,632,492 |
| 1,635,899 |
|
| 2,020,755 |
| 1,819,205 |
| 1,632,486 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Operating Income |
| 562,722 |
| 504,918 |
| 611,571 |
|
| 489,968 |
| 562,744 |
| 504,924 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Miscellaneous Income - Net |
| 30,660 |
| 9,742 |
| 4,657 |
|
| 16,228 |
| 30,660 |
| 9,742 |
| ||||||||
Interest Expense |
| 115,193 |
| 95,623 |
| 103,047 |
|
| 90,836 |
| 115,215 |
| 95,629 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Income Before Taxes |
| 478,189 |
| 419,037 |
| 513,181 |
|
| 415,360 |
| 478,189 |
| 419,037 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Income Taxes (Note 10) |
| 178,077 |
| 155,341 |
| 186,527 |
|
| 158,518 |
| 178,077 |
| 155,341 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Income Before Cumulative Effect of Changes in Accounting Principles |
| 300,112 |
| 263,696 |
| 326,654 |
|
| 256,842 |
| 300,112 |
| 263,696 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Cumulative effect of changes in accounting principles, net of tax (Note 1(q)(vi)) |
| 30,938 |
| — |
| — |
| |||||||||||||||
Cumulative effect of changes in accounting principles, net of tax (Note 1(q)(iv)) |
| — |
| 30,938 |
| — |
| |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Net Income |
| $ | 331,050 |
| $ | 263,696 |
| $ | 326,654 |
|
| $ | 256,842 |
| $ | 331,050 |
| $ | 263,696 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Preferred Dividend Requirement |
| 846 |
| 846 |
| 846 |
|
| 845 |
| 846 |
| 846 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Net Income Applicable to Common Stock |
| $ | 330,204 |
| $ | 262,850 |
| $ | 325,808 |
|
| $ | 255,997 |
| $ | 330,204 |
| $ | 262,850 |
| ||
|
|
|
|
|
|
|
| |||||||||||||||
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
103
THE CINCINNATI GAS & ELECTRIC COMPANY
ASSETS |
|
|
|
|
| |||
|
| December 31 |
| |||||
|
| 2004 |
| 2003 |
| |||
|
| (dollars in thousands) |
| |||||
Current Assets |
|
|
|
|
| |||
Cash and cash equivalents |
| $ | 4,154 |
| $ | 15,842 |
| |
Notes receivable from affiliated companies |
| 121,559 |
| 110,149 |
| |||
Accounts receivable less accumulated provision for doubtful accounts of $722 at December 31, 2004, and $1,602 at December 31, 2003 (Note 3(c)) |
| 145,105 |
| 107,733 |
| |||
Accounts receivable from affiliated companies |
| 30,916 |
| 58,406 |
| |||
Fuel, emission allowances, and supplies (Note 1(g)) |
| 199,769 |
| 135,948 |
| |||
Energy risk management current assets (Note 1(k)(i)) |
| 148,866 |
| 72,830 |
| |||
Prepayments and other |
| 54,650 |
| 15,186 |
| |||
Total Current Assets |
| 705,019 |
| 516,094 |
| |||
|
|
|
|
|
| |||
Property, Plant, and Equipment - at Cost |
|
|
|
|
| |||
Utility plant in service (Note 19) |
|
|
|
|
| |||
Electric |
| 2,249,352 |
| 2,155,457 |
| |||
Gas |
| 1,179,764 |
| 1,104,797 |
| |||
Common |
| 249,576 |
| 288,394 |
| |||
Total Utility Plant In Service |
| 3,678,692 |
| 3,548,648 |
| |||
Construction work in progress |
| 45,762 |
| 71,947 |
| |||
Total Utility Plant |
| 3,724,454 |
| 3,620,595 |
| |||
Non-regulated property, plant, and equipment (Note 19) |
| 3,660,226 |
| 3,576,187 |
| |||
Accumulated depreciation (Note 1(h)(i)) |
| 2,694,708 |
| 2,625,568 |
| |||
Net Property, Plant, and Equipment |
| 4,689,972 |
| 4,571,214 |
| |||
|
|
|
|
|
| |||
Other Assets |
|
|
|
|
| |||
Regulatory assets (Note 1(c)) |
| 609,550 |
| 611,855 |
| |||
Energy risk management non-current assets (Note 1(k)(i)) |
| 47,276 |
| 36,583 |
| |||
Restricted funds held in trust |
| 93,671 |
| — |
| |||
Other |
| 86,871 |
| 73,733 |
| |||
Total Other Assets |
| 837,368 |
| 722,171 |
| |||
|
|
|
|
|
| |||
Total Assets |
| $ | 6,232,359 |
| $ | 5,809,479 |
| |
|
|
|
|
|
| |||
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
116104
THE CINCINNATI GAS & ELECTRIC COMPANY
LIABILITIES AND SHAREHOLDER’S EQUITY |
|
|
|
|
| ||
|
| December 31 |
| ||||
|
| 2004 |
| 2003 |
| ||
|
| (dollars in thousands) |
| ||||
Current Liabilities |
|
|
|
|
| ||
Accounts payable |
| $ | 332,316 |
| $ | 217,652 |
|
Accounts payable to affiliated companies |
| 85,127 |
| 136,470 |
| ||
Accrued taxes |
| 149,010 |
| 146,216 |
| ||
Accrued interest |
| 19,408 |
| 21,572 |
| ||
Notes payable and other short-term obligations (Note 5) |
| 112,100 |
| 112,100 |
| ||
Notes payable to affiliated companies (Note 5) |
| 180,116 |
| 49,126 |
| ||
Long-term debt due within one year |
| 150,000 |
| 110,000 |
| ||
Energy risk management current liabilities (Note 1(k)(i)) |
| 120,204 |
| 77,791 |
| ||
Other |
| 33,712 |
| 32,319 |
| ||
Total Current Liabilities |
| 1,181,993 |
| 903,246 |
| ||
|
|
|
|
|
| ||
Non-Current Liabilities |
|
|
|
|
| ||
Long-term debt (Note 4) |
| 1,443,668 |
| 1,458,807 |
| ||
Deferred income taxes (Note 10) |
| 1,090,897 |
| 985,481 |
| ||
Unamortized investment tax credits |
| 73,120 |
| 79,186 |
| ||
Accrued pension and other postretirement benefit costs (Note 9) |
| 228,058 |
| 219,393 |
| ||
Regulatory liabilities (Note 1(c)) |
| 164,846 |
| 155,336 |
| ||
Energy risk management non-current liabilities (Note 1(k)(i)) |
| 40,184 |
| 11,665 |
| ||
Other |
| 70,395 |
| 69,687 |
| ||
Total Non-Current Liabilities |
| 3,111,168 |
| 2,979,555 |
| ||
|
|
|
|
|
| ||
Commitments and Contingencies (Note 11) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Total Liabilities |
| 4,293,161 |
| 3,882,801 |
| ||
|
|
|
|
|
| ||
Cumulative Preferred Stock |
|
|
|
|
| ||
Not subject to mandatory redemption |
| 20,485 |
| 20,485 |
| ||
|
|
|
|
|
| ||
Common Stock Equity (Note 2) |
|
|
|
|
| ||
Common stock - $8.50 par value; authorized shares - 120,000,000; outstanding shares—89,663,086 at December 31, 2004 and December 31, 2003 |
| 762,136 |
| 762,136 |
| ||
Paid-in capital |
| 584,176 |
| 586,528 |
| ||
Retained earnings |
| 610,232 |
| 589,993 |
| ||
Accumulated other comprehensive loss (Note 18) |
| (37,831 | ) | (32,464 | ) | ||
Total Common Stock Equity |
| 1,918,713 |
| 1,906,193 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Shareholder’s Equity |
| $ | 6,232,359 |
| $ | 5,809,479 |
|
|
|
|
|
|
| ||
ASSETSThe accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
Current Assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 15,842 |
| $ | 45,336 |
|
Restricted deposits |
| 137 |
| 3,071 |
| ||
Notes receivable from affiliated companies |
| 110,149 |
| 148,823 |
| ||
Accounts receivable less accumulated provision for doubtful accounts of $1,602 at December 31, 2003, and $5,942 at December 31, 2002 (Note 3(c)) |
| 107,733 |
| 117,269 |
| ||
Accounts receivable from affiliated companies |
| 58,406 |
| 97,584 |
| ||
Materials, supplies, and fuel |
| 123,910 |
| 121,881 |
| ||
Energy risk management current assets (Note 1(k)(i)) |
| 72,830 |
| 57,912 |
| ||
Prepayments and other |
| 27,087 |
| 8,560 |
| ||
Total Current Assets |
| 516,094 |
| 600,436 |
| ||
|
|
|
|
|
| ||
Property, Plant, and Equipment - at Cost |
|
|
|
|
| ||
Utility plant in service (Note 19) |
|
|
|
|
| ||
Electric |
| 2,155,457 |
| 2,073,133 |
| ||
Gas |
| 1,104,797 |
| 1,003,870 |
| ||
Common |
| 288,394 |
| 270,976 |
| ||
Total Utility Plant In Service |
| 3,548,648 |
| 3,347,979 |
| ||
Construction work in progress |
| 71,947 |
| 84,249 |
| ||
Total Utility Plant |
| 3,620,595 |
| 3,432,228 |
| ||
Non-regulated property, plant, and equipment (Note 19) |
| 3,576,187 |
| 3,496,242 |
| ||
Accumulated depreciation (Note 1(q)(iii)) |
| 2,625,568 |
| 2,510,088 |
| ||
Net Property, Plant, and Equipment |
| 4,571,214 |
| 4,418,382 |
| ||
|
|
|
|
|
| ||
Other Assets |
|
|
|
|
| ||
Regulatory assets (Note 1(c)) |
| 594,764 |
| 604,776 |
| ||
Energy risk management non-current assets (Note 1(k)(i)) |
| 36,583 |
| 64,762 |
| ||
Other investments |
| 1,083 |
| 1,082 |
| ||
Other |
| 89,741 |
| 61,764 |
| ||
Total Other Assets |
| 722,171 |
| 732,384 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 5,809,479 |
| $ | 5,751,202 |
|
105
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
|
|
|
|
|
|
|
| Accumulated |
| Total |
| |||||
|
|
|
|
|
|
|
| Other |
| Common |
| |||||
|
| Common |
| Paid-in |
| Retained |
| Comprehensive |
| Stock |
| |||||
|
| Stock |
| Capital |
| Earnings |
| Income (Loss) |
| Equity |
| |||||
|
| (dollars in thousands) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2002 |
|
|
|
|
|
|
|
|
|
|
| |||||
Beginning balance |
| $ | 762,136 |
| $ | 571,926 |
| $ | 408,706 |
| $ | (5,678 | ) | $ | 1,737,090 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 263,696 |
|
|
| 263,696 |
| |||||
Other comprehensive loss, net of tax effect of $13,060 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (872 | ) | (872 | ) | |||||
Unrealized loss on investment trusts |
|
|
|
|
|
|
| (462 | ) | (462 | ) | |||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
| (18,734 | ) | (18,734 | ) | |||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 243,628 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on preferred stock |
|
|
|
|
| (846 | ) |
|
| (846 | ) | |||||
Dividends on common stock |
|
|
|
|
| (185,909 | ) |
|
| (185,909 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| 14,366 |
|
|
|
|
| 14,366 |
| |||||
Other |
|
|
|
|
| 2,005 |
|
|
| 2,005 |
| |||||
Ending balance |
| $ | 762,136 |
| $ | 586,292 |
| $ | 487,652 |
| $ | (25,746 | ) | $ | 1,810,334 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2003 |
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 331,050 |
|
|
| 331,050 |
| |||||
Other comprehensive income (loss), net of tax effect of $4,321 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (8,017 | ) | (8,017 | ) | |||||
Unrealized gain on investment trusts |
|
|
|
|
|
|
| 1 |
| 1 |
| |||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
| 1,298 |
| 1,298 |
| |||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 324,332 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on preferred stock |
|
|
|
|
| (846 | ) |
|
| (846 | ) | |||||
Dividends on common stock |
|
|
|
|
| (227,863 | ) |
|
| (227,863 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| 236 |
|
|
|
|
| 236 |
| |||||
Ending balance |
| $ | 762,136 |
| $ | 586,528 |
| $ | 589,993 |
| $ | (32,464 | ) | $ | 1,906,193 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2004 |
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 256,842 |
|
|
| 256,842 |
| |||||
Other comprehensive income (loss), net of tax effect of $3,453 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (9,666 | ) | (9,666 | ) | |||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
| 4,299 |
| 4,299 |
| |||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 251,475 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on preferred stock |
|
|
|
|
| (845 | ) |
|
| (845 | ) | |||||
Dividends on common stock |
|
|
|
|
| (235,758 | ) |
|
| (235,758 | ) | |||||
Other |
|
|
| (2,352 | ) |
|
|
|
| (2,352 | ) | |||||
Ending balance |
| $ | 762,136 |
| $ | 584,176 |
| $ | 610,232 |
| $ | (37,831 | ) | $ | 1,918,713 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
117106
THE CINCINNATI GAS & ELECTRIC COMPANYCONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITYCONSOLIDATED STATEMENTS OF CASH FLOWS
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
Current Liabilities |
|
|
|
|
| ||
Accounts payable |
| $ | 217,652 |
| $ | 195,812 |
|
Accounts payable to affiliated companies |
| 136,470 |
| 146,558 |
| ||
Accrued taxes |
| 146,216 |
| 159,199 |
| ||
Accrued interest |
| 21,572 |
| 22,872 |
| ||
Notes payable and other short-term obligations (Note 6) |
| 112,100 |
| 112,100 |
| ||
Notes payable to affiliated companies (Note 6) |
| 49,126 |
| 8,947 |
| ||
Long-term debt due within one year |
| 110,000 |
| 120,000 |
| ||
Energy risk management current liabilities (Note 1(k)(i)) |
| 77,791 |
| 49,288 |
| ||
Other |
| 32,319 |
| 37,160 |
| ||
Total Current Liabilities |
| 903,246 |
| 851,936 |
| ||
|
|
|
|
|
| ||
Non-Current Liabilities |
|
|
|
|
| ||
Long-term debt (Note 4) |
| 1,458,807 |
| 1,569,713 |
| ||
Deferred income taxes (Note 10) |
| 985,481 |
| 882,628 |
| ||
Unamortized investment tax credits |
| 79,186 |
| 85,198 |
| ||
Accrued pension and other postretirement benefit costs (Note 9) |
| 219,393 |
| 201,284 |
| ||
Accrued cost of removal (Note 1 (c)) |
| 155,336 |
| 209,455 |
| ||
Energy risk management non-current liabilities (Note 1(k)(i)) |
| 11,665 |
| 31,326 |
| ||
Other |
| 69,687 |
| 88,843 |
| ||
Total Non-Current Liabilities |
| 2,979,555 |
| 3,068,447 |
| ||
|
|
|
|
|
| ||
Commitments and Contingencies (Note 11) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Total Liabilities |
| 3,882,801 |
| 3,920,383 |
| ||
|
|
|
|
|
| ||
Cumulative Preferred Stock |
|
|
|
|
| ||
Not subject to mandatory redemption |
| 20,485 |
| 20,485 |
| ||
|
|
|
|
|
| ||
Common Stock Equity (Note 2) |
|
|
|
|
| ||
Common Stock - $8.50 par value; authorized shares - 120,000,000; outstanding shares - 89,663,086 at December 31, 2003 and December 31, 2002 |
| 762,136 |
| 762,136 |
| ||
Paid-in capital |
| 586,528 |
| 586,292 |
| ||
Retained earnings |
| 589,993 |
| 487,652 |
| ||
Accumulated other comprehensive income (loss) (Note 18) |
| (32,464 | ) | (25,746 | ) | ||
Total Common Stock Equity |
| 1,906,193 |
| 1,810,334 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Shareholder’s Equity |
| $ | 5,809,479 |
| $ | 5,751,202 |
|
|
| 2004 |
| 2003 |
| 2002 |
| |||
|
| (dollars in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Operating Activities |
|
|
|
|
|
|
| |||
Net income |
| $ | 256,842 |
| $ | 331,050 |
| $ | 263,696 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
| |||
Depreciation |
| 179,487 |
| 186,819 |
| 196,539 |
| |||
Deferred income taxes and investment tax credits - net |
| 53,519 |
| 82,228 |
| 104,103 |
| |||
Cumulative effect of changes in accounting principles, net of tax |
| — |
| (30,938 | ) | — |
| |||
Change in net position of energy risk management activities |
| (15,797 | ) | (20,593 | ) | (7,061 | ) | |||
Allowance for equity funds used during construction |
| (458 | ) | (2,749 | ) | (356 | ) | |||
Regulatory asset/liability deferrals |
| (16,535 | ) | (40,510 | ) | (84,694 | ) | |||
Regulatory asset amortization |
| 48,649 |
| 36,824 |
| 44,339 |
| |||
Accrued pension and other postretirement benefit costs |
| 8,665 |
| 18,109 |
| 20,559 |
| |||
Cost of removal |
| (7,875 | ) | — |
| — |
| |||
Changes in current assets and current liabilities: |
|
|
|
|
|
|
| |||
Accounts and notes receivable |
| (25,348 | ) | 23,453 |
| 84,193 |
| |||
Fuel, emission allowances, and supplies |
| (65,030 | ) | (14,061 | ) | 19,014 |
| |||
Prepayments |
| (39,586 | ) | (6,393 | ) | 1,750 |
| |||
Accounts payable |
| 63,928 |
| 9,608 |
| (38,441 | ) | |||
Accrued taxes and interest |
| 938 |
| (14,283 | ) | 48,885 |
| |||
Other assets |
| (11,286 | ) | 20,314 |
| 2,713 |
| |||
Other liabilities |
| 15,508 |
| (21,117 | ) | (2,210 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash provided by operating activities |
| 445,621 |
| 557,761 |
| 653,029 |
| |||
|
|
|
|
|
|
|
| |||
Financing Activities |
|
|
|
|
|
|
| |||
Change in short-term debt, including net affiliate notes |
| 134,460 |
| 104,114 |
| (587,260 | ) | |||
Issuance of long-term debt |
| 39,361 |
| 256,198 |
| 580,570 |
| |||
Redemption of long-term debt |
| (110,000 | ) | (394,899 | ) | (100,000 | ) | |||
Dividends on preferred stock |
| (845 | ) | (846 | ) | (846 | ) | |||
Dividends on common stock |
| (235,758 | ) | (227,863 | ) | (185,909 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash used in financing activities |
| (172,782 | ) | (263,296 | ) | (293,445 | ) | |||
|
|
|
|
|
|
|
| |||
Investing Activities |
|
|
|
|
|
|
| |||
Construction expenditures (less allowance for equity funds used during construction) |
| (299,751 | ) | (323,959 | ) | (323,320 | ) | |||
Other investments |
| 59 |
| — |
| (2 | ) | |||
Proceeds from disposition of subsidiaries and investments |
| 15,165 |
| — |
| — |
| |||
|
|
|
|
|
|
|
| |||
Net cash used in investing activities |
| (284,527 | ) | (323,959 | ) | (323,322 | ) | |||
|
|
|
|
|
|
|
| |||
Net increase (decrease) in cash and cash equivalents |
| (11,688 | ) | (29,494 | ) | 36,262 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at beginning of period |
| 15,842 |
| 45,336 |
| 9,074 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at end of period |
| $ | 4,154 |
| $ | 15,842 |
| $ | 45,336 |
|
|
|
|
|
|
|
|
| |||
Supplemental Disclosure of Cash Flow Information |
|
|
|
|
|
|
| |||
Cash paid during the year for: |
|
|
|
|
|
|
| |||
Interest (net of amount capitalized) |
| $ | 92,542 |
| $ | 103,339 |
| $ | 86,895 |
|
Income taxes |
| $ | 102,502 |
| $ | 45,937 |
| $ | 28,687 |
|
|
|
|
|
|
|
|
| |||
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
118
107
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITYCAPITALIZATION
|
| Common |
| Paid-in |
| Retained |
| Accumulated |
| Total |
| |||||
|
| (dollars in thousands) |
| |||||||||||||
2001 |
|
|
|
|
|
|
|
|
|
|
| |||||
Beginning balance |
| $ | 762,136 |
| $ | 565,777 |
| $ | 368,911 |
| $ | (994 | ) | $ | 1,695,830 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 326,654 |
|
|
| 326,654 |
| |||||
Other comprehensive income (loss), net of tax effect of $2,970 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| 134 |
| 134 |
| |||||
Unrealized gain (loss) on investment trust |
|
|
|
|
|
|
| 461 |
| 461 |
| |||||
Cumulative effect of change in accounting principle |
|
|
|
|
|
|
| (2,500 | ) | (2,500 | ) | |||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
| (2,779 | ) | (2,779 | ) | |||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 321,970 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on preferred stock |
|
|
|
|
| (846 | ) |
|
| (846 | ) | |||||
Dividends on common stock |
|
|
|
|
| (286,269 | ) |
|
| (286,269 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| 6,149 |
|
|
|
|
| 6,149 |
| |||||
Other |
|
|
|
|
| 256 |
|
|
| 256 |
| |||||
Ending balance |
| $ | 762,136 |
| $ | 571,926 |
| $ | 408,706 |
| $ | (5,678 | ) | $ | 1,737,090 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2002 |
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 263,696 |
|
|
| 263,696 |
| |||||
Other comprehensive income (loss), net of tax effect of $13,060 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (872 | ) | (872 | ) | |||||
Unrealized gain (loss) on investment trusts |
|
|
|
|
|
|
| (462 | ) | (462 | ) | |||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
| (18,734 | ) | (18,734 | ) | |||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 243,628 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on preferred stock |
|
|
|
|
| (846 | ) |
|
| (846 | ) | |||||
Dividends on common stock |
|
|
|
|
| (185,909 | ) |
|
| (185,909 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| 14,366 |
|
|
|
|
| 14,366 |
| |||||
Other |
|
|
|
|
| 2,005 |
|
|
| 2,005 |
| |||||
Ending balance |
| $ | 762,136 |
| $ | 586,292 |
| $ | 487,652 |
| $ | (25,746 | ) | $ | 1,810,334 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2003 |
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 331,050 |
|
|
| 331,050 |
| |||||
Other comprehensive income (loss), net of tax effect of $4,321 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (8,017 | ) | (8,017 | ) | |||||
Unrealized gain (loss) on investment trusts |
|
|
|
|
|
|
| 1 |
| 1 |
| |||||
Cash flow hedges (Note 1(k)(ii)) |
|
|
|
|
|
|
| 1,298 |
| 1,298 |
| |||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 324,332 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on preferred stock |
|
|
|
|
| (846 | ) |
|
| (846 | ) | |||||
Dividends on common stock |
|
|
|
|
| (227,863 | ) |
|
| (227,863 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| 236 |
|
|
|
|
| 236 |
| |||||
Ending balance |
| $ | 762,136 |
| $ | 586,528 |
| $ | 589,993 |
| $ | (32,464 | ) | $ | 1,906,193 |
|
|
| December 31 |
| |||||||||||||
|
| 2004 |
| 2003 |
| |||||||||||
|
| (dollars in thousands) |
| |||||||||||||
|
|
|
|
|
| |||||||||||
Long-term Debt (excludes current portion) |
|
|
|
|
| |||||||||||
CG&E |
|
|
|
|
| |||||||||||
First Mortgage Bonds: |
|
|
|
|
| |||||||||||
5.45% Series due January 1, 2024 (Pollution Control) |
| $ | 46,700 |
| $ | 46,700 |
| |||||||||
5 ½% Series due January 1, 2024 (Pollution Control) |
| 48,000 |
| 48,000 |
| |||||||||||
Total First Mortgage Bonds |
| 94,700 |
| 94,700 |
| |||||||||||
|
|
|
|
|
| |||||||||||
Other Long-term Debt: |
|
|
|
|
| |||||||||||
Liquid Asset Notes with Coupon Exchange due October 1, 2007 (Executed interest rate swap to fix the rate at 6.87% through maturity) |
| 100,000 |
| 100,000 |
| |||||||||||
6.40% Debentures due April 1, 2008 |
| 100,000 |
| 100,000 |
| |||||||||||
6.90% Debentures due June 1, 2025 (Redeemable at the option of the holders on June 1, 2005) |
| — |
| 150,000 |
| |||||||||||
5.70% Debentures due September 15, 2012, effective interest rate of 6.42% |
| 500,000 |
| 500,000 |
| |||||||||||
5.40% Debentures due June 15, 2033, effective interest rate of 6.90% |
| 200,000 |
| 200,000 |
| |||||||||||
5 3/8% Debentures due June 15, 2033 |
| 200,000 |
| 200,000 |
| |||||||||||
Series 2002A, Ohio Air Quality Development Revenue Refunding Bonds, due September 1, 2037 (Pollution Control) |
| 42,000 |
| 42,000 |
| |||||||||||
Series 2002B, Ohio Air Quality Development Revenue Refunding Bonds, due September 1, 2037 (Pollution Control) |
| 42,000 |
| 42,000 |
| |||||||||||
Series 2004A, Ohio Air Quality Development Revenue Bonds, due November 1, 2039 (Pollution Control) (Note 4) |
| 47,000 |
| — |
| |||||||||||
Series 2004B, Ohio Air Quality Development Revenue Bonds, due November 1, 2039 (Pollution Control) (Note 4) |
| 47,000 |
| — |
| |||||||||||
Series 1992A, 6.50% Collateralized Pollution Control Revenue Refunding Bonds, due November 15, 2022 |
| 12,721 |
| 12,721 |
| |||||||||||
Total Other Long-term Debt |
| 1,290,721 |
| 1,346,721 |
| |||||||||||
|
|
|
|
|
| |||||||||||
Unamortized Premium and Discount - Net |
| (36,093 | ) | (37,299 | ) | |||||||||||
Total Long-term Debt |
| 1,349,328 |
| 1,404,122 |
| |||||||||||
|
|
|
|
|
| |||||||||||
The Union Light, Heat and Power Company |
|
|
|
|
| |||||||||||
Other Long-term Debt |
| 95,000 |
| 55,000 |
| |||||||||||
Unamortized Premium and Discount - Net |
| (660 | ) | (315 | ) | |||||||||||
Total Long-term Debt |
| 94,340 |
| 54,685 |
| |||||||||||
|
|
|
|
|
| |||||||||||
Total Consolidated Long-term Debt |
| $ | 1,443,668 |
| $ | 1,458,807 |
| |||||||||
|
|
|
|
|
| |||||||||||
Cumulative Preferred Stock |
|
|
|
|
| |||||||||||
|
|
|
| Shares |
|
|
|
|
|
|
|
|
| |||
Par/ |
| Authorized |
| Outstanding at December 31, 2004 |
| Series |
| Mandatory Redemption |
|
|
|
|
| |||
$ | 100 |
| 6,000,000 |
| 204,849 |
| 4% - 4 ¾% |
| No |
| $ | 20,485 |
| $ | 20,485 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Common Stock Equity |
|
|
|
|
|
|
| $ | 1,918,713 |
| $ | 1,906,193 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
| Total Consolidated Capitalization |
|
|
| $ | 3,382,866 |
| $ | 3,385,485 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
119108
THE CINCINNATI GAS & ELECTRIC COMPANYCONSOLIDATED STATEMENTS OF CASH FLOWS
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (dollars in thousands) |
| |||||||
Operating Activities |
|
|
|
|
|
|
| |||
Net income |
| $ | 331,050 |
| $ | 263,696 |
| $ | 326,654 |
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |
|
|
|
|
|
|
| |||
Depreciation |
| 186,819 |
| 196,539 |
| 186,986 |
| |||
Deferred income taxes and investment tax credits - net |
| 82,228 |
| 104,103 |
| 43,834 |
| |||
Cumulative effect of changes in accounting principles, net of tax |
| (30,938 | ) | — |
| — |
| |||
Change in net position of energy risk management activities |
| (20,593 | ) | (7,061 | ) | (67,979 | ) | |||
Allowance for equity funds used during construction |
| (2,749 | ) | (356 | ) | (2,672 | ) | |||
Regulatory assets deferrals |
| (21,175 | ) | (61,321 | ) | (116,365 | ) | |||
Regulatory assets amortization |
| 36,824 |
| 44,339 |
| 56,703 |
| |||
Accrued pension and other postretirement benefit costs |
| 18,109 |
| 20,559 |
| (632 | ) | |||
Deferred costs under gas cost recovery mechanism |
| (19,335 | ) | (23,373 | ) | 53,374 |
| |||
Changes in current assets and current liabilities: |
|
|
|
|
|
|
| |||
Restricted deposits |
| 2,934 |
| 469 |
| (3,380 | ) | |||
Accounts and notes receivable |
| 23,453 |
| 84,193 |
| 174,385 |
| |||
Materials, supplies, and fuel |
| (2,029 | ) | 16,238 |
| (39,058 | ) | |||
Prepayments |
| (6,393 | ) | 1,750 |
| 19,192 |
| |||
Accounts payable |
| 9,608 |
| (38,441 | ) | (183,982 | ) | |||
Accrued taxes and interest |
| (14,283 | ) | 48,885 |
| (37,209 | ) | |||
Other assets |
| 5,348 |
| 5,020 |
| 8,516 |
| |||
Other liabilities |
| (21,117 | ) | (2,210 | ) | (75,249 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) operating activities |
| 557,761 |
| 653,029 |
| 343,118 |
| |||
|
|
|
|
|
|
|
| |||
Financing Activities |
|
|
|
|
|
|
| |||
Change in short-term debt, including net affiliate notes |
| 104,114 |
| (587,260 | ) | 305,155 |
| |||
Issuance of long-term debt |
| 256,198 |
| 580,570 |
| — |
| |||
Redemption of long-term debt |
| (394,899 | ) | (100,000 | ) | (1,200 | ) | |||
Dividends on preferred stock |
| (846 | ) | (846 | ) | (845 | ) | |||
Dividends on common stock |
| (227,863 | ) | (185,909 | ) | (286,269 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) financing activities |
| (263,296 | ) | (293,445 | ) | 16,841 |
| |||
|
|
|
|
|
|
|
| |||
Investing Activities |
|
|
|
|
|
|
| |||
Construction expenditures (less allowance for equity funds used during construction) |
| (323,959 | ) | (323,320 | ) | (371,885 | ) | |||
Other investments |
| — |
| (2 | ) | 363 |
| |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) investing activities |
| (323,959 | ) | (323,322 | ) | (371,522 | ) | |||
|
|
|
|
|
|
|
| |||
Net increase (decrease) in cash and cash equivalents |
| (29,494 | ) | 36,262 |
| (11,563 | ) | |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at beginning of period |
| 45,336 |
| 9,074 |
| 20,637 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at end of period |
| $ | 15,842 |
| $ | 45,336 |
| $ | 9,074 |
|
|
|
|
|
|
|
|
| |||
Supplemental Disclosure of Cash Flow Information |
|
|
|
|
|
|
| |||
Cash paid during the year for: |
|
|
|
|
|
|
| |||
Interest (net of amount capitalized) |
| $ | 103,339 |
| $ | 86,895 |
| $ | 101,579 |
|
Income taxes |
| $ | 45,937 |
| $ | 28,687 |
| $ | 147,471 |
|
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
120
THE CINCINNATI GAS & ELECTRIC COMPANYCONSOLIDATED STATEMENTS OF CAPITALIZATION
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
|
|
|
|
|
| ||
Long-term Debt (excludes current portion) |
|
|
|
|
| ||
CG&E |
|
|
|
|
| ||
First Mortgage Bonds: |
|
|
|
|
| ||
6.45% Series due February 15, 2004 |
| $ | — |
| $ | 110,000 |
|
7.20% Series due October 1, 2023 |
| — |
| 265,500 |
| ||
5.45% Series due January 1, 2024 (Pollution Control) |
| 46,700 |
| 46,700 |
| ||
5 1/2% Series due January 1, 2024 (Pollution Control) |
| 48,000 |
| 48,000 |
| ||
Total First Mortgage Bonds |
| 94,700 |
| 470,200 |
| ||
|
|
|
|
|
| ||
Other Long-term Debt: |
|
|
|
|
| ||
Liquid Asset Notes with Coupon Exchange due October 1, 2007 |
|
|
|
|
| ||
(Executed interest rate swap to fix the rate at 6.87% through maturity) |
| 100,000 |
| 100,000 |
| ||
6.40% Debentures due April 1, 2008 |
| 100,000 |
| 100,000 |
| ||
6.90% Debentures due June 1, 2025 (Redeemable at the option of the holders on June 1, 2005) |
| 150,000 |
| 150,000 |
| ||
8.28% Junior Subordinated Debentures due June 30, 2025 |
| — |
| 100,000 |
| ||
5.70% Debentures due September 15, 2012, effective interest rate of 6.42% |
| 500,000 |
| 500,000 |
| ||
5.40% Debentures due June 15, 2033, effective interest rate of 6.90% |
| 200,000 |
| — |
| ||
5 3/8% Debentures due June 15, 2033 |
| 200,000 |
| — |
| ||
Series 2002A, Ohio Air Quality Development Revenue Refunding Bonds, due September 1, 2037 (Pollution Control) |
| 42,000 |
| 42,000 |
| ||
Series 2002B, Ohio Air Quality Development Revenue Refunding Bonds, due September 1, 2037 (Pollution Control) |
| 42,000 |
| 42,000 |
| ||
Series 1992A, 6.50% Collateralized Pollution Control Revenue Refunding Bonds, due November 15, 2002 |
| 12,721 |
| 12,721 |
| ||
Total Other Long-term Debt |
| 1,346,721 |
| 1,046,721 |
| ||
|
|
|
|
|
| ||
Unamortized Premium and Discount - Net |
| (37,299 | ) | (1,861 | ) | ||
Total Long-term Debt |
| 1,404,122 |
| 1,515,060 |
| ||
|
|
|
|
|
| ||
The Union Light, Heat and Power Company |
|
|
|
|
| ||
Other Long-term Debt: |
|
|
|
|
| ||
6.50% Debentures due April 30, 2008 |
| 20,000 |
| 20,000 |
| ||
7.65% Debentures due July 15, 2025 |
| 15,000 |
| 15,000 |
| ||
7.875% Debentures due September 15, 2009 |
| 20,000 |
| 20,000 |
| ||
Total Other Long-term Debt |
| 55,000 |
| 55,000 |
| ||
|
|
|
|
|
| ||
Unamortized Premium and Discount - Net |
| (315 | ) | (347 | ) | ||
Total Long-term Debt |
| 54,685 |
| 54,653 |
| ||
|
|
|
|
|
| ||
Total Consolidated Long-term Debt |
| $ | 1,458,807 |
| $ | 1,569,713 |
|
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
121
|
|
|
|
|
|
|
|
|
| December 31 |
| |||||||
|
|
|
|
|
|
|
|
|
| 2003 |
| 2002 |
| |||||
|
|
|
|
|
|
|
|
|
| (dollars in thousands) |
| |||||||
Cumulative Preferred Stock |
|
|
|
|
| |||||||||||||
Par/Stated |
| Authorized |
| Shares |
| Series |
| Mandatory |
|
|
|
|
| |||||
$100 |
| 6,000,000 |
| 204,849 |
| 4 %- 4 ¾% |
| No |
| $ | 20,485 |
| $ | 20,485 |
| |||
|
|
|
|
|
| |||||||||||||
Common Stock Equity |
|
|
|
|
| |||||||||||||
Common Stock - $8.50 par value; authorized shares - 120,000,000; outstanding shares - 89,663,086 at December 31, 2003, and December 31, 2002 |
| $ | 762,136 |
| $ | 762,136 |
| |||||||||||
Paid-in capital |
| 586,528 |
| 586,292 |
| |||||||||||||
Retained earnings |
| 589,993 |
| 487,652 |
| |||||||||||||
Accumulated other comprehensive income (loss) |
| (32,464 | ) | (25,746 | ) | |||||||||||||
Total Common Stock Equity |
| 1,906,193 |
| 1,810,334 |
| |||||||||||||
|
|
|
|
|
| |||||||||||||
Total Consolidated Capitalization |
| $ | 3,385,485 |
| $ | 3,400,532 |
| |||||||||||
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these consolidated financial statements.
122
AND SUBSIDIARY COMPANY
123109
CONSOLIDATED STATEMENTS OF INCOME
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (dollars in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Operating Revenues (Note 1(q)(i)) |
|
|
|
|
|
|
| |||
Electric |
| $ | 1,603,019 |
| $ | 1,610,578 |
| $ | 1,573,691 |
|
|
|
|
|
|
|
|
| |||
Operating Expenses |
|
|
|
|
|
|
| |||
Fuel and purchased and exchanged power (Note 1(q)(i)) |
| 608,234 |
| 527,360 |
| 631,161 |
| |||
Operation and maintenance |
| 452,673 |
| 488,903 |
| 413,275 |
| |||
Depreciation |
| 184,164 |
| 156,102 |
| 149,467 |
| |||
Taxes other than income taxes |
| 46,200 |
| 56,695 |
| 49,955 |
| |||
Total Operating Expenses |
| 1,291,271 |
| 1,229,060 |
| 1,243,858 |
| |||
|
|
|
|
|
|
|
| |||
Operating Income |
| 311,748 |
| 381,518 |
| 329,833 |
| |||
|
|
|
|
|
|
|
| |||
Miscellaneous Income - Net |
| 6,288 |
| 20,582 |
| 19,541 |
| |||
Interest Expense |
| 83,594 |
| 73,142 |
| 80,955 |
| |||
|
|
|
|
|
|
|
| |||
Income Before Taxes |
| 234,442 |
| 328,958 |
| 268,419 |
| |||
|
|
|
|
|
|
|
| |||
Income Taxes (Note 10) |
| 100,567 |
| 114,709 |
| 106,086 |
| |||
|
|
|
|
|
|
|
| |||
Income Before Cumulative Effect of a Change in Accounting Principle |
| 133,875 |
| 214,249 |
| 162,333 |
| |||
|
|
|
|
|
|
|
| |||
Cumulative effect of a change in accounting principle, net of tax (Note 1(q)(vi)) |
| (494 | ) | — |
| — |
| |||
|
|
|
|
|
|
|
| |||
Net Income |
| $ | 133,381 |
| $ | 214,249 |
| $ | 162,333 |
|
|
|
|
|
|
|
|
| |||
Preferred Dividend Requirement |
| 2,587 |
| 2,587 |
| 2,587 |
| |||
|
|
|
|
|
|
|
| |||
Net Income Applicable to Common Stock |
| $ | 130,794 |
| $ | 211,662 |
| $ | 159,746 |
|
|
| 2004 |
| 2003 |
| 2002 |
| |||||
|
| (dollars in thousands) |
| |||||||||
|
|
|
|
|
|
|
| |||||
Operating Revenues (Note 1(d)) |
|
|
|
|
|
|
| |||||
Electric |
| $ | 1,753,699 |
| $ | 1,603,019 |
| $ | 1,610,578 |
| ||
|
|
|
|
|
|
|
| |||||
Operating Expenses |
|
|
|
|
|
|
| |||||
Fuel, emission allowances, and purchased power |
| 651,086 |
| 630,216 |
| 547,031 |
| |||||
Operation and maintenance |
| 474,517 |
| 448,668 |
| 470,263 |
| |||||
Depreciation |
| 221,596 |
| 163,938 |
| 154,524 |
| |||||
Taxes other than income taxes |
| 47,152 |
| 46,200 |
| 56,695 |
| |||||
Total Operating Expenses |
| 1,394,351 |
| 1,289,022 |
| 1,228,513 |
| |||||
|
|
|
|
|
|
|
| |||||
Operating Income |
| 359,348 |
| 313,997 |
| 382,065 |
| |||||
|
|
|
|
|
|
|
| |||||
Miscellaneous Income - Net |
| 9,348 |
| 6,288 |
| 20,582 |
| |||||
Interest Expense |
| 91,481 |
| 85,843 |
| 73,689 |
| |||||
|
|
|
|
|
|
|
| |||||
Income Before Taxes |
| 277,215 |
| 234,442 |
| 328,958 |
| |||||
|
|
|
|
|
|
|
| |||||
Income Taxes (Note 10) |
| 112,213 |
| 100,567 |
| 114,709 |
| |||||
|
|
|
|
|
|
|
| |||||
Income Before Cumulative Effect of a Change in Accounting Principle |
| 165,002 |
| 133,875 |
| 214,249 |
| |||||
|
|
|
|
|
|
|
| |||||
Cumulative effect of a change in accounting principle, net of tax (Note 1(q)(iv)) |
| — |
| (494 | ) | — |
| |||||
|
|
|
|
|
|
|
| |||||
Net Income |
| $ | 165,002 |
| $ | 133,381 |
| $ | 214,249 |
| ||
|
|
|
|
|
|
|
| |||||
Preferred Dividend Requirement |
| 2,587 |
| 2,587 |
| 2,587 |
| |||||
|
|
|
|
|
|
|
| |||||
Net Income Applicable to Common Stock |
| $ | 162,415 |
| $ | 130,794 |
| $ | 211,662 |
| ||
|
|
|
|
|
|
|
| |||||
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
124110
psi energy, inc.PSI ENERGY, INC.
consolidated balance sheetsCONSOLIDATED BALANCE SHEETS
ASSETS
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
Current Assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 6,565 |
| $ | 2,007 |
|
Restricted deposits (Note 6) |
| 92,675 |
| 20 |
| ||
Notes receivable from affiliated companies (Note 5) |
| 65,715 |
| 53,755 |
| ||
Accounts receivable less accumulated provision for doubtful accounts of $1,110 at December 31, 2003, and $5,656 at December 31, 2002 (Note 3(c)) |
| 37,194 |
| 84,819 |
| ||
Accounts receivable from affiliated companies |
| 459 |
| 437 |
| ||
Materials, supplies, and fuel |
| 125,463 |
| 137,292 |
| ||
Energy risk management current assets (Note 1(k)(i)) |
| 7,959 |
| 8,701 |
| ||
Prepayments and other |
| 29,232 |
| 44,725 |
| ||
Total Current Assets |
| 365,262 |
| 331,756 |
| ||
|
|
|
|
|
| ||
Property, Plant, and Equipment - at Cost |
|
|
|
|
| ||
Utility plant in service |
| 6,183,475 |
| 5,321,066 |
| ||
Construction work in progress |
| 203,512 |
| 385,051 |
| ||
Total Utility Plant |
| 6,386,987 |
| 5,706,117 |
| ||
Accumulated depreciation |
| 2,133,235 |
| 2,018,847 |
| ||
Net Property, Plant, and Equipment (Note 19) |
| 4,253,752 |
| 3,687,270 |
| ||
|
|
|
|
|
| ||
Other Assets |
|
|
|
|
| ||
Regulatory assets (Note 1(c)) |
| 417,387 |
| 417,920 |
| ||
Energy risk management non-current assets (Note 1(k)(i)) |
| 7,061 |
| 16,590 |
| ||
Other investments |
| 66,803 |
| 54,683 |
| ||
Other |
| 29,372 |
| 30,697 |
| ||
Total Other Assets |
| 520,623 |
| 519,890 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 5,139,637 |
| $ | 4,538,916 |
|
ASSETS |
|
|
|
|
| ||
|
| December 31 |
| ||||
|
| 2004 |
| 2003 |
| ||
|
| (dollars in thousands) |
| ||||
Current Assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 10,794 |
| $ | 6,565 |
|
Restricted deposits |
| 22,063 |
| 92,675 |
| ||
Notes receivable from affiliated companies |
| 72,958 |
| 65,715 |
| ||
Accounts receivable less accumulated provision for doubtful accounts of $171 at December 31, 2004, and $1,110 at December 31, 2003 (Note 3(c)) |
| 31,177 |
| 37,194 |
| ||
Accounts receivable from affiliated companies |
| 437 |
| 459 |
| ||
Fuel, emission allowances, and supplies (Note 1(g)) |
| 108,793 |
| 149,392 |
| ||
Energy risk management current assets (Note 1(k)(i)) |
| 2,820 |
| 7,959 |
| ||
Prepayments and other |
| 8,984 |
| 5,303 |
| ||
Total Current Assets |
| 258,026 |
| 365,262 |
| ||
|
|
|
|
|
| ||
Property, Plant, and Equipment - at Cost |
|
|
|
|
| ||
Utility plant in service (Note 19) |
| 6,397,776 |
| 6,183,475 |
| ||
Construction work in progress |
| 287,925 |
| 203,512 |
| ||
Total Utility Plant |
| 6,685,701 |
| 6,386,987 |
| ||
Accumulated depreciation (Note 1(h)(i)) |
| 2,284,932 |
| 2,133,235 |
| ||
Net Property, Plant, and Equipment (Note 19) |
| 4,400,769 |
| 4,253,752 |
| ||
|
|
|
|
|
| ||
Other Assets |
|
|
|
|
| ||
Regulatory assets (Note 1(c)) |
| 420,783 |
| 417,387 |
| ||
Energy risk management non-current assets (Note 1(k)(i)) |
| 1,690 |
| 7,061 |
| ||
Other investments |
| 73,396 |
| 66,803 |
| ||
Restricted funds held in trust |
| 264,335 |
| - |
| ||
Other |
| 30,897 |
| 29,372 |
| ||
Total Other Assets |
| 791,101 |
| 520,623 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 5,449,896 |
| $ | 5,139,637 |
|
|
|
|
|
|
| ||
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
125111
psi energy, inc.PSI ENERGY, INC.
consolidated balance sheetsCONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
Current Liabilities |
|
|
|
|
| ||
Accounts payable |
| $ | 58,286 |
| $ | 113,563 |
|
Accounts payable to affiliated companies |
| 69,746 |
| 107,364 |
| ||
Accrued taxes |
| 69,419 |
| 105,960 |
| ||
Accrued interest |
| 26,615 |
| 23,078 |
| ||
Notes payable and other short-term obligations (Note 6) |
| 80,500 |
| 35,000 |
| ||
Notes payable to affiliated companies (Note 6) |
| 188,446 |
| 138,055 |
| ||
Long-term debt due within one year |
| — |
| 56,000 |
| ||
Energy risk management current liabilities (Note 1(k)(i)) |
| 14,744 |
| 8,000 |
| ||
Other |
| 25,636 |
| 22,335 |
| ||
Total Current Liabilities |
| 533,392 |
| 609,355 |
| ||
|
|
|
|
|
| ||
Non-Current Liabilities |
|
|
|
|
| ||
Long-term debt (Note 4) |
| 1,720,476 |
| 1,315,984 |
| ||
Deferred income taxes (Note 10) |
| 573,946 |
| 538,745 |
| ||
Unamortized investment tax credits |
| 29,698 |
| 32,897 |
| ||
Accrued pension and other postretirement benefit costs (Note 9) |
| 193,336 |
| 184,299 |
| ||
Accrued cost of removal (Note 1(c)) |
| 335,520 |
| 315,960 |
| ||
Energy risk management non-current liabilities (Note 1(k)(i)) |
| 2,796 |
| 17,157 |
| ||
Other |
| 74,958 |
| 80,879 |
| ||
Total Non-Current Liabilities |
| 2,930,730 |
| 2,485,921 |
| ||
|
|
|
|
|
| ||
Commitments and Contingencies (Note 11) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Total Liabilities |
| 3,464,122 |
| 3,095,276 |
| ||
|
|
|
|
|
| ||
Cumulative Preferred Stock |
|
|
|
|
| ||
Not subject to mandatory redemption |
| 42,333 |
| 42,343 |
| ||
|
|
|
|
|
| ||
Common Stock Equity (Note 2) |
|
|
|
|
| ||
Common Stock - without par value; $0.01 stated value; authorized shares - 60,000,000; outstanding shares - 53,913,701 at December 31, 2003 and December 31, 2002 |
| 539 |
| 539 |
| ||
Paid-in capital |
| 627,274 |
| 426,931 |
| ||
Retained earnings |
| 1,018,790 |
| 981,946 |
| ||
Accumulated other comprehensive income (loss) (Note 18) |
| (13,421 | ) | (8,119 | ) | ||
Total Common Stock Equity |
| 1,633,182 |
| 1,401,297 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Shareholder’s Equity |
| $ | 5,139,637 |
| $ | 4,538,916 |
|
LIABILITIES AND SHAREHOLDER’S EQUITY |
|
|
|
|
| |||
|
| December 31 |
| |||||
|
| 2004 |
| 2003 |
| |||
|
| (dollars in thousands) |
| |||||
Current Liabilities |
|
|
|
|
| |||
Accounts payable |
| $ | 65,151 |
| $ | 58,286 |
| |
Accounts payable to affiliated companies |
| 38,292 |
| 69,746 |
| |||
Accrued taxes |
| 65,871 |
| 69,419 |
| |||
Accrued interest |
| 27,532 |
| 26,615 |
| |||
Notes payable and other short-term obligations (Note 5) |
| 135,500 |
| 80,500 |
| |||
Notes payable to affiliated companies (Note 5) |
| 130,580 |
| 188,446 |
| |||
Long-term debt due within one year |
| 50,000 |
| - |
| |||
Energy risk management current liabilities (Note 1(k)(i)) |
| 1,428 |
| 14,744 |
| |||
Other |
| 31,898 |
| 25,636 |
| |||
Total Current Liabilities |
| 546,252 |
| 533,392 |
| |||
|
|
|
|
|
| |||
Non-Current Liabilities |
|
|
|
|
| |||
Long-term debt (Note 4) |
| 1,824,219 |
| 1,720,476 |
| |||
Deferred income taxes (Note 10) |
| 638,061 |
| 573,946 |
| |||
Unamortized investment tax credits |
| 26,603 |
| 29,698 |
| |||
Accrued pension and other postretirement benefit costs (Note 9) |
| 209,992 |
| 193,336 |
| |||
Regulatory liabilities (Note 1(c)) |
| 392,573 |
| 335,520 |
| |||
Energy risk management non-current liabilities (Note 1(k)(i)) |
| 475 |
| 2,796 |
| |||
Other |
| 88,190 |
| 74,958 |
| |||
Total Non-Current Liabilities |
| 3,180,113 |
| 2,930,730 |
| |||
|
|
|
|
|
| |||
Commitments and Contingencies (Note 11) |
|
|
|
|
| |||
|
|
|
|
|
| |||
Total Liabilities |
| 3,726,365 |
| 3,464,122 |
| |||
|
|
|
|
|
| |||
Cumulative Preferred Stock |
|
|
|
|
| |||
Not subject to mandatory redemption |
| 42,333 |
| 42,333 |
| |||
|
|
|
|
|
| |||
Common Stock Equity (Note 2) |
|
|
|
|
| |||
Common stock - without par value; $.01 stated value; authorized shares - 60,000,000; outstanding shares - 53,913,701 at December 31, 2004 and December 31, 2003 |
| 539 |
| 539 |
| |||
Paid-in capital |
| 626,019 |
| 627,274 |
| |||
Retained earnings |
| 1,078,617 |
| 1,018,790 |
| |||
Accumulated other comprehensive loss (Note 18) |
| (23,977 | ) | (13,421 | ) | |||
Total Common Stock Equity |
| 1,681,198 |
| 1,633,182 |
| |||
|
|
|
|
|
| |||
Total Liabilities and Shareholder’s Equity |
| $ | 5,449,896 |
| $ | 5,139,637 |
| |
|
|
|
|
|
| |||
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
126112
psi energy, inc.PSI ENERGY, INC.
consolidated statements of changes in common stock equityCONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
|
| Common |
| Paid-in |
| Retained |
| Accumulated |
| Total |
| |||||
|
| (dollars in thousands) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2001 |
|
|
|
|
|
|
|
|
|
|
| |||||
Beginning balance |
| $ | 539 |
| $ | 413,523 |
| $ | 720,153 |
| $ | (520 | ) | $ | 1,133,695 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 162,333 |
|
|
| 162,333 |
| |||||
Other comprehensive income (loss), net of tax effect of $538 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (49 | ) | (49 | ) | |||||
Unrealized gain (loss) on investment trusts |
|
|
|
|
|
|
| (1,026 | ) | (1,026 | ) | |||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 161,258 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on preferred stock |
|
|
|
|
| (2,587 | ) |
|
| (2,587 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| 2,894 |
|
|
|
|
| 2,894 |
| |||||
Other |
|
|
| (3 | ) | 230 |
|
|
| 227 |
| |||||
Ending balance |
| $ | 539 |
| $ | 416,414 |
| $ | 880,129 |
| $ | (1,595 | ) | $ | 1,295,487 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2002 |
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 214,249 |
|
|
| 214,249 |
| |||||
Other comprehensive income (loss), net of tax effect of $4,189 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (2,138 | ) | (2,138 | ) | |||||
Unrealized gain (loss) on investment trusts |
|
|
|
|
|
|
| (4,386 | ) | (4,386 | ) | |||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 207,725 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on preferred stock |
|
|
|
|
| (2,587 | ) |
|
| (2,587 | ) | |||||
Dividends on common stock |
|
|
|
|
| (111,842 | ) |
|
| (111,842 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| 10,519 |
|
|
|
|
| 10,519 |
| |||||
Other |
|
|
| (2 | ) | 1,997 |
|
|
| 1,995 |
| |||||
Ending balance |
| $ | 539 |
| $ | 426,931 |
| $ | 981,946 |
| $ | (8,119 | ) | $ | 1,401,297 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2003 |
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 133,381 |
|
|
| 133,381 |
| |||||
Other comprehensive income (loss), net of tax effect of $3,645 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (11,534 | ) | (11,534 | ) | |||||
Unrealized gain (loss) on investment trusts |
|
|
|
|
|
|
| 6,232 |
| 6,232 |
| |||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 128,079 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on preferred stock |
|
|
|
|
| (2,587 | ) |
|
| (2,587 | ) | |||||
Dividends on common stock |
|
|
|
|
| (93,950 | ) |
|
| (93,950 | ) | |||||
Contribution from parent company - equity infusion |
|
|
| 200,000 |
|
|
|
|
| 200,000 |
| |||||
Contribution from parent company for reallocation of taxes |
|
|
| 343 |
|
|
|
|
| 343 |
| |||||
Ending balance |
| $ | 539 |
| $ | 627,274 |
| $ | 1,018,790 |
| $ | (13,421 | ) | $ | 1,633,182 |
|
|
|
|
|
|
|
|
| Accumulated |
| Total |
| ||||||
|
|
|
|
|
|
|
| Other |
| Common |
| ||||||
|
| Common |
| Paid-in |
| Retained |
| Comprehensive |
| Stock |
| ||||||
|
| Stock |
| Capital |
| Earnings |
| Income (Loss) |
| Equity |
| ||||||
|
| (dollars in thousands) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2002 |
|
|
|
|
|
|
|
|
|
|
| ||||||
Beginning balance |
| $ | 539 |
| $ | 416,414 |
| $ | 880,129 |
| $ | (1,595 | ) | $ | 1,295,487 |
| |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 214,249 |
|
|
| 214,249 |
| ||||||
Other comprehensive loss, net of tax effect of $4,189 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (2,138 | ) | (2,138 | ) | ||||||
Unrealized loss on investment trusts |
|
|
|
|
|
|
| (4,386 | ) | (4,386 | ) | ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 207,725 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Dividends on preferred stock |
|
|
|
|
| (2,587 | ) |
|
| (2,587 | ) | ||||||
Dividends on common stock |
|
|
|
|
| (111,842 | ) |
|
| (111,842 | ) | ||||||
Contribution from parent company for reallocation of taxes |
|
|
| 10,519 |
|
|
|
|
| 10,519 |
| ||||||
Other |
|
|
| (2 | ) | 1,997 |
|
|
| 1,995 |
| ||||||
Ending balance |
| $ | 539 |
| $ | 426,931 |
| $ | 981,946 |
| $ | (8,119 | ) | $ | 1,401,297 |
| |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2003 |
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 133,381 |
|
|
| 133,381 |
| ||||||
Other comprehensive income (loss), net of tax effect of $3,645 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (11,534 | ) | (11,534 | ) | ||||||
Unrealized gain on investment trusts |
|
|
|
|
|
|
| 6,232 |
| 6,232 |
| ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 128,079 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Dividends on preferred stock |
|
|
|
|
| (2,587 | ) |
|
| (2,587 | ) | ||||||
Dividends on common stock |
|
|
|
|
| (93,950 | ) |
|
| (93,950 | ) | ||||||
Contribution from parent company - equity infusion |
|
|
| 200,000 |
|
|
|
|
| 200,000 |
| ||||||
Contribution from parent company for reallocation of taxes |
|
|
| 343 |
|
|
|
|
| 343 |
| ||||||
Ending balance |
| $ | 539 |
| $ | 627,274 |
| $ | 1,018,790 |
| $ | (13,421 | ) | $ | 1,633,182 |
| |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2004 |
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 165,002 |
|
|
| 165,002 |
| ||||||
Other comprehensive income (loss), net of tax effect of $7,350 (Note 18) |
|
|
|
|
|
|
|
|
|
|
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (12,597 | ) | (12,597 | ) | ||||||
Unrealized gain on investment trusts |
|
|
|
|
|
|
| 2,041 |
| 2,041 |
| ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 154,446 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Dividends on preferred stock |
|
|
|
|
| (2,587 | ) |
|
| (2,587 | ) | ||||||
Dividends on common stock |
|
|
|
|
| (102,588 | ) |
|
| (102,588 | ) | ||||||
Other |
|
|
| (1,255 | ) |
|
|
|
| (1,255 | ) | ||||||
Ending balance |
| $ | 539 |
| $ | 626,019 |
| $ | 1,078,617 |
| $ | (23,977 | ) | $ | 1,681,198 |
| |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
127113
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (dollars in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Operating Activities |
|
|
|
|
|
|
| |||
Net income |
| $ | 133,381 |
| $ | 214,249 |
| $ | 162,333 |
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |
|
|
|
|
|
|
| |||
Depreciation |
| 184,164 |
| 156,102 |
| 149,467 |
| |||
Cumulative effect of a change in accounting principle, net of tax |
| 494 |
| — |
| — |
| |||
Deferred income taxes and investment tax credits - net |
| 38,424 |
| 33,908 |
| 41,543 |
| |||
Change in net position of energy risk management activities |
| (1,133 | ) | 9,544 |
| (33,158 | ) | |||
Allowance for equity funds used during construction |
| (4,783 | ) | (12,505 | ) | (5,956 | ) | |||
Regulatory assets deferrals |
| (62,053 | ) | (49,546 | ) | (24,959 | ) | |||
Regulatory assets amortization |
| 53,652 |
| 72,173 |
| 62,641 |
| |||
Accrued pension and other postretirement benefit costs |
| 9,037 |
| 24,130 |
| 10,597 |
| |||
Cost of removal |
| (16,598 | ) | — |
| — |
| |||
Changes in current assets and current liabilities: |
|
|
|
|
|
|
| |||
Restricted deposits |
| (12,316 | ) | 499 |
| (178 | ) | |||
Accounts and notes receivable |
| 35,643 |
| 233,040 |
| 119,311 |
| |||
Materials, supplies, and fuel |
| 11,829 |
| (49,631 | ) | (33,823 | ) | |||
Prepayments |
| 686 |
| (2,908 | ) | (120 | ) | |||
Accounts payable |
| (104,515 | ) | (119,032 | ) | (84,577 | ) | |||
Accrued taxes and interest |
| (33,004 | ) | 2,961 |
| 21,374 |
| |||
Other assets |
| 22,096 |
| (22,161 | ) | 17,074 |
| |||
Other liabilities |
| (8,269 | ) | 8,224 |
| 342 |
| |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) operating activities |
| 246,735 |
| 499,047 |
| 401,911 |
| |||
|
|
|
|
|
|
|
| |||
Financing Activities |
|
|
|
|
|
|
| |||
Change in short-term debt, including net affiliate notes |
| 95,891 |
| 46,993 |
| (195,912 | ) | |||
Issuance of long-term debt |
| 431,968 |
| 47,600 |
| 322,471 |
| |||
Redemption of long-term debt |
| (460,903 | ) | (23,979 | ) | (89,248 | ) | |||
Contribution from parent |
| 200,000 |
| — |
| — |
| |||
Funds on deposit from issuance of debt securities |
| (80,339 | ) | — |
| — |
| |||
Retirement of preferred stock |
| (10 | ) | (2 | ) | (1 | ) | |||
Dividends on preferred stock |
| (2,587 | ) | (2,587 | ) | (2,587 | ) | |||
Dividends on common stock |
| (93,950 | ) | (111,842 | ) | — |
| |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) financing activities |
| 90,070 |
| (43,817 | ) | 34,723 |
| |||
|
|
|
|
|
|
|
| |||
Investing Activities |
|
|
|
|
|
|
| |||
Construction expenditures (less allowance for equity funds used during construction) |
| (330,362 | ) | (451,326 | ) | (427,787 | ) | |||
Other investments |
| (1,885 | ) | (3,484 | ) | (8,571 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) investing activities |
| (332,247 | ) | (454,810 | ) | (436,358 | ) | |||
|
|
|
|
|
|
|
| |||
Net increase (decrease) in cash and cash equivalents |
| 4,558 |
| 420 |
| 276 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at beginning of period |
| 2,007 |
| 1,587 |
| 1,311 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at end of period |
| $ | 6,565 |
| $ | 2,007 |
| $ | 1,587 |
|
|
|
|
|
|
|
|
| |||
Supplemental Disclosure of Cash Flow Information |
|
|
|
|
|
|
| |||
Cash paid during the year for: |
|
|
|
|
|
|
| |||
Interest (net of amount capitalized) |
| $ | 95,733 |
| $ | 89,865 |
| $ | 97,917 |
|
Income taxes |
| $ | 65,564 |
| $ | 27,401 |
| $ | 41,419 |
|
|
|
|
|
|
|
|
| |||
Non-cash financing and investing activities: |
|
|
|
|
|
|
| |||
Issuance of promissory notes to affiliated company for acquisition of assets |
| $ | 375,969 |
| $ | — |
| $ | — |
|
|
| 2004 |
| 2003 |
| 2002 |
| |||
|
| (dollars in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Operating Activities |
|
|
|
|
|
|
| |||
Net income |
| $ | 165,002 |
| $ | 133,381 |
| $ | 214,249 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
| |||
Depreciation |
| 221,596 |
| 163,938 |
| 154,524 |
| |||
Cumulative effect of a change in accounting principle, net of tax |
| — |
| 494 |
| — |
| |||
Deferred income taxes and investment tax credits - net |
| 49,085 |
| 38,424 |
| 33,908 |
| |||
Change in net position of energy risk management activities |
| (5,127 | ) | (1,133 | ) | 9,544 |
| |||
Allowance for equity funds used during construction |
| (1,811 | ) | (4,783 | ) | (12,505 | ) | |||
Regulatory asset/liability deferrals |
| (22,333 | ) | (41,282 | ) | (47,423 | ) | |||
Regulatory asset amortization |
| 43,723 |
| 53,107 |
| 71,628 |
| |||
Accrued pension and other postretirement benefit costs |
| 16,656 |
| 9,037 |
| 24,130 |
| |||
Cost of removal |
| (9,887 | ) | (16,598 | ) | — |
| |||
Changes in current assets and current liabilities: |
|
|
|
|
|
|
| |||
Accounts and notes receivable |
| (1,204 | ) | 35,643 |
| 233,040 |
| |||
Fuel, emission allowances, and supplies |
| 39,234 |
| 27,330 |
| (50,463 | ) | |||
Prepayments |
| 297 |
| 686 |
| (2,908 | ) | |||
Accounts payable |
| (24,589 | ) | (104,515 | ) | (119,032 | ) | |||
Accrued taxes and interest |
| (2,631 | ) | (33,004 | ) | 2,961 |
| |||
Other assets |
| (4,906 | ) | (5,721 | ) | (20,830 | ) | |||
Other liabilities |
| 20,358 |
| (8,269 | ) | 8,224 |
| |||
|
|
|
|
|
|
|
| |||
Net cash provided by operating activities |
| 483,463 |
| 246,735 |
| 499,047 |
| |||
|
|
|
|
|
|
|
| |||
Financing Activities |
|
|
|
|
|
|
| |||
Change in short-term debt, including net affiliate notes |
| (57,866 | ) | 15,542 |
| 46,991 |
| |||
Issuance of long-term debt |
| — |
| 431,968 |
| 47,600 |
| |||
Redemption of long-term debt |
| (1,100 | ) | (460,903 | ) | (23,979 | ) | |||
Contribution from parent |
| — |
| 200,000 |
| — |
| |||
Dividends on preferred stock |
| (2,587 | ) | (2,587 | ) | (2,587 | ) | |||
Dividends on common stock |
| (102,588 | ) | (93,950 | ) | (111,842 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) financing activities |
| (164,141 | ) | 90,070 |
| (43,817 | ) | |||
|
|
|
|
|
|
|
| |||
Investing Activities |
|
|
|
|
|
|
| |||
Construction expenditures (less allowance for equity funds used |
|
|
|
|
|
|
| |||
during construction) |
| (337,208 | ) | (330,362 | ) | (451,326 | ) | |||
Withdrawal of restricted funds held in trust |
| 25,273 |
| — |
| — |
| |||
Other investments |
| (3,158 | ) | (1,885 | ) | (3,484 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash used in investing activities |
| (315,093 | ) | (332,247 | ) | (454,810 | ) | |||
|
|
|
|
|
|
|
| |||
Net increase in cash and cash equivalents |
| 4,229 |
| 4,558 |
| 420 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at beginning of period |
| 6,565 |
| 2,007 |
| 1,587 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at end of period |
| $ | 10,794 |
| $ | 6,565 |
| $ | 2,007 |
|
|
|
|
|
|
|
|
| |||
Supplemental Disclosure of Cash Flow Information |
|
|
|
|
|
|
| |||
Cash paid during the year for: |
|
|
|
|
|
|
| |||
Interest (net of amount capitalized) |
| $ | 101,275 |
| $ | 95,733 |
| $ | 89,865 |
|
Income taxes |
| $ | 60,353 |
| $ | 65,564 |
| $ | 27,401 |
|
|
|
|
|
|
|
|
| |||
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
128114
psi energy, inc.PSI ENERGY, INC.
consolidated statements of capitalizationCONSOLIDATED STATEMENTS OF CAPITALIZATION
|
|
| December 31 |
|
| December 31 |
| |||||||||||||||||||||||||||||||
|
|
| 2003 |
| 2002 |
|
| 2004 |
| 2003 |
| |||||||||||||||||||||||||||
|
|
| (dollars in thousands) |
|
| (dollars in thousands) |
| |||||||||||||||||||||||||||||||
Long-term Debt (excludes current portion) | Long-term Debt (excludes current portion) |
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
First Mortgage Bonds: | First Mortgage Bonds: |
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
Series ZZ, 5 3/4 % due February 15, 2028 (Pollution Control) |
| $ | 50,000 |
| $ | 50,000 |
| |||||||||||||||||||||||||||||||
Series ZZ, 5 ¾% due February 15, 2028 (Pollution Control) |
| $ | 50,000 |
| $ | 50,000 |
| |||||||||||||||||||||||||||||||
Series AAA, 7 1/8 % due February 1, 2024 | Series AAA, 7 1/8 % due February 1, 2024 |
| 30,000 |
| 30,000 |
|
| 30,000 |
| 30,000 |
| |||||||||||||||||||||||||||
Series BBB, 8.0 % due July 15, 2009 |
| 124,665 |
| 124,665 |
| |||||||||||||||||||||||||||||||||
Series CCC, 8.85 % due January 15, 2022 |
| 53,055 |
| 53,055 |
| |||||||||||||||||||||||||||||||||
Series DDD, 8.31 % due September 1, 2032 |
| 38,000 |
| 38,000 |
| |||||||||||||||||||||||||||||||||
Series EEE, 6.65 % due June 15, 2006 |
| 325,000 |
| 325,000 |
| |||||||||||||||||||||||||||||||||
Series BBB, 8.0% due July 15, 2009 |
| 124,665 |
| 124,665 |
| |||||||||||||||||||||||||||||||||
Series CCC, 8.85% due January 15, 2022 |
| 53,055 |
| 53,055 |
| |||||||||||||||||||||||||||||||||
Series DDD, 8.31% due September 1, 2032 |
| 38,000 |
| 38,000 |
| |||||||||||||||||||||||||||||||||
Series EEE, 6.65% due June 15, 2006 |
| 325,000 |
| 325,000 |
| |||||||||||||||||||||||||||||||||
Total First Mortgage Bonds | Total First Mortgage Bonds |
| 620,720 |
| 620,720 |
|
| 620,720 |
| 620,720 |
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
Secured Medium-term Notes: | Secured Medium-term Notes: |
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
Series A, 8.55 % to 8.57% as of December 31, 2003; 8.37 % to 8.81 % as of December 31, 2002. Due November 8, 2006 to June 1, 2022 |
| 7,500 |
| 34,300 |
| |||||||||||||||||||||||||||||||||
Series B, 6.37 % to 8.24%, due August 15, 2008 to August 22, 2022 |
| 70,000 |
| 70,000 |
| |||||||||||||||||||||||||||||||||
(Series A and B, 7.255% weighted average interest rate as of December 31, 2003. 7.623% weighted average interest rate as of December 31, 2002. 10.1 and 13.9 year weighted average remaining life at December 31, 2003 and 2002, respectively) |
|
|
|
|
| |||||||||||||||||||||||||||||||||
Series A, 8.55% to 8.57% as of December 31, 2004 and 2003, respectively. Due December 27, 2011. |
| 7,500 |
| 7,500 |
| |||||||||||||||||||||||||||||||||
Series B, 6.37% to 8.24%, due August 15, 2008 to August 22, 2022 |
| 70,000 |
| 70,000 |
| |||||||||||||||||||||||||||||||||
(Series A and B, 7.255% weighted average interest rate as of December 31, 2004 and 2003, respectively. 9.1 and 10.1 year weighted average remaining life at December 31, 2004 and 2003, respectively) |
|
|
|
|
| |||||||||||||||||||||||||||||||||
Total Secured Medium-term Notes | Total Secured Medium-term Notes |
| 77,500 |
| 104,300 |
|
| 77,500 |
| 77,500 |
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
Other Long-term Debt: | Other Long-term Debt: |
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due May 1, 2035 | Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due May 1, 2035 |
| 44,025 |
| 44,025 |
|
| 44,025 |
| 44,025 |
| |||||||||||||||||||||||||||
Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due April 1, 2022 | Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due April 1, 2022 |
| 10,000 |
| 10,000 |
|
| 10,000 |
| 10,000 |
| |||||||||||||||||||||||||||
6.35% Debentures due November 15, 2006 |
| 50 |
| 50 |
| |||||||||||||||||||||||||||||||||
6.50% Synthetic Putable Yield Securities due August 1, 2026 (Interest rate resets August 1, 2005) |
| 50,000 |
| 50,000 |
| |||||||||||||||||||||||||||||||||
7.25% Junior Maturing Principal Securities due March 15, 2028 |
| 2,658 |
| 2,658 |
| |||||||||||||||||||||||||||||||||
6.00% Rural Utilities Service Obligation payable in annual installments |
| 80,988 |
| 82,025 |
| |||||||||||||||||||||||||||||||||
6.52% Senior Notes due March 15, 2009 |
| 97,342 |
| 97,342 |
| |||||||||||||||||||||||||||||||||
7.85% Debentures due October 15, 2007 |
| 265,000 |
| 265,000 |
| |||||||||||||||||||||||||||||||||
5.00% Debentures due September 15, 2013 |
| 400,000 |
| — |
| |||||||||||||||||||||||||||||||||
6.35% Debentures due November 15, 2006 |
| 50 |
| 50 |
| |||||||||||||||||||||||||||||||||
6.50% Synthetic Putable Yield Securities due August 1, 2026 (Interest rate resets August 1, 2005) |
| - |
| 50,000 |
| |||||||||||||||||||||||||||||||||
7.25% Junior Maturing Principal Securities due March 15, 2028 |
| 2,658 |
| 2,658 |
| |||||||||||||||||||||||||||||||||
6.00% Rural Utilities Service Obligation payable in annual installments |
| 79,888 |
| 80,988 |
| |||||||||||||||||||||||||||||||||
6.52% Senior Notes due March 15, 2009 |
| 97,342 |
| 97,342 |
| |||||||||||||||||||||||||||||||||
7.85% Debentures due October 15, 2007 |
| 265,000 |
| 265,000 |
| |||||||||||||||||||||||||||||||||
5.00% Debentures due September 15, 2013 |
| 400,000 |
| 400,000 |
| |||||||||||||||||||||||||||||||||
Series 2002A, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due March 1, 2031 | Series 2002A, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due March 1, 2031 |
| 23,000 |
| 23,000 |
|
| 23,000 |
| 23,000 |
| |||||||||||||||||||||||||||
Series 2002B, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due March 1, 2019 | Series 2002B, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due March 1, 2019 |
| 24,600 |
| 24,600 |
|
| 24,600 |
| 24,600 |
| |||||||||||||||||||||||||||
Series 2003, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due April 1, 2022 | Series 2003, Indiana Development Finance Authority Environmental Refunding Revenue Bonds, due April 1, 2022 |
| 35,000 |
| — |
|
| 35,000 |
| 35,000 |
| |||||||||||||||||||||||||||
Series 2004B, Indiana Development Finance Authority Environmental Revenue Bonds, due December 1, 2039 (Note 4) |
| 77,125 |
| — |
| |||||||||||||||||||||||||||||||||
Series 2004C, Indiana Development Finance Authority Environmental Revenue Bonds, due December 1, 2039 (Note 4) |
| 77,125 |
| — |
| |||||||||||||||||||||||||||||||||
Total Other Long-term Debt | Total Other Long-term Debt |
| 1,032,663 |
| 598,700 |
|
| 1,135,813 |
| 1,032,663 |
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
Unamortized Premium and Discount - Net | Unamortized Premium and Discount - Net |
| (10,407 | ) | (7,736 | ) |
| (9,814 | ) | (10,407 | ) | |||||||||||||||||||||||||||
Total Long-term Debt | Total Long-term Debt |
| 1,720,476 |
| 1,315,984 |
|
| $ | 1,824,219 |
| $ | 1,720,476 |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||
Cumulative Preferred Stock |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Par/Stated |
| Authorized |
| Shares |
| Series |
| Mandatory |
|
|
|
|
| |||||||||||||||||||||||||
$ | 100 |
| 5,000,000 |
| 347,445 |
| 3 1/2% - 6 7/8% |
| No |
| $ | 34,744 |
| $ | 34,754 |
| ||||||||||||||||||||||
$ | 25 |
| 5,000,000 |
| 303,544 |
| 4.16% - 4.32% |
| No |
| 7,589 |
| 7,589 |
| ||||||||||||||||||||||||
Total Preferred Stock |
|
|
|
|
|
|
| 42,333 |
| 42,343 |
| |||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Common Stock Equity |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Common Stock - without par value; $0.01 stated value; authorized shares - 60,000,000; outstanding shares - 53,913,701 at December 31, 2003, and December 31, 2002 |
|
|
|
|
| $ | 539 |
| $ | 539 |
| |||||||||||||||||||||||||||
Paid-in capital |
|
|
|
|
| 627,274 |
| 426,931 |
| |||||||||||||||||||||||||||||
Retained earnings |
|
|
|
|
| 1,018,790 |
| 981,946 |
| |||||||||||||||||||||||||||||
Accumulated other comprehensive income (loss) |
|
|
|
|
| (13,421 | ) | (8,119 | ) | |||||||||||||||||||||||||||||
Total Common Stock Equity |
| 1,633,182 |
| 1,401,297 |
| |||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||
Total Consolidated Capitalization |
| $ | 3,395,991 |
| $ | 2,759,624 |
| |||||||||||||||||||||||||||||||
Cumulative Preferred Stock |
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
| Shares |
|
|
|
|
|
|
|
|
| ||||
Par/Stated |
| Authorized |
| Outstanding at |
|
|
| Mandatory |
|
|
|
|
| ||||
Value |
| Shares |
| December 31, 2004 |
| Series |
| Redemption |
|
|
|
|
| ||||
$ | 100 |
| 5,000,000 |
| 347,445 |
| 3 1/2% - 6 7/8% |
| No |
| $ | 34,744 |
| $ | 34,744 |
| |
$ | 25 |
| 5,000,000 |
| 303,544 |
| 4.16% - 4.32% |
| No |
| 7,589 |
| 7,589 |
| |||
Total Preferred Stock |
|
|
|
|
|
|
| $ | 42,333 |
| $ | 42,333 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Common Stock Equity |
|
|
|
|
|
|
| $ | 1,681,198 |
| $ | 1,633,182 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
| Total Consolidated Capitalization |
| $ | 3,547,750 |
| $ | 3,395,991 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial statements.
129115
the union light, heatand power company
130
the union light, heat and power companyTHE UNION LIGHT, HEAT
statements of incomeAND POWER COMPANY
116
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF INCOME
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (dollars in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Operating Revenues |
|
|
|
|
|
|
| |||
Electric |
| $ | 222,081 |
| $ | 226,856 |
| $ | 230,960 |
|
Gas |
| 110,072 |
| 81,706 |
| 109,333 |
| |||
Total Operating Revenues |
| 332,153 |
| 308,562 |
| 340,293 |
| |||
|
|
|
|
|
|
|
| |||
Operating Expenses |
|
|
|
|
|
|
| |||
Electricity purchased from parent company for resale (Note 1(s)(ii)) |
| 154,572 |
| 159,734 |
| 151,562 |
| |||
Gas purchased |
| 69,774 |
| 46,886 |
| 72,593 |
| |||
Operation and maintenance |
| 53,704 |
| 50,223 |
| 39,501 |
| |||
Depreciation |
| 18,315 |
| 17,350 |
| 17,039 |
| |||
Taxes other than income taxes |
| 4,412 |
| 4,598 |
| 3,901 |
| |||
Total Operating Expenses |
| 300,777 |
| 278,791 |
| 284,596 |
| |||
|
|
|
|
|
|
|
| |||
Operating Income |
| 31,376 |
| 29,771 |
| 55,697 |
| |||
|
|
|
|
|
|
|
| |||
Miscellaneous Income - Net |
| 3,561 |
| 666 |
| 239 |
| |||
Interest Expense |
| 6,127 |
| 5,938 |
| 6,313 |
| |||
|
|
|
|
|
|
|
| |||
Income Before Taxes |
| 28,810 |
| 24,499 |
| 49,623 |
| |||
|
|
|
|
|
|
|
| |||
Income Taxes (Note 10) |
| 9,781 |
| 12,349 |
| 13,699 |
| |||
|
|
|
|
|
|
|
| |||
Net Income |
| $ | 19,029 |
| $ | 12,150 |
| $ | 35,924 |
|
|
| 2004 |
| 2003 |
| 2002 |
| |||||
|
| (dollars in thousands) |
| |||||||||
|
|
|
|
|
|
|
| |||||
Operating Revenues (Note 1(d)) |
|
|
|
|
|
|
| |||||
Electric |
| $ | 230,068 |
| $ | 222,081 |
| $ | 226,856 |
| ||
Gas |
| 124,475 |
| 110,072 |
| 81,706 |
| |||||
Total Operating Revenues |
| 354,543 |
| 332,153 |
| 308,562 |
| |||||
|
|
|
|
|
|
|
| |||||
Operating Expenses |
|
|
|
|
|
|
| |||||
Electricity purchased from parent company for resale (Note 1(s)(ii)) |
| 162,497 |
| 154,572 |
| 159,734 |
| |||||
Gas purchased |
| 79,278 |
| 69,774 |
| 46,886 |
| |||||
Operation and maintenance |
| 55,810 |
| 53,704 |
| 50,223 |
| |||||
Depreciation |
| 20,034 |
| 18,315 |
| 17,350 |
| |||||
Taxes other than income taxes |
| 3,544 |
| 4,412 |
| 4,598 |
| |||||
Total Operating Expenses |
| 321,163 |
| 300,777 |
| 278,791 |
| |||||
|
|
|
|
|
|
|
| |||||
Operating Income |
| 33,380 |
| 31,376 |
| 29,771 |
| |||||
|
|
|
|
|
|
|
| |||||
Miscellaneous Income - Net |
| 813 |
| 3,561 |
| 666 |
| |||||
Interest Expense |
| 5,179 |
| 6,127 |
| 5,938 |
| |||||
|
|
|
|
|
|
|
| |||||
Income Before Taxes |
| 29,014 |
| 28,810 |
| 24,499 |
| |||||
|
|
|
|
|
|
|
| |||||
Income Taxes (Note 10) |
| 10,376 |
| 9,781 |
| 12,349 |
| |||||
|
|
|
|
|
|
|
| |||||
Net Income |
| $ | 18,638 |
| $ | 19,029 |
| $ | 12,150 |
| ||
|
|
|
|
|
|
|
| |||||
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
131117
THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS
ASSETS
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
Current Assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 1,899 |
| $ | 3,926 |
|
Notes receivable from affiliated companies |
| 17,906 |
| 13,337 |
| ||
Accounts receivable less accumulated provision for doubtful accounts of $192 at December 31, 2003, and $84 at December 31, 2002 (Note 3(c)) |
| 2,458 |
| 703 |
| ||
Accounts receivable from affiliated companies |
| 4,407 |
| 1,671 |
| ||
Materials, supplies, and fuel |
| 7,936 |
| 8,182 |
| ||
Prepayments and other |
| 279 |
| 316 |
| ||
Total Current Assets |
| 34,885 |
| 28,135 |
| ||
|
|
|
|
|
| ||
Property, Plant, and Equipment - at Cost |
|
|
|
|
| ||
Utility plant in service |
|
|
|
|
| ||
Electric |
| 273,895 |
| 258,094 |
| ||
Gas |
| 239,670 |
| 215,505 |
| ||
Common |
| 53,297 |
| 50,271 |
| ||
Total Utility Plant In Service |
| 566,862 |
| 523,870 |
| ||
Construction work in progress |
| 6,165 |
| 14,745 |
| ||
Total Utility Plant |
| 573,027 |
| 538,615 |
| ||
Accumulated depreciation |
| 176,368 |
| 165,685 |
| ||
Net Property, Plant, and Equipment (Note 19) |
| 396,659 |
| 372,930 |
| ||
|
|
|
|
|
| ||
Other Assets |
|
|
|
|
| ||
Regulatory assets (Note 1(c)) |
| 13,224 |
| 5,134 |
| ||
Other |
| 3,903 |
| 1,238 |
| ||
Total Other Assets |
| 17,127 |
| 6,372 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 448,671 |
| $ | 407,437 |
|
ASSETS |
|
|
|
|
| ||
|
| December 31 |
| ||||
|
| 2004 |
| 2003 |
| ||
|
| (dollars in thousands) |
| ||||
Current Assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 4,197 |
| $ | 1,899 |
|
Notes receivable from affiliated companies |
| 20,675 |
| 17,906 |
| ||
Accounts receivable less accumulated provision for doubtful accounts of $13 at December 31, 2004, and $192 at December 31, 2003 (Note 3(c)) |
| 1,451 |
| 2,458 |
| ||
Accounts receivable from affiliated companies |
| 5,671 |
| 4,407 |
| ||
Fuel and supplies |
| 8,500 |
| 7,936 |
| ||
Prepayments and other |
| 285 |
| 279 |
| ||
Total Current Assets |
| 40,779 |
| 34,885 |
| ||
|
|
|
|
|
| ||
Property, Plant, and Equipment - at Cost |
|
|
|
|
| ||
Utility plant in service |
|
|
|
|
| ||
Electric |
| 285,828 |
| 273,895 |
| ||
Gas |
| 256,667 |
| 239,670 |
| ||
Common |
| 42,176 |
| 53,297 |
| ||
Total Utility Plant In Service |
| 584,671 |
| 566,862 |
| ||
Construction work in progress |
| 6,070 |
| 6,165 |
| ||
Total Utility Plant |
| 590,741 |
| 573,027 |
| ||
Accumulated depreciation (Note 1(h)(i)) |
| 176,726 |
| 176,368 |
| ||
Net Property, Plant, and Equipment (Note 19) |
| 414,015 |
| 396,659 |
| ||
|
|
|
|
|
| ||
Other Assets |
|
|
|
|
| ||
Regulatory assets (Note 1(c)) |
| 10,070 |
| 16,150 |
| ||
Other |
| 2,801 |
| 977 |
| ||
Total Other Assets |
| 12,871 |
| 17,127 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 467,665 |
| $ | 448,671 |
|
|
|
|
|
|
| ||
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
132118
THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
Current Liabilities |
|
|
|
|
| ||
Accounts payable |
| $ | 13,431 |
| $ | 8,816 |
|
Accounts payable to affiliated companies |
| 21,131 |
| 22,297 |
| ||
Accrued taxes |
| 298 |
| 1,487 |
| ||
Accrued interest |
| 1,230 |
| 1,226 |
| ||
Long-term debt due within one year |
| — |
| 20,000 |
| ||
Notes payable to affiliated companies (Note 6) |
| 45,233 |
| 14,076 |
| ||
Other |
| 6,815 |
| 6,368 |
| ||
Total Current Liabilities |
| 88,138 |
| 74,270 |
| ||
|
|
|
|
|
| ||
Non-Current Liabilities |
|
|
|
|
| ||
Long-term debt (Note 4) |
| 54,685 |
| 54,653 |
| ||
Deferred income taxes (Note 10) |
| 55,488 |
| 43,360 |
| ||
Unamortized investment tax credits |
| 2,879 |
| 3,143 |
| ||
Accrued pension and other postretirement benefit costs (Note 9) |
| 16,953 |
| 15,620 |
| ||
Accrued cost of removal (Note 1(c)) |
| 27,443 |
| 25,210 |
| ||
Other |
| 13,729 |
| 14,017 |
| ||
Total Non-Current Liabilities |
| 171,177 |
| 156,003 |
| ||
|
|
|
|
|
| ||
Commitments and Contingencies (Note 11) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Total Liabilities |
| 259,315 |
| 230,273 |
| ||
|
|
|
|
|
| ||
Common Stock Equity (Note 2) |
|
|
|
|
| ||
Common Stock - $15.00 par value; authorized shares - 1,000,000; outstanding shares - 585,333 at December 31, 2003 and December 31, 2002 |
| 8,780 |
| 8,780 |
| ||
Paid-in capital |
| 23,541 |
| 23,644 |
| ||
Retained earnings |
| 157,524 |
| 144,800 |
| ||
Accumulated other comprehensive income (loss) |
| (489 | ) | (60 | ) | ||
Total Common Stock Equity |
| 189,356 |
| 177,164 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Shareholder’s Equity |
| $ | 448,671 |
| $ | 407,437 |
|
LIABILITIES AND SHAREHOLDER’S EQUITY |
|
|
|
|
| ||
|
| December 31 |
| ||||
|
| 2004 |
| 2003 |
| ||
|
| (dollars in thousands) |
| ||||
Current Liabilities |
|
|
|
|
| ||
Accounts payable |
| $ | 16,028 |
| $ | 13,431 |
|
Accounts payable to affiliated companies |
| 22,236 |
| 21,131 |
| ||
Accrued interest |
| 1,370 |
| 1,230 |
| ||
Notes payable to affiliated companies (Note 5) |
| 11,246 |
| 45,233 |
| ||
Other |
| 7,009 |
| 7,113 |
| ||
Total Current Liabilities |
| 57,889 |
| 88,138 |
| ||
|
|
|
|
|
| ||
Non-Current Liabilities |
|
|
|
|
| ||
Long-term debt (Note 4) |
| 94,340 |
| 54,685 |
| ||
Deferred income taxes (Note 10) |
| 58,422 |
| 55,488 |
| ||
Unamortized investment tax credits |
| 2,626 |
| 2,879 |
| ||
Accrued pension and other postretirement benefit costs (Note 9) |
| 17,762 |
| 16,953 |
| ||
Regulatory liabilities (Note 1(c)) |
| 29,979 |
| 27,443 |
| ||
Other |
| 14,136 |
| 13,729 |
| ||
Total Non-Current Liabilities |
| 217,265 |
| 171,177 |
| ||
|
|
|
|
|
| ||
Commitments and Contingencies (Note 11) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Total Liabilities |
| 275,154 |
| 259,315 |
| ||
|
|
|
|
|
| ||
Common Stock Equity (Note 2) |
|
|
|
|
| ||
Common stock - $15.00 par value; authorized shares - 1,000,000; outstanding shares—585,333 at December 31, 2004 and December 31, 2003 |
| 8,780 |
| 8,780 |
| ||
Paid-in capital |
| 23,455 |
| 23,541 |
| ||
Retained earnings |
| 161,562 |
| 157,524 |
| ||
Accumulated other comprehensive loss |
| (1,286 | ) | (489 | ) | ||
Total Common Stock Equity |
| 192,511 |
| 189,356 |
| ||
|
|
|
|
|
| ||
Total Liabilities and Shareholder’s Equity |
| $ | 467,665 |
| $ | 448,671 |
|
|
|
|
|
|
| ||
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
133119
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
|
| Common |
| Paid-in |
| Retained |
| Accumulated |
| Total |
| |||||
|
| (dollars in thousands) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2001 |
|
|
|
|
|
|
|
|
|
|
| |||||
Beginning balance |
| $ | 8,780 |
| $ | 20,305 |
| $ | 118,103 |
| $ | — |
| $ | 147,188 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 35,924 |
|
|
| 35,924 |
| |||||
Other comprehensive income (loss), net of tax effect of $5 |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (8 | ) | (8 | ) | |||||
Total comprehensive income (loss) |
|
|
|
|
|
|
|
|
| 35,916 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on common stock |
|
|
|
|
| (11,707 | ) |
|
| (11,707 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| 806 |
|
|
|
|
| 806 |
| |||||
Ending balance |
| $ | 8,780 |
| $ | 21,111 |
| $ | 142,320 |
| $ | (8 | ) | $ | 172,203 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2002 |
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 12,150 |
|
|
| 12,150 |
| |||||
Other comprehensive income (loss), net of tax effect of $36 |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (52 | ) | (52 | ) | |||||
Total comprehensive income (loss) |
|
|
|
|
|
|
|
|
| 12,098 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on common stock |
|
|
|
|
| (9,670 | ) |
|
| (9,670 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| 2,533 |
|
|
|
|
| 2,533 |
| |||||
Ending balance |
| $ | 8,780 |
| $ | 23,644 |
| $ | 144,800 |
| $ | (60 | ) | $ | 177,164 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2003 |
|
|
|
|
|
|
|
|
|
|
| |||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| |||||
Net income |
|
|
|
|
| 19,029 |
|
|
| 19,029 |
| |||||
Other comprehensive income (loss), net of tax effect of $291 |
|
|
|
|
|
|
|
|
|
|
| |||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (429 | ) | (429 | ) | |||||
Total comprehensive income (loss) |
|
|
|
|
|
|
|
|
| 18,600 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Dividends on common stock |
|
|
|
|
| (6,305 | ) |
|
| (6,305 | ) | |||||
Contribution from parent company for reallocation of taxes |
|
|
| (103 | ) |
|
|
|
| (103 | ) | |||||
Ending balance |
| $ | 8,780 |
| $ | 23,541 |
| $ | 157,524 |
| $ | (489 | ) | $ | 189,356 |
|
|
| Common Stock |
| Paid-in Capital |
| Retained Earnings |
| Accumulated Other Comprehensive Loss |
| Total Common Stock Equity |
| ||||||
|
| (dollars in thousands) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2002 |
|
|
|
|
|
|
|
|
|
|
| ||||||
Beginning balance |
| $ | 8,780 |
| $ | 21,111 |
| $ | 142,320 |
| $ | (8 | ) | $ | 172,203 |
| |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 12,150 |
|
|
| 12,150 |
| ||||||
Other comprehensive loss, net of tax effect of $36 |
|
|
|
|
|
|
|
|
|
|
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (52 | ) | (52 | ) | ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 12,098 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Dividends on common stock |
|
|
|
|
| (9,670 | ) |
|
| (9,670 | ) | ||||||
Contribution from parent company for reallocation of taxes |
|
|
| 2,533 |
|
|
|
|
| 2,533 |
| ||||||
Ending balance |
| $ | 8,780 |
| $ | 23,644 |
| $ | 144,800 |
| $ | (60 | ) | $ | 177,164 |
| |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2003 |
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 19,029 |
|
|
| 19,029 |
| ||||||
Other comprehensive loss, net of tax effect of $291 |
|
|
|
|
|
|
|
|
|
|
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (429 | ) | (429 | ) | ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 18,600 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Dividends on common stock |
|
|
|
|
| (6,305 | ) |
|
| (6,305 | ) | ||||||
Contribution from parent company for reallocation of taxes |
|
|
| (103 | ) |
|
|
|
| (103 | ) | ||||||
Ending balance |
| $ | 8,780 |
| $ | 23,541 |
| $ | 157,524 |
| $ | (489 | ) | $ | 189,356 |
| |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
2004 |
|
|
|
|
|
|
|
|
|
|
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
| ||||||
Net income |
|
|
|
|
| 18,638 |
|
|
| 18,638 |
| ||||||
Other comprehensive loss, net of tax effect of $539 |
|
|
|
|
|
|
|
|
|
|
| ||||||
Minimum pension liability adjustment |
|
|
|
|
|
|
| (797) |
| (797 | ) | ||||||
Total comprehensive income |
|
|
|
|
|
|
|
|
| 17,841 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Dividends on common stock |
|
|
|
|
| (14,600 | ) |
|
| (14,600 | ) | ||||||
Other |
|
|
| (86 | ) |
|
|
|
| (86 | ) | ||||||
Ending balance |
| $ | 8,780 |
| $ | 23,455 |
| $ | 161,562 |
| $ | (1,286 | ) | $ | 192,511 |
| |
|
|
|
|
|
|
|
|
|
|
|
| ||||||
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
134120
THE UNION LIGHT, HEAT AND POWER COMPANY
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (dollars in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Operating Activities |
|
|
|
|
|
|
| |||
Net income |
| $ | 19,029 |
| $ | 12,150 |
| $ | 35,924 |
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |
|
|
|
|
|
|
| |||
Depreciation |
| 18,315 |
| 17,350 |
| 17,039 |
| |||
Deferred income taxes and investment tax credits - net |
| 7,808 |
| 3,116 |
| (7,116 | ) | |||
Allowance for equity funds used during construction |
| (183 | ) | (794 | ) | (143 | ) | |||
Regulatory assets deferrals |
| (1,300 | ) | 3,954 |
| 1,098 |
| |||
Regulatory assets amortization |
| 1,843 |
| (1,452 | ) | 1,038 |
| |||
Accrued pension and other postretirement benefit costs |
| 1,333 |
| 2,343 |
| 154 |
| |||
Deferred costs under gas cost recovery mechanism |
| (6,838 | ) | 3,833 |
| 9,469 |
| |||
Changes in current assets and current liabilities: |
|
|
|
|
|
|
| |||
Accounts and notes receivable |
| (9,060 | ) | 8,997 |
| 12,112 |
| |||
Materials, supplies, and fuel |
| 246 |
| 2,653 |
| (4,535 | ) | |||
Prepayments |
| 37 |
| (16 | ) | (26 | ) | |||
Accounts payable |
| 3,449 |
| 6,997 |
| (20,325 | ) | |||
Accrued taxes and interest |
| (1,185 | ) | (4,981 | ) | 12,239 |
| |||
Other assets |
| (3,521 | ) | 2,852 |
| (1,838 | ) | |||
Other liabilities |
| 3,088 |
| 3,705 |
| (7,324 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) operating activities |
| 33,061 |
| 60,707 |
| 47,766 |
| |||
|
|
|
|
|
|
|
| |||
Financing Activities |
|
|
|
|
|
|
| |||
Change in short-term debt, including net affiliate notes |
| 31,157 |
| (12,356 | ) | (2,971 | ) | |||
Redemption of long-term debt |
| (20,000 | ) | — |
| — |
| |||
Dividends on common stock |
| (6,305 | ) | (9,670 | ) | (11,707 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) financing activities |
| 4,852 |
| (22,026 | ) | (14,678 | ) | |||
|
|
|
|
|
|
|
| |||
Investing Activities |
|
|
|
|
|
|
| |||
Construction expenditures (less allowance for equity funds used during construction) |
| (39,940 | ) | (38,854 | ) | (35,449 | ) | |||
|
|
|
|
|
|
|
| |||
Net cash provided by (used in) investing activities |
| (39,940 | ) | (38,854 | ) | (35,449 | ) | |||
|
|
|
|
|
|
|
| |||
Net increase (decrease) in cash and cash equivalents |
| (2,027 | ) | (173 | ) | (2,361 | ) | |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at beginning of period |
| 3,926 |
| 4,099 |
| 6,460 |
| |||
|
|
|
|
|
|
|
| |||
Cash and cash equivalents at end of period |
| $ | 1,899 |
| $ | 3,926 |
| $ | 4,099 |
|
|
|
|
|
|
|
|
| |||
Supplemental Disclosure of Cash Flow Information |
|
|
|
|
|
|
| |||
Cash paid during the year for: |
|
|
|
|
|
|
| |||
Interest (net of amount capitalized) |
| $ | 5,842 |
| $ | 5,067 |
| $ | 6,594 |
|
Income taxes |
| $ | 3,001 |
| $ | 2,398 |
| $ | 10,848 |
|
|
| 2004 |
| 2003 |
| 2002 |
| ||||
|
| (dollars in thousands) |
| ||||||||
|
|
|
|
|
|
|
| ||||
Operating Activities |
|
|
|
|
|
|
| ||||
Net income |
| $ | 18,638 |
| $ | 19,029 |
| $ | 12,150 |
| |
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
| ||||
Depreciation |
| 20,034 |
| 18,315 |
| 17,350 |
| ||||
Deferred income taxes and investment tax credits - net |
| 7,601 |
| 7,808 |
| 3,116 |
| ||||
Allowance for equity funds used during construction |
| 18 |
| (183 | ) | (794 | ) | ||||
Regulatory asset/liability deferrals |
| (2,337 | ) | (8,138 | ) | 7,787 |
| ||||
Regulatory asset amortization |
| 1,613 |
| 1,843 |
| (1,452 | ) | ||||
Accrued pension and other postretirement benefit costs |
| 809 |
| 1,333 |
| 2,343 |
| ||||
Cost of removal |
| (1,588 | ) | — |
| — |
| ||||
Changes in current assets and current liabilities: |
|
|
|
|
|
|
| ||||
Accounts and notes receivable |
| (3,026 | ) | (9,060 | ) | 8,997 |
| ||||
Fuel and supplies |
| (564 | ) | 246 |
| 2,653 |
| ||||
Prepayments |
| (6 | ) | 37 |
| (16 | ) | ||||
Accounts payable |
| 3,702 |
| 3,449 |
| 6,997 |
| ||||
Accrued taxes and interest |
| (729 | ) | (1,185 | ) | (4,981 | ) | ||||
Other assets |
| 1,815 |
| (3,521 | ) | 2,852 |
| ||||
Other liabilities |
| (599 | ) | 3,088 |
| 3,705 |
| ||||
|
|
|
|
|
|
|
| ||||
Net cash provided by operating activities |
| 45,381 |
| 33,061 |
| 60,707 |
| ||||
|
|
|
|
|
|
|
| ||||
Financing Activities |
|
|
|
|
|
|
| ||||
Change in short-term debt, including net affiliate notes |
| (33,987 | ) | 31,157 |
| (12,356 | ) | ||||
Issuance of long-term debt |
| 39,361 |
| — |
| — |
| ||||
Redemption of long-term debt |
| — |
| (20,000 | ) | — |
| ||||
Dividends on common stock |
| (14,600 | ) | (6,305 | ) | (9,670 | ) | ||||
|
|
|
|
|
|
|
| ||||
Net cash provided by (used in) financing activities |
| (9,226 | ) | 4,852 |
| (22,026 | ) | ||||
|
|
|
|
|
|
|
| ||||
Investing Activities |
|
|
|
|
|
|
| ||||
Construction expenditures (less allowance for equity funds used during construction) |
| (33,857 | ) | (39,940 | ) | (38,854 | ) | ||||
|
|
|
|
|
|
|
| ||||
Net cash used in investing activities |
| (33,857 | ) | (39,940 | ) | (38,854 | ) | ||||
|
|
|
|
|
|
|
| ||||
Net increase (decrease) in cash and cash equivalents |
| 2,298 |
| (2,027 | ) | (173 | ) | ||||
|
|
|
|
|
|
|
| ||||
Cash and cash equivalents at beginning of period |
| 1,899 |
| 3,926 |
| 4,099 |
| ||||
|
|
|
|
|
|
|
| ||||
Cash and cash equivalents at end of period |
| $ | 4,197 |
| $ | 1,899 |
| $ | 3,926 |
| |
|
|
|
|
|
|
|
| ||||
Supplemental Disclosure of Cash Flow Information |
|
|
|
|
|
|
| ||||
Cash paid during the year for: |
|
|
|
|
|
|
| ||||
Interest (net of amount capitalized) |
| $ | 4,796 |
| $ | 5,842 |
| $ | 5,067 |
| |
Income taxes |
| $ | 2,827 |
| $ | 3,001 |
| $ | 2,398 |
| |
|
|
|
|
|
|
|
| ||||
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.
135121
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CAPITALIZATION
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (dollars in thousands) |
| ||||
|
|
|
|
|
| ||
Long-term Debt (excludes current portion) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Other Long-term Debt: |
|
|
|
|
| ||
6.50% Debentures due April 30, 2008 |
| $ | 20,000 |
| $ | 20,000 |
|
7.65% Debentures due July 15, 2025 |
| 15,000 |
| 15,000 |
| ||
7.875% Debentures due September 15, 2009 |
| 20,000 |
| 20,000 |
| ||
Total Other Long-term Debt |
| 55,000 |
| 55,000 |
| ||
|
|
|
|
|
| ||
Unamortized Premium and Discount - Net |
| (315 | ) | (347 | ) | ||
Total Long-term Debt |
| 54,685 |
| 54,653 |
| ||
|
|
|
|
|
| ||
Common Stock Equity |
|
|
|
|
| ||
Common Stock - $15.00 par value; authorized shares - 1,000,000; outstanding shares - 585,333 at December 31, 2003, and December 31, 2002 |
| $ | 8,780 |
| $ | 8,780 |
|
Paid-in capital |
| 23,541 |
| 23,644 |
| ||
Retained earnings |
| 157,524 |
| 144,800 |
| ||
Accumulated other comprehensive income (loss) |
| (489 | ) | (60 | ) | ||
Total Common Stock Equity |
| 189,356 |
| 177,164 |
| ||
|
|
|
|
|
| ||
Total Capitalization |
| $ | 244,041 |
| $ | 231,817 |
|
|
| December 31 |
| ||||||
|
| 2004 |
| 2003 |
| ||||
|
| (dollars in thousands) |
| ||||||
|
|
|
|
|
| ||||
Long-term Debt (excludes current portion) |
|
|
|
|
| ||||
|
|
|
|
|
| ||||
Other Long-term Debt: |
|
|
|
|
| ||||
6.50% Debentures due April 30, 2008 |
| $ | 20,000 |
| $ | 20,000 |
| ||
7.65% Debentures due July 15, 2025 |
| 15,000 |
| 15,000 |
| ||||
7.875% Debentures due September 15, 2009 |
| 20,000 |
| 20,000 |
| ||||
5.00% Debentures due December 15, 2014 (Note 4) |
| 40,000 |
| — |
| ||||
Total Other Long-term Debt |
| 95,000 |
| 55,000 |
| ||||
|
|
|
|
|
| ||||
Unamortized Premium and Discount - Net |
| (660 | ) | (315 | ) | ||||
Total Long-term Debt |
| $ | 94,340 |
| $ | 54,685 |
| ||
|
|
|
|
|
| ||||
Common Stock Equity |
| $ | 192,511 |
| $ | 189,356 |
| ||
|
|
|
|
|
| ||||
Total Capitalization |
| $ | 286,851 |
| $ | 244,041 |
| ||
|
|
|
|
|
| ||||
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these financial statements.statements
136122
Notes To Financial StatementsNOTES 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), PSIEnergy, 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. Summary of Significant Accounting Policies
(a)Nature of Operations
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 a result of this ownership, we are considered a utility holding company. Because we are a holding company with material utility subsidiaries operating in multiple states, we are registered with and are subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Our other principal subsidiaries are:
•are CinergyServices, Inc. (Services);
• and CinergyInvestments, Inc. (Investments); and
•. Cinergy Wholesale Energy, Inc. (Wholesale Energy).
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 its subsidiaries,ULH&P, in nearby areas of Kentucky and Indiana.Kentucky. CG&E is responsible for the majority of our power marketing and trading activity. CG&E’s principal subsidiary, The Union Light, Heat and Power Company (ULH&P), is a Kentucky corporation organized in 1901, that provides electric and gas service in northern Kentucky.CG&E’s other subsidiaries are insignificant to its results of operations.
In 2001, CG&E began a transition to electric deregulation and customer choice. Currently, the competitive retail electric market in Ohio is in the development stage. CG&E is recovering its Public Utilities Commission of Ohio (PUCO) approved costs and retail electric rates are frozen during this market development period. In January 2003, CG&E filed an application with the PUCO for approval of a methodology to establish how market-based rates for non-residential customers will be determined when the market development period ends. In December 2003, the PUCO requested that CG&E propose a rate stabilization plan. In January 2004, CG&E complied with the PUCO request and filed an electric reliability and rate stabilization plan. See Note 17 for a discussion of key elements of Ohio deregulation.
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.
137
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):
138
Principal Line(s) of Business | ||
CG&E and |
| •Generation, transmission, distribution, and sale of electricity •Sale and/or transportation of natural gas •Electric commodity marketing and trading operations |
|
|
|
PSI |
| •Generation, transmission, distribution, and sale of electricity |
|
|
|
ULH&P(1) |
| •Transmission, distribution, and sale of electricity •Sale and transportation of natural gas |
(1) |
| ||
Services is a service company that provides our subsidiaries with a variety of centralized administrative, management, and support services. Investments holds most of our domestic non-regulated, energy-related businesses and investments, including natural gas marketing and trading operations.operations (which are primarily conducted through CinergyMarketing & Trading, LP (Marketing & Trading), one of its subsidiaries).
Wholesale Energy, through a wholly-owned subsidiary, Cinergy Power Generation Services, LLC (Generation Services), provides electric production-related construction, operation, and maintenance services to certain affiliates and non-affiliated third parties.123
We conduct operations through our subsidiaries and manage our businesses through the following three reportable segments:
• Commercial Business Unit (Commercial), formerly named the Energy Merchant Business Unit;;
• Regulated Businesses Business Unit (Regulated Businesses)(Regulated); and
• Power Technology and Infrastructure Services Business Unit (Power Technology)Technology and Infrastructure).
ForSee Note 16 for further discussion of our reportable segments see Note 15.segments.
(b) Presentation
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.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.
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.
139
(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 3), 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 (losses) 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 investmentsin our Balance Sheets.
124
(c) Regulation
Our utility operating companies and certain of our non-utility subsidiaries must comply with the rules prescribed by the SEC under the PUHCA. Our utility operating companies must also comply with the rules prescribed by the Federal Energy Regulatory Commission (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 No. 71, Accounting for the Effects of Certain Types of Regulation (Statement(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.
140
ComprehensiveThe state of Ohio passed comprehensive electric deregulation legislation was passed in Ohio1999, and in July 1999. As required by the legislation, CG&E filed its Proposed Transition Plan for approval by the PUCO in December 1999. In August 2000, the PUCOPublic Utilities Commission of Ohio (PUCO) approved a stipulation agreement relating to CG&E’stransition plan. This plan createdcreating a Regulatory Transition Charge (RTC) designed to recover CG&E’s generation-related regulatory assets and transition costs over a ten-year period which beganbeginning January 1, 2001. Accordingly, application of Statement 71 was discontinued for the generation portion of CG&E’s business and Statement of Financial Accounting Standards No. 101, Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71, was applied. The effect of this change on the financial statements was immaterial. Except with respect to theExcluding CG&E’s deregulated generation-related assets and liabilities, as of December 31, 2004, CG&E, as of December 31, 2003, PSI, CG&E, and ULH&P continue to meet the criteria of Statement 71. However, to the extent other states implementIndiana or Kentucky implements deregulation legislation, the application of Statement 71 will 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, 2003,2004, is probable. For a further discussion of Ohio deregulationCG&E’s regulatory developments see Note 17.11(b)(iii). For a further discussion onof PSI’s pending retail rate caseregulatory developments see NoteNotes 11(b)((i)i) and 11(b)(ii).
141125
Our regulatory assets, liabilities, and amounts authorized for recovery through regulatory orders at December 31, 2004, and 2003, and 2002, arewere as follows:
|
| 2003 |
| 2002 |
| ||||||||||||||
|
| CG&E(1) |
| PSI |
| Cinergy |
| CG&E(1) |
| PSI |
| Cinergy |
| ||||||
|
| (in millions) |
| ||||||||||||||||
Regulatory assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts due from customers - income taxes(2) |
| $ | 53 |
| $ | 22 |
| $ | 75 |
| $ | 53 |
| $ | 25 |
| $ | 78 |
|
Gasification services agreement buyout costs(3) (6) |
| — |
| 235 |
| 235 |
| — |
| 240 |
| 240 |
| ||||||
Post-in-service carrying costs and deferred operating expenses(6)(7) |
| 2 |
| 70 |
| 72 |
| 1 |
| 42 |
| 43 |
| ||||||
Coal contract buyout costs |
| — |
| — |
| — |
| — |
| 10 |
| 10 |
| ||||||
Deferred merger costs |
| 1 |
| 46 |
| 47 |
| 1 |
| 51 |
| 52 |
| ||||||
Unamortized costs of reacquiring debt |
| 17 |
| 28 |
| 45 |
| 9 |
| 30 |
| 39 |
| ||||||
Coal gasification services expenses(6) |
| — |
| 1 |
| 1 |
| — |
| 4 |
| 4 |
| ||||||
RTC recoverable assets(4) (6) |
| 517 |
| — |
| 517 |
| 537 |
| — |
| 537 |
| ||||||
Other |
| 5 |
| 15 |
| 20 |
| 4 |
| 16 |
| 20 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total Regulatory assets |
| $ | 595 |
| $ | 417 |
| $ | 1,012 |
| $ | 605 |
| $ | 418 |
| $ | 1,023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total Regulatory assets authorized for recovery(5) |
| $ | 587 |
| $ | 317 |
| $ | 905 |
| $ | 598 |
| $ | 360 |
| $ | 958 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued cost of removal(8) |
| $ | (155 | ) | $ | (336 | ) | $ | (491 | ) | $ | — |
| $ | — |
| $ | — |
|
|
| 2004 |
| 2003 |
| ||||||||||||||
|
| CG&E(1) |
| PSI |
| Cinergy |
| CG&E(1) |
| PSI |
| Cinergy |
| ||||||
|
| (in millions) |
| ||||||||||||||||
Regulatory assets |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Amounts due from customers - income taxes(2) |
| $ | 74 |
| $ | 22 |
| $ | 96 |
| $ | 53 |
| $ | 22 |
| $ | 75 |
|
Gasification services agreement buyout costs(3)(4) |
| — |
| 227 |
| 227 |
| — |
| 235 |
| 235 |
| ||||||
Post-in-service carrying costs and deferred operating expenses(4)(9) |
| 3 |
| 80 |
| 83 |
| 2 |
| 70 |
| 72 |
| ||||||
Deferred merger costs |
| — |
| 38 |
| 38 |
| 1 |
| 46 |
| 47 |
| ||||||
Unamortized costs of reacquiring debt |
| 15 |
| 25 |
| 40 |
| 17 |
| 28 |
| 45 |
| ||||||
RTC recoverable assets(4) (5) |
| 494 |
| — |
| 494 |
| 517 |
| — |
| 517 |
| ||||||
Capital-related distribution costs(6) |
| 11 |
| — |
| 11 |
| — |
| — |
| — |
| ||||||
Other |
| 12 |
| 29 |
| 41 |
| 22 |
| 16 |
| 38 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total Regulatory assets |
| $ | 609 |
| $ | 421 |
| $ | 1,030 |
| $ | 612 |
| $ | 417 |
| $ | 1,029 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total Regulatory assets authorized for recovery(7) |
| $ | 602 |
| $ | 378 |
| $ | 980 |
| $ | 604 |
| $ | 317 |
| $ | 921 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Regulatory liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Accrued cost of removal(8) |
| $ | (164 | ) | $ | (367 | ) | $ | (531 | ) | $ | (155 | ) | $ | (336 | ) | $ | (491 | ) |
Deferred fuel costs |
| (1 | ) | (25 | ) | (26 | ) | — |
| — |
| — |
| ||||||
Total Regulatory liabilities |
| $ | (165 | ) | $ | (392 | ) | $ | (557 | ) | $ | (155 | ) | $ | (336 | ) | $ | (491 | ) |
(1) | Includes | |
(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 | |
(4) | Regulatory assets earning a return at December 31, 2004. | |
(5) | 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. | |
| In November 2004, CG&E’s rate stabilization plan (RSP) was approved by the PUCO. CG&E will have 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. | |
(7) | At December 31, | |
|
| |
|
| |
(8) | Represents amounts received for anticipated future removal and retirement costs of regulated property, plant, and | |
(9) | For PSI, this amount includes $38 million that is not yet authorized for recovery and is not earning a return at December 31, 2004. |
(d) Revenue Recognition
(i) Utility Revenues
Our utility operating companiesCG&E, PSI, and ULH&Precord 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
142
recognized and accepted practice for utilities. In making our estimates of unbilled revenues, we use complex 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 revenue isthese amounts are subsequently billed.
126
The amount of unbilled revenues for Cinergy, CG&E, PSI, and ULH&P as of December 31, 2004, 2003, 2002, and 20012002 were as follows:
|
| 2003 |
| 2002 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
| ||||||
|
| (in millions) |
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Cinergy |
| $ | 176 |
| $ | 153 |
| $ | 172 |
|
| $ | 203 |
| $ | 176 |
| $ | 153 |
|
CG&E and subsidiaries |
| 112 |
| 89 |
| 104 |
|
| 129 |
| 112 |
| 89 |
| ||||||
PSI |
| 64 |
| 64 |
| 68 |
|
| 74 |
| 64 |
| 64 |
| ||||||
ULH&P |
| 20 |
| 15 |
| 18 |
|
| 23 |
| 20 |
| 15 |
| ||||||
|
|
|
|
|
|
| ||||||||||||||
(ii) Energy Marketing and Trading Revenues
We market and trade electricity, natural gas, coal, and other energy-related products. Many of the contracts associated with these products qualify as derivatives in accordance with Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133), further discussed in (k)((i)i below.). 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). Generally, tradingTrading contracts are reported on a net basis and non-trading contracts are reported on a gross basis.
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 and exchanged 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 public utility operating companies’ franchise service territory)territories), or (b) the contracts involve the sale of gas or electricity and we have the intent and projected ability to fulfill substantially all 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.
Energy activities that do not principally involve derivatives (e.g., natural gas sales(iii) Other Operating Revenues
Cinergy and CG&E recognize revenue from storage)coal origination, which represents contract structuring and marketing of physical coal. These revenues are presented on a gross basis.
143
2. Net Reporting
Net reporting requires presentation of realized and unrealized gains and losses on trading derivatives on a net basisincluded in Other Operating Revenues. Prior to 2003, on the realized resultsStatements of Income. Other Operating Revenues for trading contracts that were physical in nature were presented on a gross basis. In 2003, we began reflecting the resultsCinergy also includes sales of trading derivatives on a net basis pursuant to the requirements of EITF 02-3, regardless of whether the transactions were settled physically. The presentation for 2002 and 2001 has been reclassified to conform to the new presentation. See (q)(i)synthetic fuel. below for further discussion.
Energy derivatives involving frequent buying and selling with the objective of generating profits from differences in price are classified as trading and reported net.
(e) Energy Purchases and Fuel Costs
The expenses associated with electric and gas services include:
• fuel used to generate electricity;electricity and the associated transportation costs;
• costs of emission allowances;
• electricity purchased from others; and
• natural gas purchased from others;others and the associated transportation costs.
• transportation costs associated with the purchase of fuel and natural gas.
127
These expenses are shown in the Statements of Income of Cinergy, CG&E, and PSI as Fuel, emission allowances, and purchased and exchanged power expense and Gas purchasedexpense. These expenses are shown in ULH&P’s Statements of Income as Electricity purchased from parent company for resaleexpense 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. Due to deregulationThe fuel adjustment clause is calculated based on the estimated cost of fuel in the state of Ohio, we no longer have direct recovery ofnext 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 deferred asset or liability until it is billed or refunded to its customers, at which point it is adjusted through fuel costs.expense.
In addition to the fuel adjustment clause, PSI utilizes a purchased power tracking mechanism (Tracker) 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 will be effective January 1, 2006 for residential customers. CG&E will begin 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 will be effective January 1, 2006 for residential customers. See Note 11(b)(viii) for additional information.
(f(f)) 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.
(g) InventoryFuel, Emission Allowances, and Supplies
We maintain coal inventories for use in the production of electricity and emission allowances inventories for regulatory compliance purposes due to the production of electricity. These inventories are accounted for at the lower of cost or market, with cost being determined using the weighted-average method.
Prior to January 1, 2003, natural gas inventoryheld in storage for our gas trading operations was accounted for at fair value. All other inventorygas held in storage was accounted for at the lower of cost or market, cost being determined through the weighted averageweighted-average method. Effective January 1, 2003, accounting for our gas trading operations’ gas inventoryheld in storage was adjusted to the lower of cost or market method with a cumulative effect adjustment, as required by EITF 02-3. See (q)(viiv) below for a summary of the cumulative effect adjustments.
144Materials and supplies inventory is accounted for on a weighted-average cost basis.
(h) 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 below in (ii) and (iii)); and
• other miscellaneous amounts.
128
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 accounted for when incurred. When regulated property, plant, and equipment is retired, Cinergy charges the original cost, less salvage, to Accumulated depreciationand the cost of removal to Accrued cost of removalRegulatory liabilities, which is consistent with the composite method of depreciation. See (j) 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 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. See (q)(iii) below for additional discussion of this change. 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, excluding software, are presented in the table below.following table.
|
| 2003 |
| 2002 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy(1) |
| 2.8 | % | 3.0 | % | 3.0 | % |
| 3.2 | % | 2.8 | % | 3.0 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CG&E and subsidiaries |
| 2.6 |
| 2.9 |
| 2.9 |
|
| 2.6 |
| 2.6 |
| 2.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PSI |
| 3.1 |
| 3.0 |
| 3.0 |
|
| 3.7 |
| 3.1 |
| 3.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ULH&P |
| 3.2 |
| 3.2 |
| 3.3 |
|
| 3.5 |
| 3.2 |
| 3.2 |
|
(1) |
|
During the third quarter of 2003,In June 2004, CG&EPSI implemented a new depreciation studyrates, as a result of its non-regulated
145
generating assets resultingchanges in an increase in the estimated useful lives of certain assets.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 onwas an increase of approximately $18 million in Cinergy’s and CG&E’sPSI’s 2003 net income and Earnings Per Common Share (EPS) - assuming dilution was an increase of $9 million (net of tax) or $0.05 per share, respectively.2004 Depreciation expense. The prospective impact of this change in accounting estimate on annual net income is expected to be $18an increase of approximately $30 million (net of tax).in annual Depreciation expense, which will be collected in revenues over that same period.
(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. These costs are
129
The equity component of AFUDC, which is credited on the Statements of Income to Miscellaneous Income -(Expense) — Net and Interest Expense for the equity and borrowed funds, respectively.
The equity component of AFUDC, for the years ended December 31, 2004, 2003, 2002, and 2001,2002, was as follows:
|
| 2003 |
| 2002 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
| ||||||
|
| (in millions) |
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Cinergy |
| $ | 7.5 |
| $ | 12.9 |
| $ | 8.6 |
|
| $ | 1.6 |
| $ | 7.5 |
| $ | 12.9 |
|
CG&E and subsidiaries |
| 2.7 |
| 0.4 |
| 2.7 |
|
| 0.5 |
| 2.7 |
| 0.4 |
| ||||||
PSI |
| 4.8 |
| 12.5 |
| 5.9 |
|
| 1.1 |
| 4.8 |
| 12.5 |
| ||||||
ULH&P |
| 0.2 |
| 0.8 |
| 0.1 |
|
| — |
| 0.2 |
| 0.8 |
| ||||||
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, 2004, 2003, 2002, and 2001,2002, was as follows:
|
| 2003 |
| 2002 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
| ||||||
|
| (in millions) |
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
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|
|
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|
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| ||||||
Cinergy |
| $ | 5.7 |
| $ | 10.1 |
| $ | 8.4 |
|
| $ | 2.7 |
| $ | 5.7 |
| $ | 10.1 |
|
CG&E and subsidiaries |
| 1.0 |
| 1.0 |
| 1.0 |
|
| 0.4 |
| 1.0 |
| 1.0 |
| ||||||
PSI |
| 4.7 |
| 9.1 |
| 7.4 |
|
| 2.3 |
| 4.7 |
| 9.1 |
| ||||||
ULH&P |
| 0.1 |
| 0.2 |
| 0.2 |
|
| 0.1 |
| 0.1 |
| 0.2 |
| ||||||
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) below for a discussion of capitalized interest. The equity and borrowed funds components of AFUDC have decreased from 2004 as compared to 2003 and 2002. 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 Statement of Financial Accounting Standards 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, 2004, 2003, 2002, and 2001,2002, were as follows:
146
|
| 2004 |
| 2003 |
| 2002 |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
Cinergy |
| $ | 4.5 |
| $ | 7.9 |
| $ | 7.3 |
|
CG&E and subsidiaries |
| 4.1 |
| 7.7 |
| 7.3 |
| |||
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
Cinergy |
| $ | 7.7 |
| $ | 7.2 |
| $ | 7.1 (1 | ) |
CG&E and subsidiaries |
| 7.7 |
| 7.2 |
| 5.5 |
| |||
(1)The results of Cinergy also include amounts related to non-registrants.
(i) Impairments
(i) Long-Lived Assets
In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets
We, 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 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
130
an impairment loss is recognized for any amount by which the carrying value exceeds the fair value of the assets less cost to sell.
(ii) 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 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, 2004, we do not have any material unrealized losses that are deemed to be temporary in nature. See Note 15(a) for the amount of impairment charges incurred during the year.
(j) Asset Retirement Obligations and Accrued Cost of Removal
WeIn 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.
We do not recognize liabilities for asset retirement obligations for which the fair value cannot be reasonably estimated. CG&E and PSI have asset retirement obligations associated with river structures at certain generating stations. However, the retirement date for these river structures cannot be reasonably estimated; therefore, the fair value of the associated liability currently cannot be estimated and no amounts are recognized in the financial statements herein.statements.
CG&E&E’s'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 Accrued cost of removalRegulatory liabilities and represents a regulatory liability,, under Statement 71, as previously disclosed in (c) above.. Effective with our adoption of Statement 143, on January 1, 2003, 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&E’s generation assets). See (q)(iiiiv) for additional information regarding the adoptiona summary of Statement 143 and the related impacts to Accrued cost of removalcumulative effect adjustments..
(k) Derivatives
We account for derivatives under Statement 133, which requires all derivatives, subject to certain
147
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.
131
(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-trading derivatives involve the physical delivery of energy and are therefore typically accounted for as accrual contracts, unless the contract does not qualify for the normal purchases and sales scope exception in Statement 133. 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(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 inventoryheld 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 (q)(viiv) below for a summary of cumulative effect adjustments.
148
adjustments.
As a response to this discontinuance of fair value accounting, in June 2003, Cinergy began designating derivatives as fair value hedges for certain volumes of our natural gas inventory.held in storage. Under this accounting election, changes in the fair value of both the derivative as well as the hedged item (the specified inventory)gas held in storage) are included in the Statements of Income. We assess the effectiveness of the derivatives in offsetting the change in fair value of the inventorygas held in storage on a quarterly basis. For the year ended, December 31, 2003, the hedges’ ineffectivenessSelected information on Cinergy’s hedge accounting activities was not material.as follows:
|
| 2004 |
| 2003 |
| ||
|
| (in millions) |
| ||||
|
|
|
|
|
| ||
Portion of gain (loss) on hedging instruments determined to be ineffective |
| $ | (2 | ) | $ | — |
|
Portion of gain on hedging instruments related to changes in time value excluded from assessment of ineffectiveness |
| 28 |
| 5 |
| ||
|
|
|
|
|
| ||
Total included in Gas operating revenues |
| $ | 26 |
| $ | 5 |
|
(ii) Financial Financial
In addition to energy marketing and trading, 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
132
cash flows for floating-interestvariable-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, 2003,2004, 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 debt instrument. The unrealized losses that will be reclassified as a charge to Interest Expense during the twelve-month period ending December 31, 2004,2005, are not expected to be material.
(l) Intangible Assets
We adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (Statement 142) in the first quarter of 2002. WithUnder the adoptionprovisions of Statement 142, goodwill and other intangiblesintangible assets with indefinite lives are no longernot amortized. Prior to adoption, we amortized goodwill on a straight-line basis over its estimated useful life, not to exceed 40 years. The discontinuance of this amortization was not material to our financial position or results of operations. 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 15.16. 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.
We finalized our transition impairment test in the fourth quarter of 2002 and recognized a non-cash impairment charge of approximately $11 million (net of tax) for goodwill related to certain of our international assets. This amount is reflected in Cinergy’s Statements of Income as a cumulative effect adjustment, net of tax. See (q)((vi)iv below) for a summary of the cumulative effect adjustments.
149
(m) 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, which conforms to the requirements of the PUHCA. 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.
Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (Statement 109), 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 10.
(n) Environmental and Legal Contingencies
In the normal course of business, Cinergy, CG&E, PSI, and ULH&P aresubject to various regulatory actions, proceedings, lawsuits and other matters, including actions under laws and regulationslawsuits related to the environment.environmental, tax, or other legal matters. We reserve for these potential contingencies when they are deemed probable and reasonably estimable liabilities. We believe that the amounts provided for in our financial statements are adequate. However, these amounts are estimates based upon assumptions involving judgment and therefore actual results could differ. For further discussion of contingencies, see Note 11.
133
(o) Pension and Other Postretirement Benefits
Cinergyprovides 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’sdefined 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 Statement of Financial Accounting Standards 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. 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 Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (Statement 106).
Cinergyreviews 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
150
and other postretirement benefits, see Note 9.
(p) Stock-Based Compensation
In 2003, we prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (Statement 123), as amended by Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure (Statement(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 (APB 25). See Note 2(c) for further information on our stock-based compensation plans. The following table illustrates the effectimpact on our Net Income and EPSearnings per common share (EPS) if the fair value based method had been applied to all outstanding and unvested awards in each period.
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| Year Ended December 31 |
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| (in millions, except per share amounts) |
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| 2003 |
| 2002 |
| 2001 |
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|
| ||||
Net income, as reported |
| $ | 470 |
| $ | 361 |
| $ | 442 |
| |
|
|
|
|
|
|
|
| ||||
Add: | Stock-based employee compensation expense included in reported net income, net of related tax effects. |
| 17 |
| 24 |
| 13 |
| |||
|
|
|
|
|
|
|
|
| |||
Deduct: | Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects. |
| 18 |
| 23 |
| 13 |
| |||
|
|
|
|
|
|
|
| ||||
Pro-forma net income |
| $ | 469 |
| $ | 362 |
| $ | 442 |
| |
|
|
|
|
|
|
|
| ||||
EPS - as reported |
| $ | 2.66 |
| $ | 2.16 |
| $ | 2.78 |
| |
EPS - pro-forma |
| $ | 2.66 |
| $ | 2.17 |
| $ | 2.78 |
| |
|
|
|
|
|
|
|
| ||||
EPS assuming dilution - as reported |
| $ | 2.63 |
| $ | 2.13 |
| $ | 2.75 |
| |
EPS assuming dilution - pro-forma |
| $ | 2.63 |
| $ | 2.14 |
| $ | 2.75 |
| |
The pro-forma amounts reflect certain assumptions used in estimating fair values. Asperiod was not material. In December 2004, the FASB issued a resultrevision of this and other factors which may affect the timing and amounts of stock-based compensation, the pro-forma effect onStatement 123 entitled Net IncomeShare-Based Payment and EPS may not be representative of future periods.. See Note 2(c)(q)(ii) for further description of the fair value assumptions.information.
(q) Accounting Changes
(i) Energy Trading
In October 2002, the EITF reached consensus in EITF 02-3, to (a) rescind EITF 98-10,
151
(b) generally preclude the recognition of gains at the inception of new derivatives, and (c) require all realized and unrealized gains and losses on energy trading derivatives to be presented net in the Statements of Income, whether or not settled physically.
The consensus to rescind EITF 98-10 required all energy trading contracts that do not qualify as derivatives to be accounted for on an accrual basis, rather than at fair value. The consensus was immediately effective for all new contracts executed after October 25, 2002, and required a cumulative effect adjustment to income, net of tax, on January 1, 2003, for all contracts executed on or prior to October 25, 2002. The cumulative effect adjustment, on a net of tax basis, was a loss of approximately $13 million for Cinergy and $8 million for CG&E, which primarily includes the impact of certain coal contracts, gas inventory, and certain gas contracts, which are accounted for at fair value. We expect this rescission to have the largest ongoing impact on our gas trading business, which uses financial contracts, physical contracts, and gas inventory to take advantage of various arbitrage opportunities. Prior to the rescission of EITF 98-10, all of these activities were accounted for at fair value. Under the revised guidance, only certain items are accounted for at fair value, which could increase inter-period volatility in reported results of operations. As a result, we began applying fair value hedge accounting in June 2003 to certain quantities of gas inventory (more fully discussed in (k)(i) above) and are further reviewing additional applications for hedge accounting.
The consensus to require all gains and losses on energy trading derivatives to be presented net in the Statements of Income was effective January 1, 2003, and required reclassification for all periods presented. This resulted in substantial reductions in reported Operating Revenues, Fuel and purchased and exchanged power expense, and Gas purchased expense. However, Operating Income and Net Income were not affected by this change.
(ii) Derivatives
In May 2003, the FASB issued Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (Statement 149). Statement 149 primarily amends Statement 133 to incorporate implementation conclusions previously cleared by the FASB staff, to clarify the definition of a derivative and to require derivative instruments that include up-front cash payments to be classified as a financing activity in the Statements of Cash Flows. Implementation issues previously cleared by the FASB staff were effective at the time they were cleared and new guidance was effective in the third quarter of 2003. In connection with our adoption, we reviewed certain power purchase or sale contracts to determine if they met the revised normal purchases and sales scope exception criteria in Statement 149. If these criteria were not met, the contract was adjusted to fair value. The impact of adopting Statement 149 was not material to our financial position or results of operations.
In June 2003, the FASB issued final guidance on the use of broad market indices (e.g., consumer price index) in power purchases and sales contracts. This guidance clarifies that the normal purchases and sales scope exception is precluded if a contract contains a broad market index that is not clearly and closely related to the asset being sold or purchased (or a direct factor in the production of the asset sold or purchased). The guidance provides criteria that must be met for the index to be considered clearly and closely related. This guidance, which was effective in the fourth quarter of 2003, was not material to our financial position or results of operations.
152
(iii) Asset Retirement Obligations
In July 2001, the FASB issued Statement 143, which requires fair value recognition beginning January 1, 2003, of legal obligations associated with the retirement or removal of long-lived assets at the time the obligations are incurred. Statement 143 prohibits the accrual of estimated retirement and removal costs unless resulting from legal obligations. Our accounting policy for such legal obligations and for accrued cost of removal for our rate regulated long-lived assets is described in (j) above.
We adopted Statement 143 on January 1, 2003, and Cinergy and CG&E both recognized a gain of $39 million (net of tax) for the cumulative effect of this change in accounting principle. Substantially all of this adjustment reflects the reversal of previously accrued cost of removal for CG&E’s generating assets, which do not apply the provisions of Statement 71. Accrued cost of removal at adoption included $316 million, $25 million, and $146 million of accumulated cost of removal related to PSI’s, ULH&P’s, and CG&E’s utility plant in service assets, respectively, which represent regulatory liabilities after adoption and were not included as part of the cumulative effect adjustment. The increases in assets and liabilities from adopting Statement 143 were not material to our financial position.
Pro-forma results as if Statement 143 was applied retroactively for the years ended December 31, 2002 and 2001, are not materially different from reported results.
(iv) Consolidation of VIEs
In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities (Interpretation 46), which significantly changeschanged the consolidation requirements for traditional special purpose entities (SPE) and certain other entities subject to its scope. This interpretation defines a VIE as (a) an entity that does not have sufficient equity to support its activities without additional financial support or (b) anany entity that has equity investors that do not have substantive voting rights, or do not absorb first dollar losses, or receive residual returns. These entities must be consolidated when certain criteria are met. The interpretation was originallywhenever Cinergy would be anticipated to be effective asabsorb greater than 50 percent of the losses or receive greater than 50 percent of the returns.
In accordance with its two stage adoption guidance, we implemented Interpretation 46 for traditional SPEs on July 1, 2003, for Cinergy; however, the FASB subsequently permitted deferral of the effective date to December 31, 2003 for traditional SPEs and to March 31, 2004 for all other entities, subject to the scopeincluding certain operating joint ventures, as of Interpretation 46. During this deferral period, the FASB clarified and amended several provisions, muchMarch 31, 2004. The consolidation of which is intended to assist in the applicationcertain operating joint ventures as of Interpretation 46 to operating entities. Clarifications wereMarch 31, 2004, did not needed for most traditional SPEs and we therefore elected to implement Interpretation 46 for such entities, as discussed below, in accordance with the original implementation datehave a material impact on our financial position or results of operations.
134
On July 1, 2003. Prior period financial statements were not restated for these changes.
2003, Interpretation 46 required us to consolidate two SPEs that have individual power sale agreements towith Central Maine Power Company (CMP). Further, we were no longer permitted to consolidate a trust that was established by Cinergy Corp. in 2001 to issue approximately $316 million of combined preferred trust securities and stock purchase contracts. Prior period financial statements were not restated for these changes. For further information on the accounting for these entities see Note 3.Notes 3(a) and (b).
Cinergy has concluded that its accounts receivable sale facility, as discussed in Note 3(c), will remain unconsolidated since it involves transfers of financial assets to a qualifying SPE, which is
153
exempted from consolidation by Interpretation 46 and Statement of Financial Accounting Standards No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities (Statement 140).
Cinergy is continuing to evaluate the impact of Interpretation 46 on several operating joint ventures, primarily involved in cogeneration and energy efficiency operations, that we currently do not consolidate. If all these entities were consolidated, their total assets of approximately $590 million (the majority of which is non-current) and total liabilities of approximately $210 million (which includes long-term debt of approximately $90 million) would be recognized on our Balance Sheets. Cinergy’s current investment in these entities is approximately $200 million. We also guarantee certain performance obligations of these entities with an estimated maximum potential exposure of approximately $40 million, as disclosed in Note 11(c)(vii). If any of these entities are required to be consolidated, they will be included in the March 31, 2004 consolidated financial statements.
(v)(ii) Share-Based Payment Financial Instruments with Characteristics of Both Liabilities and Equity
In May 2003,December 2004, the FASB issued a replacement of Statement 123, Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity123 (revised 2004), Share-Based Payment (Statement 150)123R). This standard will require accounting for all stock-based compensation arrangements under the fair value method in addition to other provisions.
In 2003, we prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of Statement 150 establishes standards123, as amended by Statement 148, for how an issuer classifies and measuresall employee awards granted or with terms modified on or after January 1, 2003. Therefore, the impact of implementation of Statement 123R on stock options within our stock-based compensation plans is not expected to be material. Statement 123R contains certain financial instruments with characteristicsprovisions that will modify the accounting for various stock-based compensation plans other than stock options. We are in the process of both liabilities and equity. This statement was effective for financial instruments entered into or modified after May 31, 2003, and was effectiveevaluating the impact of this new standard on these plans. Cinergy will adopt Statement 123R on July 1, 2003, for financial instruments held prior to issuance of this statement. Statement 150 would have required Cinergy Corp.’s preferred trust securities to be reported as a liability; however, as described more fully in Note 3(b), the trust holding these securities is no longer permitted to be consolidated and the preferred trust securities are no longer reported on Cinergy’s Balance Sheets. However, Cinergy’s note payable to the trust is recorded on the Balance Sheets as Long-term debt. As a result, the impact of adopting Statement 150 was not material to our financial position or results of operations.
As discussed in Note 3(b), Cinergy Corp. issued forward stock sale contracts that require purchase by the holder of a certain number of Cinergy Corp. shares in February 2005 (stock contracts). The number of shares to be issued is contingent on the market price of Cinergy Corp. stock, but subject to a predetermined ceiling and floor price. In October 2003, the FASB staff released an interpretation of Statement 150 that requires an evaluation of these stock contracts to determine whether they constitute a liability, with any changes in accounting required in January 2004. This interpretation did not have any impact on our current accounting.2005.
(vi)(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. In December 2004, the FASB issued Staff Position 109-2, Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004. The staff position allows additional time for an entity to evaluate the effect of the legislation on its plan for repatriation of foreign earnings for purposes of applying Statement 109. Cinergy will complete its evaluation of the effects of the provision on its plan for repatriation of foreign earnings in 2005.
135
(iv) Cumulative Effect of Changes in Accounting Principles, Net of Tax
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. In 2002, Cinergy recognized a Cumulative effect of a change in accounting principle, net of tax loss as a result of the valuation and impairment of goodwill with the implementation of Statement 142. The following table summarizes the variousthese cumulative effect adjustments and their related tax effects discussed above for the rescission of EITF 98-10 and the adoption of Statement 142 and Statement 143:effects.
154
|
| Year to Date December 31 |
| ||||||||||||||||
|
| 2003 |
| 2002 |
| ||||||||||||||
|
| Before-tax Amount |
| Tax (Expense) Benefit |
| Net-of-tax Amount |
| Before-tax Amount |
| Tax (Expense) Benefit |
| Net-of-tax Amount |
| ||||||
|
| (in millions) |
| ||||||||||||||||
Cinergy(1) |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Goodwill impairment (Statement 142 adoption) |
| $ | — |
| $ | — |
| $ | — |
| $ | (11 | ) | $ | — |
| $ | (11 | ) |
Rescission of EITF 98-10 (EITF 02-3 adoption) |
| (20 | ) | 8 |
| (12 | ) | — |
| — |
| — |
| ||||||
Asset retirement obligation (Statement 143 adoption) |
| 64 |
| (25 | ) | 39 |
| — |
| — |
| — |
| ||||||
|
| $ | 44 |
| $ | (17 | ) | $ | 27 |
| $ | (11 | ) | $ | — |
| $ | (11 | ) |
CG&E |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Rescission of EITF 98-10 (EITF 02-3 adoption) |
| $ | (13 | ) | $ | 5 |
| $ | (8 | ) | $ | — |
| $ | — |
| $ | — |
|
Asset retirement obligation (Statement 143 adoption) |
| 64 |
| (25 | ) | 39 |
| — |
| — |
| — |
| ||||||
|
| $ | 51 |
| $ | (20 | ) | $ | 31 |
| $ | — |
| $ | — |
| $ | — |
|
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Rescission of EITF 98-10 (EITF 02-3 adoption) |
| $ | (1 | ) | $ | 0.5 |
| $ | (0.5 | ) | $ | — |
| $ | — |
| $ | — |
|
|
| $ | (1 | ) | $ | 0.5 |
| $ | (0.5 | ) | $ | — |
| $ | — |
| $ | — |
|
(1) | The results of Cinergy also include amounts related to non-registrants. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(r) 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 (U.S.) 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.
(s) 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 and the applicable state and federal commission regulations. 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
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. The costcosts 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;
155136
•number of customers;employees;
• construction expenditures;number of customers; and
• other statistical information.construction expenditures.
These costs were as follows for the years ended December 31, 2004, 2003, and 2002:
|
| 2004 |
| 2003 |
| 2002 |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
CG&E and subsidiaries |
| $ | 286 |
| $ | 219 |
| $ | 206 |
|
PSI |
| 230 |
| 193 |
| 190 |
| |||
ULH&P |
| 21 |
| 22 |
| 23 |
| |||
During 2002 and 2001:
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
CG&E and subsidiaries |
| $ | 219 |
| $ | 206 |
| $ | 240 |
|
PSI |
| 193 |
| 190 |
| 196 |
| |||
ULH&P |
| 22 |
| 23 |
| 24 |
| |||
156
2003, CinergyPower Generation Services, suppliesLLC (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. The costCG&E and subsidiaries received services from Generation Services in the amounts of these services were as follows$96 million and $104 million for the years ended December 31, 2003 and 2002, respectively. PSI received services in the amounts of $55 million and 2001:
|
| 2003 |
| 2002(1) |
| 2001 |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
CG&E and subsidiaries |
| $ | 96 |
| $ | 104 |
| $ | 67 |
|
PSI |
| 55 |
| 58 |
| 21 |
| |||
(1) Increase reflects movement of Services’$58 million for the years ended December 31, 2003 and 2002, respectively. 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 Generation Services.other affiliated corporations.
(ii) Purchased Energy
ULH&Ppurchases energy from CG&Epursuant 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&Eand replaces the previous cost-of-service based contract, which expired on December 31, 2001.. ULH&P purchased energy from CG&E for resale in the amounts of $162 million, $155 million, $160 million, and $152$160 million for the years ended December 31, 2004, 2003, 2002, and 2001,2002, respectively. These amounts are reflected in the Statements of Income for ULH&Pas Electricity purchased from parent company for resale. For information on the potentialproposed transfer of generating assets to ULH&P and the effect it will have on purchased energy see Note 19.
PSIand CG&Epurchase 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 PSIand CG&Eas Electric operating revenues and Fuel, emission allowances, and purchased and exchanged power expense and were as follows for the years ended December 31, 2004, 2003, 2002, and 2001:2002:
|
| 2003 |
| 2002 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
| ||||||
|
| (in millions) |
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
CG&E |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Electric operating revenues |
| $ | 63 |
| $ | 59 |
| $ | 90 |
|
| $ | 48 |
| $ | 63 |
| $ | 59 |
|
Purchased power(1) |
| 74 |
| 43 |
| 92 |
|
| 80 |
| 74 |
| 43 |
| ||||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Electric operating revenues |
| 74 |
| 43 |
| 92 |
|
| 80 |
| 74 |
| 43 |
| ||||||
Purchased power(1) |
| 63 |
| 59 |
| 90 |
|
| 48 |
| 63 |
| 59 |
| ||||||
(1) Includes intercompany purchases that are presented net in accordance with EITF 02-3. |
To supplement native load requirements, CG&E and PSI have, from time to time, purchased peaking power from Cinergy Capital & Trading, Inc. (Capital & Trading), an indirect wholly-owned subsidiary of Cinergy CorpCorp.., under the terms of a wholesale market-based tariff. There were no purchases in 2004. For the year ended December 31, 2003, payments under this contract totaled approximately $5 million for CG&E. For the year ended December 31, 2002, payments under these contractsthis contract for both CG&Eand PSItotaled approximately $27 million and $28 million, respectively. For PSI, certain of these amounts were deferred and have subsequently been deferred for future recovery as approved by the IURC.recovered.
157137
CG&Eand PSIhave an agreement with Cinergy Marketing & Trading LP (Marketing & Trading) to purchase gas for certain gas-fired peaking plants. Purchases under this agreement were approximately $4 million, $6 million, $9 million, and $12$9 million for CG&Eand $37 million, $20 million, $5 million, and $4$5 million for PSIfor the years ended December 31, 2004, 2003, 2002, and 2001,2002, respectively. The amounts are reflected in the Statements of Income of CG&Eand PSIas Fuel, emission allowances, and purchased and exchanged power expense.
(iii) Other Other
In November 2002, CG&Eand ULH&Pentered enter into various agreements with Marketing & Trading to manage theirinterstate 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 andULH&P’sfirm requirements. These agreements expired in October 2003. In November 2003, CG&E and its subsidiaries, including ULH&P, entered into new one-year contracts with Marketing & Trading. Payments under these agreements for the years ended December 31, 2004, 2003 and 2002 were approximately $480 million, $413 million and $40 million for CG&E and subsidiaries, and $79 million, $78 million and $7 million for ULH&P. These amounts are recorded in the Statements of Income for CG&Eand ULH&Pas Gas purchasedexpense. 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.
In 2004, CG&E and PSI purchased emission allowances from each other under a federal and state approved joint operating agreement. These purchases, which totaled approximately $11 million and $36 million for CG&E and PSI, respectively, are reflected in the emission allowances inventories of both CG&E and PSI.
In February 2003, PSIacquired gas-fired peaking plants in Henry County, Indiana and Butler County, Ohio from two non-regulated affiliates. For a further discussion on the transfer of these generating assets see Note 19.
Cinergy CorpCorp.., 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 companiesand Notes receivable from affiliated companieson the Balance Sheets of our utility operating companies. For a further discussion on the money pool agreement see Note 6.5.
158138
2. 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.
|
| Shares |
| Number of |
| Shares Used to Grant or |
| ||||
2003 |
| 2002 |
| 2001 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. 1996 Long-Term Incentive Compensation Plan (LTIP) |
| 14,500,000 |
| 4,346,877 |
| 1,742,046 |
| 674,005 |
| 72,225 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Stock Option Plan (SOP) |
| 5,000,000 |
| 1,318,500 |
| 421,611 |
| 870,867 |
| 263,070 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Employee Stock Purchase and Savings Plan |
| 2,000,000 |
| 1,482,664 |
| 168,756 |
| 4,912 |
| 227,847 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. UK Sharesave Scheme |
| 75,000 |
| 62,637 |
| 3,364 |
| 8,878 |
| 121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Retirement Plan for Directors |
| 175,000 | (1) | — |
| 5,602 |
| 1,768 |
| 29,135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Directors’ Equity Compensation Plan |
| 75,000 |
| 46,771 |
| 3,824 |
| 196 |
| 1,858 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Directors’ Deferred Compensation Plan |
| 200,000 |
| 108,547 |
| 25,826 |
| — |
| 14,211 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. 401(k) Plans |
| 6,469,373 | (1) | 3,890,358 |
| 1,544,900 |
| 964,615 |
| 69,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan(2) |
| 3,000,000 | (1) | 689,820 |
| 679,301 |
| 657,943 |
| 649,834 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. 401(k) Excess Plan |
| 100,000 | (1) | — |
| — |
| — |
| — |
|
|
| Shares Authorized for Issuance under Plan |
| Number of Shares Available for Future Issuance(2) |
|
Shares Used to Grant or Settle Awards |
| ||||
|
|
|
| 2004 |
| 2003 |
| 2002 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. 1996 Long-Term Incentive Compensation Plan (LTIP) |
| 14,500,000 |
| 3,122,900 |
| 1,729,679 |
| 1,742,046 |
| 674,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Stock Option Plan (SOP) |
| 5,000,000 |
| 1,318,500 |
| 393,523 |
| 421,611 |
| 870,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Employee Stock Purchase and Savings Plan |
| 2,000,000 |
| 1,482,664 |
| — |
| 168,756 |
| 4,912 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. UK Sharesave Scheme |
| 75,000 |
| 62,200 |
| 7,313 |
| 3,364 |
| 8,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Retirement Plan for Directors |
| 175,000 | (1) | — |
| 5,909 |
| 5,602 |
| 1,768 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Directors’ Equity Compensation Plan |
| 75,000 |
| 41,034 |
| 1,095 |
| 3,824 |
| 196 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Directors’ Deferred Compensation Plan |
| 200,000 |
| 103,234 |
| 5,388 |
| 25,826 |
| — |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. 401(k) Plans |
| 6,469,373 | (1) | 2,785,258 |
| 1,174,600 |
| 1,544,900 |
| 964,615 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan |
| 3,000,000 | (1) | 1,035,551 |
| 627,205 |
| 679,301 |
| 657,943 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cinergy Corp. 401(k) Excess Plan |
| 100,000 | (1) | — |
| — |
| — |
| — |
|
(1) | Plan does not contain an authorization limit. The number of shares presented reflects amounts registered with the SEC as of December 31, |
(2) |
|
| Shares available exclude the number of shares to be issued upon exercise of outstanding options, warrants, and rights. |
We retired 519,976829,575 shares of common stock in 2004, 519,976 shares in 2003, and 422,908 shares in 2002, and 72,739 shares in 2001, mainly representing shares tendered as payment for the exercise of previously granted stock options.
In April 2001, Cinergy adopted the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan, a plan designed to provide investors with a convenient method to purchase shares of Cinergy Corp. common stock and to reinvest cash dividends in the purchase of additional shares. This plan replaced the Cinergy Corp. Dividend Reinvestment and Stock Purchase Plan.
159
In November 2001, Cinergy chose to reinstitute the practice of issuing new Cinergy Corp. common shares to satisfy obligations under certain of its employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan. This replaced our previous practice of purchasing shares in the open market to fulfill certain plan obligations.
In February 2002, Cinergy Corp. soldissued 6.5 million shares ofCinergy Corp. common stock with net proceeds of approximately $200 million.million which were used to reduce short-term debt and for other general corporate purposes.
In January 2003, Cinergy Corp. filed a registration statement with the SEC with respect to the issuance of common stock, preferred stock, and other securities in an aggregate offering amount of $750 million. In February 2003, Cinergy sold 5.7 million shares of Cinergy Corp. common stock with net proceeds of approximately $175 million under this registration statement. The net proceeds from the transaction were used to reduce short-term debt of Cinergy Corp. and for other general corporate purposes. In December 2004, Cinergy Corp. issued 6.1 million shares of common stock with net proceeds of approximately $247 million, which were used to reduce short-term debt.
In January and February 2005, CinergyCorp. 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 approximately $316 million were used to reduce short-term debt. See Note 3(b) for further discussion of the securities.
Cinergy Corp. owns all of the common stock of CG&Eand PSI. All of ULH&P’scommon stock is held by CG&E.
139
(b) Dividend Restrictions
Cinergy Corp.’s ability to pay dividends to holders of its common stock is principally dependent on the ability of CG&Eand PSIto pay Cinergy Corp. dividends on their common stock dividends.stock. Cinergy Corp.,CG&E, and PSIcannot 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’sand PSI’scredit instruments. Currently, these requirements do not impact the ability of either company to pay dividends on its common stock.
(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 2004, 2003, 2002, and 20012002 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. Prior to 2003, we had
160
accounted for our stock-based compensation plans using the intrinsic value method under APB 25. See “Stock-Based Compensation” in Note 1(p) for additional information on costs we recognized in 2003, 2002, and 2001, related to stock-based compensation plans, andplans. Effective July 1, 2005, Cinergy will adopt Statement 123R. See Note 1(q)(ii) for our pro-forma disclosure assuming compensation costs for these plans had been determined at fair value, consistent with Statement 123, as amended by Statement 148.additional information regarding this new accounting standard.
(i) LTIP LTIP
The LTIP was originally adopted in 1996 and was subsequently amended effective January 2002. 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 either three or five years. The vesting period begins on the grant date and all options expire within 10 years from that date. The number of shares of common stock issuable under the LTIP is limited to a total of 14.5 million shares.
Historically, the performance-based shares have been paid 100 percent in the form of common stock. In order to maintain market competitiveness with respect to the form of LTIP awards and to ensure continued compliance with internal guidelines on common share dilution, in 2003, the Compensation Committee of the Cinergy Corp. Board of Directors approved the future payment of performance-based share awards 50 percent in common stock and 50 percent in cash. As a result, we have reclassified the expected cash payout portion of the performance shares fromis reported in Paid-in capital to Current Liabilities - Other and Non-Current Liabilities - Other.Other.
140
Entitlement to performance-based shares is based on Cinergy’stotal shareholder return (TSR) over designated Cycles as measured against a pre-defined peer group. Target grants of performance-based shares were made for the following Cycles:
Cycle | Grant | Performance | Target | ||||
(in thousands) | |||||||
| |||||||
|
| ||||||
|
|
|
| ||||
VII |
| 1/2003 |
| 2003-2005 |
| 411 |
|
VIII |
| 1/2004 |
| 2004-2006 |
| 404 |
|
IX | 1/2005 | 2005-2007 | 395 | ||||
Participants may earn additional performance shares if Cinergy’sTSR exceeds that of the 55th percentile of the TSR of its peer group. For the three-year performance period ended December 31, 20032004 (Cycle V)VI), approximately 567,000634,000 shares (including dividend equivalent shares) were earned, based on our relative TSR.
(ii) SOP SOP
The SOP is 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 may be granted to key employees, officers, and outside directors. The activity under this plan has predominantly consisted of the issuancegrant of stock options. Options are granted with an option
161
price equal to the fair market value of the shares on the grant date. Options generally vest over five years at a rate of 20 percent per year, beginning on the grant date, and expire 10 years from the grant date. The total numberAs of shares of common stock issuable under the SOP may not exceed 5,000,000 shares. NoOctober 2004, no additional incentive stock options may be granted under the plan after October 24, 2004.plan.
(iii) Employee Stock Purchase and Savings Plan
The Employee Stock Purchase and Savings Plan allows essentially all full-time, regular employees to purchase shares of common stock pursuant to a stock option feature. Under the Employee Stock Purchase and Savings Plan, after-tax funds are withheld from a participant’s compensation during a 26-month offering period and are deposited in an interest-bearing account. At the end of the offering period, participants may apply amounts deposited in the account, plus interest, toward the purchase of shares of common stock. The purchase price is equal to 95 percent of the fair market value of a share of common stock on the first date of the offering period. Any funds not applied toward the purchase of shares are returned to the participant. A participant may elect to terminate participation in the plan at any time. Participation also will terminate if the participant’s employment ceases. Upon termination of participation, all funds, including interest, are returned to the participant without penalty. The sixthlast 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. The total number of shares of common stock issuable under the Employee Stock Purchase and Savings Plan may not exceed 2,000,000.
162141
Activity for 2004, 2003, 2002, and 20012002 for the LTIP, SOP, and Employee Stock Purchase and Savings Plan is summarized as follows:
|
| LTIP and SOP |
| Employee Stock Purchase and |
| ||||||
|
| Shares Subject |
| Weighted Average |
| Shares |
| Weighted Average |
| ||
Balance at December 31, 2000 |
| 6,990,871 |
| $ | 26.77 |
| 280,326 |
| $ | 27.73 |
|
|
|
|
|
|
|
|
|
|
| ||
Options granted |
| 811,700 |
| 33.90 |
| 299,793 |
| 32.78 |
| ||
Options exercised |
| (275,393 | ) | 24.39 |
| (227,968 | ) | 27.73 |
| ||
Options forfeited |
| (79,400 | ) | 27.29 |
| (73,826 | ) | 29.20 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Balance at December 31, 2001 |
| 7,447,778 |
| 27.63 |
| 278,325 |
| 32.78 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Options granted |
| 1,241,200 | (2) | 32.27 |
| — |
| — |
| ||
Options exercised |
| (1,308,738 | ) | 23.96 |
| (4,912 | ) | 32.78 |
| ||
Options forfeited |
| (18,540 | ) | 31.57 |
| (55,243 | ) | 32.78 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Balance at December 31, 2002 |
| 7,361,700 |
| 29.06 |
| 218,170 |
| 32.78 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Options granted |
| 897,100 | (2) | 34.30 |
| — |
| — |
| ||
Options exercised |
| (1,630,046 | ) | 24.89 |
| (168,101 | ) | 32.78 |
| ||
Options forfeited |
| (59,300 | ) | 30.51 |
| (50,069 | ) | 32.78 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Balance at December 31, 2003 |
| 6,569,454 |
| $ | 30.79 |
| — |
| $ | — |
|
|
|
|
|
|
|
|
|
|
| ||
Options Exercisable(1): |
|
|
|
|
|
|
|
|
| ||
At December 31, 2001 |
| 3,763,558 |
| $ | 27.32 |
|
|
|
|
| |
At December 31, 2002 |
| 3,744,420 |
| $ | 28.98 |
|
|
|
|
| |
At December 31, 2003 |
| 3,700,346 |
| $ | 29.52 |
|
|
|
|
| |
|
| LTIP and SOP |
| Employee Stock Purchase and Savings Plan(1) |
| ||||||
|
| Shares Subject |
| Weighted Average |
| Shares Subject |
| Weighted Average |
| ||
|
| to Option |
| Exercise Price |
| to Option |
| Exercise Price |
| ||
|
|
|
|
|
|
|
|
|
| ||
Balance at December 31, 2001 |
| 7,447,778 |
| $ | 27.63 |
| 278,325 |
| $ | 32.78 |
|
|
|
|
|
|
|
|
|
|
| ||
Options granted(2) |
| 1,241,200 |
| 32.27 |
| — |
| — |
| ||
Options exercised |
| (1,308,738 | ) | 23.96 |
| (4,912 | ) | 32.78 |
| ||
Options forfeited |
| (18,540 | ) | 31.57 |
| (55,243 | ) | 32.78 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Balance at December 31, 2002 |
| 7,361,700 |
| 29.06 |
| 218,170 |
| 32.78 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Options granted(2) |
| 897,100 |
| 34.30 |
| — |
| — |
| ||
Options exercised |
| (1,630,046 | ) | 24.89 |
| (168,101 | ) | 32.78 |
| ||
Options forfeited |
| (59,300 | ) | 30.51 |
| (50,069 | ) | 32.78 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Balance at December 31, 2003 |
| 6,569,454 |
| 30.79 |
| — |
| $ | — |
| |
|
|
|
|
|
|
|
|
|
| ||
Options granted(2) |
| 739,200 |
| 38.79 |
|
|
|
|
| ||
Options exercised |
| (1,950,570 | ) | 26.41 |
|
|
|
|
| ||
Options forfeited |
| (32,700 | ) | 35.95 |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
| ||
Balance at December 31, 2004 |
| 5,325,384 |
| $ | 33.35 |
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| ||
Options Exercisable(3): |
|
|
|
|
|
|
|
|
| ||
At December 31, 2002 |
| 3,744,420 |
| $ | 28.98 |
|
|
|
|
| |
At December 31, 2003 |
| 3,700,346 |
| $ | 29.52 |
|
|
|
|
| |
At December 31, 2004 |
| 2,706,876 |
| $ | 32.01 |
|
|
|
|
| |
(1)
| Shares were not offered after June 30, 2003. |
(2) | Options were not granted under the SOP during 2004, 2003, or 2002. |
(3) | The options under the Employee Stock Purchase and Savings Plan are generally only exercisable at the end of the offering period. |
The weighted average fair value of options granted under the combined LTIP and the SOP plans was $5.65 in 2004, $4.96 in 2003, and $4.95 in 2002, and $5.42 in 2001. The weighted average fair value of options granted under the Employee Stock Purchase and Savings Plan was $5.85 in 2001 (no options were granted in 2003 or 2002).2002. The fair values of options granted were estimated as of the grant date using the Black-Scholes option-pricing model and the following assumptions:
|
| LTIP and SOP(1) |
| Employee Stock |
|
| LTIP |
| ||||||||
|
| 2003 |
| 2002 |
| 2001 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk-free interest rate |
| 3.02 | % | 3.92 | % | 4.78 | % | 4.22 | % |
| 3.35 | % | 3.02 | % | 3.92 | % |
Expected dividend yield |
| 5.34 | % | 5.66 | % | 5.42 | % | 5.26 | % |
| 4.97 | % | 5.34 | % | 5.66 | % |
Expected lives |
| 5.35 | yrs. | 5.42 | yrs. | 5.37 | yrs. | 2.17 | yrs. | |||||||
Expected life |
| 5.33 | yrs. | 5.35 | yrs. | 5.42 | yrs. | |||||||||
Expected volatility |
| 26.15 | % | 26.45 | % | 25.01 | % | 30.67 | % |
| 24.47 | % | 26.15 | % | 26.45 | % |
| ||
| ||
163
Price ranges, along with certain other information, for options outstanding under the combined LTIP and SOP plans at December 31, 2003,2004, were as follows:
|
|
|
|
|
| Outstanding |
| Exercisable |
| ||||||||||||||||
Exercise Price Range |
| Number of Shares |
| Weighted Average Exercise Price |
| Weighted Average Remaining Contractual Life |
| Number of Shares |
| Weighted Average Exercise Price |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
$ | 23.66 |
| - |
| $ | 33.64 |
| 2,315,346 |
| $ | 29.59 |
| 6.00 yrs. |
| 1,264,238 |
| $ | 27.42 |
| ||||||
$ | 33.88 |
| - |
| $ | 36.88 |
| 2,061,638 |
| $ | 35.09 |
| 5.90 yrs. |
| 1,233,938 |
| $ | 35.60 |
| ||||||
$ | 37.82 |
| - |
| $ | 39.65 |
| 948,400 |
| $ | 38.74 |
| 7.68 yrs. |
| 208,700 |
| $ | 38.59 |
| ||||||
142
|
|
|
|
|
| Outstanding |
| Exercisable |
| ||||||||||
Exercise |
| Number |
| Weighted |
| Weighted |
| Number |
| Weighted |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
$ | 22.88 |
| - |
| $ | 24.38 |
| 2,134,724 |
| $ | 24.00 |
| 5.27 yrs. |
| 1,830,644 |
| $ | 24.03 |
|
$ | 24.63 |
| - |
| $ | 33.87 |
| 1,851,164 |
| $ | 32.05 |
| 7.20 yrs. |
| 611,236 |
| $ | 31.93 |
|
$ | 33.88 |
| - |
| $ | 38.59 |
| 2,583,566 |
| $ | 35.51 |
| 6.48 yrs. |
| 1,258,466 |
| $ | 36.32 |
|
(iv) 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 provided they have already contributed the maximum amount (pursuant to the anti-discrimination rules for highly compensated employees) under the qualified 401(k) Plan. All funds deferred are held in a rabbi trust administered by an independent trustee.
(d) 401(k) Plans
We sponsor 401(k) employee retirement plans that cover substantially all U.S.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 CorpCorp.. 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.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’smatching contributions for the years ended December 31, 2004, 2003, 2002, and 20012002 were as follows:
|
| 2003 |
| 2002 |
| 2001 |
|
| 2004 |
| 2003 |
| 2002 |
| ||||||
|
| (in millions) |
|
|
|
| (in millions) |
|
|
| ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Cinergy(1) |
| $ | 18 |
| $ | 19 |
| $ | 17 |
|
| $ | 20 |
| $ | 18 |
| $ | 19 |
|
CG&E and subsidiaries |
| 3 |
| 3 |
| 3 |
|
| 5 |
| 3 |
| 3 |
| ||||||
PSI |
| 4 |
| 3 |
| 3 |
|
| 4 |
| 4 |
| 3 |
| ||||||
(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 pay.pension eligible earnings. The deferred profit sharing contribution
164
made by Cinergy is based on ourthe corporate net income performance level for the year, and is made to the 401(k) plans in the form of Cinergy CorpCorp.. common stock. Each year’s contribution must remain invested in Cinergy CorpCorp.. common stock for a minimum of three years, or until an employee reaches age 50. Employees age 50 or older may transfer their benefit from Cinergy CorpCorp.. common stock into another investment option offered under our 401(k) plans. Employees vest in their benefit upon reaching three years of service, or immediately upon reaching age 65 while employed. Cinergyhas recorded approximately $2.4 million and $1.5 million, respectively, of profit sharing contribution costs for the yearyears ended December 31, 2004 and December 31, 2003.
(e)Stock Purchase Contracts(v) 401(k) Excess Plan
In December 2001, Cinergy Corp. issued approximately $316 million notional amount of combined securities,The 401(k) Excess Plan is a component of which was stock purchase contracts. These contracts obligate the holder to purchase common sharesnon-qualified deferred compensation plan for a select group of Cinergy Corp. stock 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 and/or before, February 2005. The number of shares to be issued is contingent upon the market price of Cinergy Corp. stock, but subject to predetermined ceiling and floor prices. See Note 3(b) for further discussion of these combined securities.a rabbi trust administered by an independent trustee.
3. Variable Interest Entities
(a) Power Sale SPEs
As discussed in Note 1(q)(iv), inIn accordance with Interpretation 46, we were required to consolidate two SPEs that have individual power sale agreements towith 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 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. Notes 4 and 58 provide additional information regarding the debt and the notes receivable, respectively.
143
(b) Preferred Trust Securities
In December 2001, Cinergy CorpCorp. . 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 CorpCorp.. common stock inby 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 is 100 percent owned by Cinergy Corp. The stock purchase contracts were issued directly by Cinergy CorpCorp. . The trust loaned the proceeds from the issuance of the securities to Cinergy CorpCorp. . in exchange for a note payable to the trust that was eliminated in consolidation. The proceeds of $306 million, which is net of approximately $10 million of issuance costs, were used to pay down Cinergy Corp.’s short-term
165
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 will bewere successfully remarketed and the dividend rate was reset no lower thanat 6.9 percent, to yield $316 millionpercent. The preferred trust securities will mature in the remarketing. The holders will use the proceeds from this remarketing to fund their obligation to purchase shares of Cinergy Corp. common stock underFebruary 2007. To settle the stock purchase contract. The holders will pay the market price for thecontracts, Cinergy Corp. issued 9.2 million shares of common stock at that time, subject to athe ceiling price of $34.40 per share and a flooras the market price of $29.15 per share. The number of shares to be issued will vary according to the stock exceeded the ceiling price subjectof the contract. Net proceeds of approximately $316 million were used to the total proceeds equaling $316 million.repay short-term indebtedness.
Each Unit willcontinues to receive quarterly cash payments of 9.56.9 percent per annum of the notional amount, which includes therepresents a preferred trust security dividend of 6.9 percent and paymentdividend. Each Unit received quarterly cash payments of 2.6 percent per annum of the notional amount, which representsrepresented principal and interest on the stock purchase contracts. UponThese payments ceased upon delivery of the shares these stock purchase contract payments will cease.in January and February 2005. The trust’s ability to pay dividends on the preferred trust securities is solely dependent on its receipt of interest payments from Cinergy CorpCorp. . on the note payable. However, Cinergy CorpCinergy 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 (previously recorded as Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company)are no longer included in Cinergy Corp.Corp.’s Balance Sheets. In addition, the note payable owed to the trust, which has a current carrying value of $319$322 million, is included in Long-term debt.debt.
(c) Sales of Accounts Receivable
In February 2002, CG&E, PSI, and ULH&Pentered into an agreement to sell certain of their accounts receivable and related collections. Cinergy CorpCorp.. formed Cinergy Receivables Company, LLC (Cinergy (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. &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 Statement 140 and is classified within Notes receivable from
166
affiliated companiesin the accompanying Balance Sheets of CG&E, PSI, and ULH&Pand is classified within Notes receivableon 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
144
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, , PSI, and ULH&Pon 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 for sales since the inception of the new agreement are as follows (all amounts are averages of the assumptions used in sales during the period):
|
| Cinergy |
| CG&E and |
| PSI |
| ULH&P |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Cinergy |
| CG&E and subsidiaries |
| PSI |
| ULH&P |
| ||||||||
|
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
|
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
Anticipated credit loss rate |
| 0.6 | % | 0.6 | % | 0.8 | % | 0.6 | % | 0.5 | % | 0.5 | % | 1.0 | % | 1.0 | % |
| 0.7 | % | 0.6 | % | 0.9 | % | 0.8 | % | 0.5 | % | 0.5 | % | 1.2 | % | 1.0 | % |
Discount rate on expected cash flows |
| 4.4 | % | 5.0 | % | 4.4 | % | 5.0 | % | 4.4 | % | 5.0 | % | 4.4 | % | 5.0 | % |
| 3.8 | % | 4.4 | % | 3.8 | % | 4.4 | % | 3.8 | % | 4.4 | % | 3.8 | % | 4.4 | % |
Receivables turnover rate(1) |
| 12.8 | % | 12.9 | % | 13.6 | % | 13.7 | % | 11.8 | % | 11.8 | % | 13.2 | % | 13.5 | % |
| 12.6 | % | 12.8 | % | 13.4 | % | 13.6 | % | 11.5 | % | 11.8 | % | 12.9 | % | 13.2 | % |
(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&Eretains 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, , PSI, and ULH&Pin the event of a loss. While no direct recourse to CG&E PSI, , PSI, and ULH&Pexists, 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&Eapproximates a market rate.
167145
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, 20032004 and 2002.2003.
|
| 2003 |
| ||||||||||
|
| Cinergy |
| CG&E and |
| PSI |
| ULH&P |
| ||||
|
| (in millions) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Receivables sold as of period end |
| $ | 487 |
| $ | 310 |
| $ | 177 |
| $ | 50 |
|
Less: Retained interests |
| 172 |
| 107 |
| 65 |
| 18 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net receivables sold as of period end |
| $ | 315 |
| $ | 203 |
| $ | 112 |
| $ | 32 |
|
|
|
|
|
|
|
|
|
|
| ||||
Purchased beneficial interests |
| $ | 14 |
| $ | — |
| $ | — |
| $ | — |
|
|
|
|
|
|
|
|
|
|
| ||||
Sales during period |
|
|
|
|
|
|
|
|
| ||||
Receivables sold |
| $ | 3,681 |
| $ | 2,140 |
| $ | 1,541 |
| $ | 346 |
|
Loss recognized on sale |
| 36 |
| 23 |
| 13 |
| 4 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Cash flows during period |
|
|
|
|
|
|
|
|
| ||||
Cash proceeds from sold receivables |
| $ | 3,601 |
| $ | 2,092 |
| $ | 1,509 |
| $ | 337 |
|
Collection fees received |
| 2 |
| 1 |
| 1 |
| — |
| ||||
Return received on retained interests |
| 16 |
| 9 |
| 7 |
| 2 |
| ||||
|
| 2002 |
|
| 2004 |
| ||||||||||||||||||||
|
| Cinergy |
| CG&E and |
| PSI |
| ULH&P |
|
| Cinergy |
| CG&E and subsidiaries |
| PSI |
| ULH&P |
| ||||||||
|
| (in millions) |
|
| (in millions) |
| ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Receivables sold as of period end |
| $ | 483 |
| $ | 299 |
| $ | 184 |
| $ | 45 |
|
| $ | 538 |
| $ | 339 |
| $ | 199 |
| $ | 54 |
|
Less: Retained interests |
| 135 |
| 81 |
| 54 |
| 13 |
|
| 194 |
| 121 |
| 73 |
| 21 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Net receivables sold as of period end |
| $ | 348 |
| $ | 218 |
| $ | 130 |
| $ | 32 |
|
| $ | 344 |
| $ | 218 |
| $ | 126 |
| $ | 33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Purchased beneficial interests |
| $ | 10 |
| $ | — |
| $ | — |
| $ | — |
| |||||||||||||
Purchased beneficial interest |
| $ | 18 |
| $ | — |
| $ | — |
| $ | — |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Sales during period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Receivables sold |
| $ | 3,233 |
| $ | 1,840 |
| $ | 1,392 |
| $ | 287 |
|
| $ | 3,895 |
| $ | 2,253 |
| $ | 1,642 |
| $ | 367 |
|
Loss recognized on sale |
| 32 |
| 19 |
| 13 |
| 3 |
|
| 38 |
| 25 |
| 13 |
| 4 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Cash flows during period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Cash proceeds from sold receivables |
| $ | 3,184 |
| $ | 1,813 |
| $ | 1,371 |
| $ | 283 |
|
| $ | 3,835 |
| $ | 2,213 |
| $ | 1,622 |
| $ | 360 |
|
Collection fees received |
| 2 |
| 1 |
| 1 |
| — |
|
| 2 |
| 2 |
| — |
| — |
| ||||||||
Return received on retained interests |
| 16 |
| 9 |
| 7 |
| 1 |
|
| 17 |
| 10 |
| 7 |
| 2 |
| ||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
|
| 2003 |
| |||||||||||||||||||||||
|
| Cinergy |
| CG&E and subsidiaries |
| PSI |
|
ULH&P |
| |||||||||||||||||
|
| (in millions) |
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Receivables sold as of period end |
| $ | 487 |
| $ | 310 |
| $ | 177 |
| $ | 50 |
| |||||||||||||
Less: Retained interests |
| 172 |
| 107 |
| 65 |
| 18 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Net receivables sold as of period end |
| $ | 315 |
| $ | 203 |
| $ | 112 |
| $ | 32 |
| |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Purchased beneficial interest |
| $ | 14 |
| $ | — |
| $ | — |
| $ | — |
| |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Sales during period |
|
|
|
|
|
|
|
|
| |||||||||||||||||
Receivables sold |
| $ | 3,681 |
| $ | 2,140 |
| $ | 1,541 |
| $ | 346 |
| |||||||||||||
Loss recognized on sale |
| 36 |
| 23 |
| 13 |
| 4 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Cash flows during period |
|
|
|
|
|
|
|
|
| |||||||||||||||||
Cash proceeds from sold receivables |
| $ | 3,601 |
| $ | 2,092 |
| $ | 1,509 |
| $ | 337 |
| |||||||||||||
Collection fees received |
| 2 |
| 2 |
| — |
| — |
| |||||||||||||||||
Return received on retained interests |
| 16 |
| 9 |
| 7 |
| 2 |
| |||||||||||||||||
A decline in the long-term senior unsecured credit ratings ofCG&E, PSI, or ULH&P below investment grade would result in a termination of the sale program and discontinuance of future sales of receivables, and could prevent Cinergy Receivables from borrowing additional funds from commercial paper conduits.
168(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.
146
4. 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 January 2002, PSI repaid at maturity $23 million principal amount of its Medium-term Notes, Series A. The securities were not replaced by new issues of long-term debt.
In September 2002, CG&E repaid at maturity $100 million principal amount of its First Mortgage Bonds, 7 ¼% Series.
Also in September 2002, CG&E borrowed the proceeds from the issuance by the Ohio Air Quality Development Authority of $84 million principal amount of its State of Ohio Air Quality Development Revenue Refunding Bonds 2002 Series A, due September 1, 2037. The issuance consists of two $42 million tranches, with the interest rate on one tranche being reset every 35 days by auction and the interest rate on the other tranche being reset every 7 days by auction. The initial interest rates for the 35-day and 7-day tranches were 1.40 percent and 1.35 percent, respectively. Proceeds from the borrowing were used in October 2002 to redeem, at par, two $42 million Series 1985 A&B Air Quality Development Authority State of Ohio Customized Purchase Revenue Bonds, due December 1, 2015. The redeemed bonds had been classified in Notes payable and other short-term obligations.
Additionally in September 2002, PSI borrowed the proceeds from the issuance by the Indiana Development Finance Authority of $23 million principal amount of its Environmental Refunding Revenue Bonds Series 2002A, due March 1, 2031. The initial interest rate for the bonds was 1.40 percent and resets every 35 days by auction. Proceeds from the borrowing were used in October 2002 to redeem, at par, the $23 million principal amount of Indiana Development Finance Authority Environmental Refunding Revenue Bonds Series 1998, due August 1, 2028. The redeemed bonds had been classified in Notes payable and other short-term obligations.
Later in September 2002, PSI borrowed the proceeds from the issuance by the Indiana Development Finance Authority of $24.6 million principal amount of its Environmental Refunding Revenue Bonds Series 2002B, due March 1, 2019. The initial interest rate for the bonds was 1.35 percent and resets every 7 days by auction. Proceeds from the issuance were used in October 2002 to redeem, at par, the $24.6 million principal amount of City of Princeton, Indiana Pollution Control Revenue Refunding Bonds 1996 Series, due March 1, 2019. The redeemed bonds had been classified in Notes payable and other short-term obligations.
The holders of the Ohio Air Quality Development Authority and Indiana Development Finance Authority bonds mentioned above have the benefit of a financial guaranty insurance policy that insures the payment of principal of, and interest on, the bonds when due. CG&E and PSI have each entered into an insurance agreement with the bond insurer and have pledged first mortgage bonds to secure their respective reimbursement obligations under such agreements.
Finally in September 2002, CG&E issued $500 million principal amount of its 5.70% Debentures due September 15, 2012. Proceeds from the offering were used to repay short-term indebtedness incurred in connection with general corporate purposes including capital
169
expenditures related to environmental compliance construction, and the repayment at maturity of $100 million principal amount of CG&E’s First Mortgage Bonds, 7(1)/4% Series. In July 2002, CG&E executed a treasury lock with a notional amount of $250 million, which was designated as a cash flow hedge of 50 percent of the forecasted interest payments on this debt offering. With the issuance of the debt, the treasury lock was settled. See Note 8(a) for additional information on this treasury lock.
In October 2002, PSI filed a petition with the IURC for the purpose of securing authorization and approval to issue two subordinated promissory notes to Cinergy Corp. for the acquisition of the Butler County, Ohio and Henry County, Indiana peaking plants. In January 2003, the IURC granted this request, and in February 2003, PSI issued the notes. One subordinated note was for the principal amount of $200 million with an annual interest rate of 6.30 percent scheduled to mature on April 15, 2004. The second subordinated note was for $176 million with an annual interest rate of 6.40 percent scheduled to mature on September 1, 2004.
In March 2003, PSI borrowed the proceeds from the issuance by the Indiana Development Finance AuthorityAuthority’s issuance of $35 million of its Environmental Refunding Revenue Bonds, Series 2003, due April 1, 2022. Interest was initially set at 1.05 percent and resets every 35 days by auction. TheBecause the holders cannot tender the bonds are not putablefor purchase by the holders; therefore,issuer while the Bonds are in the auction rate mode, PSIPSI’s’s debt obligation is classified as Long-term debt.debt. Later in March 2003, the proceeds from this borrowing plus the interest income earned were used to cause the refunding of the $35 million principal amount outstanding of the City of Princeton, Indiana Pollution Control Revenue Refunding Bonds, 1997 Series. Similar to the Indiana Development Finance Authority bonds discussed above, PSI has entered into an insurance agreement with the bond insurer and has pledged first mortgage bonds to secure its reimbursement obligations under the agreement.
In April 2003, PSI redeemed $26.8 million of the following Series A, Medium-term Notes:
Principal Amount |
| Interest Rate |
| Maturity Date |
| |
(in millions) |
|
|
|
|
| |
|
|
|
|
|
| |
$ | 2.0 |
| 8.37 | % | 11/08/2006 |
|
5.0 |
| 8.81 |
| 05/16/2022 |
| |
3.0 |
| 8.80 |
| 05/18/2022 |
| |
16.8 |
| 8.67 |
| 06/01/2022 |
| |
In June 2003, CG&E issued $200 million principal amount of its 5 3/8%3/8% 2003 Series B Debentures due June 15, 2033 (effective interest rate of 5.66 percent). Proceeds from this issuance were used for general corporate purposes, including the funding of capital expenditures related to construction projects and environmental compliance initiatives, and the repayment of outstanding indebtedness.
Also, in June 2003, CG&E modified existing debt resulting in a $200 million principal amount 5.40% 2003 Series A Debenture with a 30 year30-year maturity. The effective interest rate is 6.90 percent.
In June 2003, CG&E also redeemed its $100 million 8.28% Junior Subordinated Debentures due
170
July 1, 2025.
Cinergy adopted Interpretation 46 on July 1, 2003, as discussed in Note 1(q)(iv)(i). The adoption of this new accounting principle had the following effects on long-term debt:
•Cinergy Cinergy no longer consolidates the trust that held Company obligated, mandatorily redeemable, preferred trust securities of subsidiary, holding solely debt securities of the company.company. This resulted in the removal of these securities from our 2003 Balance Sheet and the addition to long-term debt of a $319 million (net of discount) note payable that Cinergy Corp. owes to the trust.
•Cinergy Cinergy consolidated two SPEs effective July 1, 2003. As a result, Cinergy has approximately $217$200 million of additional non-recourse debt as of December 31, 2003,2004, comprised of two separate notes.
The first note, with a December 31, 20032004 balance of $110$93 million bears an interest rate of 7.81 percent and matures in June 2009. The second note, with a December 31, 20032004 balance of $107 million, bears an interest rate of 9.23 percent and matures in November 2016.
In September 2003, PSI redeemed $56 million of its 5.93% Series B, Medium-term Notes at maturity.
In September 2003, PSI issued $400 million principal amount of its 5.00% Debentures due September 15, 2013 (effective interest rate of 5.20 percent). Proceeds from this issuance were used for the early redemption at par of two subordinated promissory notes to Cinergy Corp., as discussed above, totaling $376 million.million, issued as consideration for two gas fired electric peaking facilities transferred from Cinergy Corp. to PSI in early 2003. The remaining proceeds were used
147
to reduce short-term indebtedness associated with general corporate purposes including funding capital expenditures related to construction projects and environmental compliance initiatives.
In October 2003, CG&E redeemed its $265.5 million First Mortgage Bonds, 7.20% due October 1, 2023.
In December 2003, ULH&P redeemed $20 million of its 6.11% Senior Debentures at maturity.
In February 2004, CG&E redeemedrepaid at maturity $110 million of its 6.45% First Mortgage Bonds at maturity.Bonds.
171In 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-termdebt. 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 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.
148
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 the issuer haswe have the right to buy back a given security from the holder at a specified price before maturity. Putable means the holder has the right to sell a given security back to the issuer at a specified price before maturity.
172
Long-term Debt Maturities
|
| Cinergy(1) |
| CG&E and |
| PSI |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
2004 |
| $ | 835 |
| $ | 110 |
| $ | — |
|
|
|
|
|
|
|
|
| |||
2005(2) |
| 222 |
| 150 |
| 52 |
| |||
|
|
|
|
|
|
|
| |||
2006 |
| 354 |
| — |
| 326 |
| |||
|
|
|
|
|
|
|
| |||
2007 |
| 727 |
| 100 |
| 266 |
| |||
|
|
|
|
|
|
|
| |||
2008 |
| 550 |
| 120(3 | ) | 44 |
| |||
|
|
|
|
|
|
|
| |||
Thereafter |
| 2,333 |
| 1,126(4 | ) | 1,043 |
| |||
|
|
|
|
|
|
|
| |||
Total |
| $ | 5,021 |
| $ | 1,606 |
| $ | 1,731 |
|
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ULH&P |
| ||||
|
| (in millions) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
2005(2) |
| $ | 220 |
| $ | 150 |
| $ | 50 |
| $ | — |
|
|
|
|
|
|
|
|
|
|
| ||||
2006 |
| 355 |
| — |
| 326 |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
2007 |
| 726 |
| 100 |
| 266 |
| — |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
2008 |
| 551 |
| 120 |
| 43 |
| 20 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
2009 |
| 270 |
| 20 |
| 223 |
| 20 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Thereafter |
| 2,376 |
| 1,240 |
| 976 |
| 55 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Total |
| $ | 4,498 |
| $ | 1,630 |
| $ | 1,884 |
| $ | 95 |
|
|
(2) CG&E and subsidiaries includes long-term debt with put provisions of $150 million in 2005. PSI includes long-term debt with put provisions of $50 million in 2005. |
Maintenance and replacement fund provisions contained in PSI’sfirst 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’sPSI’s net revenues.
In August 2000, the generation assets of CG&E were released from the first mortgage indenture lien. CG&E’s remaining assets, consisting primarily of transmission and distribution assets of approximately $2.6$2.8 billion are subject to the lien of its first mortgage bond indenture. The utility property of PSIis 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 three years.
5. Notes ReceivablePayable and Other Short-term Obligations
Short-term obligations may include:
•short-term notes;
•variable rate pollution control notes;
•commercial paper; and
•money pool.
Short-term borrowings mature within one year from the date of issuance. We primarily use unsecured revolving lines of credit and the sale of commercial paper for short-term borrowings. A portion of Cinergy Corp.’s revolving lines is used to provide credit support for commercial paper and letters of credit. When revolving lines are reserved for commercial paper or backing letters of credit, they are not available for additional borrowings. The fees paid to secure short-term borrowings were immaterial during each of the years ended December 31, 2004, 2003, and 2002.
149
At December 31, 2004, Cinergy Corp. had $1.3 billion remaining unused and available capacity relating to its $2 billion revolving credit facilities. These revolving credit facilities include the following:
Credit Facility |
| Expiration |
| Established Lines |
| Outstanding and Committed |
| Unused and Available |
| |||
|
| (in millions) |
| |||||||||
|
|
|
|
|
|
|
|
|
| |||
Five-year senior revolving |
| December 2009 |
|
|
|
|
|
|
| |||
Direct borrowing |
|
|
| $ |
|
| $ | — |
| $ |
|
|
Commercial paper support |
|
|
|
|
| — |
|
|
| |||
|
|
|
|
|
|
|
|
|
| |||
Total five-year facility(1) |
|
|
| 1,000 |
| — |
| 1,000 |
| |||
|
|
|
|
|
|
|
|
|
| |||
Three-year senior revolving |
| April 2007 |
|
|
|
|
|
|
| |||
Direct borrowing |
|
|
|
|
| — |
|
|
| |||
Commercial paper support |
|
|
|
|
| 676 |
|
|
| |||
Letter of credit support |
|
|
|
|
| 12 |
|
|
| |||
|
|
|
|
|
|
|
|
|
| |||
Total three-year facility(2) |
|
|
| 1,000 |
| 688 |
| 312 |
| |||
|
|
|
|
|
|
|
|
|
| |||
Total Credit Facilities |
|
|
| $ | 2,000 |
| $ | 688 |
| $ | 1,312 |
|
(1) In April 2004, Cinergy Corp. successfully placed a $500 million 364-day senior unsecured revolving credit facility which replaced the $600 million 364-day senior unsecured revolving credit facility that expired in April 2004. In December 2004, Cinergy Corp. successfully replaced the $500 million 364-day facility with a $1 billion five-year facility. CG&E and PSIeach have $500 million borrowing sublimits on this facility. |
(2) In April 2004, Cinergy Corp. successfully placed a $1 billion three-year senior unsecured revolving credit facility. This facility replaced the $400 million three-year senior unsecured revolving credit facility that was set to expire in May 2004. |
In addition to revolving credit facilities, 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, 2004.
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, 2004, Cinergy, CG&E and PSI had $273 million, $112 million and $136 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 2003, CG&E caused the remarketing by the Ohio Air Quality Development Authority of $84 million of its State of Ohio Air Quality Development Revenue Refunding Bonds, due September 1, 2030. The issuance consists of a $42 million 1995 Series A and a $42 million 1995 Series B. The remarketing effected the conversion from a daily interest rate reset mode supported by a letter of credit to an unsecured weekly interest rate mode. The interest rate for both series was initially set at 1.30 percent and will reset every seven days going forward. 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 the Balance Sheets of Cinergy and CG&E.
Also in August 2003, CG&E caused the remarketing by the Ohio Air Quality Development Authority of $12.1 million of its State of Ohio Air Quality Development Revenue Bonds 2001 Series A due August 1, 2033. The remarketing affected the conversion from an unsecured one-year interest rate reset mode to a daily interest rate reset
150
mode supported by a standby letter of credit. The interest rate was initially set at 0.95 percent and will be reset daily going forward. Because the holders of these notes have the right to have their notes redeemed on a daily basis, they are reflected in Notes payable and other short-term obligations on the Balance Sheets of Cinergy and CG&E.
In December 2003, PSI borrowed the proceeds from the issuance by the Indiana Development Finance Authority of $80.5 million of its Indiana Development Finance Authority Environmental Revenue Bonds due December 1, 2038. The issuance consists of two $40.25 million tranches designated Series 2003A and Series 2003B. The initial interest rate for both tranches was 1.27 percent and is reset weekly. Proceeds from the borrowing are being used for the acquisition and construction of various solid waste disposal facilities located at various generating stations in Indiana. The remaining funds are being held in escrow by an independent trustee and will be drawn down as the facilities are built. 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 the Balance Sheets of Cinergy and PSI.
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 percent 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.
Cinergy Corp.’s commercial paper program is supported by Cinergy Corp.’s $2 billion revolving credit facilities. 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, 2004, Cinergy Corp. had $676 million in commercial paper outstanding.
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.
151
The following table summarizes our Notes payable and other short-term obligations and Notes payable to affiliated companies.
|
| December 31, 2004 |
| December 31, 2003 |
| ||||||||||||
|
| Established Lines |
| Outstanding |
| Weighted Average Rate |
| Established Lines |
| Outstanding |
| Weighted Average Rate |
| ||||
|
| (in millions) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cinergy |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cinergy Corp. |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Revolving lines |
| $ | 2,000 |
| $ | — |
| — | % | $ | 1,000 |
| $ | — |
| — | % |
Uncommitted lines(1) |
| 40 |
| — |
| — |
| 40 |
| — |
| — |
| ||||
Commercial paper(2) |
|
|
| 676 |
| 2.45 |
|
|
| 146 |
| 1.18 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Utility operating companies |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Uncommitted lines(1) |
| 75 |
| — |
| — |
| 75 |
| — |
| — |
| ||||
Pollution control notes |
|
|
| 248 |
| 2.43 |
|
|
| 193 |
| 1.37 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Non-regulated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Revolving lines(3) |
| 158 |
| 8 |
| 5.67 |
| 19 |
| 10 |
| 5.90 |
| ||||
Short-term debt |
|
|
| 2 |
| 4.50 |
|
|
| 2 |
| 4.80 |
| ||||
Pollution control notes |
|
|
| 25 |
| 2.30 |
|
|
| — |
| — |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cinergy Total |
|
|
| $ | 959 |
| 2.47 | % |
|
| $ | 351 |
| 1.45 | % | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Uncommitted lines(1) |
| $ | 15 |
| $ | — |
| — | % | $ | 15 |
| — |
| — | % | |
Pollution control notes |
|
|
| 112 |
| 2.34 |
|
|
| 112 |
| 1.28 |
| ||||
Money pool |
|
|
| 180 |
| 2.38 |
|
|
| 49 |
| 1.11 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
CG&E Total |
|
|
| $ | 292 |
| 2.36 | % |
|
| $ | 161 |
| 1.23 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Uncommitted lines(1) |
| $ | 60 |
| $ | — |
| — | % | $ | 60 |
| $ | — |
| — | % |
Pollution control notes |
|
|
| 136 |
| 2.49 |
|
|
| 81 |
| 1.48 |
| ||||
Money pool |
|
|
| 130 |
| 2.38 |
|
|
| 188 |
| 1.11 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
PSI Total |
|
|
| $ | 266 |
| 2.44 | % |
|
| $ | 269 |
| 1.22 | % | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
ULH&P |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Money pool |
|
|
| $ | 11 |
| 2.38 | % |
|
| $ | 45 |
| 1.11 | % | ||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
ULH&P Total |
|
|
| $ | 11 |
| 2.38 | % |
|
| $ | 45 |
| 1.11 | % | ||
(1) 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. |
(2) In September 2004, Cinergy Corp. increased its commercial paper program limit from $800 million to $1.5 billion. The commercial paper program is supported by Cinergy Corp.’s revolving lines of credit. |
(3) In December 2004, Cinergy Canada, Inc. successfully placed a $150 million three-year senior revolving credit facility. |
In our credit facilities, 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 $1 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.
152
As part of PSI’s $500 million sublimit under the $1 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.
A breach of these covenants could result in the termination of the credit facilities and the acceleration of the related indebtedness. In addition to breaches of covenants, certain other events that could result in the termination of 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.
As discussed in Note 1(q)((iv)i), long-term debt increased in the third quarter of 2003 resulting from the adoption of Interpretation 46. The debt which was recorded as a result of this new accounting pronouncement did not cause Cinergy Corp. to be in breach of any covenants at the time of adoption. As of December 31, 2004, Cinergy, CG&E, and PSI are in compliance with all of their debt covenants.
6. 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, 2004:
|
| Lease Expense |
| Estimated Minimum Lease Payments |
| |||||||||||||||||||||||||||||
|
| 2002 |
| 2003 |
| 2004 |
| 2005 |
| 2006 |
| 2007 |
| 2008 |
| 2009 |
| Thereafter |
| Total |
| |||||||||||||
|
| (in millions) |
| |||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Cinergy(1) |
| $ | 64 |
| $ | 72 |
| $ | 85 |
| $ | 43 |
| $ | 36 |
| $ | 28 |
| $ | 18 |
| $ | 14 |
| $ | 27 |
| $ | 166 |
| |||
CG&E and subsidiaries |
| 30 |
| 34 |
| 36 |
| 10 |
| 8 |
| 7 |
| 5 |
| 4 |
| 6 |
| 40 |
| |||||||||||||
PSI |
| 23 |
| 31 |
| 32 |
| 11 |
| 10 |
| 9 |
| 7 |
| 6 |
| 13 |
| 56 |
| |||||||||||||
ULH&P |
| 4 |
| 4 |
| 4 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| |||||||||||||
(1) The results of Cinergy also include amounts related to non-registrants. |
(b)Capital Leases
In each of the years 1999 through 2004, 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 48 to 105 months. 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, 2004, 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.
153
The total minimum lease payments and the present values for these capital lease items are shown below:
|
| Total Minimum Lease Payments |
| ||||||||||
|
| Cinergy |
| CG&E and subsidiaries |
| PSI |
| ULH&P |
| ||||
|
| (in millions) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Total minimum lease payments(1) |
| $ | 79 |
| $ | 49 |
| $ | 30 |
| $ | 11 |
|
Less: amount representing interest |
| (14 | ) | (9 | ) | (5 | ) | (2 | ) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Present value of minimum lease payments |
| $ | 65 |
| $ | 40 |
| $ | 25 |
| $ | 9 |
|
(1) Annual minimum lease payments are immaterial. |
7. 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). Cinergy Corp. had three interest rate swaps with a combined notional amount of $250 million which settled in September 2004. These swaps qualified as fair value hedges under the provisions of Statement 133.
Treasury locks are agreements that fix the yield or price on a specified treasury security for a specified period, which we sometimes use in connection with the issuance of fixed-rate debt. On September 23, 2002, CG&E issued $500 million principal amount senior unsecured debentures due September 15, 2012, with an interest rate of 5.70 percent. In July 2002, CG&E executed a treasury lock with a notional amount of $250 million, which was designated as a cash flow hedge of 50 percent of the forecasted interest payments on this debt offering. The treasury lock effectively fixed the benchmark interest rate (i.e., the treasury component of the interest rate, but not the credit spread) for 50 percent of the offering from July 2002 through the issuance date in order to reduce the exposure associated with treasury rate volatility. With the issuance of the debt, the treasury lock was settled. Given the use of hedge accounting, this settlement was reflected in other Accumulated other comprehensive income (loss) on an after-tax basis in the amount of $13 million, rather than a charge to net income. This amount will be reclassified to InterestExpense over the 10-year life of the related debt as interest is accrued.
See Note 1(k)(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.
154
(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):
|
| December 31, 2004 |
| December 31, 2003 |
| ||||||||
Financial Instruments |
| Carrying Amount |
| Fair Value |
| Carrying Amount |
| Fair Value |
| ||||
|
| (in millions) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Cinergy(1) |
|
|
|
|
|
|
|
|
| ||||
First mortgage bonds and other long-term debt(2) |
| $ | 4,448 |
| $ | 4,710 |
| $ | 4,971 |
| $ | 5,297 |
|
|
|
|
|
|
|
|
|
|
| ||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
| ||||
First mortgage bonds and other long-term debt(2) |
| $ | 1,594 |
| $ | 1,641 |
| $ | 1,569 |
| $ | 1,582 |
|
|
|
|
|
|
|
|
|
|
| ||||
PSI |
|
|
|
|
|
|
|
|
| ||||
First mortgage bonds and other long-term debt(2) |
| $ | 1,874 |
| $ | 1,999 |
| $ | 1,720 |
| $ | 1,861 |
|
|
|
|
|
|
|
|
|
|
| ||||
ULH&P |
|
|
|
|
|
|
|
|
| ||||
Other long-term debt |
| $ | 94 |
| $ | 99 |
| $ | 55 |
| $ | 61 |
|
(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)Concentrations of 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, 2004, 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
155
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, 2004, approximately 93 percent of the 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. The remaining seven percent represents $59 million with counterparties rated non-investment grade.
As of December 31, 2004, CG&E had a concentration of trading credit exposure of approximately $45 million with two counterparties accounting for greater than 10 percent of CG&E’s total trading credit exposure. These counterparties are 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 may 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.
8. Notes Receivable
As discussed in Note 1(q)(i), Cinergy consolidated two previously unconsolidated SPEs effective July 1, 2003. As a result, Cinergy has approximately $214 million and $231 million of additional notes receivable as of December 31, 2004 and 2003, respectively, comprised of two separate notes.
The first note, with a December 31, 2004 balance of $101 million and a December 31, 2003 balance of $118 million, bears an effective interest rate of 7.81 percent and matures in August 2009. The second note, with a December 31, 2003 balance of $113 million as of December 31, 2004 and 2003, respectively, bears an effective interest rate of 9.23 percent and matures in December 2016.
The following table reflects the maturities of these notes.notes as of December 31, 2004.
Notes Receivable Maturities
|
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| 20 |
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| 94 |
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| 214 |
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156
9. 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 or benefit amount.
Benefits are accrued under the cash balance formula based upon a percentage of 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. Benefits earned under the traditional defined benefit pension formula ceased accruing at December 31, 2002 only for those employees who elected the cash balance formula. There was no change to retirement benefits earned through December 31, 2002 in converting to the cash balance formula. The pension benefits of all non-union and certain union employees hired after December 31, 2002 are calculated using the cash balance formula.
The introduction of the defined benefit plan with cash balance features did not have a material effect on our financial position or results of operations for 2003.
Funding for the qualified defined benefit pension plans is based on actuarially determined contributions, the maximum of which is generally the amount deductible for income 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
183
“core” portfolio is a domestic, investment grade portfolio. 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.
184
Cinergy’s qualified 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, 2004, approximately 80 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 an alternative investment strategy in its investment program. This strategy incorporates an investment in a fund of hedge funds in conjunction with an S&P 500 swaps and futures overlay program and will be classified as part of our large-cap United States equity allocation. Other than the alternative investment 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.
157
Cinergy uses a September 30 measurement date for its defined benefit pension plans. The asset allocation at September 30, 2004 and 2003 by asset category was as follows:
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| Percentage of Fair Value of Plan Assets at September 30 |
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Asset Category |
| 2004 |
| 2003 |
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Equity securities(1) |
| 62% |
| 62% |
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Debt securities(2) |
| 38% |
| 38% |
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(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 (65 percent) and debt (35 percent) securities at December 31, 2004, is not restricted to the payment of plan benefits and therefore, not considered plan assets under Statement 87. At December 31, 2004 and 2003, trust assets were approximately $10 million and $9 million, respectively, and are reflected in Cinergy’s Balance Sheets as Other investments.
In 2003 and 2002, Cinergy offered voluntary early retirement programs to certain individuals. In accordance with Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits (Statement 88), Cinergy recognized expense of approximately $9 million and $39 million in 2003 and 2002, respectively.
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, 2004, is not restricted to the payment of plan benefits and therefore, not considered plan assets under Statement 106. At December 31, 2004 and 2003, trust assets were approximately $71 million and $64 million, respectively, and are reflected in Cinergy’s Balance Sheets as Other investments.
Based on preliminary estimates, we expect 2005 contributions of $72 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:
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| Other |
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| Qualified Pension Benefits |
| Non-Qualified Pension Benefits |
| Postretirement Benefits |
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| (in millions) |
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2005 |
| $ | 77 |
| $ | 9 |
| $ | 25 |
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2006 |
| 76 |
| 9 |
| 26 |
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2007 |
| 77 |
| 9 |
| 27 |
| |||
2008 |
| 78 |
| 9 |
| 28 |
| |||
2009 |
| 80 |
| 11 |
| 29 |
| |||
Five years thereafter |
| 443 |
| 56 |
| 162 |
| |||
158
Our benefit plans’ costs for the past three years included the following components:
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| Qualified |
| Non-Qualified |
| Other |
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| Pension Benefits |
| Pension Benefits |
| Postretirement Benefits |
| ||||||||||||||||||||||
|
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
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| (in millions) |
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Service cost |
| $ | 35 |
| $ | 31 |
| $ | 27 |
| $ | 5 |
| $ | 3 |
| $ | 3 |
| $ | 5 |
| $ | 4 |
| $ | 3 |
| |
Interest cost |
| 89 |
| 86 |
| 79 |
| 7 |
| 7 |
| 5 |
| 22 |
| 23 |
| 20 |
| ||||||||||
Expected return on plans’ assets |
| (81 | ) | (81 | ) | (86 | ) | — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Amortization of transition (asset) obligation |
| (1 | ) | (1 | ) | (1 | ) | — |
| — |
| — |
| 1 |
| 3 |
| 5 |
| ||||||||||
Amortization of prior service cost |
| 5 |
| 5 |
| 6 |
| 2 |
| 1 |
| 1 |
| — |
| — |
| — |
| ||||||||||
Recognized actuarial (gain) loss |
| 2 |
| — |
| (6 | ) | 2 |
| 2 |
| 1 |
| 8 |
| 5 |
| 1 |
| ||||||||||
Voluntary early retirement costs (Statement 88) |
| — |
| 9 |
| 39 |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Net periodic benefit cost |
| $ | 49 |
| $ | 49 |
| $ | 58 |
| $ | 16 |
| $ | 13 |
| $ | 10 |
| $ | 36 |
| $ | 35 |
| $ | 29 |
| |
The net periodic benefit cost by registrant was as follows:
|
| Qualified |
| Non-Qualified |
| Other |
| |||||||||||||||||||||
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| Pension Benefits |
| Pension Benefits |
| Postretirement Benefits |
| |||||||||||||||||||||
|
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| |||||||||
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| (in millions) |
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Cinergy(1) |
| $ | 49 |
| $ | 49 |
| $ | 58 |
| $ | 16 |
| $ | 13 |
| $ | 10 |
| $ | 36 |
| $ | 35 |
| $ | 29 |
|
CG&E and subsidiaries |
| 15 |
| 10 |
| 7 |
| 1 |
| 1 |
| 1 |
| 9 |
| 9 |
| 7 |
| |||||||||
PSI |
| 13 |
| 12 |
| 12 |
| 1 |
| 1 |
| 1 |
| 20 |
| 18 |
| 15 |
| |||||||||
ULH&P |
| 1 |
| 1 |
| 2 |
| — |
| — |
| — |
| 1 |
| 1 |
| — |
| |||||||||
(1) The results of Cinergy also include amounts related to non-registrants.
159
The following table provides a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for 2004 and 2003, 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.
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| Other |
| ||||||||
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| Qualified |
| Non-Qualified |
| Postretirement |
| ||||||||||||
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| Pension Benefits |
| Pension Benefits |
| Benefits |
| ||||||||||||
|
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| ||||||
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| (in millions) |
| ||||||||||||||||
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Change in benefit obligation |
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| ||||||
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| ||||||
Benefit obligation at beginning of period |
| $ | 1,458 |
| $ | 1,315 |
| $ | 108 |
| $ | 98 |
| $ | 399 |
| $ | 343 |
|
|
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|
|
|
|
|
|
|
|
|
|
| ||||||
Service cost |
| 35 |
| 31 |
| 5 |
| 3 |
| 5 |
| 4 |
| ||||||
Interest cost |
| 88 |
| 86 |
| 7 |
| 7 |
| 22 |
| 23 |
| ||||||
Amendments(1) |
| (1 | ) | — |
| 8 |
| — |
| (24 | ) | (3 | ) | ||||||
Actuarial (gain) loss |
| 69 |
| 98 |
| — |
| 7 |
| 27 |
| 54 |
| ||||||
Benefits paid |
| (71 | ) | (72 | ) | (8 | ) | (7 | ) | (20 | ) | (22 | ) | ||||||
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| ||||||
Benefit obligation at end of period |
| 1,578 |
| 1,458 |
| 120 |
| 108 |
| 409 |
| 399 |
| ||||||
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|
|
| ||||||
Change in plan assets |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fair value of plan assets at beginning of period |
| 877 |
| 757 |
| — |
| — |
| — |
| — |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Actual return on plan assets |
| 98 |
| 118 |
| — |
| — |
| — |
| — |
| ||||||
Employer contribution |
| 117 |
| 74 |
| 8 |
| 7 |
| 20 |
| 22 |
| ||||||
Benefits paid |
| (71 | ) | (72 | ) | (8 | ) | (7 | ) | (20 | ) | (22 | ) | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fair value of plan assets at end of period |
| 1,021 |
| 877 |
| — |
| — |
| — |
| — |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Funded status |
| (557 | ) | (581 | ) | (120 | ) | (108 | ) | (409 | ) | (399 | ) | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Unrecognized prior service cost |
| 30 |
| 36 |
| 19 |
| 13 |
| (2 | ) | — |
| ||||||
Unrecognized net actuarial loss |
| 304 |
| 256 |
| 38 |
| 43 |
| 189 |
| 176 |
| ||||||
Unrecognized net transition (asset) obligation |
| — |
| (1 | ) | — |
| — |
| 4 |
| 27 |
| ||||||
Employer contribution |
| — |
| — |
| 2 |
| — |
| 5 |
| — |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Accrued benefit cost at December 31 |
| $ | (223 | ) | $ | (290 | ) | $ | (61 | ) | $ | (52 | ) | $ | (213 | ) | $ | (196 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Amounts recognized in balance sheets |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Accrued benefit liability |
| $ | (366 | ) | $ | (366 | ) | $ | (109 | ) | $ | (101 | ) | $ | (213 | ) | $ | (196 | ) |
Intangible asset |
| 30 |
| 22 |
| 19 |
| 13 |
| — |
| — |
| ||||||
Accumulated other comprehensive income (pre-tax) |
| 113 |
| 54 |
| 29 |
| 36 |
| — |
| — |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net recognized at end of period |
| $ | (223 | ) | $ | (290 | ) | $ | (61 | ) | $ | (52 | ) | $ | (213 | ) | $ | (196 | ) |
(1)For 2003, the Qualified Pension Benefits includes approximately $9 million of voluntary early retirement expenses in accordance with Statement 88, as previously discussed.
The accumulated benefit obligation for the qualified defined benefit pension plans was approximately $1,387 million and approximately $1,237 million for 2004 and 2003, respectively. The accumulated benefit obligation for the non-qualified defined benefit pension plans was approximately $111 million and $102 million for 2004 and 2003, respectively.
160
The weighted-average assumptions used to determine benefit obligations were as follows:
|
| Qualified |
| Non-Qualified Pension |
| Other |
| ||||||
|
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 6.25 | % | 6.25 | % | 6.25 | % | 6.25 | % | 5.75 | % | 6.25 | % |
Rate of future compensation increase |
| 4.00 |
| 4.00 |
| 4.00 |
| 4.00 |
| N/A |
| N/A |
|
The weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31, 2004, 2003, and 2002 were as follows:
|
| Qualified Pension Benefits |
| Non-Qualified Pension Benefits |
| Other Postretirement Benefits |
| ||||||||||||
|
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 6.25 | % | 6.75 | % | 7.50 | % | 6.25 | % | 6.75 | % | 7.50 | % | 6.25 | % | 6.75 | % | 7.50 | % |
Expected return on plans’ assets |
| 8.50 |
| 9.00 |
| 9.25 |
| N/A |
| N/A |
| N/A |
| N/A |
| N/A |
| 3.00 |
|
Rate of future compensation increase |
| 4.00 |
| 4.00 |
| 4.00 |
| 4.00 |
| 4.00 |
| 4.00 |
| N/A |
| N/A |
| N/A |
|
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 illiquidity, 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:
|
| 2004 |
| 2003 |
|
|
|
|
|
|
|
Health care cost trend rate assumed for next year |
| 8.00 | % | 9.00 | % |
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) |
| 5.00 | % | 5.00 | % |
Year that the rate reaches the ultimate trend rate |
| 2008 |
| 2008 |
|
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
|
| One-Percentage- Point Increase |
| One-Percentage- Point Decrease |
| ||
|
| (in millions) |
| ||||
|
|
|
|
|
| ||
Effect on total of service and interest cost components |
| $ | 4 |
| $ | (3 | ) |
Effect on APBO |
| 48 |
| (43 | ) | ||
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
161
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 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.
162
10. 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:
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ULH&P |
| |||||||||||||||||
|
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| |||||||||
|
| (in millions) |
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Deferred Income Tax Liability |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Property, plant, and equipment |
| $ | 1,706 |
| $ | 1,525 |
| $ | 971 |
| $ | 879 |
| $ | 656 |
| $ | 569 |
| $ | 63 |
| $ | 50 |
| |
Unamortized costs of reacquiring debt |
| 15 |
| 16 |
| 6 |
| 6 |
| 9 |
| 10 |
| — |
| — |
| |||||||||
Deferred operating expenses and carrying costs |
| — |
| 2 |
| — |
| 1 |
| — |
| — |
| — |
| — |
| |||||||||
Purchased power tracker |
| 4 |
| 4 |
| — |
| — |
| 4 |
| 4 |
| — |
| — |
| |||||||||
RTC |
| 194 |
| 204 |
| 194 |
| 204 |
| — |
| — |
| — |
| — |
| |||||||||
Net energy risk management assets |
| 51 |
| 10 |
| 5 |
| 10 |
| — |
| — |
| — |
| — |
| |||||||||
Amounts due from customers-income taxes |
| 39 |
| 47 |
| 28 |
| 26 |
| 11 |
| 22 |
| 2 |
| 4 |
| |||||||||
Gasification services agreement buyout costs |
| 86 |
| 86 |
| — |
| — |
| 86 |
| 86 |
| — |
| — |
| |||||||||
Other |
| 32 |
| 24 |
| 19 |
| 15 |
| 7 |
| — |
| — |
| 11 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Total Deferred Income Tax Liability |
| 2,127 |
| 1,918 |
| 1,223 |
| 1,141 |
| 773 |
| 691 |
| 65 |
| 65 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Deferred Income Tax Asset |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Unamortized investment tax credits |
| 39 |
| 39 |
| 29 |
| 30 |
| 11 |
| 9 |
| 1 |
| 1 |
| |||||||||
Accrued pension and other postretirement benefit costs |
| 222 |
| 195 |
| 60 |
| 98 |
| 65 |
| 58 |
| 5 |
| 4 |
| |||||||||
Net energy risk management liabilities |
| 28 |
| 9 |
| — |
| — |
| 28 |
| 9 |
| — |
| — |
| |||||||||
Deferred operating expenses and carrying costs |
| 26 |
| — |
| 9 |
| — |
| — |
| — |
| — |
| — |
| |||||||||
Rural Utilities Service obligation |
| 27 |
| 28 |
| — |
| — |
| 27 |
| 28 |
| — |
| — |
| |||||||||
Tax credit carryovers |
| 121 |
| 47 |
| — |
| — |
| — |
| — |
| — |
| — |
| |||||||||
Other |
| 67 |
| 42 |
| 34 |
| 28 |
| 4 |
| 13 |
| 1 |
| 5 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Total Deferred Income Tax Asset |
| 530 |
| 360 |
| 132 |
| 156 |
| 135 |
| 117 |
| 7 |
| 10 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Net Deferred Income Tax Liability |
| $ | 1,597 |
| $ | 1,558 |
| $ | 1,091 |
| $ | 985 |
| $ | 638 |
| $ | 574 |
| $ | 58 |
| $ | 55 |
| |
(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. Cinergy and its subsidiaries have an income tax allocation agreement, which conforms to the requirements of the PUHCA. 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.
163
The following table summarizes federal and state income taxes charged (credited) to income for Cinergy, CG&E, PSI, and ULH&P:
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ULH&P |
| ||||||||||||||||||||||||||||
|
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| ||||||||||||
|
| (in millions) |
| ||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Current Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Federal |
| $ | 78 |
| $ | 34 |
| $ | 16 |
| $ | 88 |
| $ | 84 |
| $ | 50 |
| $ | 52 |
| $ | 45 |
| $ | 71 |
| $ | 3 |
| $ | 1 |
| $ | 3 |
|
State |
| 30 |
| 25 |
| (4 | ) | 17 |
| 12 |
| 1 |
| 11 |
| 17 |
| 10 |
| — |
| 1 |
| 6 |
| ||||||||||||
Total Current Income Taxes |
| 108 |
| 59 |
| 12 |
| 105 |
| 96 |
| 51 |
| 63 |
| 62 |
| 81 |
| 3 |
| 2 |
| 9 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Deferred Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Federal |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Depreciation and other property, plant, and equipment-related items |
| 126 |
| 130 |
| 172 |
| 76 |
| 74 |
| 74 |
| 61 |
| 41 |
| 80 |
| 7 |
| 8 |
| 3 |
| ||||||||||||
Pension and other postretirement benefit costs |
| (29 | ) | 23 |
| (17 | ) | — |
| 10 |
| (5 | ) | (14 | ) | 7 |
| (7 | ) | — |
| — |
| — |
| ||||||||||||
Unrealized energy risk management transactions |
| 26 |
| 6 |
| 9 |
| 13 |
| 5 |
| 2 |
| 1 |
| 1 |
| (3 | ) | — |
| — |
| — |
| ||||||||||||
Fuel costs |
| (48 | ) | 7 |
| (23 | ) | (27 | ) | 5 |
| 9 |
| (21 | ) | 3 |
| (32 | ) | (1 | ) | — |
| (1 | ) | ||||||||||||
Purchased power tracker |
| 4 |
| (5 | ) | 2 |
| 5 |
| — |
| — |
| (1 | ) | (7 | ) | 2 |
| — |
| — |
| — |
| ||||||||||||
Gasification services agreement buyout costs |
| — |
| (3 | ) | (3 | ) | — |
| — |
| — |
| — |
| (3 | ) | (3 | ) | — |
| — |
| — |
| ||||||||||||
Tax credit carryovers |
| (74 | ) | (47 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||||
Other-net |
| 3 |
| (40 | ) | (14 | ) | (7 | ) | (20 | ) | 8 |
| 13 |
| (8 | ) | (8 | ) | — |
| (2 | ) | 1 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Total Deferred Federal Income Taxes |
| 8 |
| 71 |
| 126 |
| 60 |
| 74 |
| 88 |
| 39 |
| 34 |
| 29 |
| 6 |
| 6 |
| 3 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
State |
| (4 | ) | 22 |
| 30 |
| (1 | ) | 13 |
| 21 |
| 13 |
| 8 |
| 8 |
| 1 |
| 2 |
| — |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Total Deferred Income Taxes |
| 4 |
| 93 |
| 156 |
| 59 |
| 87 |
| 109 |
| 52 |
| 42 |
| 37 |
| 7 |
| 8 |
| 3 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Investment Tax Credits-Net |
| (8 | ) | (8 | ) | (8 | ) | (5 | ) | (5 | ) | (5 | ) | (3 | ) | (3 | ) | (3 | ) | — |
| — |
| — |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Total Income Taxes |
| $ | 104 |
| $ | 144 |
| $ | 160 |
| $ | 159 |
| $ | 178 |
| $ | 155 |
| $ | 112 |
| $ | 101 |
| $ | 115 |
| $ | 10 |
| $ | 10 |
| $ | 12 |
|
(1) The results of Cinergy also include amounts related to non-registrants.
Internal Revenue Code (IRC) Section 29 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 $98 million, $84 million, and $42 million for 2004, 2003, and 2002, respectively. See Note 11(c)(iv) for further information on this tax credit.
164
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.
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ULH&P |
| ||||||||||||||||||||||||||||
|
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| 2004 |
| 2003 |
| 2002 |
| ||||||||||||
|
| (in millions) |
| ||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Statutory federal income tax provision |
| $ | 167 |
| $ | 186 |
| $ | 186 |
| $ | 140 |
| $ | 158 |
| $ | 139 |
| $ | 89 |
| $ | 73 |
| $ | 109 |
| $ | 9 |
| $ | 9 |
| $ | 6 |
|
Increases (reductions) in taxes resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Amortization of investment tax credits |
| (8 | ) | (8 | ) | (8 | ) | (5 | ) | (5 | ) | (5 | ) | (3 | ) | (3 | ) | (3 | ) | — |
| — |
| — |
| ||||||||||||
Depreciation and other property, plant, and equipment-related differences |
| 8 |
| 4 |
| — |
| 4 |
| 1 |
| 1 |
| 4 |
| 4 |
| (1 | ) | — |
| (2 | ) | — |
| ||||||||||||
Preferred dividend requirements of subsidiaries |
| 1 |
| 1 |
| 1 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||||
Income tax credits |
| (97 | ) | (84 | ) | (42 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||||
Foreign tax adjustments |
| 4 |
| 5 |
| 3 |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||||
Employee SOP dividend |
| (7 | ) | (6 | ) | (3 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||||
Other-net |
| 10 |
| (1 | ) | (3 | ) | 4 |
| (1 | ) | (2 | ) | (2 | ) | 2 |
| (8 | ) | — |
| — |
| — |
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Federal Income Tax Expense |
| $ | 78 |
| $ | 97 |
| $ | 134 |
| $ | 143 |
| $ | 153 |
| $ | 133 |
| $ | 88 |
| $ | 76 |
| $ | 97 |
| $ | 9 |
| $ | 7 |
| $ | 6 |
|
(1) The results of Cinergy also include amounts related to non-registrants.
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11. Commitments and Contingencies
(a)Environmental
(i) Ozone Transport Rulemakings
In October 1998, the United States 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. We currently estimate that we will incur capital costs of approximately $23 million in addition to $777 million already incurred to comply with this program.
(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. Depending on the EPA’s final disposition of the pending petition and its proposal discussed previously, Cinergy’s generating stations could become subject to requirements for additional sulfur dioxide (SO2) and NOX emissions reductions. We expect a decision from the EPA on this matter by August 2005. It is unclear at this time whether any additional reductions would be necessary beyond those required under the CAA.
(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 (District Court) 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 Generating Station (Beckjord Station). The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s Beckjord Station and Miami Fort Station, and PSI’s Cayuga Generating Station, Gallagher Generating Station, Wabash River Generating Station, and Gibson Generating Station (Gibson Station), 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. The case is currently in discovery, and the District Court has set the case for trial by jury commencing in February 2006.
In March 2000, the United States also filed in the District Court 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 District Court in that case ruled that the Government and the intervening plaintiff environmental groups cannot seek
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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.
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 generating station operated by DP&L and jointly-owned by 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 Cinergy, DP&L and CSP for alleged violations of the CAA at this same generating station.
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. 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. Cinergy intends to defend these lawsuits vigorously in court and filed motions to dismiss with the other defendants in September 2004. 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
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 over an acid aerosol mist haze (plume) sometimes occurring in areas near the plant. Portions of the plume from those units’ stacks appeared to break apart and descend to ground level at certain times under certain weather conditions. As a result, and, working with the City of Mt. Carmel, Illinois, Illinois EPA, Indiana Department of Environmental Management (IDEM), EPA, and the State of Illinois, we developed a protocol regarding the use of the SCRs while we explored alternatives to address this issue. After the protocol was finalized, the Illinois Attorney General brought an action in Wabash County Circuit Court against PSI seeking a preliminary injunction to enforce the protocol. In August 2004, the court granted that preliminary injunction. PSI is appealing that decision to the Fifth District Appellate Court, but we cannot predict the ultimate outcome of that appeal or of the underlying action by the Illinois Attorney General.
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, Ohio laws against nuisance and common law nuisance. CG&E filed a motion to dismiss the lawsuit on primarily procedural grounds and we intend to defend against these claims vigorously. At this time, we cannot predict whether the outcome of this matter will have a material impact on our financial position or result of operations.
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(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. The IDEM oversees investigation and cleanup of all of these sites. 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 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. The trial court issued a variety of rulings with respect to the claims and defenses in the litigation. PSI appealed certain adverse rulings to the Indiana Court of Appeals and the appellate court remanded the case to the trial court. PSI settled 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 is considering whether to appeal this decision. At the present time, PSI cannot predict the outcome of this litigation if it were to appeal the decision.
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
CG&E and PSI have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 100 pending lawsuits. In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work at the 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. A majority of the lawsuits to date have been brought against PSI. 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 in the amount of approximately $500,000 on a negligence claim and a verdict for PSI on punitive damages. PSI received an adverse ruling in its initial appeal of the negligence claim verdict, but the Indiana Supreme Court accepted the transfer of the case and heard oral argument in June 2004. In addition, PSI has settled a number of other lawsuits for amounts, which neither individually nor in the aggregate, are material to PSI’s financial position or results of operations.
At this time, CG&E and PSI are not able to predict the ultimate outcome of these lawsuits or the impact on CG&E’s and PSI’s financial position or results of operations.
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(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 results in an approximate $140 million increase in annual revenues. PSI’s original request for an approximate $180 million annual revenue increase was reduced by approximately $20 million for a lower return on equity, approximately $15 million of assumed profits included in base rates related to off-system sales (subject to future adjustment through a tracking mechanism and a 50/50 sharing agreement), and approximately $5 million of additional items. The order authorizes full recovery of all requested regulatory assets and an overall 7.3 percent return, including a 10.5 percent return on equity. In addition, the IURC’s order provides 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 Independent Transmission System Operator, Inc. (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 pending SO2, NOX, and mercury emission reduction requirements, 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 operating and maintenance costs, among others, related to approximately $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 is scheduled for April 2005 and a final IURC Order is expected in the third quarter of 2005.
(iii) CG&E Electric Rate Filings
CG&E made multiple rate filings in 2003 with the PUCO seeking approval of CG&E’s methodology for establishing market-based rates for generation service at the end of the market development period and to recover investments made in the transmission and distribution system. The PUCO requested in these proceedings that CG&E propose a RSP to mitigate the potential for significant rate increases when the market development (frozen rate) period comes to an end. In January 2004, CG&E filed its proposed RSP. In May 2004, CG&E entered into a settlement agreement with many of the parties to these proceedings requesting that the PUCO approve a modified version of the RSP. In September 2004, the PUCO issued an order seeking to modify several key provisions of this settlement and as a result of these modifications, CG&E filed a petition for rehearing in October 2004. The PUCO approved a modified version of the plan in November 2004, the major features of which are as follows:
•Provider of Last Resort (POLR) Charge:CG&E will begin to collect a POLR charge from non-residential customers effective January 1, 2005, and from residential customers effective January 1, 2006. The POLR charge includes several discrete charges, the most significant being an annually adjusted component (AAC) intended to provide cost recovery primarily for environmental compliance expenditures; an infrastructure maintenance fund charge (IMF) intended to provide compensation to CG&E for committing its physical capacity to meet its POLR obligation; anda system reliability tracker (SRT) intended to provide cost recovery for capacity purchases, purchased power, reserve capacity, and related market costs for purchases to meet capacity needs. We anticipate the collection of the AAC and IMF will result in an approximate $36 million increase in revenues in 2005 and an additional $50 million in 2006. The SRT will be billed based on dollar-for-dollar costs incurred. A portion of these charges are avoidable by certain customers who switch to an alternative generation supplier. Therefore, these estimates are subject to change, depending on the level of switching that occurs in future periods. In 2007 and 2008, CG&E could seek additional increases in the AAC component of the POLR based on CG&E’s actual net costs for the specified expenditures.
•Generation Rates and Fuel Recovery: A new rate has been established for generation service after the market development period ends. In addition, a fuel cost recovery mechanism will be established to recover costs 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 will apply to
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non-residential customers beginning January 1, 2005 and to residential customers beginning January 1, 2006.
•Generation Rate Reduction: The existing five percent generation rate reduction required by statute for residential customers implemented under CG&E’s 2000 plan will end on December 31, 2005.
•Transmission Cost Recovery: Transmission cost recovery mechanisms will be established beginning January 1, 2005 for non-residential customers and January 1, 2006 for residential customers. The transmission cost recovery mechanisms will 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.
•Distribution Cost Recovery: CG&E will have 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 beginning January 1, 2006 through December 31, 2010.
CG&E had also filed an electric distribution base rate case for residential and non-residential customers to be effective January 1, 2005. Under the terms of the RSP described previously, CG&E withdrew this base rate case and, in February 2005, CG&E filed a new distribution base rate case with rates to become effective January 1, 2006. The requested amount of the increase is approximately $78 million.
(iv) ULH&P Gas Rate Case
In the second quarter of 2001, ULH&P filed a retail gas rate case with the KPSC requesting, among other things, recovery of costs associated with an accelerated gas main replacement program of up to $112 million over ten years. The costs would be recovered through a tracking mechanism for an initial three year period, with the possibility of renewal up to ten years. The tracking mechanism allows ULH&P to recover depreciation costs and rate of return annually over the life of the deferred assets. Through December 31, 2004, ULH&P has recovered approximately $5.1 million under this tracking mechanism. The Kentucky Attorney General has appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism and the new tracking mechanism rates. 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. ULH&P is requesting approval to continue the tracking mechanism in addition to its request for a $14 million increase in base rates, which is a seven percent increase in current retail gas rates.
(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 the approximately 5,000 SHA risers will not be material. At this time, Cinergy, CG&E,and ULH&P cannot predict the outcome of this matter.
(c)Other
(i) Gas Customer Choice
In January 2000, Investments sold Cinergy Resources, Inc. (Resources), a former subsidiary, to Licking Rural Electrification, Inc., doing business as The Energy Cooperative (Energy Cooperative). In February 2001, Cinergy, CG&E, and Resources were named as defendants in three class action lawsuits brought by customers relating to Energy Cooperative’s removal from the Ohio Gas Customer Choice program and the failure to deliver gas to customers. Subsequently, these class action suits were amended and consolidated into one suit (Class-action). In October 2001, Cinergy, CG&E, and Investments initiated litigation against Energy Cooperative requesting
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indemnification by Energy Cooperative for the claims asserted by former customers in the Class-action litigation (Cinergy lawsuit).
In March 2001, Cinergy, CG&E, and Investments were named as defendants in a lawsuit filed by Energy Cooperative and Resources (Energy Cooperative lawsuit). This lawsuit concerned any obligations or liabilities Investments may have had to Energy Cooperative following its sale of Resources. All three matters were settled in the second quarter of 2004. In the Energy Cooperative lawsuit, Energy Cooperative agreed to indemnify Cinergy, CG&E and Investments for the claims asserted by the former residential customers in the Class-action litigation. In exchange, Cinergy has agreed to settle claims that it brought in the Cinergylawsuit. The settlement received final court approval in January 2005. None of these settlements are material to Cinergy’s financial position or results of operations.
(ii) Energy Market Investigations
In July 2003, Cinergy received a subpoena from the Commodity Futures Trading Commission (CFTC). The CFTC request sought certain information regarding our trading activities, including price reporting to energy industry publications for the period May 2000 through January 2001. Based on our review of these matters, we terminated one employee and took disciplinary action on a second employee. In November 2004, we settled this matter with the CFTC with a payment of $3 million.
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. 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. We believe this action against Marketing & Trading is without merit and intend to defend this lawsuit vigorously.
In the second quarter of 2003, Cinergy received initial and follow-up third-party subpoenas from the SEC requesting information related to particular trading activity with one of its counterparties who was the target of an investigation by the SEC. Cinergy fully cooperated with the SEC in connection with this matter and has received no further requests since the second quarter of 2003.
From time to time, Cinergy receives subpoenas regarding investigations into energy market practices that various Assistant United States Attorneys are conducting. We understand that we are neither a target nor into energy market practices are we under investigation by the Department of Justice in relation to any of these communications.
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.
(iii) Patents
Ronald A. Katz Technology Licensing, L.P. (RAKTL) has offered us a license to a portfolio of patents claiming that the patents may be infringed by certain products and services utilized by us. The patents purportedly relate to various aspects of telephone call processing in Cinergy call centers. As of this date, no legal proceedings have been instituted against us, but if the RAKTL patents are valid, enforceable, and apply to our business, we could be required to seek a license from RAKTL or to discontinue certain activities. Based on the information we have at this time, we do not believe resolution of this matter will have a material impact on our financial position or results of operations.
(iv) Synthetic Fuel Production
In July 2002, Capital & Trading acquired a coal-based synthetic fuel production facility. The synthetic fuel produced at this facility qualifies for tax credits (through 2007) in accordance with IRC Section 29 if certain
171
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.
During the third quarter of 2004, several unrelated entities announced that the IRS had or threatened to challenge the placed in service dates of some of the entities’ synthetic fuel plants. A successful IRS challenge could result in disallowance of all credits previously claimed for fuel produced by the subject plants. Cinergy’s sale of synthetic fuel has generated approximately $219 million in tax credits through December 31, 2004, of which approximately $96 million were generated in 2004.
The IRS has not yet audited Cinergy for any tax year in which Cinergy has claimed Section 29 credits related to synthetic fuel. However, it is reasonable to anticipate that the IRS will evaluate the placed in service date and other key requirements for claiming the credit. We anticipate this audit to begin in the spring of 2005.
Cinergy received a private letter ruling from the IRS in connection with the acquisition of the facility that specifically addressed the significant chemical change requirement. Additionally, although not addressed in the letter ruling, we believe that our facility’s in service date meets the Section 29 requirements.
IRC Section 29 also provides for a phase-out of the credit based on the price of crude oil. The phase-out is based on a prescribed calculation and definition of crude oil prices. We do not expect any impact on our ability to utilize Section 29 credits in 2004. Future increases in crude oil prices above the price stipulated by the IRS could negatively impact our ability to utilize credits in subsequent years.
(v) 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 entitieson 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 has guaranteed the payment of approximately $9 million as of December 31, 2004, for borrowings by individuals under the Director, Officer, and Key Employee Stock Purchase Program. Cinergy may be 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. The guarantees do not have a set termination date; however, the borrowings associated with these guarantees are due in March 2005.
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, operations 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, 2004. 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 thesecontracts 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
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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 beforeany 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 $128 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 2005 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.
(vi) Construction and Other Commitments
Forecasted construction and other committed expenditures for the year 2005 and for the five-year period 2005-2009 (in nominal dollars) are presented in the table below:
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| 2005 |
| 2005-2009 |
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| (in millions) |
| ||||
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|
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Cinergy(1) |
| $ | 1,115 |
| $ | 5,430 |
|
CG&E and subsidiaries |
| 430 |
| 2,345 |
| ||
PSI |
| 620 |
| 2,645 |
| ||
ULH&P |
| 80 |
| 335 |
| ||
(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.
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12. 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, 2004, CG&E’s and PSI’s investments in jointly-owned plant or facilities were as follows:
|
| Ownership |
| Property, Plant, and |
| Accumulated |
| Construction Work in |
| |||
|
| Share |
| Equipment |
| Depreciation |
| Progress |
| |||
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| (in millions) |
| |||||||||
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|
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|
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|
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| |||
CG&E |
|
|
|
|
|
|
|
|
| |||
Production: |
|
|
|
|
|
|
|
|
| |||
Miami Fort Station (Units 7 and 8) |
| 64.00 | % | $ | 328 |
| $ | 133 |
| $ | 18 |
|
Beckjord Station (Unit 6) |
| 37.50 |
| 45 |
| 29 |
| — |
| |||
Stuart Station(1) |
| 39.00 |
| 384 |
| 161 |
| 15 |
| |||
Conesville Station (Unit 4)(1) |
| 40.00 |
| 76 |
| 48 |
| 5 |
| |||
Zimmer Station |
| 46.50 |
| 1,308 |
| 438 |
| 4 |
| |||
East Bend Station |
| 69.00 |
| 394 |
| 200 |
| 5 |
| |||
Killen Station(1) |
| 33.00 |
| 206 |
| 112 |
| 1 |
| |||
Transmission |
| Various |
| 88 |
| 44 |
| — |
| |||
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|
|
|
|
|
|
|
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| |||
PSI |
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|
|
|
|
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| |||
Production: |
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|
|
|
|
|
|
|
| |||
Gibson Station (Unit 5) |
| 50.05 |
| 287 |
| 131 |
| 6 |
| |||
Transmission and local facilities |
| 94.54 |
| 2,567 |
| 1,006 |
| — |
| |||
(1) Station is not operated by CG&E.
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13. Quarterly Financial Data (unaudited)
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| Second |
| Third |
| Fourth |
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2004 |
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|
| ||||||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| ||||||||
Operating Revenues |
| $ | 1,289 |
| $ | 1,054 |
| $ | 1,129 |
| $ | 1,216 |
| $ | 4,688 |
| |||
Operating Income |
| 216 |
| 137 |
| 183 |
| 202 |
| 738 |
| ||||||||
Net Income |
| 103 |
| 59 |
| 93 |
| 146 |
| 401 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Per Share Data: |
|
|
|
|
|
|
|
|
|
|
| ||||||||
EPS - basic: |
|
|
|
|
|
|
|
|
|
|
| ||||||||
Net Income |
| 0.57 |
| 0.33 |
| 0.51 |
| 0.81 |
| 2.22 |
| ||||||||
EPS - diluted: |
|
|
|
|
|
|
|
|
|
|
| ||||||||
Net Income |
| 0.57 |
| 0.32 |
| 0.50 |
| 0.79 |
| 2.18 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
2003 |
|
|
|
|
|
|
|
|
|
|
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| ||||||||
Operating Revenues |
| $ | 1,268 |
| $ | 934 |
| $ | 1,092 |
| $ | 1,122 |
| $ | 4,416 |
| |||
Operating Income |
| 256 |
| 138 |
| 205 |
| 212 |
| 811 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| 140 |
| 76 |
| 112 |
| 107 |
| 435 |
| ||||||||
Discontinued operations, net of tax(2) |
| — |
| 9 |
| — |
| — |
| 9 |
| ||||||||
Cumulative effect of changes in accounting principles, net of tax(3) |
| 26 |
| — |
| — |
| — |
| 26 |
| ||||||||
Net Income |
| $ | 166 |
| $ | 85 |
| $ | 112 |
| $ | 107 |
| $ | 470 |
| |||
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Per Share Data: |
|
|
|
|
|
|
|
|
|
|
| ||||||||
EPS - basic: |
|
|
|
|
|
|
|
|
|
|
| ||||||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| 0.81 |
| 0.42 |
| 0.63 |
| 0.60 |
| 2.46 |
| ||||||||
Discontinued operations, net of tax(2) |
| — |
| 0.05 |
| — |
| — |
| 0.05 |
| ||||||||
Cumulative effect of changes in accounting principles, net of tax(3) |
| 0.15 |
| — |
| — |
| — |
| 0.15 |
| ||||||||
Net Income |
| $ | 0.96 |
| $ | 0.47 |
| $ | 0.63 |
| $ | 0.60 |
| $ | 2.66 |
| |||
EPS - diluted: |
|
|
|
|
|
|
|
|
|
|
| ||||||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| 0.80 |
| 0.42 |
| 0.62 |
| 0.59 |
| 2.43 |
| ||||||||
Discontinued operations, net of tax(2) |
| — |
| 0.05 |
| — |
| — |
| 0.05 |
| ||||||||
Cumulative effect of changes in accounting principles, net of tax(3) |
| 0.15 |
| — |
| — |
| — |
| 0.15 |
| ||||||||
Net Income |
| $ | 0.95 |
| $ | 0.47 |
| $ | 0.62 |
| $ | 0.59 |
| $ | 2.63 |
| |||
175
|
| First |
| Second |
| Third |
| Fourth |
|
|
| |||||
|
| Quarter |
| Quarter |
| Quarter |
| Quarter |
| Total |
| |||||
|
| (in millions, except per share amounts) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2004 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues |
| $ | 765 |
| $ | 546 |
| $ | 554 |
| $ | 646 |
| $ | 2,511 |
|
Operating Income |
| 144 |
| 106 |
| 120 |
| 120 |
| 490 |
| |||||
Net Income |
| 77 |
| 55 |
| 64 |
| 61 |
| 257 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2003 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues |
| $ | 704 |
| $ | 483 |
| $ | 541 |
| $ | 654 |
| $ | 2,382 |
|
Operating Income |
| 157 |
| 102 |
| 144 |
| 160 |
| 563 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Income before cumulative effect of changes in accounting principles |
| 86 |
| 51 |
| 79 |
| 84 |
| 300 |
| |||||
Cumulative effect of changes in accounting principles, net of tax(3) |
| 31 |
| — |
| — |
| — |
| 31 |
| |||||
Net Income |
| $ | 117 |
| $ | 51 |
| $ | 79 |
| $ | 84 |
| $ | 331 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
PSI |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2004 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues |
| $ | 416 |
| $ | 414 |
| $ | 480 |
| $ | 444 |
| $ | 1,754 |
|
Operating Income |
| 87 |
| 67 |
| 112 |
| 93 |
| 359 |
| |||||
Net Income |
| 41 |
| 25 |
| 48 |
| 51 |
| 165 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2003 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues |
| $ | 412 |
| $ | 361 |
| $ | 437 |
| $ | 393 |
| $ | 1,603 |
|
Operating Income |
| 74 |
| 55 |
| 89 |
| 96 |
| 314 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Income before cumulative effect of a change in accounting principle |
| 34 |
| 23 |
| 38 |
| 39 |
| 134 |
| |||||
Cumulative effect of a change in accounting principle, net of tax(3) |
| (1 | ) | — |
| — |
| — |
| (1 | ) | |||||
Net Income |
| $ | 33 |
| $ | 23 |
| $ | 38 |
| $ | 39 |
| $ | 133 |
|
(1) The results of Cinergy also include amounts related to non-registrants.
(2) See Note 14 for further explanation.
(3) See Note 1(q)(iv) for further explanation of cumulative effect of changes in accounting principles.
176
14. Discontinued Operations
During 2002, Cinergy began taking steps to monetize certain non-core investments, including renewable and international investments within Commercial. During the second half of 2002, Cinergy either sold or initiated plans to dispose of generation and electric and gas distribution operations in the Czech Republic, Estonia, and South Africa. Cinergy also sold investments, which were accounted for under the equity method, in renewable investments located in Spain and California. In total, Cinergy disposed of approximately $125 million of investments at a net loss, after-tax, of $7 million in 2002. Included in this net loss were cumulative foreign currency translation losses of approximately $4 million, after-tax.
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).
GAAP requires different accounting treatment for investment disposals involving entities which are consolidated and entities which are accounted for under the equity method. The consolidated entities have been presented as Discontinued operations, net of tax in Cinergy’s Statements of Income and as Assets/Liabilities of Discontinued Operations in Cinergy’s Balance Sheets. The accompanying financial statements and prior year financial statements have been reclassified to account for these entities as such. The disposal of the entities accounted for using the equity method cannot be presented as discontinued operations. A gain of approximately $17 million on the sale of these entities is included in Miscellaneous Income (Expense)-Net in Cinergy’s 2002 Statements of Income.
177
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, 2003 and 2002. We did not have any investments accounted for as discontinued operations in 2004.
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (in millions) |
| ||||
|
|
|
|
|
| ||
Revenues(1) |
| $ | 22 |
| $ | 95 |
|
|
|
|
|
|
| ||
Income (Loss) Before Taxes |
| $ | 4 |
| $ | (27 | ) |
|
|
|
|
|
| ||
Income Taxes Benefit |
| $ | 4 |
| $ | 2 |
|
|
|
|
|
|
| ||
Income (Loss) from Discontinued Operations |
|
|
|
|
| ||
Income (Loss) from operations, net of tax |
| $ | — |
| $ | (1 | ) |
Gain (Loss) on disposal, net of tax(2) |
| 9 |
| (24 | ) | ||
|
|
|
|
|
| ||
Total Income (Loss) from Discontinued Operations |
| $ | 9 |
| $ | (25 | ) |
|
|
|
|
|
| ||
Assets |
|
|
|
|
| ||
Current assets |
| $ | 5 |
| $ | 49 |
|
Property, plant, and equipment-net |
| — |
| 78 |
| ||
Other assets |
| — |
| 20 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 5 |
| $ | 147 |
|
|
|
|
|
|
| ||
Liabilities |
|
|
|
|
| ||
Current liabilities |
| $ | 12 |
| $ | 7 |
|
Long-term debt (including Long-term debt due within one year) |
| — |
| 85 |
| ||
Other |
| — |
| 17 |
| ||
|
|
|
|
|
| ||
Total Liabilities |
| $ | 12 |
| $ | 109 |
|
(1) Presented for informational purposes only. All results of operations are reported net in our Statements of Income.
(2) For 2002, approximately $17 million of this amount represents a write-down to fair value, less cost to sell, on assets classified as held for sale at December 31, 2002. The remaining loss on disposal for 2002 represents actual losses on completed sales.
The losses included in the 2002 discontinued operations primarily pertain to two investments. In one case, the primary customer of a combined heat and power plant filed for bankruptcy resulting in a significant reduction in future expected revenues from the investment. This investment was sold in December 2002. In the second case, the retail market of a gas distribution business did not develop as expected, and we elected to exit the business rather than invest the additional capital which would be required to reach a sustainable level of market penetration. The investment was written down to its realizable value in December 2002 and was subsequently sold in April 2003.
178
15. Investment Activity
(a)Investment Impairment
Cinergy holds a portfolio of direct and indirect investments in Power Technology and Infrastructure (discussed further in Note 16). 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 approximately $21 million relating to this sale. These earnings are reflected in Equity in Earnings of Unconsolidated Subsidiaries in Cinergy’s Statements of Income.
16. Financial Information by Business Segment
We conduct operations through our subsidiaries and manage our businesses through the following three reportable segments:
•Commercial;
•Regulated; and
•Power Technology and Infrastructure.
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.
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.
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.
179
Financial results by business unit for the years ended December 31, 2004, 2003, and 2002, by asset category was as follows:
|
| Percentage of Fair Value of |
| ||
Asset Category |
| 2003 |
| 2002 |
|
|
|
|
|
|
|
Equity securities(1) |
| 62 | % | 50 | % |
Debt securities(2) |
| 38 | % | 50 | % |
(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, we sponsor non-qualified pension plans (plans that do not meet the criteria for 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 (63 percent) and debt (37 percent) securities at December 31, 2003, is not restricted to the payment of plan benefits and therefore, not considered plan assets under Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions. At December 31, 2003 and 2002, trust assets were approximately $9 million and $8 million, respectively, and are reflected in Cinergy’s Balance Sheets as Other investments.
In 2003 and 2002, Cinergy offered voluntary early retirement programs to certain individuals. In accordance with Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits (Statement 88), Cinergy recognized an expense of $8.5 million and $39.1 million in 2003 and 2002, respectively.
We provide certain health care and life insurance benefits to retired U.S. 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 (63 percent) and debt (37 percent) securities at December 31, 2003, is not restricted to the payment of plan benefits and therefore, not considered plan assets under Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (Statement 106). At December 31, 2003 and 2002, trust assets were approximately $64 million and $52 million, respectively, and are reflected in Cinergy’s Balance Sheets as Other investments.
Based on preliminary estimates, we expect 2004 contributions of $107 million for qualified pension benefits. In addition, we expect to make contributions of $8 million and $27 million in 2004 for non-qualified pension benefits and other postretirement benefits, respectively.
185
Our benefit plans’ costs for the past three years included the following components:
|
| Qualified |
| Non-Qualified |
| Other |
| ||||||||||||||||||||||
|
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
| ||||||||||
|
| (in millions) |
| ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Service cost |
| $ | 31.3 |
| $ | 27.3 |
| $ | 27.9 |
| $ | 3.3 |
| $ | 2.7 |
| $ | 2.1 |
| $ | 4.1 |
| $ | 3.5 |
| $ | 3.8 |
| |
Interest cost |
| 85.9 |
| 79.2 |
| 77.5 |
| 6.4 |
| 5.1 |
| 4.8 |
| 22.4 |
| 19.6 |
| 17.9 |
| ||||||||||
Expected return on plans’ assets |
| (80.8 | ) | (86.3 | ) | (81.9 | ) | — |
| — |
| — |
| — |
| (0.3 | ) | — |
| ||||||||||
Amortization of transition (asset) obligation |
| (1.0 | ) | (1.3 | ) | (1.3 | ) | — |
| 0.1 |
| 0.1 |
| 3.3 |
| 5.0 |
| 5.0 |
| ||||||||||
Amortization of prior service cost |
| 4.8 |
| 6.2 |
| 4.6 |
| 1.3 |
| 0.9 |
| 1.1 |
| — |
| — |
| — |
| ||||||||||
Recognized actuarial (gain) loss |
| — |
| (5.4 | ) | (3.2 | ) | 2.1 |
| 0.8 |
| 0.6 |
| 5.2 |
| 1.1 |
| 0.1 |
| ||||||||||
Voluntary early retirement costs (Statement 88) |
| 8.5 |
| 38.6 |
| — |
| — |
| 0.5 |
| — |
| — |
| — |
| — |
| ||||||||||
Net periodic benefit cost |
| $ | 48.7 |
| $ | 58.3 |
| $ | 23.6 |
| $ | 13.1 |
| $ | 10.1 |
| $ | 8.7 |
| $ | 35.0 |
| $ | 28.9 |
| $ | 26.8 |
| |
The net periodic benefit cost by registrant was as follows:
|
| Qualified |
| Non-Qualified |
| Other |
| |||||||||||||||||||||
|
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
| |||||||||
|
| (in millions) |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Cinergy(1) |
| $ | 48.7 |
| $ | 58.3 |
| $ | 23.6 |
| $ | 13.1 |
| $ | 10.1 |
| $ | 8.7 |
| $ | 35.0 |
| $ | 28.9 |
| $ | 26.8 |
|
CG&E and subsidiaries |
| 9.7 |
| 7.2 |
| 1.9 |
| 1.0 |
| 1.1 |
| 1.7 |
| 9.0 |
| 7.2 |
| 6.9 |
| |||||||||
PSI |
| 11.7 |
| 12.2 |
| 7.5 |
| 0.7 |
| 0.6 |
| 0.7 |
| 17.6 |
| 15.3 |
| 13.5 |
| |||||||||
ULH&P |
| 1.0 |
| 1.7 |
| 0.3 |
| — |
| — |
| — |
| 0.9 |
| 0.4 |
| 0.4 |
| |||||||||
(1) The results of Cinergy also include amounts related to non-registrants.
186
The following table provides a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for 2003 and 2002, 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.
|
| Qualified |
| Non-Qualified |
| Other |
| ||||||||||||
|
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| ||||||
|
| (in millions) |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Change in benefit obligation |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Benefit obligation at beginning of period |
| $ | 1,314.9 |
| $ | 1,083.5 |
| $ | 97.8 |
| $ | 70.9 |
| $ | 343.2 |
| $ | 270.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Service cost |
| 31.3 |
| 27.3 |
| 3.3 |
| 2.7 |
| 4.1 |
| 3.5 |
| ||||||
Interest cost |
| 85.9 |
| 79.2 |
| 6.4 |
| 5.1 |
| 22.4 |
| 19.6 |
| ||||||
Amendments(1) |
| 0.3 |
| 43.3 |
| 0.1 |
| 4.5 |
| (3.3 | ) | (12.3 | ) | ||||||
Actuarial loss |
| 97.9 |
| 156.5 |
| 7.4 |
| 20.6 |
| 54.3 |
| 80.2 |
| ||||||
Benefits paid |
| (72.5 | ) | (74.9 | ) | (7.4 | ) | (6.0 | ) | (22.0 | ) | (18.2 | ) | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Benefit obligation at end of period |
| 1,457.8 |
| 1,314.9 |
| 107.6 |
| 97.8 |
| 398.7 |
| 343.2 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Change in plan assets |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fair value of plan assets at beginning of period |
| 756.5 |
| 875.4 |
| — |
| — |
| — |
| — |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Actual return on plan assets |
| 119.3 |
| (48.0 | ) | — |
| — |
| — |
| — |
| ||||||
Employer contribution |
| 74.0 |
| 4.0 |
| 7.4 |
| 6.0 |
| 22.0 |
| 18.2 |
| ||||||
Benefits paid |
| (72.5 | ) | (74.9 | ) | (7.4 | ) | (6.0 | ) | (22.0 | ) | (18.2 | ) | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fair value of plan assets at end of period |
| 877.3 |
| 756.5 |
| — |
| — |
| — |
| — |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Funded status |
| (580.5 | ) | (558.4 | ) | (107.6 | ) | (97.8 | ) | (398.7 | ) | (343.2 | ) | ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Unrecognized prior service cost |
| 35.4 |
| 48.4 |
| 12.3 |
| 13.5 |
| — |
| — |
| ||||||
Unrecognized net actuarial loss |
| 255.5 |
| 196.2 |
| 43.1 |
| 37.6 |
| 175.7 |
| 125.5 |
| ||||||
Unrecognized net transition (asset) obligation |
| (0.8 | ) | (1.9 | ) | — |
| 0.1 |
| 26.9 |
| 33.5 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Benefit cost at December 31 |
| $ | (290.4 | ) | $ | (315.7 | ) | $ | (52.2 | ) | $ | (46.6 | ) | $ | (196.1 | ) | $ | (184.2 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Amounts recognized in balance sheets |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Accrued benefit liability |
| $ | (366.2 | ) | $ | (353.0 | ) | $ | (100.5 | ) | $ | (89.0 | ) | $ | (196.1 | ) | $ | (184.2 | ) |
Intangible asset |
| 22.1 |
| 32.6 |
| 12.3 |
| 13.6 |
| — |
| — |
| ||||||
Accumulated other comprehensive income (pre-tax) |
| 53.7 |
| 4.7 |
| 36.0 |
| 28.8 |
| — |
| — |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net recognized at end of period |
| $ | (290.4 | ) | $ | (315.7 | ) | $ | (52.2 | ) | $ | (46.6 | ) | $ | (196.1 | ) | $ | (184.2 | ) |
187
(1) For 2003, the amount of $0.3 million includes $8.5 million of voluntary early retirement expenses in accordance with Statement 88, as previously discussed. For 2002, the amounts of $43.3 million and $4.5 million include $38.6 million and $0.5 million, respectively, of voluntary early retirement expenses in accordance with Statement 88, as previously discussed.
The accumulated benefit obligation for the qualified defined benefit pension plans was $1,237.3 million and $1,101.7 million for 2003 and 2002, respectively. The accumulated benefit obligation for the non-qualified defined benefit pension plans was $102.1 million and $90.4 million for 2003 and 2002, respectively.
The weighted-average assumptions used to determine benefit obligations were as follows:
|
| Qualified |
| Non-Qualified |
| Other |
| ||||||
|
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 6.25 | % | 6.75 | % | 6.25 | % | 6.75 | % | 6.25 | % | 6.75 | % |
Rate of future compensation increase |
| 4.00 |
| 4.00 |
| 4.00 |
| 4.00 |
| N/A |
| N/A |
|
The weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows:
|
| Qualified |
| Non-Qualified |
| Other |
| ||||||||||||
|
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
| 6.75 | % | 7.50 | % | 7.50 | % | 6.75 | % | 7.50 | % | 7.50 | % | 6.75 | % | 7.50 | % | 7.50 | % |
Expected return on plans’ assets |
| 9.00 |
| 9.25 |
| 9.00 |
| N/A |
| N/A |
| N/A |
| N/A |
| 3.00 |
| N/A |
|
Rate of future compensation increase |
| 4.00 |
| 4.00 |
| 4.50 |
| 4.00 |
| 4.00 |
| 4.50 |
| N/A |
| N/A |
| N/A |
|
Cinergy’s expected long-term rate of return on plan assets is based on a calculation provided by an independent investment-consulting firm. The calculation of the expected 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 illiquidity, 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. We periodically request a new calculation for use in validating our current expected long-term rate of return.
The assumed health care cost trend rates were as follows:
188
|
| 2003 |
| 2002 |
|
|
|
|
|
|
|
Health care cost trend rate assumed for next year |
| 9.00 | % | 7.00 | % |
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) |
| 5.00 | % | 5.00 | % |
Year that the rate reaches the ultimate trend rate |
| 2008 |
| 2008 |
|
189
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
|
| One-Percentage- |
| One-Percentage- |
| ||
|
| (in millions) |
| ||||
|
|
|
|
|
| ||
Effect on total of service and interest cost components |
| $ | 4.1 |
| $ | (3.5 | ) |
Effect on accumulated postretirement benefit obligation |
| 52.1 |
| (45.7 | ) | ||
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. In January 2004, the FASB staff issued FASB Staff Position 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (FSP 106-1). FSP 106-1 allows sponsors of postretirement health care plans that provide a prescription drug benefit to make a one-time election to defer accounting for certain provisions of the Act until further authoritative guidance is issued by FASB. Alternatively, sponsors not electing the deferral option must account for the effects of the Act. Cinergy is required to make its election on whether it will defer accounting for the effects of the Act by the first quarter of 2004. Cinergy expects that it will not elect the deferral option but will account for the subsidy as a reduction of our accumulated postretirement benefit obligation with actuarial gain/loss treatment.
In accordance with the provisions of Statement 106, the Act had no effect on Cinergy’s reported 2003 accumulated postretirement benefit obligation, measured at September 30, 2003, or our 2003 net periodic postretirement benefit costs. Cinergy expects that the FASB will issue final authoritative guidance on accounting for the subsidy during 2004. Depending upon the timing of such guidance and our conclusion of whether or not to defer reflecting the effects of the Act, our net periodic postretirement benefit costs reported during the interim periods of 2004 could change.
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 will have the opportunity to make a one-time election to remain in Cinergy’s current retiree healthcare program or to move to 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 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.
190
10. Income Taxes
The following table shows the significant components of Cinergy’s, CG&E’s, and PSI’s net deferred income tax liabilities as of December 31:
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| ||||||||||||
|
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| 2003 |
| 2002 |
| ||||||
|
| (in millions) |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Deferred Income Tax Liability |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Property, plant, and equipment |
| $ | 1,524.8 |
| $ | 1,373.6 |
| $ | 879.0 |
| $ | 803.1 |
| $ | 569.1 |
| $ | 520.3 |
|
Unamortized costs of reacquiring debt |
| 15.9 |
| 13.9 |
| 5.8 |
| 2.8 |
| 10.1 |
| 11.0 |
| ||||||
Deferred operating expenses and carrying costs |
| 1.6 |
| 4.4 |
| 1.6 |
| — |
| — |
| 4.4 |
| ||||||
Purchased power tracker |
| 3.9 |
| 11.6 |
| — |
| — |
| 3.9 |
| 11.6 |
| ||||||
RTC |
| 204.2 |
| 213.2 |
| 204.2 |
| 213.2 |
| — |
| — |
| ||||||
Net energy risk management assets |
| 10.0 |
| 8.8 |
| 9.7 |
| 1.0 |
| — |
| — |
| ||||||
Amounts due from customers-income taxes |
| 47.6 |
| 37.4 |
| 26.0 |
| 20.1 |
| 21.6 |
| 17.3 |
| ||||||
Gasification services agreement buyout costs |
| 85.8 |
| 89.8 |
| — |
| — |
| 85.8 |
| 89.8 |
| ||||||
Other |
| 24.6 |
| 14.4 |
| 15.3 |
| 10.9 |
| — |
| 1.2 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total Deferred Income Tax Liability |
| 1,918.4 |
| 1,767.1 |
| 1,141.6 |
| 1,051.1 |
| 690.5 |
| 655.6 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Deferred Income Tax Asset |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Unamortized investment tax credits |
| 39.3 |
| 42.5 |
| 30.1 |
| 32.9 |
| 9.2 |
| 9.6 |
| ||||||
Accrued pension and other postretirement benefit costs |
| 195.6 |
| 196.3 |
| 97.9 |
| 107.5 |
| 58.2 |
| 60.1 |
| ||||||
Net energy risk management liabilities |
| 8.8 |
| — |
| — |
| — |
| 8.8 |
| 9.0 |
| ||||||
Rural Utilities Service obligation |
| 27.9 |
| 28.2 |
| — |
| — |
| 27.9 |
| 28.2 |
| ||||||
Tax credit carryovers |
| 47.0 |
| — |
| — |
| — |
| — |
| — |
| ||||||
Other |
| 41.8 |
| 41.9 |
| 28.1 |
| 28.1 |
| 12.5 |
| 10.0 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Total Deferred Income Tax Asset |
| 360.4 |
| 308.9 |
| 156.1 |
| 168.5 |
| 116.6 |
| 116.9 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net Deferred Income Tax Liability |
| $ | 1,558.0 |
| $ | 1,458.2 |
| $ | 985.5 |
| $ | 882.6 |
| $ | 573.9 |
| $ | 538.7 |
|
(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. Cinergy and its subsidiaries have an income tax allocation agreement, which conforms to the requirements of the PUHCA. 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.
191
The following table summarizes federal and state income taxes charged (credited) to income for Cinergy, CG&E, and PSI:
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| |||||||||||||||||||||
|
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
| |||||||||
|
| (in millions) |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Current Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Federal |
| $ | 33.5 |
| $ | 16.3 |
| $ | 129.4 |
| $ | 83.9 |
| $ | 50.6 |
| $ | 135.1 |
| $ | 44.6 |
| $ | 71.1 |
| $ | 59.9 |
|
State |
| 24.9 |
| (4.1 | ) | 9.3 |
| 11.9 |
| 0.6 |
| 7.6 |
| 17.5 |
| 9.7 |
| 4.6 |
| |||||||||
Total Current Income Taxes |
| 58.4 |
| 12.2 |
| 138.7 |
| 95.8 |
| 51.2 |
| 142.7 |
| 62.1 |
| 80.8 |
| 64.5 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Deferred Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Federal |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Depreciation and other property, plant, and equipment-related items(2) |
| 129.4 |
| 172.2 |
| 42.7 |
| 73.8 |
| 73.6 |
| 23.3 |
| 40.8 |
| 79.6 |
| 10.7 |
| |||||||||
Pension and other postretirement benefit costs |
| 22.9 |
| (17.4 | ) | (11.8 | ) | 9.7 |
| (4.7 | ) | (4.2 | ) | 7.4 |
| (7.4 | ) | (7.6 | ) | |||||||||
Deferred excise taxes |
| — |
| — |
| 14.5 |
| — |
| — |
| 14.5 |
| — |
| — |
| — |
| |||||||||
Unrealized energy risk management transactions |
| 6.1 |
| 9.0 |
| 44.0 |
| 5.4 |
| 2.2 |
| 23.9 |
| 0.5 |
| (2.8 | ) | 11.6 |
| |||||||||
Fuel costs |
| 7.2 |
| (22.7 | ) | 5.7 |
| 4.6 |
| 8.8 |
| (8.0 | ) | 2.6 |
| (31.5 | ) | 13.7 |
| |||||||||
Purchased power tracker |
| (4.6 | ) | 1.5 |
| 8.5 |
| — |
| — |
| — |
| (6.4 | ) | 1.5 |
| 8.5 |
| |||||||||
Gasification services agreement buyout costs |
| (3.2 | ) | (2.6 | ) | (2.2 | ) | — |
| — |
| — |
| (3.2 | ) | (2.6 | ) | (2.2 | ) | |||||||||
Tax credit carryovers |
| (47.0 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| |||||||||
Other-net |
| (39.5 | ) | (14.1 | ) | 10.9 |
| (19.7 | ) | 8.3 |
| (4.8 | ) | (8.3 | ) | (7.5 | ) | 5.3 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Total Deferred Federal Income Taxes |
| 71.3 |
| 125.9 |
| 112.3 |
| 73.8 |
| 88.2 |
| 44.7 |
| 33.4 |
| 29.3 |
| 40.0 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
State |
| 21.7 |
| 30.4 |
| 15.4 |
| 13.2 |
| 20.8 |
| 5.0 |
| 8.3 |
| 7.8 |
| 4.8 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Total Deferred Income Taxes |
| 93.0 |
| 156.3 |
| 127.7 |
| 87.0 |
| 109.0 |
| 49.7 |
| 41.7 |
| 37.1 |
| 44.8 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Investment Tax Credits-Net |
| (7.9 | ) | (8.2 | ) | (9.1 | ) | (4.7 | ) | (4.9 | ) | (5.9 | ) | (3.2 | ) | (3.2 | ) | (3.2 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Total Income Taxes |
| $ | 143.5 |
| $ | 160.3 |
| $ | 257.3 |
| $ | 178.1 |
| $ | 155.3 |
| $ | 186.5 |
| $ | 100.6 |
| $ | 114.7 |
| $ | 106.1 |
|
(1) The results of Cinergy also include amounts related to non-registrants.
(2) The increase from 2001 to 2002 in deferred income taxes for depreciation and other property, plant, and equipment-related items includes a change in accounting method for tax purposes related to capitalized costs.
Internal Revenue Code Section 29 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 $83.7 million, $41.6 million, and $1.1 million for 2003, 2002, and 2001, respectively.
192
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, and PSI.
|
| Cinergy(1) |
| CG&E and subsidiaries |
| PSI |
| |||||||||||||||||||||
|
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
| 2003 |
| 2002 |
| 2001 |
| |||||||||
|
| (in millions) |
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Statutory federal income tax provision |
| $ | 186.0 |
| $ | 185.7 |
| $ | 235.3 |
| $ | 158.6 |
| $ | 139.2 |
| $ | 175.2 |
| $ | 73.0 |
| $ | 109.0 |
| $ | 90.7 |
|
Increases (reductions) in taxes resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Amortization of investment tax credits |
| (7.9 | ) | (8.2 | ) | (9.1 | ) | (4.7 | ) | (4.9 | ) | (5.9 | ) | (3.2 | ) | (3.2 | ) | (3.2 | ) | |||||||||
Depreciation and other property, plant, and equipment-related differences |
| 4.3 |
| 0.2 |
| 3.2 |
| 0.5 |
| 1.0 |
| 2.6 |
| 3.7 |
| (0.8 | ) | 0.6 |
| |||||||||
Preferred dividend requirements of subsidiaries |
| 1.2 |
| 1.2 |
| 1.2 |
| — |
| — |
| — |
| — |
| — |
| — |
| |||||||||
Income tax credits |
| (83.7 | ) | (41.6 | ) | (2.1 | ) | — |
| — |
| — |
| — |
| — |
| — |
| |||||||||
Foreign tax adjustments |
| 5.1 |
| 3.2 |
| (2.1 | ) | — |
| — |
| — |
| — |
| — |
| — |
| |||||||||
Employee Stock Option Plan dividend |
| (6.5 | ) | (3.0 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| |||||||||
Other-net |
| (1.6 | ) | (3.5 | ) | 6.2 |
| (1.4 | ) | (1.4 | ) | 2.0 |
| 1.3 |
| (7.8 | ) | 8.6 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Federal Income Tax Expense |
| $ | 96.9 |
| $ | 134.0 |
| $ | 232.6 |
| $ | 153.0 |
| $ | 133.9 |
| $ | 173.9 |
| $ | 74.8 |
| $ | 97.2 |
| $ | 96.7 |
|
(1) The results of Cinergy also include amounts related to non-registrants.
The following table shows the significant components of ULH&P’s net deferred income tax liability as of December 31, 2003 and 2002:
|
| ULH&P |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (in thousands) |
| ||||
|
|
|
|
|
| ||
Deferred Income Tax Liability |
|
|
|
|
| ||
Property, plant, and equipment |
| $ | 49,662 |
| $ | 44,309 |
|
Unamortized costs of reacquiring debt |
| 599 |
| 652 |
| ||
Amounts due from customers-income taxes |
| 3,926 |
| 2,194 |
| ||
Deferred fuel costs |
| 1,631 |
| — |
| ||
Other |
| 9,764 |
| 6,340 |
| ||
|
|
|
|
|
| ||
Total Deferred Income Tax Liability |
| 65,582 |
| 53,495 |
| ||
|
|
|
|
|
| ||
Deferred Income Tax Asset |
|
|
|
|
| ||
Unamortized investment tax credits |
| 1,160 |
| 1,309 |
| ||
Deferred fuel costs |
| — |
| 1,987 |
| ||
Accrued pension and other postretirement benefit costs |
| 4,444 |
| 4,410 |
| ||
Other |
| 4,490 |
| 2,429 |
| ||
|
|
|
|
|
| ||
Total Deferred Income Tax Asset |
| 10,094 |
| 10,135 |
| ||
|
|
|
|
|
| ||
Net Deferred Income Tax Liability |
| $ | 55,488 |
| $ | 43,360 |
|
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The following table summarizes federal and state income taxes charged (credited) to income for ULH&P:
|
| ULH&P |
| |||||||
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Current Income Taxes |
|
|
|
|
|
|
| |||
Federal |
| $ | 783 |
| $ | 3,250 |
| $ | 23,109 |
|
State |
| 1,190 |
| 5,984 |
| (2,293 | ) | |||
Total Current Income Taxes |
| 1,973 |
| 9,234 |
| 20,816 |
| |||
|
|
|
|
|
|
|
| |||
Deferred Income Taxes |
|
|
|
|
|
|
| |||
Federal |
|
|
|
|
|
|
| |||
Depreciation and other property, plant, and equipment-related items |
| 8,032 |
| 2,797 |
| 1,042 |
| |||
Pension and other benefit costs |
| 258 |
| (309 | ) | (140 | ) | |||
Fuel costs |
| — |
| (696 | ) | (7,338 | ) | |||
Unamortized costs of reacquiring debt |
| — |
| (70 | ) | (30 | ) | |||
Service company allocations |
| — |
| — |
| 192 |
| |||
Other-net |
| (1,857 | ) | 1,138 |
| 212 |
| |||
|
|
|
|
|
|
|
| |||
Total Deferred Federal Income Taxes |
| 6,433 |
| 2,860 |
| (6,062 | ) | |||
|
|
|
|
|
|
|
| |||
Deferred State Income Taxes |
| 1,640 |
| 522 |
| (781 | ) | |||
|
|
|
|
|
|
|
| |||
Total Deferred Income Taxes |
| 8,073 |
| 3,382 |
| (6,843 | ) | |||
|
|
|
|
|
|
|
| |||
Investment Tax Credits-Net |
| (265 | ) | (267 | ) | (274 | ) | |||
|
|
|
|
|
|
|
| |||
Total Income Taxes |
| $ | 9,781 |
| $ | 12,349 |
| $ | 13,699 |
|
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 ULH&P.
|
| ULH&P |
| |||||||
|
| 2003 |
| 2002 |
| 2001 |
| |||
|
| (in thousands) |
| |||||||
|
|
|
|
|
|
|
| |||
Statutory federal income tax provision |
| $ | 9,093 |
| $ | 6,298 |
| $ | 18,444 |
|
Increases (reductions) in taxes resulting from: |
|
|
|
|
|
|
| |||
Amortization of investment tax credits |
| (265 | ) | (267 | ) | (274 | ) | |||
Depreciation and other property, plant, and equipment-related differences |
| (1,379 | ) | (387 | ) | 23 |
| |||
Other-net |
| (498 | ) | 199 |
| (1,420 | ) | |||
|
|
|
|
|
|
|
| |||
Federal Income Tax Expense |
| $ | 6,951 |
| $ | 5,843 |
| $ | 16,773 |
|
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11. Commitments and Contingencies
(a)Environmental
(i) Ozone Transport Rulemakings
In June 1997, the Ozone Transport Assessment Group, which consisted of 37 states, made a wide range of recommendations to the U.S. Environmental Protection Agency (EPA) to address the impact of ozone transport on serious non-attainment areas (geographic areas defined by the EPA as non-compliant with ozone standards) in the Northeast, Midwest, and South. Ozone transport refers to wind-blown movement of ozone and ozone-causing materials across city and state boundaries.
1. Nitrogen Oxide (NOX) State Implementation Plan (SIP) Call
In October 1998, the EPA finalized its ozone transport rule, also known as the NOX SIP Call. It applied to 22 states in the eastern half of the U.S., including the three states in which our electric utilities operate, and proposed a model NOX emission allowance trading program. This rule recommended that states reduce NOX emissions primarily from industrial and utility sources to a certain level by May 2003.
In August 2000, the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals) extended the deadline for NOX reductions to May 31, 2004. The states of West Virginia and Illinois, along with various industry groups (some of which we are a member), have challenged portions of the final rule in an action filed in the Court of Appeals. A decision is expected some time in the first quarter of 2004. It is unclear whether the Court of Appeals’ decision in this matter will result in an increase or decrease in the size of the NOX reduction requirement, or a deferral of the May 31, 2004 compliance deadline.
The states of Indiana and Kentucky developed final NOX SIP rules in response to the NOX SIP Call, through cap and trade programs, in June and July of 2001, respectively. The EPA has approved Indiana’s and Kentucky’s SIP rules, which have both become effective, and has conditionally approved Ohio’s SIP rules. Ohio Environmental Protection Agency is still promulgating the changes to its rules to satisfy the EPA’s conditions for approval. Cinergy’s current plans for compliance with the EPA’s NOX SIP Call would also satisfy compliance with Indiana’s, Kentucky’s, and Ohio’s SIP rules.
In September 2000, Cinergy announced a plan for its subsidiaries, CG&E and PSI, to invest in pollution control equipment and other methods to reduce NOX emissions. This plan includes the following:
• install selective catalytic reduction units at several different generating stations;
• install other pollution control technologies, including new computerized combustion controls, at all generating stations;
• make combustion improvements; and
• utilize the NOX allowance market to buy or sell NOX allowances as appropriate.
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The current estimate for additional expenditures for this plan is approximately $104 million and is in addition to the $685 million already incurred to comply with this program.
2. Section 126 Petitions
In February 1998, several northeast states filed petitions seeking the EPA’s assistance in reducing ozone in the Eastern U.S. under Section 126 of the Clean Air Act (CAA). The EPA believes that Section 126 petitions allow a state to claim that sources in another state are contributing to its air quality problem and request that the EPA require the upwind sources to reduce their emissions.
In December 1999, the EPA granted four Section 126 petitions relating to NOX emissions. This ruling affected all of our Ohio and Kentucky facilities, as well as some of our Indiana facilities, and required us to reduce our NOX emissions to a certain level by May 2003. The EPA subsequently extended the Section 126 rule compliance deadline to May 31, 2004, thus harmonizing the deadline with that for the NOX SIP Call.
In April 2003, the EPA issued a proposed rule withdrawing the Section 126 rule in states with approved SIPs under the NOX SIP Call, which include the states of Indiana and Kentucky. The proposed rule states that the EPA will withdraw the Section 126 rule in Ohio once Ohio has a fully approved SIP. As a result of these actions, we anticipate that the Section 126 rule will be withdrawn and, as a result, not affect any of our facilities.
(ii) Clean Air Act Lawsuit
In November 1999, and through subsequent amendments, the United States brought a lawsuit in the United States Federal District Court (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 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 Generating Station (Beckjord Station). The suit seeks (1) injunctive relief to require installation of pollution control technology on various generating units at CG&E’s Beckjord Station and Miami Fort Generating Station (Miami Fort Station), and PSI’s Cayuga Generating Station, Gallagher Generating Station, Wabash River Generating Station, and Gibson Generating Station (Gibson Station), 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. The case is currently in discovery, and the District Court has set the case for trial by jury commencing in August 2005.
In March 2000, the United States also filed 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 the 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 District Court in that case
196
ruled that the Government and the intervening plaintiff environmental groups could seek injunctive relief for alleged violations that occurred more than five years before the filing of the complaint only. Thus, if the plaintiffs prevail in their claims, any calculation for penalties will not start on the date of the alleged violations, unless those alleged violations occurred after November 3, 1994, but CSP would be forced to install the controls required under the CAA. Neither party appealed that decision.
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 SIP requirements at a generating station operated by DP&L and jointly-owned by CG&E. The NOV indicated the EPA may (1) issue an order requiring compliance with the requirements of the SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation.
In December 2000, Cinergy, CG&E, and PSI reached an agreement in principle with the plaintiffs regarding the above matters. The complete resolution of these issues was contingent upon establishing a final agreement with the EPA and other parties. Although we have continued to negotiate with the plaintiffs to achieve a final agreement, the plaintiffs have insisted on commitments from us which go beyond those contained in the agreement in principle. At this time we believe it is unlikely that a final settlement agreement will be reached on these terms. If a final settlement agreement is not reached, we intend to defend against the allegations, discussed above, vigorously in court. In such an event it is not possible to predict whether resolution of these matters would have a material effect on our financial position or results of operations.
(iii) Manufactured Gas Plant (MGP) Sites
Prior to the 1950s, gas was produced at MGP sites through a process that involved the heating of coal and/or oil. The gas produced from this process was sold for residential, commercial, and industrial uses.
Coal tar residues, related hydrocarbons, and various metals have been found at former MGP sites in Indiana, including 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).
In a combination of lawsuits and notices of violation, 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. The Indiana Department of Environmental Management (IDEM) oversees investigation and cleanup of all of these sites. 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 sites for which PSI has primary responsibility.
PSI notified its insurance carriers of the claims related to MGP sites raised by IDEM and costs included in the Site Participation and Cost Sharing Agreements. In April 1998, PSI filed suit in
197
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. The trial court issued a variety of rulings with respect to the claims and defenses in the litigation. PSI appealed certain adverse rulings to the Indiana Court of Appeals and the appellate court has remanded the case to the trial court. A new trial date has yet to be scheduled. At the present time, PSI cannot predict the outcome of this litigation, including the outcome of the appeals.
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 if 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 has performed site assessments on its sites where we believe MGP activities have occurred at some point in the past and found no imminent risk to the environment.
(iv) Asbestos Claims Litigation
CG&E and PSI have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 80 pending lawsuits. In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work at the 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. A majority of the lawsuits to date have been brought against PSI. 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 in the amount of approximately $500,000 on a negligence claim and for PSI on punitive damages. PSI recently received an adverse ruling in an appeal of that verdict and is reviewing whether to appeal the verdict to the Indiana Supreme Court. In addition, we have settled a number of other lawsuits for amounts, which neither individually nor in the aggregate are material to CG&E’s and PSI’s financial position or results of operations.
At this time, CG&E and PSI are not able to predict the ultimate outcome of these lawsuits or the impact on CG&E’s and PSI’s financial position or results of operations.
(b)Regulatory
(i) PSI Retail Electric Rate Case
In December 2002, PSI filed a petition with the IURC seeking approval of a base retail electric rate increase. PSI has filed initial and rebuttal testimony in this case and the final set of hearings
198
took place in November 2003. PSI filed its proposed order in December 2003. Based on updated testimony filed in October 2003 and the proposed order, PSI proposes an increase in annual revenues of approximately $180 million, or an average increase of approximately 14 percent over PSI’s retail electric rates in effect at the end of 2002. An IURC decision is anticipated by the end of the first quarter of 2004.
(ii) PSI Fuel Adjustment Charge
In June 2001, PSI filed a petition with the IURC requesting authority to recover $16 million in under billed deferred fuel costs incurred from March 2001 through May 2001. The IURC approved recovery of these costs subject to refund pending the findings of an investigative sub-docket. The sub-docket was opened to investigate the reasonableness of, and underlying reasons for, the under billed deferred fuel costs. A hearing was held in July 2002, and in March 2003 the IURC issued an order giving final approval to PSI’s recovery of the $16 million.
(iii) PSI Construction Work in Progress (CWIP) Ratemaking Treatment for NOX Equipment
In April 2003, PSI filed an application with the IURC requesting that its CWIP rate adjustment mechanism be updated for expenditures through December 2002 related to NOX equipment currently being installed at certain PSI generation facilities. CWIP ratemaking treatment allows for the recovery of carrying costs on certain pollution control equipment while and after the equipment is under construction. A final order was issued in September 2003. The order granted substantially all of PSI’s requested relief, leaving only the issue of whether certain specific equipment qualified for CWIP ratemaking treatment to be decided in the first half of 2004. This CWIP rate mechanism adjustment resulted in less than a one percent increase in customer rates.
In October 2003, PSI filed an application with the IURC requesting that its CWIP rate adjustment mechanism be updated for additional expenditures through September 30, 2003, related to NOX equipment currently being installed at certain PSI generation facilities. If the application is approved, it will result in the recovery of an additional $7 million. An order on this third CWIP update case is expected in the first half of 2004.
PSI’s initial CWIP rate mechanism adjustment (authorized in July 2002) resulted in an approximately one percent increase in customer rates. Under the IURC’s CWIP rules, PSI may update its CWIP tracker at six-month intervals. The first such update to PSI’s CWIP rate mechanism occurred in the first quarter of 2003. The IURC’s July 2002 order also authorized PSI to defer, for subsequent recovery, post-in-service depreciation and to continue the accrual for AFUDC. Pursuant to Statement of Financial Accounting Standards No. 92, Regulated Enterprises-Accounting for Phase-in Plans, the equity component of AFUDC will not be deferred for financial reporting after the related assets are placed in service.
(iv) PSI Environmental Compliance Cost Recovery
In 2002, the Indiana General Assembly passed legislation that, among other things, encourages the deployment of advanced technologies that reduce regulated air emissions, while allowing the continued use of high sulfur Midwest coal in existing electric generating plants. The legislation
199
authorizes the IURC to provide financial incentives to utilities that deploy such advanced technologies. PSI soughtIURC approval, under this new law, of a cost tracking mechanism for PSI’s NOX equipment-related depreciation and operation and maintenance costs, authority to use accelerated (18-year) depreciation for its NOX compliance equipment, and approval of a NOX emission allowance purchase and sales tracker. In October 2003, PSI reached a settlement with the other parties to this case that provides for the relief described above for most of PSI’s environmental compliance equipment. In December 2003, the IURC approved the settlement agreement. Previously, the majority of these costs (the post-in-service depreciation costs) were being deferred pursuant to the July 2002 CWIP order described above, and as a result, the settlement agreement did not have a material impact on PSI’s results of operations or financial condition.
(v) PSI Purchased Power Tracker
The Tracker was designed to provide for the recovery of costs related to certain specified purchases of power necessary to meet native load customers’ summer peak demand requirements to the extent such costs are not recovered through the existing fuel adjustment clause.
PSI is authorized to seek recovery of 90 percent of its purchased power expenses through the Tracker (net of the displaced energy portion recovered through the fuel recovery process and net of the mitigation credit portion), with the remaining 10 percent deferred for subsequent recovery in PSI’s general retail electric rate case. In March 2002, PSI filed a petition with the IURC seeking approval to extend the Tracker process beyond the summer of 2002. A hearing was held in January 2003, and in June 2003 the IURC approved the extension for up to an additional two years with the ultimate determination concerning PSI’s continued use of the Tracker process to be made in PSI’s pending retail electric rate case.
In June 2002, PSI also filed a petition with the IURC seeking approval of the recovery through the Tracker of its actual summer 2002 purchased power costs. In May 2003, the IURC approved PSI’s recovery of $18 million related to its summer 2002 purchased power costs, and also authorized $2 million of deferred costs sought for recovery in PSI’s general retail electric rate case.
(vi) CG&E Transmission and Distribution Rate Filings
In October 2003, CG&E filed an application with the PUCO seeking deferral of approximately $173 million, of which approximately $42 million has been incurred as of December 31, 2003, in depreciation, property taxes and carrying costs related to net additions to transmission and distribution utility plant in service from January 2001 through December 2005. Rates are frozen in Ohio under the state’s electric restructuring law from 2001 through the end of the market development period. CG&E has not deferred any of these costs as of December 31, 2003.
CG&E is proposing a mechanism to recover costs related to net additions to transmission and distribution utility plant in service after the end of the market development period. The mechanism would work in a similar manner to the monthly customer charge the PUCO approved for CG&E’s accelerated natural gas main replacement program, discussed belowin (vii), which is adjusted annually based on expenditures in the previous year.
200
In the alternative electric reliability and rate stabilization proposal that CG&E filed in January 2004 with the PUCO, which is described in more detail in Note 17 below, CG&E made an alternative proposal to seek deferrals of transmission and distribution utility plant in service from January 2003 through December 2004, for the PUCO to declare an end to the market development period effective December 31, 2004, and for CG&E to file a transmission and distribution base rate case in 2004 to be effective January 1, 2005. The alternative proposal also includes tracking mechanisms as described in the preceding paragraph, which would recover ongoing transmission and distribution costs.
(vii) CG&E Gas Rate Case
In the third quarter of 2001, CG&E filed a retail gas rate case with the PUCO seeking to increase base rates for natural gas distribution service and requesting recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with an estimated capital cost of $716 million over 10 years. An order was issued in May 2002, in which the PUCO authorized a base rate increase of approximately $15 million, or 3.3 percent overall, effective May 30, 2002. In addition, the PUCO authorized CG&E to implement the tracking mechanism to recover the costs of the accelerated gas main replacement program, subject to certain rate caps that increase in amount annually through May 2007, through the effective date of new rates in CG&E’s next retail gas rate case. In April 2003, CG&E received approval to increase its rates under the tracking mechanism by $6.5 million. This increase was effective in May 2003. CG&E filed another application in January 2004 to increase its rates by approximately $7 million under the tracking mechanism. CG&E expects that the PUCO will rule on this application in the second quarter of 2004.
(viii) ULH&P Gas Rate Case
In the second quarter of 2001, ULH&P filed a retail gas rate case with the KPSC seeking to increase base rates for natural gas distribution services and requesting recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with an estimated capital cost of $112 million over 10 years. Through December 31, 2003, ULH&P has recovered approximately $1.4 million under this tracking mechanism. The Kentucky Attorney General has appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism and the KPSC’s orders approving the new tracking mechanism rates. At the present time, ULH&P cannot predict the timing or outcome of this litigation.
(ix) 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. Cinergy has an estimated 190,000 SHA risers on its distribution system, of which 155,000 are in CG&E’s service area and 31,000 are in ULH&P’s service area. Further investigation as to whether any additional SHA risers will need maintenance or replacement is ongoing. If CG&E and ULH&P
201
determine that replacement of all SHA risers is appropriate, we currently estimate that the replacement cost could be up to approximately $70 million. CG&E and ULH&P would pursue recovery of this cost through rates. At this time, Cinergy, CG&E, and ULH&P cannot predict the outcome of this matter.
(c)Other
(i) Gas Customer Choice
In January 2000, Investments sold Cinergy Resources, Inc. (Resources), a former subsidiary, to Licking Rural Electrification, Inc., doing business as The Energy Cooperative (Energy Cooperative). In February 2001, Cinergy, CG&E, and Resources were named as defendants in three class action lawsuits brought by customers relating to Energy Cooperative’s removal from the Ohio Gas Customer Choice program and the failure to deliver gas to customers. Subsequently, these class action suits were amended and consolidated into one suit. CG&E has been dismissed as a defendant in the consolidated suit. This customer litigation is pending in the Hamilton County Common Pleas Court. The trial court certified a class against CG&E in November 2003. A trial date has not been set.
In March 2001, Cinergy, CG&E, and Investments were named as defendants in a lawsuit filed by Energy Cooperative and Resources. This lawsuit concerns any obligations or liabilities Investments may have to Energy Cooperative following its sale of Resources. This lawsuit is pending in the Licking County Common Pleas Court. Trial is anticipated to occur in November 2004. In October 2001, Cinergy, CG&E, and Investments initiated litigation against the Energy Cooperative requesting indemnification by the Energy Cooperative for the claims asserted by former customers in the class action litigation. We intend to vigorously defend these lawsuits and do not believe their outcome will have a material effect on our financial position or results of operations.
(ii) Contract Disputes
Cinergy, through a subsidiary of Investments, has been involved in negotiations to resolve a customer billing dispute. The primary issue of contention between the parties related to the determinants used in calculating the monthly charge billed for electricity. Receivables from the customer have been recorded at their net realizable value and in January 2004, Cinergy settled the dispute. The impact of the settlement was not material to our financial position or results of operations.
Marketing & Trading was in arbitration with Apache Corporation (Apache) concerning disputes under an agreement whereby we marketed natural gas that Apache produced or acquired in North America. Effective July 1, 2003, Marketing & Trading terminated its marketing relationship with Apache. The termination of the marketing relationship ended the arbitration and all outstanding monetary issues related to the arbitration were settled. The impact of the settlement was not material to our financial position or results of operations.
202
(iii) Enron Bankruptcy
In December 2001, Enron filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of New York. We decreased our trading activities with Enron in the months prior to its bankruptcy filing and filed a motion with the bankruptcy court overseeing the Enron bankruptcy seeking appropriate netting of the various payables and receivables between and among Enron and Cinergy entities. Based on judicial decisions regarding the permissibility of certain broad netting arrangements and the results of our mediation, we entered into a settlement agreement with Enron, which became final on January 13, 2004. As a result of this agreement, we paid Enron approximately $14 million of which $12 million was charged to expense during the third quarter of 2003. We believe this resolves all of our claims with the Enron entities, except for one claim being handled outside the United States proceeding involving the recovery of an insignificant amount.
(iv) Synthetic Fuel Production
In July 2002, Capital & Trading acquired a coal-based synthetic fuel production facility. As of December 31, 2003, Capital & Trading’s net book value in this facility was approximately $60 million. The synthetic fuel produced at this facility qualifies for tax credits in accordance with Section 29 of the Internal Revenue Code. Eligibility for these credits expires after 2007. Cinergy received a private letter ruling from the IRS in connection with the acquisition of the facility. To date, Cinergy has produced and sold approximately 4.4 million tons of synthetic fuel at this facility, resulting in approximately $120 million in tax credits, including approximately $80 million in 2003.
In the second quarter of 2003, the IRS announced, as a result of an audit of another taxpayer, that it had reason to question and was reviewing the scientific validity of test procedures and results that were presented as evidence the fuel underwent a significant chemical change. The IRS recently announced that it has finished its review and has determined that test procedures and results used by taxpayers may be scientifically valid if the procedures are applied in a consistent and unbiased manner. The IRS also announced that it plans to impose new testing and record-keeping requirements on synthetic fuel producers and plans to issue guidance extending these requirements to taxpayers already holding private letter rulings on the issue of significant chemical change. Cinergy believes that any new testing or record-keeping requirements imposed by the IRS will not have a material effect on our financial position or results of operations.
(v) Energy Market Investigations
In July 2003, Cinergy received a subpoena from the Commodity Futures Trading Commission (CFTC). As has been previously reported by the press, the CFTC has served subpoenas on numerous other energy companies. The CFTC request sought certain information regarding our trading activities, including price reporting to energy industry publications. The CFTC sought particular information concerning these matters for the period May 2000 through January 2001 as to one of Cinergy’s employees. Based on an initial review of these matters, we placed that employee on administrative leave and have subsequently terminated his employment. Cinergy is continuing an investigation of these matters, including whether price reporting inconsistencies occurred in our operations, and has been cooperating fully with the CFTC.
In August 2003, Cinergy, along with 38 other companies, was named as a defendant in civil
203
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. Plaintiffs filed a consolidated class action complaint in January 2004. We believe this action is without merit and intend to defend this lawsuit vigorously; however, we cannot predict the outcome of this matter at this time.
In the second quarter of 2003, Cinergy received initial and follow-up third-party subpoenas from the SEC requesting information related to particular trading activity with one of its counterparties who was the target of an investigation by the SEC. Cinergy has fully cooperated with the SEC in connection with this matter. In January 2004, Cinergy received a grand jury subpoena from the Assistant United States Attorney in the Southern District of Texas for information relating to the same trading activities being investigated by the SEC. Specifically, the Assistant United States Attorney has requested information relating to communications between a former employee and another energy company. We understand that we are neither a target nor are we under investigation by the Department of Justice in relation to these communications.
At this time, it is not possible to predict the outcome of these investigations and litigation or their impact on Cinergy’s financial position or results of operations; although, in the opinion of management, they are not likely to have a material adverse effect on our financial position or results of operations.
(vi) Patents
Ronald A. Katz Technology Licensing, L.P. (RAKTL) has offered us a license to a portfolio of patents claiming that the patents may be infringed by certain products and services utilized by us. The patents purportedly relate to various aspects of telephone call processing in Cinergy call centers. As of this date, no legal proceedings have been instituted against us, but if the RAKTL patents are valid, enforceable and apply to our business, we could be required to seek a license from RAKTL or to discontinue certain activities. We are currently considering this matter, but lack sufficient information to assess the potential outcome at this time.
(vii) 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 entitieson 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
204
of the guaranteed transactions, to the extent such amount is estimable.
Cinergy has guaranteed the payment of $25 million as of December 31, 2003, for borrowings by individuals under the Director, Officer, and Key Employee Stock Purchase Program. Cinergy may be 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. Most of the guarantees do not have a set termination date; however, the borrowings associated with the majority of the guarantees are due in the first quarter of 2005.
205
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, operations 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 amount to be $104 million under these guarantees as of December 31, 2003. 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 thesecontracts 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 beforeany payments would become due.In other cases (such as indemnifications for willful misconduct of employees in a joint venture), the maximum potential amount is not estimable given that the magnitude of any claims under those indemnifications would be a function of the extent of damages actually incurred, which is not practicable to estimate unless and until the event occurs. Cinergy has estimated the maximum potential amount, where estimable, to be $115 million under these indemnification provisions. The termination period for the majority of matters provided by indemnification provisions in purchase and sale agreements generally ranges from 2004 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.
(viii) Construction and Other Commitments
Forecasted construction and other committed expenditures, including capitalized financing costs, for the year 2004 and for the five-year period 2004-2008 (in nominal dollars) are presented in the table below:
|
| 2004 |
| 2004-2008 |
| ||
|
| (in millions) |
| ||||
|
|
|
|
|
| ||
Cinergy(1) |
| $ | 756 |
| $ | 4,133 |
|
CG&E and subsidiaries |
| 302 |
| 1,591 |
| ||
PSI(2) |
| 336 |
| 1,978 |
| ||
ULH&P |
| 39 |
| 212 |
| ||
(1)The results of Cinergy also include amounts related to non-registrants.
(2)Excludes intercompany purchase of peaking plants from a non-regulated affiliate.
206
This forecast includes an estimate of expenditures in accordance with the companies’ plans regarding environmental compliance.
12. 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, 2003, CG&E’s and PSI’s investments in jointly-owned plant or facilities were as follows:
|
| Ownership |
| Property, |
| Accumulated |
| Construction |
|
|
| (in millions) |
| ||||||
|
|
|
|
|
|
|
|
|
|
CG&E |
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
Miami Fort Station (Units 7 and 8) |
| 64.00 | % | $334 |
| $132 |
| $2 |
|
Beckjord Station (Unit 6) |
| 37.50 |
| 45 |
| 28 |
| 1 |
|
Stuart Station(1) |
| 39.00 |
| 308 |
| 156 |
| 75 |
|
Conesville Station (Unit 4)(1) |
| 40.00 |
| 76 |
| 46 |
| 1 |
|
Zimmer Station |
| 46.50 |
| 1,240 |
| 420 |
| 16 |
|
East Bend Station |
| 69.00 |
| 392 |
| 193 |
| 3 |
|
Killen Station(1) |
| 33.00 |
| 193 |
| 108 |
| 13 |
|
Transmission |
| Various |
| 85 |
| 40 |
| — |
|
|
|
|
|
|
|
|
|
|
|
PSI |
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
Gibson Station (Unit 5) |
| 50.05 |
| 218 |
| 125 |
| 48 |
|
Transmission and local facilities |
| 94.37 |
| 2,466 |
| 950 |
| — |
|
(1)Station is not operated by CG&E.
207
13. Quarterly Financial Data (unaudited)
|
| First |
| Second |
| Third |
| Fourth |
| Total |
| |||||
|
| (in millions, except per share amounts) |
| |||||||||||||
Cinergy(1) |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2003 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues(2) |
| $ | 1,268 |
| $ | 934 |
| $ | 1,092 |
| $ | 1,122 |
| $ | 4,416 |
|
Operating Income |
| 255 |
| 138 |
| 204 |
| 212 |
| 809 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| 140 |
| 76 |
| 112 |
| 107 |
| 435 |
| |||||
Discontinued operations, net of tax(3) |
| — |
| 9 |
| — |
| — |
| 9 |
| |||||
Cumulative effect of changes in accounting principles, net of tax(4) |
| 26 |
| — |
| — |
| — |
| 26 |
| |||||
Net Income |
| $ | 166 |
| $ | 85 |
| $ | 112 |
| $ | 107 |
| $ | 470 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Per Share Data: |
|
|
|
|
|
|
|
|
|
|
| |||||
EPS |
|
|
|
|
|
|
|
|
|
|
| |||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| 0.81 |
| 0.42 |
| 0.63 |
| 0.60 |
| 2.46 |
| |||||
Discontinued operations, net of tax(3) |
| — |
| 0.05 |
| — |
| — |
| 0.05 |
| |||||
Cumulative effect of changes in accounting principles, net of tax(4) |
| 0.15 |
| — |
| — |
| — |
| 0.15 |
| |||||
Net Income |
| $ | 0.96 |
| $ | 0.47 |
| $ | 0.63 |
| $ | 0.60 |
| $ | 2.66 |
|
EPS - assuming dilution |
|
|
|
|
|
|
|
|
|
|
| |||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| 0.80 |
| 0.42 |
| 0.62 |
| 0.59 |
| 2.43 |
| |||||
Discontinued operations, net of tax(3) |
| — |
| 0.05 |
| — |
| — |
| 0.05 |
| |||||
Cumulative effect of changes in accounting principles, net of tax(4) |
| 0.15 |
| — |
| — |
| — |
| 0.15 |
| |||||
Net Income |
| $ | 0.95 |
| $ | 0.47 |
| $ | 0.62 |
| $ | 0.59 |
| $ | 2.63 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2002 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues(2) |
| $ | 967 |
| $ | 907 |
| $ | 1,120 |
| $ | 1,065 |
| $ | 4,059 |
|
Operating Income |
| 211 |
| 136 |
| 239 |
| 214 |
| 800 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Income before discontinued operations and a cumulative effect of a change in accounting principle |
| 95 |
| 45 |
| 132 |
| 125 |
| 397 |
| |||||
Discontinued operations, net of tax(3) |
| 1 |
| — |
| (1 | ) | (25 | ) | (25 | ) | |||||
Cumulative effect of a change in accounting principle, net of tax(7) |
| (11 | ) | — |
| — |
| — |
| (11 | ) | |||||
Net Income |
| $ | 85 |
| $ | 45 |
| $ | 131 |
| $ | 100 |
| $ | 361 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Per Share Data: |
|
|
|
|
|
|
|
|
|
|
| |||||
EPS |
|
|
|
|
|
|
|
|
|
|
| |||||
Income before discontinued operations and a cumulative effect of a change in accounting principle |
| 0.57 |
| 0.27 |
| 0.79 |
| 0.74 |
| 2.37 |
| |||||
Discontinued operations, net of tax(3) |
| 0.01 |
| — |
| (0.01 | ) | (0.15 | ) | (0.15 | ) | |||||
Cumulative effect of a change in accounting principle, net of tax(7) |
| (0.06 | ) | — |
| — |
| — |
| (0.06 | ) | |||||
Net Income |
| $ | 0.52 |
| $ | 0.27 |
| $ | 0.78 |
| $ | 0.59 |
| $ | 2.16 |
|
EPS - assuming dilution |
|
|
|
|
|
|
|
|
|
|
| |||||
Income before discontinued operations and cumulative effect of a change in accounting principle |
| 0.57 |
| 0.26 |
| 0.78 |
| 0.73 |
| 2.34 |
| |||||
Discontinued operations, net of tax(3) |
| 0.01 |
| — | �� | (0.01 | ) | (0.15 | ) | (0.15 | ) | |||||
Cumulative effect of a change in accounting principle, net of tax(7) |
| (0.06 | ) | — |
| — |
| — |
| (0.06 | ) | |||||
Net Income |
| $ | 0.52 |
| $ | 0.26 |
| $ | 0.77 |
| $ | 0.58 |
| $ | 2.13 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E and subsidiaries |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2003 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues(2) |
| $ | 704 |
| $ | 483 |
| $ | 541 |
| $ | 654 |
| $ | 2,382 |
|
Operating Income |
| 157 |
| 102 |
| 144 |
| 160 |
| 563 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Income before cumulative effect of changes in accounting principles |
| 86 |
| 51 |
| 79 |
| 84 |
| 300 |
| |||||
Cumulative effect of changes in accounting principles, net of tax(5) |
| 31 |
| — |
| — |
| — |
| 31 |
| |||||
Net Income |
| 117 |
| 51 |
| 79 |
| 84 |
| 331 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2002 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues(2) |
| $ | 577 |
| $ | 466 |
| $ | 534 |
| $ | 560 |
| $ | 2,137 |
|
Operating Income |
| 155 |
| 101 |
| 135 |
| 114 |
| 505 |
| |||||
Net Income |
| 78 |
| 53 |
| 72 |
| 61 |
| 264 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
PSI |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2003 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues(2) |
| $ | 412 |
| $ | 361 |
| $ | 437 |
| $ | 393 |
| $ | 1,603 |
|
Operating Income |
| 74 |
| 55 |
| 88 |
| 95 |
| 312 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Income before cumulative effect of a change in accounting principle |
| 34 |
| 23 |
| 38 |
| 39 |
| 134 |
| |||||
Cumulative effect of a change in accounting principle, net of tax(6) |
| (1 | ) | — |
| — |
| — |
| (1 | ) | |||||
Net Income |
| 33 |
| 23 |
| 38 |
| 39 |
| 133 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
2002 |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Results of Operations: |
|
|
|
|
|
|
|
|
|
|
| |||||
Operating Revenues(2) |
| $ | 366 |
| $ | 378 |
| $ | 471 |
| $ | 396 |
| $ | 1,611 |
|
Operating Income |
| 74 |
| 52 |
| 120 |
| 136 |
| 382 |
| |||||
Net Income |
| 38 |
| 30 |
| 68 |
| 78 |
| 214 |
| |||||
(1)The results of Cinergy also include amounts related to non-registrants.
(2)EITF 02-3 required that all gains and losses on energy trading derivatives be presented on a net basis beginning January 1, 2003. This resulted in substantial reductions in reported Operating Revenues, Fuel and purchased and exchanged power expense, and Gas purchased expense. However, Operating Income and Net Income were not affected by this change. For further information on EITF 02-3 see Note 1(q)(i).
(3)See Note 14 for further explanation.
(4)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. See Note 1(q)(vi) for further information on the effects of changes in accounting principles.
(5)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. See Note 1(q)(vi) for further information of the effects of changes in accounting principles.
(6)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. See Note 1(q)(vi) for further information of the effect of a change in accounting principle.
(7)Upon implementation of Statement 142, Cinergy recognized a non-cash impairment charge of ($11) million, net of tax, for goodwill related to certain international assets. See Note 1(q)(vi) for further information of the effect of a change in accounting principle.
208
14. Discontinued Operations
During 2002, Cinergy began taking steps to monetize certain non-core investments, including renewable and international investments within Commercial. During the second half of the year, Cinergy either sold or initiated plans to dispose of generation and electric and gas distribution operations in the Czech Republic, Estonia, and South Africa. Cinergy also sold investments, which were accounted for under the equity method, in renewable investments located in Spain and California. In total, Cinergy disposed of approximately $125 million of investments at a net loss, after-tax, of $7 million in 2002. Included in this net loss were cumulative foreign currency translation losses of approximately $4 million, after-tax.
During 2003, Cinergy completed the disposal of its gas distribution operation in South Africa, sold its remaining wind assets in the U.S., 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 have been sold or converted into cash and liabilities of approximately $100 million have been 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).
GAAP requires different accounting treatment for investment disposals involving entities which are consolidated and entities which are accounted for under the equity method. The consolidated entities have been presented as Discontinued operations, net of tax in Cinergy’s Statements of Income and as Assets/Liabilities of Discontinued Operations in Cinergy’s Balance Sheets. The accompanying financial statements and prior year financial statements have been reclassified to account for these entities as such. The disposal of the entities accounted for using the equity method are not allowed to be presented as discontinued operations. A gain of approximately $17 million on the sale of these entities is included in Miscellaneous-Net in Cinergy’s 2002 Statements of Income.
209
The table below 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, 2003 and 2002.
|
| December 31 |
| ||||
|
| 2003 |
| 2002 |
| ||
|
| (in thousands) |
| ||||
|
|
|
|
|
| ||
Revenues(1) |
| $ | 22,257 |
| $ | 95,493 |
|
|
|
|
|
|
| ||
Income (Loss) Before Taxes |
| $ | 4,445 |
| $ | (27,152 | ) |
|
|
|
|
|
| ||
Income Taxes Benefit (Expense) |
| $ | 4,441 |
| $ | 1,991 |
|
|
|
|
|
|
| ||
Income (Loss) from Discontinued Operations |
|
|
|
|
| ||
Income (Loss) from operations, net of tax |
| $ | 3 |
| $ | (829 | ) |
Gain (Loss) on disposal, net of tax(2) |
| 8,883 |
| (24,332 | ) | ||
|
|
|
|
|
| ||
Total Income (Loss) from Discontinued Operations |
| $ | 8,886 |
| $ | (25,161 | ) |
|
|
|
|
|
| ||
Assets |
|
|
|
|
| ||
Current assets |
| $ | 4,501 |
| $ | 48,719 |
|
Property, plant, and equipment-net |
| — |
| 78,309 |
| ||
Other assets |
| — |
| 20,237 |
| ||
|
|
|
|
|
| ||
Total Assets |
| $ | 4,501 |
| $ | 147,265 |
|
|
|
|
|
|
| ||
Liabilities |
|
|
|
|
| ||
Current liabilities |
| $ | 11,594 |
| $ | 6,632 |
|
Long-term debt (including Long-term debt due within one year) |
| — |
| 84,654 |
| ||
Other |
| — |
| 17,547 |
| ||
|
|
|
|
|
| ||
Total Liabilities |
| $ | 11,594 |
| $ | 108,833 |
|
(1)Presented for informational purposes only. All results of operations are reported net in our Statements of Income.
(2)For 2002, approximately $17 million of this amount represents a write-down to fair value, less cost to sell, on assets classified as held for sale at December 31, 2002. The remaining loss on disposal for 2002 represents actual losses on completed sales.
The losses included in the 2002 discontinued operations primarily pertain to two investments. In one case, the primary customer of a combined heat and power plant filed for bankruptcy resulting in a significant reduction in future expected revenues from the investment. This investment was sold in December 2002. In the second case, the retail market of a gas distribution business did not develop as expected, and we elected to exit the business rather than invest the additional capital which would be required to reach a sustainable level of market penetration. The investment was written down to its realizable value in December 2002 and was subsequently sold in April 2003.
210
15. Financial Information by Business Segment
We conduct operations through our subsidiaries and manage our businesses through the following three reportable segments:
• Commercial;
• Regulated Businesses; and
• Power Technology.
The following section describes the activities of our business units as of December 31, 2003.
Commercial manages wholesale generation and energy marketing and trading of energy commodities. Additionally, Commercial operates and maintains our electric generating plants including some of our jointly-owned plants. Commercial is also responsible for all of our international operations and performs energy risk management activities, trading activities, and customized energy solutions.
Regulated Businesses consists of PSI’s regulated, integrated utility operations, and Cinergy’s other regulated electric and gas transmission and distribution systems. Regulated Businesses plans, constructs, operates, and maintains Cinergy’s transmission and distribution systems and delivers gas and electric energy to consumers. Regulated Businesses also earns revenues from wholesale customers primarily by transmitting electric power through Cinergy’s transmission system.
Power Technology 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 manages our investments in other energy infrastructure and telecommunication service providers.
Following are the financial results by business unit. Certain amounts for the prior year have been restated to reflect implementation of EITF 02-3 and other prior year amounts have been reclassified to conform to the current presentation.
211
Financial results by business unit for the years ended December 31, 2003, 2002, and 2001, are as indicated below:
Business Units
|
| 2003 |
| |||||||||||||||||||
|
| Cinergy Business Units |
|
|
|
|
|
|
| |||||||||||||
|
| Commercial |
| Regulated |
| Power |
| Total |
| All Other (1) |
| Reconciling |
| Consolidated |
| |||||||
|
| (in millions) |
| |||||||||||||||||||
Operating revenues - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External customers |
| $ | 1,630 |
| $ | 2,786 |
| $ | — |
| $ | 4,416 |
| $ | — |
| $ | — |
| $ | 4,416 |
|
Intersegment revenues |
| 157 |
| — |
| — |
| 157 |
| — |
| (157 | ) | — |
| |||||||
Cost of sales - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Fuel and purchased and exchanged power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External customers |
| 645 |
| 513 |
| — |
| 1,158 |
| — |
| — |
| 1,158 |
| |||||||
Intersegment costs |
| — |
| 157 |
| — |
| 157 |
| — |
| (157 | ) | — |
| |||||||
Gas purchased |
| 122 |
| 382 |
| — |
| 504 |
| — |
| — |
| 504 |
| |||||||
Depreciation(3) |
| 135 |
| 284 |
| — |
| 419 |
| — |
| — |
| 419 |
| |||||||
Equity in earnings (losses) of unconsolidated subsidiaries |
| 14 |
| 4 |
| (3 | ) | 15 |
| — |
| — |
| 15 |
| |||||||
Interest expense(4) |
| 94 |
| 158 |
| 17 |
| 269 |
| — |
| — |
| 269 |
| |||||||
Income taxes |
| 7 | (5) | 148 |
| (11 | ) | 144 |
| — |
| — |
| 144 |
| |||||||
Discontinued operations, net of tax(6) |
| 9 |
| — |
| — |
| 9 |
| — |
| — |
| 9 |
| |||||||
Cumulative effect of changes in accounting principles, net of tax(7) |
| 26 |
| — |
| — |
| 26 |
| — |
| — |
| 26 |
| |||||||
Segment profit (loss)(8) |
| 275 |
| 211 |
| (16 | ) | 470 |
| — |
| — |
| 470 |
| |||||||
Segment assets from continuing operations |
| 5,361 |
| 8,515 |
| 175 |
| 14,051 |
| 63 |
| — |
| 14,114 |
| |||||||
Segment assets from discontinued operations |
| 5 |
| — |
| — |
| 5 |
| — |
| — |
| 5 |
| |||||||
Total segment assets |
| 5,366 |
| 8,515 | (9) | 175 |
| 14,056 |
| 63 |
| — |
| 14,119 |
| |||||||
Investments in unconsolidated subsidiaries |
| 400 |
| 14 |
| 81 |
| 495 |
| — |
| — |
| 495 |
| |||||||
Total expenditures for long-lived assets |
| 158 |
| 554 |
| — |
| 712 |
| — |
| — |
| 712 |
| |||||||
|
| 2004 |
| ||||||||||||||||||||
|
| Cinergy Business Units |
|
|
|
|
|
|
| ||||||||||||||
|
|
|
| Reconciling |
| Power Technology |
|
|
|
|
|
|
|
|
| ||||||||
|
| Commercial |
|
| and Infrastructure |
| Total |
| All Other(1) |
| Eliminations(2) |
| Consolidated |
| |||||||||
|
| (in millions) |
| ||||||||||||||||||||
Operating revenues - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
External customers |
| $ | 1,665 |
| $ | 3,023 |
| $ | — |
| $ | 4,688 |
| $ | — |
| $ | — |
| $ | 4,688 |
| |
Intersegment revenues |
| 163 |
| — |
| — |
| 163 |
| — |
| (163 | ) | — |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Gross Margins |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Electric(3) |
| 637 |
| 1,656 |
| — |
| 2,293 |
| — |
| — |
| 2,293 |
| ||||||||
Gas(4) |
| 92 |
| 263 |
| — |
| 355 |
| — |
| — |
| 355 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Depreciation |
| 133 |
| 326 |
| 1 |
| 460 |
| — |
| — |
| 460 |
| ||||||||
Equity in earnings of unconsolidated subsidiaries |
| 25 |
| 3 |
| 20 |
| 48 |
| — |
| — |
| 48 |
| ||||||||
Interest expense(5) |
| 121 |
| 149 |
| 5 |
| 275 |
| — |
| — |
| 275 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Income taxes |
| (61 | )(6) | 178 |
| (13 | ) | 104 |
| — |
| — |
| 104 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Segment profit (loss)(7) |
| 179 |
| 253 |
| (31 | ) | 401 |
| — |
| — |
| 401 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Total segment assets |
| 4,992 |
| 9,774 |
| 136 |
| 14,902 |
| 80 |
| — |
| 14,982 |
| ||||||||
Investments in unconsolidated subsidiaries |
| 413 |
| 18 |
| 83 |
| 514 |
| — |
| — |
| 514 |
| ||||||||
Total expenditures for long-lived assets |
| 176 |
| 517 |
| 7 |
| 700 |
| — |
| — |
| 700 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
212
|
| 2002 |
| |||||||||||||||||||
|
| Cinergy Business Units |
|
|
|
|
|
|
| |||||||||||||
|
| Commercial |
| Regulated |
| Power |
| Total |
| All Other(1) |
| Reconciling |
| Consolidated |
| |||||||
|
| (in millions) |
| |||||||||||||||||||
Operating revenues - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External customers |
| $ | 1,419 |
| $ | 2,640 |
| $ | — |
| $ | 4,059 |
| $ | — |
| $ | — |
| $ | 4,059 |
|
Intersegment revenues |
| 160 |
| — |
| — |
| 160 |
| — |
| (160 | ) | — |
| |||||||
Cost of sales - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Fuel and purchased and exchanged power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External customers |
| 532 |
| 458 |
| — |
| 990 |
| — |
| — |
| 990 |
| |||||||
Intersegment costs |
| — |
| 160 |
| — |
| 160 |
| — |
| (160 | ) | — |
| |||||||
Gas purchased |
| 77 |
| 233 |
| — |
| 310 |
| — |
| — |
| 310 |
| |||||||
Depreciation(3) |
| 150 |
| 249 |
| 6 |
| 405 |
| — |
| — |
| 405 |
| |||||||
Equity in earnings (losses) of unconsolidated subsidiaries |
| 20 |
| 5 |
| (10 | ) | 15 |
| — |
| — |
| 15 |
| |||||||
Interest expense(4) |
| 102 |
| 133 |
| 8 |
| 243 |
| — |
| — |
| 243 |
| |||||||
Income taxes |
| 23 | (5) | 151 |
| (14 | ) | 160 |
| — |
| — |
| 160 |
| |||||||
Discontinued operations, net of tax(6) |
| (25 | ) | — |
| — |
| (25 | ) | — |
| — |
| (25 | ) | |||||||
Cumulative effect of a change in accounting principle, net of tax(7) |
| (11 | ) | — |
| — |
| (11 | ) | — |
| — |
| (11 | ) | |||||||
Segment profit (loss)(8) |
| 115 |
| 270 |
| (24 | ) | 361 |
| — |
| �� |
| 361 |
| |||||||
Segment assets from continuing operations |
| 5,691 |
| 7,746 |
| 155 |
| 13,592 |
| 93 |
| — |
| 13,685 |
| |||||||
Segment assets from discontinued operations |
| 147 |
| — |
| — |
| 147 |
| — |
| — |
| 147 |
| |||||||
Total segment assets |
| 5,838 |
| 7,746 |
| 155 |
| 13,739 |
| 93 |
| — |
| 13,832 |
| |||||||
Investments in unconsolidated subsidiaries |
| 337 |
| 10 |
| 70 |
| 417 |
| — |
| — |
| 417 |
| |||||||
Total expenditures for long-lived assets |
| 188 |
| 681 |
| 1 |
| 870 |
| — |
| — |
| 870 |
| |||||||
(1)The All Other category represents miscellaneous corporate items, which are not allocated to business units for purposes of segment performance measurement.
(2)The Reconciling Eliminations category eliminates the intersegment revenues of Commercial and the intersegment costs of Regulated Businesses.Commercial.
(3)The componentsElectric gross margins are calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Depreciation include depreciation of fixed assets and amortization of intangible assets.Income.
(4)InterestGas gross margins are calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
(5) Interest income is deemed immaterial.
(5)(6) The decreasereduction in 2002,income taxes in 2004, as compared to 2001,2003, primarily reflects lower business unit taxable income and also includes an increase in part reflects the effect ofannual tax credits associated with the production and sale of synthetic fuel beginning in July 2002.
(6) fuel. For further information, see Note 14.11(c)(iv).
(7) Upon implementation of Statement 142, Cinergy recognized a non-cash impairment charge of $11 million, net of tax, for goodwill related to certain international assets. See Note 1(l) for further information.
(8)Management utilizes Segment profit (loss), after taxes, to evaluate segment performance.
213180
|
| 2001 |
| |||||||||||||||||||
|
| Cinergy Business Units |
|
|
|
|
|
|
| |||||||||||||
|
| Commercial |
| Regulated |
| Power |
| Total |
| All Other(1) |
| Reconciling |
| Consolidated |
| |||||||
|
| (in millions) |
| |||||||||||||||||||
Operating revenues - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External customers |
| $ | 1,247 |
| $ | 2,703 |
| $ | — |
| $ | 3,950 |
| $ | — |
| $ | — |
| $ | 3,950 |
|
Intersegment revenues |
| 144 |
| — |
| — |
| 144 |
| — |
| (144 | ) | — |
| |||||||
Cost of sales - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Fuel and purchased and exchanged power |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External customers |
| 546 |
| 469 |
| — |
| 1,015 |
| — |
| — |
| 1,015 |
| |||||||
Intersegment costs |
| — |
| 144 |
| — |
| 144 |
| — |
| (144 | ) | — |
| |||||||
Gas purchased |
| — |
| 397 |
| — |
| 397 |
| — |
| — |
| 397 |
| |||||||
Depreciation(3) |
| 130 |
| 236 |
| 1 |
| 367 |
| — |
| — |
| 367 |
| |||||||
Equity in earnings (losses) of unconsolidated subsidiaries |
| 9 |
| — |
| (8 | ) | 1 |
| — |
| — |
| 1 |
| |||||||
Interest expense(4) |
| 108 |
| 142 |
| 9 |
| 259 |
| — |
| — |
| 259 |
| |||||||
Income taxes |
| 93 |
| 169 |
| (5 | ) | 257 |
| — |
| — |
| 257 |
| |||||||
Discontinued operations, net of tax(5) |
| (14 | ) | — |
| — |
| (14 | ) | — |
| — |
| (14 | ) | |||||||
Segment profit (loss)(6) |
| 188 |
| 266 |
| (12 | ) | 442 |
| — |
| — |
| 442 |
| |||||||
Segment assets from continuing operations |
| 4,836 |
| 7,512 |
| 164 |
| 12,512 |
| 46 |
| — |
| 12,558 |
| |||||||
Segment assets from discontinued operations |
| 234 |
| — |
| — |
| 234 |
| — |
| — |
| 234 |
| |||||||
Total segment assets |
| 5,070 |
| 7,512 |
| 164 |
| 12,746 |
| 46 |
| — |
| 12,792 |
| |||||||
Investments in unconsolidated subsidiaries |
| 256 |
| — |
| 76 |
| 332 |
| — |
| — |
| 332 |
| |||||||
Total expenditures for long-lived assets |
| 764 |
| 633 |
| — |
| 1,397 |
| — |
| — |
| 1,397 |
| |||||||
|
| 2003 |
|
| ||||||||||||||||||||||||||||||
|
| Cinergy Business Units |
|
|
|
|
|
|
| |||||||||||||||||||||||||
|
|
|
|
|
| Power Technology |
|
|
|
|
| Reconciling |
|
|
|
| ||||||||||||||||||
|
| Commercial |
| Regulated |
| and Infrastructure |
| Total |
| All Other (1) |
|
| Consolidated |
|
| |||||||||||||||||||
|
| (in millions) |
|
| ||||||||||||||||||||||||||||||
Operating revenues - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
External customers |
| $ | 1,630 |
| $ | 2,786 |
| $ | — |
| $ | 4,416 |
| $ | — |
| $ | — |
| $ | 4,416 |
|
| |||||||||||
Intersegment revenues |
| 185 |
| 1 |
| — |
| 186 |
| — |
| (186 | ) | — |
|
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Gross margins |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Electric(3) |
| 714 |
| 1,469 |
| — |
| 2,183 |
| — |
| — |
| 2,183 |
|
| ||||||||||||||||||
Gas(4) |
| 88 |
| 244 |
| — |
| 332 |
| — |
| — |
| 332 |
|
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Depreciation |
| 135 |
| 264 |
| — |
| 399 |
| — |
| — |
| 399 |
|
| ||||||||||||||||||
Equity in earnings (losses) of unconsolidated subsidiaries |
| 14 |
| 4 |
| (3 | ) | 15 |
| — |
| — |
| 15 |
|
| ||||||||||||||||||
Interest expense(5) |
| 94 |
| 160 |
| 17 |
| 271 |
| — |
| — |
| 271 |
|
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Income taxes |
| 7(6 | ) | 148 |
| (11 | ) | 144 |
| — |
| — |
| 144 |
|
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Discontinued operations, net of tax(7) |
| 9 |
| — |
| — |
| 9 |
| — |
| — |
| 9 |
|
| ||||||||||||||||||
Cumulative effect of changes in accounting principles (net of tax)(8) |
| 26 |
| — |
| — |
| 26 |
| — |
| — |
| 26 |
|
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Segment profit (loss)(9) |
| 275 |
| 211 |
| (16 | ) | 470 |
| — |
| — |
| 470 |
|
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Segment assets from continuing operations |
| 5,361 |
| 8,515 |
| 175 |
| 14,051 |
| 63 |
| — |
| 14,114 |
|
| ||||||||||||||||||
Segment assets from discontinued operations |
| 5 |
| — |
| — |
| 5 |
| — |
| — |
| 5 |
|
| ||||||||||||||||||
Total segment assets |
| 5,366 |
| 8,515 |
| 175 |
| 14,056 |
| 63 |
| — |
| 14,119 |
|
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Investments in unconsolidated subsidiaries |
| 400 |
| 14 |
| 81 |
| 495 |
| — |
| — |
| 495 |
|
| ||||||||||||||||||
Total expenditures for long-lived assets |
| 158 |
| 554 |
| — |
| 712 |
| — |
| — |
| 712 |
|
| ||||||||||||||||||
(1)The All Other category represents miscellaneous corporate items, which are not allocated to business units for purposes of segment performance measurement.
(2)The Reconciling Eliminations categorycolumn eliminates the intersegment revenues of Commercial and the intersegment costs of Regulated Businesses.Commercial.
(3)The componentsElectric gross margins are calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Depreciation include depreciation of fixed assets and amortization of intangible assets.Income.
(4)InterestGas gross margins are calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
(5) Interest income is deemed immaterial.
(5)(6) The decrease in 2003, as compared to 2002, in part reflects the effect of tax credits associated with production of synthetic fuel beginning in July 2002.
(7) For further information, see Note 14.
(6)(8) For further information, see Note 1(q)(iv).
(9) Management utilizes Segment profit (loss), after taxes, to evaluate segment performance.
214181
|
| 2002 |
| |||||||||||||||||||
|
| Cinergy Business Units |
|
|
|
|
|
|
| |||||||||||||
|
|
|
|
|
| Power Technology |
|
|
|
|
| Reconciling |
|
|
| |||||||
|
| Commercial |
| Regulated |
| and Infrastructure |
| Total |
| All Other(1) |
|
| Consolidated |
| ||||||||
|
| (in millions) |
| |||||||||||||||||||
Operating revenues - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
External customers |
| $ | 1,592 |
| $ | 2,467 |
| $ | — |
| $ | 4,059 |
| $ | — |
| $ | — |
| $ | 4,059 |
|
Intersegment revenues |
| 190 |
| — |
| — |
| 190 |
| — |
| (190 | ) | — |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Gross margins |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Electric(3) |
| 735 |
| 1,571 |
| — |
| 2,306 |
| — |
| — |
| 2,306 |
| |||||||
Gas(4) |
| 77 |
| 203 |
| — |
| 280 |
| — |
| — |
| 280 |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Depreciation |
| 150 |
| 248 |
| 6 |
| 404 |
| — |
| — |
| 404 |
| |||||||
Equity in earnings (losses) of unconsolidated subsidiaries |
| 20 |
| 5 |
| (10 | ) | 15 |
| — |
| — |
| 15 |
| |||||||
Interest expense(5) |
| 102 |
| 133 |
| 9 |
| 244 |
| — |
| — |
| 244 |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Income taxes |
| 23 |
| 151 |
| (14 | ) | 160 |
| — |
| — |
| 160 |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Discontinued operations (net of tax)(6) |
| (25 | ) | — |
| — |
| (25 | ) | — |
| — |
| (25 | ) | |||||||
Cumulative effect of a change in accounting principle (net of tax)(7) |
| (11 | ) | — |
| — |
| (11 | ) | — |
| — |
| (11 | ) | |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Segment profit (loss)(8) |
| 115 |
| 270 |
| (24 | ) | 361 |
| — |
| — |
| 361 |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Segment assets from continuing operations |
| 5,691 |
| 7,746 |
| 155 |
| 13,592 |
| 93 |
| — |
| 13,685 |
| |||||||
Segment assets from discontinued operations |
| 147 |
| — |
| — |
| 147 |
| — |
| — |
| 147 |
| |||||||
Total segment assets |
| 5,838 |
| 7,746 |
| 155 |
| 13,739 |
| 93 |
| — |
| 13,832 |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Investments in unconsolidated subsidiaries |
| 337 |
| 10 |
| 70 |
| 417 |
| — |
| — |
| 417 |
| |||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Total expenditures for long-lived assets from continuing operations |
| 184 |
| 681 |
| 1 |
| 866 |
| — |
| — |
| 866 |
| |||||||
Total expenditures for long-lived assets from discontinued operations |
| 4 |
| — |
| — |
| 4 |
| — |
| — |
| 4 |
| |||||||
Total expenditures for long-lived assets |
| 188 |
| 681 |
| 1 |
| 870 |
| — |
| — |
| 870 |
| |||||||
(1) The All Other category represents miscellaneous corporate items, which are not allocated to business units for purposes of segment performance measurement.
(2) The Reconciling Eliminations column eliminates the intersegment revenues of Commercial.
(3) Electric gross margins are calculated as Electric operating revenues less Fuel, emission allowances, and purchased power expense from the Statements of Income.
(4) Gas gross margins are calculated as Gas operating revenues less Gas purchased expense from the Statements of Income.
(5) Interest income is deemed immaterial.
(6) For further information, see Note 14.
(7) For further information, see Note 1(q)(iv).
(8) Management utilizes segment profit (loss), after taxes, to evaluate segment performance.
182
Products and Services
(in millions)
|
| Revenues |
|
| Revenues |
| ||||||||||||||||||||||||||||||||||||||||||||
|
| Utility |
| Wholesale Commodity |
|
|
|
|
|
| Traditional Utility |
| Wholesale Commodity |
|
|
|
|
| ||||||||||||||||||||||||||||||||
Year |
| Electric |
| Gas |
| Total |
| Electric |
| Gas |
| Total |
| Other |
| Consolidated |
|
| Electric |
| Gas |
| Total |
| Electric |
| Gas |
| Total |
| Other |
| Consolidated |
| ||||||||||||||||
2004 |
| $ | 2,324 |
| $ | 690 |
| $ | 3,014 |
| $ | 1,213 |
| $ | 93 |
| $ | 1,306 |
| $ | 368 |
| $ | 4,688 |
| |||||||||||||||||||||||||
2003 |
| $ | 2,156 |
| $ | 626 |
| $ | 2,782 |
| $ | 1,227 |
| $ | 210 |
| $ | 1,437 |
| $ | 197 |
| $ | 4,416 |
|
| 2,156 |
| 626 |
| 2,782 |
| 1,164 |
| 210 |
| 1,374 |
| 260 |
| 4,416 |
| ||||||||
2002 |
| 2,197 |
| 436 |
| 2,633 |
| 1,141 |
| 154 |
| 1,295 |
| 131 |
| 4,059 |
|
| 2,024 |
| 436 |
| 2,460 |
| 1,232 |
| 155 |
| 1,387 |
| 212 |
| 4,059 |
| ||||||||||||||||
2001 |
| 2,101 |
| 595 |
| 2,696 |
| 1,115 |
| 61 |
| 1,176 |
| 78 |
| 3,950 |
| |||||||||||||||||||||||||||||||||
Geographic Areas and Long-Lived Assets
Revenues
(in millions)
Year |
| Domestic |
| International |
| Consolidated |
|
| Domestic |
| International |
| Consolidated |
| ||||||
2004 |
| $ | 4,637 |
| $ | 51 |
| $ | 4,688 |
| ||||||||||
2003 |
| $ | 4,371 |
| $ | 45 |
| $ | 4,416 |
|
| 4,371 |
| 45 |
| 4,416 |
| |||
2002 |
| 4,011 |
| 48 |
| 4,059 |
|
| 4,011 |
| 48 |
| 4,059 |
| ||||||
2001 |
| 3,913 |
| 37 |
| 3,950 |
| |||||||||||||
|
| Long-Lived Assets from |
| Long-Lived Assets from |
| Total Long-Lived Assets |
| |||||||||||||||||||||
|
| (in millions) |
| (in millions) |
| (in millions) |
| |||||||||||||||||||||
Year |
| Domestic |
| International |
| Consolidated |
| Domestic |
| International |
| Consolidated |
| Domestic |
| International |
| Consolidated |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
2004 |
| $ | 12,162 |
| $ | 284 |
| $ | 12,446 |
| $ | — |
| $ | — |
| $ | — |
| $ | 12,162 |
| $ | 284 |
| $ | 12,446 |
|
2003 |
| 11,524 |
| 273 |
| 11,797 |
| — |
| — |
| — |
| 11,524 |
| 273 |
| 11,797 |
| |||||||||
2002 |
| 10,801 |
| 296 |
| 11,097 |
| — |
| 97 |
| 97 |
| 10,801 |
| 393 |
| 11,194 |
| |||||||||
183
Long-Lived Assets
(in millions)
Year |
| Domestic |
| International |
| Consolidated |
| |||
2003 |
| $ | 11,524 |
| $ | 273 |
| $ | 11,797 |
|
2002 |
| 10,801 |
| 393 |
| 11,194 |
| |||
2001 |
| 10,174 |
| 428 |
| 10,602 |
| |||
215
16.17. Earnings Per Common Share
A reconciliation of EPS - basic to EPS - assuming dilutiondiluted is presented below:below for the years ended December 31, 2004, 2003, and 2002:
|
| Income |
| Shares |
| EPS |
|
| Income |
| Shares |
| EPS |
| ||||||
|
| (in thousands, except per share amounts) |
|
| (in thousands, except per share amounts) |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Year ended December 31, 2004 |
|
|
|
|
|
|
| |||||||||||||
EPS - basic: |
|
|
|
|
|
|
| |||||||||||||
Net income |
| $ | 400,868 |
| 180,965 |
| $ | 2.22 |
| |||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Effect of dilutive securities: |
|
|
|
|
|
|
| |||||||||||||
Common stock options |
|
|
| 678 |
|
|
| |||||||||||||
Directors’ compensation plans |
|
|
| 150 |
|
|
| |||||||||||||
Contingently issuable common stock |
|
|
| 605 |
|
|
| |||||||||||||
Stock purchase contracts |
|
|
| 1,133 |
|
|
| |||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
EPS - diluted: |
|
|
|
|
|
|
| |||||||||||||
Net income plus assumed conversions |
| $ | 400,868 |
| 183,531 |
| $ | 2.18 |
| |||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Year ended December 31, 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
EPS: |
|
|
|
|
|
|
| |||||||||||||
EPS - basic: |
|
|
|
|
|
|
| |||||||||||||
Income before discontinued operations and cumulative effect of changes in accounting principles |
| $ | 434,424 |
|
|
| $ | 2.46 |
|
| $ | 434,424 |
|
|
| $ | 2.46 |
| ||
Discontinued operations, net of tax |
| 8,886 |
|
|
| 0.05 |
|
| 8,886 |
|
|
| 0.05 |
| ||||||
Cumulative effect of changes in accounting principles, net of tax |
| 26,462 |
|
|
| 0.15 |
|
| 26,462 |
|
|
| 0.15 |
| ||||||
Net income |
| $ | 469,772 |
| 176,535 |
| $ | 2.66 |
|
| $ | 469,772 |
| 176,535 |
| $ | 2.66 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Common stock options |
|
|
| 746 |
|
|
|
|
|
| 746 |
|
|
| ||||||
Directors’ compensation plans |
|
|
| 152 |
|
|
|
|
|
| 152 |
|
|
| ||||||
Contingently issuable common stock |
|
|
| 851 |
|
|
|
|
|
| 851 |
|
|
| ||||||
Stock purchase contracts |
|
|
| 189 |
|
|
|
|
|
| 189 |
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
EPS - assuming dilution: |
|
|
|
|
|
|
| |||||||||||||
EPS - diluted: |
|
|
|
|
|
|
| |||||||||||||
Net income plus assumed conversions |
| $ | 469,772 |
| 178,473 |
| $ | 2.63 |
|
| $ | 469,772 |
| 178,473 |
| $ | 2.63 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Year ended December 31, 2002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
EPS: |
|
|
|
|
|
|
| |||||||||||||
EPS - basic: |
|
|
|
|
|
|
| |||||||||||||
Income before discontinued operations and cumulative effect of a change in accounting principle |
| $ | 396,636 |
|
|
| $ | 2.37 |
|
| $ | 396,636 |
|
|
| $ | 2.37 |
| ||
Discontinued operations, net of tax |
| (25,161 | ) |
|
| (0.15 | ) |
| (25,161 | ) |
|
| (0.15 | ) | ||||||
Cumulative effect of a change in accounting principle, net of tax |
| (10,899 | ) |
|
| (0.06 | ) |
| (10,899 | ) |
|
| (0.06 | ) | ||||||
Net income |
| $ | 360,576 |
| 167,047 |
| $ | 2.16 |
|
| $ | 360,576 |
| 167,047 |
| $ | 2.16 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Common stock options |
|
|
| 899 |
|
|
|
|
|
| 899 |
|
|
| ||||||
Employee Stock Purchase and Savings Plan |
|
|
| 3 |
|
|
|
|
|
| 3 |
|
|
| ||||||
Directors’ compensation plans |
|
|
| 169 |
|
|
|
|
|
| 169 |
|
|
| ||||||
Contingently issuable common stock |
|
|
| 934 |
|
|
|
|
|
| 934 |
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
EPS - assuming dilution: |
|
|
|
|
|
|
| |||||||||||||
EPS - diluted: |
|
|
|
|
|
|
| |||||||||||||
Net income plus assumed conversions |
| $ | 360,576 |
| 169,052 |
| $ | 2.13 |
|
| $ | 360,576 |
| 169,052 |
| $ | 2.13 |
| ||
|
|
|
|
|
|
|
| |||||||||||||
Year ended December 31, 2001 |
|
|
|
|
|
|
| |||||||||||||
EPS: |
|
|
|
|
|
|
| |||||||||||||
Income before discontinued operations and cumulative effect of a change in accounting principle |
| $ | 456,629 |
|
|
| $ | 2.87 |
| |||||||||||
Discontinued operations, net of tax |
| (14,350 | ) |
|
| (0.09 | ) | |||||||||||||
Net income |
| $ | 442,279 |
| 159,110 |
| $ | 2.78 |
| |||||||||||
|
|
|
|
|
|
|
| |||||||||||||
Effect of dilutive securities: |
|
|
|
|
|
|
| |||||||||||||
Common stock options |
|
|
| 975 |
|
|
| |||||||||||||
Directors’ compensation plans |
|
|
| 152 |
|
|
| |||||||||||||
Contingently issuable common stock |
|
|
| 810 |
|
|
| |||||||||||||
|
|
|
|
|
|
|
| |||||||||||||
EPS - assuming dilution: |
|
|
|
|
|
|
| |||||||||||||
Net income plus assumed conversions |
| $ | 442,279 |
| 161,047 |
| $ | 2.75 |
| |||||||||||
Options to purchase shares of common stock are excluded from the calculation of EPS -
216
assuming dilution when the exercise price of these options plus unrecognized compensation expense is greater than the average market price of a common share during the period multiplied by the number of options outstanding at the end of the period because diluted, if they are considered to be anti-dilutive. For the years ended December 31, 2004, 2003, and 2002, and 2001, approximately 0.9 million, 1.6 million, 3.0 million, and 2.13.0 million shares, respectively, were excluded from the EPS - assuming dilutiondiluted calculation.
Also excluded from the EPS - assuming dilutiondiluted calculation for the years ended December 31, 2004, 2003, and 2002 are up to 9.7 million, 10.6 million, and 10.8 million shares, respectively, issuable pursuant to the stock purchase contracts issued by Cinergy Corp. in December 2001 associated with the preferred trust securities transaction. The number of shares issuable pursuant toIn January
184
and February 2005, the stock purchase contracts is contingent upon the market pricewere settled and holders purchased a total of 9.2 million shares of Cinergy Corp. stock in February 2005 and could range between 9.2 and 10.8 million shares.
17. Deregulation
CG&E is in a market development period, transitioning to deregulation of electric generation and a competitive retail electric service market in the state of Ohio. The transition period is governed by the Amended Substitute Senate Bill No. 3 (Electric Restructuring Bill) and a stipulated transition plan adopted and approved by the PUCO. The Electric Restructuring Bill provides for a market development period that began January 1, 2001, and ends no later than December 31, 2005.
The major features of CG&E’s transition plan include:
• Residential customer rates are frozen through December 31, 2005;
• Residential customers received a five-percent reduction in the generation portion of their electric rates, effective January 1, 2001;
•CG&E will provide $4 million from 2001 to 2005 in support of energy efficiency and weatherization services for low income customers;
•CG&E will provide shopping credits to switching customers;
• The creation of a RTC designed to recover CG&E’s regulatory assets and other transition costs over a ten-year period;
• Authority for CG&E to transfer its generation assets to one or more, non-regulated affiliates to provide flexibility to manage its generation asset portfolio in a manner that enhances opportunities in a competitive marketplace;
• Authority for CG&E to apply thecommon stock. Net proceeds of transition cost recoveryapproximately $316 million were used to costs incurred during the transition period, including implementation costs and purchased power costs that may be incurred by CG&E to maintain an operating reserve margin sufficient to provide reliable service to its customers;
• Authority for CG&E to adjust the amortization of its regulatory assets and other transition costs to reflect the effects of any shopping incentives provided to customers; and
•CG&E will provide standard offer default supplier service (i.e., CG&E will be the supplier of last resort, so that no customer will be without an electric supplier).
Under CG&E’s transition plan, retail customers continue to receive transmission and
217
distribution services from CG&E, but may purchase electricity from another supplier. Retail customers that purchase electricity from another supplier receive shopping credits from CG&E. The shopping credits generally reflect the costs of electric generation included in CG&E’s frozen rates. However, shopping credits for the first 20 percent of electricity usage in each customer class to switch suppliers are higher than shopping credits for subsequent switchers in order to stimulate the development of the competitive retail electric service market.
CG&E recovers its generation-related regulatory assets and certain other deferred transition costs through an RTC paid by all retail customers. As the RTC is collected from customers, CG&E amortizes the deferred balance of regulatory assets and other transition costs. A portion of the RTC collected from customers is recognized currently as a return on the deferred balance of regulatory assets and other transition costs and as reimbursement for the difference in the shopping credits provided to retail customers and the wholesale revenues from generation made available by switched customers. The ability of CG&E to recover its regulatory assets and other transition costs is dependent on several factors, including, but not limited to, the level of CG&E’s electric sales, prices in the wholesale power markets, and the amount of customers switching to other electric suppliers.
In January 2003, CG&E filed an application with the PUCO for approval of a methodology to establish how market-based rates for non-residential customers will be determined when the market development period ends. In the filing, CG&E seeks to establish a market-based standard service offer rate for non-residential customers that do not switch suppliers and a process for establishing the competitively-bid generation service option required by the Electric Restructuring Bill. As of December 31, 2002, more than 20 percent of the load of CG&E’s commercial and industrial customer classes had switched to other electric suppliers, and the other public authorities group was at 19.95 percent at December 31, 2003. Under its transition plan, CG&E may end the market development period for those classes of customers once 20 percent switching has been achieved; however, PUCO approval of the standard service offer rate and competitive bidding process is required before the market development period can be ended.
In December 2003, the PUCO issued an order that the CG&E application filed in January 2003 would proceed to a hearing and be consolidated with CG&E’s application to defer certain administrative transmission charges and the application to defer costs of capital investments made to their transmission and distribution system during the market development period. As part of this order, the PUCO requested that CG&E file a rate stabilization plan to mitigate the effects of market based pricing on retail customers while the competitive retail electric market continues to mature. In response to this request, on January 26, 2004, CG&E filed an offer of settlement, including an electric reliability and rate stabilization plan. In this proposal, CG&E has also asked to end the market development period for all customers effective December 31, 2004.
218
The major features of CG&E’s electric reliability and rate stabilization plan include:
• The market development period would end for all customers on December 31, 2004;
•CG&E would begin to collect a non-bypassable Provider of Last Resort (POLR) charge from all customers effective January 1, 2005. This charge could be increased by up to 10 percent of CG&E’s generation charge each year from 2005 through 2008;
•CG&E would offer its current generation rates as its market based rates until December 31, 2008;
•CG&E would request a transmission and distribution rate increase effective January 1, 2005;
•CG&E would begin charging RTC as an explicit wires charge;
• PUCO approval of previously requested transmission and distribution deferrals and cost recovery riders (see Note 11(b)(vi));
• The five percent generation rate reduction for residential customers would continue through 2008;
• Extend recovery of residential RTC from 2008 through 2010.·
The POLR charge would allow for recovery of increased costs of fuel and purchased power, transmission congestion, environmental compliance, homeland security, taxes and maintaining an adequate reserve margin.
An evidentiary hearing addressing the issues described above is scheduled for the second quarter of 2004. At the current time CG&E is unable to predict the outcome of this proceeding or the effects it could have on its results of operations or financial condition.reduce short-term debt.
18. 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 adjustment,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 U.S.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 U.S.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
219
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 9.
We record unrealized gains and losses on equity investments in trusts we have established for our benefit plans, primarily by PSI. See Note 9 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 8(a)7(a).
220185
The elements of Comprehensive income and their related tax effects for the years ended December 31, 2004, 2003, 2002, and 20012002 are as follows:
|
| Comprehensive Income |
| |||||||||||||||||||||||||
|
| 2003 |
| 2002 |
| 2001 |
| |||||||||||||||||||||
|
| Before-tax |
| Tax |
| Net-of-Tax |
| Before-tax |
| Tax |
| Net-of-Tax |
| Before-tax |
| Tax |
| Net-of-Tax |
| |||||||||
|
| (dollars in thousands) |
| |||||||||||||||||||||||||
Cinergy(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Net income |
| $ | 626,284 |
| $ | (156,512) |
| $ | 469,772 |
| $ | 518,840 |
| $ | (158,264) |
| $ | 360,576 |
| $ | 697,785 |
| $ | (255,506) |
| $ | 442,279 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Foreign currency translation adjustment |
| 25,311 |
| (8,649 | ) | 16,662 |
| 35,574 |
| (14,034 | ) | 21,540 |
| 4,996 |
| (3,355 | ) | 1,641 |
| |||||||||
Reclassification adjustments |
| (9,437 | ) | 3,303 |
| (6,134 | ) | 4,377 |
| — |
| 4,377 |
| — |
| — |
| — |
| |||||||||
Total foreign currency translation adjustment |
| 15,874 |
| (5,346 | ) | 10,528 |
| 39,951 |
| (14,034 | ) | 25,917 |
| 4,996 |
| (3,355 | ) | 1,641 |
| |||||||||
Minimum pension liability adjustment |
| (56,238 | ) | 22,392 |
| (33,846 | ) | (23,031 | ) | 9,268 |
| (13,763 | ) | (2,636 | ) | 1,081 |
| (1,555 | ) | |||||||||
Unrealized gain (loss) on investment trusts |
| 11,113 |
| (4,356 | ) | 6,757 |
| (8,637 | ) | 3,360 |
| (5,277 | ) | (1,345 | ) | 504 |
| (841 | ) | |||||||||
Cumulative effect of change in accounting principle |
| — |
| — |
| — |
| — |
| — |
| — |
| (4,026 | ) | 1,526 |
| (2,500 | ) | |||||||||
Cash flow hedges |
| 2,516 |
| (990 | ) | 1,526 |
| (32,663 | ) | 12,915 |
| (19,748 | ) | (4,477 | ) | 1,698 |
| (2,779 | ) | |||||||||
Total other comprehensive income (loss) |
| (26,735 | ) | 11,700 |
| (15,035 | ) | (24,380 | ) | 11,509 |
| (12,871 | ) | (7,488 | ) | 1,454 |
| (6,034 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Total comprehensive income |
| $ | 599,549 |
| $ | (144,812 | ) | $ | 454,737 |
| $ | 494,460 |
| $ | (146,755 | ) | $ | 347,705 |
| $ | 690,297 |
| $ | (254,052 | ) | $ | 436,245 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
CG&E and subsidiaries(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Net income |
| $ | 529,032 |
| $ | (197,982 | ) | $ | 331,050 |
| $ | 419,037 |
| $ | (155,341 | ) | $ | 263,696 |
| $ | 513,181 |
| $ | (186,527 | ) | $ | 326,654 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Minimum pension liability adjustment |
| (13,174 | ) | 5,157 |
| (8,017 | ) | (1,423 | ) | 551 |
| (872 | ) | 106 |
| 28 |
| 134 |
| |||||||||
Unrealized gain (loss) on investment trusts |
| 2 |
| (1 | ) | 1 |
| (745 | ) | 283 |
| (462 | ) | 743 |
| (282 | ) | 461 |
| |||||||||
Cumulative effect of change in accounting principle |
| — |
| — |
| — |
| — |
| — |
| — |
| (4,026 | ) | 1,526 |
| (2,500 | ) | |||||||||
Cash flow hedges |
| 2,133 |
| (835 | ) | 1,298 |
| (30,960 | ) | 12,226 |
| (18,734 | ) | (4,477 | ) | 1,698 |
| (2,779 | ) | |||||||||
Total other comprehensive income (loss) |
| (11,039 | ) | 4,321 |
| (6,718 | ) | (33,128 | ) | 13,060 |
| (20,068 | ) | (7,654 | ) | 2,970 |
| (4,684 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Total comprehensive income |
| $ | 517,993 |
| $ | (193,661 | ) | $ | 324,332 |
| $ | 385,909 |
| $ | (142,281 | ) | $ | 243,628 |
| $ | 505,527 |
| $ | (183,557 | ) | $ | 321,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Net income |
| $ | 233,632 |
| $ | (100,251 | ) | $ | 133,381 |
| $ | 328,958 |
| $ | (114,709 | ) | $ | 214,249 |
| $ | 268,419 |
| $ | (106,086 | ) | $ | 162,333 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Minimum pension liability adjustment |
| (19,183 | ) | 7,649 |
| (11,534 | ) | (3,534 | ) | 1,396 |
| (2,138 | ) | (76 | ) | 27 |
| (49 | ) | |||||||||
Unrealized gain (loss) on investment trusts |
| 10,236 |
| (4,004 | ) | 6,232 |
| (7,179 | ) | 2,793 |
| (4,386 | ) | (1,537 | ) | 511 |
| (1,026 | ) | |||||||||
Total other comprehensive income (loss) |
| (8,947 | ) | 3,645 |
| (5,302 | ) | (10,713 | ) | 4,189 |
| (6,524 | ) | (1,613 | ) | 538 |
| (1,075 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Total comprehensive income |
| $ | 224,685 |
| $ | (96,606 | ) | $ | 128,079 |
| $ | 318,245 |
| $ | (110,520 | ) | $ | 207,725 |
| $ | 266,806 |
| $ | (105,548 | ) | $ | 161,258 |
|
|
| Comprehensive Income |
| ||||||||||||||||||||||||||||||||||
|
| 2004 |
| 2003 |
| 2002 |
| ||||||||||||||||||||||||||||||
|
| Before-tax Amount |
| Tax (Expense) Benefit |
| Net-of-Tax Amount |
| Before-tax Amount |
| Tax (Expense) Benefit |
| Net-of-Tax Amount |
| Before-tax Amount |
| Tax (Expense) Benefit |
| Net-of-Tax Amount |
| ||||||||||||||||||
|
| (dollars in millions) |
| ||||||||||||||||||||||||||||||||||
Cinergy(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Net income |
| $ | 505 |
| $ | (104 | ) | $ | 401 |
| $ | 626 |
| $ | (156 | ) | $ | 470 |
| $ | 519 |
| $ | (158 | ) | $ | 361 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Foreign currency translation adjustment |
| 23 |
| (8 | ) | 15 |
| 25 |
| (8 | ) | 17 |
| 36 |
| (14 | ) | 22 |
| ||||||||||||||||||
Reclassification adjustments |
| — |
| — |
| — |
| (9 | ) | 3 |
| (6 | ) | 4 |
| — |
| 4 |
| ||||||||||||||||||
Total foreign currency translation adjustment |
| 23 |
| (8 | ) | 15 |
| 16 |
| (5 | ) | 11 |
| 40 |
| (14 | ) | 26 |
| ||||||||||||||||||
Minimum pension liability adjustment |
| (53 | ) | 21 |
| (32 | ) | (56 | ) | 22 |
| (34 | ) | (23 | ) | 9 |
| (14 | ) | ||||||||||||||||||
Unrealized gain (loss) on investment trusts |
| 4 |
| (2 | ) | 2 |
| 11 |
| (4 | ) | 7 |
| (8 | ) | 3 |
| (5 | ) | ||||||||||||||||||
Cash flow hedges |
| 8 |
| (3 | ) | 5 |
| 2 |
| (1 | ) | 1 |
| (33 | ) | 13 |
| (20 | ) | ||||||||||||||||||
Total other comprehensive income (loss) |
| (18 | ) | 8 |
| (10 | ) | (27 | ) | 12 |
| (15 | ) | (24 | ) | 11 |
| (13 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Total comprehensive income |
| $ | 487 |
| $ | (96 | ) | $ | 391 |
| $ | 599 |
| $ | (144 | ) | $ | 455 |
| $ | 495 |
| $ | (147 | ) | $ | 348 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
CG&E and subsidiaries(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Net income |
| $ | 415 |
| $ | (158 | ) | $ | 257 |
| $ | 529 |
| $ | (198 | ) | $ | 331 |
| $ | 419 |
| $ | (155 | ) | $ | 264 |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Minimum pension liability adjustment |
| (16 | ) | 6 |
| (10 | ) | (13 | ) | 5 |
| (8 | ) | (1 | ) | — |
| (1 | ) | ||||||||||||||||||
Cash flow hedges |
| 7 |
| (3 | ) | 4 |
| 2 |
| (1 | ) | 1 |
| (32 | ) | 13 |
| (19 | ) | ||||||||||||||||||
Total other comprehensive income (loss) |
| (9 | ) | 3 |
| (6 | ) | (11 | ) | 4 |
| (7 | ) | (33 | ) | 13 |
| (20 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||
Total comprehensive income |
| $ | 406 |
| $ | (155 | ) | $ | 251 |
| $ | 518 |
| $ | (194 | ) | $ | 324 |
| $ | 386 |
| $ | (142 | ) | $ | 244 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
PSI |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Net income |
| $ | 277 |
| $ | (112 | ) | $ | 165 |
| $ | 233 |
| $ | (100 | ) | $ | 133 |
| $ | 329 |
| $ | (115 | ) | $ | 214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Minimum pension liability adjustment |
| (21 | ) | 8 |
| (13 | ) | (18 | ) | 7 |
| (11 | ) | (3 | ) | 1 |
| (2 | ) | |||||||||
Unrealized gain (loss) on investment trusts |
| 3 |
| (1 | ) | 2 |
| 10 |
| (4 | ) | 6 |
| (7 | ) | 3 |
| (4 | ) | |||||||||
Total other comprehensive income (loss) |
| (18 | ) | 7 |
| (11 | ) | (8 | ) | 3 |
| (5 | ) | (10 | ) | 4 |
| (6 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||
Total comprehensive income |
| $ | 259 |
| $ | (105 | ) | $ | 154 |
| $ | 225 |
| $ | (97 | ) | $ | 128 |
| $ | 319 |
| $ | (111 | ) | $ | 208 |
|
(1)The results of Cinergy also include amounts related to non-registrants.
(2) IIndividualndividual amounts for ULH&P are immaterial.
221186
The after-tax components of Accumulated other comprehensive income (loss) as of December 31, 2004, 2003, 2002, and 20012002 are as follows:
|
| Accumulated Other Comprehensive Income (Loss) Classification |
| |||||||||||||
|
| Foreign |
| Minimum |
| Unrealized |
| Cash Flow |
| Total Other |
| |||||
|
| (dollars in thousands) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cinergy(1) |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2000 |
| $ | (6,072 | ) | $ | (4,780 | ) | $ | (43 | ) | $ | — |
| $ | (10,895 | ) |
Cumulative effect of change in accounting principle |
| — |
| — |
| — |
| (2,500 | ) | (2,500 | ) | |||||
Current-period change |
| 1,641 |
| (1,555 | ) | (841 | ) | (2,779 | ) | (3,534 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2001 |
| $ | (4,431 | ) | $ | (6,335 | ) | $ | (884 | ) | $ | (5,279 | ) | $ | (16,929 | ) |
Current-period change |
| 25,917 |
| (13,763 | ) | (5,277 | ) | (19,748 | ) | (12,871 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2002 |
| $ | 21,486 |
| $ | (20,098 | ) | $ | (6,161 | ) | $ | (25,027 | ) | $ | (29,800 | ) |
Current-period change |
| 10,528 |
| (33,846 | ) | 6,757 |
| 1,526 |
| (15,035 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2003 |
| $ | 32,014 |
| $ | (53,944 | ) | $ | 596 |
| $ | (23,501 | ) | $ | (44,835 | ) |
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E and subsidiaries(2) |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2000 |
| $ | — |
| $ | (994 | ) | $ | — |
| $ | — |
| $ | (994 | ) |
Cumulative effect of change in accounting principle |
| — |
| — |
| — |
| (2,500 | ) | (2,500 | ) | |||||
Current-period change |
| — |
| 134 |
| 461 |
| (2,779 | ) | (2,184 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2001 |
| $ | — |
| $ | (860 | ) | $ | 461 |
| $ | (5,279 | ) | $ | (5,678 | ) |
Current-period change |
| — |
| (872 | ) | (462 | ) | (18,734 | ) | (20,068 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2002 |
| $ | — |
| $ | (1,732 | ) | $ | (1 | ) | $ | (24,013 | ) | $ | (25,746 | ) |
Current-period change |
| — |
| (8,017 | ) | 1 |
| 1,298 |
| (6,718 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2003 |
| $ | — |
| $ | (9,749 | ) | $ | — |
| $ | (22,715 | ) | $ | (32,464 | ) |
|
|
|
|
|
|
|
|
|
|
|
| |||||
PSI |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2000 |
| $ | — |
| $ | (705 | ) | $ | 185 |
| $ | — |
| $ | (520 | ) |
Current-period change |
| — |
| (49 | ) | (1,026 | ) | — |
| (1,075 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2001 |
| $ | — |
| $ | (754 | ) | $ | (841 | ) | $ | — |
| $ | (1,595 | ) |
Current-period change |
| — |
| (2,138 | ) | (4,386 | ) | — |
| (6,524 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2002 |
| $ | — |
| $ | (2,892 | ) | $ | (5,227 | ) | $ | — |
| $ | (8,119 | ) |
Current-period change |
| — |
| (11,534 | ) | 6,232 |
| — |
| (5,302 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2003 |
| $ | — |
| $ | (14,426 | ) | $ | 1,005 |
| $ | — |
| $ | (13,421 | ) |
222
|
| Accumulated Other Comprehensive Income (Loss) Classification |
| |||||||||||||
|
| Foreign Currency Translation Adjustment |
| Minimum Pension Liability Adjustment |
| Unrealized Gain (Loss) on Investment Trusts |
| Cash Flow Hedges |
| Total Other Comprehensive Income (Loss) |
| |||||
|
| (dollars in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cinergy(1) |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2001 |
| $ | (5 | ) | $ | (6 | ) | $ | (1 | ) | $ | (5 | ) | $ | (17 | ) |
Current-period change |
| 26 |
| (14 | ) | (5 | ) | (20 | ) | (13 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2002 |
| $ | 21 |
| $ | (20 | ) | $ | (6 | ) | $ | (25 | ) | $ | (30 | ) |
Current-period change |
| 11 |
| (34 | ) | 7 |
| 1 |
| (15 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2003 |
| $ | 32 |
| $ | (54 | ) | $ | 1 |
| $ | (24 | ) | $ | (45 | ) |
Current-period change |
| 15 |
| (32 | ) | 2 |
| 5 |
| (10 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2004 |
| $ | 47 |
| $ | (86 | ) | $ | 3 |
| $ | (19 | ) | $ | (55 | ) |
|
|
|
|
|
|
|
|
|
|
|
| |||||
CG&E and subsidiaries(2) |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2001 |
| $ | — |
| $ | (1 | ) | $ | — |
| $ | (5 | ) | $ | (6 | ) |
Current-period change |
| — |
| (1 | ) | — |
| (19 | ) | (20 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2002 |
| $ | — |
| $ | (2 | ) | $ | — |
| $ | (24 | ) | $ | (26 | ) |
Current-period change |
| — |
| (8 | ) | — |
| 1 |
| (7 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2003 |
| $ | — |
| $ | (10 | ) | $ | — |
| $ | (23 | ) | $ | (33 | ) |
Current-period change |
| — |
| (9 | ) | — |
| 4 |
| (5 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2004 |
| $ | — |
| $ | (19 | ) | $ | — |
| $ | (19 | ) | $ | (38 | ) |
|
|
|
|
|
|
|
|
|
|
|
| |||||
PSI |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2001 |
| $ | — |
| $ | (1 | ) | $ | (1 | ) | $ | — |
| $ | (2 | ) |
Current-period change |
| — |
| (2 | ) | (4 | ) | — |
| (6 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2002 |
| $ | — |
| $ | (3 | ) | $ | (5 | ) | $ | — |
| $ | (8 | ) |
Current-period change |
| — |
| (11 | ) | 6 |
| — |
| (5 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2003 |
| $ | — |
| $ | (14 | ) | $ | 1 |
| $ | — |
| $ | (13 | ) |
Current-period change |
| — |
| (13 | ) | 2 |
| — |
| (11 | ) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Balance at December 31, 2004 |
| $ | — |
| $ | (27 | ) | $ | 3 |
| $ | — |
| $ | (24 | ) |
(1)The results of Cinergy also include amounts related to non-registrants.
(2)Individual amounts for ULH&P are immaterial.
223187
19. Transfer of Generating Assets
In December 2002, the IURC approved a settlement agreement among PSI, the Indiana Office of the Utility Consumer Counselor, and the IURC Testimonial Staff authorizing PSI’s purchases of the Henry County, Indiana and Butler County, Ohio, gas-fired peaking plants from two non-regulated affiliates. In February 2003, the FERC issued an order under Section 203 of the Federal Power Act authorizing PSI’s acquisitions of the plants, which occurred on February 5, 2003. Subsequently, in April 2003, the FERC issued a tolling order allowing additional time to consider a request for rehearing filed in response to the February 2003 FERC order. At this time,In September 2004, FERC issued an order denying the request for rehearing request is still pending beforeand affirming the FERC, and PSI cannot predictacquisition of the outcome of this matter.plants.
In July 2003,The KPSC has conditionally approved ULH&P&P’s filed an application with the KPSC requesting a certificateplanned acquisition of public convenience and necessity to acquire CG&E’s 68.9 percent ownership interest in the East Bend Generating Station, located in Boone County, Kentucky, the Woodsdale Generating Station, located in Butler County, Ohio, and one generating unit at the four-unit Miami Fort Station located in Hamilton County, Ohio. In December 2003,ULH&P is currently seeking approval for the KPSC conditionally approved this application.transaction from the SEC, wherein the Ohio Consumers Counsel has intervened in opposition, and the FERC. The transfer, which will be madepaid for at net book value, will not affect current electric rates for ULH&P’s customers, as power will be provided under the same terms as under the current wholesale power contract with CG&E through at least December 31, 2006. ULH&P will also seekAssuming receipt of regulatory approval for aspectsapprovals, we would anticipate the transfer to take place in the second quarter of this transaction from the FERC and SEC. At this time, ULH&P is unable to predict the outcome of this matter.2005.
224188
Disclosure with respect to this Item, for each of the registrants, has been previously provided on the Form 8-K dated April 30, 2002 and as amended on May 15, 2002.None.
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, 2003,2004, 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, 20032004 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
225Management 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, 2004. 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, 2004, was effective.
The Company’s independent auditors have issued an attestation report on management’s assessment of the Company’s internal control over financial reporting. That report follows.
189
To the Board of Directors and Stockholders of Cinergy Corp.
Cincinnati, Ohio
We have audited management’s assessment, included in the accompanying Management Report on Internal Control over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004, 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, 2004, 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, 2004, 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, 2004 of the Company and our report dated February 11, 2005 expressed an unqualified opinion on those financial statements and financial statement schedule and contained an explanatory paragraph regarding the Company’s change in accounting in 2003, for asset retirement obligations, variable interest entities, and stock-based compensation.
/s/ Deloitte & Touche LLP | |
Deloitte & Touche LLP | |
Cincinnati, Ohio | |
February 11, 2005 |
190
Information regarding Cinergy Corp.’s directors is incorporated by reference from its definitive Proxy Statement for the 20042005 Annual Meeting of Shareholders.
The directors of The Cincinnati Gas & Electric Company (CG&E) at February 6, 2004,January 31, 2005, are as follows:
• R. Foster DuncanMichael J. Cyrus -Mr. Duncan,Cyrus, age 49, is Executive Vice President and Chief Financial Officer of CG&E, a position he has held since February 2001. He has served as director of CG&E since AprilSeptember 2001. His current term as director expires May 3, 2004.4, 2005.
• James E. Rogers - Mr. Rogers, age 56,57, is Chairman of the Board and Chief Executive Officer of CG&E. He has served as a director of CG&E since 1994. His current term as director expires May 3, 2004.4, 2005.
• James L. Turner - Mr. Turner, age 44,45, is Executive Vice President and Chief Financial Officer of CG&E, a position he has held since September 2004. Prior to that, Mr. Turner served as Executive Vice President of CG&E since July 2000. He served as a director of CG&E from February 15, 1999 to April 30, 2001 at which time Mr. William J. Grealis was elected as successor-director to Mr. Turner. Mr. Turnerand was re-elected, effective October 1, 2001, as successor-director to Mr. Grealis.2001. Mr. Turner’s current term as director expires May 3, 2004.4, 2005.
Additional information on each of the directors of CG&E is presented in the following “Executive Officers” section.
Information regarding PSI Energy, Inc.’s (PSI) directors is incorporated by reference from PSI’s 20042005 Information Statement.
226192
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 February 6, 2004)January 31, 2005), and their business experience during the past five years is included in the chart below.
Positions and Length of Service | ||||||||
Name | Age | Cinergy Corp. | CG&E | PSI | ||||
Michael J. Cyrus |
|
|
| Executive Vice President | Executive Vice President | Executive Vice President | ||
R. Foster Duncan(1) |
|
|
| Executive Vice President | Executive Vice President | Executive Vice President | ||
|
|
|
| |||||
Gregory C. Ficke |
|
|
| Vice President and Chief Information Officer, Regulated | President |
|
| |
227
Lynn J. Good(2) |
|
|
| Vice President, Finance and Controller | Vice President, |
| Vice President, Finance and Controller | |||
William J. Grealis |
|
|
| Executive Vice President | Executive Vice President | Executive Vice President
| ||||
Julia S. Janson | 40 | Chief Compliance Officer | Chief Compliance Officer | Chief Compliance Officer |
193
Positions and Length of Service | ||||||||
Name | Age | Cinergy Corp. | CG&E | PSI | ||||
Marc E. Manly(3) |
|
|
| Executive Vice President and Chief Legal Officer | Executive Vice President and Chief Legal Officer | Executive Vice President and Chief Legal Officer | ||
Theodore R. Murphy II(4) |
|
|
| Senior Vice President and Chief Risk Officer | Senior Vice President and Chief Risk Officer | Senior Vice President and Chief Risk Officer | ||
Frederick J. Newton III(5) |
|
|
| Executive Vice President and Chief Administrative Officer | Executive Vice President and Chief Administrative Officer | Executive Vice President and Chief Administrative Officer | ||
Kay E. Pashos | 45 | Vice President and General Counsel, Regulated Business Unit | President | |||||
Ronald R. Reising(6) | 44 | Chief Procurement Officer | Chief Procurement Officer | Chief Procurement Officer | ||||
James E. Rogers |
|
| Chairman of the Board | Chairman of the Board | Chairman of the Board | |||
James L. |
|
| Executive Vice President | Executive Vice President | Executive Vice President | |||
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) | Prior to joining Cinergy, Mr. Duncan was Executive Vice President and Chief Financial Officer of LG&E Energy Corp. (LG&E) (a non-affiliate of Cinergy) in Louisville, Kentucky since December 1998. |
| |
(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. Prior to that, he was Vice President, Chief Counsel for AT&T Consumer Services Group (a non-affiliate of Cinergy) from January 1995 to April 2000. 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. |
194
(1)Prior to joining Cinergy, Mr. Duncan was Executive Vice President and Chief Financial Officer of LG&E Energy Corp. (LG&E) (a non-affiliate of Cinergy) in Louisville, Kentucky since December 1998.
228
(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.
(6) Prior to joining Cinergy, Mr. Reising was Chief Financial Officer of Focal Communications Corporation (a non-affiliate of Cinergy) from February 2001 to January 2002. Prior to that, he was Chief Financial Officer of Derivon (a non-affiliate of Cinergy) from May 2000 to February 2001. Prior to that, he was Chief Financial Officer of Bell Canada (a non-affiliate of Cinergy) from May 1999 to May 2000. On December 19, 2002, Focal Communications filed a petition for relief under Chapter 11 of The United States Bankruptcy Code. (7) 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. Information in response to Item 405 of Regulation S-K and regarding Cinergy Corp.’s audit committee required by Items 401(h) and 401(i) of Regulation S-K is incorporated by reference from its definitive Proxy Statement for the (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. Prior to that, he was Vice President, Chief Counsel for AT&T Consumer Services Group (a non-affiliate of Cinergy) from January 1995 to April 2000. On June 11, 2002, NewPower Holdings, Inc. and its affiliates, TNPC Holdings, Inc. and the NewPower Company,(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)Beginning in April 1998 until January 2000, Mr. Turner had full responsibility for Cinergy’s Government and Regulatory Affairs Department. Mr. Turner served as Vice President of Customer Services from January 2000 until July 2000.20042005 Annual Meeting of Shareholders.229195
Information in response to this item for Cinergy Corp. and CG&E is incorporated by reference from Cinergy Corp.’s definitive Proxy Statement for the 20042005 Annual Meeting of Shareholders.
All CG&E directors currently are employees of Cinergy and receive no compensation for their services as directors.
Information in response to this item for PSI is incorporated by reference from PSI’s 20042005 Information Statement.
AND RELATED STOCKHOLDER MATTERS
Information in response to this item for Cinergy Corp. is incorporated by reference from its definitive Proxy Statement for the 20042005 Annual Meeting of Shareholders.
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 February 6, 2004.January 31, 2005. The beneficial ownership of Cinergy Corp. common stock by each director and named executive officer of CG&E as of February 6, 2004,January 31, 2005, is set forth in the following table:
Name of Beneficial Owner | Amount and Nature of | Percent of | |||
|
|
|
|
|
|
Michael J. Cyrus |
|
|
|
| * |
R. Foster Duncan |
|
|
|
| * |
William J. Grealis |
|
|
|
| * |
|
|
|
|
| * |
James E. Rogers |
|
|
|
|
|
All directors and executive officers as a group |
|
|
|
| % |
*
| Less than 1 percent |
(1) | Includes shares which there is a right to acquire within 60 days pursuant to the exercise of stock options in the following amounts: Mr. Cyrus - 141,799; Mr. Duncan - 213,500; Mr. Grealis - 235,701; Mr. Turner - 101,626; Mr. Rogers - 970,300; and all directors and executive officers as a group - 1,768,036. |
Information in response to this item for PSI is incorporated by reference from its 20042005 Information Statement.
230196
The following table reflects Cinergy’s equity compensation plan information as of December 31, 2003:2004:
Equity Compensation Plan Information
Plan Category |
| Number of securities to |
| Weighted-average |
| Number of securities |
|
| Number of securities to be issued upon exercise of outstanding options, warrants and rights |
| Weighted-average exercise price of outstanding options, warrants and rights |
| Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Equity compensation plans approved by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Cinergy Corp. 1996 Long-Term Incentive Compensation Plan |
| 7,070,221 |
| $ | 29.37 |
| 4,346,877 |
|
| 6,564,519 |
| $ | 33.25 |
| 3,122,900 |
|
Cinergy Corp. Stock Option Plan |
| 1,021,923 |
| $ | 29.95 |
| 1,318,500 |
|
| 628,400 |
| $ | 34.12 |
| 1,318,500 |
|
Cinergy Corp. Employee Stock Purchase and Savings Plan |
| — |
| N/A |
| 1,482,664 |
|
| — |
| N/A |
| 1,482,664 |
| ||
Cinergy Corp. Retirement Plan for Directors |
| 85,288 |
| N/A |
| — |
|
| 3,917 |
| N/A |
| — |
| ||
Cinergy Corp. Directors’ Equity Compensation Plan |
| 22,201 |
| N/A |
| 46,771 |
|
| 26,843 |
| N/A |
| 41,034 |
| ||
Cinergy Corp. Directors’ Deferred Compensation Plan |
| 48,639 |
| N/A |
| 108,547 |
|
| 48,564 |
| N/A |
| 103,234 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Equity compensation plans not approved by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Cinergy Corp. UK Sharesave Scheme |
| 6,876 |
| $ | 25.14 |
| 62,637 |
|
| 436 |
| $ | 25.14 |
| 62,200 |
|
Cinergy Corp. 401(k) Excess Plan |
| 76,604 |
| N/A |
| — |
|
| 77,558 |
| N/A |
| — |
| ||
|
|
|
|
|
|
|
| |||||||||
The following information describes the equity compensation plans that have not been approved by shareholders.
The Cinergy Corp. UK Sharesave Scheme allows essentially all full-time, regular 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. A participant may elect to terminate participation in the plan at any time. Participation also will terminate if the participant’s employment ceases. Upon termination of participation, all funds are returned to the participant without penalty although, in certain specified circumstances, options may be exercised early on a pro-rata basis.
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
231
the maximum amount (pursuant to the anti-discrimination rules for highly compensated employees) under the 401(k) Plan. All funds deferred are held in a rabbi trust administered by an independent trustee.
Information in response to this item for Cinergy Corp. and CG&E is incorporated by reference from Cinergy Corp.’s definitive Proxy Statement for the 20042005 Annual Meeting of Shareholders.
Information in response to this item for PSI is incorporated by reference from PSI’s 20042005 Information Statement.
197
Information in response to this Itemitem for Cinergy, CG&E and PSI is incorporated by reference from Cinergy Corp.’s definitive Proxy Statement for the 20042005 Annual Meeting of Shareholders.
232198
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.
The following reports on Form 8-K were furnished or filed during the quarter ended December 31, 2003.
|
|
| |||
|
|
|
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:
Exhibit | Registrant(s)(1) | Nature of Exhibit | Previously Filed as | |||
Articles of Incorporation /By-laws | ||||||
3-a |
| Cinergy Corp. |
| Certificate of Incorporation of Cinergy Corp., a Delaware corporation, as amended May 10, 2001. | Cinergy Corp. March 31, 2001, Form 10-Q | |
3-b |
| Cinergy Corp. |
| By-Laws of Cinergy Corp., as amended on July 23, 2003. | Cinergy Corp. June 30, 2003, Form 10-Q | |
3-c |
| CG&E |
| Amended Articles of Incorporation of CG&E effective October 23, 1996. | CG&E September 30, 1996, Form 10-Q | |
3-d |
| CG&E |
| Regulations of CG&E, as amended on July 23, 2003. | CG&E June 30, 2003, Form 10-Q | |
3-e |
| PSI |
| Amended Articles of Consolidation of PSI, as amended April 20, 1995. | PSI June 30, 1995, Form 10-Q | |
3-f |
| PSI |
| Amendment to Article D of the Amended Articles of Consolidation of PSI, effective July 10, 1997. |
| |
3-g |
| PSI |
| By-Laws of PSI, as amended on July 23, 2003. | PSI June 30, 2003, Form 10-Q | |
3-h |
| ULH&P |
| Restated Articles of Incorporation made effective May 7, 1976. | ULH&P Form 8-K, May 1976 | |
3-i |
| ULH&P |
| By-Laws of ULH&P, as amended on July 23, 2003. | ULH&P June 30, 2003, Form 10-Q | |
3-j |
| ULH&P |
| Amendment to Restated Articles of Incorporation of ULH&P (Article Third) and Amendment to the By-Laws of ULH&P (Article 1), both effective July 24, 1997. |
| |
Instruments defining the rights of holders, incl. Indentures |
233
4-a |
| Cinergy Corp. PSI |
| Original Indenture (First Mortgage Bonds) dated September 1, 1939, between PSI and The First National Bank of Chicago, as Trustee, and LaSalle National Bank, as Successor Trustee. |
| Exhibit A-Part 3 in File No. 70-258 Supplemental Indenture dated March 30, 1984 |
4-b |
| Cinergy Corp. PSI |
| Twenty-fifth Supplemental Indenture between PSI and The First National Bank of Chicago dated September 1, 1978. |
| File No. 2-62543 |
4-c |
| Cinergy Corp. PSI |
| Thirty-fifth Supplemental Indenture between PSI and The First National Bank of Chicago dated March 30, 1984. | PSI 1984 Form 10-K | |
4-d |
| Cinergy Corp. PSI |
| Forty-second Supplemental Indenture between PSI and LaSalle National Bank dated August 1, 1988. | PSI 1988 Form 10-K | |
4-e |
| Cinergy Corp. PSI |
| Forty-fourth Supplemental Indenture between PSI and LaSalle National Bank dated March 15, 1990. | PSI 1990 Form 10-K | |
4-f |
| Cinergy Corp. PSI |
| Forty-fifth Supplemental Indenture between PSI and LaSalle National Bank dated March 15, 1990. | PSI 1990 Form 10-K | |
4-g |
| Cinergy Corp. PSI |
| Forty-sixth Supplemental Indenture between PSI and LaSalle National Bank dated June 1, 1990. | PSI 1991 Form 10-K | |
4-h |
| Cinergy Corp. PSI |
| Forty-seventh Supplemental Indenture between PSI and LaSalle National Bank dated July 15, 1991. | PSI 1991 Form 10-K | |
4-i |
| Cinergy Corp. PSI |
| Forty-eighth Supplemental Indenture between PSI and LaSalle National Bank dated July 15, 1992. | PSI 1992 Form 10-K | |
4-j |
| Cinergy Corp. PSI |
| Forty-ninth Supplemental Indenture between PSI and LaSalle National Bank dated February 15, 1993. | PSI 1992 Form 10-K | |
4-k |
| Cinergy Corp. PSI |
| Fiftieth Supplemental Indenture between PSI and LaSalle National Bank dated February 15, 1993. | PSI 1992 Form 10-K |
199
4-l |
| Cinergy Corp. PSI |
| Fifty-first Supplemental Indenture between PSI and LaSalle National Bank dated February 1, 1994. | PSI 1993 Form 10-K | |
4-m |
| Cinergy Corp. PSI |
| Fifty-second Supplemental Indenture between PSI and LaSalle National Bank, as Trustee, dated as of April 30, 1999. | PSI March 31, 1999, Form 10-Q | |
4-n |
| Cinergy Corp. PSI |
| Fifty-third Supplemental Indenture between PSI and LaSalle National Bank dated June 15, 2001. |
| |
4-o |
| Cinergy Corp. PSI |
| Fifty-fifth Supplemental Indenture between PSI and LaSalle National Bank dated February 15, 2003. |
| |
4-p |
| Cinergy Corp. PSI |
| Indenture (Secured Medium-term Notes, Series A), dated July 15, 1991, between PSI and LaSalle National Bank, as Trustee. | PSI Form 10-K/A, Amendment No. 2, dated July 15, 1993 | |
4-q |
| Cinergy Corp. PSI |
| Indenture (Secured Medium-term Notes, Series B), dated July 15, 1992, between PSI and LaSalle National Bank, as Trustee. | PSI Form 10-K/A, Amendment No. 2, dated July 15, 1993 | |
4-r |
| Cinergy Corp. PSI |
| Loan Agreement between PSI and the City of Princeton, Indiana dated as of November 7, 1996. | PSI September 30, 1996, Form 10-Q | |
4-s |
| Cinergy Corp. PSI |
| Loan Agreement between PSI and the City of Princeton, Indiana dated as of February 1, 1997. |
| |
4-t |
| Cinergy Corp. PSI |
| Indenture dated November 15, 1996, between PSI and The Fifth Third Bank, as Trustee. |
| |
4-u |
| Cinergy Corp. PSI |
| First Supplemental Indenture dated November 15, 1996, between PSI and The Fifth Third Bank, as Trustee. |
| |
4-v |
| Cinergy Corp. PSI |
| Third Supplemental Indenture dated as of March 15, 1998, between PSI and The Fifth Third Bank, as Trustee. |
| |
4-w |
| Cinergy Corp. PSI |
| Fourth Supplemental Indenture dated as of August 5, 1998, between PSI and The Fifth Third Bank, as Trustee. | PSI June 30, 1998, Form 10-Q | |
4-x |
| Cinergy Corp. PSI |
| Fifth Supplemental Indenture dated as of December 15, 1998, between PSI and The Fifth Third Bank, as Trustee. | PSI 1998 Form 10-K | |
4-y |
| Cinergy Corp. PSI |
| Sixth Supplemental Indenture dated as of April 30, 1999, between PSI and Fifth Third Bank, as Trustee. | PSI March 31, 1999, Form 10-Q | |
4-z |
| Cinergy Corp. PSI |
| Seventh Supplemental Indenture dated as of October 20, 1999, between PSI and Fifth Third Bank, as Trustee. | PSI September 30, 1999, Form 10-Q | |
4-aa |
| Cinergy Corp. PSI |
| Eighth Supplemental Indenture dated as of September 23, 2003, between PSI and Fifth Third Bank, as Trustee. | PSI September 30, 2003, Form 10-Q | |
4-bb |
| Cinergy Corp. PSI |
| Unsecured Promissory Note dated October 14, 1998, between PSI and the Rural Utilities Service. | PSI 1998 Form 10-K | |
4-cc |
| Cinergy Corp. PSI |
| Loan Agreement between PSI and the Indiana Development Finance Authority dated as of July 15, 1998. | PSI June 30, 1998, Form 10-Q | |
4-dd |
| Cinergy Corp. PSI |
| Loan Agreement between PSI and the Indiana Development Finance Authority dated as of May 1, 2000. | PSI June 30, 2000, Form 10-Q | |
4-ee |
| Cinergy Corp. CG&E |
| Original Indenture (First Mortgage Bonds) between CG&E and The Bank of New York (as Trustee) dated as of August 1, 1936. | CG&E Registration Statement No. 2-2374 | |
4-ff |
| Cinergy Corp. CG&E |
| Fourteenth Supplemental Indenture between CG&E and The Bank of New York dated as of November 2, 1972. | CG&E Registration Statement No. 2-60961 |
234
4-gg |
| Cinergy Corp. CG&E |
| Thirty-third Supplemental Indenture between CG&E and The Bank of New York dated as of September 1, 1992. | CG&E Registration Statement No. 33-53578 | |
4-hh |
| Cinergy Corp. CG&E |
| Thirty-fourth Supplemental Indenture between CG&E and The Bank of New York dated as of October 1, 1993. | CG&E September 30, 1993, Form 10-Q | |
4-ii |
| Cinergy Corp. CG&E |
| Thirty-fifth Supplemental Indenture between CG&E and The Bank of New York dated as of January 1, 1994. | CG&E Registration Statement No. 33-52335 | |
4-jj |
| Cinergy Corp. CG&E |
| Thirty-sixth Supplemental Indenture between CG&E and The Bank of New York dated as of February 15, 1994. | CG&E Registration Statement No. 33-52335 | |
4-kk |
| Cinergy Corp. CG&E |
| Thirty-seventh Supplemental Indenture between CG&E and The Bank of New York dated as of October 14, 1996. |
| |
4-ll |
| Cinergy Corp. CG&E |
| Thirty-eighth Supplemental Indenture between CG&E and The Bank of New York dated as of February 1, 2001. |
| |
4-mm |
| Cinergy Corp. CG&E |
| Loan Agreement between CG&E and the County of Boone, Kentucky dated as of February 1, 1985. | CG&E 1984 Form 10-K | |
4-nn |
| Cinergy Corp. CG&E |
| Repayment Agreement between CG&E and The Dayton Power and Light Company dated as of December 23, 1992. | CG&E 1992 Form 10-K | |
4-oo |
| Cinergy Corp. CG&E |
| Loan Agreement between CG&E and the County of Boone, Kentucky dated as of January 1, 1994. | CG&E 1993 Form 10-K | |
4-pp |
| Cinergy Corp. CG&E |
| Loan Agreement between CG&E and the State of Ohio Air Quality Development Authority dated as of December 1, 1985. | CG&E 1985 Form 10-K | |
4-qq |
| Cinergy Corp. CG&E |
| Loan Agreement between CG&E and the State of Ohio Air Quality Development Authority dated as of September 13, 1995. | CG&E September 30, 1995, Form 10-Q | |
4-rr |
| Cinergy Corp. CG&E |
| Loan Agreement between CG&E and the State of Ohio Water Development Authority dated as of January 1, 1994. | CG&E 1993 Form 10-K |
200
4-ss |
| Cinergy Corp. CG&E |
| Loan Agreement between CG&E and the State of Ohio Air Quality Development Authority dated as of January 1, 1994. | CG&E 1993 Form 10-K | |
4-tt |
| CG&E |
| Loan Agreement between CG&E and the State of Ohio Air Quality Development Authority dated August 1, 2001. |
| |
4-uu |
| Cinergy Corp. CG&E |
| Original Indenture (Unsecured Debt Securities) between CG&E and The Fifth Third Bank dated as of May 15, 1995. | CG&E Form 8-A dated July 24, 1995 | |
4-vv |
| Cinergy Corp. CG&E |
| First Supplemental Indenture between CG&E and The Fifth Third Bank dated as of June 1, 1995. | CG&E June 30, 1995, Form 10-Q | |
4-ww |
| Cinergy Corp. CG&E |
| Second Supplemental Indenture between CG&E and The Fifth Third Bank dated as of June 30, 1995. | CG&E Form 8-A dated July 24, 1995 | |
4-xx |
| Cinergy Corp. CG&E |
| Third Supplemental Indenture between CG&E and The Fifth Third Bank dated as of October 9, 1997. | CG&E September 30, 1997, Form 10-Q | |
4-yy |
| Cinergy Corp. CG&E |
| Fourth Supplemental Indenture between CG&E and The Fifth Third Bank dated as of April 1, 1998. | CG&E March 31, 1998, Form 10-Q | |
4-zz |
| Cinergy Corp. CG&E |
| Fifth Supplemental Indenture between CG&E and The Fifth Third Bank dated as of June 9, 1998. | CG&E June 30, 1998, Form 10-Q | |
4-aaa |
| Cinergy Corp. CG&E |
| Seventh Supplemental Indenture between CG&E and The Fifth Third Bank dated as of June 15, 2003. | CG&E June 30, 2003, Form 10-Q | |
4-bbb |
| Cinergy Corp. CG&E |
| Original Indenture (First Mortgage Bonds) between ULH&P and The Bank of New York dated as of February 1, 1949. | ULH&P Registration Statement No. 2-7793 | |
4-ccc |
| Cinergy Corp. CG&E |
| Fifth Supplemental Indenture between ULH&P and The Bank of New York dated as of January 1, 1967. | CG&E Registration Statement No. 2-60961 | |
4-ddd |
| Cinergy Corp. CG&E |
| Thirteenth Supplemental Indenture between ULH&P and The Bank of New York dated as of August 1, 1992. | ULH&P 1992 Form 10-K | |
4-eee |
| Cinergy Corp. CG&E |
| Original Indenture (Unsecured Debt Securities) between ULH&P and The Fifth Third Bank dated as of July 1, 1995. | ULH&P June 30, 1995, Form 10-Q | |
4-fff |
| Cinergy Corp. CG&E |
| First Supplemental Indenture between ULH&P and The Fifth Third Bank dated as of July 15, 1995. | ULH&P June 30, 1995, Form 10-Q | |
4-ggg |
| Cinergy Corp. CG&E |
| Second Supplemental Indenture between ULH&P and The Fifth Third Bank dated as of April 30, 1998. | ULH&P March 31, 1998, Form 10-Q | |
4-hhh |
| Cinergy Corp. CG&E |
| Third Supplemental Indenture between ULH&P and The Fifth Third Bank dated as of December 8, 1998. | ULH&P 1998 Form 10-K |
235
4-iii |
| Cinergy Corp. CG&E |
| Fourth Supplemental Indenture between ULH&P and The Fifth Third Bank, as Trustee, dated as of September 17, 1999. | ULH&P September 30, 1999, Form 10-Q | |
4-jjj |
| Cinergy Corp. |
| Base Indenture dated as of October 15, 1998, between Global Resources and The Fifth Third Bank, as Trustee. | Cinergy Corp. September 30, 1998, Form 10-Q | |
4-kkk |
| Cinergy Corp. |
| First Supplemental Indenture dated as of October 15, 1998, between Global Resources and The Fifth Third Bank, as Trustee. | Cinergy Corp. September 30, 1998, Form 10-Q | |
4-lll |
| Cinergy Corp. |
| Indenture dated as of December 16, 1998, between Cinergy Corp. and The Fifth Third Bank. | Cinergy Corp. 1998 Form 10-K | |
4-mmm |
| Cinergy Corp. |
| Indenture between Cinergy Corp. and The Fifth Third Bank, as Trustee, dated as of April 15, 1999. | Cinergy Corp. March 31, 1999, Form 10-Q | |
4-nnn |
| Cinergy Corp. |
| Indenture between Cinergy Corp. and The Fifth Third Bank, as Trustee, dated September 12, 2001. | Cinergy Corp. September 30, 2001, Form 10-Q | |
4-ooo |
| Cinergy Corp. |
| First Supplemental Indenture between Cinergy Corp. and The Fifth Third Bank, as Trustee, dated September 12, 2001. | Cinergy Corp. September 30, 2001, Form 10-Q | |
4-ppp |
| Cinergy Corp. |
| Second Supplemental Indenture, dated December 18, 2001, between Cinergy Corp. and The Fifth Third Bank, as Trustee. | Cinergy Corp. Form 8-K, December 19, 2001 | |
4-qqq |
| Cinergy Corp. |
| Rights Agreement between Cinergy Corp. and The Fifth Third Bank, as Rights Agent, dated October 16, 2000. | Cinergy Corp. Registration Statement on Form 8-A dated October 16, 2000 | |
4-rrr |
| Cinergy Corp. |
| Purchase Contract Agreement, dated December 18, 2001, between Cinergy Corp. and The Bank of New York, as Purchase Contract Agent. | Cinergy Corp. Form 8-K, December 19, 2001 | |
4-sss |
| Cinergy Corp. |
| Pledge Agreement, dated December 18, 2001, among Cinergy Corp., JP Morgan Chase Bank, as Collateral Agent, Custodial Agent and Securities Intermediary, and The Bank of New York, as Purchase Contract Agent. | Cinergy Corp. Form 8-K, December 19, 2001 |
201
4-ttt |
| Cinergy Corp. |
| Thirty-ninth Supplemental Indenture dated as of September 1, 2002, between CG&E and The Bank of New York, as Trustee. | Cinergy Corp. September 30, 2002, Form 10-Q | |
4-uuu |
| Cinergy |
| Fifty-fourth Supplemental Indenture dated as of September 1, 2002, between PSI and LaSalle Bank National Association, as Trustee. | Cinergy Corp. September 30, 2002, Form 10-Q | |
4-vvv |
| Cinergy Corp. |
| Sixth Supplemental Indenture between CG&E and Fifth Third Bank dated as of September 15, 2002. | Cinergy Corp. September 30, 2002, Form 10-Q | |
4-www |
| Cinergy |
| Loan Agreement between PSI and the Indiana Development Finance Authority dated as of September 1, 2002. | Cinergy Corp. September 30, 2002, Form 10-Q | |
4-xxx |
| Cinergy Corp. |
| Loan Agreement between PSI and the Indiana Development Finance Authority dated as of September 1, 2002. | Cinergy Corp. September 30, 2002, Form 10-Q | |
4-yyy |
| Cinergy Corp. |
| Loan Agreement between CG&E and the Ohio Air Quality Development Authority dated as of September 1, 2002. | Cinergy Corp. September 30, 2002, Form 10-Q | |
4-zzz |
| Cinergy Corp. |
| First Amendment to Rights Agreement, dated August 28, 2002, effective September 16, 2002, between Cinergy Corp. and The Fifth Third Bank, as Rights Agent. | Cinergy Corp. Form 8-A/A, Amendment No. 1, filed September 16, 2002 | |
4-aaaa |
| PSI |
| Loan Agreement between PSI and the Indiana Development Finance Authority dated as of February 15, 2003. | PSI March 31, 2003, Form 10-Q | |
4-bbbb |
| PSI |
| 6.302% Subordinated Note between PSI and Cinergy Corp., dated February 5, 2003. | PSI March 31, 2003, Form 10-Q | |
4-cccc |
| PSI |
| 6.403% Subordinated Note between PSI and Cinergy Corp., dated February 5, 2003. | PSI March 31, 2003, Form 10-Q | |
4-dddd | CG&E | Loan Agreement between CG&E and the Ohio Air Quality Development Authority dated as of November 1, 2004, relating to Series A | CG&E Form 8-K, filed November 19, 2004 | |||
4-eeee | CG&E | Loan Agreement between CG&E and the Ohio Air Quality Development Authority dated as of November 1, 2004, relating to Series B | CG&E Form 8-K, filed November 19, 2004 | |||
4-ffff | PSI | Loan Agreement between PSI and the Indiana Development Finance Authority dated as of December 1, 2004, relating to Series 2004B | PSI Form 8-K, filed December 9, 2004 | |||
4-gggg | PSI | Loan Agreement between PSI and the Indiana Development Finance Authority dated as of December 1, 2004, relating to Series 2004C | PSI Form 8-K, filed December 9, 2004 | |||
4-hhhh | Cinergy Corp. | Fifty-Sixth Supplemental Indenture dated as of December 1, 2004, between PSI and LaSalle Bank National Association, as Trustee | ||||
4-iiii | Cinergy Corp. | Indenture between ULH&P and Deutsche Bank dated as of December 1, 2004, between ULH&P and Deutsche Bank Trust Company Americas, as Trustee | ||||
Material |
|
|
|
|
| |
10-a |
| Cinergy Corp. CG&E |
| Amended and Restated Employment Agreement dated October 24, 1994, among CG&E, Cinergy Corp., PSI Resources, Inc., and PSI, and Jackson H. Randolph. | Cinergy Corp. 1994 Form 10-K | |
10-b |
| Cinergy Corp. CG&E |
| Employment Agreement dated February 4, 2004, among Cinergy Corp., CG&E, and PSI, and James E. Rogers. | Cinergy Corp. 2003 Form 10-K | |
10-c |
| Cinergy Corp. CG&E |
| Amended and Restated Employment Agreement dated October 11, 2002, among Cinergy Corp., Cinergy Services, Inc. (Services), CG&E, and PSI, and William J. Grealis. | Cinergy Corp. 2002 Form 10-K | |
10-d |
| Cinergy Corp. CG&E |
| Amended Employment Agreement effective December 17, 2003 to Employment Agreement dated October 11, 2002, among Cinergy Corp., Services, CG&E, and PSI, and William J. Grealis. | Cinergy Corp. 2003 Form 10-K | |
10-e |
| Cinergy Corp. CG&E |
| Amended and Restated Employment Agreement dated October 1, 2002, among Cinergy Corp., Services, CG&E, and PSI, and Donald B. Ingle, Jr. | Cinergy Corp. 2002 Form 10-K |
236
10-f |
| Cinergy Corp. CG&E |
| Amended and Restated Employment Agreement dated September 12, 2002, among Cinergy Corp., Services, CG&E, and PSI, and Michael J. Cyrus. | Cinergy Corp. 2002 Form 10-K | |
10-g |
| Cinergy Corp. |
| Amended Employment Agreement effective December 17, 2003 to Employment Agreement dated September 12, 2002, among Cinergy Corp., Services, CG&E, and PSI, and Michael J. Cyrus. | Cinergy Corp. 2003 Form 10-K | |
10-h |
| Cinergy Corp. |
| Amended and Restated Employment Agreement dated September 24, 2002, among Cinergy Corp., Services, CG&E, and PSI, and James L. Turner. | Cinergy Corp. 2002 Form 10-K | |
10-i |
| Cinergy Corp. |
| Amended Employment Agreement effective December 17, 2003 to Employment Agreement dated September 24, 2002, among Cinergy Corp., Services, CG&E, and PSI, and James L. Turner. | Cinergy Corp. 2003 Form 10-K | |
10-j |
| Cinergy Corp. |
| Amended and Restated Employment Agreement dated January 1, 2002, among Cinergy Corp., Services, CG&E, and PSI, and R. Foster Duncan. | Cinergy Corp. 2002 Form 10-K | |
10-k |
| Cinergy Corp. |
| Amended Employment Agreement effective December 17, 2003 to Employment Agreement dated January 1, 2002, among Cinergy Corp., Services, CG&E, and PSI, and R. Foster Duncan. | Cinergy Corp. 2003 Form 10-K | |
10-l |
| Cinergy Corp. |
| Employment Agreement dated November 15, 2002, among Cinergy Corp., CG&E, and PSI and Marc E. Manly. | Cinergy Corp. 2003 Form 10-K | |
10-m |
| Cinergy Corp. |
| Amended Employment Agreement effective December 17, 2003 to Employment Agreement dated November 15, 2002, among Cinergy Corp., CG&E, and PSI, and Marc E. Manly. | Cinergy Corp. 2003 Form 10-K | |
10-n |
| Cinergy Corp. |
| Amended and Restated Separation and Retirement Agreement and Waiver and Release of Liability dated February 15, 2002, between Cinergy Corp., and Larry E. Thomas. | Cinergy Corp. 2001 Form 10-K |
202
10-o |
| Cinergy Corp. |
| Separation and Retirement Agreement and Waiver and Release of Liability dated October 8, 2002 between Cinergy Corp. and Donald B. Ingle, Jr. | Cinergy Corp. 2002 Form 10-K | |
10-p |
| Cinergy Corp. PSI |
| Deferred Compensation Agreement, effective as of January 1, 1992, between PSI and James E. Rogers. | PSI Form 10-K/A, Amendment No. 1, dated April 29, 1993 | |
10-q |
| Cinergy Corp. PSI |
| Split Dollar Life Insurance Agreement, effective as of January 1, 1992, between PSI and James E. Rogers. | PSI Form 10-K/A, Amendment No. 1, dated April 29, 1993 | |
10-r |
| Cinergy Corp. PSI |
| First Amendment to Split Dollar Life Insurance Agreement between PSI and James E. Rogers dated December 11, 1992. | PSI Form 10-K/A, Amendment No. 1, dated April 29, 1993 | |
10-s |
| Cinergy Corp. CG&E |
| Deferred Compensation Agreement between CG&E and Jackson H. Randolph dated January 1, 1992. | CG&E 1992 Form 10-K | |
10-t |
| Cinergy Corp. CG&E |
| Split Dollar Insurance Agreement, effective as of May 1, 1993, between CG&E and Jackson H. Randolph. |
| |
10-u |
| Cinergy Corp. CG&E |
| Amended and Restated Supplemental Retirement Income Agreement between CG&E and Jackson H. Randolph dated January 1, 1995. |
| |
10-v |
| Cinergy Corp. CG&E |
| Amended and Restated Supplemental Executive Retirement Income Agreement between CG&E and certain executive officers. |
| |
10-w |
| Cinergy Corp. | Cinergy Corp. Supplemental Executive Retirement Plan amended and restated effective January 1, 1999, adopted October 15, 1998. | Cinergy Corp. 1999 Form 10-K | ||
10-x |
| Cinergy Corp. |
| Amendment to Cinergy Corp. Supplemental Executive Retirement Plan, effective January 1, 2003, adopted October 10, 2003. | Cinergy Corp. 2003 Form 10-K | |
10-y |
| Cinergy Corp. |
| Amendment to Cinergy Corp. Supplemental Executive Retirement Plan, effective January 1, 2003, adopted December 15, 2003. | Cinergy Corp. 2003 Form 10-K | |
10-z |
| Cinergy Corp. |
| 1997 Amendments to Various Compensation and Benefit Plans of Cinergy Corp., adopted January 30, 1997. | Cinergy Corp. 1997 Form 10-K | |
10-aa |
| Cinergy Corp. | Cinergy Corp. Stock Option Plan, adopted October 18, 1994, effective October 24, 1994. | Cinergy Corp. Form S-8, filed October 19, 1994 | ||
10-bb |
| Cinergy Corp. |
| Amendment to Cinergy Corp. Stock Option Plan, amended October 22, 1996, effective November 1, 1996. | Cinergy Corp. September 30, 1996, Form 10-Q | |
10-cc |
| Cinergy Corp. |
| Amended and Restated Cinergy Corp. Annual Incentive Plan, effective January 25, 2002. | Cinergy Corp. 2001 Form 10-K | |
10-dd |
| Cinergy Corp. | Cinergy Corp. Employee Stock Purchase and Savings Plan, adopted October 18, 1994, effective October 24, 1994. | Cinergy Corp. Form S-8, filed October 19, 1994 | ||
10-ee |
| Cinergy Corp. |
| Amendment to Cinergy Corp. Employee Stock Purchase and Savings Plan, adopted April 26, 1996, effective January 1, 1996. | Cinergy Corp. June 30, 1996, Form 10-Q |
237
10-ff |
| Cinergy Corp. |
| Amendment to Cinergy Corp. Employee Stock Purchase and Savings Plan, adopted October 22, 1996, effective November 1, 1996. | Cinergy Corp. September 30, 1996, Form 10-Q | |
10-gg |
| Cinergy Corp. | Cinergy Corp. UK Sharesave Scheme, adopted and effective December 16, 1999. | Cinergy Corp. 1999 Form 10-K | ||
10-hh |
| Cinergy Corp. | Cinergy Corp. Directors’ Deferred Compensation Plan, adopted October 18, 1994, effective October 24, 1994. | Cinergy Corp. Form S-8, filed October 19, 1994 | ||
10-ii |
| Cinergy Corp. |
| Amendment to Cinergy Corp. Directors’ Deferred Compensation Plan, adopted October 22, 1996. | Cinergy Corp. September 30, 1996, Form 10-Q | |
10-jj |
| Cinergy Corp. | Cinergy Corp. Retirement Plan for Directors, amended and restated effective January 1, 1999, adopted October 15, 1998. | Cinergy Corp. Schedule 14A Definitive Proxy Statement filed March 12, 1999 | ||
10-kk |
| Cinergy Corp. | Cinergy Corp. Directors’ Equity Compensation Plan adopted October 15, 1998, effective January 1, 1999. | Cinergy Corp. Schedule 14A Definitive Proxy Statement filed March 12, 1999 | ||
10-ll |
| Cinergy Corp. | Cinergy Corp. Executive Supplemental Life Insurance Program adopted October 18, 1994, effective October 24, 1994, consisting of Defined Benefit Deferred Compensation Agreement, Executive Supplemental Life Insurance Program Split Dollar Agreement I, and Executive Supplemental Life Insurance Program Split Dollar Agreement II. | Cinergy Corp. 1994 Form 10-K | ||
10-mm |
| Cinergy Corp. | Cinergy Corp.Executive Life Insurance Plan, effective as of January 1, 2004, adopted December 18, 2003. | Cinergy Corp. 2003 Form 10-K | ||
10-nn |
| Cinergy Corp. |
| Amended and Restated Cinergy Corp. 1996 Long-term Incentive Compensation Plan, effective January 25, 2002. | Cinergy Corp. 2001 Form 10-K | |
10-oo |
| Cinergy Corp. | Cinergy Corp. 401(k) Excess Plan, effective January 1, 1997, adopted December 17, 1996. | Cinergy Corp. 1996 Form 10-K | ||
10-pp |
| Cinergy Corp. |
| Amendment to Cinergy Corp. 401(k) Excess Plan, adopted January 24, 2002, effective January 1, 2002. | Cinergy Corp. Form S-8, filed January 31, 2002 |
203
10-qq |
| Cinergy Corp. |
| Amendment to Cinergy Corp. 401(k) Excess Plan, adopted December 18, 2002, effective January 1, 2003. | Cinergy Corp. 2002 Form 10-K | |
10-rr |
| Cinergy Corp. |
| Amendment to Cinergy Corp. 401(k) Excess Plan, adopted March 31, 2004, effective January 1, 2004. | Cinergy Corp. March 31, 2004 Form 10-Q | |
10-ss | Cinergy Corp. | Cinergy Corp. Nonqualified Deferred Incentive Compensation Plan, effective January 1, 1997, adopted December 17, 1996. | Cinergy Corp. 1996 Form 10-K | |||
|
| Cinergy Corp. |
| Amendment to Cinergy Corp. Nonqualified Deferred Incentive Compensation Plan, adopted December 18, 2002, effective January 1, 2002. | Cinergy Corp. 2002 Form 10-K | |
|
| Cinergy Corp. | Cinergy Corp. Director, Officer and Key Employee Stock Purchase Program, effective January 7, 2000, adopted December 10, 1999. | Cinergy Corp. 1999 Form 10-K | ||
|
| Cinergy Corp. | Cinergy Corp. Non-Union Employees’ Pension Plan adopted December 18, 2002, amended and restated effective January 1, 2003. | Cinergy Corp. 2002 Form 10-K | ||
| Cinergy Corp. | Amendment to Cinergy Corp. Non-Union Employees’ Pension Plan, effective May 1, 2003, adopted October 10, 2003. | Cinergy Corp. 2003 Form 10-K | |||
10-xx | Cinergy Corp. | Amendment to Cinergy Corp. Non-Union Employees’ Pension Plan, effective December 1, 2003, adopted October 10, 2003. | Cinergy Corp. 2003 Form 10-K | |||
10-yy |
| Cinergy Corp. |
| Amendment to Cinergy Corp. Non-Union Employees’ Pension Plan, effective | ||
|
| Cinergy Corp. |
| |||
|
| Cinergy Corp. Non-Union Employees’ Severance Opportunity Plan as amended and restated effective June 1, 2001, adopted May 30, 2001. | Cinergy Corp. June 30, 2001, Form 10-Q | |||
|
| Cinergy Corp. |
| Amendment to the Amended and Restated Separation and Retirement Agreement and Waiver and Release of Liability, between Cinergy Corp. and Larry E. Thomas. | Cinergy Corp. March 31, 2002, Form 10-Q | |
|
| Cinergy Corp. |
| Second Amendment to the Amended and Restated Separation and Retirement Agreement and Waiver and Release of Liability, between Cinergy Corp. and Larry E. Thomas. | Cinergy Corp. June 30, 2002, Form 10-Q | |
|
| Cinergy Corp. |
| Amended and Restated Cinergy Corp. Non-Union Employees’ 401(k) Plan, adopted December 18, 2002, effective January 1, 2003. | Cinergy Corp. 2002 Form 10-K | |
|
| Cinergy Corp. |
| Amendment to Cinergy Corp. Non-Union Employees’ 401(k) Plan, effective December 1, 2003, adopted October 10, 2003. | Cinergy Corp. 2003 Form 10-K | |
|
| Cinergy Corp. |
| Amendment to Cinergy Corp. Non-Union Employees’ 401(k) Plan, effective January 1, 2004, adopted December 16, 2003. | Cinergy Corp. 2003 Form 10-K | |
|
| Cinergy Corp. |
| Amendment to Cinergy Corp. Non-Union Employees’ 401(k) Plan, effective January 1, 2005, adopted December 17, 2004. | ||
10-ggg | Cinergy Corp. | Cinergy Corp. Union Employees’ 401(k) Plan as amended and restated effective January 1, 1998, adopted December 18, 1997. |
| |||
|
|
|
| |||
|
|
|
238
|
|
| Cinergy Corp. 1999 Form 10-K | |||
10-hhh |
| Cinergy Corp. |
| Amendment to Cinergy Corp. Union Employees’ | Cinergy Corp. 1999 Form 10-K | |
10-iii |
| Cinergy Corp. |
| Amendment to Cinergy Corp. Union Employees’ | Cinergy Corp. 2003 Form 10-K | |
10-jjj |
| Cinergy Corp. |
| Amendment to Cinergy Corp. | ||
10-kkk |
| Cinergy Corp. | Cinergy Corp. Union Employees’ Savings Incentive Plan as amended and restated effective January 1, 1998, adopted December 18, 1997. | Cinergy Corp. 1999 Form 10-K | ||
10-lll | Cinergy Corp. | Amendment to Cinergy Corp. Union Employees’ Savings Incentive Plan, effective December 1, 1999, adopted December 10, 1999. | Cinergy Corp. 1999 Form 10-K | |||
10-mmm | Cinergy Corp. | Amendment to Cinergy Corp. Union Employees’ Savings Incentive Plan, effective January 1, 2004, adopted December 16, 2003. | Cinergy Corp. 2003 Form 10-K | |||
10-nnn | Cinergy Corp. | Amendment to Cinergy Corp. Union Employees’ Savings Incentive Plan, effective January 1, 2005, adopted December 17, 2004. | ||||
10-ooo | Cinergy Corp. | Cinergy Corp. Excess Profit Sharing Plan, effective as of January 1, 2003, adopted December 20, 2002. | Cinergy Corp. 2003 Form 10-K | |||
10-ppp | Cinergy Corp. | Cinergy Corp. Excess Pension Plan, as amended and restated, effective as of January 1, 1998. | Cinergy Corp. 2003 Form 10-K | |||
|
| Cinergy Corp. |
| Amendment to Cinergy Corp. Excess Pension Plan, effective as of August 29, 2002. | Cinergy Corp. 2003 Form 10-K | |
|
| Cinergy Corp. |
| Amendment to Cinergy Corp.Excess Pension Plan, effective as of January 1, 2003, adopted October 10, 2003. | Cinergy Corp. 2003 Form 10-K | |
|
| Cinergy Corp. |
| Amendment to Cinergy Corp. Excess Pension Plan, effective as of December 15, 2003. | Cinergy Corp. 2003 Form 10-K |
204
|
| Cinergy Corp. |
| Amendment to Cinergy Corp. Excess Pension Plan, effective as of January 1, 2004, adopted December 16, 2003. | Cinergy Corp. 2003 Form 10-K | |
10-uuu |
| Cinergy Corp. | Amendment to Cinergy Corp. Excess Pension Plan, effective as of January 1, 2005, adopted December 17, 2004. | |||
|
| PSI |
| Asset Purchase Agreement by and among Cinergy Capital & Trading, Inc., CinCap Madison, LLC and PSI dated as of February 5, 2003. | PSI March 31, 2003 Form 10-Q | |
|
| PSI |
| Asset Purchase Agreement by and among Cinergy Capital & Trading, Inc., CinCap VII, LLC and PSI dated as of February 5, 2003. | PSI March 31, 2003 Form 10-Q | |
10-xxx |
| Form of | Cinergy Corp. September 30, 2004 Form 10-Q | |||
10-yyy | Cinergy Corp. | Form of non-qualified stock option grant agreement. | Cinergy Corp. September 30, 2004 Form 10-Q | |||
10-zzz | Cinergy Corp. | Form of restricted stock grant agreement. | Cinergy Corp. September 30, 2004 Form 10-Q | |||
10-aaaa | Cinergy Corp. | Form of performance share grant agreement. | Cinergy Corp. September 30, 2004 Form 10-Q | |||
10-bbbb | Cinergy Corp. | Form of phantom stock grant agreement. | Cinergy Corp. September 30, 2004 Form 10-Q | |||
10-cccc | Cinergy Corp. | Summary Sheet of Compensation Arrangement between Cinergy Corp. and its Non-Employee Directors. | ||||
|
|
|
|
|
| |
10-dddd | Cinergy Corp. | Form of Stock Award Agreement by and between Cinergy Corp. and its Directors | Cinergy Corp. Form 8-K, filed December 14, 2004 | |||
10-eeee | Cinergy Corp. | Form of Deferred Compensation Agreement by and between Cinergy Corp. and its Directors | Cinergy Corp. Form 8-K, filed December 14, 2004 | |||
Subsidiaries of the registrant | ||||||
21 |
| Cinergy Corp. CG&E |
| Subsidiaries of Cinergy Corp., CG&E, and PSI |
|
|
Consent of experts and counsel | ||||||
23 |
| Cinergy Corp. CG&E |
| Independent Auditors’ Consent |
|
|
Power of attorney | ||||||
24 |
| Cinergy Corp. CG&E |
| Power of Attorney |
|
|
Certifications | ||||||
31-a |
| Cinergy Corp. CG&E |
| Certification by James E. Rogers pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
31-b |
| Cinergy Corp. CG&E |
| Certification by | ||
32-a |
| Cinergy Corp. CG&E |
| Certification by James E. Rogers pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of | ||
32-b |
| Cinergy Corp. CG&E |
| Certification by |
|
|
(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 Cinergyand 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 | |
Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not previously listed. |
(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 1-11377CG&E in file number 1-1232PSI in file number 1-3543ULH&P in file number 2-7793
Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above.
239205
CINERGY CORP. AND SUBSIDIARIESSCHEDULE II
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 20032004
(in thousands)
Col. A |
| Col. B |
| Col. C |
| Col. D |
| Col. E |
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| Col. B |
| Col. C |
| Col. D |
| Col. E |
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| Deductions |
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Description |
| Balance at |
| Charged to |
| Charged |
| For Purposes |
| Other |
| Balance at |
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| Balance at Beginning of Period |
| Charged to Expenses |
| Charged to Other Accounts |
| For Purposes for Which Reserves Were Created |
| Other |
| Balance at Close of Period |
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Cinergy Corp. and subsidiaries |
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Accumulated Provisions |
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Deducted from Applicable Assets |
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Allowance for Doubtful Accounts |
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2004 |
| $ | 7,884 |
| $ | 1,317 |
| $ | 153 |
| $ | 3,840 |
| $ | — |
| $ | 5,514 |
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2003 |
| $ | 16,368 |
| $ | 3,256 |
| $ | 302 |
| $ | 12,042 |
| $ | — |
| $ | 7,884 |
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| $ | 16,368 |
| $ | 3,256 |
| $ | 302 |
| $ | 12,042 |
| $ | — |
| $ | 7,884 |
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2002 |
| $ | 34,110 |
| $ | 7,883 |
| $ | 9,270 |
| $ | 34,873 |
| $ | 22 |
| $ | 16,368 |
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| $ | 34,110 |
| $ | 7,883 |
| $ | 9,270 |
| $ | 34,873 |
| $ | 22 |
| $ | 16,368 |
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2001 |
| $ | 29,951 |
| $ | 39,693 |
| $ | 5,254 |
| $ | 40,788 |
| $ | — |
| $ | 34,110 |
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CG&E and subsidiaries |
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Accumulated Provisions |
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Deducted from Applicable Assets |
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Allowance for Doubtful Accounts |
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2004 |
| $ | 1,602 |
| $ | 570 |
| $ | 114 |
| $ | 1,564 |
| $ | — |
| $ | 722 |
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2003 |
| $ | 5,942 |
| $ | 2,900 |
| $ | 256 |
| $ | 7,496 |
| $ | — |
| $ | 1,602 |
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2002 |
| $ | 25,874 |
| $ | 2,029 |
| $ | 6,096 |
| $ | 28,057 |
| $ | — |
| $ | 5,942 |
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Accumulated Provisions |
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Deducted from Applicable Assets |
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Allowance for Doubtful Accounts |
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2004 |
| $ | 1,110 |
| $ | 21 |
| $ | — |
| $ | 960 |
| $ | — |
| $ | 171 |
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2003 |
| $ | 5,656 |
| $ | — |
| $ | — |
| $ | 4,546 |
| $ | — |
| $ | 1,110 |
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2002 |
| $ | 6,773 |
| $ | 2,310 |
| $ | 3,174 |
| $ | 6,579 |
| $ | 22 |
| $ | 5,656 |
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ULH&P |
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Accumulated Provisions |
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Deducted from Applicable Assets |
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Allowance for Doubtful Accounts |
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2004 |
| $ | 192 |
| $ | — |
| $ | — |
| $ | 179 |
| $ | — |
| $ | 13 |
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2003 |
| $ | 84 |
| $ | — |
| $ | 108 |
| $ | — |
| $ | — |
| $ | 192 |
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2002 |
| $ | 1,196 |
| $ | 392 |
| $ | 2,383 |
| $ | 3,887 |
| $ | — |
| $ | 84 |
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240206
THE CINCINNATI GAS & ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTSFOR THE THREE YEARS ENDED DECEMBER 31, 2003
(in thousands)
Col. A |
| Col. B |
| Col. C |
| Col. D |
| Col. E |
| ||||||||||
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|
|
| Additions |
| Deductions |
|
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Description |
| Balance at |
| Charged to |
| Charged |
| For Purposes |
| Other |
| Balance at |
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Accumulated Provisions |
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Deducted from Applicable Assets |
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Allowance for Doubtful Accounts |
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2003 |
| $ | 5,942 |
| $ | 2,900 |
| $ | 256 |
| $ | 7,496 |
| $ | — |
| $ | 1,602 |
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2002 |
| $ | 25,874 |
| $ | 2,029 |
| $ | 6,096 |
| $ | 28,057 |
| $ | — |
| $ | 5,942 |
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2001 |
| $ | 19,044 |
| $ | 30,166 |
| $ | 4,089 |
| $ | 27,425 |
| $ | — |
| $ | 25,874 |
|
241
PSI ENERGY, INC. AND SUBSIDIARY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTSFOR THE THREE YEARS ENDED DECEMBER 31, 2003
(in thousands)
Col. A |
| Col. B |
| Col. C |
| Col. D |
| Col. E |
| ||||||||||
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| Additions |
| Deductions |
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Description |
| Balance at |
| Charged to |
| Charged |
| For Purposes |
| Other |
| Balance at |
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Accumulated Provisions |
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Deducted from Applicable Assets |
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Allowance for Doubtful Accounts |
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2003 |
| $ | 5,656 |
| $ | — |
| $ | — |
| $ | 4,546 |
| $ | — |
| $ | 1,110 |
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| ||||||
2002 |
| $ | 6,773 |
| $ | 2,310 |
| $ | 3,174 |
| $ | 6,579 |
| $ | 22 |
| $ | 5,656 |
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2001 |
| $ | 9,317 |
| $ | 8,339 |
| $ | 1,165 |
| $ | 12,048 |
| $ | — |
| $ | 6,773 |
|
242
THE UNION LIGHT, HEAT AND POWER COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTSFOR THE THREE YEARS ENDED DECEMBER 31, 2003
(in thousands)
Col. A |
| Col. B |
| Col. C |
| Col. D |
| Col. E |
| ||||||||||
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| Additions |
| Deductions |
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Description |
| Balance at |
| Charged to |
| Charged |
| For Purposes |
| Other |
| Balance at |
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Accumulated Provisions |
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Deducted from Applicable Assets |
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Allowance for Doubtful Accounts |
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2003 |
| $ | 84 |
| $ | — |
| $ | 108 |
| $ | — |
| $ | — |
| $ | 192 |
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2002 |
| $ | 1,196 |
| $ | 392 |
| $ | 2,383 |
| $ | 3,887 |
| $ | — |
| $ | 84 |
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2001 |
| $ | 1,492 |
| $ | 3,050 |
| $ | 4 |
| $ | 3,350 |
| $ | — |
| $ | 1,196 |
|
243
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.
THE CINCINNATI GAS & ELECTRIC COMPANY
PSI ENERGY,ENERGY, INC.
THE UNION LIGHT, HEAT AND POWER COMPANY
Registrants
Date: |
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| By | /s/ James E. Rogers |
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| James E. Rogers |
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| Chief Executive Officer |
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244207
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:
245
Signature | Title | Date | ||||||||||||||||
Cinergy Corp. | ||||||||||||||||||
| Michael G. Browning* |
| Director |
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| Phillip R. Cox* |
| Director |
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| George C. Juilfs* |
| Director |
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| Thomas E. Petry* |
| Director |
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| /s/ James E. Rogers |
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| James E. Rogers |
| Director and Chief Executive Officer |
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| Mary L. Schapiro* |
| Director |
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| John J. Schiff, Jr.* |
| Director |
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| Philip R. Sharp* |
| Director |
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| Dudley S. Taft* |
| Director |
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| /s/ |
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| Chief Financial Officer (principal |
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| /s/ Lynn J. Good |
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| Lynn J. Good |
| Vice President and Controller (principal accounting officer) |
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CG&E | ||||||||||||||||||
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| Director |
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| /s/ James E. Rogers |
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| James E. Rogers |
| Director and Chief Executive Officer |
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/s/ James L. Turner |
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| James L. |
| Director and Chief Financial Officer (principal financial officer) |
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| /s/ Lynn J. Good |
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| Lynn J. Good |
| Vice President and Controller (principal accounting officer) |
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PSI | ||||||||||||||||||
| Michael G. Browning* |
| Director |
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| Director |
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| |||||||||||||
| /s/ James E. Rogers |
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| ||||||||||||
| James E. Rogers |
| Director and Chief Executive Officer |
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| /s/ |
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| Chief Financial Officer (principal |
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| /s/ Lynn J. Good |
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| ||||||||||||
| Lynn J. Good |
| Vice President and Controller (principal accounting officer) |
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ULH&P | ||||||||||||||||||
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| Director |
| February 25, 2005 | ||||||||||||
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| /s/ James E. Rogers |
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| James E. Rogers |
| Director and Chief Executive Officer |
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/s/ James L. Turner |
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| James L. |
| Director and Chief Financial Officer (principal financial officer) |
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| /s/ Lynn J. Good |
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| Lynn J. Good |
| Vice President and Controller (principal accounting officer) |
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* The undersigned, by signing his name hereto, does hereby execute this Form 10-K on behalf of the officers and directors of the registrant previously indicated above 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.
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/s/ James E. Rogers | ||||
James E. Rogers | ||||
Attorney-In-Fact | ||||
February 25, 2005 | ||||
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/s/ James | L. Turner | |||
James L. Turner | ||||
Attorney-In-Fact | ||||
February 25, 2005 |
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