ITEM 1. BUSINESS
GENERAL DEVELOPMENTS
In 1996, the Securities and Exchange Commission (SEC) wrote guidelines to help make shareholder communications more understandable. These guidelines were termed "plain English". This year, we have written our annual report in accordance with these guidelines. Our objective is to present a more user-friendly, understandable, and logically-flowing document for our readers.
In connection with this change, we (which includes Cinergy Corp. and all of our regulated and non-regulated subsidiaries, also Cinergy) are, at times, referred to in the first person ("we", "our", or "us").
ORGANIZATION
Cinergy Corp., a Delaware corporation created in October 1994, owns all outstanding common stock of The Cincinnati Gas & Electric Company (CG&E) and PSI Energy, Inc. (PSI), both of which are public utility subsidiaries. As a result of this ownership, we are considered a utility holding company. Because we are a holding company whose utility subsidiaries operate 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 (PUHCA). Our other direct subsidiaries are:
•Cinergy Services, Inc. (Services);
•Cinergy Investments, Inc. (Investments); and
•Cinergy Global Resources, Inc. (Global Resources).
CG&E, an Ohio corporation, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through its subsidiaries, in nearby areas of Kentucky and Indiana. It has five wholly-owned utility subsidiaries and one wholly-owned non-utility subsidiary. CG&E's principal utility subsidiary, The Union Light, Heat and Power Company (ULH&P), is a Kentucky corporation that provides electric and gas service in northern Kentucky. CG&E's other subsidiaries are insignificant to its results of operations.
PSI, an Indiana corporation, is an electric utility that provides service in north central, central, and southern Indiana.
The following table presents further information related to the operations of our domestic utility subsidiaries (our operating companies):
Principal
Line(s) of Business
Major Cities Served
Approximate
Population
Served
CG&E and subsidiaries
•
Generation, transmission, distribution, and sale of electricity
Cincinnati, OH
Middletown, OH
Covington, KY
2,005,000
•
Sale and/or transportation of natural gas
Florence, KY
Newport, KY
Lawrenceburg, IN
PSI
•
Generation, transmission, distribution, and sale of electricity
Bloomington, IN
Columbus, IN
Kokomo, IN
Lafayette, IN
New Albany, IN
Terre Haute, IN
2,182,000
ULH&P
•
Transmission, distribution, and sale of electricity
Covington, KY
Florence, KY
328,000
•
Sale and transportation of natural gas
Newport, KY
Services is a service company that provides our regulated and non-regulated subsidiaries with a variety of centralized administrative, management, and support services. Investments holds most of our domestic non-regulated businesses and investments. Global Resources primarily holds our international businesses and investments.
We had 8,950 employees at December 31, 1999, of whom 947 were employed by our international subsidiaries. We have collective bargaining agreements with the International Brotherhood of Electrical Workers (IBEW), the United Steelworkers of America (USWA), the Independent Utilities Union (IUU), and various international union organizations. The following table indicates the number of employees by classification:
(1)Contract will expire April 1, 2006.
(2)Contract will expire May 15, 2002.
(3)Contract will expire April 1, 2001.
(4)Contract will expire April 30, 2002.
(5)Of this number, 547 belonged to bargaining units.
BUSINESS UNITS
We conduct operations through our subsidiaries, and we manage through the following four business units:
•Energy Commodities Business Unit (Commodities);
•Energy Delivery Business Unit (Delivery);
•Cinergy Investments Business Unit (Cinergy Investments); and
•International Business Unit (International).
The following section describes the activities of our business units. (See Note 15 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 137 for financial information by business unit.)
Commodities
Commodities operates and maintains our domestic electric generating plants and some of our jointly-owned plants. As of December 31, 1999, the total winter electric capability (including our portion of the total capacity for the jointly-owned plants) of these generating plants was 11,221 megawatts (MW, the basic unit of electric energy equal to 1 million watts) of electricity. These plants are mostly coal fired. (See "Item 2.
ITEM 2. PROPERTIES
COMMODITIES
Our operating companies' total winter electric capabilities reflected in MW (MW is the basic unit of electric energy equal to 1 million watts), as of December 31, 1999, are shown in the table that follows. Our electric generating plants are located in Ohio, Kentucky, and Indiana and are wholly- or jointly-owned facilities.
(1)This table includes only our portion of the total capacity for the jointly-owned plants. Refer to Note 13 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 135 for a discussion of jointly-owned plants.
During July 1999, we incurred peak loads of 5,041 MW for CG&E and 5,637 MW for PSI. We are forecasting our peak load and kilowatt hour (kWh, kilowatt hour is the basic unit of electric energy equal to 1,000 watts supplied for one hour continuously) sales to each have an annual growth of 2% for CG&E, and 1% for PSI for the period 2000 through 2004. This forecast includes the following assumptions:
•increase in demand at a specific point and time;
•alternative energy choices;
•population growth; and
•new residential and commercial construction.
This forecast excludes non-firm power transactions (a non-guaranteed commitment to deliver power) and any potential off-system (purchases in the open market), long-term firm power sales.
On September 30, 1999, one of our non-regulated subsidiaries formed a partnership with Duke Energy North America LLC. This partnership will jointly construct and own three wholesale generating facilities to be located in southwestern Ohio, and east central and western Indiana, with total capacity of approximately 1,400 MW. These facilities will be natural gas-fired peaking stations with commercial operations anticipated for the summer of 2000. Our portion (50%) of the output will be sold to and marketed by Cinergy Capital & Trading (a wholly-owned subsidiary of Investments) or another Cinergy affiliate.
During 1999, our electric generating plants operated reliably, as evidenced by our annual capacity factor of 69% (excluding natural gas peaking stations), and at satisfactory levels of utilization. A capacity factor is a percentage that tells how much of a power plant's capacity is used over time.
Comprehensive electric deregulation legislation was passed in Ohio on July 6, 1999, as further discussed in the "Retail Market Developments" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" on page 54. If CG&E's Proposed Transition Plan is approved it will materially affect the nature of CG&E's operations.
DELIVERY
Electric
The electric transmission and distribution systems (excluding our proportionate share of jointly-owned facilities) for our operating companies, as of December 31, 1999, are indicated in the following table:
(1)Kilovolt-amperes (1,000 volt-amperes) are a broad measure of our substation transformer capacity.
Our operating companies' electric systems are interconnected with thirteen other utilities. Refer to the map on page 8 illustrating these interconnected utility companies.
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 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.
During 1998, the FERC approved the formation of the Midwest Independent Transmission System Operator, Inc. (Midwest ISO), which is further discussed in the "Midwest ISO" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" on page 60. The Midwest ISO will oversee the combined transmission systems of its 14 current members. This joint effort will help to facilitate a reliable and efficient market for electric power and facilitate open transmission access consistent with FERC policies.
Gas
As of December 31, 1999, the natural gas transmission and distribution systems of CG&E and its subsidiaries had 7,543 miles of mains and service lines located in southwestern Ohio, southeastern Indiana, and northern Kentucky. CG&E and its subsidiaries also own three underground caverns with a total storage capacity of 23 million gallons of liquid propane. As of December 31, 1999, we had 20 million gallons of liquid propane in storage. This liquid propane is used in the three propane/air
peak shaving plants located in Ohio and Kentucky. These plants convert liquid propane into natural gas to be used only during peak demand periods and emergencies. During 1999, CG&E and its subsidiaries' natural gas transmission and distribution systems operated reliably, at a load factor of 30%, and at satisfactory levels of utilization. Load factor is used to indicate the percentage of capacity of an energy facility, such as gas distribution, that is utilized at a given period of time.
CINERGY INVESTMENTS
As of December 31, 1999, we have ownership interest and/or operating control in cogeneration (simultaneous production of two or more forms of useable energy from a single fuel source) plants producing 312 MW of electricity through our various Trigen-Cinergy Solutions LLC (Trigen-Cinergy) joint ventures. Trigen-Cinergy builds, owns, operates, and maintains combined heat and power facilities for large industrial customers. During 2000, Trigen-Cinergy anticipates starting construction of three new cogeneration plants which will produce an additional 45 MW of electricity.
INTERNATIONAL
As of December 31, 1999, our international subsidiaries and jointly-owned investments had ownership interests in generating plants producing 164 MW of electricity. In addition, we own four district heating plants and have a minority interest in a fifth district heating plant in the Czech Republic that, in total, provide 1,480 MW of thermal steam capacity, which may be used to produce 186 MW of electricity. We also own interests in 1,243 miles of transmission and distribution systems through jointly-owned investments. We serve 40,000 transmission and distribution customers, 518 retail district heating and district electric customers, and 106 wholesale heating and electric customers.
On July 15, 1999, we sold our 50% ownership interest in Avon Energy to GPU. See Note 10 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 126 for further information.
GENERAL INFORMATION
The utility property of both CG&E and PSI are subject to the lien of each applicable company's first mortgage bond indenture.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
NEW SOURCE REVIEW AND NOTICES OF VIOLATION
See Notes 12(c) and (e) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" beginning on page 132 for a discussion of the lawsuit and notices of violation filed by the U.S. Environmental Protection Agency against Cinergy, CG&E, and PSI.
MANUFACTURED GAS PLANT CLAIMS
See Note 12(d) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 133 for a further discussion of manufactured gas plant sites as they relate to our operating companies.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders for Cinergy, CG&E, or PSI during the fourth quarter of 1999.
EXECUTIVE OFFICERS
The names of the executive officers of each registrant, their ages (as of December 31, 1999), the positions they hold, held, or have been elected to as of this report filing date, and their business experience during the past five years appear below.
None of the officers are related in any manner. Our executive officers hold the offices set opposite their names until the next annual meeting of the Board of Directors and until their successors have been elected and qualified.
(1)Prior to joining Cinergy, Ms. Bailey served as Commissioner of the FERC, a position she had held since 1993.
(2)Mr. Bryant has also served in the following roles:
•Generation Director of Midlands (1992 - 1996);
•Executive Generation Director of Midlands (1996 - 1997); and
•Managing Director of Cinergy Global Power Services Limited, Cinergy's international project development subsidiary (1997 - present).
(3)Prior to joining Cinergy, Mr. Cyrus was Senior Vice President of Trading and Operations with Electric Clearinghouse, Inc. (ECI; a non-affiliate of Cinergy), the power subsidiary of Natural Gas Clearinghouse (NGC; a non-affiliate of Cinergy) in Houston, Texas, a position he had held since 1997. Mr. Cyrus joined NGC in 1993, holding various executive positions involving energy trading, marketing, and risk management. Prior to serving as Senior Vice President of ECI, Mr. Cyrus was President of NGC Canada and Executive Vice President of Novagas Clearinghouse Ltd., where he had oversight responsibilities for NGC's Canadian commercial operations.
(4)Mr. Grealis served as President of Investments from 1995 to March 1999. Mr. Grealis has also served in the following roles:
•Interim President, PSI Investments, Inc. (1992 - 1994);
•President, Gas Business Unit of CG&E (1995); and
•President, Cinergy's Energy Services Business Unit (1996 - 5/97).
Prior to joining Cinergy, Mr. Grealis was a partner in the Washington, D.C. law firm of Akin, Gump, Strauss, Hauer & Feld L.L.P.
(5)Since 1992, Mr. Hale has served as President of Cinergy Foundation, Inc., a Cinergy affiliate that is organized and operated exclusively for charitable purposes.
(6)Since 1996, Mr. Harkness has served as Executive Vice President and Chief Operating Officer of Trigen-Cinergy, a joint venture company formed by Cinergy and Trigen Energy Corporation.
(7)Mr. Ingle has served as President of Investments since March 1999. From 1995 to March 1999, he served as Contract Consultant for Investments. Mr. Ingle also served as President of Cinergy's Energy Services Business Unit (1997 - 3/99). Prior to joining Cinergy, Mr. Ingle was President and Chief Executive Officer for Cornerstone Industries, Inc., a non-affiliate of Cinergy.
(8)Prior to joining Cinergy, Ms. Ludlow had the following business experience:
•Vice President and Treasurer of Enterprise Diversified Holdings Incorporated, a subsidiary of Public Service Enterprise Group Incorporated (PSEG, a non-affiliate of Cinergy) (1992 - 1996); and
•Vice President of PSEG (1996 - 1997).
(9)Effective January 1, 2000, Mr. Sheafer retired and Andrew M. Turk succeeded him as Vice President and Treasurer for Cinergy, CG&E and PSI.
(10)Effective January 10, 2000, Cinergy's Economic Development, Community Affairs, State Regulatory Affairs and State Governmental Affairs were merged into the Energy Delivery Business Unit, of which Mr. Thomas is President (since its formation in 1996). These areas were combined with the former energy services functions to form a new unit called Customer Services, of which Mr. James L. Turner is Vice President, reporting to Mr. Thomas (refer to note 12 below).
(11)Mr. Turk has served since 1997 as Vice President of International Development for Cinergy Global Power, Inc. Also, Mr. Turk served as finance director of Midlands Power International, the non-regulated subsidiary of Midlands from 1993 to 1997.
(12)In addition to serving as President of CG&E and as Vice President of Services, effective January 10, 2000, Mr. Turner was named Vice President of Customer Services, reporting to Mr. Thomas in this capacity. Customer Service is part of the Energy Delivery Business Unit, and includes Cinergy's Economic Development, Community Affairs, State Regulatory Affairs, and State Governmental Affairs groups, along with Cinergy's energy services functions. Previously, Mr. Turner had full responsibility for Cinergy's Government and Regulatory Affairs Department (from April 1998 until January 2000). Prior to that, in March 1997, Mr. Turner was appointed Vice President of Services, having responsibility for the coordination of transition issues across all corporate subsidiaries in the move for full customer choice. Before joining Cinergy's legal department in June 1995, Mr. Turner was a principal in the Indianapolis law firm of Lewis & Kappes, P.C. (non-affiliate of Cinergy), representing industrial customers in utility regulatory and legislative matters.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our 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:
On February 29, 2000, the closing price of our common stock was $21.375.
We hold all of CG&E and PSI common stock, and CG&E holds all ULH &P common stock. Therefore, no public trading market exists for CG&E, PSI and ULH &P.
As of February 29, 2000, we had 64,826 common stockholders of record.
We declared dividends on common stock of $.45 per share for each quarter of 1998 and 1999. The dividends paid by our operating companies for the past two years were as follows:
(1)During the second quarter of 1998, PSI paid a non-cash dividend on common stock of approximately $12 million.
See Note 2(b) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 109 for a brief description of the registrants' common stock dividend restrictions.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(1)See "Item 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
In MD&A, we explain our general operating environment, as well as our liquidity, capital resources, and results of operations. Specifically, we discuss the following:
•factors affecting current and future operations;
•why revenues and expenses changed from period to period;
•how the above items affect our overall financial condition;
•what our expenditures for construction and other commitments were during 1999, and what we expect them to be in 2000-2004; and
•potential sources of cash for future capital expenditures.
ORGANIZATION
Cinergy Corp., a Delaware corporation created in October 1994, owns all outstanding common stock of CG&E and PSI Energy, Inc. (PSI), both of which are public utility subsidiaries. As a result of this ownership, we are considered a utility holding company. Because we are a holding company whose utility subsidiaries operate 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 (PUHCA). Our other direct subsidiaries are:
•Cinergy Services, Inc. (Services);
•Cinergy Investments, Inc. (Investments); and
•Cinergy Global Resources, Inc. (Global Resources).
CG&E, an Ohio corporation, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through its subsidiaries, in nearby areas of Kentucky and Indiana. It has five wholly-owned utility subsidiaries and one wholly-owned non-utility subsidiary. CG&E's principal utility subsidiary, The Union Light, Heat and Power Company (ULH&P), is a Kentucky corporation that provides electric and gas service in northern Kentucky. CG&E's other subsidiaries are insignificant to its results of operations.
PSI, an Indiana corporation, is an electric utility that provides service in north central, central, and southern Indiana.
The following table presents further information related to the operations of our domestic utility companies (our operating companies):
Principal
Line(s) of Business
CG&E
•Generation, transmission, distribution, and sale of electricity
•Sale and/or transportation of natural gas
PSI
•Generation, transmission, distribution, and sale of electricity
ULH&P
•Transmission, distribution, and sale of electricity
•Sale and transportation of natural gas
Services is a service company that provides our regulated and non-regulated subsidiaries with a variety of centralized administrative, management, and support services. Investments holds most of our domestic non-regulated businesses and investments. Global Resources primarily holds our international businesses and investments.
The majority of our operating revenues are derived from the sale of electricity and the sale and/or transportation of natural gas.
We conduct operations through our subsidiaries, and we manage through the following four business units:
•Energy Commodities Business Unit (Commodities);
•Energy Delivery Business Unit (Delivery);
•Cinergy Investments Business Unit (Cinergy Investments); and
•International Business Unit (International).
See Note 15 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 137 for financial information by business unit.
LIQUIDITY
In the "Liquidity" section, we discuss 1999 cash flows, environmental issues, construction and other commitments, other investing activities, and Year 2000 as they relate to our current and future cash needs. In the "Capital Resources" section beginning on page 38, we discuss how we intend to meet these capital requirements.
1999 Cash Flows
Our Cash and cash equivalents decreased $18 million during 1999. The significant uses of cash during 1999 were:
•the net redemption of $77 million in short-term and long-term debt;
•the payment of $286 million in common stock dividends;
•construction expenditures of $386 million; and
•investments in consolidated and unconsolidated subsidiaries of $309 million. (This amount includes the September 30, 1999, transaction where we formed a partnership with Duke Energy North America LLC (Duke), as discussed in the "Construction and Other Commitments" section on page 34.)
Offsetting these decreases were the following sources of cash:
•proceeds of $690 million from the sale of our 50% ownership interest in Avon Energy Partners Holdings (Avon Energy), the parent company of Midlands Electricity plc (Midlands), to GPU, Inc. (GPU), as discussed in Note 10 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 126; and
•cash from ongoing operating activities.
For further detail regarding the classification of these items, see our Consolidated Statements of Cash Flows in "Item 8. Financial Statements and Supplementary Data" on page 77.
Environmental Issues
In the "Environmental Issues" section, we discuss the Acid Rain Program, ozone transport rulemakings, ambient air standards and regional haze, global climate change, air toxics, new source review, and manufactured gas plants as they relate to us and our operating companies.
Acid Rain Program The Acid Rain Program of the 1990 amendments to the Clean Air Act (CAA) required reductions in both sulfur dioxide (SO2) and nitrogen oxide (NOX) emissions from utility sources. The revisions established two phases for reductions of these emissions. The revisions required compliance under Phase I by January 1, 1995, and required compliance under Phase II by January 1, 2000. The U.S. Environmental Protection Agency (EPA) allocated emission allowances to the utility sources (for example, our electric generating units operated by Commodities) to achieve the SO2 reduction objectives of the Acid Rain Program. Each allowance permits one ton of SO2 emissions. The Acid Rain Program allows compliance with the SO2 reduction objectives to be achieved on a national level; therefore, companies may comply with the requirements by (1) reducing emissions, or (2) purchasing emission allowances from other sources.
We complied with Phase I prior to January 1, 1995. We implemented Phase II compliance by (1) using lower-sulfur coal blends in our generating units, and (2) using an emission allowance banking strategy. This cost-effective strategy allows us to implement Phase II SO2 reduction requirements while maintaining optimal flexibility to meet (1) changes in output due to increased customer choice, and (2) potentially significant future environmental requirements.
To meet Phase II NOX reduction requirements, we (1) have changed the burners on our generating units, and (2) are using a system-wide NOX emission averaging strategy (where the overall emission average of all of our generating units must be below a certain level).
Ozone Transport Rulemakings In June 1997, the Ozone Transport Assessment Group, which consists of 37 states, made a wide range of recommendations to the 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-causing materials across city and state boundaries. In late 1997, the EPA published a proposed call for revisions to State Implementation Plans (SIPs). (A SIP is a state's implementation plan for achieving emissions reductions to address air quality concerns.)
NOX SIP Call In October 1998, the EPA finalized its ozone transport rule, also known as the NOX SIP Call. It applies to 22 states in the eastern half of the U.S., including the three states in which our electric utilities operate, and also proposes a model NOX emission allowance trading program. If implemented by the states, the trading program would allow us to buy NOX emission allowances from, or sell NOX emission allowances to, other companies as necessary. This rule recommends that states reduce NOX emissions from primarily industrial and utility sources to a certain level by May 2003. The EPA gave the affected states until September 30, 1999, to incorporate NOX reductions and, in the discretion of the state, a trading program into their SIPs. The EPA proposed to implement a federal plan to accomplish the equivalent NOX reductions by May 2003 if states failed to revise their SIPs. The EPA must approve all SIPs.
Ohio, Indiana, a number of other states, and various industry groups (some of which we are a member), filed legal challenges to the NOX SIP Call in late 1998. On May 25, 1999, the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals) granted a request for a deferral of the rule and indefinitely suspended the September 30 filing deadline, pending further review by the Court of Appeals. The Court of Appeals heard arguments on the case on November 9, 1999, and is expected to make a decision in the first quarter of 2000.
Section 126 Petitions In February 1998, the northeast states filed petitions seeking the EPA's assistance in reducing ozone in the eastern U.S. under Section 126 of the CAA. The EPA believes that Section 126 petitions allow a state to claim that another state is contributing to its air quality problem and request that the EPA require the upwind state to reduce its emissions. On April 30, 1999, the EPA found that the Midwest facilities (including most of our generating facilities) named in the petitions are significantly contributing to ozone problems in the northeast for both the one- and eight-hour ozone level health standards. Industry has challenged the EPA's findings and related rulemaking.
Based on a court decision regarding ambient (outside) air standards (discussed below) and the May 25 court decision (previously discussed), in June 1999, the EPA modified and re-proposed the Section 126 petitions rulemaking to address only the one-hour ozone standard. The EPA also limited the petitions to 12 states instead of the original 22 states. Indiana, Kentucky, and Ohio would still have to meet the same NOX emissions requirements through a 12-state trading program.
In December 1999, the EPA granted four Section 126 petitions relating to NOX emissions. This ruling affects all of our Ohio and Kentucky facilities, as well as some of our Indiana facilities, and requires us to reduce our NOX emissions to a certain level by May 2003. We are appealing this ruling; however, we currently cannot predict the outcome of the appeal. Compliance with this EPA finding is anticipated to require us to perform substantially all of the NOX reduction work that would be required under the NOX SIP Call. In the event the EPA successfully implements either program (the NOX SIP Call or the Section 126 petitions), capital expenditures for compliance are substantially the same, and are currently estimated at $500 million to $700 million (in 1999 dollars) by May 2003. This estimate depends on several factors, including:
•final determination regarding both the timing and strictness of the final required NOX reductions;
•emission output of our generating units;
•availability of adequate supplies of resources to construct the necessary control equipment; and
•whether a viable market will exist to buy and sell NOX allowances.
State Ozone Plans On November 15, 1999, the State of Indiana and the Commonwealth of Kentucky (along with Jefferson County, Kentucky) jointly filed an amendment to their SIPs on how they intend to bring the greater Louisville area, including Floyd and Clark Counties in Indiana, into attainment with the one-hour ozone standard. The area did not reach attainment by the required date
of November 15, 1997, reportedly due in part to transported ozone from outside the area. Recognizing the failure of the area to reach attainment and the need for regional NOX reductions, on May 21, 1999, the EPA published a proposed rule to extend the attainment date to 2003, if the states enact adequate regional NOX reductions.
The SIP amendments call for, among other things, statewide NOX reductions from utilities in Indiana, Kentucky, and surrounding states which are less stringent than the EPA's NOX SIP Call. The states of Indiana and Kentucky have committed to adopt utility NOX control rules by December 2000 that would require controls be installed by May 2003. Currently, the states have not yet decided whether their rules would include a NOX trading program or some other compliance mechanism. Because the rulemakings are in the early stages, the financial impact cannot currently be estimated.
Ambient Air Standards and Regional Haze During 1997, the EPA revised the National Ambient Air Quality Standards for ozone and fine particulate matter and proposed rules for regional haze. Fine particulate matter refers to very small solid or liquid particles in the air. Regional haze involves fine particulate matter that impairs visibility in national parks. It was anticipated that utility NOX reductions called for in the EPA's final NOX SIP Call would address both the one-hour ozone standard and the new eight-hour ozone standard. With the recent challenges to the NOX SIP Call and the eight-hour ozone standard (discussed below), it is unclear to what extent additional NOX reductions will be required of utilities to address eight-hour ozone non-attainment issues.
The EPA estimates it will take up to five years to collect sufficient ambient air monitoring data to determine fine particulate matter non-attainment areas. The states will then determine the sources of the particulates and determine a regional emission reduction plan. We currently cannot predict the exact amount and timing of required reductions.
On May 14, 1999, the Court of Appeals ruled that both the new eight-hour ozone standard and the fine particulate matter standard were found questionable and were determined to be unenforceable by the EPA. In June 1999, the EPA appealed the decision. On October 29, 1999, the full Court of Appeals rejected the EPA's request for reconsideration. In January 2000, the EPA appealed to the U.S. Supreme Court. We currently cannot determine the outcome of the appeals process and the effects on future emissions reduction requirements.
The EPA published the final regional haze rule on July 1, 1999. This rule establishes planning and emission reduction timelines for states to use to improve visibility in national parks throughout the U.S. The ultimate effect of the new regional haze rule could be requirements for (1) newer and cleaner technologies and additional controls on conventional particulates, and (2) reductions in SO2 and NOX emissions from utility sources. If more utility emissions reductions are required, the compliance cost could be significant. In August 1999, several industry groups (some of which we are a member) filed a petition for reconsideration of the regional haze rules with the courts. We currently cannot determine the outcome or effects of the courts' or states' determination.
Global Climate Change In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming. The Kyoto Protocol establishes legally binding greenhouse gas emission (man-made pollutants thought to be artificially warming the earth's atmosphere) targets for developed nations. On November 12, 1998, the U.S. signed the Kyoto Protocol; however, it will not be effective in the U.S. until it is approved by a two-thirds vote of the U.S. Senate, which is currently deemed unlikely.
Because of a lack of support for the Kyoto Protocol or similar legislation, significant uncertainty exists about how and when greenhouse gas emissions reductions will be required. Our plan for managing the potential risk and uncertainty of regulations relating to climate change includes the following:
•implementing cost-effective greenhouse gas 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.
We believe that voluntary programs, such as the U.S. Department of Energy Climate Challenge Program that we joined in 1995, are the most cost-effective way to limit greenhouse gas emissions.
Air Toxics The air toxics provisions of the CAA Amendments delayed possible air toxics regulation of fossil-fueled steam utility plants until the EPA completed a study. The final report, issued in February 1998, confirmed that utility air toxic emissions pose little risk to public health. It stated that mercury is the pollutant of the greatest concern and requires further study. A Mercury Study Report, issued in December 1997, stated that mercury is not a risk to the average American and expressed uncertainty about whether reductions in current domestic sources would reduce human mercury exposure. U.S. utilities are a large domestic source, but they are insignificant when compared to global mercury emissions. The EPA was unable to show a feasible mercury control technology for coal-fired utilities.
In November 1998, the EPA finalized its mercury Information Collection Request (ICR). The ICR required all generating units to provide detailed information about coal use and mercury content during 1999. The EPA also selected about 100 generating units for one-time stack sampling. We completed testing at Gibson Generating Station Unit No. 3 and the Wabash River Repowering Project in October 1999. The EPA is planning to make its regulatory determination on the need for additional regulation by the fourth quarter of 2000. If more air toxics regulations are issued, the compliance cost could be significant. We currently cannot predict the outcome or effects of the EPA's determination.
New Source Review The CAA's New Source Review (NSR) provisions require that a company obtain a pre-construction permit if it plans to build a new stationary source of pollution or make a major change to an existing facility unless the changes are exempt. In July 1998, the EPA requested comments on proposed revisions to the NSR rules that would change NSR applicability by eliminating exemptions contained in the current regulation. We believe that if these changes are finalized, it will be significantly harder to maintain our facilities without triggering the NSR permit requirements.
Since July 1999, CG&E and PSI have received requests from the EPA (Region 5), under Section 114 of the CAA, seeking documents and information regarding capital and maintenance expenditures at several of their respective generating stations. These activities are part of an industry-wide investigation assessing compliance with the NSR and the New Source Performance Standards (NSPS, emissions standards that apply to new and changed units) of the CAA at electric generating stations.
On September 15, 1999, and on November 3, 1999, the Attorneys General of the States of New York and Connecticut, respectively, issued letters notifying Cinergy and CG &E of their intent to sue under the citizens suit provisions of the CAA. New York and Connecticut allege violations of the CAA by constructing and continuing to operate a major change to CG&E's W.C. Beckjord Station (Beckjord) without obtaining the required NSR pre-construction permits.
On November 3, 1999, the EPA sued a number of holding companies and electric utilities, including Cinergy, CG&E, and PSI, in various U.S. District Courts. The Cinergy, CG&E, and PSI suit alleges violations of the CAA at some of our generating stations relating to NSR and NSPS requirements. The suit seeks (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord and PSI's Cayuga Generating Station (Cayuga), and (2) civil penalties in amounts of up to $27,500 per day for each violation.
On March 1, 2000, the EPA filed an amended complaint against Cinergy, CG&E, and PSI. The amended complaint added the alleged violations of the NSR requirements of the CAA at two of our generating stations contained in the notice of violation (NOV) filed by the EPA on November 3, 1999.
It also added claims for relief alleging violations of (1) nonattainment NSR, (2) Indiana and Ohio SIPs, and (3) particulate matter emission limits (as discussed in the 'Other' section on page 33). The amended complaint seeks (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord, Cayuga, and PSI's Wabash River and Gallagher Generating Stations, and such other measures as necessary, and (2) civil penalties in amounts of up to $27,500 per day for each violation. We believe the allegations contained in the amended complaint are without merit and plan to defend the suit vigorously in court. At this time, it is not possible to determine the likelihood that the EPA will prevail on its claims or whether resolution of this matter will have a material effect on our financial condition.
On March 1, 2000, the EPA also filed an amended complaint alleging violations of the CAA relating to NSR, Prevention of Significant Deterioration, and Ohio SIP requirements regarding a generating station operated by the Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company, and CG&E. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. We believe the allegations in the amended complaint are without merit. At this time, it is not possible to determine the likelihood that the EPA will prevail on its claims or whether resolution of this matter will have a material effect on our financial condition.
Refer to Note 12(c) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 132 for a more detailed discussion of NSR issues.
Manufactured Gas Plant (MGP) Sites PSI received claims from Indiana Gas Company, Inc. (IGC) in 1994, and from Northern Indiana Public Service Company (NIPSCO) in 1995, as more fully discussed in Note 12(d)(ii) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 133. The basis of these claims was that PSI is a Potentially Responsible Party with respect to certain MGP sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The claims further asserted that PSI is legally responsible for the costs of investigating and remediating the sites.
In November 1998, NIPSCO, IGC, and PSI entered into a Site Participation and Cost Sharing Agreement. The agreement allocated CERCLA liability for past and future costs at seven MGP sites in Indiana among the three companies. Similar agreements were reached between IGC and PSI that allocate CERCLA liability at 14 MGP sites with which NIPSCO was not involved. These agreements conclude all CERCLA and similar claims between the three companies related to MGP sites. The parties continue to investigate and remediate the sites, as appropriate under the agreements and applicable laws. The Indiana Department of Environmental Management (IDEM) oversees investigation and cleanup of some of the sites.
PSI notified its insurance carriers of the claims related to MGP sites raised by IGC, NIPSCO, and IDEM. In April 1998, PSI filed suit against its general liability insurance carriers. Among other matters, PSI requested a declaratory judgment that would 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. The case has been set for trial beginning in May 2001. PSI cannot predict the outcome of this litigation. Currently, reserves recorded related to MGP sites are immaterial to our financial condition or results of operations. However, as further investigation and remediation activities are performed at these sites, the potential liability for MGP sites could be material to our financial position or results of operations.
Other On November 30, 1999, the EPA filed a NOV against Cinergy and CG &E because emissions of particulate matter at Beckjord exceeded the allowable limit. The NOV indicated that the EPA may (1) issue an administrative penalty order, or (2) file a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. The allegations contained in this NOV were
incorporated within the March 1, 2000, amended complaint, as discussed in the "New Source Review" section on page 31. We are currently unable to determine whether resolution of this matter will have a material effect on our financial condition.
See Notes 12(b), (c), (d), and (e) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data", beginning on page 131, for a more detailed discussion of the status of these environmental issues.
Construction and Other Commitments
Construction Actual construction expenditures for 1999 and forecasted construction expenditures in nominal dollars for 2000 and for the next five years (2000-2004) are presented in the table below:
This table includes forecasted expenditures for 2000 of $65 million for preparing utility systems for customer choice. This table excludes an estimate of expenditures necessary to comply with the EPA's proposed stricter NOX emission control standards associated with the 22-state NOX SIP Call and Section 126 petitions (as discussed in the "Environmental Issues" section beginning on page 27). In the event the EPA successfully implements either program (the NOX SIP Call or the Section 126 petitions), capital expenditures for compliance are substantially the same, and are currently estimated at $500 million to $700 million (in 1999 dollars) by May 2003, approximately $105 million of which is estimated to be spent in 2000.
All forecasted amounts reflect the following assumptions relating to the factors below, which may change significantly:
•the general economy;
•capital markets;
•construction programs;
•legislative and regulatory actions;
•frequency and timing of rate increases; and
•other related factors.
Other Commitments Committed projects for both international and domestic non-regulated investment activities of approximately $160 million for 2000 are excluded from the table above. On September 30, 1999, one of our non-regulated subsidiaries formed a partnership with Duke. This partnership will jointly construct and own three wholesale generating facilities in southwestern Ohio, and east central and western Indiana, with total capacity of approximately 1,400 megawatts (MW). These facilities will be natural gas-fired peaking stations with commercial operation anticipated for the summer of 2000. Our portion (50%) of the remaining capital expenditures to complete this project is estimated at $110 million for 2000 and is included in the $160 million discussed above.
Additionally, Commodities constantly assesses the adequacy of its available power supply in order to meet the demands of its customers. It must consider other supply alternatives to pursue to most
effectively meet demands, mitigate risks, and satisfy regulatory requirements. Supply alternatives include the following:
•investments in existing facilities;
•investments in new facilities; and/or
•acquisitions of power supply from the market.
Other Investing Activities
Our mission is to be one of the top five in our industry within two years on the following five key dimensions: market capitalization, number of customers, electric and gas commodity trading, international presence, and productivity.
In pursuit of these goals, we have entered into various growth initiatives, including: (1) energy marketing and trading; (2) retail energy products and services; and (3) additional international investments. We are constantly working toward maximizing the value of existing operations and assets and continue to explore the potential for mergers, acquisitions, and strategic alliances.
Our ability to invest in growth initiatives is limited by certain legal and regulatory requirements, including the PUHCA. The PUHCA restricts the amount which can be invested in 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 regulations, we are allowed to invest or commit to invest in certain non-utility businesses, including:
1. Exempt Wholesale Generators (EWG) and Foreign Utility Companies (FUCO)
An EWG is a special purpose entity that owns or operates domestic or foreign electric generating facilities whose power is sold entirely at wholesale. A FUCO is a company all of whose utility assets and operations are located outside the U.S. and which are used for the generation, transmission, or distribution of electric energy for sale, or the distribution of gas at retail.
The SEC has issued an order under the PUHCA permitting Cinergy to invest, on a recourse basis, an amount equal to 100% of consolidated retained earnings in EWGs and FUCOs. The definition of consolidated retained earnings, under the applicable SEC regulations, is the average consolidated retained earnings of the four most recent quarterly periods. At December 31, 1999, we had invested or committed to invest $580 million of the approximately $1 billion available.
On November 16, 1999, we filed a request with the SEC under the PUHCA for additional authority to, among other things, increase the amount we can invest in EWGs and FUCOs, as further discussed in the "Capital Resources" section on page 38 and the "Retail Market Developments" section beginning on page 54. While we currently cannot predict the outcome of this request, the existing limits could restrict our ability to invest in desired transactions.
2. Qualifying Facilities and Energy Related Non-utility Entities
SEC regulations under the PUHCA permit Cinergy to invest and/or guarantee an amount equal to 15% of consolidated capitalization (consolidated capitalization is the sum of Notes payable and other short-term obligations, Long-term debt (including amounts due within one year), 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, 1999, we had invested and/or guaranteed approximately $650 million of the $948 million available.
Year 2000
The Year 2000 concern generally existed because many computer systems and applications, including those systems embedded in equipment and facilities, used two-digit date fields rather than four-digit date fields to designate an applicable year. As a result, these systems and applications were not expected to properly recognize dates including and beyond the Year 2000. The potential consequences of this action included data miscalculations and inaccuracies or operational malfunctions and failures, which could have materially affected a company's financial position, operating results, and cash flows.
Cinergy established a centrally managed, company-wide initiative, known as the Cinergy Year 2000 Readiness Program, to identify, evaluate, and address Year 2000 issues. The Cinergy Year 2000 Readiness Program, which began in the fourth quarter of 1996, was generally focused on three elements that were integral to this initiative: (1) business continuity, (2) risk management, and (3) regulatory compliance.
Under the Cinergy Year 2000 Readiness Program, we achieved a target date of June 30, 1999, for the remediation and testing of our mission-critical generation, transmission, and distribution systems, components, and applications (gas and electric). An innovative remediation and testing effort, which we also completed on June 30, 1999, involved resetting the clocks on all of our generation units and operating them as if January 1, 2000, had already occurred.
In August of 1999, the North American Electric Reliability Council (NERC) submitted a final status report to the Department of Energy, in which we were listed as a "Y2K Ready" organization. In September of 1999, we participated in the NERC-sponsored national preparedness drill. The goal of this drill was to rehearse, under simulated conditions, key portions of our administrative, operating, communications, and contingency plans for the transition into the Year 2000. We were successful in meeting the objectives of this drill.
We reviewed and assessed the potential for business disruption in various scenarios, including the most reasonably likely worst-case scenario, and provided for key operational back up, recovery, and restoration alternatives. We also established a supplier compliance program, and worked with our critical suppliers in an effort to minimize risks.
The total cost for the inventory, assessment, remediation, testing, and upgrading of our systems as a result of the Year 2000 effort was approximately $13 million. These expenses included labor, hardware and related software upgrades.
Our rollover to the Year 2000 was uneventful. All mission critical systems for gas and electric service performed without any disruption to customer service. We had a force of 1,100 employees in place during the rollover to monitor systems, substations, power generating stations, gas regulating stations and other facilities. Our systems continue to operate without problems related to the Year 2000.
The above information is a Year 2000 Readiness Disclosure pursuant to the Federal Year 2000 Information and Readiness Disclosure Act.
CAPITAL RESOURCES
During 1999, we met our capital requirements through a combination of internally generated funds and debt issuances. We expect to meet our future capital needs through a combination of internally and externally generated funds, including the issuance of debt and/or equity securities.
See the "Proposed Financing Authority" section on page 42 for information on our request for additional authority to issue debt, guarantees, and common stock.
Internally Generated Funds
Currently, a substantial portion of our revenues and corresponding cash flows are derived from our regulated operations. With the recent passage of legislation throughout several states, we believe it is likely the generation component of the electric utility industry will ultimately be deregulated. (Within our own utility jurisdictions, only the State of Ohio has passed similar legislation during 1999. Refer to the "Retail Market Developments" section on page 54.) In the interim, revenues provided by our regulated operations will continue as our primary source of funds. As a low cost provider of energy service, we believe we will be successful in a competitive environment. However, as the industry becomes more competitive, future cash flows from operations could be subject to a higher degree of volatility than under our present regulatory structure.
Debt
We may be required to secure authority to issue 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 debt for Cinergy Corp. Our three state utility commissions regulate the issuance of debt for our operating companies.
Cinergy Corp. has current authorization from the SEC under the PUHCA to issue and sell short-term notes and commercial paper and long-term unsecured debt through December 31, 2002, provided the total principal amount of all these debt securities may not exceed $2 billion at any time. In addition, Cinergy Corp.'s long-term debt cannot exceed $400 million at any time. As of December 31, 1999, Cinergy Corp. has $400 million of long-term debt outstanding, and therefore, under the current authorization, it cannot issue any additional long-term debt. See the "Proposed Financing Authority" section on page 42 for information on our request for additional authority to issue debt.
Short-term Debt In connection with this SEC authorization, Cinergy Corp. has established lines of credit. As of December 31, 1999, all of its $645 million established lines were unused and available.
Our operating companies have regulatory authority to borrow up to a total of $853 million in short-term debt ($453 million for CG&E and its subsidiaries including $50 million for ULH&P, and $400 million for PSI). In connection with this authority, we have established lines of credit for CG &E and PSI of which, $124 million and $110 million, respectively, remained unused and available at December 31, 1999.
As of December 31, 1999, our non-regulated subsidiaries have $83 million in short-term debt and established lines of credit of which, $.6 million was unused and available. Our non-regulated subsidiaries have the availability of funds from Cinergy Corp. if the need arises.
Cinergy Corp.'s established lines of credit also provide credit support for our commercial paper program, which is limited to a maximum principal amount of $400 million. As of December 31, 1999, Cinergy Corp. has not used any of the established principal amount, leaving $400 million available. CG&E and PSI also have the capacity to issue commercial paper, which must be supported by available committed lines of the respective company. The maximum outstanding principal amount for CG&E is
$200 million and for PSI is $100 million. Neither CG&E nor PSI issued commercial paper in 1999 or 1998.
For a detailed discussion of the registrants' short-term indebtedness, refer to Note 5 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 117.
Long-term Debt Under the PUHCA authorization mentioned above, we are able to issue and sell long-term debt at the parent holding company level. In addition, Cinergy Corp.'s long-term debt cannot exceed $400 million at any time. As of December 31, 1999, Cinergy Corp. has $400 million of long-term debt outstanding, and therefore, under the current authorization, it cannot issue any additional long-term debt.
Currently, our operating companies have the following types of outstanding long-term debt: First Mortgage Bonds and other Secured Notes, and Senior and Junior Unsecured Debt. Under our existing authority, the remaining unissued debt, as of February 29, 2000, is reflected in the following table:
We may, at any time, request additional long-term debt authorization to increase our authority. This request is subject to regulatory approval which may or may not be granted.
As of December 31, 1999, through shelf registrations filed with the SEC under the Securities Act of 1933, we could issue the following amounts of debt securities:
Capital Leases We are able to enter into capital leases under state regulatory authorizations. However, our ability to enter into capital leases is limited to the total authorized limit granted by the applicable state utility commission. We may, at any time, request additional capital lease authorization to increase our limits. This request is subject to approval by the applicable state utility commission and may or may not be granted. Under our existing authority, the remaining unused capital lease authority, is $86 million for CG&E, $100 million for PSI, and $24 million for ULH&P.
Common Stock
Cinergy Corp. has authority to issue additional shares of common stock on the open market to meet future capital requirements. However, we do not have plans to issue common stock for capital requirements in the foreseeable future. We generally use open market purchases of common stock to satisfy the majority of our obligations of our various stock-based employee plans. We plan to continue using market purchases of common stock to satisfy these obligations. This decision will be reevaluated as future capital requirements are considered.
The following table reflects the number of shares purchased and issued for our various stock-based plans for the following years:
The SEC authorized us under the PUHCA to issue and sell an additional 22 million shares of common stock for these stock-based employee plans. This authorization expires December 31, 2000. Also, we have authority to issue and sell an additional 30 million shares of common stock for general corporate purposes, which expires December 31, 2002. See the "Proposed Financing Authority" section on page 42 for information on our request for additional authority to issue common stock.
Dividend Restrictions
For a discussion of dividend restrictions, refer to Note 2(b) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 109.
Securities Ratings
As of February 29, 2000, the major credit rating agencies rated our securities as follows:
(1)Duff & Phelps Credit Rating Co. (D&P)
(2)Fitch IBCA, Inc. (Fitch)
(3)Moody's Investors Service (Moody's)
(4)Standard & Poor's Ratings Services (S&P)
These securities ratings may be revised or withdrawn at any time, and each rating should be evaluated independently of any other rating.
Guarantees
We are subject to a SEC order under the PUHCA which limits the amounts Cinergy Corp. can have outstanding under guarantees (promises to pay by one party in the event of default by another party) at any one time to $1 billion. As of December 31, 1999, we had $515 million outstanding under the guarantees issued. See the "Proposed Financing Authority" section on page 42 for information on our request for additional authority to issue guarantees.
In February 2000, Cinergy Corp. issued approximately $43 million in guarantees for loans and the associated interest related to the Director, Officer and Key Employee Stock Purchase Program. For a detailed discussion of this program, refer to Note 2(d) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 115.
Proposed Financing Authority
On November 16, 1999, Cinergy Corp. filed a request with the SEC under the PUHCA for additional authority to issue and/or sell:
•up to $4.4 billion aggregate principal amount of any combination of short- and long-term debt;
•up to $2 billion outstanding amounts under guarantees issued; and
•up to 75 million additional shares of common stock.
We proposed to use the proceeds from the transactions described above for general corporate purposes, including additional investments in EWGs and FUCOs.
This request would increase the amount we can invest in EWGs and FUCOs to an amount equal to 100% of consolidated retained earnings plus $2 billion, excluding our aggregate investment in one or more EWG affiliates formed to acquire all or a substantial portion of the existing generating facilities owned by our utility subsidiaries. We currently cannot predict the outcome of this request.
Sale of Accounts Receivable
For the detailed discussion of our sales of accounts receivable, refer to Note 6 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 120.
The format of the following Results of Operations discussions has been changed from the format of prior periods. Unlike prior reports, the Results of Operations discussions for Cinergy, CG&E, and PSI are combined within this section.
1999 RESULTS OF OPERATIONS
SUMMARY OF RESULTS
Electric and gas margins and net income for Cinergy, CG&E, and PSI for the years ended December 31, 1999, and 1998, were as follows:
(1)The results of Cinergy also include amounts related to non-registrants.
Our 1999 diluted earnings per share (EPS) increased to $2.53 from $1.65 per share for 1998.
The overall increase in EPS for 1999 is mainly due to our international operations and our regulated electric operations. The contribution to earnings of our international operations increased $.36 per share for the year ended December 31, 1999, compared with a year ago, primarily the result of the sale of our 50% ownership interest in Avon Energy to GPU. Earnings from regulated operations had a net increase of $.55 per share for the year ended December 31, 1999, compared with a year earlier. The increase is primarily due to an overall return to more normal weather in 1999 and growth
in retail electric revenues. This retail revenue growth reflects an increase in residential and commercial customers and growth in the industrial market. Included in this overall increase is a $.36 per share reduction related to energy marketing and trading losses experienced in July 1999. Our electric margins were positively impacted $12 million or $.07 per share (net of fuel and income taxes) as a result of a change in estimate of PSI's utility services delivered but unbilled at month end which occurred during the third quarter of 1999.
The 1999 increase in earnings from regulated operations was also impacted by the following 1998 charges:
•a reduction of $.14 per share for the effects of milder than normal weather;
•a charge of $.32 per share related to a settlement with Wabash Valley Power Association, Inc. (WVPA). (See Note 18 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 144 for a discussion of the WVPA settlement.); and
•total charges of $.54 per share due to losses related to our energy marketing and trading activity.
The explanations below follow the line items on the Statements of Income for Cinergy, CG&E, and PSI, which begin on page 73. However, only the line items that varied significantly from prior periods are discussed.
ELECTRIC OPERATING REVENUES
(1)The results of Cinergy also include amounts related to non-registrants.
Electric operating revenues for Cinergy, CG&E, and PSI decreased for 1999, as compared to 1998, due to a decrease in volumes on non-firm wholesale transactions related to energy marketing and trading activity. Partially offsetting the decline was an increase in the average price per kilowatt hour (kWh) realized for non-firm power transactions and higher firm wholesale kWh sales. Non-firm power is power without a guaranteed commitment for physical delivery. Retail kWh sales also increased as a result of new residential and commercial customers, growth in the industrial market, and an overall return to more normal weather. Our electric margins were positively impacted $12 million or $.07 per share (net of fuel and income taxes) as a result of a change in estimate of PSI's utility services delivered but unbilled at month end which occurred during the third quarter of 1999.
GAS OPERATING REVENUES
(1)The results of Cinergy also include amounts related to non-registrants.
Gas operating revenues for Cinergy increased in 1999, when compared to 1998. This increase reflects a full year's realization of the gas operating revenues of Cinergy Marketing and Trading, LLC (Marketing & Trading), an indirect subsidiary of Cinergy that was acquired in June 1998. Based on the actual results of Marketing & Trading for 1998, if we had owned it for all of 1998, our 1999 revenues, as compared to 1998, would have increased due to a higher price received per thousand cubic feet (mcf) sold.
CG&E's retail gas revenues decreased 10% due to a decline in mcf sales. This resulted primarily from milder weather experienced during the first quarter of 1999. This decline was partially offset by an increase in transportation revenues due to the continued progression of full-service customers (customers who purchase gas and utilize the transportation services of CG&E) purchasing gas directly from suppliers and using transportation services provided by CG&E.
OPERATING EXPENSES
(1)The results of Cinergy also include amounts related to non-registrants.
Fuel
Fuel 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 1998 to 1999:
(1)The results of Cinergy also include amounts related to non-registrants.
Purchased and Exchanged Power
Purchased and exchanged power represents the electricity that is bought to be sold through our energy marketing and trading activities. This expense decreased for Cinergy, CG&E, and PSI in 1999. This decrease was primarily due to a reduction in purchases of non-firm wholesale power as a result of a decline in sales volume in the energy marketing and trading operations. Included in purchased and exchanged power are additional costs related to energy marketing and trading losses experienced in July 1999, as previously indicated above in "Summary of Results", as well as, losses related to our 1998 energy marketing and trading activity. (See "Market Risk Sensitive Instruments and Positions" on page 61 and Note 1(j) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 106 for discussions on our energy marketing and trading operations.)
Gas Purchased
Gas purchased expense increased for Cinergy in 1999, when compared to 1998. This increase primarily reflects a full year's Gas purchased volumes for Marketing & Trading in 1999, as previously indicated above in "Gas Operating Revenues".
CG&E's Gas purchased expense decreased for 1999, as compared to 1998. This decline is mainly due to decreased sales volume as previously indicated above in "Gas Operating Revenues".
Operation
PSI's Operation costs decreased in 1999, in comparison to 1998. This decrease was the result of a one-time charge of $80 million in 1998 for the implementation of the 1989 settlement with WVPA. (See Note 18 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 144 for a discussion of the WVPA settlement.)
Maintenance
Cinergy's, CG&E's, and PSI's Maintenance costs increased in 1999, as compared to 1998, primarily as a result of planned outages and repairs at certain production facilities. These activities represent a return to a more normal level of maintenance expenditures.
Depreciation and Amortization
Cinergy's, CG&E's, and PSI's Depreciation and amortization costs increased in 1999, as compared to 1998. These increases were the result of additions to depreciable plant. Additionally, Cinergy's and CG&E's increases also included the amortization of phase-in deferrals reflecting the Public Utilities Commission of Ohio (PUCO)-approved phase-in plan for CG&E's William H. Zimmer Generating Station (Zimmer).
EQUITY IN EARNINGS OF UNCONSOLIDATED SUBSIDIARIES
Cinergy's Equity in earnings of unconsolidated subsidiaries increased $7 million (13%) in 1999, as compared to 1998. This increase was primarily driven by the earnings of our non-regulated domestic and international subsidiaries. Included in Equity in earnings of unconsolidated subsidiaries was $58 million for 1999, and $57 million for 1998, related to our 50% ownership interest in Avon Energy. As a result of the sale of our ownership interest (as discussed below), our Equity in earnings of unconsolidated subsidiaries will reflect a decline in future periods.
GAIN ON SALE OF INVESTMENT IN UNCONSOLIDATED SUBSIDIARY
On July 15, 1999, we sold our 50% ownership interest in Avon Energy to GPU, as previously indicated above in "Summary of Results". The sale resulted in a net contribution to earnings of approximately $.43 per share (basic and diluted). For a further discussion of this transaction, see Note 10 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 126.
PREFERRED DIVIDEND REQUIREMENTS
Cinergy's Preferred dividend requirements of subsidiaries and PSI's Preferred dividend requirement each decreased $1 million for 1999, as compared to 1998. These decreases were attributable to PSI's redemption of all outstanding shares of its 7.44% Series Cumulative Preferred Stock on March 1, 1998.
ULH&P
The format of the following Results of Operations discussion has been changed from the format of prior reports. Unlike prior reports, the Results of Operations discussion for ULH&P is presented only for the year ended December 31, 1999, in accordance with General Instructions I(2)(a).
Electric and gas margins and net income for ULH&P for the years ended December 31, 1999, and 1998 were as follows:
The increases in Electric and Gas operating revenues for the year ended December 31, 1999, compared to 1998, were primarily attributable to higher retail kWh and mcf sales, resulting from growth in the number of electric and gas residential and commercial customers. In addition, Electric operating revenues increased due to an overall return to more normal weather. These increases in sales volume also correspond with increases in Electricity purchased from parent company for resale and Gas purchased expenses.
The increase in Operation and Maintenance costs for the year ended December 31, 1999, as compared to 1998, was the result of increased maintenance of overhead lines and gas mains.
The increase in Depreciation for the year ended December 31, 1999, as compared to 1998, was primarily due to additions to depreciable plant. The Interest expense increase for the year ended December 31, 1999, as compared to 1998, was primarily due to the issuance of $20 million of debt during the fourth quarter of 1998.
1998 RESULTS OF OPERATIONS
SUMMARY OF RESULTS
Electric and gas margins and net income for Cinergy, CG&E, and PSI for the years ended December 31, 1998, and 1997, were as follows:
(1)The results of Cinergy also include amounts related to non-registrants.
Earnings of $1.65 per share in 1998 were up $.04 per share compared with $1.61 per share in 1997. Included in 1997 results was a one-time extraordinary charge of $.69 per share for the windfall profits tax levied against our 50% ownership interest in Midlands. (See Note 17 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 144 for a discussion of the windfall profits tax.)
Our 1998 EPS reflects the following:
•a reduction of $.14 per share for the effects of milder than normal weather;
•a charge of $.32 per share related to a previously reported settlement with WVPA (See Note 18 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 144 for a discussion of the WVPA settlement.); and
•total charges of $.54 per share due to losses related to our energy marketing and trading activity.
The explanations below follow the line items on the Statements of Income for Cinergy, CG&E, and PSI, which begin on page 73. However, only the line items that varied significantly from prior periods are discussed.
ELECTRIC OPERATING REVENUES
(1)The results of Cinergy also include amounts related to non-registrants.
Electric operating revenues for Cinergy, CG&E, and PSI increased for 1998, as compared to 1997. Wholesale revenues increased primarily due to increased sales volume and a higher average price per kWh realized on non-firm wholesale transactions, which were a result of our energy marketing and trading activity. Retail kWh sales increased due to warmer weather in 1998, when compared to 1997, and as a result of an increase in the number of residential and commercial customers.
GAS OPERATING REVENUES
(1)The results of Cinergy also include amounts related to non-registrants.
Gas operating revenues for Cinergy increased for 1998, when compared to 1997, primarily due to the gas operating revenues of Marketing & Trading, an indirect subsidiary of Cinergy that was acquired in June 1998. Partially offsetting this increase was the decline in retail sales for CG&E.
CG&E's retail sales decreased due to lower mcf volumes reflecting, in part, the milder weather during the first quarter of 1998, and a reduction in the number of full-service residential, commercial, and industrial customers. In addition, CG&E's transportation revenues increased as full-service customers continued the trend of purchasing gas directly from suppliers and using transportation services provided by CG&E.
OPERATING EXPENSES
(1)The results of Cinergy also include amounts related to non-registrants.
Fuel
The following table details the changes to fuel expense from 1997 to 1998:
(1)The results of Cinergy also include amounts related to non-registrants.
Purchased and Exchanged Power
Purchased and exchanged power expense increased for Cinergy, CG&E, and PSI in 1998. This increase was primarily the result of more purchases of non-firm wholesale power due to an increase in energy marketing and trading activity and an increase in the average price paid per kWh. Also in 1998, Cinergy recognized $135 million ($73 million for CG&E, and $62 million for PSI), of unrealized losses related to our energy marketing and trading activity. (See "Market Risk Sensitive Instruments and Positions" on page 61 and Note 1(j) of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 106 for discussions on our energy marketing and trading activity.)
Gas Purchased
Gas purchased expense increased for Cinergy in 1998, primarily due to the Gas purchased expense of Marketing & Trading, an indirect subsidiary of Cinergy, that was acquired in June 1998. CG&E's Gas purchased expense decreased because of a decline in the volumes purchased, due to lower demand, and a lower average cost per mcf of gas purchased.
Operation
Cinergy's and PSI's Operation costs increased in 1998, as compared to 1997. These increases primarily relate to a one-time charge of $80 million for the implementation of the 1989 settlement with WVPA. (See Note 18 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 144 for a discussion of the WVPA settlement.) Additionally, Cinergy's increase was also the result of additional costs related to new initiatives of the non-regulated businesses.
Maintenance
Cinergy's and PSI's Maintenance costs increased in 1998, as compared to 1997, primarily due to increases in boiler plant maintenance costs and distribution line maintenance costs resulting from storm damage.
Depreciation and Amortization
Cinergy's and CG&E's Depreciation and amortization costs increased in 1998, as compared to 1997. These increases primarily relate to an increase of $9 million attributable to the amortization of phase-in deferrals reflecting the PUCO-approved phase-in plan for Zimmer.
EQUITY IN EARNINGS OF UNCONSOLIDATED SUBSIDIARIES
Cinergy's Equity in earnings of unconsolidated subsidiaries decreased $9 million (15%) in 1998, as compared to 1997. The majority of this decrease reflects a decline in the earnings of Midlands, resulting from milder weather conditions and a one-time penalty imposed (in 1998) on each electric distribution company caused by the delay in opening the electricity supply business to competition.
INTEREST
CG&E's Interest expense decreased $14 million (12%) in 1998, as compared to 1997, due to decreases in both interest on long-term debt and other interest expense. The decrease in interest expense on long-term debt is primarily due to a net redemption of approximately $86 million of long-term debt during the period of March 1997 through December 1998. The decrease in other interest is due to a reduction in average short-term borrowings.
PSI's Interest expense increased $5 million (6%) for 1998, as compared to 1997. Interest on long-term debt increased $9 million, due primarily to the net issuance of approximately $163 million of long-term debt during the period from March 1998 to December 1998. Offsetting this increase was a decrease in other interest expense, primarily resulting from a reduction in average short-term borrowings and lower short-term interest rates.
INCOME TAXES
Cinergy's Income taxes decreased $96 million (45%) in 1998, as compared to 1997, due to a decrease in taxable income over the prior year and the increased utilization of foreign tax credits.
PREFERRED DIVIDEND REQUIREMENTS
Cinergy's Preferred dividend requirements of subsidiaries and PSI's Preferred dividend requirement each decreased $6 million in 1998, as compared to 1997. These decreases resulted from PSI's redemption of all outstanding shares of its 7.44% Series Cumulative Preferred Stock on March 1, 1998.
EXTRAORDINARY ITEM
Extraordinary item-equity share of windfall profits tax represents the one-time charge for the windfall profits tax levied against Midlands, recorded in 1997. (See Note 17 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 144.)
FUTURE EXPECTATIONS/TRENDS
In the "Future Expectations/Trends" section, we discuss electric and gas industry developments, market risk sensitive instruments and positions, impact of acquisitions and dispositions, inflation, and accounting changes. Each of these discussions will address the current status and potential future impact on our results of operations and financial condition.
ELECTRIC INDUSTRY
The utility industry has traditionally operated as a regulated monopoly but is transitioning to an environment of increased wholesale and retail competition. Regulatory and legislative decisions being made at the federal and state levels aimed at promoting customer choice are shaping this transition. Customer choice provides the customer the ability to select an energy supplier (the company that generates or supplies the power), in an open and competitive marketplace. This emerging environment presents significant challenges, which are discussed below.
Wholesale Market Developments
In 1996, the Federal Energy Regulatory Commission (FERC) issued orders to open the wholesale electric markets to competition. Competitors within the wholesale market include both utilities and non-utilities such as exempt wholesale generators, independent power producers, and power marketers. We are involved in wholesale power marketing and trading through Commodities.
In late June 1998, and again in late July 1999, Midwest wholesale electric power markets experienced unprecedented price spikes. These price spikes were caused by a number of factors including (1) unseasonably hot weather, (2) unplanned generating unit outages, (3) transmission constraints, and (4) increased electric commodity market volatility. These simultaneous events created temporary but extreme prices in the Midwest electricity markets. As a result, during 1999 and 1998, we recorded after tax charges to income of $0.36 per share and $0.54 per share, respectively. In response to these events, we are aggressively pursuing a combination of mitigation strategies. These strategies, along with the expiration of the legacy wholesale contracts discussed below, the anticipated effects of recently enacted customer choice legislation in Ohio beginning in 2001, new contracts for additional transmission from outside the region, and general market maturation, should result in reduced exposure to the consequences of extreme weather and operating conditions and, therefore, the risk of future financial losses in 2000 and beyond.
Supply-side Actions On September 30, 1999, one of our non-regulated subsidiaries formed a partnership with Duke, in an effort to increase the available generating capacity for use during peak demand periods. This partnership will jointly construct and own three wholesale generating facilities to be located in southwestern Ohio, and east central and western Indiana, with total capacity of approximately 1,400 MW. These facilities will be natural gas-fired peaking stations with commercial operation anticipated for the summer of 2000. Our portion (50%) of the output will be sold to and marketed by Cinergy Capital & Trading (a wholly-owned subsidiary of Investments) or another Cinergy affiliate. We are supplementing this additional capability with block power purchases for the summer of 2000 peak period.
Demand-side Actions Demand on our system is expected to be reduced in future years as a result of the roll-off of existing wholesale contractual obligations and peak load management initiatives recently developed by us.
Over the next five years, our wholesale obligations will decline from almost 3,000 MW of obligations in 1999 to about 1,000 MW in 2005. In addition to the normal expiration of contract commitments over time, we are pursuing contract restructurings with certain wholesale customers.
Finally, Ohio's recently enacted customer choice legislation contemplates that 20% of CG&E's retail load be switched to alternative suppliers by June 2003. In its transition plan filed with the PUCO, CG&E indicated that it currently has no plans to replace these customers by acquiring new retail customers, although CG&E reserved the flexibility to replace load in the wholesale market to the extent it chooses.
For further discussion, see the "Market Risk Sensitive Instruments and Positions" section on page 61.
Retail Market Developments
Currently, regulatory and legislative initiatives shaping the transition to a competitive retail market are the responsibilities of the individual states. Many states, including Ohio, have enacted electric utility deregulation legislation. In general, these initiatives have sought to separate the electric utility service into its basic components (generation, transmission, and distribution) and offer each component separately for sale. This separation is referred to as unbundling of the integrated services. We currently supply (either through generation or open market purchase), transmit, and distribute electricity to all retail customers in our service area. Under the customer choice initiatives, we would continue to transmit and distribute electricity; however, the customer could purchase electricity from any available supplier. The following sections will further discuss the current status of deregulation legislation in the states of Ohio, Indiana, and Kentucky, each of which includes a portion of our service territory.
Federal Update The Clinton Administration has introduced a bill-the Comprehensive Electricity Competition Act-that would grant all retail electric customers the right to choose their electricity supplier beginning January 1, 2003. The legislation would allow a state regulatory authority to opt out of the retail competition system if the authority conducted a public proceeding and determined that the electric customers of that state would be better served by a monopoly system or an alternative retail competition plan. A "compromise bipartisan" deregulation bill introduced on May 26, 1999, by Representatives Largent (R-OK) and Markey (D-MA) includes similar mandates and opt out provisions with an effective date of January 1, 2002.
Both the U.S. House of Representatives and the U.S. Senate continue to hold hearings on electric restructuring to see if consensus legislation can be developed, but it is uncertain whether federal retail customer choice legislation will be passed by this Congress.
Ohio On July 6, 1999, Ohio Governor Robert Taft signed Amended Substitute Senate Bill No. 3 (Electric Restructuring Bill, the Bill), beginning the transition to electric deregulation and customer choice for the State of Ohio. The Electric Restructuring Bill creates a competitive electric retail service market beginning January 1, 2001. The legislation provides for a market development period that begins January 1, 2001, and ends no later than December 31, 2005. Ohio electric utilities have an opportunity to recover PUCO-approved transition costs during the market development period. CG&E is seeking to recover all generation-related regulatory assets and above-market generation costs as allowable transition costs. The legislation also freezes retail electric rates during the market development period, except for a five-percent reduction in the generation component of residential rates and other potential adjustments. Furthermore, the legislation contemplates that twenty percent of the current electric retail customers will switch suppliers no later than December 31, 2003.
The Electric Restructuring Bill required each utility supplying retail electric service in Ohio to file a comprehensive proposed transition plan with the PUCO addressing specific requirements of the legislation. CG&E filed its plan on December 28, 1999. The PUCO is required to issue a transition order no later than October 31, 2000. Consumers will be allowed to begin selecting alternative electricity suppliers beginning January 1, 2001.
As required by the Electric Restructuring Bill, CG&E's Proposed Transition Plan (Transition Plan) is comprised of the following eight component plans:
(1)Rate Unbundling Plan;
(2)Corporate Separation Plan;
(3)Operational Support Plan;
(4)Employee Assistance Plan;
(5)Consumer Education Plan;
(6)Application for Receipt of Transition Revenues (Transition Revenue Plan);
(7)Independent Transmission Plan; and
(8)Shopping Incentive Plan.
Rate Unbundling Plan The Electric Restructuring Bill requires the unbundling of retail electric rates in effect on October 4, 1999. The Bill also requires creation of new tariffs that will facilitate the transition to effective customer choice.
The CG&E Rate Unbundling Plan complies with the guidelines set forth in the legislation and separates CG&E's current retail electric rates into a transmission service component, a distribution service component, and a generation service component.
Corporate Separation Plan The Electric Restructuring Bill requires a corporate separation plan to ensure that a regulated utility (transmission and distribution services) will not extend any undue preference or advantage to any affiliate, division, or part of its own business engaged in competitive retail generation service. To this end, the legislation calls for the operational control of transmission assets to reside with a FERC-approved transmission entity that will not have control of any generation assets.
To meet these requirements, CG&E's Proposed Transition Plan provides for corporate separation of competitive retail electric services and other products and services from noncompetitive retail electric services. Also, CG&E plans to transfer the operational control of its transmission assets to Midwest Independent Transmission System Operator, Inc. (Midwest ISO), a FERC-approved transmission entity.
To further the policy goals of the legislation, CG&E has requested approval from the PUCO to establish an EWG. In order to create an EWG, CG&E must apply to the FERC for approval. Because Cinergy is a registered holding company under the PUHCA, before the FERC approves such an application, the Ohio, Indiana, and Kentucky state utility commissions must find that the transfer of CG&E's generating assets to an EWG: (1) will benefit consumers, (2) is in the public interest, and (3) does not violate state law. CG&E believes that its plan meets each of these requirements.
Operational Support Plan The Electric Restructuring Bill requires the submission of an operational support plan. This plan should address the operational support systems and business processes necessary to ensure a successful implementation of the customer's ability to choose its generation supplier.
CG&E's operational support plan complies with the guidelines and requirements established by the legislation and includes the following:
•the financial, technical and managerial requirements for Certified Suppliers (a certified supplier is a supplier who has applied for and received permission from the State of Ohio to market electricity to consumers);
•the enrollment process for customers who choose a Certified Supplier;
•the load forecasting and settlement process to ensure that Certified Suppliers are supplying the electricity needs of their retail customers; and
•the metering, billing and payment processes.
Employee Assistance Plan The Electric Restructuring Bill requires the submission of an employee assistance plan that addresses severance, retraining, early retirement, retention, outplacement, and other assistance for utilities' employees whose employment is adversely affected by electric restructuring during the market development period (January 1, 2001 through December 31, 2005).
To address this requirement, CG&E developed a plan for both non-union and union employees. For non-union employees, CG&E's plan describes severance and ancillary benefits. CG&E reserves the right to implement involuntary workforce reductions to achieve any reductions necessary, but intends to initially use voluntary reductions, if such reductions become necessary. For union employees, to date CG&E has met with one collective bargaining agent to discuss potential effects of restructuring on these union employees. This union membership approved a new agreement on February 4, 2000.
Consumer Education Plan The Electric Restructuring Bill calls for Ohio utilities to spend, in the aggregate, up to $16 million in the first year of the market development period, and $17 million throughout the remainder of the market development period, educating Ohio consumers on their opportunity to choose an alternative supplier of electricity.
Through participation in the Ohio Electric Utility Institute (OEUI), CG&E will support a statewide consumer education plan. Additionally, CG&E has developed a comprehensive service territory-specific consumer education campaign designed to educate Ohio consumers on how to exercise their right to choose. CG&E estimates its share of the costs associated with the consumer education program will not be material. As discussed further below, CG&E is requesting full recovery of these costs.
Application for Receipt of Transition Revenues (Transition Revenue Plan) The Electric Restructuring Bill provides that a utility's proposed transition plan may include an application to receive transition revenues. Transition revenues are collected in two ways: (1) through the payment of the generation component of unbundled rates by customers who do not switch generation suppliers, and (2) through payment of nonbypassable transition charges by customers who switch generation suppliers. Transition costs are costs that meet the following criteria:
•prudently incurred;
•legitimate, net, verifiable, and directly assignable or allocable to Ohio retail electric generation consumers;
•unrecoverable in a competitive market; and
•CG&E would otherwise be entitled an opportunity to recover in rates as a regulated utility.
The legislation requires that the PUCO must establish nonbypassable transition charges so that a utility has an opportunity to collect its transition revenues from customers that choose an alternative supplier during the market development period.
CG&E filed, with its Proposed Transition Plan, a request to recover generation-related regulatory assets and other transition costs through the receipt of transition revenues, beginning January 1, 2001. CG&E is seeking recovery of two primary components of transition costs. First, CG&E is requesting recovery of the balance of the Ohio retail jurisdictional generation-related assets on the books and records as of December 31, 2000, including a return on the unamortized balance. At December 31, 1999, the balance of the generation-related assets was approximately $436 million. The projected jurisdictional balance at December 31, 2000, is approximately $364 million. CG&E is requesting recovery to continue until December 31, 2010, or until the balance, including carrying costs, is fully amortized. CG&E has proposed to recover this amount utilizing the total amount that is currently included in rates for the recovery of regulatory assets. Additionally, CG&E is requesting recovery of other transition costs during the market development period, consisting primarily of above-market generation costs. As included in CG&E's Proposed Transition Plan, the projected balance at December 31, 2000, of these above-market generation costs is approximately $563 million. The transition costs associated with any above-market generation assets represents the difference between the net investment in such assets on CG&E's books and records as of December 31, 2000, and its market value, including carrying costs. CG&E has proposed to recover this amount through an adjustment mechanism that includes a periodic update of other transition costs, revenues and charges for changes in the market price of electricity. The carrying costs on CG&E's total transition costs are estimated at $311 million.
In addition, CG&E has requested that the costs described below be considered regulatory assets and deferred for future recovery in regulated utility rates, including carrying costs, after the market development period. These items total an estimated $116 million.
•incremental costs incurred to prepare utility systems for customer choice, including computerized customer service system costs;
•incremental costs incurred in presenting the Proposed Transition Plan;
•incremental costs incurred for the Consumer Education Plan;
•incremental costs incurred for the Independent Transmission Plan, including Midwest ISO costs;
•incremental costs for CG&E's share of the PUCO's Proposed Transition Plan consultant; and
•incremental costs to create an EWG.
CG&E is requesting this ratemaking treatment because each of the above items represents direct and incremental costs of transitioning to a competitive electric industry. CG&E will need to incur these costs in order to provide a safe, efficient and reliable public utility service. These costs are neither currently included in CG&E's rates nor recoverable in a competitive environment. To the extent that the PUCO does not allow deferral of these costs, they will be expensed as incurred.
Independent Transmission Plan The Electric Restructuring Bill requires that a utility not own or control transmission facilities located in Ohio as of January 1, 2001, unless it belongs to and transfers control of the transmission facilities to an operational "qualifying transmission entity" that meets nine requirements as set forth in the Bill.
To this end, CG&E has agreed to transfer functional control of its transmission facilities to the FERC-approved Midwest ISO. The requirements for FERC approval are substantially similar to the "qualifying transmission entity" test in the Bill. As a result, the FERC's approval of the Midwest ISO should satisfy the nine requirements set forth in the Bill requiring the Midwest ISO be a "qualifying transmission entity". For additional information about the Midwest ISO, see the "Midwest ISO" section on page 60.
Shopping Incentive Plan The Electric Restructuring Bill requires that the PUCO consider, in prescribing the transition charge for each customer class, a shopping incentive designed to induce, at a minimum, a twenty percent load switching rate by customer class halfway through the market development period, but not later than December 31, 2003.
CG&E's Shopping Incentive Plan describes the methodologies employed in arriving at a load switching forecast and additional factors that have been considered in developing a methodology for implementing a shopping incentive designed to induce at least a twenty percent load switching by customer class by December 31, 2003.
CG&E has further requested that, before implementing a shopping incentive credit to induce additional switching, the PUCO consider foregoing the mandatory five percent decrease in the unbundled generation component for residential customers. If switching levels remain below the twenty percent level or significantly below forecast, CG&E proposes that a shopping incentive credit then be implemented and adjusted by customer class until the twenty percent threshold has been achieved.
Conclusion While CG&E believes there is sound basis for the various requests made in its Proposed Transition Plan, it is currently unable to predict the extent to which the Proposed Transition Plan will be approved and its resulting effect on results of operations, cash flows, and financial position. CG&E is seeking to recover all generation-related regulatory assets and above-market generation costs as allowable transition costs. CG&E believes its current accounting for regulatory assets has been consistent with the regulatory orders issued by the PUCO and that such costs should be recovered in future rates. However, to the extent requested recovery of generation-related regulatory assets is disallowed or generating assets are financially impaired, CG&E will be required to recognize a loss under generally accepted accounting principles. With regard to these assets, CG&E will continue to apply Statement No. 71 until the effect of deregulation is estimable.
Indiana In January 1999, electric deregulation legislation was introduced into the Indiana General Assembly. Proposed and supported by a group of large industrial customers, this legislation did not pass in the 1999 session of the Indiana General Assembly. Due to a "short session" in 2000, the Indiana General Assembly is not expected to consider any electric deregulation initiatives. We will continue to work with the other Indiana investor-owned utilities in an effort to draft acceptable customer choice legislation. The outcome of this effort remains uncertain.
Kentucky Throughout 1999, a special Kentucky Electricity Restructuring Task Force, convened by the Kentucky legislature, studied the issues of electric deregulation. In January 2000, the Task Force issued a final report to Kentucky Governor Paul Patton recommending that lawmakers wait until the 2002 General Assembly before considering any deregulation legislation that would open the state's electric industry to competition.
Other
Our operating companies currently apply the provisions of Statement 71. Statement 71 applies to the financial statements of a rate-regulated company. The provisions allow our operating companies 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, 1999, our operating companies have $1,055 million of net regulatory assets, of which $956 million have been approved for recovery.
As of December 31, 1999, our regulated operations continue to meet each of the criteria required for the use of Statement 71. However, as states implement deregulation legislation, the application of Statement 71 will need to be reviewed. This potential change in accounting practice could create future extraordinary losses to the extent these regulatory assets are determined not to be recoverable. The
effect of the discontinuance of Statement 71 on the results of operations, cash flows, or statements of position cannot be determined until deregulation legislation plans have been approved by each state in which we do business. See "Ohio" section of "Retail Market Developments" on page 54 for details of how the Ohio deregulation legislation plan could affect our application of Statement 71.
Midwest ISO
As part of the effort to create a competitive wholesale power marketplace, the FERC approved the formation of the Midwest ISO during 1998. The Midwest ISO will oversee the combined transmission systems of its members. The organization is expected to begin operations in late 2001. This effort will help to facilitate a reliable and efficient market for electric power and create open transmission access consistent with FERC policies. The Midwest ISO currently includes 14 members with over 69,000 miles of transmission lines in 16 states and an aggregate investment of over $8.5 billion. In December 1999, the Midwest ISO announced plans to combine operations with the Mid-Continent Power Pool and the Southwest Power Area Pool.
Repeal of PUHCA
Various proposals to repeal or amend the PUHCA are pending before Congress. In February 1999, the Senate Banking, Housing and Urban Affairs Committee reported out of committee S.313, a bill to repeal the PUHCA. S.313 is awaiting action by the full Senate. In June 1999, H.R.2363, a bill to repeal the PUHCA was introduced in the U.S. House of Representatives as a companion to S.313. H.R.2363 is awaiting action by the House Commerce Committee.
The Clinton Administration has introduced legislation which repeals the PUHCA as part of a broader restructuring of the electricity industry. In October 1999, the House Subcommittee on Energy and Commerce reported out to the full House Commerce Committee H.R.2944, which would also repeal the PUHCA as part of a broader restructuring of the electricity industry. We support the repeal of the PUHCA either as part of broader restructuring of the electricity industry or as separate legislation.
Significant Rate Developments
Purchased Power Tracker On May 28, 1999, PSI filed a petition with the Indiana Utility Regulatory Commission (IURC) seeking approval of a purchased power tracking mechanism (tracker). This request is designed to provide for the recovery of costs related to purchases of power necessary to meet native load requirements to the extent such costs are not sought through the existing fuel adjustment clause. The tracker is intended to apply to a limited number of purchases made for the purpose of ensuring adequate power reserves to meet peak retail native load requirements, which in recent years have coincided with periods of extreme price volatility. As proposed by PSI, the tracker would only apply to capacity purchases which are presented to the IURC for review and approval as to reasonableness under the circumstances.
A hearing on this request was completed on December 9, 1999. An order is expected by the second quarter of 2000.
Coal Gasification PSI and Dynegy, Inc. (Dynegy, formerly Destec) entered into a 25-year contract for the provision of coal gasification services beginning in November 1995. The agreement required PSI to pay Dynegy a base monthly fee including certain monthly operating expenses. PSI received authorization in the September 1996 Order (an IURC order issued in September 1996 on PSI's retail rate proceeding) for the inclusion of these costs in retail rates. In addition, PSI received authorization to defer, for subsequent recovery in retail rates, the base monthly fees and expenses incurred prior to the effective date of the September 1996 Order.
During the third quarter of 1998, PSI reached an agreement with Dynegy to purchase the remainder of its 25-year contract for coal gasification services. The settlement agreement specified a purchase price of $247 million.
In anticipation of the buyout, PSI and the Indiana Office of Utility Consumer Counselor (UCC) came to a settlement agreement with respect to the proper ratemaking treatment of the buyout fee and other buyout implementation costs in June 1999. The agreement provides for PSI's retail electric rates to be decreased to eliminate jurisdictional costs associated with the gasification services agreement. In order to offset the buyout costs of the contract, the agreement allows PSI to recover the retail electric jurisdictional portion of the buyout fee and the associated buyout implementation costs through its rates with carrying costs on unrecovered amounts, over an eighteen-year period. In September 1999, the IURC approved the settlement agreement. In September 1999, PSI recorded a regulatory asset to reflect the buyout fee and the associated buyout implementation costs. In October 1999, PSI issued $265 million in debentures due in 2007 to fund the buyout of the remaining term of the contract and for the estimated cost of plant modifications to allow the use of natural gas.
MARKET RISK SENSITIVE INSTRUMENTS AND POSITIONS
Energy Commodities Sensitivity
The transactions associated with Commodities' energy marketing and trading activities give rise to various risks, including market risk. Market risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. As Commodities 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.
The energy marketing and trading activities of Commodities principally consist of CG&E's and PSI's power marketing and trading operations. These 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 U.S.. The power marketing and trading operation consists of both physical and trading activities. Transactions are designated as a physical activity when there is intent and ability to physically deliver the power from company-owned generation. All other transactions are considered trading activities. Substantially all of the contracts in both the physical and trading portfolios commit us to purchase or sell electricity at fixed prices in the future. Commodities also markets and trades over-the-counter option contracts. Substantially all of the contracts in the physical portfolio require settlement by physical delivery of electricity. Contracts within the trading portfolio generally require settlement by physical delivery or are netted out in accordance with industry trading standards. The use of these types of physical commodity instruments is designed to allow Commodities to (1) manage and hedge contractual commitments, (2) reduce exposure relative to the volatility of cash market prices, and (3) take advantage of selected arbitrage opportunities.
Commodities 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 Commodities 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.
Commodities measures the market risk inherent in the trading portfolio employing value-at-risk analysis and other methodologies, which utilize forward price curves in electric power markets to quantify estimates of the magnitude and probability of potential future losses related to open contract positions. Value-at-risk is a statistical measure used to quantify the potential loss in fair value of the trading portfolio over a particular period of time, with a specified likelihood of occurrence, due to an adverse market movement. Because most of the contracts in the physical portfolio require physical delivery of electricity and generally do not allow for net cash settlement, these contracts are not included in the value-at-risk analysis.
Our value-at-risk is reported as a percentage of operating income, based on a 95% confidence interval, utilizing one-day holding periods. This means that on a given day (one-day holding period) there is a 95% chance (confidence interval) that our trading portfolio will lose less than the stated percentage of operating income. We disclose our value-at-risk for power activities as a percent of consolidated operating income for a one-day basis at December 31, the average one-day basis at the end of each quarter, and the daily basis at December 31 of each year. On a one-day basis as of December 31, 1999, the value-at-risk for the power trading activity was less than 1% of 1999 consolidated operating income and as of December 31, 1998, was less than 1% of 1998 consolidated operating income. On a one-day basis at the end of each quarter, the value-at-risk for the power trading activity was less than 1% of consolidated operating income in 1999, and less than 2% in 1998. The daily value-at-risk for the power trading portfolio as of December 31, 1998, was less than 1% of 1999 consolidated operating income and as of December 31, 1997, was also less than 1% of 1998 consolidated operating income. The value-at-risk model uses the variance-covariance statistical modeling technique and historical volatilities and correlations over the past 200-day period. The estimated market prices used to value these transactions for value-at-risk purposes reflect the use of established pricing models and various factors including quotations from exchanges and over-the-counter markets, price volatility factors, the time value of money, and location differentials.
Commodities, through some of our non-regulated subsidiaries, actively markets physical natural gas and actively trades derivative commodity instruments which are usually settled in cash, including forwards, futures, swaps, and options. The aggregated value-at-risk amounts associated with these other trading and hedging activities were less than $2 million as of December 31, 1999, and less than $1 million at December 31, 1998. The market risk exposures of these non-regulated trading activities is not considered significant to our financial condition or results of operations.
Credit Risk Credit risk is the exposure to economic losses 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.
Our concentration of credit risk with respect to Delivery's trade accounts receivable from electric and gas retail customers is limited. The large number of customers and the diversified customer base of residential, commercial, and industrial customers significantly reduce our credit risk. Contracts within the physical portfolio of Commodities' power marketing and trading operations are primarily with traditional electric cooperatives and municipalities and other investor-owned utilities. At December 31, 1999, we do not believe we have significant exposure to credit risk with our trade accounts receivable within Delivery and our physical portfolio within Commodities.
Contracts within the trading portfolio of Commodities' power marketing and trading operations are primarily with power marketers and other investor-owned utilities. As of December 31, 1999, approximately 75% of the activity within the trading portfolio represent commitments with 10 counterparties, compared to 10 counterparties representing approximately 73% of the activity at
December 31, 1998. The majority of these contracts are for terms of one year or less. Counterparty credit exposure within the power-trading portfolio is routinely factored into the mark-to-market valuation. As a result of the extreme volatility experienced in the Midwest power markets during 1998, several new entrants into the market experienced financial difficulties and failed to perform their contractual obligations. This resulted in us recording bad debt provisions of approximately $13 million with respect to settled transactions. At December 31, 1999, our exposure to credit risk within the power-trading portfolio is not believed to be significant. As the competitive electric power market continues to develop, counterparties will increasingly include new market entrants, such as other power marketers, brokers, and commodity traders. This increased level of new market entrants, as well as competitive pressures on existing market participants, could increase Commodities' exposure to credit risk with respect to its power marketing and trading operation.
As of December 31, 1999, approximately one-third of the activity within the physical gas marketing and trading portfolio represents commitments with 10 counterparties, compared to 10 counterparties representing approximately 37% of the activity at December 31, 1998. Credit risk losses related to gas and other commodity physical and trading operations have not been significant. At December 31, 1999, the credit risk within the gas and other commodity trading portfolios is not believed to be significant because of the characteristics of counterparties and customers with which transactions are executed.
Potential exposure to credit risk also exists from our use of financial derivatives such as currency swaps, foreign exchange forward contracts, and interest rate swaps. Because these financial instruments are transacted only with highly rated financial institutions, we do not anticipate nonperformance by any of the counterparties.
Risk Management We manage, on a portfolio basis, the market risks in our energy marketing and trading transactions subject to parameters established by our Risk Policy Committee. Our market and credit risks are monitored by the risk management and credit functions to ensure compliance with stated risk management policies and procedures. These functions operate independently from the business units which originate and actively manage the market and credit risk exposures. The policies and procedures are periodically reviewed and monitored to ensure their responsiveness to changing market and business conditions. In addition, efforts are ongoing to develop systems to improve the timeliness and quality of market and credit risk information.
We have a risk management function and have implemented active risk management policies and procedures. These policies and procedures allow us to manage and minimize corporate and business unit exposure to: price risks and associated volatilities, credit risks, and other market risks. We also maintain counterparty credit policies to manage and minimize our exposure to credit risk.
These policies include:
•requiring parent company guarantees, under certain circumstances;
•various forms of collateral, under certain circumstances; and
•the use of mutual netting/closeout agreements.
Exchange Rate Sensitivity
From time to time, we may utilize foreign exchange forward contracts and currency swaps to hedge certain of our net investments in foreign operations. These contracts and swaps allow us to hedge our position against currency exchange rate fluctuations.
Through our investments in Midlands, we had exposure to fluctuations in the U.S. dollar/United Kingdom pound sterling exchange rate. We used dollar denominated variable interest rate debt to fund the investment and hedged our exposure through a currency swap. On July 15, 1999, we sold our 50% ownership interest in Avon Energy to GPU, as discussed in Note 10 of the "Notes to Financial
Statements" in "Item 8. Financial Statements and Supplementary Data" on page 126. As a result of this transaction, we terminated the hedging contracts related to the investment.
We also have exposure to fluctuations in the U.S. dollar/Czech koruna rate through our investments in the Czech Republic. We have historically hedged the exchange rate exposure related to certain of the Czech koruna denominated investments through foreign exchange forward contracts. However, during the second quarter of 1999, we settled these forward exchange contracts. The settlement costs were not material. The remaining foreign exchange hedging contracts are not significant.
Exposure to fluctuations in exchange rates between the U.S. dollar and the currencies of foreign countries where we have investments do exist. When it is appropriate we will hedge our exposure to cash flow transactions, such as a dividend payment by one of our foreign subsidiaries. At December 31, 1999, we do not believe we have a material exposure to the currency risk attributable to these investments.
Interest Rate Sensitivity
Our exposure to changes in interest rates consists of short-term debt instruments, pollution control debt, sale of accounts receivable, and the Woodsdale capital lease. The following table reflects the different instruments used and the method of benchmarking interest rates, as of December 31, 1999, and 1998:
(1) London Inter-Bank Offered Rate (LIBOR)
The weighted-average interest rates on the above instruments at December 31, 1999, and 1998, were as follows:
Current forward yield curves project an increase in applicable short-term interest rates over the next five years.
The following table presents principal cash repayments by maturity date and other selected information for each registrant's long-term fixed-rate debt, other debt, and capital lease obligations as of December 31, 1999:
(1)All long-term debt is fixed rate and 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 obligations, the weighted-average interest rate is based on the coupon rates of the debt that is maturing in the year reported; (2) for the variable rate capital leases, the interest rate is based on a spread over 3-month LIBOR, and averaged to be approximately 6% in 1999; (3) for the fixed rate capital leases, the interest rate is fixed at 6.71% with an amortizing principal structure; and (4) for the Foote Creek III Investment, the interest rate is based on a spread over 6- and 12-month LIBOR.
(3)Variable rate debt related to an investment under Global Resources.
(4)6.00% Debentures due December 14, 2016, reflected as maturing in 2001, as the interest rate resets on December 14, 2001.
(5)6.35% Debentures due June 15, 2038, reflected as maturing in 2003, as the interest rate resets on June 15, 2003.
(6)6.35% Debentures due November 15, 2006, reflected as maturing in 2000, as the Debentures are putable back to PSI on November 15, 2000.
Our current policy in managing exposure to fluctuations in interest rates is to maintain 25% of the total amount outstanding debt in floating interest rate debt instruments. To help maintain this level of exposure, we have previously entered into interest rate swaps. Under these swaps, we have agreed with other parties to exchange, at specified intervals, the difference between fixed rate and floating rate interest amounts calculated on an agreed notional principal amount. When less than 25% of the
outstanding debt had floating interest rates, we entered into swaps whereby we would receive a fixed rate and pay a floating rate. When more than 25% of the outstanding debt had fixed interest rates, we entered into swaps that allowed us to receive a floating rate while paying a fixed rate. At December 31, 1999, the composition of our debt consisted of slightly less than 25% of the outstanding amount having floating interest rates. PSI has an outstanding interest rate swap agreement that will increase this percentage of floating rate debt in the second half of 2000. Under the agreement, which has a notional amount of $100 million, PSI will pay a floating rate and receive a fixed rate for a six month period. The floating rate will be based on a short-term money market index. At December 31, 1999, the fair value of this interest rate swap was not significant. In the future, we will continually monitor market conditions to evaluate whether to increase, or decrease, our level of exposure to fluctuations in interest rates.
GAS INDUSTRY
Legislation
Customer Choice In November 1997, the State of Ohio commenced a customer choice program for the gas utility industry. This voluntary program gives residential and small commercial customers the opportunity to select their own gas supplier. Approximately two-thirds of the gas customers in the State of Ohio are eligible to participate. This program excludes large industrial, commercial, and educational institution customers because they already have the ability to select their own gas supplier.
Although the gas supplier may vary by customer, CG&E continues to provide gas transportation services for substantially all customers within its franchise territory.
Regulations
PUCO Order In 1996, the PUCO approved an overall increase in gas revenues of 2.5%, or $9.3 million annually, for CG&E. In establishing the rate increase, the PUCO excluded certain requests made by CG&E. In April 1997, CG&E filed a notice of appeal with the Supreme Court of Ohio to challenge the PUCO decisions. On July 7, 1999, the Supreme Court issued a ruling on the appeal. The ruling resulted in a revision in rates generating a $3 million increase in annual revenues for CG&E, which represents less than a one percent increase in retail rates. The implementation of this incremental rate change began in the third quarter of 1999.
IMPACT OF ACQUISITIONS AND DISPOSITIONS
Acquisitions
During 1999, we invested an additional $309 million in consolidated and unconsolidated subsidiaries, the most significant of which is the partnership with Duke. The Duke partnership is discussed in the "Wholesale Market Developments" section on page 53.
Dispositions
During 1999, we sold our 50% ownership interest in Avon Energy to GPU. See Note 10 of the "Notes to Financial Statements" in "Item 8. Financial Statements and Supplementary Data" on page 126 for an additional discussion of this sale.
INFLATION
We believe that the recent inflation rates do not materially impact our financial condition. However, under existing regulatory practice, 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.
ACCOUNTING CHANGES
During the second quarter of 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (Statement 133). This standard requires companies to record derivative instruments as assets or liabilities, measured at fair value. Changes in the derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Hedges are transactions entered into for the purpose of reducing exposure to one or more types of business risk. Gains and losses on derivatives that qualify as hedges can offset related results on the hedged item in the income statement.
This standard, as subsequently amended by Statement of Financial Accounting Standards No. 137, Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133 (Statement 137), is effective for fiscal years beginning after June 15, 2000. The purpose of Statement 137 was to delay the effective date of Statement 133 by one year. We expect to reflect the adoption of this standard in financial statements issued beginning in the first quarter of 2001. In recognition of the complexity of this new standard, the Derivatives Implementation Group has been formed by the FASB. In preparation for our implementation of this new standard, we have formed a cross-functional project team. The project team is identifying and analyzing all contracts which could be subject to the new standard, developing required documentation, defining relevant processes and information systems needs, and promoting internal awareness of the requirements and potential effects of the new standard. While we continue to analyze and follow the development of implementation guidelines, at this time we are unable to predict whether the implementation of this accounting standard will be material to our results of operations or financial position. However, the adoption of Statement 133 could increase volatility in earnings and other comprehensive income.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to the "Market Risk Sensitive Instruments and Positions" section of "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" on page 61.
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
The information required to be submitted in schedules other than those indicated above has been included in the balance sheets, the statements of income, related schedules, the notes thereto, or omitted as not required by the Rules of Regulation S-X.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company:
We have audited the financial statements of Cinergy Corp. (a Delaware Corporation), The Cincinnati Gas & Electric Company (an Ohio Corporation), PSI Energy, Inc. (an Indiana Corporation), and The Union Light, Heat and Power Company (a Kentucky Corporation), as of December 31, 1999 and 1998, and for each of the three years in the period ended December 31, 1999, as listed in the index on page 70. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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, the financial statements referred to above present fairly, in all material respects, the financial position of Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
As explained in Note 1 to the consolidated financial statements, the Company changed its method of accounting for its energy trading and risk management activities effective December 31, 1998.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index on page 70 pursuant to Item 14, are presented for purposes of complying with the Securities and Exchange Commissions Rules and Regulations under the Securities Exchange Act of 1934 and are not a required part of the basic financial statements. The schedules have been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth in relation to the basic financial statements taken as a whole.
Arthur Andersen LLP
Cincinnati, Ohio
January 26, 2000
CINERGY CORP.
AND SUBSIDIARY COMPANIES
CINERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes as they relate to Cinergy Corp. are an
integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to Cinergy Corp. are an
integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to Cinergy Corp. are an
integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
The accompanying notes as they relate to Cinergy Corp. are an
integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes as they relate to Cinergy Corp. are an
integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
AND SUBSIDIARY COMPANIES
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes as they relate to The Cincinnati Gas & Electric Company
are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to The Cincinnati Gas & Electric Company
are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to The Cincinnati Gas & Electric Company
are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
The accompanying notes as they relate to The Cincinnati Gas & Electric Company
are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes as they relate to The Cincinnati Gas & Electric Company
are an integral part of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Continued)
The accompanying notes as they relate to The Cincinnati Gas & Electric Company
are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
AND SUBSIDIARY COMPANY
PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes as they relate to PSI Energy, Inc.
are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to PSI Energy, Inc.
are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes as they relate to PSI Energy, Inc.
are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
The accompanying notes as they relate to PSI Energy, Inc.
are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes as they relate to PSI Energy, Inc.
are an integral part of these consolidated financial statements.
PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
The accompanying notes as they relate to PSI Energy, Inc.
are an integral part of these consolidated financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF INCOME
The accompanying notes as they relate to The Union Light, Heat and Power Company
are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS
The accompanying notes as they relate to The Union Light, Heat and Power Company
are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS
The accompanying notes as they relate to The Union Light, Heat and Power Company
are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
The accompanying notes as they relate to The Union Light, Heat and Power Company
are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CASH FLOWS
The accompanying notes as they relate to The Union Light, Heat and Power Company
are an integral part of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CAPITALIZATION
The accompanying notes as they relate to The Union Light, Heat and Power Company
are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
In 1996, the Securities and Exchange Commission (SEC) wrote guidelines to help make shareholder communications more understandable. These guidelines were termed "plain English". This year, we have written our annual report in accordance with these guidelines. Our objective is to present a more user-friendly, understandable, and logically-flowing document for our readers.
In connection with this change, we (which includes Cinergy Corp. and all of our regulated and non-regulated subsidiaries, also Cinergy) are, at times, referred to in the first person ("we", "our", or "us").
1. Summary of Significant Accounting Policies
(a) Nature of Operations Cinergy Corp., a Delaware corporation created in October 1994, owns all outstanding common stock of The Cincinnati Gas & Electric Company (CG&E) and PSI Energy, Inc. (PSI), both of which are public utility subsidiaries. As a result of this ownership, we are considered a utility holding company. Because we are a holding company whose utility subsidiaries operate 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 (PUHCA). Our other direct subsidiaries are:
•Cinergy Services, Inc. (Services);
•Cinergy Investments, Inc. (Investments); and
•Cinergy Global Resources, Inc. (Global Resources).
CG&E, an Ohio corporation, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through its subsidiaries, in nearby areas of Kentucky and Indiana. It has five wholly-owned utility subsidiaries and one wholly-owned non-utility subsidiary. CG&E's principal utility subsidiary, The Union Light, Heat and Power Company (ULH&P), is a Kentucky corporation that provides electric and gas service in northern Kentucky. CG&E's other subsidiaries are insignificant to its results of operations.
PSI, an Indiana corporation, is an electric utility that provides service in north central, central, and southern Indiana.
The following table presents further information related to the operations of our domestic utility companies (our operating companies):
Services is a service company that provides our regulated and non-regulated subsidiaries with a variety of centralized administrative, management, and support services. Investments holds most of our domestic non-regulated businesses and investments. Global Resources primarily holds our international businesses and investments.
The majority of our operating revenues are derived from the sale of electricity and the sale and/or transportation of natural gas.
We conduct operations through our subsidiaries, and we manage through the following four business units:
•Energy Commodities Business Unit (Commodities);
•Energy Delivery Business Unit (Delivery);
•Cinergy Investments Business Unit (Cinergy Investments); and
•International Business Unit (International).
See Note 15 on page 137 for financial information by business unit.
(b) Presentation We use two different methods to report investments in subsidiaries or other companies: the consolidation method or the equity method. Additionally, we use estimates and have reclassified certain amounts in the preparation of the financial statements.
Consolidation Method We use consolidation when we own a majority of the voting stock of or have the ability to control the subsidiary. 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.
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% to 50% ownership). Under the equity method, we report:
•our investment in the entity as Investments in unconsolidated subsidiaries in our Consolidated Balance Sheets, on page 74; and
•our percentage share of the earnings from the entity as Equity in earnings of unconsolidated subsidiaries in our Consolidated Statements of Income, on page 73.
Use of Estimates Management makes estimates and assumptions when preparing financial statements under generally accepted accounting principles. Actual results could differ, as these estimates and assumptions involve judgment. 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.
Reclassifications We have reclassified certain prior-year amounts in the financial statements of Cinergy, CG&E, PSI, and ULH&P for comparative purposes.
(c) Regulation Our operating companies and certain of our non-utility subsidiaries must comply with the rules prescribed by the SEC under the PUHCA. Our operating companies must also comply with the rules prescribed by the Federal Energy Regulatory Commission (FERC) and the state utility commissions of Ohio, Indiana, and Kentucky.
Our operating companies use the same accounting policies and practices for financial reporting purposes as non-regulated companies under generally accepted accounting principles. 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 Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (Statement 71).
In accordance with Statement 71, we record regulatory assets and liabilities (that is, expenses deferred for future recovery from customers or obligations to be refunded to customers) on our Balance Sheets.
Our regulatory assets and amounts authorized for recovery through regulatory orders at December 31, 1999, and 1998, are as follows:
(1)Includes $11 million at December 31, 1999, and $11 million at December 31, 1998, related to ULH&P (for deferred merger costs, unamortized costs of reacquiring debt and other regulatory assets). Of these amounts, $4 million at December 31, 1999, and $4 million at December 31, 1998, have been authorized for recovery.
(2)The various regulatory commissions overseeing the regulated business operations of our 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 and PSI and a regulatory liability for ULH&P.
(3)PSI reached an agreement with Dynegy, Inc. (Dynegy) to purchase the remainder of its 25-year contract for coal gasification services. In accordance with an order from the Indiana Utility Regulatory Commission (IURC), PSI will begin recovering this asset over an 18-year period upon termination of the gas services agreement in 2000.
(4)In August 1996, PSI entered into a coal supply agreement, which expires December 31, 2000. The agreement provides for a buyout charge, which is being recovered through the fuel adjustment clauses through December 2002.
(5)In accordance with an order from the Public Utilities Commission of Ohio (PUCO), CG&E is recovering this asset over a seven-year period, which began in May 1995.
(6)At December 31, 1999, these amounts are being recovered through rates charged to customers over a period ranging from 1 to 28 years for CG&E, 1 to 32 years for PSI, and 3 to 21 years for ULH&P.
Based on regulatory authority and the regulatory environment in which we currently operate, we believe that we continue to meet the requirements of Statement 71.
Comprehensive electric deregulation legislation was passed in Ohio on July 6, 1999. As required by the legislation, CG&E filed its Proposed Transition Plan (Transition Plan) for approval by the PUCO on December 28, 1999. While CG&E believes there is sound basis for the various requests made in its Proposed Transition Plan, it is currently unable to predict the extent to which the Proposed Transition Plan will be approved and its resulting effect on results of operations, cash flows, and financial position. CG&E is seeking to recover all generation-related regulatory assets and above-market generation costs as allowable transition costs. CG&E believes its current accounting for regulatory assets discussed above has been consistent with the regulatory orders issued by the PUCO and that such costs should be recovered in future rates. However, to the extent requested recovery of generation-related regulatory assets is disallowed or generating assets are financially impaired, CG&E will be required to recognize a loss under generally accepted accounting principles. With regard to these assets, CG&E will continue to apply Statement 71 until the effect of deregulation is estimable.
(d) Statements of Cash Flows We define Cash equivalents as investments with maturities of three months or less when acquired. See Note 18 for information concerning non-cash financing transactions.
(e) Operating Revenues and Fuel Costs Our operating companies record Operating revenues for electric and gas service, including unbilled revenues and the associated expenses, when they provide the service to the customers. The associated expenses include:
•the fuel used to generate electricity;
•electricity purchased from others; and
•natural gas purchased from others.
These expenses are shown in our Statements of Income as Fuel and purchased and exchanged power and Gas purchased. Any portion of these costs that are recoverable or refundable to customers in future periods is deferred in either Accounts receivable or Accounts payable in our Balance Sheets.
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.
(f) Utility Plant Utility plant includes the utility business property and equipment that is in use, being held for future use, or under construction. We report our utility plant at its original cost, which includes:
•material;
•salaries;
•payroll taxes;
•fringe benefits;
•an allowance for funds used during construction (described in (h) below); and
•other miscellaneous amounts.
Most of our operating companies' utility property serves as collateral under each company's first mortgage bond indenture.
(g) Depreciation and Maintenance 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 (the number of years we expect to be able to use the properties) and the cost to remove the properties. The average depreciation rates for utility plant, excluding software, are discussed in the table below.
(h) Allowance for Funds Used During Construction Our 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. The Allowance for Funds Used During Construction (AFUDC) is calculated using a methodology authorized by the regulatory authorities. AFUDC rates are compounded semi-annually and are as follows:
The borrowed funds component of AFUDC, which is recorded on a pre-tax basis, is as follows:
(i) Federal and State Income Taxes Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, requires us to report revenues and expenses differently for financial reporting than for income tax return purposes. The tax effects of these differences are reported as deferred income tax assets or liabilities in our Balance Sheets and are based on current income tax rates in effect.
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.
(j) Energy Marketing and Trading We market and trade electricity, natural gas, and other energy-related products. We designate transactions as physical or trading at the time they are originated. Physical refers to our intent and projected ability to fulfill obligations from company-owned assets. We sell generation to third parties when it is not required to meet native load requirements (end-use customers within our operating companies' franchise service territory). We account for physical transactions on a settlement basis and trading transactions using the mark-to-market method of accounting. Under the mark-to-market method of accounting, trading transactions are shown at fair value in our Consolidated Balance Sheets as Energy risk management assets-and Energy risk management liabilities-current and long-term. We reflect changes in fair value resulting in unrealized gains and losses in Fuel and purchased and exchanged power and Gas purchased. We record the revenues and costs for all transactions in our Consolidated Statements of Income when the contracts are settled. We recognize revenues in Operating revenues; costs are recorded in Fuel and purchased and exchanged power and Gas purchased. Prior to December 31, 1998, we accounted for and valued trading transactions at the aggregate of lower of cost or market. Under this method, only the net value of the trading portfolio is recorded as a liability in our Consolidated Balance Sheets.
Although we intend to settle physical contracts with company-owned generation, there are times when we have to settle these contracts with power purchased 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 the power is delivered. Open market purchases may occur for the following reasons:
•generating station outages;
•least-cost alternative;
•native load requirements; and
•extreme weather.
We value contracts in the trading portfolio using end of the period market prices, utilizing the following factors (as applicable):
•closing exchange prices (that is, closing prices for standardized electricity 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 pricing underlying any options and contractual commitments).
We anticipate that some of these obligations, even though considered trading contracts, will ultimately be settled using company-owned generation. The cost of this generation is usually below the market price at which the trading portfolio has been valued.
We expect earnings volatility from period to period due to the risks associated with marketing and trading electricity, natural gas, and other energy-related products.
Commodities, through Cinergy Marketing & Trading, LLC (Marketing & Trading), and International, through Cinergy Global Trading Limited, market and trade natural gas and other energy-related products. For physical gas sales, transactions are recorded when the contracts are settled, due to the exchange of title to the natural gas throughout the earnings process. Energy risk management assets and liabilities, as well as gross margins from trading activities are recorded in our consolidated financial statements.
(k) Financial Derivatives We use derivative financial instruments to manage: (1) funding costs; (2) exposures to fluctuations in interest rates; and (3) exposures to foreign currency exchange rates. These financial instruments must be designated as a hedge (for example, an offset of foreign exchange or interest rate risks) at the inception of the contract and must be effective at reducing the risk associated with the underlying instrument. An underlying instrument is one that gives rise to the derivative financial instrument. Accordingly, changes in the market values of instruments designated as hedges must be highly correlated with changes in the market values of the underlying instrument.
From time to time, we may utilize foreign exchange forward contracts (for example, a contract obligating one party to buy, and the other to sell, a specified quantity of a foreign currency for a fixed price at a future date) and currency swaps (for example, a contract whereby two parties exchange principal and interest cash flows denominated in different currencies) to hedge certain of our net investments in foreign operations. Accordingly, any translation gains and losses are recorded in Accumulated other comprehensive income (loss), which is a component of Common stock equity. Aggregate translation losses related to these instruments are reflected net in Current liabilities in our Consolidated Balance Sheets. At December 31, 1999, no such instruments were held.
We also use interest rate swaps (an agreement by two parties to exchange fixed-interest rate cash flows for floating-interest rate cash flows). We use the accrual method to account for these interest rate swaps. Accordingly, gains and losses are calculated based on the difference between the fixed-rate and the floating-rate interest amounts, using agreed upon principal amounts. These gains and losses are recognized in our Consolidated Statements of Income as a component of Interest over the life of the agreement.
(l) Accounting Changes During the second quarter of 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
(Statement 133). This standard requires companies to record derivative instruments as assets or liabilities, measured at fair value. Changes in the derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Hedges are transactions entered into for the purpose of reducing exposure to one or more types of business risk. Gains and losses on derivatives that qualify as hedges can offset related results on the hedged item in the income statement.
This standard, as subsequently amended by Statement of Financial Accounting Standards No. 137, Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133 (Statement 137), is effective for fiscal years beginning after June 15, 2000. The purpose of Statement 137 was to delay the effective date of Statement 133 by one year. We expect to reflect the adoption of this standard in financial statements issued beginning in the first quarter of 2001. In recognition of the complexity of this new standard, the Derivatives Implementation Group has been formed by the FASB. In preparation for our implementation of this new standard, we have formed a cross-functional project team. The project team is identifying and analyzing all contracts which could be subject to the new standard, developing required documentation, defining relevant processes and information systems needs, and promoting internal awareness of the requirements and potential effects of the new standard. While we continue to analyze and follow the development of implementation guidelines, at this time we are unable to predict whether the implementation of this accounting standard will be material to our results of operations and financial position. However, the adoption of Statement 133 could increase volatility in earnings and other comprehensive income.
(m) Translation of Foreign Currency We translate the assets and liabilities of foreign subsidiaries, whose functional currency (generally that is 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.
(n) Related Party Transactions 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 cost of these services are charged to our operating companies on a direct basis, or for general costs which cannot be directly attributed, based on predetermined allocation factors, including the following:
•sales ratio;
•electric peak load ratio;
•number of employees ratio;
•number of customers ratio;
•construction expenditures ratio; and
•other statistical information ratios.
These costs were as follows for the years ended December 31:
At December 31, 1999, and 1998, the Balance Sheets of our operating companies included the following amounts payable to Services:
2. Common Stock
(a) Changes In Common Stock Outstanding The following table reflects selected information related to our shares of common stock reserved for stock-based plans.
We retired 31,777 shares of common stock in 1999; 44,981 shares in 1998; and 304 shares in 1997, mainly representing shares tendered as payment for the exercise of previously granted stock options.
Cinergy Corp. owns all of the common stock of CG&E and PSI. All of ULH&P's common stock is held by CG&E.
(b) Dividend Restrictions Cinergy Corp.'s ability to pay dividends to common stock shareholders is principally dependent on the ability of CG&E and PSI to pay Cinergy Corp. common dividends. CG&E and PSI cannot purchase or otherwise acquire for value or pay dividends on their common stock if preferred stock dividends are in arrears. The amount of common stock dividends that each company can pay also is limited by certain capitalization and earnings requirements under CG&E'sand PSI's credit 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 seven stock-based compensation plans:
•LTIP;
•Stock Option Plan;
•Employee Stock Purchase and Savings Plan;
•Sharesave Scheme;
•Retirement Plan for Directors;
•Directors' Equity Compensation Plan; and
•Directors' Deferred Compensation Plan.
In the sections below, we will further discuss the LTIP, the Stock Option plan, and the Employee Stock Purchase and Savings Plan. The activity in 1999 for the remaining stock-based compensation plans was not significant.
We account for our stock-based compensation plans under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB 25). Under APB 25, stock option-type awards are recorded at intrinsic value. In 1999, we recognized a $7 million reduction in compensation cost, before income taxes, in the Consolidated Statements of Income related to our stock-based compensation plans. This reduction was a result of our revised estimates for the performance-based shares accrued under the LTIP plan for cycle I. For further discussion see section (i) below. For 1998, and 1997, we recognized compensation cost related to stock-based compensation plans, before income taxes, of $1 million and $6 million, respectively, in the Consolidated Statements of Income.
Net income for 1999, 1998 and 1997, assuming compensation cost for these plans had been determined at fair value, consistent with the provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (Statement 123), would have been unchanged for 1999, reduced by $3 million for 1998, and reduced by $2 million for 1997. Earnings per share (EPS) would have been reduced by $.02 basic and $.03 diluted for 1998, and $.02 basic and $.01 diluted for 1997.
In estimating the pro forma amounts, the fair value method of accounting was not applied to options granted prior to January 1, 1995. This is in accordance with the provisions of Statement 123. As a result, the pro forma effect on net income and EPS may not be representative of future years. In addition, the pro forma amounts reflect certain assumptions used in estimating fair values. These fair value assumptions are described under each applicable plan discussion below.
(i) LTIP The LTIP was originally adopted in 1996. Under this plan, certain key employees may be granted stock options and the opportunity to earn performance-based shares. For each performance cycle, stock options are granted to participants at fair market value on the date of grant. The number of shares of common stock to be awarded under the LTIP is limited to a total of 7,000,000 shares.
LTIP stock option activity for 1999, 1998, and 1997 is summarized as follows:
The weighted average fair value of options granted was $2.57 in 1999, $4.68 in 1998, and $3.54 in 1997. The fair values of options granted were estimated as of the date of grant using a Black-Scholes
option-pricing model. The weighted averages for the assumptions used in determining the fair values of options granted were as follows:
Price ranges, along with certain other information, for the options outstanding under the LTIP at December 31, 1999, are as follows:
In January 2000, approximately 1.2 million stock options at $24.38 per share were granted under the LTIP.
Entitlement to performance based shares is based on Cinergy's Total Shareholder Return (TSR) over designated performance cycles as measured against a peer group. In January 2000, a target grant of performance based shares was made for the following periods, which are structured to phase-in during three overlapping performance cycles.
Potential awards for cycles II and III are prorated for the length of the cycle. Participants may earn additional performance shares if Cinergy's TSR exceeds that of the peer group. No shares were earned in Cycle I (1997 - 1999).
(ii) Stock Option Plan The Stock Option Plan is designed to align executive compensation with shareholder interests. Under the Stock Option Plan, incentive and non-qualified stock options, stock appreciation rights (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 issuance of stock options. Options are granted at the fair market value of the shares on the date of grant. Options generally vest over five years at a rate of 20% per year, beginning on the date of grant, and expiring 10 years from the date of grant. The total number of shares of common stock available under the Stock Option Plan may not exceed 5,000,000 shares. No stock options may be granted under the plan after October 24, 2004.
Stock Option Plan activity for 1999, 1998, and 1997 is summarized as follows:
The weighted average fair value of options granted during 1999 was $2.40 and $4.53 in 1998. The fair values of options granted were estimated as of the date of grant using a Black-Scholes option-pricing model. The weighted averages for the assumptions used in determining the fair values of options granted in 1999 and 1998 (no options were granted during 1997), were as follows:
Price ranges, along with certain other information, for options outstanding under the Stock Option Plan at December 31, 1999, are as follows:
(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% 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 third (current) offering period began March 1, 1999, and ends April 30, 2001. The purchase price for all shares under this offering is $27.73. The second offering period ended February 28, 1999. At the end of the second offering of the Plan, the market price was below the established share price; therefore in accordance with the Plan provisions, all participants in the Plan at February 28, 1999, were distributed cash funds in March 1999. The total number of shares of common stock available under the Employee Stock Purchase and Savings Plan may not exceed 2,000,000.
Employee Stock Purchase and Savings Plan activity for 1999, 1998, and 1997 is summarized as follows:
The weighted average fair value of options granted was $3.97 in 1999, and $3.08 in 1997. The fair values of options granted were estimated as of the date of grant using a Black-Scholes option-pricing model. The weighted averages for the assumptions used in determining the fair values of options granted were as follows:
(d) Director, Officer and Key Employee Stock Purchase Program In December 1999, Cinergy Corp. adopted the Director, Officer and Key Employee Stock Purchase Program (the Program). The purpose of the Program is to facilitate the purchase of Cinergy Corp.'s common stock by its directors, officers and key employees, thereby further aligning their interests with those of its shareholders.
In February 2000, Cinergy Corp. purchased approximately 1.6 million shares of common stock on behalf of the participants at an average price of $24.82 per share.
Participants had the option of financing the purchases through a five-year credit facility arranged by Cinergy Corp. with a bank. Each participant is obligated to repay the bank any loan principal, interest, and prepayment fees, and each has assigned his or her dividend rights on the purchased shares to the bank to be applied to interest payments as due on the loan.
Services, and in part, Cinergy Corp., have guaranteed repayment to the bank of 100% of each participant's loan obligations and the associated interest, and each participant has agreed to indemnify the guarantor for any payments made by it under the guaranty on the participant's behalf. A participant's obligations to the bank are unsecured, and no restrictions are placed on the participant's ability to sell, pledge or otherwise encumber or dispose of his or her purchased shares.
(e) PSP The PSP was a long-term incentive plan developed to reward officers and other key employees for achieving corporate and individual goals. Under the PSP, participants were granted contingent shares of common stock. As of December 31, 1996, we ceased accrual of incentive
compensation under the PSP, and a final payout of approximately 35,000 shares was made in February 1999.
3. Change in Preferred Stock of Subsidiaries
In 1998, PSI redeemed approximately 3.4 million shares of its $25 par value, 7.44% series of preferred stock for $85 million. All other classes of preferred stock redeemed from 1997 to 1999 were immaterial for CG&E and PSI. Refer to the Consolidated Statements of Capitalization for detailed information for CG&E (on page 84) and PSI (on page 92).
4. Long-Term Debt
Refer to the Statements of Capitalization for detailed information for CG&E (on page 84), PSI (on page 92), and ULH&P (on page 99). In addition, Cinergy Corp. and Global Resources also have the following total long-term debt (excluding Long-term debt due within one year, which is reflected in Current liabilities in the Consolidated Balance Sheets):
The following table reflects the long-term debt maturities for the next five years, excluding any redemptions due to the exercise of call or put provisions. Callable means the issuer has 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.
(1)CG&E and subsidiaries include ULH&P's $20 million maturing in 2003.
Maintenance and replacement fund provisions contained in PSI's first mortgage bond indenture require: (1) cash payments, (2) bond retirements, or (3) pledges of unfunded property additions each year based on an amount related to PSI's net revenues.
5. Notes Payable and Other Short-term Obligations
Short-term obligations may include:
•short-term notes;
•commercial paper;
•variable rate pollution control notes; and
•money pooling.
Short-term Notes Short-term borrowings mature within one year from the date of issuance. We mainly use unsecured revolving lines of credit for short-term borrowings. A portion of each company's committed lines is used to provide credit support for commercial paper (discussed below) and other uncommitted lines. When committed lines are reserved for commercial paper or other uncommitted lines, they are not available for additional borrowings. The fees we paid to secure short-term notes were immaterial during the period from 1997 to 1999.
At December 31, 1999, Cinergy Corp. did not have any borrowings or commercial paper outstanding related to its $645 million revolving and uncommitted lines. The acquisition line shown in the table to follow was initially established to fund the purchase of Avon Energy Partners Holdings (Avon Energy), the parent company of Midlands Electricity plc (Midlands). However, on July 15, 1999, we sold our 50% ownership interest in Avon Energy to GPU, Inc. (GPU), and as a result of this transaction, the available acquisition line has been eliminated. For a discussion of this transaction, see Note 10 on page 126.
Global Resources established a $100 million revolving credit agreement in 1998, which expired on August 29, 1999, and was not extended or replaced.
Commercial Paper The commercial paper (debt instruments exchanged between companies) program is limited to a maximum outstanding principal amount of $400 million for Cinergy Corp. CG&E and PSI also have the capacity to issue commercial paper, which must be supported by available committed lines of the respective company. The maximum outstanding principal amount for CG&E is $200 million and for PSI is $100 million. Neither CG&E nor PSI issued commercial paper in 1999 or 1998.
Variable Rate Pollution Control Notes CG&E and PSI have issued variable rate pollution control notes (tax-exempt notes obtained to finance equipment or land development to control pollution). Because the holders of these notes have the right to redeem their notes on any business day, they are reflected in Notes payable and other short-term obligations in the Consolidated Balance Sheets for Cinergy on page 74, for CG&E on page 80, and for PSI on page 88.
The following tables summarize our Notes payable and other short-term obligations; but exclude Notes payable to affiliated companies.
Cinergy
(1)Excess over Established Line represents amount sold by dealers to other investors.
(2)Does not include a $150 million revolving line established by one of our non-utility unconsolidated subsidiaries. There were no borrowings under this line at December 31, 1999.
CG&E
PSI
Money Pool Our operating companies and their subsidiaries participate in a money pool arrangement to better manage cash and working capital requirements. Under this arrangement, our operating companies and their subsidiaries with surplus short-term funds provide short-term loans to each other. This surplus cash may be from internal or external sources. The amounts outstanding under this money pool arrangement are shown as Notes receivable from affiliated companies or Notes payable to affiliated companies on the Consolidated Balance Sheets for CG&E on pages 80 through 81, PSI on pages 88 through 89, and the Balance Sheets for ULH&P on pages 95 through 96.
6. Sale of Accounts Receivable
In 1996, CG&E, PSI, and ULH&P entered into an agreement to sell, on a revolving basis, undivided percentage interests in certain of their accounts receivable up to an aggregate maximum of $350 million. The Accounts receivable on the Consolidated Balance Sheets of Cinergy, CG&E, and PSI and on the Balance Sheets of ULH&P are net of the amounts sold at December 31, 1999, and 1998. The following table shows the amounts sold, net of reserves for 1999:
Sale of Accounts Receivable
(in millions)
7. Leases
(a) Operating Leases We have entered into operating lease agreements for various facilities and properties such as computer, communications, transportation equipment, and office space. Total rental payments on operating leases for each of the past three years are detailed below in the 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, 1999:
(1)Estimated Minimum Payments are immaterial.
(b) Capital Leases In February 1999, CG&E, PSI, and ULH &P entered into capital lease arrangements to fund the purchase of gas and electric meters. The terms are for 120 months commencing December 1999, with early buyout options at 48, 72, and 105 months. Since the objective is to own the meters indefinitely, the companies plan to exercise the buyout option at month 105. The lease rate used to determine the monthly payments is 6.06%. The meters are depreciated at the same rate as if they were owned by the companies. CG&E, PSI, and ULH&P each recorded a capital lease obligation, included in Non-current liabilities-other. The total minimum lease payments, as if the buyout option is exercised at month 105, and the present value are shown below:
(1)Annual Minimum Lease Payments are immaterial.
In 1996, CG&E entered into a sale-leaseback agreement for certain equipment at Woodsdale Generating Station. The lease is a capital lease with an initial lease term of five years. At the end of this term, the lease may be renewed at mutually agreeable terms or CG&E may purchase the equipment at the original sale amount. The monthly lease payment is interest only and is based on the applicable London Inter-bank Offered Rate (LIBOR). LIBOR is the rate at which the highest rated banks offer to lend to one another. Interest rates are frequently quoted as a spread to LIBOR. The capital lease obligation will not be reduced over the initial lease term. The equipment under the capital lease is depreciated at the same rate as if CG&E owned it. CG&E recorded a capital lease obligation, included in Non-current liabilities-other, of $22 million, which is the book value of the equipment at the beginning of the lease.
8. Financial Instruments
(a) Financial Derivatives We have entered into financial derivative contracts for the purposes described below.
(i) Interest Rate Risk Management Our current policy in managing exposure to fluctuations in interest rates is to maintain 25% of the total amount outstanding debt in floating interest rate debt instruments. To help maintain this level of exposure, we have previously entered into interest rate swaps. Under these swaps, we have agreed with other parties to exchange, at specified intervals, the
difference between fixed-rate and floating-rate interest amounts calculated on an agreed notional principal amount. When less than 25% of the outstanding debt had floating interest rates, we entered into swaps whereby we would receive a fixed rate and pay a floating rate. When more than 25% of the outstanding debt had fixed interest rates, we entered into swaps that allowed us to receive a floating rate while paying a fixed rate. At December 31, 1999, the composition of the total amount of debt outstanding consisted of slightly less than 25% of the outstanding amount having floating interest rates. PSI has an outstanding interest rate swap agreement that will increase this percentage of floating rate debt in the second half of 2000. Under the agreement, which has a notional amount of $100 million, PSI will pay a floating rate and receive a fixed rate for a six month period. The floating rate will be based on a short-term money market index. At December 31, 1999, the fair value of this interest rate swap was not significant. In the future, we will continually monitor market conditions to evaluate whether to increase, or decrease, our level of exposure to fluctuations in interest rates.
(ii) Foreign Exchange Hedging Activity From time to time, we may utilize foreign exchange forward contracts and currency swaps to hedge certain of our net investments in foreign operations. These contracts and swaps allow us to hedge our position against currency exchange rate fluctuations.
Exposure to fluctuations in exchange rates between the U.S. dollar and the currencies of foreign countries where we have investments do exist. When it is appropriate we will hedge our exposure to cash flow transactions, such as a dividend payment by one of our foreign subsidiaries. At December 31, 1999, we do not believe we have a material exposure to the currency risk attributable to these investments.
(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):
The following methods and assumptions were used to estimate the fair values of each major class of instruments:
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.
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 losses 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.
Our concentration of credit risk with respect to Delivery's 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 Commodities' power marketing and trading operations are primarily with the traditional electric cooperatives and municipalities and other investor-owned utilities. At December 31, 1999, we do not believe we have significant exposure to credit risk with our trade accounts receivable within Delivery and our physical portfolio within Commodities.
Contracts within the trading portfolio of the power marketing and trading operations are primarily with power marketers and other investor-owned utilities. As of December 31, 1999, approximately 75% of the activity within the trading portfolio represents commitments with 10 counterparties. The majority of these contracts are for terms of one year or less. Counterparty credit exposure within the power-trading portfolio is routinely factored into the mark-to-market valuation. As a result of the extreme volatility experienced in the Midwest power markets during 1998, several new entrants into the market experienced financial difficulties and failed to perform their contractual obligations. This resulted in us recording bad debt provisions of approximately $13 million with respect to settled transactions. At December 31, 1999, our exposure to credit risk within the power-trading portfolio is not believed to be significant. As the competitive electric power market continues to develop, counterparties will increasingly include new market entrants, such as other power marketers, brokers, and commodity traders. This increased level of new market entrants, as well as competitive pressures on existing market participants, could increase Commodities' exposure to credit risk with respect to its power marketing and trading operations.
As of December 31, 1999, approximately one-third of the activity within the physical gas marketing and trading portfolio represents commitments with 10 counterparties. Credit risk losses related to gas and other commodity physical and trading operations have not been significant. At December 31, 1999, the credit risk within the gas and commodity trading portfolios is not believed to be significant because of the characteristics of counterparties and customers with which transactions are executed.
Potential exposure to credit risk also exists from our use of financial derivatives such as currency swaps, foreign exchange forward contracts, and interest rate swaps. Because these financial instruments are transacted only with highly rated financial institutions, we do not anticipate nonperformance by any of the counterparties.
9. Pension and Other Postretirement Benefits
We provide benefits to retirees in the form of pensions and other postretirement benefits.
Our defined benefit pension plans cover substantially all United States (U.S.) employees meeting certain minimum age and service requirements. A final average pay formula determines plan benefits. These plan benefits are based on (1) years of participation, (2) age at retirement, and (3) the applicable average Social Security wage base or benefit amount.
Effective January 1, 1998, we reconfigured our defined benefit pension plans. The reconfigured plans cover the same employees as the previous plans and established a uniform final average pay
formula for all employees. The reconfiguration of the pension plans did not have a significant impact on our financial position or results of operations.
Our pension plan funding policy for U.S. employees is to contribute at least the amount required by the Employee Retirement Income Security Act of 1974, and up to the amount deductible for income tax purposes. The pension plans' assets consist of investments in equity and fixed income securities.
We provide certain health care and life insurance benefits to retired U.S. employees and their eligible dependents. These benefits are subject to the retiree meeting 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. Prior to January 1, 1997, CG&E and PSI employees had separate postretirement benefit plans. Effective January 1, 1997, most of our active U.S. employees are eligible to receive essentially the same postretirement health care benefits. Certain classes of employees (based on age) and all retirees have been grandfathered under benefit provisions in place prior to January 1, 1997. CG&E does not pre-fund its obligations for these postretirement benefits. During 1999, PSI began pre-funding its obligations as authorized by the IURC through a grantor trust.
Our benefit plans' costs for the past three years, as well as the actuarial assumptions used in determining these costs, included the following components:
For measurement purposes, we assumed an 8% annual rate of increase in the per capita cost of covered health care benefits for 2000. It was assumed that the rate would decrease gradually to 5% in 2008 and remain at that level thereafter.
The following table provides a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two-year period ended December 31, 1999, and a statement of the funded status as of December 31 of both years.
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:
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.
The pension benefit obligations and pension cost under these plans were as follows:
10. Investments/Dispositions in Unconsolidated Subsidiaries
On July 15, 1999, we sold our 50% ownership interest in Avon Energy to GPU. In exchange for our interest in Avon Energy, we received 452.5 million pounds sterling (approximately $700 million). As a result of the transaction, we realized a net contribution to earnings of approximately $.43 per share (basic and diluted), after deducting financing, transaction, and currency costs.
Pro forma information is presented below. This reflects the net income and earnings per share without the investment in Avon Energy for 1999 and 1998.
(1)Represents basic earnings per share. Diluted earnings per share were $2.53, and pro forma diluted earnings per share were $1.93.
(2)Both basic and diluted.
On September 30, 1999, one of our non-regulated subsidiaries formed a partnership with Duke Energy North America LLC (Duke). This partnership will jointly construct and own three wholesale generating facilities located in southwestern Ohio, and east central and western Indiana, with total capacity of approximately 1,400 megawatts (MW). These facilities will be natural gas-fired peaking stations with commercial operations anticipated for the summer of 2000. Our portion (50%) of the output will be sold to and marketed by Cinergy Capital & Trading (a wholly-owned subsidiary of Investments) or another Cinergy affiliate.
11. Income Taxes
The following table shows the significant components of Cinergy, CG&E, and PSI net deferred income tax liabilities as of December 31, 1999, and 1998:
(1)Cinergy's net deferred income tax liability does not equal the sum of the net deferred income tax liabilities of CG&E and PSI because of foreign subsidiary activity included at the Cinergy and other subsidiaries' level.
We will file a consolidated federal income tax return for the year ended December 31, 1999. The current tax liability is allocated among the members of the group pursuant to a tax sharing agreement filed with the SEC under the PUHCA.
The following table indicates a summary of federal and state income taxes charged (credited) to income:
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 extraordinary items and federal income tax) to the federal income tax expense reported in the Consolidated Statements of Income for Cinergy, CG&E, and PSI.
The following table shows the significant components of ULH&P net deferred income tax liability as of December 31, 1999, and 1998:
The following table indicates a summary of federal and state income taxes charged (credited) to income:
The following table presents a reconciliation of federal income taxes (which are calculated by multiplying the statutory federal income tax rate by book income and federal income tax) to the federal income tax expense reported in the Statement of Income for ULH&P.
12. Commitments and Contingencies
(a) Construction and Other Commitments Forecasted construction expenditures in nominal dollars for 2000 and for the next five years (2000-2004) are presented in the table below:
This table includes forecasted expenditures for 2000 of $65 million for preparing utility systems for customer choice. This forecast excludes an estimate of expenditures necessary to comply with the United States Environmental Protection Agency's (EPA's) proposed stricter nitrogen oxide (NOX) emission control standards, as discussed below.
Committed projects for both international and domestic non-regulated investment activities of approximately $160 million for 2000 are excluded from the table above. On September 30, 1999, one of our non-regulated subsidiaries formed a partnership with Duke, as discussed in Note 10 on page 126. Our portion (50%) of the remaining capital expenditures to complete this project is estimated at $110 million for 2000 and is included in the $160 million discussed above.
(b) Ozone Transport Rulemaking In October 1998, the EPA finalized its ozone transport rule, also known as the NOX SIP Call. (A SIP is a state's implementation plan for achieving emissions reductions to address air quality concerns.) It applies to 22 states in the eastern half of the U.S., including the three states in which our electric utilities operate. This rule recommends that states reduce NOX emissions from primarily industrial and utility sources to a certain level by May 2003. The EPA gave the affected states until September 30, 1999, to incorporate NOX reductions with a trading program into their SIPs. The EPA proposed to implement a federal plan to accomplish the equivalent NOX reductions by May 2003 if the states failed to revise their SIPs. The EPA must approve all SIPs.
Ohio, Indiana, a number of other states, and various industry groups (some of which we are a member), filed legal challenges to the NOX SIP Call in late 1998. On May 25, 1999, the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals) granted a request for a deferral of the rule and indefinitely suspended the September 30 filing deadline, pending further review by the Court of Appeals. The Court of Appeals heard arguments on the case on November 9, 1999, and is expected to make a decision in the first quarter of 2000.
In December 1999, the EPA granted four Section 126 petitions relating to NOX emissions. The EPA believes that these petitions, which are filed under Section 126 of the Clean Air Act (CAA), allow a state to claim that another state is contributing to its air quality problem and request that the EPA require the upwind state to reduce its emissions. This ruling affects all of our Ohio and Kentucky facilities, as well as some of our Indiana facilities, and requires us to reduce our NOX emissions to a certain level by May 2003. We are appealing this ruling; however, we currently cannot predict the outcome of the appeal. Compliance with this EPA finding is anticipated to require us to perform substantially all of the NOX reduction work that would be required under the NOX SIP Call. In the event the EPA successfully implements either program (the NOX SIP Call or the Section 126 petitions), capital expenditures for compliance are substantially the same, and are currently estimated at $500 million to $700 million (in 1999 dollars) by May 2003, approximately $105 million of which is estimated to be spent in 2000. This estimate depends on several factors, including:
•final determination regarding both the timing and strictness of the final required NOX reductions;
•emission output of our generating units;
•availability of adequate supplies of resources to construct the necessary control equipment; and
•whether a viable market will exist to buy and sell NOX allowances.
(c) New Source Review (NSR) Since July 1999, CG&E and PSI have received requests from the EPA (Region 5), under Section 114 of the CAA, seeking documents and information regarding capital and maintenance expenditures at several of their generating stations. These activities are part of an industry-wide investigation assessing compliance with the NSR and the New Source Performance Standards (NSPS, emissions standards that apply to new and changed units) of the CAA at electric generating stations. The NSR provisions require that a company obtain a pre-construction permit if it plans to build a new stationary source of pollution or make a major change to an existing facility unless the changes are exempt.
On November 3, 1999, the EPA sued a number of holding companies and electric utilities, including Cinergy, CG&E, and PSI, in various U.S. District Courts. The Cinergy, CG&E, and PSI suit alleges violations of the CAA at some of our generating stations relating to NSR and NSPS requirements. The suit seeks (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord and PSI's Cayuga Generating Station (Cayuga), and (2) civil penalties in amounts of up to $27,500 per day for each violation.
On March 1, 2000, the EPA filed an amended complaint against Cinergy, CG&E, and PSI. The amended complaint added the alleged violations of the NSR requirements of the CAA at two of our generating stations contained in the notice of violation (NOV) filed by the EPA on November 3, 1999. It also added claims for relief alleging violations of (1) nonattainment NSR, (2) Indiana and Ohio SIPs, and (3) particulate matter emission limits (as discussed in Note 12(e) on page 134). The amended complaint seeks (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord, Cayuga, and PSI's Wabash River and Gallagher Generating Stations, and such other measures as necessary, and (2) civil penalties in amounts of up to $27,500 per day for each violation. We believe the allegations contained in the amended complaint are without merit and plan to defend the suit vigorously in court. At this time, it is not possible to determine the likelihood that the EPA will prevail on its claims or whether resolution of this matter will have a material effect on our financial condition.
On March 1, 2000, the EPA also filed an amended complaint alleging violations of the CAA relating to NSR, Prevention of Significant Deterioration, and Ohio SIP requirements regarding a generating station operated by the Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company, and CG&E. The EPA is seeking injunctive relief and civil
penalties of up to $27,500 per day for each violation. We believe the allegations in the amended complaint are without merit. At this time, it is not possible to determine the likelihood that the EPA will prevail on its claims or whether resolution of this matter will have a material effect on our financial condition.
(d) Manufactured Gas Plant (MGP) Sites
(i) General 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.
(ii) PSI Coal tar residues, related hydrocarbons, and various metals associated with MGP sites have been found at former MGP sites in Indiana, including at least 21 sites which PSI or its predecessors previously owned. PSI acquired four of the sites from Northern Indiana Public Service Company (NIPSCO) in 1931. At the same time, PSI sold NIPSCO the sites located in Goshen and Warsaw, Indiana. In 1945, PSI sold 19 of these sites (including the four sites it acquired from NIPSCO) to the predecessor of the Indiana Gas Company, Inc. (IGC). IGC later sold the site located in Rochester, Indiana, to NIPSCO.
IGC (in 1994) and NIPSCO (in 1995) both made claims against PSI. The basis of these claims was that PSI is a Potentially Responsible Party with respect to the 21 MGP sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The claims further asserted that PSI is therefore legally responsible for the costs of investigating and remediating the sites. In August of 1997, NIPSCO filed suit against PSI in federal court claiming recovery (pursuant to CERCLA) of NIPSCO's past and future costs of investigating and remediating MGP related contamination at the Goshen MGP site.
In November 1998, NIPSCO, IGC, and PSI entered into a Site Participation and Cost Sharing Agreement. The agreement allocated CERCLA liability for past and future costs at seven MGP sites in Indiana among the three companies. As a result of the agreement, NIPSCO's lawsuit against PSI was dismissed. The parties have assigned lead responsibility for managing further investigation and remediation activities at each of the sites to one of the parties. Similar agreements were reached between IGC and PSI that allocate CERCLA liability at 14 MGP sites with which NIPSCO was not involved. These agreements conclude all CERCLA and similar claims between the three companies related to MGP sites. The parties continue to investigate and remediate the sites, as appropriate under the agreements and applicable laws. The Indiana Department of Environmental Management (IDEM) oversees investigation and cleanup of some of the sites.
PSI notified its insurance carriers of the claims related to MGP sites raised by IGC, NIPSCO, and the IDEM. In April 1998, PSI filed suit in Hendricks County Circuit Court in the State of Indiana against its general liability insurance carriers. Among other matters, PSI requested a declaratory judgment that would 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. The case was moved to the Hendricks County Superior Court 1 on a request for a change of judge. The Hendricks County Superior Court 1 has set the case for trial beginning in May 2001. It ordered the parties to meet certain deadlines for discovery proceedings based upon this trial date. PSI cannot predict the outcome of this litigation.
PSI has accrued costs for the sites related to investigation, remediation, and groundwater monitoring for the work performed to date. The estimated costs for such remedial activities are accrued when the costs are probable and can be reasonably estimated. PSI does not believe it can provide an estimate of the reasonably possible total remediation costs for any site before a remedial investigation/feasibility study has been completed. To the extent remediation is necessary, the timing of
the remediation activities impacts the cost of remediation. Therefore, PSI currently cannot determine the total costs that may be incurred in connection with the remediation of all sites, to the extent that remediation is required. According to current information, these future costs at the 21 Indiana MGP sites are not material to our financial condition or results of operations. As further investigation and remediation activities are performed at these sites, the potential liability for the 21 MGP sites could be material to our financial position or results of operations.
(iii) CG&E CG&E and its utility subsidiaries are aware of potential sites where MGP activities have occurred at some time in the past. None of these sites is known to present a risk to the environment. CG&E and its utility subsidiaries have begun preliminary site assessments to obtain information about some of these MGP sites.
(e) Other On November 30, 1999, the EPA filed a NOV against Cinergy and CG&E because emissions of particulate matter (very small solid particles in the air) at CG&E's W.C. Beckjord Generating Station exceeded the allowable limit. The NOV indicated that the EPA may (1) issue an administrative penalty order, or (2) file a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. The allegations contained in this NOV were incorporated within the March 1, 2000, amended complaint, as discussed in Note 12(c) on page 132. We are currently unable to determine whether resolution of this matter will have a material effect on our financial condition.
13. Jointly-Owned Plant
CG&E, CSP, and DP&L jointly own electric generating units and related transmission facilities. PSI is also a joint-owner of Gibson Generating Station (Gibson) Unit 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 Consolidated Statements of Income reflect CG&E's and PSI's portions of all operating costs associated with the jointly-owned facilities.
CG&E's and PSI's investments in jointly-owned plant or facilities are as follows:
(1)Station is not operated by CG&E.
14. Quarterly Financial Data (unaudited)
(1)In the third quarter of 1999, we realized a net contribution to earnings of approximately $.43 per share (basic and diluted) when we sold our 50% ownership interest in Avon Energy to GPU. For a discussion of this transaction, see Note 10.
(2)In the third quarter of 1999, through CG&E and PSI, we experienced extreme weather conditions which resulted in a reduction in net income of $57 million ($16 million for CG&E, $41 million for PSI) after tax or $.36 per share (basic and diluted).
(3)In the second quarter of 1998, we recorded charges of $65 million, pretax ($58 million for CG&E and $7 million for PSI) related to power marketing and trading operations which constitutes, after tax, $.26 per share (basic and diluted). For a discussion of the energy marketing and trading operations, see Note 1(j).
(4)In the second quarter of 1998, we, through PSI, recorded a charge against earnings of $80 million ($50 million after tax or $.32 per share basic and diluted) for a settlement related to the Marble Hill nuclear project. For a discussion of this settlement, see Note 18.
(5)In the third quarter of 1998, we recorded charges of $20 million pretax ($(5) million for CG&E and $25 million for PSI) related to power marketing and trading operations which constitutes, after tax, $.08 per share (basic and diluted). For a discussion of the energy marketing and trading operations, see Note 1(j).
(6)In the fourth quarter of 1998, we recorded charges of $50 million, pretax ($20 million for CG&E and $30 million for PSI) related to power marketing and trading operations which constitutes, after tax, $.20 per share (basic and diluted). For a discussion of the energy marketing and trading operations, see Note 1(j).
(7)In the third quarter of 1999, Cinergy's electric margins, through PSI's, were positively impacted by $12 million pretax, or $.07 per share (basic and diluted) after tax, as a result of a change in estimate of PSI's utility services delivered but unbilled at month end.
15. Financial Information by Business Segment
During 1998, we adopted the requirements of Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information (Statement 131). Statement 131 requires disclosures about reportable operating segments in annual and interim condensed financial statements based on the following:
•products and services;
•geography;
•legal structure;
•management structure; or
•any other manner in which management divides a company.
Our business units were initially formed during the second half of 1996 and began operating as separately identifiable business units in 1997. In early 1999, we made certain organizational changes to further align the business units to reflect our strategic vision. Prior years' financial information has been restated to conform with the current year's presentation. Each business unit has its own management structure, headed by a business unit president who reports directly to our chief executive officer. As discussed in Note 1(a) on page 100, our business units are Commodities, Delivery, Cinergy Investments, and International. Each business unit and its responsibilities are described below.
Commodities operates and maintains our domestic electric generating plants and some of our jointly-owned plants. It also conducts the following activities: (1) wholesale energy marketing and trading, (2) energy risk management, (3) financial restructuring services, and (4) proprietary arbitrage activities. Commodities earns revenues from external customers from its marketing, trading, and risk management activities. Commodities earns intersegment revenues from the sale of electric power to Delivery.
Delivery plans, constructs, operates, and maintains our operating companies' transmission and distribution systems and provides gas and electric energy to consumers. Delivery earns revenues from customers other than consumers primarily by transmitting electric power through our transmission system. Delivery currently receives all of its electricity from Commodities at a transfer price based upon current regulatory ratemaking methodology.
Cinergy Investments manages the development, marketing, and sales of our domestic non-regulated retail energy and energy-related products and services. This is accomplished through various subsidiaries and joint ventures. Cinergy Investments earns all of its revenues from the sale of such products and services to ultimate consumers. These products and services include the following:
•energy management and consulting services to commercial customers that operate retail facilities (for example, finding more efficient ways for a customer to use energy);
•utility operations/services to other utilities (for example, providing underground locating and construction services for other utilities); and
•building, operating, and maintaining combined heat and power facilities through joint ventures with Trigen Energy Corporation.
International directs and manages our international business holdings, which include wholly- and jointly-owned companies in six countries. In addition, International also directs our renewable energy investing activities (for example, wind farms) both inside and outside the U.S. International earns (1) revenues, and (2) equity earnings from unconsolidated companies primarily from energy-related businesses.
Financial information by (1) business units, (2) products and services, and (3) geographic areas and long-lived assets for the years ending December 31, 1999, 1998, and 1997, is as follows:
Business Units
(1)The All Other category represents miscellaneous corporate items which are not allocated to business units for purposes of segment profit measurement.
(2)The Reconciling Eliminations category eliminates the intersegment revenues of Commodities.
(3)The components of depreciation and amortization include depreciation of fixed assets, amortization of intangible assets, amortization of phase-in deferrals, and amortization of post-in-service deferred operating expenses.
(4)Interest income is deemed immaterial.
(5)Management utilizes segment profit (loss) after taxes to evaluate segment profitability.
(1)The All Other category represents miscellaneous corporate items which are not allocated to business units for purposes of segment profit measurement.
(2)The Reconciling Eliminations category eliminates the intersegment revenues of Commodities.
(3)The components of depreciation and amortization include depreciation of fixed assets, amortization of intangible assets, amortization of phase-in deferrals, and amortization of post-in-service deferred operating expenses.
(4)Interest income is deemed immaterial.
(5)Management utilizes segment profit (loss) after taxes to evaluate segment profitability.
(1)The All Other category represents miscellaneous corporate items which are not allocated to business units for purposes of segment profit measurement.
(2)The Reconciling Eliminations category eliminates the intersegment revenues of Commodities.
(3)The components of depreciation and amortization include depreciation of fixed assets, amortization of intangible assets, amortization of phase-in deferrals, and amortization of post-in-service deferred operating expenses.
(4)Interest income is deemed immaterial.
(5)Windfall profits tax. (See Note 17.)
(6)Management utilizes segment profit (loss) after taxes to evaluate segment profitability.
Our products and services focus on providing utility services (the supply of electric energy and gas supply) and energy marketing and trading services.
(1)
As discussed in Note 10, on July 15, 1999, we sold our 50% ownership interest in Avon Energy to GPU. Prior to the sale, Midlands had provided the majority of International's earnings.
(2)
We own four district heating plants and have a minoirty interest in a fifth district heating plant in the Czech Republic that, in total, provide 1,480 MW of thermal steam capacity, which may be used to produce 186 MW of electricity. These plants' assets and results of operations are consolidated into our financial statements. International accounts for its remaining long-lived assets as equity method investments. As a result, revenues from International are insignificant.
16. Earnings Per Share
A reconciliation of earnings per common share (basic EPS) to earnings per common share assuming dilution (diluted EPS) is presented below:
Options to purchase shares of common stock are excluded from the calculation of EPS-assuming dilution when the exercise prices of these options are greater than the average market price of the common shares during the period. For 1999 and 1998, approximately two million and one million shares, respectively, were excluded from the EPS-assuming dilution calculation. For 1997, shares excluded from this calculation were immaterial.
17. Extraordinary Item-Equity Share of Windfall Profits Tax
During the third quarter of 1997, a windfall profits tax was enacted into law in Great Britain. This tax was levied against a limited number of British companies, including Midlands, which had previously been owned and operated by the government. The government believed these companies were undervalued at the time of transition to private entities. As a result, the tax was levied and seen as a recovery of funds by the government.
Our share of the tax was approximately 67 million pounds sterling. This translates to $109 million or $.69 per share, basic and diluted. We recorded the tax as an extraordinary item in the 1997 Consolidated Statement of Income. No related tax benefit was recorded for the charge. The windfall profit tax is not deductible for corporate income tax purposes in Great Britain. Also, we expect that any potential benefits derived for U.S. federal income taxes will not be significant.
18. Wabash Valley Power Association Settlement
In February 1989, PSI and WVPA entered into a settlement agreement to resolve all claims related to Marble Hill, a nuclear project canceled in 1984. Implementation of the settlement was contingent on a number of events. During 1998, PSI reached agreement on all matters with the relevant parties and, as a result, recorded a liability to the RUS. PSI will repay the obligation to the RUS with interest over a 35-year term. The net proceeds from a 35-year power sales agreement with WVPA will be used to fund the principal and interest on the obligation to the RUS. Assumption of the liability (recorded as Long-term debt in the Consolidated Balance Sheet) resulted in a charge against earnings of $80 million ($50 million after tax or $.32 per share basic and diluted) in the second quarter of 1998.
19. Ohio Deregulation
On July 6, 1999, Ohio Governor Robert Taft signed Amended Substitute Senate Bill No. 3 (Electric Restructuring Bill), beginning the transition to electric deregulation and customer choice for the state of Ohio. The Electric Restructuring Bill creates a competitive electric retail service market beginning January 1, 2001. The legislation provides for a market development period that begins January 1, 2001, and ends no later than December 31, 2005. Ohio electric utilities have an opportunity to recover Public Utilities Commission of Ohio (PUCO)-approved transition costs during the market development period. CG&E is seeking to recover all generation-related regulatory assets and above-market generation costs as allowable transition costs. The legislation also freezes retail electric rates during the market development period, except for a five percent reduction in the generation component of residential rates and other potential adjustments. Furthermore, the legislation contemplates that twenty percent of the current electric retail customers will switch suppliers no later than December 31, 2003.
The Electric Restructuring Bill has required each utility supplying retail electric service in Ohio to file a comprehensive proposed transition plan with the PUCO addressing specific requirements of the legislation. CG&E filed its plan on December 28, 1999. The PUCO is required to issue a transition order no later than October 31, 2000. Consumers will be allowed to begin selecting alternative electricity suppliers beginning January 1, 2001.
While CG&E believes there is sound basis for the various requests made in its Proposed Transition Plan, it is currently unable to predict the extent to which the Proposed Transition Plan will be approved and its resulting effect on results of operations, cash flows, and financial position. CG&E is seeking to recover all generation-related regulatory assets and above-market generation costs as allowable transition costs. CG&E believes its current accounting for regulatory assets has been consistent with the regulatory orders issued by the PUCO and that such costs should be recovered in future rates. However, to the extent requested recovery of generation-related regulatory assets is disallowed or generating assets are financially impaired, CG&E will be required to recognize a loss under generally accepted accounting principles. With regard to these assets, CG&E will continue to apply Statement 71 until the effect of deregulation is estimable.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
BOARD OF DIRECTORS
Information regarding Cinergy Corp.'s directors is incorporated by reference from its definitive Proxy Statement for the 2000 Annual Meeting of Shareholders.
The directors of The Cincinnati Gas & Electric Company (CG&E) at February 29, 2000, are as follows:
•Jackson H. Randolph-Mr. Randolph, age 69, is Chairman of CG&E, a position he has held since 1995. He has served as a director of CG&E since 1983. His current term as director expires April 26, 2000.
•James E. Rogers-Mr. Rogers, age 52, is Vice Chairman and Chief Executive Officer of CG&E, a position he has held since 1995. He has served as a director of CG&E since 1994. His current term as director expires April 26, 2000.
•James L. Turner-Mr. Turner, age 40, is President of CG&E, a position he has held since 1999. Before joining Cinergy Corp.'s legal department in June 1995, Mr. Turner was a principal in the Indianapolis law firm of Lewis & Kappes, P.C., representing industrial customers in utility regulatory and legislative matters. In March 1997, Mr. Turner was appointed Vice President of Cinergy Services, Inc., having responsibility for the coordination of transition issues across all corporate subsidiaries in the move for full customer choice. From April 1998 to January 2000, he was responsible for Cinergy Corp.'s Government and Regulatory Affairs department. Effective January 2000, he was appointed Vice President of Customer Services. He has served as a director of CG&E since February 15, 1999. His current term as director expires April 26, 2000.
Information regarding PSI Energy, Inc.'s (PSI) directors is incorporated by reference from its 2000 Information Statement.
EXECUTIVE OFFICERS
The information included in Part I of this report on pages 17 through 20 under the caption "Executive Officers" is referenced in reliance upon General Instruction G to Form 10-K and Instruction 3 to Item 401 (b) of Regulation S-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding Cinergy Corp.'s executive compensation is incorporated by reference from its definitive Proxy Statement for the 2000 Annual Meeting of Shareholders.
Information regarding CG&E's executive compensation is incorporated by reference from Cinergy Corp.'s definitive Proxy Statement for the 2000 Annual Meeting of Shareholders, except for the following information regarding the compensation of directors.
Each non-employee director of CG&E is eligible to receive an annual retainer fee of $8,000 plus a fee of $1,000 for each CG&E board of directors' meeting attended. However, any non-employee director of CG&E who also serves as a non-employee director of Cinergy Corp. or any of its affiliates shall not receive the annual retainer fee, or any compensation for attendance at any CG&E board meeting that is held concurrently or consecutively with a meeting of our board of directors. All CG&E directors currently are also employees of Cinergy Corp. and/or its subsidiaries, and receive no compensation for their services as directors.
Under the Directors' Deferred Compensation Plan, each non-employee director of Cinergy Corp. and its subsidiaries may choose to defer his or her fees into a bookkeeping account denominated in either:
•units representing shares of our common stock, and/or
•cash.
If deferred in units, dividends are credited to the director's account, acquiring additional units at the same time and rate as dividends are paid to holders of common stock. Amounts deferred in cash earn interest at the annual rate (adjusted quarterly) equal to the interest rate for a one-year certificate of deposit, as quoted in The Wall Street Journal for the first business day of the calendar quarter. Deferred units are distributed as shares of common stock, and accrued cash accounts are paid in cash, generally after the director retires from the appropriate board.
Effective January 1, 1999, the Retirement Plan for Directors was amended and restated to eliminate the award of future benefits. Each of the non-employee directors with an accrued benefit through December 31, 1998 was permitted to convert it from cash to units representing shares of common stock. If converted to stock units, dividends are credited to the director's account, acquiring additional units at the same time and rate as dividends are paid to holders of our common stock. A director's account is distributed as shares of common stock after he or she retires from the appropriate board. Each non-employee director of Cinergy Corp. and/or its subsidiaries who retired before January 1, 1999, or who chose not to convert the cash benefit, will receive an annual cash payment equal to the fees in effect at the time of retirement from the appropriate board.
Information regarding PSI's executive compensation is incorporated by reference from its 2000 Information Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding Cinergy Corp.'s security ownership of certain beneficial owners and management is incorporated by reference from its definitive Proxy Statement for the 2000 Annual Meeting of Shareholders.
Cinergy Corp. owns all outstanding shares of common stock of CG&E, CG&E's only voting security. Pursuant to Section 13(d) of the Securities Exchange Act of 1934, a beneficial owner of a security is any person who directly or indirectly has or shares voting or investment power over such security. No person or group is known by the management of CG&E to be the beneficial owner of more than 5% of CG&E's class of cumulative preferred stock as of December 31, 1999.
CG&E's directors and executive officers did not beneficially own shares of any series of the class of CG&E's cumulative preferred stock as of February 28, 1999. The beneficial ownership of Cinergy Corp. common stock held by each director and named executive officer as of February 29, 2000, is set forth in the following table:
(1)No individual listed beneficially owned more than 0.464% of the outstanding shares of our common stock.
(2)Includes shares which there is a right to acquire within 60 days pursuant to the exercise of stock options in the following amounts: Mr. Grealis-113,937; Mr. Randolph-141,258; Mr. Rogers-461,029; Mr. Thomas-100,916; Mr. Turner-2,300; and all directors and executive officers as a group-962,086.
Information regarding PSI's security ownership of certain beneficial owners and management is incorporated by reference to its 2000 Information Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding Cinergy Corp.'s and CG&E's certain relationships and related transactions is incorporated by reference from Cinergy Corp.'s definitive Proxy Statement for the 2000 Annual Meeting of Shareholders.
Information regarding PSI's certain relationships and related transactions is incorporated by reference from its 2000 Information Statement.
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Schedules
Refer to the page captioned "Index to Financial Statements and Financial Statement Schedules", on page 70 of this report, for an index of our financial statements and financial statement schedules included in this report.
Form 8-K
No reports on Form 8-K were filed during the quarter.
Exhibits
Copies of the documents listed below which are identified with an asterisk (*) have heretofore been filed with the Securities and Exchange Commission and are incorporated herein by reference and made a part hereof. Exhibits identified with a pound sign (#) are being filed herewith by the registrant
identified in the exhibit discussion below and are incorporated herein by reference with respect to any other designated registrant. Exhibits not so identified are filed herewith:
Exhibit
Designation
Registrant
Nature of Exhibit
Filed as Exhibit to:
Articles of
Incorporation/
By-laws
3-a
Cinergy(1)
*Certificate of Incorporation of Cinergy, a Delaware corporation.
Cinergy 1993 Form 10-K.
3-b
Cinergy
*By-laws of Cinergy as amended October 15, 1998.
Cinergy October 15, 1998, Form 8-K.
3-c
Cinergy
*By-Laws of Cinergy, as amended on April 21, 1999.
Cinergy March 31, 1999, Form 10-Q.
3-d
CG&E(2)
*Amended Articles of Incorporation of CG&E effective October 23, 1996.
CG&E September 30, 1996, Form 10-Q.
3-e
CG&E
*Regulations of CG&E as amended, April 25, 1996.
CG&E March 31, 1996, Form 10-Q.
3-f
PSI(3)
*Amended Articles of Consolidation of PSI, as amended to April 20, 1995.
PSI June 30, 1995, Form 10-Q.
3-g
PSI
*Amendment to Article D of the Amended Articles of Consolidation of PSI, effective July 10, 1997.
Cinergy 1997 Form 10-K.
3-h
PSI
*By-laws of PSI, as amended to December 17, 1996.
PSI March 31, 1997, Form 10-Q.
3-i
ULH&P(4)
*Restated Articles of Incorporation made effective May 7, 1976.
ULH&P Form 8-K, May 1976.
3-j
ULH&P
*By-laws of ULH&P as amended, adopted May 8, 1996.
ULH&P March 31, 1996, Form 10-Q.
3-k
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.
Cinergy 1997 Form 10-K.
Instruments defining the rights of holders, incl. indentures
4-a
Cinergy
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
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
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
PSI
*Forty-second Supplemental Indenture between PSI and LaSalle National Bank dated August 1, 1988.
PSI 1988 Form 10-K.
4-e
Cinergy
PSI
*Forty-fourth Supplemental Indenture between PSI and LaSalle National Bank dated March 15, 1990.
PSI 1990 Form 10-K.
4-f
Cinergy
PSI
*Forty-fifth Supplemental Indenture between PSI and LaSalle National Bank dated March 15, 1990.
PSI 1990 Form 10-K.
4-g
Cinergy
*Forty-sixth Supplemental Indenture between PSI and LaSalle National Bank dated June 1, 1990.
PSI 1991 Form 10-K.
4-h
Cinergy
PSI
*Forty-seventh Supplemental Indenture between PSI and LaSalle National Bank dated July 15, 1991.
PSI 1991 Form 10-K.
4-i
Cinergy
PSI
*Forty-eighth Supplemental Indenture between PSI and LaSalle National Bank dated July 15, 1992.
PSI 1992 Form 10-K.
4-j
Cinergy
PSI
*Forty-ninth Supplemental Indenture between PSI and LaSalle National Bank dated February 15, 1993.
PSI 1992 Form 10-K.
4-k
Cinergy
PSI
*Fiftieth Supplemental Indenture between PSI and LaSalle National Bank dated February 15, 1993.
PSI 1992 Form 10-K.
4-l
Cinergy
PSI
*Fifty-first Supplemental Indenture between PSI and LaSalle National Bank dated February 1, 1994.
PSI 1993 Form 10-K.
4-m
Cinergy
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
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-o
Cinergy
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-p
Cinergy
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-q
Cinergy
PSI
*Loan Agreement between PSI and the City of Princeton, Indiana dated as of February 1, 1997.
Cinergy 1996 Form 10-K.
4-r
Cinergy
PSI
*Indenture dated November 15, 1996, between PSI and The Fifth Third Bank, as Trustee.
Cinergy 1996 Form 10-K.
4-s
Cinergy
PSI
*First Supplemental Indenture dated November 15, 1996, between PSI and The Fifth Third Bank, as Trustee.
Cinergy 1996 Form 10-K.
4-t
Cinergy
PSI
*Third Supplemental Indenture dated as of March 15, 1998, between PSI and The Fifth Third Bank, as Trustee.
Cinergy 1997 Form 10-K.
4-u
Cinergy
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-v
Cinergy
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-w
Cinergy
PSI
*Sixth Supplemental Indenture between PSI and Fifth Third Bank, as Trustee, dated as of April 30, 1999.
PSI March 31, 1999, Form 10-Q.
4-x
Cinergy
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-y
Cinergy
PSI
*Unsecured Promissory Note dated October 14, 1998, between PSI and the Rural Utilities Service.
PSI 1998 Form 10-K.
4-z
Cinergy
PSI
*Loan Agreement between PSI and the Indiana Department Finance Authority dated as of July 15, 1998.
PSI June 30, 1998, Form 10-Q.
4-aa
Cinergy
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-bb
Cinergy
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.
4-cc
Cinergy
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-dd
Cinergy
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-ee
Cinergy
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-ff
Cinergy
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-gg
Cinergy
CG&E
*Thirty-seventh Supplemental Indenture between CG&E and The Bank of New York dated as of October 14, 1996.
Cinergy 1996 Form 10-K.
4-hh
Cinergy
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-ii
Cinergy
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-jj
Cinergy
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-kk
Cinergy
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-ll
Cinergy
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-mm
Cinergy
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-nn
Cinergy 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-oo
Cinergy 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.
4-pp
Cinergy 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-qq
Cinergy 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-rr
Cinergy 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-ss
Cinergy 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-tt
Cinergy 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-uu
Cinergy 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-vv
Cinergy 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-ww
Cinergy
CG&E
ULH&P
*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-xx
Cinergy
CG&E
ULH&P
*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-yy
Cinergy CG&E
ULH&P
*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-zz
Cinergy CG&E
ULH&P
*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-aaa
Cinergy CG&E
ULH&P
*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-bbb
Cinergy CG&E
ULH&P
*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-ccc
Cinergy CG&E
ULH&P
*Third Supplemental Indenture between ULH&P and The Fifth Third Bank dated as of December 8, 1998.
ULH&P 1998 Form 10-K.
4-ddd
Cinergy CG&E
ULH&P
*Fourth Supplemental Indenture dated as of September 17, 1999, between ULH&P and Fifth Third Bank as Trustee.
ULH&P September 30, 1999 Form 10-Q.
4-eee
Cinergy
*Base Indenture dated as of October 15, 1998, between Cinergy Global Resources, Inc. ("Global Resources") and The Fifth Third Bank as Trustee.
Cinergy September 30, 1998, Form 10-Q.
4-fff
Cinergy
*First Supplemental Indenture dated as of October 15, 1998, between Global Resources and The Fifth Third Bank as Trustee.
Cinergy September 30, 1998, Form 10-Q.
4-ggg
Cinergy
*Indenture dated as of December 16, 1998, between Cinergy and The Fifth Third Bank.
Cinergy 1998 Form 10-K.
4-hhh
Cinergy
*Indenture between Cinergy and Fifth Third Bank, as Trustee, dated as of April 15, 1999.
Cinergy March 31, 1999, Form 10-Q.
Material contracts
10-a
Cinergy
CG&E
PSI
*Amended and Restated Employment Agreement dated October 24, 1994, among CG&E, Cinergy Corp. (an Ohio corporation), Cinergy, PSI Resources, Inc., and Jackson H. Randolph.
Cinergy 1994 Form 10-K.
10-b
Cinergy
CG&E
PSI
Amended and Restated Employment Agreement dated December 30, 1999, among Cinergy, Services, CG&E, and PSI and James E. Rogers.
Cinergy 1999 Form 10-K.
10-c
Cinergy
CG&E
PSI
Amended and Restated Employment Agreement dated December 30, 1999, among Cinergy, Services, CG&E, and PSI and William J. Grealis.
Cinergy 1999 Form 10-K.
10-d
Cinergy
CG&E
PSI
Amended and Restated Employment Agreement dated December 30, 1999, among Cinergy, Services, CG&E, PSI and Larry E. Thomas.
Cinergy 1999 Form 10-K.
10-e
Cinergy
CG&E
PSI
Amended and Restated Employment Agreement dated December 30, 1999, among Cinergy, Services, CG&E, PSI and Cheryl M. Foley.
Cinergy 1999 Form 10-K.
10-f
Cinergy
CG&E
PSI
Amended and Restated Employment Agreement dated December 30, 1999, among Cinergy, Services, CG&E, PSI and Madeleine W. Ludlow.
Cinergy 1999 Form 10-K.
10-g
Cinergy
CG&E
PSI
Amended and Restated Employment Agreement dated December 30, 1999, among Cinergy, Services, CG&E, PSI, and Donald B. Ingle, Jr.
Cinergy 1999 Form 10-K.
10-h
Cinergy
CG&E
PSI
Amended and Restated Employment Agreement dated December 30, 1999, among Cinergy, Services, CG&E, PSI and Michael J. Cyrus.
Cinergy 1999 Form 10-K.
10-i
Cinergy
CG&E
PSI
Employment Agreement dated December 30, 1999 among Cinergy, Services, CG&E, PSI and Jerome A. Vennemann.
Cinergy 1999 Form 10-K.
10-j
Cinergy
CG&E
PSI
Amended and Restated Employment Agreement dated December 30, 1999, among Cinergy, Services, CG&E, PSI and Charles J. Winger.
Cinergy 1999 Form 10-K.
10-k
Cinergy
PSI
Deferred Compensation Agreement, effective as of January 1, 1992, between PSI and James E. Rogers, Jr.
PSI For 10-K/A, Amendment No. 1, dated April 29, 1993.
10-l
Cinergy
PSI
*Split Dollar Life Insurance Agreement, effective as of January 1, 1992, between PSI and James E. Rogers, Jr.
PSI Form 10-K/A, Amendment No. 1, dated April 29, 1993.
10-m
Cinergy
PSI
*First Amendment to Split Dollar Life Insurance Agreement between PSI and James E. Rogers, Jr. dated December 11, 1992.
PSI Form 10-K/A, Amendment No. 1, dated April 29, 1993.
10-n
Cinergy
CG&E
*Deferred Compensation Agreement between CG&E and Jackson H. Randolph dated January 1, 1992.
CG&E 1992 Form 10-K.
10-o
Cinergy
CG&E
*Split Dollar Insurance Agreement, effective as of May 1, 1993, between CG&E and Jackson H. Randolph.
Cinergy 1994 Form 10-K.
10-p
Cinergy CG&E
*Amended and Restated Supplemental Retirement Income Agreement between CG&E and Jackson H. Randolph.
Cinergy 1995 Form 10-K.
10-q
Cinergy CG&E
*Amended and Restated Supplemental Executive Retirement Income Agreement between CG&E and certain executive officers.
Cinergy 1997 Form 10-K.
10-r
Cinergy
Cinergy Union Employees' 401(k) Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.
Cinergy 1999 Form 10-K.
10-s
Cinergy
Amendment to Cinergy Union Employees' 401(k) Plan, adopted December 10, 1999, effective December 1, 1999.
Cinergy 1999 Form 10-K.
10-t
Cinergy
Cinergy Non-Union Employees' 401(k) Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.
Cinergy 1999 Form 10-K.
10-u
Cinergy
Amendment to Cinergy Non-Union Employees' 401(k) Plan, adopted December 10, 1999, effective December 1, 1999.
Cinergy 1999 Form 10-K.
10-v
Cinergy
Cinergy Union Employees' Savings Incentive Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.
Cinergy 1999 Form 10-K.
10-w
Cinergy
Amendment to Cinergy Union Employees' Savings Incentive Plan, effective December 1, 1999, adopted December 10, 1999.
Cinergy 1999 Form 10-K.
10-x
Cinergy
Cinergy Supplemental Executive Retirement Plan amended and restated effective January 1, 1999, adopted October 15, 1998.
Cinergy 1999 Form 10-K.
10-y
Left blank intentionally.
10-z
Cinergy
*1997 Amendments to Various Compensation and Benefit Plans of Cinergy, adopted January 30, 1997.
Cinergy 1997 Form 10-K.
10-aa
Cinergy
*Cinergy Stock Option Plan, adopted October 18, 1994, effective October 24, 1994.
Cinergy Form S-8, filed October 19, 1994.
10-bb
Cinergy
*Amendment to Cinergy Stock Option Plan, amended October 22, 1996, effective November 1, 1996.
Cinergy September 30, 1996, Form 10-Q.
10-cc
Cinergy
*Cinergy Annual Incentive Plan, adopted October 18, 1994, effective October 24, 1994.
Cinergy 1994 Form 10-K.
10-dd
Cinergy
*Amendment to Cinergy Annual Incentive Plan, amended January 25, 1996, effective January 1, 1996.
Cinergy 1996 10-K.
10-ee
Cinergy
*Cinergy Employee Stock Purchase and Savings Plan, adopted October 18, 1994, effective October 24, 1994.
Cinergy Form S-8, filed October 19, 1994.
10-ff
Cinergy
*Amendment to Cinergy Employee Stock Purchase and Savings Plan, adopted April 26, 1996, effective January 1, 1996.
Cinergy June 30, 1996, Form 10-Q.
10-gg
Cinergy
*Amendment to Cinergy Employee Stock Purchase and Savings Plan, adopted October 22, 1996, effective November 1, 1996.
Cinergy September 30, 1996, Form 10-Q.
10-hh
Cinergy
Cinergy UK Sharesave Scheme, adopted and effective December 16, 1999.
Cinergy 1999 Form 10-K.
10-ii
Cinergy
*Cinergy Directors' Deferred Compensation Plan, adopted October 18, 1994, effective October 24, 1994.
Cinergy Form S-8, filed October 19, 1994.
10-jj
Cinergy
*Amendment to Cinergy Directors' Deferred Compensation Plan, adopted October 22, 1996.
Cinergy September 30, 1996, Form 10-Q.
10-kk
Cinergy
*Cinergy Retirement Plan for Directors, adopted October 18, 1994, effective October 24, 1994.
Cinergy 1994 Form 10-K.
10-ll
Cinergy
*Cinergy Retirement Plan for Directors, amended and restated effective January 1, 1999, adopted October 15, 1998.
Schedule 14A Definitive Proxy Statement filed March 12, 1999.
10-mm
Cinergy
Cinergy Directors' Equity Compensation Plan adopted October 15, 1998, effective January 1, 1999.
Schedule 14A Definitive Proxy Statement filed March 12, 1999.
10-nn
Cinergy
*Cinergy 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 1994 Form 10-K.
10-oo
Cinergy
*Cinergy 1996 Long-Term Incentive Compensation Plan, adopted April 26, 1996.
Cinergy Schedule 14A Definitive Proxy Statement filed March 13, 1996.
10-pp
Cinergy
*Amendment to Cinergy 1996 Long-Term Incentive Compensation Plan, adopted October 22, 1996, effective November 1, 1996.
Cinergy September 30, 1996, Form 10-Q.
10-qq
Cinergy
*Cinergy 401(k) Excess Plan, effective January 1, 1997, adopted December 17, 1996.
Cinergy 1996 Form 10-K.
10-rr
Cinergy
*Cinergy Nonqualified Deferred Incentive Compensation Plan, effective January 1, 1997, adopted December 17, 1996.
Cinergy 1996 Form 10-K.
10-ss
Cinergy
Cinergy Director, Officer and Key Employee Stock Purchase Program, effective January 7, 2000, adopted December 10, 1999.
Cinergy 1999 Form 10-K.
10-tt
Cinergy
Cinergy Non-Union Employees' Pension Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.
Cinergy 1999 Form 10-K.
10-uu
Cinergy
Cinergy Union Employees' Pension Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.
Cinergy 1999 Form 10-K.
10-vv
Cinergy
Cinergy Union Employees' Retirement Income Plan as amended and restated effective January 1, 1998, adopted December 18, 1997.
Cinergy 1999 Form 10-K.
Subsidiaries of the registrant
Cinergy
CG&E
PSI
Subsidiaries of Cinergy, CG&E, and PSI
Consent of experts and counsel
Cinergy
CG&E
PSI
ULH&P
Consent of Independent Public Accountants
Power of attorney
Cinergy
CG&E
PSI
ULH&P
Power of Attorney
Financial data schedule
Cinergy
CG&E
PSI
ULH&P
Financial Data Schedules (included in electronic submission only)
Management contract, compensation plan, or arrangement required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K
(1)Cinergy Corp. (Cinergy) in file number 1-11377
(2)The Cincinnati Gas & Electric Company (CG&E) in file number 1-1232
(3)PSI Energy, Inc. (PSI) in file number 1-3543
(4)The Union Light, Heat and Power Company (ULH&P) in file number 2-7793
SCHEDULE II
CINERGY CORP.
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(in thousands)
SCHEDULE II
THE CINCINNATI GAS & ELECTRIC COMPANY
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(in thousands)
SCHEDULE II
PSI ENERGY, INC.
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(in thousands)
SCHEDULE II
THE UNION LIGHT, HEAT AND POWER COMPANY
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(in thousands)
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company have each duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CINERGY CORP.
THE CINCINNATI GAS & ELECTRIC COMPANY
PSI ENERGY, INC.
THE UNION LIGHT, HEAT AND POWER COMPANY
Registrants
Date: February 29, 2000
By /s/ JAMES E. ROGERS
James E. Rogers
Vice Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the indicated registrants and in the capacities and on the dates indicated:
Signature
Title
Date
Cinergy, CG&E, and PSI
Jackson H. Randolph
Chairman
Cinergy
Neil A. Armstrong
Director
Phillip R. Cox
Director
Kenneth M. Duberstein
Director
George C. Juilfs
Director
Melvin Perelman
Director
Thomas E. Petry
Director
Mary L. Schapiro
Director
John J. Schiff, Jr.
Director
Philip R. Sharp
Director
Dudley S. Taft
Director
Oliver W. Waddell
Director
Cinergy and PSI
James K. Baker
Director
Michael G. Browning
Director
John A. Hillenbrand II
Director
CG&E and ULH&P
James L. Turner
President and Director
Cinergy, CG&E, PSI, and ULH&P
/s/ JAMES E. ROGERS James E. Rogers
Attorney-in-fact for all
the foregoing persons
Vice Chairman, Chief Executive Officer, and Director President of Cinergy (Principal Executive Officer)
February 29, 2000
/s/ MADELEINE W. LUDLOW Madeleine W. Ludlow
Vice President and Chief Financial Officer Director of ULH&P (Principal Financial Officer)
February 29, 2000
/s/ BERNARD F. ROBERTS Bernard F. Roberts
Vice President and Comptroller (Principal Accounting Officer)
February 29, 2000
PART I.
[MAP TO GO HERE]
PART II
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
CINERGY CORP. AND SUBSIDIARY COMPANIES
NOTES TO FINANCIAL STATEMENTS
Sale of Accounts Receivable (in millions)
PART III
SIGNATURES