PSI ENERGY INC, DEF 14C, 2000-03-17

PSI ENERGY INC
DEF 14C, 2000-03-17
ELECTRIC SERVICES

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SCHEDULE 14C INFORMATION

Information Statement Pursuant to Section 14(c) of
the Securities Exchange Act of 1934 (Amendment No. )

Check the appropriate box:
/ /		Preliminary Information Statement
/ /		Confidential, for Use of the Commission Only (as permitted by Rule 14c-5(d)(2))
/ /		Definitive Information Statement

PSI ENERGY, INC.
(Name of Registrant As Specified In Its Charter)

Payment of Filing Fee (Check the appropriate box):
/ /	No fee required
/ /	Fee computed on table below per Exchange Act Rules 14c-5(g) and 0-11
	(1)	Title of each class of securities to which transaction applies:
	(2)	Aggregate number of securities to which transaction applies:
	(3)	Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined):
	(4)	Proposed maximum aggregate value of transaction:
	(5)	Total fee paid:
/ /	Fee paid previously with preliminary materials.
/ /	Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.
	(1)	Amount Previously Paid:
	(2)	Form, Schedule or Registration Statement No.:
	(3)	Filing Party:
	(4)	Date Filed:

1999 CINERGY CORP. FINANCIAL REPORT
2000 PSI ENERGY, INC. INFORMATION STATEMENT

Life is lived looking forward.

TABLE OF CONTENTS

Notice of 2000 Annual Meeting		2
Information Statement		3
Mailing of Material		3
Voting Securities		3
Stock Ownership Information		3
Certain Beneficial Owners		3
Ownership of Directors and Executive Officers		4
Director, Officer and Key Employee Stock Purchase Program		4
Election of Directors		4
Director Biographies		5
Meetings and Committees of the Board		5
Director Compensation		5
Report on Executive Compensation and Related Information		6-14
Relationship with Independent Public Accountants		14
Proposals and Business by Shareholders		14
Appendix A: 1999 Financial Report		A-1
Cautionary Statements Regarding Forward-Looking Information		A-1
Review of Financial Condition and Results of Operations		A-2
Consolidated Statements of Income		A-24
Consolidated Balance Sheets		A-25
Consolidated Statements of Changes in Common Stock Equity		A-27
Consolidated Statements of Cash Flows		A-28
Consolidated Statements of Capitalization		A-29
Notes to Consolidated Financial Statements		A-32
Responsibility for Financial Statements		A-56
Report of Independent Public Accountants		A-57
Five Year Statistical Summary		A-59

NOTICE OF ANNUAL MEETING OF SHAREHOLDERS TO BE HELD ON APRIL 27, 2000

We will hold the Annual Meeting of Shareholders of PSI Energy, Inc. on Thursday, April 27, 2000 at 10:00 a.m., eastern daylight time, at the OMNI NETHERLAND PLAZA HOTEL, 35 West Fifth Street, Cincinnati, Ohio.

The purposes of the Annual Meeting are to:

• elect five directors to serve for one-year terms ending in 2001;

and to transact any other business that may properly come before the meeting (or any adjournment or postponement of the meeting).

Shareholders of record at the close of business on Monday, February 28, 2000 may vote at the Annual Meeting.

Proxies will not be solicited for this meeting and you are requested not to send us a proxy. Shareholders are welcome to attend the meeting in person and cast their votes by ballot on the issues presented at the meeting.

By Order of the Board of Directors,

Cheryl M. Foley
Vice President and Secretary

Dated: March 22, 2000

PSI Energy, Inc.
1000 East Main Street
Plainfield, Indiana 46168
(317) 839-9611

INFORMATION STATEMENT

INTRODUCTION

PSI Energy, Inc., an Indiana corporation, is an operating utility primarily engaged in providing electric service to our customers in north central, central, and southern Indiana. PSI is a subsidiary of Cinergy Corp., which is a Delaware corporation and is also the parent company of:

•: Cinergy Services, Inc., the subsidiary used to provide a variety of centralized administrative, management and support services to Cinergy and its subsidiaries and affiliates;
•: Cinergy Global Resources, Inc., the subsidiary primarily used to hold Cinergy's international businesses and certain of its domestic investments;
•: Cinergy Investments, Inc., the subsidiary used to hold most of Cinergy's domestic, non-utility businesses; and
•: The Cincinnati Gas & Electric Company, which is an operating utility that provides electric and gas service to customers in southwestern Ohio and, through a principal subsidiary, The Union Light, Heat and Power Company, to customers in adjacent areas in Kentucky.

MAILING OF MATERIAL

We began mailing this Information Statement on or about March 22, 2000 to the shareholders of PSI cumulative preferred stock in connection with the Annual Meeting of Shareholders to be held on April 27, 2000. Cinergy's consolidated financial statements and accompanying notes for the calendar year ended December 31, 1999, as well as other information relating to corporate financial results and position, are contained in Appendix A to this Information Statement. Cinergy's Summary Annual Report to Shareholders is also enclosed.

We have hired Corporate Investor Communications, Inc. to help with the mailing of this material to the beneficial owners of PSI cumulative preferred stock held through brokerage houses and other custodians, nominees and fiduciaries. We will reimburse them for their out-of-pocket expenses for forwarding the material.

VOTING SECURITIES

PSI's outstanding voting securities are divided into two classes: common stock and cumulative preferred stock. The class of cumulative preferred stock has been further issued in four series. Holders of record of PSI's two classes of voting securities on February 28, 2000, the record date, may vote at the Annual Meeting.

Cinergy beneficially owns all of the 53,913,701 outstanding shares of PSI common stock. There were 956,950 outstanding shares of PSI cumulative preferred stock on the record date.

Because Cinergy's beneficial ownership represents more than 98% of the total votes that could be cast at the Annual Meeting, and because shareholders do not have cumulative voting rights and Cinergy intends to vote in favor of all director-nominees for election as directors to PSI's Board of Directors, the election of all director- nominees is assured. Therefore, the Board considered it inappropriate to solicit proxies for the Annual Meeting. Please be advised, therefore, that this is only an Information Statement. WE ARE NOT ASKING YOU FOR A PROXY AND YOU ARE REQUESTED NOT TO SEND US A PROXY. However, if you wish to vote your shares of cumulative preferred stock, you may do so by attending the Annual Meeting in person and casting your vote by a ballot which will be provided for that purpose.

The shares outstanding as of the record date, and the vote to which each share is entitled, are as follows:

Class	Shares Outstanding	Votes Per Share

Common Stock (without par value)	53,913,701	1 vote
Cumulative Preferred Stock
par value $100 per share	639,026	1 vote
par value $25 per share	317,924	¹/4 vote

SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT

The following table shows the owners of 5% or more of PSI's outstanding shares of cumulative preferred stock as of December 31, 1999. This information is based on the most recently available reports filed with the Securities and Exchange Commission and provided to us by the companies listed.

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percent of Class

Lehman Brothers Holdings Inc. 3 World Financial Center New York, NY 10285	176,800 shares (1)	18.5	%
Wellington Management Company, LLP 75 State Street Boston, MA 02109	48,890 shares (2)	5.1	%

(1): Beneficial ownership consists entirely of PSI's 6.875% Series of Cumulative Preferred Stock, representing 29.5% of the outstanding shares of that Series. Holder reports having sole voting and dispositive powers with respect to all shares, and shared voting and dispositive powers with respect to none of these shares.
(2): Beneficial ownership consists of: (i) 40,000 shares of PSI's 6.875% Series of Cumulative Preferred Stock, representing 6.67% of the outstanding shares of that Series; and (ii) 8,890 shares of PSI's 4.32% Series of Cumulative Preferred Stock, representing 5.26% of the outstanding shares of that Series. Holder reports having shared dispositive power with respect to all shares, and sole voting and dispositive powers and shared voting power with respect to none of these shares

The following table shows the number of shares of Cinergy common stock beneficially owned by each of PSI's director-nominees and executive officers named in the summary compensation table (on page 9), and by all directors and executive officers as a group, as of the record date. PSI's director-nominees and named executive officers did not beneficially own any shares of PSI cumulative preferred stock as of the record date.

Name of Beneficial Owner (1)		Amount and Nature of Beneficial Ownership (2)

James K. Baker		26,105 shares
Michael G. Browning		111,920 shares
Michael J. Cyrus		108,059 shares
William J. Grealis		233,373 shares
John A. Hillenbrand II		76,264 shares
Jackson H. Randolph		267,726 shares
James E. Rogers		736,553 shares
Larry E. Thomas		253,982 shares
All directors and executive officers as a group		2,224,908 shares

(1)

The beneficial ownership of all directors and executive officers as a group represents 1.40% of the outstanding shares of
Cinergy common stock; no individual person's ownership
exceeds 0.464% of the outstanding shares.

(2)

Includes shares acquired under Cinergy's Director, Officer and Key Employee Stock Purchase Program which is described below.

Also includes shares which there is a right to acquire within 60 days pursuant to the exercise of stock options in the following amounts: Mr. Baker—12,500; Mr. Browning—25,287; Mr. Grealis—113,937; Mr. Hillenbrand—12,500; Mr. Randolph—141,258; Mr. Rogers—461,029; Mr. Thomas—100,916; and all directors and executive officers as a group—1,010,073.

Does not include units representing shares of Cinergy common stock credited under Cinergy's Retirement Plan for Directors, Directors' Equity Compensation Plan and/or Directors' Deferred Compensation Plan in the following amounts: Mr. Baker—18,580; Mr. Browning—19,625; and Mr. Hillenbrand—13,365.

DIRECTOR, OFFICER AND KEY EMPLOYEE STOCK PURCHASE PROGRAM

In December 1999, Cinergy's board of directors adopted the Director, Officer and Key Employee Stock Purchase Program. The purpose of the program is to facilitate the purchase of Cinergy common stock by directors, officers and key employees, thereby further aligning their interests with those of Cinergy shareholders.

All of our non-employee directors and executive officers who will not be retiring within the next two years purchased stock through the Program and are participating in the financing portion of the Program described below. A total of $18,000,000 of common stock purchased by directors and executive officers and $17,950,000 purchased by other officers and key employees is being financed through the Program. Individual purchases financed by directors and executive officers range from $150,000 to $3,000,000.

Participants had the option of financing the purchases through a five-year credit facility arranged by Cinergy with a bank. Loans to participants under the facility bear interest at the rate of 8.68% per year. Each participant is obligated to repay the bank any loan principal, interest and prepayment fees associated with his or her loan, 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.

Cinergy Services and, in part, Cinergy 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.

ELECTION OF DIRECTORS

In accordance with PSI's By-Laws, the Board shall consist of not less than one and not more than seven persons. The size of the Board is currently fixed at five and the Board has nominated the individuals listed below for election as directors, all of whom are presently members of the Board and were elected by shareholders at the 1999 annual meeting. All of the proposed director-nominees have signified their willingness to serve, if elected.

We would like to acknowledge Mr. John M. Mutz, who retired from full-time service as President of PSI effective May 31, 1999, and retired as a member of our Board effective December 31, 1999. Mr. Mutz first joined our Board in 1991 and was named President in 1993, helping successfully manage PSI through the merger with CG&E to form Cinergy. His support, valued counsel and many contributions during his years of devoted and distinguished service to our company are immeasurable and greatly appreciated.

For the election of directors at the Annual Meeting, the five persons receiving the greatest number of votes will be elected to the Board. As previously stated, Cinergy intends to vote all of the outstanding shares of PSI common stock in favor of the director-nominees, and because Cinergy's beneficial ownership of PSI's voting securities represents over 98% of the total votes that could be cast at the Annual Meeting, the election of the director-nominees is assured.

The following brief biographies contain information about the five director-nominees. The information includes each person's principal occupations and business experience for at least the past five years. Messrs. Randolph and Rogers are the only directors who are employees of Cinergy and its affiliates or subsidiaries, including PSI.

James K. Baker

Director of PSI since 1986. Director of Cinergy since 1994. Age 68.

Mr. Baker served as Vice Chairman of Arvin Industries, Inc., a worldwide supplier of automotive parts, from 1996 until his retirement in 1998. Previously, he served in various executive capacities at Arvin, including Chairman of the Board and Chief Executive Officer. Mr. Baker is a director of Amcast Industrial Corp., Geon Company and Tokheim Corporation.

Michael G. Browning

Director of PSI since 1990. Director of Cinergy since 1994. Age 53.

Mr. Browning is Chairman and President of Browning Investments, Inc., which is engaged in real estate ventures. He also previously served as President of Browning Real Estate, Inc., the general partner of various real estate investment partnerships.

John A. Hillenbrand II

Director of PSI since 1985. Director of Cinergy since 1994. Age 68.

Mr. Hillenbrand principally serves as Chairman, President and Chief Executive Officer of Glynnadam, Inc., a personal investment holding company. He is also Chairman of Able Body Corporation and Nambe' Mills, Inc., and Vice Chairman of Pri-Pak, Inc. Mr. Hillenbrand is also a director of Hillenbrand Industries, Inc.

Jackson H. Randolph

Director of PSI since 1994; Member of the Executive Committee. Director of Cinergy since 1993 and of CG&E since 1983. Age 69.

Mr. Randolph is Chairman of the Board of Cinergy and certain of its subsidiaries, including PSI. Previously, he also served as Chief Executive Officer of Cinergy and its principal subsidiaries, including PSI. Mr. Randolph is a director of Cincinnati Financial Corporation and PNC Bank Corp.

James E. Rogers

Director of PSI since 1988; Chairperson of the Executive Committee. Director of Cinergy since 1993 and of CG&E since 1994. Age 52.

Mr. Rogers is Vice Chairman, President and Chief Executive Officer of Cinergy, and Vice Chairman and Chief Executive Officer of PSI. He also holds similar executive officer positions with Cinergy's other principal subsidiaries. Previously, Mr. Rogers served as Vice Chairman, President and Chief Operating Officer of Cinergy and also held similar executive officer positions with its principal subsidiaries, including PSI. Mr. Rogers is a director of Duke-Weeks Realty Corp., Fifth Third Bancorp and The Fifth Third Bank.

MEETINGS AND COMMITTEES OF THE BOARD

PSI's Board met six times during 1999, with each meeting being held concurrently or consecutively with a meeting of Cinergy's board of directors. All directors attended more than 75% of the total number of Board meetings and, if applicable, committee meetings on which they served. The Executive Committee is the only standing committee of the Board.

COMPENSATION OF DIRECTORS

Each non-employee director of PSI is eligible to receive an annual retainer fee of $8,000 plus a fee of $1,000 for each Board meeting attended. However, any non-employee director of PSI who also serves as a non-employee director of Cinergy or any of its affiliates shall not receive the annual retainer fee, or any compensation for attendance at any Board meeting that is held concurrently or consecutively with a meeting of Cinergy's board of directors. Each non-
employee director of PSI (Messrs. Baker, Browning and Hillenbrand) is currently also a non-employee director of Cinergy. Directors who are employees of Cinergy or any of its subsidiaries (Messrs. Randolph and Rogers) receive no compensation for their services as directors.

Under Cinergy's Directors' Deferred Compensation Plan, each non-employee director of Cinergy and its subsidiaries may choose to defer his or her fees into a bookkeeping account denominated in either:

•: units representing shares of Cinergy 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 Cinergy 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 Cinergy common stock, and accrued cash accounts are paid in cash, generally after the director retires from the appropriate board.

Effective January 1, 1999, Cinergy's Retirement Plan for Directors was amended and restated to eliminate the accrual of future benefits. Each non- employee director of Cinergy with an accrued benefit through December 31, 1998 was permitted to convert it from cash to units representing shares of Cinergy 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 Cinergy common stock. A director's account is distributed as shares of Cinergy common stock after he or she retires from the Board. Each non-employee director of Cinergy 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.

BOARD COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION

The Compensation Committee of Cinergy's board of directors:

•: establishes the executive compensation policy;
•: recommends, oversees and administers compensation plans for executive officers and key employees;
•: determines compensation for the chief executive officer; and
•: reviews and approves compensation for our remaining executive officers.

During 1999, the Committee consisted of Messrs. Van P. Smith (Chairperson until his retirement from Cinergy's board of directors in April 1999), Michael G. Browning (Chairperson since April 1999), George C. Juilfs, Thomas E. Petry (member since April 1999) and John J. Schiff, Jr. Each of the members is an independent, "non-employee director" within the meaning of Rule 16b-3 under the Securities Exchange Act of 1934 and an "outside director" within the meaning of Section 162(m) of the Internal Revenue Code.

Compensation Policy

Our compensation program for executive officers consists of salary, annual cash incentives and long- term incentives. The program is designed to attract, retain and motivate the high quality employees needed to provide superior service to customers and to maximize returns to shareholders.

Base salaries for the executive group are competitive (targeted at the 50^th to 75^th percentile) with those provided by utility companies that are of comparable size to Cinergy. Base salaries are reviewed annually. Any increases are based on such factors as competitive industry salaries, corporate financial results and a subjective assessment of each person's performance, role and skills.

Our executive compensation program also seeks to link executive and shareholder interests through cash and equity incentive plans, in order to reward corporate and individual performance. Annual and long-term incentive plans are designed to provide opportunities that are competitive with comparably sized utility companies.

The Committee believes strongly that annual and long-term incentive opportunities assist in motivating the type of behavior necessary to successfully manage short- and long-term corporate goals. This emphasis results in a compensation mix in which annual and long-term incentives make up, on the average, at least 50% of the annual compensation that can be earned by the chief executive officer and the other executive officers.

Cinergy also has two non-qualified deferred compensation plans for executive officers:

•: the Deferred Incentive Compensation Plan allows deferral of all or a portion of cash awards otherwise payable under Cinergy's Annual Incentive Plan; and
•: the Excess 401(k) Plan allows deferral of a portion of base salaries that cannot be deferred under Cinergy's 401(k) plan because of federal limitations on the amount of compensation that can be deferred into qualified plans.

Annual Incentive Compensation

Approximately 460 management employees, including all executive officers, are eligible to participate in Cinergy's Annual Incentive Plan. Each participant is eligible to receive an incentive cash award or bonus to the extent that certain pre-determined corporate or business unit and individual goals are achieved. For 1999, the corporate goal was based on earnings per share. The achievement level for the corporate goal was at the 3.0 award level—on a sliding scale of 1.0 to 3.0—for 1999. Achievement of the corporate goal for 1999 originally was anticipated to be 40% of the total possible award and achievement of individual goals the remaining 60%. However, because of the decision (discussed below) to revise and expand the achievement factors considered in 2000 for all business unit participants, the Committee decided to retain for 1999 the 50%-50% weighting for corporate and individual goals that had been used in prior years. For business unit presidents, however, 10% of the total possible award was based on business unit earnings per share targets, 40% was based on the corporate goal, and the remaining 50% was based on individual goals.

For 1999, potential awards ranged from 2.5% to 90% of the employee's annual base salary, depending upon the achievement levels and the employee's position. Graduated standards for achievement were developed to encourage each employee's contribution.

Also for 1999, the Committee determined the achievement level for each named executive officer based on an assessment of both individual objective goals and an evaluation of individual performance. The Committee, in its effort to accurately measure each officer's performance, determined that the achievement level for individual goals ranged from 2.5 to 3.0 on a 1.0 to 3.0 scale. As to named executives who are also business unit presidents, only one achieved his business unit goal for the year.

For 2000, Cinergy's Annual Incentive Plan will be based on a corporate earnings per share goal, business unit earnings per share targets, business unit objective value measures, and individual goals. For corporate center employees, the corporate earnings per share goal and individual goals will be equally weighted. For business unit employees, the weightings of the business unit earnings per share goals, the business unit objective value measures, and individual goals will vary by business unit.

Long-Term Incentive Compensation

Cinergy has a long-term incentive compensation program (the "LTIP") under the terms of the 1996 Long-Term Incentive Compensation Plan. The LTIP is designed to combine the interests of Cinergy's shareholders, customers and management to enhance value by increasing total shareholder return. The LTIP ties a large portion of the participants' potential pay to long-term performance. This approach provides a greater upside potential for outperforming peer companies, plus downside risk for underperforming.

Approximately 85 management employees, including all executive officers, except the chairman of the board, participate in the LTIP.

The first performance cycle of the LTIP covered the calendar years 1997 through 1999 and consisted of two parts: stock options and the "Value Creation Plan."

For the first performance cycle, annual grants of stock options were made effective January 1 of 1997, 1998, and 1999. The number of options granted to a participant was determined by taking 25% of the participant's target LTIP award value and dividing it by the projected stock price appreciation of an option, to arrive at the number of options granted for each year of the three-year cycle.

The Value Creation Plan portion of the LTIP for the first performance cycle consisted of a target grant of performance-based restricted stock and performance shares, both of which could be earned based on Cinergy's total shareholder return ("TSR") vs. the TSR of a peer group. TSR means share price appreciation plus dividends, divided by the stock price at the beginning of the cycle. For the three-year performance cycle, Cinergy's average TSR was measured against the average TSR of the peer group. The peer companies were the 25 largest utility companies, based on kilowatt-hours sold. Because Cinergy's TSR for the three-year cycle was lower than that of the peer group, participants forfeited all restricted shares and no performance shares were earned.

Effective January 1, 2000, three separate performance cycles were initiated so that, going forward, the LTIP will consist of overlapping three-year performance cycles. The second performance cycle will cover only calendar year 2000; the third performance cycle will cover calendar years 2000 through 2001; and the fourth performance cycle will cover calendar years 2000 through 2002. The fifth performance cycle will start January 1, 2001.

For the second, third and fourth performance cycles, the annualized target award opportunity as a percent of base salary ranges from 20% to 160% depending on the participant's position. The target LTIP award values are 160% of base salary for the chief executive officer and 90% of the respective base salary for each of the other eligible named executive officers. Stock options comprise 25% of the total award opportunity under the fourth performance cycle, and the Value Creation Plan comprises the other 75%. For the fourth performance cycle, a grant of stock options was made effective January 19, 2000. No grants of options were made with respect to the second and third performance cycles, so the Value Creation Plan makes up the total available award opportunity under those cycles.

For the second, third and fourth performance cycles of the Value Creation Plan, the TSR performance measure will continue to be used. However, instead of using restricted stock, the new cycles grant performance shares that will vest in the participants to the extent the TSR targets are met as compared with the peer group (the S&P Super Composite Electric Index). A target grant of performance shares was made effective January 19, 2000.

Under the new cycles, except in the case of disability, death, or retirement on or after age 50 during the cycle, a participant must be employed by Cinergy on January 1 following the end of a cycle to receive an earned award. Earned performance shares will be paid out no later than April 1 following the end of the cycle.

Chief Executive Officer

The Committee determined Mr. Rogers' 1999 base salary after considering his employment agreement with Cinergy (see "Employment Agreements and Severance Arrangements" on page 12), competitive salaries at peer companies and general industry, and a subjective assessment of his performance. For 1999, Mr. Rogers received a cash award under the Annual Incentive Plan in the amount of $877,507. The award was based on Cinergy's achievement of its corporate earnings per share goal for the year, and the Committee's determination of Mr. Rogers' achievement of individual goals. Mr. Rogers' maximum potential 1999 award under the Annual Incentive Plan was equal to 90% of his annual base salary (including deferred compensation).

Effective January 1, 1999, December 14, 1999, and January 3, 2000, the Committee granted Mr. Rogers three separate options to purchase 55,400, 444,600, and 55,400 shares of Cinergy common stock, at the respective fair market values of $34.125, $23.8125, and $23.65625 per share. The first grant was the third annual option grant under the first performance period of the LTIP. The latter two grants were part of a grant intended to encourage Mr. Rogers to remain in the employ of Cinergy. Similar retention option grants of 150,000 shares of Cinergy common stock also were made to Messrs. Cyrus, Grealis and Thomas on December 14, 1999.

Code Section 162(m)

Internal Revenue Code Section 162(m) generally limits Cinergy's tax deduction to one million dollars for compensation paid to each of the named executive officers. However, qualifying performance-based compensation is exempted from the deduction limit under certain conditions. As to the named executive officers who may be subject to Code Section 162(m), the Committee intends to use performance-based compensation reflective of corporate and individual performance, including stock options and performance share grants under the LTIP and objective goals under the Annual Incentive Plan, under most circumstances. However, when appropriate for competitive purposes to attract and retain employees, the Committee will award compensation that does not qualify for exemption from the deduction limit under Code Section 162(m).

The tables that follow, and accompanying footnotes, reflect the decisions covered by this discussion.

Compensation Committee
Michael G. Browning, Chairperson
George C. Juilfs
Thomas E. Petry
John J. Schiff, Jr.

[Remainder of this page intentionally left blank.]

SUMMARY COMPENSATION TABLE

The following table shows, for the past three years, the compensation paid to our chief executive officer and to the individuals who were our other four most highly compensated executive officers in 1999. These amounts include payments for services in all capacities to Cinergy and its subsidiaries, including PSI. We sometimes refer to the persons listed below as the "named executive officers."

					Long-Term Compensation
		Annual Compensation			Awards		Payouts
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)
Name and Principal Position	Year	Salary ($)	Bonus (1) ($)	Other Annual Compen- sation ($)	Restricted Stock Awards (2) ($)	Securities Underlying Options/SARs (#)	LTIP Payouts ($)	All Other Compen sation (3) ($)

James E. Rogers	1999	925,008	877,507	42,288	0	500,000	0	153,866
Vice Chairman	1998	810,000	619,200	47,041	0	535,400	0	138,329
and Chief Executive Officer	1997	700,008	337,504	17,039	1,951,169	55,400	0	126,956
Jackson H. Randolph	1999	585,000	321,750	17,551	0	0	0	110,990
Chairman of the Board	1998	585,000	321,750	13,405	0	0	0	98,157
	1997	585,000	321,750	14,575	0	0	0	88,181
Michael J. Cyrus (4)	1999	491,250	245,625	79,451	0	174,300	0	14,079
Vice President	1998	332,308	180,000	0	1,579,282	24,300	0	200,157
William J. Grealis	1999	440,004	264,002	22,958	0	170,700	0	22,690
Vice President	1998	396,900	180,590	25,643	0	20,700	0	34,313
	1997	378,000	113,400	13,094	728,443	20,700	0	15,550
Larry E. Thomas	1999	390,000	234,000	34,343	0	168,400	0	14,998
Vice President	1998	352,848	169,367	9,678	0	18,400	0	16,594
	1997	336,048	100,814	11,502	647,575	18,400	0	15,809

(1): Amounts appearing in this column reflect the Annual Incentive Plan award earned during the year listed and paid in the following year.
(2): Amounts appearing in this column reflect the dollar values of restricted stock awards, determined by multiplying the number of shares in each award by the closing market price of Cinergy common stock as of the effective date of grant. The aggregate number of all restricted stock holdings and values at calendar year ended December 31, 1999, determined by multiplying the number of shares by the year end closing market price, are as follows: Mr. Rogers—58,462 shares ($1,399,434); Mr. Cyrus—43,268 shares ($1,035,728); Mr. Grealis—21,826 shares ($522,460); and Mr. Thomas—19,403 shares ($464,459). Of Mr. Cyrus' restricted shares, 27,258 were issued in accordance with his employment agreement. All other restricted shares referenced in the Table were issued under the Value Creation Plan portion of Cinergy's LTIP and, together with their related dividends which had been held by Cinergy, were forfeited to Cinergy effective January 1, 2000 because the performance targets for the three-year performance cycle under which they were awarded were not met.
(3): Amounts appearing in this column for 1999 include for Messrs. Rogers, Randolph, Cyrus, Grealis and Thomas, respectively: (i) employer matching contributions under 401(k) plan and related excess benefit plan of $27,750, $17,550, $11,138, $13,200 and $11,700; and (ii) insurance premiums paid with respect to executive/group-term life insurance of $524, $1,620, $2,941, $9,490 and $3,298. Also includes for Mr. Rogers deferred compensation in the amount of $50,000, and for Messrs. Rogers and Randolph, respectively, above-market interest on amounts deferred pursuant to deferred compensation agreements of $61,617 and $76,420, and benefits under split dollar life insurance agreements of $13,975 and $15,400.
(4): Mr. Cyrus was not employed by Cinergy or any of its subsidiaries or affiliates prior to 1998.

OPTION/SAR GRANTS TABLE

The following table shows individual grants of options to purchase Cinergy common stock made to the named executive officers during 1999.

Individual Grants (1)						Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term (2)
(a)	(b)	(c)		(d)	(e)	(f)	(g)
Name	Number of Securities Underlying Options/SARs Granted (#)	% of Total Options/SARs Granted to Employees in Fiscal Year		Exercise or Base Price ($/Sh)	Expiration Date	5% ($)	10% ($)

James E. Rogers	55,400	2.08	%	34.125	1/1/2009	1,188,884	3,013,206
	444,600	16.69	%	23.8125	12/14/2009	6,660,108	16,872,570
Michael J. Cyrus	24,300	0.91	%	34.125	1/1/2009	521,478	1,321,677
	150,000	5.63	%	23.8125	12/14/2009	2,247,000	5,692,500
William J. Grealis	20,700	0.78	%	34.125	1/1/2009	444,222	1,125,873
	150,000	5.63	%	23.8125	12/14/2009	2,247,000	5,692,500
Larry E. Thomas	18,400	0.69	%	34.125	1/1/2009	394,864	1,000,776
	150,000	5.63	%	23.8125	12/14/2009	2,247,000	5,692,500

(1): Options shown in the first row of column (b) for each named officer were granted effective January 1, 1999 and become exercisable on January 1, 2002, the third anniversary of the grant. Options shown in the second row of column (b) for each named officer were granted effective December 14, 1999 and become exercisable in five equal annual installments beginning on December 14, 2000. In the case of a change-in-control of Cinergy, all stock options become immediately exercisable.
(2): The amounts shown in columns (f) and (g) represent hypothetical potential appreciation of Cinergy common stock and do not represent either historical performance or, necessarily, expected future levels of appreciation. The actual values which may be realized, if any, upon the exercise of stock options will depend on the future market price of Cinergy common stock, which cannot be forecast with reasonable accuracy.

AGGREGATED OPTION/SAR EXERCISES AND YEAR END OPTION/SAR VALUES TABLE

The following table shows, for each named executive officer, the number of shares covered by options held on December 31, 1999 and the value of the person's "in-the-money" options. "In-the-money" value is the positive spread between the market price of Cinergy common stock on December 31, 1999 ($23.9375 per share) and an option's exercise price per share. As indicated, no options were exercised by the named executive officers during 1999.

(a)	(b)	(c)	(d)	(e)
			Number of Securities Underlying Unexercised Options/SARs at Year End (#)	Value of Unexercised In-The-Money Options/SARs at Year End ($)
Name	Shares Acquired on Exercise (#)	Value Realized ($)	Exercisable/ Unexercisable	Exercisable/ Unexercisable

James E. Rogers	0	0	381,029/955,400	260,981/55,575
Jackson H. Randolph	0	0	141,258/0	150,087/0
Michael J. Cyrus	0	0	0/198,600	0/18,750
William J. Grealis	0	0	113,937/191,400	0/18,750
Larry E. Thomas	0	0	100,916/186,800	87,673/18,750

PENSION BENEFITS

At retirement, the named executive officers will receive benefits under Cinergy's Non-union Employees' Pension Plan, plus certain supplemental plans or agreements. The Pension Plan is a defined benefit pension plan, which means that the annual pension benefit is calculated by a formula. Participants do not contribute to this Plan.

The formula takes into account the participant's highest average earnings, years of plan participation, and covered compensation. Highest average earnings is the average annual salary during the employee's three consecutive years producing the highest average within the ten years immediately preceding his or her retirement. Highest average earnings also includes any short-term incentive and/or deferred compensation. Covered compensation is the average social security taxable wage base over a period of up to 35 years.

The formula for calculating the annual pension benefit is:

•: 1.1% of highest average earnings plus 0.5% of highest average earnings in excess of covered compensation,
times the number of years of plan participation through 35 years,
•: plus 1.4% of highest average earnings times the number of years of plan participation over 35 years.

Each year, the Internal Revenue Service establishes a dollar limit on the amount of pay that can be counted for purposes of benefits under this type of pension plan and on the annual benefit that may be provided. As a result, Cinergy also has an Excess Pension Plan which is designed to restore pension benefits, calculated in accordance with the formula given above, to those individuals whose benefits under the Pension Plan otherwise would be reduced by the IRS limits. Each named executive officer is covered under the Excess Pension Plan.

The table below shows the estimated annual pension benefits payable as a straight-life annuity under both pension plans to participants who retire at age 62. The benefits are not subject to any deduction for social security or other offset amounts.

Mr. Randolph's accrued annual pension benefit is based upon 40 years of credited service. The estimated credited years of service at age 62 for the remaining named executive officers are as follows: Mr. Rogers, 20 years; Mr. Cyrus, 19 years; Mr. Grealis, 12 years; and Mr. Thomas, 37 years.

In addition to the pension plans, Cinergy has a Supplemental Executives Retirement Plan ("SERP"). The Senior Executive Supplement portion of the SERP provides selected executive officers an opportunity to earn a pension benefit that will replace up to 60% of their final pay. Each participant accrues a retirement income replacement percentage at the rate of 4% per year from the date that the participant begins service as a senior executive (up to a maximum of 15 years). The Senior Executive Supplement is an amount equal to a maximum of 60% of the greater of the employee's highest average earnings (as defined in the Pension Plan) or the final 12 months of base pay and Annual Incentive Plan pay. The Senior Executive Supplement is reduced by the actual benefits provided under the Pension Plan and the Excess Pension Plan, and further reduced by 50% of the employee's age 62

		Years of Service
Compensation		5		10		15		20		25		30		35		40

$	500,000	$	38,940	$	77,875	$	116,815	$	155,755	$	194,690	$	233,630	$	272,570	$	307,570
	600,000		46,940		93,875		140,815		187,755		234,690		281,630		328,570		370,570
	700,000		54,940		109,875		164,815		219,755		274,690		329,630		384,570		433,570
	800,000		62,940		125,875		188,815		251,755		314,690		377,630		440,570		496,570
	900,000		70,940		141,875		212,815		283,755		354,690		425,630		496,570		559,570
	1,000,000		78,940		157,875		236,815		315,755		394,690		473,630		552,570		622,570
	1,100,000		86,940		173,875		260,815		347,755		434,690		521,630		608,570		685,570
	1,200,000		94,940		189,875		284,815		379,755		474,690		569,630		664,570		748,570
	1,300,000		102,940		205,875		308,815		411,755		514,690		617,630		720,570		811,570
	1,400,000		110,940		221,875		332,815		443,755		554,690		665,630		776,570		874,570
	1,500,000		118,940		237,875		356,815		475,755		594,690		713,630		832,570		937,570
	1,600,000		126,940		253,875		380,815		507,755		634,690		761,630		888,570		1,000,570
	1,700,000		134,940		269,875		404,815		539,755		674,690		809,630		944,570		1,063,570
	1,800,000		142,940		285,875		428,815		571,755		714,690		857,630		1,000,570		1,126,570
	1,900,000		150,940		301,875		452,815		603,755		754,690		905,630		1,056,570		1,189,570
	2,000,000		158,940		317,875		476,815		635,755		794,690		953,630		1,112,570		1,252,570
	2,100,000		166,940		333,875		500,815		667,755		834,690		1,001,630		1,168,570		1,315,570
	2,200,000		174,940		349,875		524,815		699,755		874,690		1,049,630		1,224,570		1,378,570
	2,300,000		182,940		365,875		548,815		731,755		914,690		1,097,630		1,280,570		1,441,570

social security benefit. Messrs. Rogers, Cyrus, Grealis and Thomas are covered under the Senior Executive Supplement; the estimated retirement income replacement percentage for each is 60%, 60%, 48% and 52%, respectively.

Mr. Randolph has a Supplemental Executive Retirement Income Agreement under which he or his beneficiary will receive an annual supplemental retirement benefit of $511,654, in monthly installments of $42,638 for 180 months beginning December 1, 2000.

Cinergy's Executive Supplemental Life Insurance Program provides key management personnel, including the named executive officers, with additional life insurance during employment and with post-retirement deferred compensation. At the later of age 50 or retirement, the life insurance coverage is canceled and, instead, the participant receives the value of the coverage in the form of deferred compensation, payable in ten equal annual installments of $15,000 per year.

EMPLOYMENT AGREEMENTS AND SEVERANCE ARRANGEMENTS

Mr. Randolph has an employment agreement with Cinergy which was entered into in 1994 and continues until November 30, 2000. Under the agreement he serves as Cinergy's Chairman of the Board and receives a minimum annual base salary of $465,000.

Each of the other named executive officers has an amended and restated employment agreement with Cinergy which became effective December 30, 1999 and expires on December 31, 2002. Unless the executive officer or Cinergy gives timely notice otherwise, the term of the officer's agreement automatically is extended for an additional year on each December 31.

Under his agreement, Mr. Rogers receives a minimum annual base salary of $810,000. Mr. Rogers' employment agreement also provides that if he retires, or dies prior to retirement, after reaching age 50, he (or his spouse) will be entitled to a supplemental retirement benefit equal to the difference between (1) his total benefit under the Pension Plan, the Excess Pension Plan and the SERP (together, the executive retirement plans) and (2) 60% of his highest average earnings times a fraction, the numerator of which is his years of participation and the denominator of which is 35. For purposes of Mr. Rogers' employment agreement, his highest average earnings are as defined in the Pension Plan plus any amounts deferred under his Deferred Compensation Agreement (described below) during the calculation period.

Under his agreement, Mr. Cyrus receives a minimum annual base salary of $495,000. He also was awarded $1,000,000 in restricted shares of Cinergy common stock under his original agreement. If after reaching age 55 Mr. Cyrus retires or dies prior to retirement, he (or his spouse) will receive a supplemental retirement benefit equal to the difference between his total benefit under all executive retirement plans and 60% of his highest average earnings (as defined in the Pension Plan).

Under his agreement, Mr. Grealis receives a minimum annual base salary of $440,000. If after reaching age 50 Mr. Grealis retires or dies prior to retirement, he (or his spouse) will be entitled to a supplemental retirement benefit equal to the difference between (1) his total benefit under the executive retirement plans and (2) the greater of (a) 60% of his highest average earnings (as defined in the Pension Plan) times a fraction, the numerator of which is his years of participation and the denominator of which is 35 or (b) $283,000 per year.

Under his agreement, Mr. Thomas receives a minimum annual base salary of $390,000. The supplemental retirement benefit provisions of Mr. Thomas' employment agreement are the same as those described above for Mr. Grealis, except that no minimum annual benefit is set.

For purposes of each of Messrs. Rogers', Grealis', and Thomas' agreements, years of participation means the lesser of 35, or 25 plus two additional years for each birthday after age 50.

Each named executive officer participates in Cinergy's Annual Incentive Plan, Stock Option Plan, LTIP, Excess Pension Plan, SERP and Executive Supplemental Life Insurance Program, except that Mr. Randolph does not participate in the LTIP or SERP and Mr. Cyrus does not participate in the Stock Option Plan. The named executive officers also participate in all other retirement and welfare benefit plans generally applicable to our employees and/or executives and receive other fringe benefits such as the use of automobiles, the payment of club dues and the furnishing of financial planning and tax preparation services.

The employment agreement of each named executive officer specifies Cinergy's obligations in the event of the executive's termination of employment before the end of the term of his agreement. The principal termination provisions are described below. Each agreement is, however, somewhat different and all of the provisions described may not apply to a particular executive.

If an executive officer's employment terminates for any reason, he will be paid:

•: any accrued and unpaid base salary,
•: a pro rata portion of the executive's Annual Incentive Plan bonus, based at least on his target amount for the year,
•: any compensation which the executive has deferred, including any accrued interest or earnings, and
•: any other vested benefits which are not forfeited under the terms of Cinergy's various benefit plans and agreements.

In addition, if the termination of employment is prior to a "change in control" and is by Cinergy without "cause" or by the executive for "good reason" (as each is defined in the executive's agreement), the executive will receive:

•: three times his annual salary plus annual incentive plan bonus, with the bonus amount being not less than his target amount in effect at the time of notice of termination,
•: the present value of any additional amounts to which the executive would have been entitled at the end of the agreement's term under the Executive Supplemental Life Insurance Program and the LTIP's Value Creation Plan,
•: the value of all deferred compensation and executive life insurance benefits (not covered above), whether or not then vested or payable,
•: either continued medical and welfare benefits through the end of the term of the agreement, or a lump sum payment equal to the amount of the premiums for the medical and welfare benefits, and
•: ownership of his company car and certain tax counseling services.

Alternatively, if Cinergy terminates the executive officer's employment without cause or he terminates his employment for good reason, within 24 months after a change in control, the executive will receive a severance payment equal to the greater of:

•: the present value of the amounts and benefits described above, except for the medical and welfare benefits, or
•: three times the sum of
(a): his base salary in effect immediately prior to the event resulting in termination or, if higher, to the date of the change in control, and
(b): his pay under all Cinergy incentive compensation or bonus plans for the year preceding termination or, if higher, the year preceding the change in control.

The executive officer also will be provided with either replacement life, disability, accident and health insurance benefits for 36 months, reduced to the extent he receives, without cost to him, comparable benefits, or a lump sum payment equal to the amount of the premiums for these insurance benefits.

In addition to the above:

•: Upon termination for any reason, Messrs. Randolph and Rogers will receive benefits under their deferred compensation agreements (described below) and their split dollar life insurance agreements.
•: If the employment of Mr. Rogers, Grealis or Thomas is terminated for other than cause following a change in control, the executive's supplemental retirement benefit will equal the difference between his total benefit under all executive retirement plans and 60% of his highest average earnings.
•: Messrs. Rogers, Cyrus, Grealis and Thomas are each entitled to reimbursement for relocation expenses after termination of employment for any reason other than death.
•: Cinergy will pay all legal fees and expenses incurred by the executive officer as a result of successfully disputing a termination of employment which entitles the executive to benefits under his agreement.
•: If an executive officer's termination of employment payments are subject to an excise tax, Cinergy must pay the executive an additional amount so that the net amount retained by the executive after taxes, including taxes on the additional amount, equals the pre-tax benefit amount to which the executive is entitled.

DEFERRED COMPENSATION AGREEMENTS

Each of Mr. Randolph and Mr. Rogers has a deferred compensation agreement with Cinergy.

Under his agreement, Mr. Randolph was credited annually, for the five-year period from 1992 through 1996, with a $50,000 base salary increase in the form of deferred compensation. When his employment terminates, Mr. Randolph will receive an annual cash benefit of $179,000 payable for a 15-year period beginning January 2001.

Under his agreement, Mr. Rogers also was credited annually, from 1992 through 1996, with a $50,000 base salary increase in the form of deferred compensation. He is credited annually with the same amount for the additional five-year period from 1997 through 2001. When his employment terminates for any reason other than death, Mr. Rogers will receive an annual cash benefit over a 15-year period beginning the first January following termination of his employment, but in no event earlier than January 2003 or later than January 2010. The annual cash benefit amount payable for the 15-year period ranges from $179,000 per year, if payment begins in January 2003, to $554,400 per year if payment begins in January 2010. Comparable amounts are payable if Mr. Rogers dies before these payments begin.

In addition, if Mr. Rogers' employment terminates for any reason other than death:

•: before January 1, 2002, he will receive a lump sum cash payment equal to the total amount deferred during the second five-year period described above, plus interest; or
•: on or after January 1, 2002, he will receive an additional annual benefit for a 15-year period beginning the first January following termination of his employment, but in no event earlier than January 2008 or later than January 2010. This benefit will range from $179,000 per year, if payment begins in January 2008, to $247,000 per year if payment begins in January 2010.

Comparable amounts are payable if Mr. Rogers' dies:

•: prior to January 1, 2002 while employed or disabled, or
•: on or after January 1, 2002, but before payment of benefits begins.

If Mr. Rogers becomes disabled prior to the completion of the second award period, his benefits for that period will be proportionately reduced to take into account the deferred compensation not yet credited for the remainder of the period.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

Mr. Schiff, who is Chairman of the Board, President and Chief Executive Officer of Cincinnati Financial Corporation (an insurance holding company), serves on the Cinergy Compensation Committee. Mr. Randolph, who serves as Chairman of the Board of Cinergy and its principal subsidiaries, including PSI, is a member of the board of directors of Cincinnati Financial Corporation.

RELATIONSHIP WITH INDEPENDENT PUBLIC ACCOUNTANTS

Arthur Andersen LLP served as independent public accountants for Cinergy and its subsidiaries, including PSI, for 1999. Cinergy's board of directors, at the recommendation of its Audit Committee, has re- appointed Arthur Andersen LLP as independent public accountants for Cinergy and its subsidiaries for 2000. Representatives of Arthur Andersen LLP are expected to be present at the Annual Meeting. They will have an opportunity to make a statement, if they desire to do so, and will be available to respond to appropriate questions.

PROPOSALS AND BUSINESS BY SHAREHOLDERS

If you wish to submit a proposal for inclusion in the information statement for our 2001 annual meeting of shareholders, we must receive it by November 22, 2000. In addition, if you wish to introduce business at our 2001 annual meeting (besides that in the Notice of the meeting), you must send us written notice of the matter. Your notice must comply with the requirements of our By-Laws, and we must receive it no earlier than February 12, 2001 and no later than March 8, 2001. Your proposal or notice should be mailed to PSI's Secretary at 1000 East Main Street, Plainfield, Indiana 46168.

By Order of the Board of Directors,

Cheryl M. Foley
Vice President and Secretary

Dated: March 22, 2000

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APPENDIX A

CINERGY CORP.
1999 FINANCIAL REPORT

TABLE OF CONTENTS

Cautionary Statements Regarding Forward-Looking Information		A-1
Review of Financial Condition and Results of Operations		A-2
Consolidated Statements of Income		A-24
Consolidated Balance Sheets		A-25
Consolidated Statements of Changes in Common Stock Equity		A-27
Consolidated Statements of Cash Flows		A-28
Consolidated Statements of Capitalization		A-29
Notes to Consolidated Financial Statements		A-32
Responsibility for Financial Statements		A-56
Report of Independent Public Accountants		A-57
Five Year Statistical Summary		A-59

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").

CAUTIONARY STATEMENTS
REGARDING FORWARD-LOOKING INFORMATION

The "Review of Financial Condition and Results of Operations" section discusses various matters that should make management's corporate vision of the future more clear for you. Management's goals and aspirations are outlined and specific projections may be made. These goals and projections are considered forward-looking statements and are based on management's beliefs and assumptions.

Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ are often presented with forward- looking statements. In addition, other factors could cause actual results to differ materially from those indicated in any forward-looking statement. These include:

•: Factors affecting operations, such as:

(1) unusual weather conditions;

(2) catastrophic weather-related damage;

(3) unscheduled generation outages;

(4) unusual maintenance or repairs;

(5) unanticipated changes in fossil fuel costs, gas supply costs, or availability constraints;

(6) environmental incidents; and

(7) electric transmission or gas pipeline system constraints.

•: Legislative and regulatory initiatives regarding deregulation of the industry, including Ohio's comprehensive deregulation legislation and the outcome of The Cincinnati Gas & Electric Company's (CG&E) Proposed Transition Plan.
•: The timing and extent of the entry of additional competition in electric or gas markets and the effects of continued industry consolidation through the pursuit of mergers, acquisitions, and strategic alliances.
•: Regulatory factors such as changes in the policies or procedures that set rates, changes in our ability to recover investments made under traditional regulation through rates, and changes to the frequency and timing of rate increases.
•: Financial or regulatory accounting principles or policies imposed by governing bodies.
•: Political, legal, and economic conditions and developments in the United States (U.S.) and the foreign countries in which we have a presence. This would include inflation rates and monetary fluctuations.
•: Changing market conditions and other factors related to physical energy and financial trading activities. These would include price, basis, credit, liquidity, volatility, capacity, transmission, currency exchange rates, interest rates, and warranty risks.
•: The performance of projects undertaken by our non-regulated businesses and the success of efforts to invest in and develop new opportunities.
•: Availability of, or cost of capital.
•: Employee workforce factors, including changes in key executives, collective bargaining agreements with union employees, and work stoppages.
•: Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures.
•: Costs and effects of legal and administrative proceedings, settlements, investigations, and claims. Examples can be found in Note 12 of the Notes to Financial Statements.
•: Changes in international, federal, state, or local legislative requirements, such as changes in tax laws, tax rates, and environmental laws and regulations.
•: Potential remaining challenges related to Year 2000 readiness.

Unless we otherwise have a duty to do so, the SEC's rules do not require forward-looking statements to be revised or updated (whether as a result of changes in actual results, changes in assumptions, or other factors affecting the statements). Our forward-looking statements reflect our best beliefs as of the time they are made and may not be updated for subsequent developments.

REVIEW OF FINANCIAL
CONDITION AND RESULTS OF
OPERATIONS

INTRODUCTION

In the "Review of Financial Condition and Results of Operations" section, 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 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, 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.)

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; and
•: cash from ongoing operating activities.

For further detail regarding the classification of these items, see our Consolidated Statements of Cash Flows.

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 (NO_X) 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 NO_X reduction requirements, we (1) have changed the burners on our generating units, and (2) are using a system-wide NO_X 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.)

NO_X SIP Call In October 1998, the EPA finalized its ozone transport rule, also known as the NO_X 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 NO_X emission allowance trading program. If implemented by the states, the trading program would allow us to buy NO_X emission allowances from, or sell NO_X emission allowances to, other companies as necessary. This rule recommends that states reduce NO_X 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 NO_X 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 NO_X 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 NO_X 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 NO_X emissions requirements through a 12-state trading program.

In December 1999, the EPA granted four Section 126 petitions relating to NO_X 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 NO_X 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 NO_X reduction work that would be required under the NO_X SIP Call. In the event the EPA successfully implements either program (the NO_X 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 NO_X 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 NO_X 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 NO_X reductions, on May 21, 1999, the EPA published a proposed rule to extend the attainment date to 2003, if the states enact adequate regional NO_X reductions.

The SIP amendments call for, among other things, statewide NO_X reductions from utilities in Indiana, Kentucky, and surrounding states which are less stringent than the EPA's NO_X SIP Call. The states of Indiana and Kentucky have committed to adopt utility NO_X 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 NO_X 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 NO_X reductions called for in the EPA's final NO_X SIP Call would address both the one-hour ozone standard and the new eight-hour ozone standard. With the recent challenges to the NO_X SIP Call and the eight-hour ozone standard (discussed below), it is unclear to what extent additional NO_X 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 NO_X 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.

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). 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 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. 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 PSIthat 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 above. 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 for a more detailed discussion of the status of these environmental issues.

CONSTRUCTION AND OTHER COMMITMENTS

Construction Our actual construction expenditures for 1999 were $386 million. Our forecasted construction expenditures in nominal dollars for 2000 are $495 million, and are $2,002 million for the next five years (2000-2004).

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 NO_X emission control standards associated with the 22-state NO_X SIP Call and Section 126 petitions (as discussed in the "Environmental Issues" section). In the event the EPA successfully implements either program (the NO_X 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 and the "Retail Market Developments" section. 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 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.) 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 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. 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.

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:

Authorizing Agency (in millions)	CG&E		PSI

Applicable State Utility Commission
(Secured or Unsecured Debt)	$	200	$	400

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:

(in millions)	CG&E		PSI

First Mortgage Bonds and Other Secured Notes	$	300	$	265
Senior or Junior Unsecured Debt		50		400

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 and $100 million for PSI.

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:

(in millions)	1999	1998	1997

Purchased Shares	748	861	1,700
Issued Shares	291	194	66

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 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.

SECURITIES RATINGS

As of February 29, 2000, the major credit rating agencies rated our securities as follows:

	D&P⁽¹⁾	Fitch⁽²⁾	Moody's⁽³⁾	S&P⁽⁴⁾

Cinergy Corp.
Corporate Credit	BBB+	BBB+	Baa2	BBB+
Commercial Paper	D-2	F-2	P-2	A-2
CG&E
Secured Debt	A-	A-	A3	A-
Senior Unsecured Debt	BBB+	BBB+	Baa1	BBB+
Junior Unsecured Debt	BBB	BBB+	Baa2	BBB
Preferred Stock	BBB	BBB+	Baa1	BBB
Commercial Paper	D-1-	F-1	P-2	Not Rated
PSI
Secured Debt	A-	A-	A3	A-
Senior Unsecured Debt	BBB+	BBB+	Baa1	BBB+
Junior Unsecured Debt	BBB	BBB	Baa1	BBB
Preferred Stock	BBB	BBB	Baa1	BBB
Commercial Paper	D-1-	F-1	P-2	Not Rated
ULH&P
Secured Debt	A-	Not Rated	Not Rated	A-
Unsecured Debt	Not Rated	Not Rated	Baa1	BBB+

(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 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.

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.

RESULTS OF OPERATIONS

SUMMARY OF RESULTS

Electric and gas margins and net income for the years ended December 31, 1999, 1998, and 1997, were as follows:

(in thousands)	1999		1998		1997

Electric gross margin	$	2 052 602	$	1 909 423	$	1 948 905
Gas gross margin		212 153		204 684		227 398
Net income		403 641		260 968		253 238

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 1998 charges discussed below.

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 for a discussion of the windfall profits tax.)

Our 1998 EPS reflects the following charges:

•: 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 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 our Consolidated Statements of Income. However, only the line items that varied significantly from prior periods are discussed.

ELECTRIC OPERATING REVENUES

(in millions)	1999		1998		1997

Retail	$	2 725	$	2 553	$	2 455
Wholesale		1 455		2 140		1 368
Other		133		70		39

Total	$	4 313	$	4 763	$	3 862

Electric operating revenues decreased 7% 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.

Electric operating revenues increased 4% 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

(in millions)	1999		1998		1997

Non-regulated	$	1 221	$	698	$	29
Retail		320		357		454
Transportation		51		41		33
Other		4		4		4

Total	$	1 596	$	1 100	$	520

Gas operating revenues increased 75% 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. Partially offsetting this increase was a decline in retail mcf sales resulting primarily from milder weather experienced during the first quarter of 1999. Transportation revenues increased 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.

Gas operating revenues increased for 1998, when compared to 1997, primarily due to the gas operating revenues of Marketing & Trading. Partially offsetting this increase was an overall decrease in retail sales 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. 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

(in millions)	1999		1998		1997

Fuel	$	761	$	730	$	693
Purchased and exchanged power		1 499		2 124		1 220
Gas purchased		1 384		895		292
Operation		775		784		667
Maintenance		206		192		177
Depreciation and amortization		354		326		307
Taxes other than income taxes		266		275		265

Total	$	5 245	$	5 326	$	3 621

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 for the years ended December 31, 1999, and 1998:

(in millions)	1999			1998

Prior year's fuel expense	$	730		$	693
Increase (Decrease) due to changes in:
Price of fuel		—			(23	)
Deferred fuel cost		(10	)		22
kWh generation		28			29
Other		13			9

Current year's fuel expense	$	761		$	730

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 29% in 1999, 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.

Purchased and exchanged power expense increased 74% in 1998, primarily due to 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 of unrealized losses related to our energy marketing and trading activity.

(See the "Market Risk Sensitive Instruments and Positions" section and Note 1(j) of the Notes to Financial Statements for discussions on our energy marketing and trading operations.)

Gas Purchased

Gas purchased expense increased 55% 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". Partially offsetting this increase was the decline in Gas purchased expense for CG&E, mainly due to decreased sales volume as previously indicated above in "Gas Operating Revenues".

Gas purchased expense increased in 1998, primarily due to the Gas purchased expense of Marketing & Trading. Slightly offsetting this increase was a decrease in CG&E's Gas purchased expense because of a decline in the volumes purchased, due to lower

demand, and a lower average cost per mcf of gas purchased.

Operation

Operation costs decreased 1% 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 PSI's 1989 settlement with WVPA. (See Note 18 of the Notes to Financial Statements for a discussion of the WVPA settlement.)

Operation costs increased 18% in 1998, as compared to 1997. These increases primarily relate to the 1989 settlement with WVPA discussed above. Additionally, the increase was also the result of additional costs related to new initiatives of the non-regulated businesses.

Maintenance

Maintenance costs increased 7% 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.

Maintenance costs increased 8% 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

Depreciation and amortization costs increased 9% in 1999, as compared to 1998, and increased 6% in 1998, as compared to 1997. These increases were the result of additions to depreciable plant in 1999 and 1998. Additionally, the 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

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.

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.

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.

INCOME TAXES

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

Preferred dividend requirements of subsidiaries decreased $1 million (16%) for 1999, as compared to 1998, and decreased $6 million (48%) for 1998, as compared to 1997. These decreases were attributable to 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.)

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 expiration 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.

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'sgenerating 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.

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" 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'sretail 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. 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:

(in millions)	Interest Benchmark	1999		1998

Short-term Bank Loans/Commercial Paper	• Short-term Money Market	$	283	$	637
Pollution Control Debt	• Daily Market		267		267
Sale of Accounts Receivable	• Short-term Money Market		257		253
Woodsdale Capital Lease	• LIBOR⁽¹⁾		22		22

(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:

	1999		1998

Short-term Bank Loans/Commercial Paper	6.2	%	6.0	%
Pollution Control Debt	4.1	%	4.0	%
Sale of Accounts Receivable	6.1	%	6.0	%
Woodsdale Capital Lease	5.3	%	5.3	%

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:

	Expected Maturity Date
(in millions)	2000			2001			2002			2003			2004			Thereafter			Total			Fair Value

Liabilities
Long-term Debt⁽¹⁾	$	132	⁽⁶⁾	$	90	⁽⁴⁾	$	124		$	177	⁽⁵⁾	$	311		$	2 177		$	3 011		$	2 798
Weighted-average interest rate⁽²⁾		6.2	%		5.2	%		7.3	%		6.2	%		6.2	%		7.0	%		6.8	%
Other⁽³⁾	$	.9		$	1.0		$	1.1		$	1.3		$	1.5		$	16.6		$	22.4		$	22.4
Weighted-average interest rate⁽²⁾		8.4	%		8.4	%		8.4	%		8.4	%		8.4	%		8.4	%		8.4	%
Capital Lease
Fixed rate	$	.7		$	.7		$	.8		$	.8		$	.9		$	6.1		$	10.0		$	10.0
Interest rate		6.7	%		6.7	%		6.7	%		6.7	%		6.7	%		6.7	%		6.7	%
Variable rate		–		$	22			–			–			–			–		$	22		$	22
Weighted-average interest rate⁽²⁾		–			5.3	%		–			–			–			–			5.3	%

(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.

DISPOSITIONS

During 1999, we sold our 50% ownership interest in Avon Energy to GPU. See Note 10 of the Notes to Financial Statements 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.

(in thousands, except per share amounts)	1999		1998			1997

Operating Revenues
Electric	$	4 312 899	$	4 763 289		$	3 861 698
Gas		1 596 146		1 099 629			519 536
Other		28 843		48 373			5 867

Total Operating Revenues		5 937 888		5 911 291			4 387 101
Operating Expenses
Fuel and purchased and exchanged power		2 260 297		2 853 866			1 912 793
Gas purchased		1 383 993		894 945			292 138
Operation and maintenance		981 054		976 289			843 887
Depreciation and amortization		353 820		326 492			306 922
Taxes other than income taxes		265 501		274 635			265 693

Total Operating Expenses		5 244 665		5 326 227			3 621 433
Operating Income		693 223		585 064			765 668
Equity in Earnings of Unconsolidated Subsidiaries		58 021		51 484			60 392
Gain on Sale of Investment in Unconsolidated Subsidiary (Note 10)		99 272		—			—
Miscellaneous—Net		2 031		(8 289	)		(1 534	)
Interest		234 778		243 587			236 319

Income Before Taxes		617 769		384 672			588 207
Income Taxes (Note 11)		208 671		117 187			213 000
Preferred Dividend Requirements of Subsidiaries		5 457		6 517			12 569

Net Income Before Extraordinary Item	$	403 641	$	260 968		$	362 638
Extraordinary Item—Equity Share of Windfall Profits Tax (Less Applicable Income Taxes of $0) (Note 17)		—		—			(109 400	)

Net Income	$	403 641	$	260 968		$	253 238
Average Common Shares Outstanding		158 863		158 238			157 685
Earnings Per Common Share (Note 16)
Net income before extraordinary item		$2.54		$1.65			$2.30
Net income		$2.54		$1.65			$1.61
Earnings Per Common Share—Assuming Dilution (Note 16)
Net income before extraordinary item		$2.53		$1.65			$2.28
Net income		$2.53		$1.65			$1.59
Dividends Declared Per Common Share		$1.80		$1.80			$1.80

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.


(dollars in thousands) December 31	1999		1998

ASSETS
Current Assets
Cash and cash equivalents	$	81 919	$	100 154
Restricted deposits		628		3 587
Notes receivable		481		64
Accounts receivable less accumulated provision for doubtful accounts of $26,811 at December 31, 1999, and $25,622 at December 31, 1998 (Note 6)		706 068		580 305
Materials, supplies, and fuel–at average cost		205 749		202 747
Energy risk management assets (Note 1(j))		131 145		283 924
Prepayments and other		77 701		74 849

Total Current Assets		1 203 691		1 245 630
Utility Plant—Original Cost
In service
Electric		9 414 744		9 222 261
Gas		824 427		786 188
Common		189 124		186 364

Total		10 428 295		10 194 813
Accumulated depreciation		4 259 877		4 040 247

Total		6 168 418		6 154 566
Construction work in progress		249 054		189 883

Total Utility Plant		6 417 472		6 344 449
Other Assets
Regulatory assets (Note 1(c))		1 055 012		970 767
Investments in unconsolidated subsidiaries (Note 10)		358 853		574 401
Energy risk management assets (Note 1(j))		26 624		73 662
Other		555 296		478 472

Total Other Assets		1 995 785		2 097 302
Total Assets	$	9 616 948	$	9 687 381

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.


(dollars in thousands) December 31	1999			1998

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	734 937		$	668 860
Accrued taxes		219 266			228 347
Accrued interest		49 354			51 679
Notes payable and other short-term obligations (Note 5)		550 194			903 700
Long-term debt due within one year (Note 4)		31 000			136 000
Energy risk management liabilities (Note 1(j))		126 682			398 538
Other		76 774			93 376

Total Current Liabilities		1 788 207			2 480 500
Non-Current Liabilities
Long-term debt (Notes 4 and 18)		2 989 242			2 604 467
Deferred income taxes (Note 11)		1 174 818			1 091 075
Unamortized investment tax credits		147 550			156 757
Accrued pension and other postretirement benefit costs (Note 9)		355 917			315 147
Energy risk management liabilities (Note 1(j))		132 041			107 194
Other		282 855			298 370

Total Non-Current Liabilities		5 082 423			4 573 010
Total Liabilities		6 870 630			7 053 510
Cumulative Preferred Stock of Subsidiaries (Note 3)
Not subject to mandatory redemption		92 597			92 640
Common Stock Equity (Note 2)
Common Stock–$.01 par value; authorized shares–600,000,000; outstanding shares–158,923,399 in 1999 and 158,664,532 in 1998		1 589			1 587
Paid-in capital		1 597 554			1 595 237
Retained earnings		1 064 319			945 214
Accumulated other comprehensive income (loss)		(9 741	)		(807	)

Total Common Stock Equity		2 653 721			2 541 231
Commitments and Contingencies (Note 12)
Total Liabilities and Shareholders' Equity	$	9 616 948		$	9 687 381

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

(dollars in thousands)	Common Stock			Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Stock Equity

1997
Beginning balance	$	1 577		$	1 590 735		$	993 526		$	(1 384	)	$	2 584 454
Comprehensive income:
Net income								253 238						253 238
Other comprehensive income (loss), net of tax effect of $1,595
Foreign currency translation adjustment											(394	)		(394	)
Minimum pension liability adjustment											(1 083	)		(1 083	)

Total comprehensive income														251 761
Issuance of 65,529 shares of common stock-net					2 066									2 066
Treasury shares purchased		(11	)		(46 199	)								(46 210	)
Treasury shares reissued		11			21 975									21 986
Dividends on common stock (see page A-24 for per share amounts)								(283 866	)					(283 866	)
Other					4 487			4 522						9 009

Ending balance	$	1 577		$	1 573 064		$	967 420		$	(2 861	)	$	2 539 200
1998
Comprehensive income:
Net income								260 968						260 968
Other comprehensive income (loss), net of tax effect of $(1,813)
Foreign currency translation adjustment											2 160			2 160
Minimum pension liability adjustment											(106	)		(106	)

Total comprehensive income														263 022
Issuance of 919,874 shares of common stock-net		10			30 225									30 235
Treasury shares purchased		(3	)		(8 205	)								(8 208	)
Treasury shares reissued		3			12 455									12 458
Dividends on common stock (see page A-24 for per share amounts)								(284 703	)					(284 703	)
Other					(12 302	)		1 529						(10 773	)

Ending balance	$	1 587		$	1 595 237		$	945 214		$	(807	)	$	2 541 231
1999
Comprehensive income:
Net income								403 641						403 641
Other comprehensive income (loss), net of tax effect of $5,833
Foreign currency translation adjustment											(9 781	)		(9 781	)
Minimum pension liability adjustment											(1 239	)		(1 239	)
Unrealized gains on grantor and rabbi trusts											2 086			2 086

Total comprehensive income														394 707
Issuance of 258,867 shares of common stock-net		2			6 720									6 722
Treasury shares purchased					(233	)								(233	)
Treasury shares reissued					3 660									3 660
Dividends on common stock (see page A-24 for per share amounts)								(284 545	)					(284 545	)
Other					(7 830	)		9						(7 821	)

Ending balance	$	1 589		$	1 597 554		$	1 064 319		$	(9 741	)	$	2 653 721

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

(dollars in thousands)	1999			1998			1997

Operating Activities
Net income	$	403 641		$	260 968		$	253 238
Items providing or (using) cash currently:
Depreciation and amortization		353 820			326 492			306 922
Wabash Valley Power Association, Inc. settlement		–			80 000			–
Deferred income taxes and investment tax credits – net		96 067			(107 835	)		67 638
Unrealized (gain) loss from energy risk management activities		(47 192	)		135 000			15 000
Equity in earnings of unconsolidated subsidiaries		(44 904	)		(45 374	)		(35 239	)
Gain on sale of investment in unconsolidated subsidiary		(99 272	)		–			–
Allowance for equity funds used during construction		(3 633	)		(1 668	)		(98	)
Regulatory assets – net		(203 224	)		46 856			33 605
Extraordinary item – equity share of windfall profits tax		–			–			109 400
Changes in current assets and current liabilities:
Restricted deposits		2 959			(1 268	)		(598	)
Accounts and notes receivable		(118 561	)		(45 811	)		(217 157	)
Materials, supplies, and fuel		(3 002	)		(33 484	)		21 817
Accounts payable		61 590			44 535			183 296
Accrued taxes and interest		(11 406	)		46 371			(21 414	)
Other items – net		(44 265	)		19 226			17 168

Net cash provided by operating activities		342 618			724 008			733 578
Financing Activities
Change in short-term debt		(353 506	)		(245 413	)		191 811
Issuance of long-term debt		829 948			785 554			100 062
Redemption of long-term debt		(553 191	)		(384 520	)		(336 312	)
Retirement of preferred stock of subsidiaries		(34	)		(85 299	)		(16 269	)
Issuance of common stock		6 722			3 724			2 066
Dividends on common stock		(285 925	)		(283 884	)		(283 866	)

Net cash used in financing activities		(355 986	)		(209 838	)		(342 508	)

Investing Activities
Construction expenditures (less allowance for equity funds used during construction)		(386 293	)		(368 609	)		(328 055	)
Acquisition of businesses (net of cash acquired)		(24 500	)		(63 412	)		–
Investments in unconsolidated subsidiaries		(284 343	)		(35 305	)		(29 032	)
Sale of investment in unconsolidated subsidiary		690 269			–			–

Net cash used in investing activities		(4 867	)		(467 326	)		(357 087	)
Net increase (decrease) in cash and cash equivalents		(18 235	)		46 844			33 983
Cash and cash equivalents at beginning of period		100 154			53 310			19 327

Cash and cash equivalents at end of period	$	81 919		$	100 154		$	53 310
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized)	$	232 019		$	236 982		$	241 349
Income taxes	$	130 179		$	179 677		$	140 655

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

(dollars in thousands)December 31	1999			1998

LONG-TERM DEBT (excludes current portion)
Cinergy Corp.
Other Long-term Debt:
6.53% Debentures due December 16, 2008	$	200 000		$	200 000
6.125% Debentures due April 15, 2004		200 000			–
Total other long-term debt		400 000			200 000
Unamortized Discount		(333	)		(87	)

Total–Cinergy Corp.		399 667			199 913
Cinergy Global Resources, Inc.
Other Long-term Debt:
6.20% Debentures due November 3, 2008		150 000			150 000
Variable interest rate set at 7.56% commencing August 6, 1999, due July 6, 2012		15 300			–
Variable interest rate set at 8.44% commencing August 6, 1999, due July 6, 2009		7 100			–
Other		–			9 443

Total other long-term debt		172 400			159 443
Unamortized Discount		(293	)		(326	)

Total-Cinergy Global Resources, Inc.		172 107			159 117
CG&E and Subsidiaries
CG&E
First Mortgage Bonds:
7¹/4% Series due September 1, 2002		100 000			100 000
6.45% Series due February 15, 2004		110 000			110 000
7.20% Series due October 1, 2023		265 500			300 000
5.45% Series due January 1, 2024 (Pollution Control)		46 700			46 700
5¹/2% Series due January 1, 2024 (Pollution Control)		48 000			48 000

Total first mortgage bonds		570 200			604 700
Pollution Control Notes:
6.50% due November 15, 2022		12 721			12 721
Other Long-term Debt:
Liquid Asset Notes with Coupon Exchange
(LANCE) due October 1, 2007; (Redeemable at the option of CG&E)
(Variable interest rate set at 6.50% commencing October 1, 1999)
(Holders of not less than 66²/3% in an aggregate principal amount of the LANCEs have the one-time right to convert from the 6.50% fixed rate to a London Interbank Offered Rate (LIBOR)-based floating rate at any interest rate payment date between October 1, 1999 and October 1, 2002)		100 000			100 000
6.40% Debentures due April 1, 2008		100 000			100 000
6.90% Debentures due June 1, 2025 (Redeemable at the option of the holders on June 1, 2005)		150 000			150 000
8.28% Junior Subordinated Debentures due July 1, 2025		100 000			100 000
6.35% Debentures due June 15, 2038 (Interest rate resets June 15, 2003)		100 000			100 000
Total other long-term debt		550 000			550 000
Unamortized Premium and Discount – Net		(2 762	)		(3, 396	)

Total – CG&E		1 130 159			1 164 025

(dollars in thousands)			December 31	1999			1998

ULH&P	Other Long-term Debt: 6.11%		Debentures due December 8, 2003		20 000			20 000
		6.50%	Debentures due April 30, 2008		20 000			20 000
		7.65%	Debentures due July 15, 2025		15 000			15 000
		7.875%	Senior Unsecured Debentures due September 15, 2009		20 000			–

			Total other long-term debt		75 000			55 000
	Unamortized Premium and Discount—Net				(443	)		(447	)

			Total—ULH&P		74 557			54 553
Lawrenceburg Gas
Company	First Mortgage Bonds: 9³/4%		Series due October 1, 2001		1 200			1 200

			Total—CG&E and Subsidiaries		1 205 916			1 219 778
PSI	First Mortgage Bonds:	Series TT,7³/8%,	due March 15, 2012 (Pollution Control)		10 000			10 000
		Series UU,7¹/2%,	due March 15, 2015 (Pollution Control)		14 250			14 250
		Series YY,5.60%,	due February 15, 2023 (Pollution Control)		29 945			29 945
		Series ZZ,5³/4%,	due February 15, 2028 (Pollution Control)		50 000			50 000
		Series AAA,7¹/8%,	due February 1, 2024		30 000			50 000
		Series BBB,8.0%,	due July 15, 2009		124 665			–
		Series CCC,8.850%,	due January 15, 2022		53 055			–
		Series DDD,8.310%,	due September 1, 2032		38 000			–

		Total first mortgage bonds			349 915			154 195
	Secured Medium-term Notes:	Series A, 7.61%	to 8.81%, due November 1, 2001 to June 1, 2022		75 800			284 000
		Series B,5.93%	to 8.24%, due September 17, 2003 to August 22, 2022		126 000			195 000
			(Series A and B, 7.019% weighted average interest rate and 14 year weighted average remaining life)

		Total secured medium-term notes			201 800			479 000
	Other Long-term Debt:	Series 1994A Promissory Note, non-interest bearing, due January 3, 2001			19 825			19 825
		6.35%	Debentures due November 15, 2006 *(Redeemable in whole or in part at the option of the holders on November 15, 2000)*		100 000			100 000
		6.00%	Debentures due December 14, 2016 *(Redeemable in whole or in part at the option of the holders on December 14, 2001)*		50 000			50 000
		6.50%	Synthetic Putable Yield Securities due August 1, 2026		50 000			50 000
		7.25%	Junior Maturing Principal Securities due March 15, 2028		2 658			100 000
		6.00%	Rural Utilities Service (RUS) Obligation payable in annual installments (Note 18)		84 798			85 620
		6.52%	Senior Notes due March 15, 2009		97 342			—
		7.85%	Debentures due October 15, 2007		265 000			—

		Total other long-term debt			669 623			405 445
	Unamortized Premium and Discount—Net				(9 786	)		(12 981	)

		PSI—Total			1 211 552			1 025 659

		Total Consolidated Long-term Debt		$	2 989 242		$	2 604 467

CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES

							December 31
(dollars in thousands)							1999		1998

Company	Par/Stated Value		Authorized Shares	Shares Outstanding	Series	Mandatory Redemption

CG&E	$	100	6 000 000	206 859	4%–4³/4%	No	$	20 686	$	20 717
PSI	$	100	5 000 000	639 626	3¹/2%–6⁷/8%	No		63 963		63 975
PSI	$	25	5 000 000	317 924	4.16%–4.32%	No		7 948		7 948

Total cumulative preferred stock							$	92 597	$	92 640

COMMON STOCK EQUITY
Common Stock–$.01 par value; authorized shares–600 000 000; outstanding shares–158 923 399 in 1999 and 158 664 532 in 1998	$	1 589		$	1 587
Paid-in capital		1 597 554			1 595 237
Retained earnings		1 064 319			945 214
Accumulated other comprehensive income (loss)		(9 741	)		(807	)

Total common stock equity		2 653 721			2 541 231
Total Capitalization	$	5 735 560		$	5 238 338

The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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).

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

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 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; and
•: our percentage share of the earnings from the entity as Equity in earnings of unconsolidated subsidiaries in our Consolidated Statements of Income.

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 our consolidated financial statements 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 Consolidated Balance Sheets.

Our regulatory assets and amounts authorized for recovery through regulatory orders at December 31, 1999, and 1998, are as follows:

	1999						1998

(in millions)	CG&E⁽¹⁾		PSI		Cinergy		CG&E⁽¹⁾		PSI		Cinergy

Amounts due from customers–income taxes⁽²⁾	$	276	$	18	$	294	$	331	$	26	$	357
Dynegy gas services agreement buyout costs⁽³⁾		—		250		250		—		—		—
Post-in-service carrying costs and deferred operating expenses		121		42		163		128		43		171
Coal contract buyout cost⁽⁴⁾		—		77		77		—		99		99
Deferred demand-side management (DSM)		38		11		49		40		43		83
Phase-in deferred return and depreciation⁽⁵⁾		54		—		54		75		—		75
Deferred merger costs		15		65		80		16		69		85
Unamortized costs of reacquiring debt		31		30		61		34		29		63
Coal gasification services expenses		—		16		16		—		19		19
Other		1		10		11		3		16		19

Total regulatory assets	$	536	$	519	$	1 055	$	627	$	344	$	971
Authorized for recovery⁽⁶⁾	$	467	$	489	$	956	$	553	$	334	$	887

(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 Consolidated 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 Consolidated 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.

	1999		1998		1997

CG&E and its subsidiaries
Electric	2.9	%	2.9	%	2.9	%
Gas	2.9		2.9		2.9
Common	2.7		2.6		3.0
PSI	3.0		3.0		3.0

(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:

	1999		1998		1997

Cinergy average	7.3	%	6.6	%	6.3	%
CG&E and its subsidiaries average	8.0		7.1		6.4
PSI average	6.5		5.6		5.9

The borrowed funds component of AFUDC, which is recorded on a pre-tax basis, is as follows:

(in millions)	1999		1998		1997

Cinergy	$	5.6	$	7.5	$	5.4
CG&E and its subsidiaries		3.4		5.5		4.6
PSI		2.2		2.0		0.8

(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 Consolidated 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

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:

(in millions)	1999		1998		1997

CG&E and its subsidiaries	$	208	$	207	$	254
PSI		168		183		218

At December 31, 1999, and 1998, the Balance Sheets of our operating companies included the following amounts payable to Services:

(in millions)	1999		1998

CG&E and its subsidiaries	$	23	$	11
PSI		7		9

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.

	Shares Reserved at Dec. 31, 1999	Shares Issued
	Shares Reserved at Dec. 31, 1999	1999	1998	1997

Cinergy Corp. 1996 Long-term Incentive Compensation Plan (LTIP)	6 956 386	–	–	43 614
Cinergy Corp. Stock Option Plan	4 110 358	255 828	192 591	22 219
Cinergy Corp. Employee Stock Purchase and Savings Plan	1 931 112	266	1 006	–
Cinergy Corp. UK Sharesave Scheme	75 000	–	–	–
Cinergy Corp. Retirement Plan for Directors	175 000	–	–	–
Cinergy Corp. Directors' Equity Compensation Plan	75 000	–	–	–
Cinergy Corp. Directors' Deferred Compensation Plan	200 000	–	–	–
Cinergy Corp. 401k Plans	6 469 373	–	–	–
Cinergy Corp. Dividend Reinvestment and Stock Purchase Plan	1 798 486	–	–	–
Cinergy Corp. Performance Shares Plan (PSP)	736 751	34 550	–	–

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.

(b) DIVIDEND RESTRICTIONS

Cinergy Corp. owns all of the common stock of CG&E and PSI. 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's and 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:

	Shares Subject to Option		Weighted Average Exercise Price

Balance at December 31, 1996	–			–
Options granted	369 600		$	33.60

Balance at December 31, 1997	369 600			33.60
Options granted	471 400			38.19
Options forfeited	(68 000	)		36.06

Balance at December 31, 1998	773 000			36.19
Options granted	2 663 600			25.48
Options forfeited	(59 500	)		35.65

Balance at December 31, 1999	3 377 100		$	27.75

Options Exercisable:
At December 31, 1998	11 600		$	36.05
At December 31, 1999	88 600		$	35.78

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:

	1999		1998		1997

Risk-free interest rate	6.1	%	5.6	%	6.2	%
Expected dividend yield	7.2	%	4.8	%	5.4	%
Expected lives	5.5	yrs.	5.6	yrs.	5.4	yrs.
Expected common stock variance	3.8	%	1.8	%	1.7	%

Price ranges, along with certain other information, for the options outstanding under the LTIP at December 31, 1999, are as follows:

	Outstanding				Exercisable
Exercise Price Range	Number	Weighted Average Exercise Price		Weighted Average Contractual Life	Number	Weighted Average Exercise Price

$23.81–$23.88	2 232 900	$	23.81	10.0 yrs.	—	$	—
$33.31–$34.50	744 500	$	33.88	8.3 yrs.	52 600	$	33.86
$35.91–$38.59	399 700	$	38.33	8.0 yrs.	36 000	$	38.59

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.

Cycle	Performance Period	Target Grant of Shares

		(in thousands)
II	2000	120
III	2000-2001	241
IV	2000-2002	362

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:

	Shares Subject to Option		Weighted Average Exercise Price

Balance at December 31, 1996	3 334 637		$	23.57
Options exercised	(380 162	)		21.71

Balance at December 31, 1997	2 954 475			23.79
Options granted	480 000			36.88
Options exercised	(430 961	)		21.62
Options forfeited	(100 000	)		26.92

Balance at December 31, 1998	2 903 514			26.17
Options granted	152 500			24.66
Options exercised	(259 865	)		21.51
Options forfeited	(36 000	)		25.89

Balance at December 31, 1999	2 760 149		$	26.53
Options Exercisable:
At December 31, 1997	1 389 975		$	22.58
At December 31, 1998	1 535 514			23.61
At December 31, 1999	1 898 149			24.67

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:

	1999		1998

Risk-free interest rate	6.2	%	5.6	%
Expected dividend yield	7.3	%	4.8	%
Expected lives	6.5	yrs.	6.5	yrs.
Expected common stock variance	3.9	%	2.0	%

Price ranges, along with certain other information, for options outstanding under the Stock Option Plan at December 31, 1999, are as follows:

	Outstanding				Exercisable
Exercise Price Range	Number	Weighted Average Exercise Price		Weighted Average Contractual Life	Number	Weighted Average Exercise Price

$15.09–$22.88	797 647	$	22.61	4.6 yrs.	797 647	$	22.61
$23.81–$25.19	1 193 529	$	24.27	5.7 yrs.	811 029	$	24.33
$28.44–$36.88	768 973	$	34.09	6.3 yrs.	289 473	$	31.30

(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:

	Shares Subject to Option		Weighted Average Exercise Price

Balance at December 31, 1996	—			—
Options granted	338 947		$	31.83
Options exercised	(95	)		31.83
Options forfeited	(12 485	)		31.83

Balance at December 31, 1997	326 367			31.83
Options exercised	(3 342	)		31.83
Options forfeited	(25 651	)		31.83

Balance at December 31, 1998	297 374			31.83
Options granted	368 889			27.73
Options exercised	(266	)		27.73
Options forfeited	(306 692	)		27.73

Balance at December 31, 1999	359 305		$	27.73

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:

	1999		1997

Risk-free interest rate	5.0	%	5.9	%
Expected dividend yield	6.2	%	5.4	%
Expected lives	2.0	yrs.	2.0	yrs.
Expected common stock variance	5.2	%	1.6	%

(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 a schedule of Cumulative preferred stock at December 31, 1999, and 1998.

4. LONG-TERM DEBT

Refer to the Consolidated Statements of Capitalization for a schedule of long-term debt (excluding Long-term debt due within one year, which is reflected in Current liabilities in the Consolidated Balance Sheets) at December 31, 1999, and 1998.

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.

	Cinergy and Subsidiaries (in millions)		CG&E and Subsidiaries		PSI

2000	$	33	$	—	$	31
2001		41		1		39
2002		125		100		24
2003		78		20		57
2004		313		110		1

	$	590	$	231	$	152

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.

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 our Consolidated Balance Sheets.

The following tables summarize our Notes payable and other short-term obligations; but exclude Notes payable to affiliated companies.

Cinergy

	December 31, 1999							December 31, 1998

(in millions)	Established Lines			Outstanding		Weighted Average Rate		Established Lines		Outstanding			Weighted Average Rate

Cinergy Corp.
Committed lines
Acquisition line	$	—		$	—	—		$	160	$	160		5.61	%
Revolving line		600			—	—			600		245		5.68
Uncommitted lines		45			—	—			45		50	⁽¹⁾	5.84
Commercial paper		—			—	—			—		50		5.78
Operating companies
Committed lines		195			120	6.68	%		300		—		—
Uncommitted lines		300			81	6.44			410		95		5.90
Pollution control notes		N/A			267	4.10			N/A		267		3.83
Non-regulated subsidiaries
Revolving lines		14	⁽²⁾		13	6.26			105		5		13.11
Short-term debt		69			69	6.86			33		32		13.11

Cinergy Total				$	550	5.41	%			$	904		5.20	%

(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.

6. SALE OF ACCOUNTS RECEIVABLE

In 1996, CG&E and PSI 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. As of December 31, 1999, $257 million, net of reserves, has been sold. The Accounts receivable on the Consolidated Balance Sheets are net of the amounts sold at December 31, 1999, and 1998.

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:

							Estimated Minimum Payments
	Actual Payments						Estimated Minimum Payments
	Actual Payments																After 2004
(in millions)	1997		1998		1999		2000		2001		2002		2003		2004		After 2004		Total

Cinergy	$	36	$	42	$	50	$	36	$	28	$	18	$	13	$	10	$	35	$	140

(b) CAPITAL LEASES

In February 1999, our operating companies 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. Our operating companies 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:

	Total Minimum Lease Payments

Total minimum lease payments⁽¹⁾	$	13 935
Less: amount representing interest		(3 838	)

Present value of minimum lease payments	$	10 097

(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

(b) FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS

The estimated fair values of other financial instruments were as follows (this information does not claim to be a valuation of the companies as a whole):

	December 31, 1999				December 31, 1998

(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Financial Instruments
First mortgage bonds and other long-term debt (includes amounts reflected as long-term debt due within one year)	$	3 020	$	2 820	$	2 740	$	2 934

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.

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:

	Pension Benefits									Other Postretirement Benefits

(in millions)	1999			1998			1997			1999			1998			1997

Service cost	$	24.8		$	21.8		$	19.8		$	3.5		$	4.1		$	3.1
Interest cost		70.8			71.6			67.8			16.2			16.1			16.3
Expected return on plans' assets		(72.0	)		(66.9	)		(62.8	)		–			–			–
Amortization of transition obligation/(asset)		(1.3	)		(1.3	)		(1.3	)		5.0			5.0			5.0
Amortization of prior service cost		4.5			4.4			4.4			–			–			–
Recognized actuarial (gain) loss		.6			–			(.3	)		.8			.4			.3

Net periodic benefit cost	$	27.4		$	29.6		$	27.6		$	25.5		$	25.6		$	24.7


Actuarial assumptions:
Discount rate		7.50	%		6.75	%		7.50	%		7.50	%		6.75	%		7.50	%
Rate of future compensation increase		4.50			3.75			4.50			N/A			N/A			N/A
Rate of return on plans' assets		9.00			9.00			9.00			N/A			N/A			N/A

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.

	Pension Benefits						Other Postretirement Benefits

(in millions)	1999			1998			1999			1998

Change in benefit obligation
Benefit obligation at beginning of period	$	1 052.1		$	960.3		$	246.5		$	221.9
Service cost		24.8			21.8			3.5			4.1
Interest cost		70.8			71.6			16.2			16.1
Amendments		1.1			1.0			–			–
Actuarial (gain)/loss		(90.3	)		53.6			(18.4	)		17.4
Benefits paid		(56.5	)		(56.2	)		(13.4	)		(13.0	)

Benefit obligation at end of period		1 002.0			1 052.1			234.4			246.5

Change in plan assets
Fair value of plan assets at beginning of period		865.3			888.1			–			–
Actual return on plan assets		137.3			9.9			–			–
Employer contribution		–			23.5			13.4			13.0
Benefits paid		(56.5	)		(56.2	)		(13.4	)		(13.0	)

Fair value of plan assets at end of period		946.1			865.3			–			–

Funded status		(55.9	)		(186.8	)		(234.4	)		(246.5	)
Unrecognized prior service cost		39.9			43.3			–			–
Unrecognized net actuarial (gain)/loss		(180.6	)		(24.1	)		20.1			40.3
Unrecognized net transition (asset)/obligation		(5.8	)		(7.1	)		60.8			65.8

Accrued benefit cost at December 31	$	(202.4	)	$	(174.7	)	$	(153.5	)	$	(140.4	)

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 millions)	One-Percentage- Point Increase		One-Percentage- Point Decrease

Effect on total of service and interest cost components	$	2.8	$	(2.4	)
Effect on postretirement benefit obligation		30.1		(26.2	)

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:

(in millions)		1999		1998

Pension benefit obligations	$	37.0	$	31.4
Pension cost		4.0		4.5

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.

	Year Ended December 31
	1999					1998
(in millions, except for earnings per share)	Net Income			Earnings per Share⁽¹⁾		Net Income			Earnings per Share⁽²⁾

Cinergy	$	404		$	2.54	$	261		$	1.65
Pro forma adjustments:
Equity in earnings of Avon Energy		(58	)				(57	)
Gain on sale of investment in Avon Energy		(99	)				–
Interest expense		21					43
Income taxes		40					(18	)

Pro forma result	$	308		$	1.94	$	229		$	1.45

(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 our net deferred income tax liabilities as of December 31, 1999, and 1998:

(in millions)	1999		1998

Deferred Income Tax Liability
Utility plant	$	1 130.4	$	1 104.2
Unamortized costs of reacquiring debt		20.9		21.2
Deferred operating expenses and carrying costs		43.5		73.3
Amounts due from customers- income taxes		95.6		121.7
Foreign income taxes		2.7		–
Dynegy gas services agreement buyout costs		94.9		–
Other		53.0		73.8

Total Deferred Income Tax Liability		1 441.0		1 394.2
Deferred Income Tax Asset
Unamortized investment tax credits		53.6		57.0
Accrued pension and other benefit costs		88.0		89.0
Net energy risk management liabilities		32.3		54.5
Rural Utilities Service (RUS) obligation		30.7		29.5
Investments in unconsolidated subsidiaries		–		13.1
Other		61.6		60.0

Total Deferred Income Tax Asset		266.2		303.1
Net Deferred Income Tax Liability	$	1 174.8	$	1 091.1

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:

(in millions)	1999			1998			1997

Current Income Taxes
Federal	$	114.0		$	209.0		$	133.3
State		(1.5	)		16.9			12.1

Total Current Income Taxes		112.5			225.9			145.4
Deferred Income Taxes
Federal
Depreciation and other utility plant-related items		24.0			25.3			26.7
Pension and other benefit costs		(10.5	)		(3.3	)		.9
Litigation settlement		–			–			1.8
RUS obligations		–			(22.5	)		(3.5	)
Unrealized energy risk management losses		(5.1	)		(49.4	)		(1.5	)
Fuel costs		4.3			(1.0	)		4.4
Dynegy gas services agreement buyout costs		83.6			–			–
Coal contract buyout		4.2			3.1			5.5
Coal gasification payments		–			–			–
Other items-net		(9.3	)		(43.9	)		40.5

Total Deferred Federal Income Taxes		91.2			(91.7	)		74.8
State		14.2			(7.4	)		2.4
Total Deferred Income Taxes		105.4			(99.1	)		77.2

Investment Tax Credits–Net		(9.2	)		(9.6	)		(9.6	)

Total Income Taxes	$	208.7		$	117.2		$	213.0

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.

(in millions)	1999			1998			1997

Statutory federal income tax provision	$	209.9		$	129.0		$	196.4
Increases (Reductions) in taxes resulting from:
Amortization of investment tax credits		(9.2	)		(9.6	)		(9.6	)
Depreciation and other utility plant-related differences		14.4			10.4			11.7
Preferred dividend requirements of subsidiaries		5.4			2.3			4.4
Foreign tax adjustments		(15.5	)		(20.0	)		(13.2	)
Other–net		(9.0	)		(4.4	)		8.8

Federal income tax expense	$	196.0		$	107.7		$	198.5

12. COMMITMENTS AND CONTINGENCIES

(a) CONSTRUCTION AND OTHER COMMITMENTS

Our forecasted construction expenditures in nominal dollars for 2000 are $495 million, and are $2,002 million for the next five years (2000–2004).

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 (NO_X) 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. 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 NO_X 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 NO_X 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 NO_X reductions with a trading program into their SIPs. The EPA proposed to implement a federal plan to accomplish the equivalent NO_X reductions by May 2003 if the states failed to revise their SIPs. The EPA must approve all SIPs.

In December 1999, the EPA granted four Section 126 petitions relating to NO_X 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 NO_X 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 NO_X reduction work that would be required under the NO_X SIP Call. In the event the EPA successfully implements either program (the NO_X 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 NO_X 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 NO_X 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)). 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.

(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). 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:

(dollars in millions)	Ownership Share		Utility Plant in Service		Accumulated Depreciation		Construction Work in Progress

CG&E
Production:
Miami Fort Station (Units 7 and 8)	64.00	%	$	216	$	125	$	9
W.C. Beckjord Station (Unit 6)	37.50			42		27		1
J.M. Stuart Station⁽¹⁾	39.00			277		135		5
Conesville Station (Unit 4)⁽¹⁾	40.00			75		41		2
William H. Zimmer Station⁽¹⁾	46.50			1 222		311		12
East Bend Station	69.00			333		180		3
Killen Station	33.00			187		96		1
Transmission	Various			65		34		–
PSI
Production:
Gibson (Unit 5)	50.05			214		107		1
Transmission and local facilities	94.68			2		1		–

(1): Station is not operated by CG&E.

14. QUARTERLY FINANCIAL DATA (unaudited)


(in millions, except per share amounts)

Quarter Ended	Operating Revenues			Operating Income			Net Income			Basic Earnings Per Share			Diluted Earnings Per Share

1999
March 31	$	1 402		$	234		$	127		$	.80		$	.80
June 30		1 275			137			59			.37			.37
September 30		1 782	⁽⁷⁾		137	^(2,7)		122	^(1,2,7)		.77	^(1,2,7)		.76	^(1,2,7)
December 31		1 479			185			96			.60			.60

Total	$	5 938		$	693		$	404		$	2.54		$	2.53

1998
March 31	$	1 348		$	226		$	106		$	.67		$	.67
June 30		1 168			3	^(3,4)		(25	) ^(3,4)		(.16	) ^(3,4)		(.16	) ^(3,4)
September 30		1 977			204	⁽⁵⁾		109	⁽⁵⁾		.69	⁽⁵⁾		.69	⁽⁵⁾
December 31		1 418			152	⁽⁶⁾		71	⁽⁶⁾		.45	⁽⁶⁾		.45	⁽⁶⁾

Total	$	5 911		$	585		$	261		$	1.65		$	1.65

(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 after tax or $.36 per share (basic and diluted).
(3): In the second quarter of 1998, we recorded charges of $65 million pretax 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 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 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, or pretax of $.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), 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


(in millions)


	1999

	Cinergy Business Units
	Commodities			Delivery		Cinergy Investments			International		Total		All Other⁽¹⁾		Reconciling Eliminations⁽²⁾			Consolidated

Operating revenues–External customers	$	2 586		$	3 232	$	59		$	61	$	5 938	$	–	$	–		$	5 938
Intersegment revenues		1 857			–		–			–		1 857		–		(1 857	)		–
Depreciation and amortization⁽³⁾		209			138		–			7		354		–		–			354
Equity in earnings of unconsolidated subsidiaries		(2	)		–		–			60		58		–		–			58
Gain on sale of investment in unconsolidated subsidiary		–			–		–			99		99		–		–			99
Interest expense⁽⁴⁾		96			102		4			32		234		1		–			235
Income taxes		70			120		(6	)		25		209		–		–			209
Segment profit (loss)⁽⁵⁾		136			184		(9	)		93		404		–		–			404
Total segment assets		5 042			4 058		130			340		9 570		47		–			9 617
Investments in unconsolidated subsidiaries		257			–		25			77		359		–		–			359
Total expenditures for long-lived assets		131			256		3			–		390		–		–			390

(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.


(in millions)


	1998

	Cinergy Business Units
	Commodities			Delivery		Cinergy Investments			International			Total			All Other⁽¹⁾			Reconciling Eliminations⁽²⁾			Consolidated

Operating revenues–
External customers	$	2 726		$	3 090	$	52		$	43		$	5 911		$	–		$	–		$	5 911
Intersegment revenues		1 782			–		–			–			(1 782	)		–			(1 782	)		–
Depreciation and amortization⁽³⁾		197			127		–			2			326			–			–			326
Equity in earnings of unconsolidated subsidiaries		(1	)		–		(4	)		56			51			–			–			51
Interest expense⁽⁴⁾		95			91		–			51			237			7			–			244
Income taxes		57			90		(6	)		(17	)		124			(7	)		–			117
Segment profit (loss)⁽⁵⁾		94			157		(11	)		32			272			(11	)		–			261
Total segment assets		4 863			3 987		42			752			9 644			43			–			9 687
Investments in unconsolidated subsidiaries		–			–		8			566			574			–			–			574
Total expenditures for long-lived assets		108			242		3			–			353			17			–			370

(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.


(in millions)


	1997

	Cinergy Business Units
	Commodities		Delivery		Cinergy Investments			International			Total			All Other⁽¹⁾			Reconciling Eliminations⁽²⁾			Consolidated

Operating revenues–
External customers	$	1 287	$	3 066	$	32		$	2		$	4 387		$	–		$	–		$	4 387
Intersegment revenues		1 688		–		–			–			1 688			–			(1 688	)		–
Depreciation and amortization⁽³⁾		184		123		–			–			307			–			–			307
Equity in earnings of unconsolidated subsidiaries		–		–		(3	)		63			60			–			–			60
Interest expense⁽⁴⁾		108		88		1			39			236			–			–			236
Income taxes		123		91		(3	)		5			216			(3	)		–			213
Extraordinary item⁽⁵⁾		–		–		–			(109	)		(109	)		–			–			(109	)
Segment profit (loss)⁽⁶⁾		207		148		(7	)		16			364			(1	)		–			363
Total segment assets		4 380		3 870		26			562			8 838			20			–			8 858
Investments in unconsolidated subsidiaries		–		–		3			535			538			–			–			538
Total expenditures for long-lived assets		78		231		6			–			315			13			–			328

(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.

PRODUCTS AND SERVICES

(in millions)
	Revenues
	Utility						Energy Marketing and Trading
Year	Electric		Gas		Total		Electric		Gas		Total		Other		Consolidated

1999	$	2 938	$	420	$	3 358	$	1 375	$	1 176	$	2 551	$	29	$	5 938
1998		2 707		441		3 148		2 056		659		2 715		48		5 911
1997		2 579		491		3 070		1 283		28		1 311		6		4 387

Our products and services focus on providing utility services (the supply of electric energy and gas supply) and energy marketing and trading services.

GEOGRAPHIC AREAS AND LONG-LIVED ASSETS

(in millions)
	Revenues
			International
Year	Domestic		UK⁽¹⁾		All Other⁽²⁾		Total		Consolidated

1999	$	5 877	$	–	$	61	$	61	$	5 938
1998		5 868		–		43		43		5 911
1997		4 385		–		2		2		4 387

(in millions)
	Long-Lived Assets
			International
Year	Domestic		UK⁽¹⁾		All Other⁽²⁾		Total		Consolidated

1999	$	7 841	$	2	$	277	$	279	$	8 120
1998		7 375		501		209		710		8 085
1997		7 264		505		44		549		7 813

(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:

(in millions, except per share amounts)	Income		Shares	EPS

1999
Earnings per common share: Net income	$	404	159	$	2.54
Effect of dilutive securities: Common stock options			–

EPS–assuming dilution: Net income plus assumed conversions	$	404	159	$	2.53
1998
Earnings per common share: Net income	$	261	158	$	1.65
Effect of dilutive securities: Common stock options			1

EPS–assuming dilution: Net income plus assumed conversions	$	261	159	$	1.65
1997
Earnings per common share: Net income before extraordinary item⁽¹⁾	$	363	158	$	2.30
Effect of dilutive securities: Common stock options			1

EPS–assuming dilution: Net income before extraordinary item plus assumed conversions	$	363	159	$	2.28

(1): The after-tax EPS impact of the extraordinary item – equity share of windfall profits tax in 1997 was $.69 for both basic and diluted EPS.

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.

Management is responsible for the accuracy, objectivity, and consistency of the financial statements presented in this report. The Consolidated Financial Statements of Cinergy Corp. (Cinergy) conform to generally accepted accounting principles and have also been prepared to comply with accounting policies and principles prescribed by the applicable regulatory authorities.

To assure the reliability of Cinergy's financial statements, management maintains a system of internal controls. This system is designed to provide reasonable assurance that assets are safeguarded, that transactions are executed with management's authorization, and that transactions are properly recorded so financial statements can be prepared in accordance with the policies and principles previously described.

Cinergy has established policies intended to ensure that employees adhere to the highest standards of business ethics. Management also takes steps to assure the integrity and objectivity of Cinergy's accounts by careful selection of managers, division of responsibilities, delegation of authority, and communication programs to assure that policies and standards are understood.

An internal auditing program is used to evaluate the adequacy of and compliance with internal controls. Although no cost effective internal control system will preclude all errors and irregularities, management believes that Cinergy's system of internal controls provides reasonable assurance that material errors or irregularities are prevented, or would be detected within a timely period.

Cinergy's Consolidated Financial Statements have been audited by Arthur Andersen LLP, which has expressed its opinion with respect to the fairness of the statements. The auditors' examination included a review of the system of internal controls and tests of transactions to the extent they considered necessary to render their opinion.

The Board of Directors, through its audit committee of outside directors, meets periodically with management, internal auditors, and independent auditors to assure that they are carrying out their respective responsibilities. The audit committee has full access to the internal and independent auditors, and meets with them, with and without management present, to discuss auditing and financial reporting matters.

[/S/ JAMES E. ROGERS]

James E. Rogers

President and

Chief Executive Officer

[/S/ MADELEINE W. LUDLOW]

Madeleine W. Ludlow

Vice President and

Chief Financial Officer

To the Board of Directors of Cinergy Corp.:

We have audited the accompanying consolidated balance sheets of Cinergy Corp. (a Delaware Corporation) and its subsidiary companies as of December 31, 1999 and 1998, and the related consolidated statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits 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. and its subsidiary companies 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.

Arthur Andersen LLP
Cincinnati, Ohio,
January 26, 2000

[This page intentionally left blank.]

		1999			1998			1997			1996			1995

Operating Revenues (thousands)		$	5 937 888		$	5 911 291		$	4 387 101		$	3 276 187		$	3 023 431

Net Income (thousands)		$	403 641		$	260 968		$	253 238		$	334 797		$	347 182

Total Assets (thousands)		$	9 616 948		$	9 687 381		$	8 858 153		$	8 724 934		$	8 103 242

Construction Expenditures (Including AFUDC) (thousands)		$	389 926		$	370 277		$	328 153		$	324 238		$	326 869

Capitalization	Common Equity	$	2 653 721		$	2 541 231		$	2 539 200		$	2 584 454		$	2 548 843
($—thousands)	Preferred Stock^(a)
	Subject to Mandatory Redemption		—			—			—			—			160 000
	Not Subject to Mandatory Redemption		92 597			92 640			177 989			194 232			227 897
	Long-term Debt^(a)		2 989 242			2 604 467			2 150 902			2 326 378			2 346 766

	Total Capitalization	$	5 735 560		$	5 238 338		$	4 868 091		$	5 105 064		$	5 283 506

Other Common	Avg Shares Outstanding (millions)		159			158			158			158			157
Stock Data	Avg Shares Outstanding— Assuming Dilution (millions)		159			159			159			159			158
	Earnings Per Share	$	2.54		$	1.65		$	1.61	^(c)	$	2.00	^(b)	$	2.22
	Earnings Per Share—Assuming Dilution	$	2.53		$	1.65		$	1.59	^(c)	$	1.99	^(b)	$	2.20
	Dividends Declared Per Share	$	1.80		$	1.80		$	1.80		$	1.74		$	1.72
	Payout Ratio		70.9	%		109.1	%		111.8	%^(c)		87.0	%^(b)		77.5	%
	Book Value Per Share (year-end)	$	16.70		$	16.06		$	16.10		$	16.39		$	16.17

Degree Day Data	CG&E Heating (30 year average—5,248)		4 750			4 282			5 271			5 611			5 323
	Cooling (30 year average—996)		1 125			1 235			851			916			1 216
	PSI Heating (30 year average—5,609)		4 877			4 440			5 680			5 891			5 578
	Cooling (30 year average—1,014)		1 177			1 250			871			989			1 214

Employee Data	Number of Employees (year-end)		8 950			8 794			7 609			7 973			8 602

GAS OPERATIONS

Gas Revenues	Residential	$	210 557		$	240 297		$	284 516		$	272 303		$	237 576
(thousands)	Commercial		85 169			87 583			121 345			118 994			99 708
	Industrial		13 797			17 320			31 168			30 409			28 979
	Other		11 291			12 888			18 554			20 133			19 740

	Total Sales		320 814			358 088			455 583			441 839			386 003
	Gas Transported		50 895			41 050			32 456			27 679			20 934

	Total Sales & Transported		371 709			399 138			488 039			469 518			406 937
	Total Non-regulated		1 221 755			697 736			28 392			—			—
	Other Gas Revenues		2 682			2 755			3 106			4 517			3 915

	Total Gas	$	1 596 146		$	1 099 629		$	519 537		$	474 035		$	410 852

Gas Sales	Residential		32 790			36 256			41 846			44 721			43 153
(million cu. ft.)	Commercial		14 474			13 999			19 141			21 199			19 664
	Industrial		2 646			2 941			5 240			5 746			6 624
	Other		2 656			2 449			3 162			3 947			4 584

	Total Sales		52 566			55 645			69 389			75 613			74 025
	Gas Transported		39 568			57 881			53 448			48 560			40 543
	Total Non-regulated Sales		529 990			353 054			9 023			—			—

	Total Sales		622 124			466 580			131 860			124 173			114 568

Gas Customers	Residential		387 769			404 417			407 128			397 660			389 165
(Avg)	Commercial		38 033			39 332			41 915			41 499			40 897
	Industrial		1 457			1 569			1 960			1 961			1 959
	Other		1 148			1 227			1 505			1 518			1 558
	Transportation		43 642			15 626			1 205			829			599
	Non-regulated		1 797			497			134			—			—

	Total		473 846			462 668			453 847			443 467			434 178

System Maximum Day Sendout (million cu. ft.)			841			788			932			861			813

Avg Cost Per Mcf Purchased (cents)			304.78	^(d)		364.43	^(d)		380.41			326.50			277.92

Load Factor—Gas			30.0	%		39.5	%		36.1	%		39.5	%		38.7	%

Certain amounts in prior years have been reclassified to conform to the 1999 presentation.

(a): Excludes amounts due within one year.
(b): Includes $.12 per share for the cost of reacquiring 90% of CG&E's preferred stock through a tender offer.
(c): Includes $.69 per share for an extraordinary item (Midlands windfall profit tax).
(d): Excludes Non-regulated numbers. Had they been included the Avg Cost Per Mcf Purchased (cents) would be 369.89 for 1997, 218.28 for 1998, and 224.81 for 1999.

ELECTRIC OPERATIONS		1999			1998			1997			1996			1995

Electric Revenues (thousands)	Residential	$	1 127 289		$	1 028 314		$	984 891		$	996 959		$	965 278
	Commercial		754 965			722 292			689 091			673 181			661 496
	Industrial		725 641			702 208			669 464			657 563			637 090
	Other		117 284			100 017			111 867			110 003			118 458

	Total Retail		2 725 179			2 552 831			2 455 313			2 437 706			2 382 322
	Sales For Resale		1 454 855			2 140 431			1 367 897			296 600			197 943
	Other		49 035			46 399			38 488			34 400			32 314

	Total Regulated Electric		4 229 069			4 739 661			3 861 698			2 768 706			2 612 579
	Total Non-regulated		83 830			23 628			—			—			—

	Total Electric	$	4 312 899		$	4 763 289		$	3 861 698		$	2 768 706		$	2 612 579

Electric Sales (million kwh)	Residential		16 069			14 551			14 147			14 705			14 366
	Commercial		13 102			12 524			12 034			11 802			11 648
	Industrial		18 830			18 093			17 321			16 803			16 264
	Other		1 939			1 815			1 825			1 811			1 795

	Total Retail		49 940			46 983			45 327			45 121			44 073
	Sales For Resale		49 087			77 558			57 454			12 399			7 769

	Total Regulated Electric		99 027			124 541			102 781			57 520			51 842
	Total Non-regulated		796			201			—			—			—

	Total Electric		99 823			124 742			102 781			57 520			51 842

Electric Customers (Avg)	Residential		1 280 658			1 257 853			1 236 974			1 215 782			1 195 323
	Commercial		156 897			153 674			151 093			149 015			147 888
	Industrial		6 486			6 473			6 472			6 470			6 424
	Other		6 746			6 500			6 372			6 265			6 008

	Total		1 450 787			1 424 500			1 400 911			1 377 532			1 355 643

System Capability—Summer (mw)^(a)	Consolidated		11 014			10 936			10 936			11 037			11 133
	CG&E		5 132			5 075			5 075			5 175			5 271
	PSI		5 882			5 861			5 861			5 862			5 862

System Capability—Winter (mw)^(a)	Consolidated		11 221			11 221			11 221			11 221			11 351
	CG&E		5 245			5 245			5 245			5 245			5 374
	PSI		5 976			5 976			5 976			5 976			5 977

System Peak Load (mw)	CG&E		5 041			4 725			4 638			4 452			4 509
	PSI		5 637			5 450			5 313			5 227			5 274

Annual Load Factor—Electric	CG&E		57.3	%		59.0	%		58.4	%		60.5	%		58.8	%
	PSI		59.4	%		59.7	%		59.2	%		59.0	%		57.4	%
Electricity Output (million kwh)	Generated—Net
	CG&E		27 113			26 069			25 329			25 844			23 959
	PSI		32 276			30 851			29 521			26 815			28 499
	Purchased		3 809			3 718			4 073			7 990			2 576

Source of Energy Supply (%)	Coal		91.47	%		90.73	%		90.74	%		85.69	%		93.93	%
	Hydro		0.52	%		0.58	%		0.72	%		0.56	%		0.66	%
	Oil & Gas		1.98	%		2.56	%		1.63	%		0.58	%		0.73	%
	Purchased		6.03	%		6.13	%		6.91	%		13.17	%		4.68	%

Fuel Cost	Per MMBtu	$	1.23		$	1.24		$	1.25		$	1.35		$	1.37

Heat Rate (Btu per kwh sendout)	Consolidated		10 189			10 274			10 190			10 113			10 035
	CG&E		10 161			10 110			9 984			9 816			9 832
	PSI		10 213			10 414			10 369			10 403			10 207

Certain amounts in prior years have been reclassified to conform to the 1999 presentation.

(a): Includes amounts to be purchased, subject to availability, pursuant to agreements with other utilities.

Wisdom is gained looking back.

PSI Energy, Inc. -- 1000 East Main Street -- Plainfield, Indiana 46168

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NOTICE OF ANNUAL MEETING OF SHAREHOLDERS TO BE HELD ON APRIL 27, 2000
INFORMATION STATEMENT
CINERGY CORP. 1999 FINANCIAL REPORT
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
2. COMMON STOCK
7. LEASES
8. FINANCIAL INSTRUMENTS