UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______________ TO _______________. ---------- Commission file number 1-31447 CENTERPOINT ENERGY, INC. (Exact name of registrant as specified in its charter) TEXAS (State or other jurisdiction of 74-0694415 incorporation or organization) (I.R.S. Employer Identification No.) 1111 LOUISIANA HOUSTON, TEXAS 77002 (713) 207-1111 (Address and zip code of principal (Registrant's telephone number, executive offices) including area code) ---------- Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ----- ----- Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No ----- ----- Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No X ----- ----- As of November 1, 2005, CenterPoint Energy, Inc. had 310,106,178 shares of common stock outstanding, excluding 166 shares held as treasury stock.
CENTERPOINT ENERGY, INC. QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2005 TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Item 1. Financial Statements.................................... 1 Statements of Consolidated Operations Three Months and Nine Months Ended September 30, 2004 and 2005 (unaudited)...................................... 1 Consolidated Balance Sheets December 31, 2004 and September 30, 2005 (unaudited)...... 2 Statements of Consolidated Cash Flows Nine Months Ended September 30, 2004 and 2005 (unaudited)................................................ 4 Notes to Unaudited Consolidated Financial Statements......... 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 32 Item 3. Quantitative and Qualitative Disclosures about Market Risk.......................................... 50 Item 4. Controls and Procedures................................. 51 PART II. OTHER INFORMATION Item 1. Legal Proceedings....................................... 52 Item 5. Other Information....................................... 52 Item 6. Exhibits................................................ 58 i
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION From time to time, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify our forward-looking statements by the words "anticipate," "believe," "continue," "could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective," "plan," "potential," "predict," "projection," "should," "will," or other similar words. We have based our forward-looking statements on our management's beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements. The following are some of the factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements: - the timing and amount of our recovery of the true-up components; - state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, constraints placed on our activities or business by the Public Utility Holding Company Act of 1935, as amended (1935 Act), the impact of the repeal of the 1935 Act, changes in or application of laws or regulations applicable to other aspects of our business and actions with respect to: - allowed rates of return; - rate structures; - recovery of investments; and - operation and construction of facilities; - timely rate increases, including recovery of costs; - industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns; - the timing and extent of changes in commodity prices, particularly natural gas; - changes in interest rates or rates of inflation; - weather variations and other natural phenomena; - the timing and extent of changes in the supply of natural gas; - commercial bank and financial market conditions, our access to capital, the cost of such capital, receipt of certain financing approvals under the 1935 Act, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; - actions by rating agencies; - effectiveness of our risk management activities; - inability of various counterparties to meet their obligations to us; - non-payment for our services due to financial distress of our customers, including Reliant Energy, Inc. (formerly named Reliant Resources, Inc.) (RRI); - the outcome of the pending lawsuits against us, Reliant Energy, Incorporated and RRI; ii
- the ability of RRI to satisfy its obligations to us, including indemnity obligations; - our ability to control costs; - the investment performance of our employee benefit plans; - our potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or to have the anticipated benefits to us; and - other factors we discuss in "Risk Factors" in Item 5 of Part II of this report beginning on page 52. Additional risk factors are described in other documents we file with the Securities and Exchange Commission. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement. iii
PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS CENTERPOINT ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED OPERATIONS (MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ------- ------ ------- ------ REVENUES ..................................................... $ 1,669 $2,218 $ 5,897 $6,912 ------- ------ ------- ------ EXPENSES: Natural gas ............................................... 928 1,422 3,701 4,563 Operation and maintenance ................................. 319 336 932 974 Depreciation and amortization ............................. 126 145 362 411 Taxes other than income taxes ............................. 89 90 269 277 ------- ------ ------- ------ Total .................................................. 1,462 1,993 5,264 6,225 ------- ------ ------- ------ OPERATING INCOME ............................................. 207 225 633 687 ------- ------ ------- ------ OTHER INCOME (EXPENSE): Gain (loss) on Time Warner investment ..................... (31) 30 (40) (29) Gain (loss) on indexed debt securities .................... 34 (29) 43 34 Interest and other finance charges ........................ (183) (168) (554) (521) Interest on transition bonds .............................. (9) (9) (29) (27) Return on true-up balance ................................. -- 35 -- 104 Other, net ................................................ 1 7 15 18 ------- ------ ------- ------ Total .................................................. (188) (134) (565) (421) ------- ------ ------- ------ INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM ........................................ 19 91 68 266 Income Tax Expense ........................................ (2) (41) (25) (122) ------- ------ ------- ------ INCOME FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM .. 17 50 43 144 DISCONTINUED OPERATIONS: Income from Texas Genco, net of tax ....................... 109 -- 241 11 Minority Interest in Income from Texas Genco .............. (22) -- (49) -- Loss on Disposal of Texas Genco, net of tax ............... (346) -- (346) (14) ------- ------ ------- ------ Total .................................................. (259) -- (154) (3) ------- ------ ------- ------ INCOME (LOSS) BEFORE EXTRAORDINARY ITEM ...................... (242) 50 (111) 141 EXTRAORDINARY ITEM, NET OF TAX ............................... (894) -- (894) 30 ------- ------ ------- ------ NET INCOME (LOSS) ............................................ $(1,136) $ 50 $(1,005) $ 171 ======= ====== ======= ====== BASIC EARNINGS PER SHARE: Income from Continuing Operations ......................... $ 0.05 $ 0.16 $ 0.14 $ 0.46 Discontinued Operations, net of tax (0.84) -- (0.50) (0.01) Extraordinary Item, net of tax (2.90) -- (2.91) 0.10 ------- ------ ------- ------ Net Income (Loss) ......................................... $ (3.69) $ 0.16 $ (3.27) $ 0.55 ======= ====== ======= ====== DILUTED EARNINGS PER SHARE: Income from Continuing Operations ......................... $ 0.05 $ 0.15 $ 0.14 $ 0.43 Discontinued Operations, net of tax (0.83) -- (0.50) (0.01) Extraordinary Item, net of tax (2.88) -- (2.89) 0.09 ------- ------ ------- ------ Net Income (Loss) ......................................... $ (3.66) $ 0.15 $ (3.25) $ 0.51 ======= ====== ======= ====== See Notes to the Company's Interim Financial Statements 1
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (MILLIONS OF DOLLARS) (UNAUDITED) ASSETS DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- CURRENT ASSETS: Cash and cash equivalents ....................... $ 165 $ 162 Investment in Time Warner common stock .......... 421 392 Accounts receivable, net ........................ 742 745 Accrued unbilled revenues ....................... 576 313 Natural gas inventory ........................... 174 309 Materials and supplies .......................... 78 88 Non-trading derivative assets ................... 50 195 Current assets of discontinued operations ....... 514 -- Prepaid expenses ................................ 21 18 Other current assets ............................ 96 240 ------- ------- Total current assets ......................... 2,837 2,462 ------- ------- PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment ................... 10,963 11,323 Less accumulated depreciation and amortization .. (2,777) (2,962) ------- ------- Property, plant and equipment, net ........... 8,186 8,361 ------- ------- OTHER ASSETS: Goodwill, net ................................... 1,741 1,744 Other intangibles, net .......................... 58 56 Regulatory assets ............................... 3,350 2,943 Non-trading derivative assets ................... 18 108 Non-current assets of discontinued operations ... 1,051 -- Other ........................................... 921 838 ------- ------- Total other assets ........................... 7,139 5,689 ------- ------- TOTAL ASSETS .............................. $18,162 $16,512 ======= ======= See Notes to the Company's Interim Financial Statements 2
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - (CONTINUED) (MILLIONS OF DOLLARS) (UNAUDITED) LIABILITIES AND SHAREHOLDERS' EQUITY DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- CURRENT LIABILITIES: Current portion of transition bond long-term debt ..................... $ 47 $ 54 Current portion of other long-term debt ............................... 1,789 2,004 Indexed debt securities derivative .................................... 342 307 Accounts payable ...................................................... 868 845 Taxes accrued ......................................................... 609 174 Interest accrued ...................................................... 151 143 Non-trading derivative liabilities .................................... 26 89 Regulatory liabilities ................................................ 225 -- Accumulated deferred income taxes, net ................................ 261 366 Current liabilities of discontinued operations ........................ 449 -- Other ................................................................. 420 692 ------- ------- Total current liabilities .......................................... 5,187 4,674 ------- ------- OTHER LIABILITIES: Accumulated deferred income taxes, net ................................ 2,415 2,480 Unamortized investment tax credits .................................... 54 48 Non-trading derivative liabilities .................................... 6 14 Benefit obligations ................................................... 440 457 Regulatory liabilities ................................................ 1,082 749 Non-current liabilities of discontinued operations .................... 420 -- Other ................................................................. 259 378 ------- ------- Total other liabilities ............................................ 4,676 4,126 ------- ------- LONG-TERM DEBT: Transition bonds ...................................................... 629 575 Other ................................................................. 6,564 5,919 ------- ------- Total long-term debt ............................................... 7,193 6,494 ------- ------- COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 11) SHAREHOLDERS' EQUITY: Common stock (308,045,215 shares and 310,069,770 shares outstanding at December 31, 2004 and September 30, 2005, respectively) ......... 3 3 Additional paid-in capital ............................................ 2,891 2,917 Retained deficit ...................................................... (1,727) (1,661) Accumulated other comprehensive loss .................................. (61) (41) ------- ------- Total shareholders' equity ......................................... 1,106 1,218 ------- ------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ...................... $18,162 $16,512 ======= ======= See Notes to the Company's Interim Financial Statements 3
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (MILLIONS OF DOLLARS) (UNAUDITED) NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2004 2005 -------- ------ CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) ....................................................... $(1,005) $ 171 Discontinued operations, net of tax ..................................... 154 3 Extraordinary item, net of tax .......................................... 894 (30) ------- ----- Income from continuing operations ....................................... 43 144 Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation and amortization ........................................ 362 411 Amortization of deferred financing costs ............................. 63 59 Deferred income taxes ................................................ 105 162 Investment tax credit ................................................ (6) (6) Unrealized loss on Time Warner investment ............................ 40 29 Unrealized gain on indexed debt securities ........................... (43) (34) Changes in other assets and liabilities: Accounts receivable and unbilled revenues, net .................... 292 300 Inventory ......................................................... (75) (134) Accounts payable .................................................. (144) (18) Fuel cost over (under) recovery/surcharge ......................... 43 (69) Non-trading derivatives, net ...................................... (19) 8 Margin deposits, net .............................................. 15 78 Short-term risk management activities, net ........................ 1 (19) Interest and taxes accrued ........................................ (28) (381) Excess tax deduction related to share-based payment arrangements .. -- (3) Net regulatory assets and liabilities ............................. (253) (166) Other current assets .............................................. (6) (47) Other current liabilities ......................................... (2) 8 Other assets ...................................................... (12) (2) Other liabilities ................................................. (41) 37 Other, net ........................................................... 19 7 ------- ----- Net cash provided by operating activities ...................... 354 364 ------- ----- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures .................................................... (359) (497) Proceeds from sale of Texas Genco ....................................... -- 700 Dividends received from Texas Genco ..................................... 49 -- Other, net .............................................................. 6 1 ------- ----- Net cash provided by (used in) investing activities ............ (304) 204 ------- ----- CASH FLOWS FROM FINANCING ACTIVITIES: Decrease in short-term borrowings, net .................................. (63) -- Long-term revolving credit facilities, net .............................. 358 (239) Proceeds from commercial paper, net ..................................... -- 187 Proceeds from long-term debt ............................................ 229 -- Payments of long-term debt .............................................. (545) (424) Debt issuance costs ..................................................... (13) (7) Payment of common stock dividends ....................................... (92) (105) Proceeds from issuance of common stock, net ............................. 9 14 Excess tax deduction related to share-based payment arrangements ........ -- 3 ------- ----- Net cash used in financing activities ............................. (117) (571) ------- ----- CASH FLOWS FROM DISCONTINUED OPERATIONS: Cash provided by (used in) operating activities ......................... 107 (66) Cash provided by (used in) investing activities ......................... (46) 374 Cash used in financing activities ....................................... (61) (308) ------- ----- Net cash provided by discontinued operations ...................... -- -- ------- ----- NET DECREASE IN CASH AND CASH EQUIVALENTS .................................. (67) (3) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ........................... 87 165 ------- ----- CASH AND CASH EQUIVALENTS AT END OF PERIOD ................................. $ 20 $ 162 ======= ===== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest ................................................................ $ 572 $ 515 Income taxes (refunds) .................................................. (17) 464 See Notes to the Company's Interim Financial Statements 4
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (1) BACKGROUND AND BASIS OF PRESENTATION General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy, Inc. are the consolidated interim financial statements and notes (Interim Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy, or the Company). The Interim Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CenterPoint Energy for the year ended December 31, 2004 (CenterPoint Energy Form 10-K). Background. CenterPoint Energy, Inc. is a public utility holding company, created on August 31, 2002 as part of a corporate restructuring of Reliant Energy, Incorporated (Reliant Energy) that implemented certain requirements of the Texas Electric Choice Plan (Texas electric restructuring law). CenterPoint Energy is a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (1935 Act). The 1935 Act and related rules and regulations impose a number of restrictions on the activities of the Company and those of its subsidiaries. The 1935 Act, among other things, limits the ability of the Company and its subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliated service, sales and construction contracts. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act). Under that legislation, the 1935 Act is repealed effective February 8, 2006. After the effective date of the repeal, the Company and its subsidiaries will no longer be subject to restrictions imposed under the 1935 Act. Until the repeal is effective, the Company and its subsidiaries remain subject to the provisions of the 1935 Act and the terms of orders issued by the Securities and Exchange Commission (SEC) under the 1935 Act. The Energy Act grants to the Federal Energy Regulatory Commission (FERC) authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by FERC and state regulatory authorities. The Energy Act requires FERC to issue regulations to implement its jurisdiction under the Energy Act, and on September 16, 2005, FERC issued proposed rules for public comment. It is presently unknown what, if any, specific obligations under those rules may be imposed on the Company and its subsidiaries as a result of that rulemaking. The Company's operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of September 30, 2005, the Company's indirect wholly owned subsidiaries included: - CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes Houston; and - CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC), which owns gas distribution systems. The operations of its local distribution companies are conducted through two unincorporated divisions: Minnesota Gas and Southern Gas Operations, which includes Houston Gas. Through wholly owned subsidiaries, CERC owns two interstate natural gas pipelines and gas gathering systems, provides various ancillary services, and offers variable and fixed-price physical natural gas supplies to commercial and industrial customers and natural gas distributors. On April 13, 2005, the Company sold Texas Genco Holdings, Inc. (Texas Genco), whose primary remaining asset was its ownership interest in a nuclear generating facility, to Texas Genco LLC in exchange for a cash payment to the Company of $700 million. Texas Genco owned and operated additional generating facilities during most of 2004. See Note 2 for further discussion. Basis of Presentation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and 5
liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company's Interim Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods. Amounts reported in the Company's Statements of Consolidated Operations are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests. In addition, certain amounts from the prior year have been reclassified to conform to the Company's presentation of financial statements in the current year. These reclassifications do not affect net income. Note 2(d) (Long-Lived Assets and Intangibles), Note 2(e) (Regulatory Assets and Liabilities), Note 4 (Regulatory Matters), Note 5 (Derivative Instruments), Note 6 (Indexed Debt Securities (ZENS) and Time Warner Securities) and Note 11 (Commitments and Contingencies) to the consolidated annual financial statements in the CenterPoint Energy Form 10-K (CenterPoint Energy Notes) relate to certain contingencies. These notes, as updated herein, are incorporated herein by reference. For information regarding certain legal and regulatory proceedings and environmental matters, see Note 11 to the Interim Financial Statements. (2) DISCONTINUED OPERATIONS In July 2004, the Company announced its agreement to sell its majority-owned generating subsidiary, Texas Genco, to Texas Genco LLC. On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco distributed $2.231 billion in cash to the Company. Following that sale, Texas Genco's principal remaining asset was its ownership interest in a nuclear generating facility. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to the Company of $700 million, was completed on April 13, 2005. The Company recorded an after-tax loss of $259 million and $154 million for the three and nine months ended September 30, 2004, respectively, related to the operations of Texas Genco. The Company recorded an after-tax loss of $3 million for the nine months ended September 30, 2005. General corporate overhead, previously allocated to Texas Genco from the Company, was $5 million and $15 million for the three and nine months ended September 30, 2004, respectively, and was less than $1 million for the nine months ended September 30, 2005. These amounts will not be eliminated by the sale of Texas Genco and were excluded from income from discontinued operations and reflected as general corporate overhead of the Company in income from continuing operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). The Interim Financial Statements present Texas Genco's operations as discontinued operations in accordance with SFAS No. 144. Interest expense of $14 million and $38 million for the three and nine months ended September 30, 2004, respectively, was reclassified to discontinued operations of Texas Genco related to the applicable amounts of CenterPoint Energy's term loan and revolving credit facility debt that would have been assumed to be paid off with any proceeds from the sale of Texas Genco during those respective periods in accordance with SFAS No. 144. Revenues related to Texas Genco included in discontinued operations for the three and nine months ended September 30, 2004 were $638 million and $1.6 billion, respectively. Revenues for the nine months ended September 30, 2005 were $62 million. Loss from these discontinued operations for the three and nine months ended September 30, 2004 is reported net of income tax benefit of $164 million and $94 million, respectively. Income from these discontinued operations for the nine months ended September 30, 2005 is reported net of income tax expense of $4 million. 6
(3) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS (a) Stock-Based Incentive Compensation Plans. The Company has long-term incentive compensation plans (LICPs) that provide for the issuance of stock-based incentives, including performance-based shares, performance-based units, restricted shares and stock options to directors, officers and key employees. A maximum of approximately 37 million shares of CenterPoint Energy common stock is authorized to be issued under these plans. Performance-based shares, performance-based units and restricted shares are granted to employees without cost to the participants. The performance shares and units vest three years after the grant date based upon the performance of the Company over a three-year cycle. The restricted shares vest at various times ranging from one year to the end of a three-year period. Upon vesting, the shares are issued to the plan participants. Option awards are generally granted with an exercise price equal to the average of the high and low sales price of the Company's stock at the date of grant. These option awards generally become exercisable in one-third increments on each of the first through third anniversaries of the grant date and have 10-year contractual terms. No options were granted during the three and nine months ended September 30, 2005. Effective January 1, 2005, the Company adopted SFAS No. 123 (Revised 2004), "Share-Based Payment" (SFAS 123(R)), using the modified prospective transition method. Under this method, the Company records compensation expense at fair value for all awards it grants after the date it adopted the standard. In addition, the Company is required to record compensation expense at fair value (as previous awards continue to vest) for the unvested portion of previously granted stock option awards that were outstanding as of the date of adoption. Pre-adoption awards of time-based restricted stock and performance-based restricted stock will continue to be expensed using the guidance contained in Accounting Principles Board Opinion No. 25. The adoption of SFAS 123(R) did not have a material impact on the Company's results of operations, financial condition or cash flows. The Company recorded LICP compensation expense of $2 million and $6 million for the three and nine months ended September 30, 2004, respectively. LICP compensation expense for the three and nine months ended September 30, 2005 was $4 million and $10 million, respectively. The total income tax benefit recognized related to such arrangements was less than $1 million and $2 million for the three and nine months ended September 30, 2004, respectively. Income tax benefit for the three and nine months ended September 30, 2005 was $2 million and $4 million, respectively. No compensation cost was capitalized as a part of inventory and fixed assets in either of the three or nine months ended September 30, 2004 and 2005. Pro forma information for the three and nine months ended September 30, 2004 is provided to show the effect of amortizing stock-based compensation to expense on a straight-line basis over the vesting period. Had compensation costs been determined as prescribed by SFAS No. 123(R), the Company's net income and earnings per share would have been as follows (in millions, except per share amounts): THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 2004 SEPTEMBER 30, 2004 ------------------ ------------------ Net Income (Loss): As reported.............................................. $(1,136) $(1,005) Total stock-based employee compensation determined under the fair value based method.......... (1) (3) -------- ------- Pro forma................................................ $(1,137) $(1,008) ======= ======= Basic Earnings Per Share: As reported.............................................. $ (3.69) $ (3.27) Pro forma................................................ (3.70) (3.28) Diluted Earnings Per Share: As reported.............................................. (3.66) (3.25) Pro forma................................................ (3.67) (3.26) 7
The following tables summarize the methods used to measure compensation cost for the various types of awards granted under the LICPs: FOR AWARDS GRANTED BEFORE JANUARY 1, 2005 AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST - ------------------------------ ----------------------------------------------- Performance shares Initially measured using fair value and expected achievement levels on the date of grant. Compensation cost is then periodically adjusted to reflect changes in market prices and achievement through the settlement date. Performance units Initially measured using the award's target unit value of $100 that reflects expected achievement levels on the date of grant. Compensation cost is then periodically adjusted to reflect changes in achievement through the settlement date. Time-based restricted stock Measured using fair value on the grant date. Stock options Estimated using the Black-Scholes option valuation method. FOR AWARDS GRANTED AS OF AND AFTER JANUARY 1, 2005 AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST - ------------------------------ ----------------------------------------------- Performance shares Measured using fair value and expected achievement levels on the grant date. Time-based restricted stock Measured using fair value on the grant date. For awards granted before January 1, 2005, forfeitures of awards were measured upon their occurrence. For awards granted as of and after January 1, 2005, forfeitures are estimated on the date of grant and are adjusted as required through the remaining vesting period. The following tables summarize the Company's LICP activity for the three and nine months ended September 30, 2005: STOCK OPTIONS OUTSTANDING OPTIONS THREE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------- SHARES WEIGHTED-AVERAGE (THOUSANDS) EXERCISE PRICE ----------- ---------------- Outstanding at June 30, 2005........... 14,888 $15.78 Canceled............................ (303) 19.03 Exercised........................... (503) 7.71 ------ Outstanding at September 30, 2005...... 14,082 16.00 ====== NON-VESTED OPTIONS THREE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- Outstanding at June 30, 2005........... 4,032 $1.76 Vested.............................. -- -- Canceled............................ -- -- ----- Outstanding at September 30, 2005...... 4,032 1.76 ===== 8
OUTSTANDING OPTIONS NINE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------------------- REMAINING WEIGHTED- AVERAGE AGGREGATE AVERAGE CONTRACTUAL INTRINSIC SHARES EXERCISE LIFE VALUE (THOUSANDS) PRICE (YEARS) (MILLIONS) ----------- --------- ----------- ---------- Outstanding at December 31, 2004... 16,159 $15.42 Canceled........................ (966) 16.78 Exercised....................... (1,111) 6.97 ------ Outstanding at September 30, 2005.. 14,082 16.00 4.4 $39 ====== Exercisable at September 30, 2005.. 12,127 17.04 3.9 28 ====== NON-VESTED OPTIONS NINE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- Outstanding at December 31, 2004... 6,854 $1.61 Vested.......................... (2,770) 1.40 Canceled........................ (52) 1.90 ------ Outstanding at September 30, 2005.. 4,032 1.76 ====== PERFORMANCE SHARES OUTSTANDING AND NON-VESTED SHARES THREE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- Outstanding at June 30, 2005.............. 1,587 $9.27 Granted................................ -- -- Canceled............................... (27) 5.64 Vested and released to participants.... -- -- ----- Outstanding at September 30, 2005......... 1,560 9.33 ===== OUTSTANDING SHARES NINE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------- REMAINING AVERAGE AGGREGATE CONTRACTUAL INTRINSIC SHARES LIFE VALUE (THOUSANDS) (YEARS) (MILLIONS) ----------- ----------- ---------- Outstanding at December 31, 2004.......... 1,169 Granted................................ 945 Canceled............................... (181) Vested and released to participants.... (373) ----- Outstanding at September 30, 2005......... 1,560 1.4 $19 ===== NON-VESTED OPTIONS NINE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- Outstanding at December 31, 2004.......... 756 $ 5.70 Granted................................ 945 12.13 Canceled............................... (121) 9.17 Vested and released to participants.... (20) 5.64 ----- Outstanding at September 30, 2005......... 1,560 9.33 ===== The non-vested and outstanding shares displayed in the above tables assume that shares are issued at the maximum performance level (150%). The aggregate intrinsic value reflects the impacts of current expectations of achievement and stock price. 9
PERFORMANCE-BASED UNITS OUTSTANDING AND NON-VESTED UNITS THREE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE UNITS GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- Outstanding at June 30, 2005................. 35 $100.00 Canceled.................................. (1) -- Vested and released to participants....... -- -- --- Outstanding at September 30, 2005............ 34 100.00 === OUTSTANDING AND NON-VESTED UNITS NINE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------------------- REMAINING WEIGHTED- AVERAGE AGGREGATE AVERAGE CONTRACTUAL INTRINSIC UNITS GRANT DATE LIFE VALUE (THOUSANDS) FAIR VALUE (YEARS) (MILLIONS) ----------- ---------- ----------- ---------- Outstanding at December 31, 2004......... 37 $100.00 Canceled.............................. (2) 100.00 Vested and released to participants... (1) 100.00 --- Outstanding at September 30, 2005........ 34 100.00 1.3 $3 === The aggregate intrinsic value reflects the value of the performance units given current expectations of performance through the end of the cycle. TIME-BASED RESTRICTED STOCK OUTSTANDING AND NON-VESTED SHARES THREE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- Outstanding at June 30, 2005............. 974 $ 8.72 Granted............................... 30 13.34 Canceled.............................. (27) 7.27 Vested and released to participants... (8) 10.98 --- Outstanding at September 30, 2005........ 969 8.89 === OUTSTANDING AND NON-VESTED SHARES NINE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------------------- REMAINING WEIGHTED- AVERAGE AGGREGATE AVERAGE CONTRACTUAL INTRINSIC SHARES GRANT DATE LIFE VALUE (THOUSANDS) FAIR VALUE (YEARS) (MILLIONS) ----------- ---------- ----------- ---------- Outstanding at December 31, 2004........ 769 $ 7.49 Granted.............................. 307 12.25 Canceled............................. (70) 8.79 Vested and released to participants.. (37) 7.82 --- Outstanding at September 30, 2005....... 969 8.89 1.2 $14 === The weighted-average grant-date fair values of awards granted were as follows for the three and nine months ended September 30, 2004 and 2005: THREE MONTHS ENDED SEPTEMBER 30, -------------------------------- 2004 2005 ------ ------ Options....................... $ -- $ -- Performance units............. -- -- Performance shares............ -- -- Time-based restricted stock... 11.42 13.34 10
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2004 2005 ------- ----- Options ...................... $ 1.86 $ -- Performance units ............ 100.00 -- Performance shares ........... -- 12.13 Time-based restricted stock .. 10.94 12.25 The total intrinsic value of awards received by participants were as follows for the three and nine months ended September 30, 2004 and 2005: THREE MONTHS ENDED SEPTEMBER 30, -------------------------------- 2004 2005 ---- ---- (IN MILLIONS) Options exercised... $1 $3 NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2004 2005 ---- ---- (IN MILLIONS) Options exercised.... $3 $7 Performance shares... 7 5 As of September 30, 2005, there was $16 million of total unrecognized compensation cost related to non-vested LICP arrangements. That cost is expected to be recognized over a weighted-average period of 1.7 years. Cash received from LICPs was less than $1 million and $3 million for the three and nine months ended September 30, 2004, respectively. Cash received from LICPs was $4 million and $8 million for the three and nine months ended September 30, 2005, respectively. The actual tax benefit realized for tax deductions related to LICPs totaled less than $1 million and $4 million for the three and nine months ended September 30, 2004, respectively. Tax benefits realized for the three and nine months ended September 30, 2005 were $1 million and $5 million, respectively. The Company has a policy of issuing new shares in order to satisfy share-based payments related to LICPs. For further information, please read Note 9 to the CenterPoint Energy Form 10-K. (b) Employee Benefit Plans. The Company's net periodic cost includes the following components relating to pension and postretirement benefits: THREE MONTHS ENDED SEPTEMBER 30, ----------------------------------------------------- 2004 2005 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN MILLIONS) Service cost .................... $ 10 $ 1 $ 9 $ 1 Interest cost ................... 26 8 24 6 Expected return on plan assets .. (26) (4) (34) (3) Net amortization ................ 9 4 9 2 Curtailment ..................... -- 17 -- 1 ---- --- ---- --- Net periodic cost ............... $ 19 $26 $ 8 $ 7 ==== === ==== === 11
NINE MONTHS ENDED SEPTEMBER 30, ----------------------------------------------------- 2004 2005 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN MILLIONS) Service cost .................... $ 30 $ 3 $ 26 $ 2 Interest cost ................... 77 24 72 20 Expected return on plan assets .. (78) (10) (103) (9) Net amortization ................ 28 10 28 7 Curtailment ..................... -- 17 -- 1 Other ........................... 3 2 -- -- ---- ---- ----- --- Net periodic cost ............... $ 60 $ 46 $ 23 $21 ==== ==== ===== === Included in the net periodic cost for the three and nine months ended September 30, 2004 is $20 million and $28 million, respectively, of expense related to Texas Genco's participants, which is reflected in discontinued operations in the Statements of Consolidated Operations. Contributions to the pension plan are not required in 2005; however, the Company may make a contribution in an amount that would insure that plan assets exceed the accumulated benefit obligation at December 31, 2005. The Company expects that it will contribute $23 million to its postretirement benefits plan in 2005. As of September 30, 2005, $17 million of contributions have been made. In addition to the Company's non-contributory pension plan, the Company maintains a non-qualified benefit restoration plan. The net periodic cost associated with this plan was $2 million for each of the three months ended September 30, 2004 and 2005, respectively, and $5 million for each of the nine months ended September 30, 2004 and 2005. (4) NEW ACCOUNTING PRONOUNCEMENTS In May 2005, the Financial Accounting Standards Board (FASB) issued SFAS No. 154, "Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3" (SFAS No. 154). SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The correction of an error in previously issued financial statements is not an accounting change and must be reported as a prior-period adjustment by restating previously issued financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. In March 2005, the FASB issued FASB Interpretation No. (FIN) 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47). FIN 47 clarifies that an entity must record a liability for a "conditional" asset retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The Company is evaluating the effect of adoption of this new standard on its financial position, results of operations and cash flows. (5) REGULATORY MATTERS (a) Recovery of True-Up Balance. The Texas electric restructuring law provides for the Public Utility Commission of Texas (Texas Utility Commission) to conduct a "true-up" proceeding to determine CenterPoint Houston's stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for its recovery of those costs. In March 2004, CenterPoint Houston filed its stranded cost true-up application with the Texas Utility Commission. CenterPoint Houston had requested recovery of $3.7 billion, excluding interest. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. 12
CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. That court held a hearing on the appeal in early August 2005, and on August 26, 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the Texas Utility Commission's order, but reversed two of the Texas Utility Commission's rulings, which would have the effect of restoring approximately $620 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston's initial request. First, the court reversed the Texas Utility Commission's decision to prohibit CenterPoint Houston from recovering $180 million in credits through August 2004 that CenterPoint Houston was ordered to provide to retail electric providers as a result of a stranded cost estimate made by the Texas Utility Commission in 2000 that subsequently proved to be inaccurate. Second, the court reversed the Texas Utility Commission's disallowance of $440 million in transition costs which are recoverable under the Texas Utility Commission's regulations. Additional credits of approximately $30 million paid after August 2004 and interest would be added to these amounts. CenterPoint Houston and other parties appealed the district court decision to the 3rd Court of Appeals in Austin in September 2005. The parties have agreed to a briefing schedule whereby briefs will be filed by the parties on a schedule extending into February 2006. No amounts related to the court's judgment have been recorded in the Company's consolidated financial statements. There are two ways for CenterPoint Houston to recover the true-up balance: by issuing transition bonds to securitize the amounts due and/or by implementing a competition transition charge (CTC). In March 2005, the Texas Utility Commission issued a financing order that authorized the issuance of approximately $1.8 billion of transition bonds. In August 2005, the same Travis County District Court considering the appeal of the True-Up Order affirmed the financing order in all respects. CenterPoint Houston expects to complete the issuance of transition bonds under that order in the fourth quarter of 2005, subject to, among other matters, market conditions and the completion of documentation and rating agency reviews. On July 14, 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC to collect approximately $570 million over 14 years plus interest at an annual rate of 11.075%. The CTC order authorizes CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not covered by the financing order. The CTC order also allows CenterPoint Houston to collect approximately $24 million of rate case expenses over three years through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $600 million and the rate case expenses. Certain other parties appealed the CTC order to the Travis County Court on September 27, 2005. Additionally, during the period from September 13, 2005, the date of implementation of the CTC order, through September 30, 2005, CenterPoint Houston recognized approximately $7 million in CTC revenue, which was partially offset by $5 million in related amortization of the CTC regulatory asset. Under the True-Up Order, CenterPoint Houston is allowed a return until the true-up balance is recovered. The rate of return is based on CenterPoint Houston's cost of capital, established in the Texas Utility Commission's final order issued in October 2001, which is derived from CenterPoint Houston's cost to finance assets (debt return) and an allowance for earnings on shareholders' investment (equity return). Consequently, in accordance with SFAS No. 92, "Regulated Enterprises -- Accounting for Phase-in Plans," the rate of return has been bifurcated into a debt return component and an equity return component. CenterPoint Houston was allowed a return on the true-up balance of $62 million and $189 million for the three months and nine months ended September 30, 2005, respectively. Effective September 13, 2005, the date of implementation of the CTC order, the return on the CTC portion of the true-up balance is included in CenterPoint Houston's tariff-based revenues. The debt return of $35 million and $104 million for the three months and nine months ended September 30, 2005, respectively, was accrued and included in other income in the Company's Statements of Consolidated Operations. The debt return will continue to be recognized as earned going forward. The equity return of $27 million and $85 million for the three months and nine months ended September 30, 2005, respectively, will be recognized in income as it is recovered in the future. As of September 30, 2005, the Company has recorded a regulatory asset of $331 million related to the debt return on its true-up balance and has not recorded an allowed equity return of $232 million on its true-up balance because such return will be recognized as it is recovered in the future. Net income for the nine months ended September 30, 2005 included an after-tax extraordinary gain of $30 million ($0.09 per diluted share) reflecting an adjustment to the extraordinary loss recorded in the last half of 2004 13
to write down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission. As a result of a settlement reached in a separate proceeding involving Reliant Energy, Inc.'s (RRI) Price-to-Beat, excess mitigation credits were terminated as of April 29, 2005. As a result of this settlement, the Company has applied the remaining unrefunded excess mitigation credits of approximately $522 million to reduce the regulatory asset related to stranded costs. (b) Final Fuel Reconciliation. The results of the Texas Utility Commission's final decision related to CenterPoint Houston's final fuel reconciliation are a component of the True-Up Order. CenterPoint Houston has appealed certain portions of the True-Up Order involving a disallowance of approximately $67 million relating to the final fuel reconciliation plus interest of $10 million. A hearing on this issue was held before a district court in Travis County on April 22, 2005 and a judgment was entered from the district court on May 13, 2005 affirming the Texas Utility Commission's decision. CenterPoint Houston filed an appeal to the Court of Appeals in June 2005. The parties are briefing the issues before the court. (c) Rate Cases. In November 2004, Southern Gas Operations filed an application for a $28 million base rate increase, as adjusted, with the Arkansas Public Service Commission (APSC). In September 2005, the APSC ordered an $11 million rate reduction, including a $10 million reduction relating to depreciation rates, which went into effect on September 25, 2005. In April 2005, the Railroad Commission of Texas (Railroad Commission) approved a settlement that increased Southern Gas Operations' base rate and service revenues by a combined $2 million in the unincorporated environs of its Beaumont/East Texas and South Texas Divisions. In June and August 2005, Southern Gas Operations filed requests to implement these rates within the incorporated cities located in its Beaumont/East Texas and South Texas Divisions. If these rates are approved in all jurisdictions as requested, Southern Gas Operations' base rate and service revenues are expected to increase by an additional $16 million annually. In June 2005, the Minnesota Public Utilities Commission (MPUC) approved a settlement which increases Minnesota Gas' base rates by approximately $9 million annually. An interim rate increase of $17 million had been implemented in October 2004. Substantially all of the excess amounts collected in interim rates over those approved in the final settlement were refunded to customers in the third quarter. On November 2, 2005, Minnesota Gas filed a request with the MPUC to increase annual rates by $41 million. It has requested that an interim rate increase of $35 million be implemented January 1, 2006. Any difference between the interim rates collected and the final rates would be subject to refund to customers. A decision by the MPUC is expected in the third quarter of 2006. (d) City of Tyler, Texas Dispute. In July 2002, the City of Tyler, Texas, asserted that Southern Gas Operations had overcharged residential and small commercial customers in that city for gas costs under supply agreements in effect since 1992. That dispute was referred to the Railroad Commission by agreement of the parties for a determination of whether Southern Gas Operations has properly charged and collected for gas service to its residential and commercial customers in its Tyler distribution system in accordance with lawful filed tariffs during the period beginning November 1, 1992, and ending October 31, 2002. In December 2004, the Railroad Commission conducted a hearing on the matter. On May 25, 2005, the Railroad Commission issued a final order finding that the Company had complied with its tariffs, acted prudently in entering into its gas supply contracts, and prudently managed those contracts. On August 10, 2005, the City of Tyler appealed this order to the Court of Appeals. 14
(e) City of Houston Franchise. On June 27, 2005, CenterPoint Houston accepted an ordinance granting CenterPoint Houston a new 30-year franchise to use the public rights-of-way to conduct its business in the City of Houston (New Franchise Ordinance). The New Franchise Ordinance took effect on July 1, 2005, and replaced the prior electricity franchise ordinance, which had been in effect since 1957. The New Franchise Ordinance clarifies certain operational obligations of CenterPoint Houston and the City of Houston and provides for streamlined payment and audit procedures and a two-year statute of limitations on claims for underpayment or overpayment under the ordinance. Under the prior electricity franchise ordinance, CenterPoint Houston paid annual franchise fees of $76.6 million to the City of Houston for the year ended December 31, 2004. For the twelve-month period beginning July 1, 2005, the annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance will include a base amount of $88.1 million (Base Amount) and an additional payment of $8.5 million (Additional Amount). The Base Amount and the Additional Amount will be adjusted annually based on the increase, if any, in kWh delivered by CenterPoint Houston within the City of Houston. CenterPoint Houston began paying the new annual franchise fees on July 1, 2005. Pursuant to the New Franchise Ordinance, the Annual Franchise Fee will be reduced prospectively to reflect any portion of the Annual Franchise Fee that is not included in CenterPoint Houston's base rates in any subsequent rate case. In accordance with CenterPoint Houston's rights under the New Franchise Ordinance, CenterPoint Houston filed a request with the City of Houston to implement a tariff rider to collect the Additional Amount, but subsequently asked the City of Houston to abate further consideration of that application. (f) Settlement of FERC Audit. On June 27, 2005, CenterPoint Energy Gas Transmission Company (CEGT), a subsidiary of CERC Corp., received an Order from FERC accepting the terms of a settlement agreed upon by CEGT with the Staff of the FERC's Office of Market Oversight and Investigations (OMOI). The settlement brought to a conclusion an investigation of CEGT initiated by OMOI in August 2003. Among other things, the investigation involved a comprehensive review of CEGT's relationship with its marketing affiliates and compliance with various FERC record-keeping and reporting requirements covering the period from January 1, 2001 through September 22, 2004. OMOI Staff took the position that some of CEGT's actions resulted in a limited number of violations of FERC's affiliate regulations or were in violation of certain record-keeping and administrative requirements. OMOI did not find any systematic violations of its rules governing communications or other relationships among affiliates. The settlement included two remedies: a payment of a $270,000 civil penalty and the execution of a compliance plan, applicable to both CEGT and CenterPoint Energy-Mississippi River Transmission Corporation (MRT). The compliance plan consists of a detailed set of Implementation Procedures that will facilitate compliance with FERC's Order No. 2004, the Standards of Conduct, which regulate behavior between regulated entities and their affiliates. The Company does not believe the compliance plan will have any material effect on CEGT's or MRT's ability to conduct their business. (g) Texas Utility Commission Staff Report. The Texas Utility Commission requires each electric utility to file, on commission-prescribed forms, an annual Earnings Report providing certain information to enable the Texas Utility Commission to monitor the electric utilities' earnings and financial condition within the state. On May 16, 2005, CenterPoint Houston filed its Earnings Report for the calendar year ended December 31, 2004. CenterPoint Houston's Earnings Report shows that it earned less than its authorized rate of return on equity in 2004. On October 21, 2005, the Texas Utility Commission Staff filed a memorandum summarizing their review of the Earnings Reports filed by electric utilities. Based on its review, the Texas Utility Commission Staff concluded that continuation of CenterPoint Houston's existing rates could result in excess revenues of as much as $105 million annually and recommended that the Texas Utility Commission initiate a review of the reasonableness of existing rates. The Texas Utility Commission Staff's analysis is based on an estimated 9.60% midpoint cost of equity, which is more than 150 basis points lower than the approved return on equity from CenterPoint Houston's last rate proceeding, the elimination of interest on debt maturing in November 2005 and certain other adjustments to CenterPoint Houston's reported information. Additionally, an assumed hypothetical capital structure of 60% debt and 40% equity was used which 15
would vary materially from the projected capital structure after the maturity of CenterPoint Houston's $1.31 billion term loan at the end of 2005. On October 28, 2005, the Texas Utility Commission considered the Staff report and agreed to initiate a rate proceeding by December 1, 2005 if CenterPoint Houston and other parties have not reached a settlement of the alleged excess earnings. CenterPoint Houston disagrees with several of the adjustments discussed in the memorandum and believes the Texas Utility Commission should base any such analysis on updated expense and revenue amounts and the appropriate capital structure and cost of capital. (6) DERIVATIVE FINANCIAL INSTRUMENTS The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative financial instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in cash flows of its natural gas businesses on its operating results and cash flows. Cash Flow Hedges. During the nine months ended September 30, 2004 and 2005, hedge ineffectiveness was less than $1 million from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive loss. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Company's Statements of Consolidated Operations under the caption "Natural Gas." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of September 30, 2005, the Company expects $(0.4) million in accumulated other comprehensive loss to be reclassified into net income during the next twelve months. Other Derivative Financial Instruments. The Company also has natural gas contracts that are derivatives which are not hedged and are accounted for on a mark-to-market basis with changes in fair value reported through earnings. Load following services that the Company offers its natural gas customers create an inherent tendency for the Company to be either long or short natural gas supplies relative to customer purchase commitments. The Company measures and values all of its volumetric imbalances on a real-time basis to minimize its exposure to commodity price and volume risk. The Company does not engage in proprietary or speculative commodity trading. Unhedged positions are accounted for by adjusting the carrying amount of the contracts to market and recognizing any gain or loss in operating income, net. During the nine months ended September 30, 2004 and 2005, the Company recognized net gains (losses) related to unhedged positions amounting to $(4) million and $14 million, respectively. As of December 31, 2004, the Company had recorded short-term risk management assets and liabilities of $4 million and $5 million, respectively, included in other current assets and other current liabilities, respectively. As of September 30, 2005, the Company had recorded short-term risk management assets and liabilities of $55 million and $37 million, respectively, included in other current assets and other current liabilities, respectively. A portion of CenterPoint Energy Services, Inc.'s (CES) activities include entering into transactions for the physical purchase, transportation and sale of natural gas at different locations (physical contracts). CES attempts to mitigate basis risk associated with these activities by entering into financial derivative contracts (financial contracts or financial basis swaps) to address market price volatility between the purchase and sale delivery points that can occur over the term of the physical contracts. The underlying physical contracts are accounted for on an accrual basis with all associated earnings not recognized until the time of actual physical delivery. The timing of the earnings impacts for the financial contracts differs from the physical contracts because the financial contracts meet the definition of a derivative under SFAS No. 133, "Accounting for Derivative Instruments" (SFAS No. 133), and are recorded at fair value as of each reporting balance sheet date with changes in value reported through earnings. Changes in prices between the delivery points (basis spreads) can and do vary daily resulting in changes to the fair value of the financial contracts. However, the economic intent of the financial contracts is to fix the actual net difference in the natural gas pricing at the different locations for the associated physical purchase and sale contracts throughout the life of the physical contracts and thus, when combined with the physical contracts' terms, provide an expected fixed gross margin on the physical contracts that will ultimately be recognized in earnings at the time of actual delivery of the natural gas. As of September 30, 2005, the mark-to-market value of the financial 16
contracts described above reflected an unrealized loss of $3.6 million; however, the underlying expected fixed gross margin associated with delivery under the physical contracts combined with the price risk management provided through the financial contracts is $2.3 million. As described above, over the term of these financial contracts, the quarterly reported mark-to-market changes in value may vary significantly and the associated unrealized gains and losses will be reflected in CES' earnings. CES also sells physical gas and basis to its end-use customers who desire to lock in a future spread between a specific location and Henry Hub (NYMEX). As a result, CES incurs exposure to commodity basis risk related to these transactions, which it attempts to mitigate by buying offsetting financial basis swaps. Under SFAS No. 133, CES records at fair value and marks-to-market the financial basis swaps as of each reporting balance sheet date with changes in value reported through earnings. However, the associated physical sales contracts are accounted for using the accrual basis, whereby earnings impacts are not recognized until the time of actual physical delivery. Although the timing of earnings recognition for the financial basis swaps differs from the physical contracts, the economic intent of the financial basis swaps is to fix the basis spread over the life of the physical contracts to an amount substantially the same as the portion of the basis spread pricing included in the physical contracts. In so doing, over the period that the financial basis swaps and related physical contracts are outstanding, actual cumulative earnings impacts for changes in the basis spread should be minimal, even though from a timing perspective there could be fluctuations in unrealized gains or losses associated with the changes in fair value recorded for the financial basis swaps. The cumulative earnings impact from the financial basis swaps recognized each reporting period is expected to be offset by the value realized when the related physical sales occur. As of September 30, 2005, the mark-to-market value of the financial basis swaps reflected an unrealized loss of $4.8 million. Interest Rate Swaps. During 2002, the Company settled forward-starting interest rate swaps having an aggregate notional amount of $1.5 billion at a cost of $156 million, which was recorded in other comprehensive loss and is being amortized into interest expense over the life of the designated fixed-rate debt. Amortization of amounts deferred in accumulated other comprehensive loss for the nine months ended September 30, 2004 and 2005, was $19 million and $23 million, respectively. Embedded Derivative. The Company's $575 million and $255 million of convertible senior notes contain contingent interest provisions. The contingent interest component is an embedded derivative as defined by SFAS No. 133, and accordingly, must be split from the host instrument and recorded at fair value on the balance sheet. The value of the contingent interest components was not material at issuance or at September 30, 2005. (7) GOODWILL AND INTANGIBLES Goodwill by reportable business segment is as follows (in millions): DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- Natural Gas Distribution .. $1,085 $1,085 Pipelines and Gathering ... 601 604 Other Operations .......... 55 55 ------ ------ Total .................. $1,741 $1,744 ====== ====== The Company performs its goodwill impairment test at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon adoption of SFAS No. 142, "Goodwill and Other Intangible Assets," the Company initially selected January 1 as its annual goodwill impairment testing date. Since the time the Company selected the January 1 date, the Company's year-end closing and reporting process has been truncated in order to meet the accelerated reporting requirements of the SEC, resulting in significant constraints on the Company's human resources at year-end and during its first fiscal quarter. Accordingly, in order to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in the third quarter of 2005, the Company changed the date on which it performs its annual goodwill impairment test from January 1 to July 1. The Company believes the July 1 alternative date will alleviate the resource constraints that exist during the first quarter and allow it to utilize additional resources in conducting the annual impairment evaluation of goodwill. The Company performed the test at July 1, 2005, and determined that no impairment charge for goodwill was required. The change is not intended to delay, accelerate or avoid an impairment charge. The Company believes that this accounting change is an alternative accounting principle that is preferable under the circumstances. 17
The components of the Company's other intangible assets consist of the following: DECEMBER 31, 2004 SEPTEMBER 30, 2005 ----------------------- ----------------------- CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION -------- ------------ -------- ------------ (IN MILLIONS) Land use rights .................................... $55 $(12) $55 $(13) Other .............................................. 21 (6) 21 (7) --- ---- --- ---- Total ........................................... $76 $(18) $76 $(20) === ==== === ==== The Company recognizes specifically identifiable intangibles, including land use rights and permits, when specific rights and contracts are acquired. The Company has no intangible assets with indefinite lives recorded as of September 30, 2005. The Company amortizes other acquired intangibles on a straight-line basis over the lesser of their contractual or estimated useful lives that range from 40 to 75 years for land use rights and 4 to 25 years for other intangibles. Amortization expense for other intangibles for both of the three months ended September 30, 2004 and 2005 was less than $1 million and for both of the nine months ended September 30, 2004 and 2005 was $2 million. Estimated amortization expense for the last three months of 2005 and the five succeeding fiscal years is as follows (in millions): 2005 ...... $-- 2006 ...... 3 2007 ...... 3 2008 ...... 3 2009 ...... 3 2010 ...... 2 --- Total .. $14 === (8) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income (net of tax): FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------------- ------------------------- 2004 2005 2004 2005 ------- ---- ------- ---- (IN MILLIONS) Net income (loss) ................................... $(1,136) $50 $(1,005) $171 ------- --- ------- ---- Other comprehensive income (loss): Minimum benefit liability ........................ 14 -- 14 -- Net deferred gain from cash flow hedges .......... 17 1 33 11 Reclassification of deferred loss (gain) from cash flow hedges realized in net income ............ (2) (2) (1) 6 Other comprehensive income (loss) from discontinued operations ....................... (93) -- (93) 3 ------- --- ------- ---- Other comprehensive income (loss) ................... (64) (1) (47) 20 ------- --- ------- ---- Comprehensive income (loss) ......................... $(1,200) $49 $(1,052) $191 ======= === ======= ==== 18
The following table summarizes the components of accumulated other comprehensive loss: DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- (IN MILLIONS) Minimum pension liability adjustment ................... $ (6) $ (6) Net deferred loss from cash flow hedges ................ (52) (35) Other comprehensive loss from discontinued operations .. (3) -- ---- ---- Total accumulated other comprehensive loss ............. $(61) $(41) ==== ==== (9) CAPITAL STOCK CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock. At December 31, 2004, 308,045,381 shares of CenterPoint Energy common stock were issued and 308,045,215 shares of CenterPoint Energy common stock were outstanding. At September 30, 2005, 310,069,936 shares of CenterPoint Energy common stock were issued and 310,069,770 shares of CenterPoint Energy common stock were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2004 and September 30, 2005. CenterPoint Energy's board of directors declared a dividend of $0.10 per share in each of the first three quarters of 2004. On January 26, 2005, the Company's board of directors declared a dividend of $0.10 per share of common stock payable on March 10, 2005 to shareholders of record as of the close of business on February 16, 2005. On March 3, 2005, the Company's board of directors declared a dividend of $0.10 per share of common stock payable on March 31, 2005 to shareholders of record as of the close of business on March 16, 2005. This additional first quarter dividend was declared to address technical restrictions that might have limited the Company's ability to pay a regular dividend during the second quarter of this year. Due to the limitations imposed under the 1935 Act, the Company may declare and pay dividends only from earnings in the specific quarter in which the dividend is paid, absent specific authorization from the SEC approving payment of the quarterly dividend from capital or unearned surplus. There can be no assurance, however, that the SEC would authorize such payments. On June 2, 2005, the Company's board of directors declared a dividend of $0.07 per share of common stock payable on June 30, 2005 to shareholders of record as of the close of business on June 15, 2005. On August 31, 2005, the Company's board of directors declared a dividend of $0.07 per common share, payable on September 30, 2005, to shareholders of record as of the close of business on September 12, 2005. The dividends declared and paid for the first three quarters of 2005 totaled $0.34 per share versus $0.30 per share for the first three quarters of 2004. On October 24, 2005, the Company's board of directors declared a dividend of $0.06 per common share, payable on December 9, 2005, to shareholders of record as of the close of business on November 16, 2005. (10) LONG-TERM DEBT AND RECEIVABLES FACILITY (a) Long-term Debt. In March 2005, the Company replaced its $750 million revolving credit facility with a $1 billion five-year revolving credit facility. Borrowings may be made under the facility at the London interbank offered rate (LIBOR) plus 87.5 basis points based on current credit ratings. An additional utilization fee of 12.5 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. As of September 30, 2005, borrowings of $187 million in commercial paper were backstopped by the revolving credit facility and $27 million in letters of credit were outstanding under the revolving credit facility. In March 2005, CenterPoint Houston established a $200 million five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 75 basis points based on CenterPoint Houston's current credit ratings. An additional utilization fee of 12.5 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. As of September 30, 2005, there were no borrowings outstanding under the revolving credit facility. 19
CenterPoint Houston also established a $1.31 billion credit facility in March 2005. CenterPoint Houston expects to utilize this facility to refinance CenterPoint Houston's $1.31 billion term loan maturing on November 11, 2005. Drawings may be made under this credit facility until November 16, 2005, at which time any outstanding borrowings are converted to term loans maturing in November 2007. Under this facility, (i) 100% of the net proceeds from the issuance of transition bonds and (ii) the proceeds, in excess of $200 million, from certain other new net indebtedness for borrowed money incurred by CenterPoint Houston must be used to repay borrowings under the facility. Based on CenterPoint Houston's current credit ratings, borrowings under the facility may be made at LIBOR plus 75 basis points. The interest rate under the term loan which this facility would replace is LIBOR plus 975 basis points. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. Any drawings under this facility must be secured by CenterPoint Houston's general mortgage bonds in the same principal amount and bearing the same interest rate as such drawings. In June 2005, CERC Corp. replaced its $250 million three-year revolving credit facility with a $400 million five-year revolving credit facility. The new credit facility terminates on June 30, 2010. Borrowings under this facility may be made at LIBOR plus 55 basis points, including the facility fee, based on current credit ratings. An additional utilization fee of 10 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. As of September 30, 2005, such credit facility was not utilized. Convertible Debt. In August 2005, the Company accepted for exchange approximately $572 million aggregate principal amount of its 3.75% convertible senior notes due 2023 (Old Notes) for an equal amount of its new 3.75% convertible senior notes due 2023 (New Notes). Old Notes of approximately $3 million remain outstanding. The Company commenced the exchange offer in response to the guidance set forth in Emerging Issues Task Force (EITF) Issue No. 04-8, "Accounting Issues Related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per Share" (EITF 04-8). Under that guidance, because settlement of the principal portion of the New Notes will be made in cash rather than stock, the exchange of New Notes for Old Notes will allow the Company to exclude the portion of the conversion value of the New Notes attributable to their principal amount from its computation of diluted earnings per share from continuing operations. See Note 12 for the impact on diluted earnings per share related to these securities. Additionally, as of September 30, 2005, the 3.75% convertible senior notes have been included as current portion of long-term debt in the Consolidated Balance Sheet because the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the third calendar quarter was greater than or equal to 120% of the conversion price of the 3.75% convertible senior notes and therefore, during the fourth quarter of 2005, the 3.75% convertible senior notes meet the criteria to be converted by the noteholders. Junior Subordinated Debentures (Trust Preferred Securities). In February 1997, a Delaware statutory business trust created by CenterPoint Energy (HL&P Capital Trust II) issued to the public $100 million aggregate amount of capital securities. The trust used the proceeds of the offering to purchase junior subordinated debentures issued by CenterPoint Energy having an interest rate and maturity date that correspond to the distribution rate and the mandatory redemption date of the capital securities. The amount of outstanding junior subordinated debentures discussed above was included in long-term debt as of December 31, 2004 and September 30, 2005. The junior subordinated debentures are the trust's sole assets and their entire operations. CenterPoint Energy considers its obligations under the Amended and Restated Declaration of Trust, Indenture, Guaranty Agreement and, where applicable, Agreement as to Expenses and Liabilities, relating to the capital securities, taken together, to constitute a full and unconditional guarantee by CenterPoint Energy of the trust's obligations with respect to the capital securities. The capital securities are mandatorily redeemable upon the repayment of the related series of junior subordinated debentures at their stated maturity or earlier redemption. Subject to some limitations, CenterPoint Energy has the option of deferring payments of interest on the junior subordinated debentures. During any deferral or event of default, CenterPoint Energy may not pay dividends on its capital stock. As of September 30, 2005, no interest payments on the junior subordinated debentures had been deferred. 20
The outstanding aggregate liquidation amount, distribution rate and mandatory redemption date of the capital securities of the trust described above and the identity and similar terms of the related series of junior subordinated debentures are as follows: AGGREGATE LIQUIDATION AMOUNTS AS OF DISTRIBUTION MANDATORY ---------------------------- RATE/ REDEMPTION DECEMBER 31, SEPTEMBER 30, INTEREST DATE/ TRUST 2004 2005 RATE MATURITY DATE JUNIOR SUBORDINATED DEBENTURES - ----- ------------ ------------- ------------ ------------- ------------------------------ (IN MILLIONS) HL&P Capital Trust II... $100 $100 8.257% February 2037 8.257% Junior Subordinated Deferrable Interest Debentures Series B In June 1996, a Delaware statutory business trust created by CERC Corp. (CERC Trust) issued $173 million aggregate amount of convertible preferred securities to the public. CERC Trust used the proceeds of the offering to purchase convertible junior subordinated debentures issued by CERC Corp. having an interest rate and maturity date that correspond to the distribution rate and mandatory redemption date of the convertible preferred securities. CERC Corp. considers its obligation under the Amended and Restated Declaration of Trust, Indenture and Guaranty Agreement relating to the convertible preferred securities, taken together, to constitute a full and unconditional guarantee by CERC Corp. of CERC Trust's obligations with respect to the convertible preferred securities. The convertible junior subordinated debentures represented CERC Trust's sole asset and its entire operations. The amount of outstanding junior subordinated debentures was included in long-term debt as of December 31, 2004. On July 1, 2005, the remaining $0.3 million of convertible preferred securities and the $6 million of related convertible junior subordinated debentures were called for redemption on August 1, 2005. Most of the convertible preferred securities were converted prior to the redemption date and the remaining securities were redeemed. (b) Receivables Facility. In January 2005, CERC's $250 million receivables facility was extended to January 2006 and temporarily increased, for the period from January 2005 to June 2005, to $375 million to provide additional liquidity to CERC during the peak heating season of 2005. As of September 30, 2005, CERC had $141 million of advances under its receivables facility. Advances under the receivables facility averaged $173 million for the nine months ended September 30, 2005. Sales of receivables were approximately $447 million and $480 million for the three months ended September 30, 2004 and 2005, respectively, and $1.7 billion and $1.4 billion for the nine months ended September 30, 2004 and 2005, respectively. (11) COMMITMENTS AND CONTINGENCIES (a) Legal Matters. RRI Indemnified Litigation The Company, CenterPoint Houston or their predecessor, Reliant Energy, and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between the Company and RRI, the Company and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys' fees and other costs, arising out of the lawsuits described below under Electricity and Gas Market Manipulation Cases and Other Class Action Lawsuits. Pursuant to the indemnification obligation, RRI is defending the Company and its subsidiaries to the extent named in these lawsuits. The ultimate outcome of these matters cannot be predicted at this time. Electricity and Gas Market Manipulation Cases. A large number of lawsuits have been filed against numerous market participants and remain pending in both federal and state courts in California and Nevada in connection with the operation of the electricity and natural gas markets in California and certain other western states in 2000-2001, a time of power shortages and significant increases in prices. These lawsuits, many of which have been filed as class actions, are based on a number of legal theories, including violation of state and federal antitrust laws, laws against unfair and unlawful business practices, the federal Racketeer Influenced Corrupt Organization Act, false claims statutes and similar theories and breaches of contracts to supply power to governmental entities. Plaintiffs in these 21
lawsuits, which include state officials and governmental entities as well as private litigants, are seeking a variety of forms of relief, including recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages and punitive damages, injunctive relief, restitution, interest due, disgorgement, civil penalties and fines, costs of suit, attorneys' fees and divestiture of assets. To date, several of the electricity complaints have been dismissed by the trial court and are on appeal, and several of the dismissals have been affirmed by appellate courts. Others remain in the early procedural stages. One of the gas complaints has also been dismissed and is on appeal. The other gas cases remain in the early procedural stages. The Company's former subsidiary, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally. RRI, some of its subsidiaries and, in some cases, former corporate officers or employees of some of those companies have been named as defendants in these suits. The Company or its predecessor, Reliant Energy, has been named in approximately 30 of these lawsuits, which were instituted between 2001 and 2005 and are pending in California state courts in San Diego County, in Kansas state court in Wyandotte County and in federal district courts in San Francisco, San Diego, Los Angeles, Fresno, Sacramento, San Jose, Kansas and Nevada and before the Ninth Circuit Court of Appeals. However, the Company, CenterPoint Houston and Reliant Energy were not participants in the electricity or natural gas markets in California. The Company and Reliant Energy have been dismissed from certain of the lawsuits, either voluntarily by the plaintiffs or by order of the court, and the Company believes it is not a proper defendant in the remaining cases and will continue to seek dismissal from such remaining cases. On July 6, 2004 and on October 12, 2004, the Ninth Circuit affirmed the Company's removal to federal district court of two electric cases brought by the California Attorney General and affirmed the federal court's dismissal of these cases based upon the filed rate doctrine and federal preemption. On April 18, 2005, the Supreme Court of the United States denied the Attorney General's petition for certiorari in one of these cases. No petition for certiorari was filed in the other case, and both of these cases are now finally resolved in favor of the defendants. A third case filed by the California Attorney General has been resolved in the settlement described in the following paragraph. Several cases that are now pending in state court in San Diego County were originally filed in several California state courts but were removed by the defendants to federal district court. When the federal district court remanded those cases, they were coordinated in front of one San Diego state court. In July 2005, that San Diego state court refused to dismiss certain of those cases based on defendants' claims of federal preemption and the filed rate doctrine. On August 12, 2005, RRI reached a settlement with the states of California, Washington and Oregon, California's three largest investor-owned utilities, classes of consumers from California and other western states, and a number of California city and county government entities that resolves their claims against RRI related to the operation of the electricity markets in California and certain other western states in 2000-2001. The settlement also resolves the claims of the states and the investor-owned utilities related to the 2000-2001 natural gas markets. The settlement must be approved by FERC, the California Public Utilities Commission and the courts in which the class action cases are pending. Approvals are expected by the end of 2005. The Company is not a party to the settlement, but may rely on the settlement as a defense to any claims brought against it related to the time when the Company was an affiliate of RRI. The terms of the settlement do not require payment by the Company. Other Class Action Lawsuits. Fifteen class action lawsuits filed in May, June and July 2002 on behalf of purchasers of securities of RRI and/or Reliant Energy have been consolidated in federal district court in Houston. RRI and certain of its former and current executive officers are named as defendants. The consolidated complaint also names RRI, Reliant Energy, the underwriters of the initial public offering of RRI's common stock in May 2001 (RRI Offering), and RRI's and Reliant Energy's independent auditors as defendants. The consolidated amended complaint seeks monetary relief purportedly on behalf of purchasers of common stock of Reliant Energy or RRI during certain time periods ranging from February 2000 to May 2002, and purchasers of common stock that can be traced to the RRI Offering. The plaintiffs allege, among other things, that the defendants misrepresented their revenues and trading volumes by engaging in round-trip trades and improperly accounted for certain structured transactions as cash-flow hedges, which resulted in earnings from these transactions being accounted for as future earnings rather than being accounted for as earnings in fiscal year 2001. In January 2004, the trial judge dismissed the plaintiffs' allegations that the defendants had engaged in fraud, but claims based on alleged misrepresentations in the registration statement issued in the RRI Offering remain. In June 2004, the plaintiffs filed a motion for class certification, which the court granted in February 2005. The defendants appealed the court's order certifying the class and asked the trial court to reconsider its ruling certifying the class. In July 2005, the parties announced that they had reached a settlement in this matter, subject to court approval. The parties filed a stipulation and agreement 22
of settlement in September 2005, and in October 2005, filed a corrected and supplemental submission at the court's request. Notice is being sent to settlement class members, and a settlement fairness hearing is set for January 2006. The terms of the settlement do not require payment by the Company. In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by the Company. Two of the lawsuits have been dismissed without prejudice. The Company and certain current and former members of its benefits committee are the remaining defendants in the third lawsuit. That lawsuit alleges that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by the Company, in violation of the Employee Retirement Income Security Act of 1974. The plaintiffs allege that the defendants permitted the plans to purchase or hold securities issued by the Company when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaint seeks monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held CenterPoint Energy or RRI securities, as well as restitution. Both the plaintiffs and the defendants have pending motions for summary judgment before the court. Trial is set for January 2006. In October 2002, a derivative action was filed in the federal district court in Houston against the directors and officers of the Company. The complaint set forth claims for breach of fiduciary duty, waste of corporate assets, abuse of control and gross mismanagement. Specifically, the shareholder plaintiff alleged that the defendants caused the Company to overstate its revenues through so-called "round trip" transactions. The plaintiff also alleged breach of fiduciary duty in connection with the spin-off of RRI and the RRI Offering. The complaint sought monetary damages on behalf of the Company as well as equitable relief in the form of a constructive trust on the compensation paid to the defendants. The Company's board of directors investigated that demand and similar allegations made in a June 28, 2002 demand letter sent on behalf of a Company shareholder. The second letter demanded that the Company take several actions in response to alleged round-trip trades occurring in 1999, 2000, and 2001. In June 2003, the board determined that these proposed actions would not be in the best interests of the Company. In March 2003, the court dismissed this case on the grounds that the plaintiff did not make an adequate demand on the Company before filing suit. Thereafter, the same party sent another demand asserting the same claims, but there has been no further activity. The Company believes that none of the lawsuits described under Other Class Action Lawsuits has merit because, among other reasons, the alleged misstatements and omissions were not material and did not result in any damages to the plaintiffs. Other Legal Matters Texas Antitrust Actions. In July 2003, Texas Commercial Energy filed in federal court in Corpus Christi, Texas a lawsuit against Reliant Energy, the Company and CenterPoint Houston, as successors to Reliant Energy, Genco LP, RRI, Reliant Energy Solutions, LLC, several other RRI subsidiaries and a number of other participants in the Electric Reliability Council of Texas (ERCOT) power market. The plaintiff, a retail electricity provider with the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws and committed fraud and negligent misrepresentation. The lawsuit sought damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys' fees. The plaintiff's principal allegations had previously been investigated by the Texas Utility Commission and found to be without merit. In June 2004, the federal court dismissed the plaintiff's claims and the plaintiff appealed to the U.S. Fifth Circuit Court of Appeals, which affirmed the dismissal. The plaintiff has now sought review by the U.S. Supreme Court in a petition for certiorari. The Company is vigorously contesting the appeal. The ultimate outcome of this matter cannot be predicted at this time. In February 2005, Utility Choice Electric filed in federal court in Houston, Texas a lawsuit against the Company, CenterPoint Houston, CenterPoint Energy Gas Services, Inc., CenterPoint Energy Alternative Fuels, Inc., Genco LP and a number of other participants in the ERCOT power market. The plaintiff, a retail electricity provider with the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws, intentionally interfered with prospective business relationships and contracts, and committed fraud and negligent misrepresentation. The plaintiff's principal allegations had previously been investigated by the Texas Utility Commission and found to be without merit. The Company intends to vigorously defend the case. The ultimate outcome of this matter cannot be predicted at this time. 23
Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena (Three Cities) filed suit in state district court in Harris County, Texas for themselves and a proposed class of all similarly situated cities in Reliant Energy's electric service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly owned subsidiary of the Company's predecessor, Reliant Energy) alleging underpayment of municipal franchise fees. The plaintiffs claimed that they were entitled to 4% of all receipts of any kind for business conducted within these cities over the previous four decades. After a jury trial involving the Three Cities' claims (but not the class of cities), the trial court entered a judgment on the Three Cities' breach of contract claims for $1.7 million, including interest, plus an award of $13.7 million in legal fees. It also decertified the class. Following this ruling, 45 cities filed individual suits against Reliant Energy in the District Court of Harris County. On February 27, 2003, a state court of appeals in Houston rendered an opinion reversing the judgment against the Company and rendering judgment that the Three Cities take nothing by their claims. The court of appeals held that all of the Three Cities' claims were barred by the jury's finding of laches, a defense similar to the statute of limitations, due to the Three Cities' having unreasonably delayed bringing their claims during the more than 30 years since the alleged wrongs began. The court also held that the Three Cities were not entitled to recover any attorneys' fees. The Three Cities filed a petition for review to the Texas Supreme Court, which declined to hear the case. Thus, the Three Cities' claims have been finally resolved in the Company's favor, but the individual claims of the remaining 45 cities remain pending in the same court. There has been no activity in the claims of the 45 cities since the Texas Supreme Court dismissed the claims of the Three Cities. The Company does not expect the outcome of the remaining claims to have a material impact on its financial condition, results of operations or cash flows. Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in a suit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs, and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs' alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the Btu content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. CERC and its subsidiaries believe that there has been no systematic mismeasurement of gas and that the suits are without merit. CERC does not expect the ultimate outcome to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC. Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CERC, Entex Gas Marketing Company, and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. Subsequently, the plaintiffs added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Gas Transmission Company, United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy Pipeline Services, Inc., and CenterPoint Energy Trading and Transportation Group, Inc., all of which are subsidiaries of the Company. The plaintiffs alleged that defendants inflated the prices charged 24
to certain consumers of natural gas. In February 2003, a similar suit was filed in state court in Caddo Parish, Louisiana against CERC with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against CERC seeking to recover alleged overcharges for gas or gas services allegedly provided by Southern Gas Operations to a purported class of certain consumers of natural gas and gas service without advance approval by the Louisiana Public Service Commission (LPSC). In October 2004, a similar case was filed in district court in Miller County, Arkansas against the Company, CERC, Entex Gas Marketing Company, CenterPoint Energy Gas Transmission Company, CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc., Mississippi River Transmission Corp. and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in at least the states of Arkansas, Louisiana, Mississippi, Oklahoma and Texas. At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish cases have been stayed pending the resolution of the respective proceedings by the LPSC. The plaintiffs in the Miller County case seek class certification, but the proposed class has not been certified. In November 2004, the Miller County case was removed to federal district court in Texarkana, Arkansas. In February 2005, the Wharton County case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily moved to dismiss the case and agreed not to refile the claims asserted unless the Miller County case is not certified as a class action or is later decertified. In June 2005, the Miller County case was remanded to state district court in Miller County. The range of relief sought by the plaintiffs in these cases includes injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages, civil penalties and attorney's fees. In these cases, the Company, CERC and their affiliates deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. The allegations in these cases are similar to those asserted in the City of Tyler proceeding described in Note 5(d). The Company and CERC do not expect the outcome of these matters to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC. Pipeline Safety Compliance. In 2005, CERC received an order from the Minnesota Office of Pipeline Safety to remove certain components from a portion of its distribution system by December 2, 2005. Those components were installed by a predecessor company and are not in compliance with current state and federal codes. CERC estimates the amount of expenditures to locate and replace such components to be approximately $38 million. CERC is seeking to recover the capitalized expenditures, together with a return on those amounts through rates. Minnesota Cold Weather Rule. In December 2004, the MPUC opened an investigation to determine whether CERC's practices regarding restoring natural gas service during the period between October 15 and April 15 (Cold Weather Period) are in compliance with the MPUC's Cold Weather Rule (CWR), which governs disconnection and reconnection of customers during the Cold Weather Period. The Minnesota Office of the Attorney General (OAG) issued its report alleging CERC has violated the CWR and recommended a $5 million penalty. CERC filed its reply comments in July 2005. CERC and the OAG have reached agreement on procedures to be followed for the current Cold Weather Period beginning October 15, 2005. In addition, in June 2005, CERC was named in a suit filed on behalf of a purported class of customers who allege that CERC's conduct under the CWR was in violation of the Minnesota Consumer Fraud Act and the Minnesota Deceptive Trade Practices Act and was negligent and fraudulent. CERC believes that it has not knowingly and intentionally violated the CWR and intends to vigorously contest the lawsuit. CERC does not expect this matter to have a material adverse effect on its financial condition, results of operations or cash flows. (b) Environmental Matters. Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. 25
Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The Company does not expect the ultimate cost associated with resolving this matter to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC. Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory. CERC believes that it has no liability with respect to two of these sites. At September 30, 2005, CERC had accrued $18 million for remediation of certain Minnesota sites. At September 30, 2005, the estimated range of possible remediation costs for these sites was $7 million to $42 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of September 30, 2005, CERC has collected a total of $13 million from insurance companies and its environmental tracker to be used for future environmental remediation. In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in two lawsuits under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is the subject of one of the lawsuits. In March 2005, the court considering the other suit for contribution granted CERC's motion to dismiss on the grounds that CERC was not an "operator" of the site as had been alleged. The plaintiff in that case has filed an appeal of the court's dismissal of CERC. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of those sites under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting those suits and its designation as a PRP. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company does not expect the costs of any remediation of these sites to be material to the Company's financial condition, results of operations or cash flows. Asbestos. A number of facilities owned by the Company contain significant amounts of asbestos insulation and other asbestos-containing materials. The Company or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations owned by the Company, but most existing claims relate to facilities previously owned by the Company but currently owned by Texas Genco LLC. The Company anticipates that additional claims like those received may be asserted in the future. Under the terms of the separation agreement between the Company and Texas Genco, ultimate financial responsibility for uninsured losses relating to these claims has been assumed by Texas Genco, but under the terms of its agreement to sell Texas Genco 26
to Texas Genco LLC, the Company has agreed to continue to defend such claims to the extent they are covered by insurance maintained by the Company, subject to reimbursement of the costs of such defense from Texas Genco LLC. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company's financial condition, results of operations or cash flows. Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company's financial condition, results of operations or cash flows. (c) Other Proceedings. The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management does not expect the disposition of these matters to have a material adverse effect on the Company's financial condition, results of operations or cash flows. (d) Tax Contingencies. As discussed in Note 10 to the CenterPoint Energy Notes, in the 1997 through 2000 audit (which now includes 2001), the Internal Revenue Service (IRS) disallowed all deductions for original issue discount (OID) relating to the Company's 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) and 7% Automatic Common Exchange Securities (ACES). It is the contention of the IRS that (1) those instruments, in combination with the Company's long position in Time Warner common stock (TW Common), constitute a straddle under Section 1092 and 246 of the Internal Revenue Code of 1986, as amended and (2) the indebtedness underlying those instruments was incurred to carry the TW Common. If the IRS prevails on both of these positions, all OID (including interest actually paid) on the ZENS and ACES would not be currently deductible, but would instead be added to the Company's basis in the TW Common it holds. The capitalization of OID to the TW Common basis would have the effect of recharacterizing ordinary interest deductions to capital losses or reduced capital gains. The Company's ability to realize the tax benefit of future capital losses, if any, from the sale of the 21.6 million shares of TW Common currently held will depend on the timing of those sales, the value of TW Common stock when sold, and the extent of any other capital gains and losses. Although the Company is protesting the contention of the IRS, at December 31, 2004, the Company had established a tax reserve for this issue of $79 million, which was increased to $111 million at September 30, 2005. The additions to the reserve for the three and nine months ended September 30, 2005 were $10 million and $32 million, respectively. The Company has also reserved for other significant tax items including issues relating to acquisitions, capital cost recovery and certain positions taken with respect to state tax filings. The total amount reserved for the other items is approximately $42 million. (e) Nuclear Decommissioning Trusts. CenterPoint Houston, as collection agent for the nuclear decommissioning charge assessed on its transmission and distribution customers, deposited $2.9 million in 2004 to trusts established to fund Texas Genco's share of the decommissioning costs for the South Texas Project, and expects to deposit approximately $2.9 million of collected charges in 2005. There are various investment restrictions imposed upon Texas Genco by the Texas Utility Commission and the Nuclear Regulatory Commission relating to Texas Genco's nuclear decommissioning trusts. Pursuant to the provisions of both a separation agreement and the Texas Utility Commission's final order, CenterPoint Houston and Texas Genco are presently jointly administering the decommissioning funds through the Nuclear Decommissioning Trust Investment Committee. Texas Genco and CenterPoint Houston have each appointed two members to the Nuclear Decommissioning Trust Investment Committee which establishes the 27
investment policy of the trusts and oversees the investment of the trusts' assets. As administrators of the decommissioning funds, CenterPoint Houston and Texas Genco are jointly responsible for assuring that the funds are prudently invested in a manner consistent with the rules of the Texas Utility Commission. CenterPoint Houston and Texas Genco expect to file a request with the Texas Utility Commission in 2005 to name Texas Genco as the sole fund administrator. Pursuant to the Texas electric restructuring law, costs associated with nuclear decommissioning that were not recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be charged to transmission and distribution customers of CenterPoint Houston or its successor. 28
(12) EARNINGS PER SHARE The following table reconciles numerators and denominators of the Company's basic and diluted earnings per share (EPS) calculations: FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, --------------------------- --------------------------- 2004 2005 2004 2005 ------------ ------------ ------------ ------------ (IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS) Basic EPS Calculation: Income from continuing operations before extraordinary item .............................. $ 17 $ 50 $ 43 $ 144 Discontinued operations, net of tax ................ (259) -- (154) (3) Extraordinary item, net of tax ..................... (894) -- (894) 30 ------------ ------------ ------------ ------------ Net income (loss) .................................. $ (1,136) $ 50 $ (1,005) $ 171 ============ ============ ============ ============ Weighted average shares outstanding ................... 307,592,000 309,657,000 306,954,000 309,080,000 ============ ============ ============ ============ Basic EPS: Income from continuing operations before extraordinary item .............................. $ 0.05 $ 0.16 $ 0.14 $ 0.46 Discontinued operations, net of tax ................ (0.84) -- (0.50) (0.01) Extraordinary item, net of tax ..................... (2.90) -- (2.91) 0.10 ------------ ------------ ------------ ------------ Net income (loss) .................................. $ (3.69) $ 0.16 $ (3.27) $ 0.55 ============ ============ ============ ============ Diluted EPS Calculation: Net income (loss) .................................. $ (1,136) $ 50 $ (1,005) $ 171 Plus: Income impact of assumed conversions: Interest on 3.75% convertible senior notes ...... -- 2 -- 9 ------------ ------------ ------------ ------------ Total earnings effect assuming dilution ............ $ (1,136) $ 52 $ (1,005) $ 180 ============ ============ ============ ============ Weighted average shares outstanding ................... 307,592,000 309,657,000 306,954,000 309,080,000 Plus: Incremental shares from assumed conversions (1): Stock options ................................... 1,280,000 1,457,000 1,235,000 1,259,000 Restricted stock ................................ 1,276,000 1,500,000 1,276,000 1,500,000 2.875% convertible senior notes ................. -- 1,620,000 -- -- 3.75% convertible senior notes .................. -- 32,269,000 -- 43,183,000 6.25% convertible trust preferred securities .... 17,000 -- 17,000 -- ------------ ------------ ------------ ------------ Weighted average shares assuming dilution .......... 310,165,000 346,503,000 309,482,000 355,022,000 ============ ============ ============ ============ Diluted EPS: Income from continuing operations before extraordinary item .............................. $ 0.05 $ 0.15 $ 0.14 $ 0.43 Discontinued operations, net of tax ................ (0.83) -- (0.50) (0.01) Extraordinary item, net of tax ..................... (2.88) -- (2.89) 0.09 ------------ ------------ ------------ ------------ Net income (loss) .................................. $ (3.66) $ 0.15 $ (3.25) $ 0.51 ============ ============ ============ ============ - ---------- (1) For the three months ended September 30, 2004 and 2005, the computation of diluted EPS excludes options to purchase 10,005,605 and 8,940,201 shares of common stock, respectively, that have exercise prices (ranging from $11.29 to $32.26 per share and $14.01 to $32.26 per share for the third quarter of 2004 and 2005, respectively) greater than the per share average market price for the period and would thus be antidilutive if exercised. For the nine months ended September 30, 2004 and 2005, the computation of diluted EPS excludes options to purchase 12,015,605 and 8,940,201 shares of common stock, respectively, that have exercise prices (ranging 29
from $10.92 to $32.26 per share and $14.01 to $32.26 per share for the first nine months of 2004 and 2005, respectively) greater than the per share average market price for the period and would thus be antidilutive if exercised. Diluted earnings per share for the three months and nine months ended September 30, 2004 have not been restated for the adoption of EITF 04-8, effective December 31, 2004, as inclusion of the contingently convertible shares had an antidilutive effect. The impact on the Company's diluted EPS from continuing operations for the three and nine months ended September 30, 2005 was a decrease of $0.01 and $0.03 per share, respectively. In accordance with EITF 04-8, because all of the 2.875% contingently convertible senior notes and approximately $572 million of the 3.75% contingently convertible senior notes provide for settlement of the principal portion in cash rather than stock, the Company excludes the portion of the conversion value of these notes attributable to their principal amount from its computation of diluted earnings per share from continuing operations. The Company includes the conversion spread in the calculation of diluted earnings per share when the average market price of the Company's common stock in the respective reporting period exceeds the conversion price. The conversion prices for the 2.875% and the 3.75% contingently convertible senior notes are $12.81 and $11.58, respectively. (13) REPORTABLE BUSINESS SEGMENTS The Company's determination of reportable business segments considers the strategic operating units under which the Company manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The Company has identified the following reportable business segments: Electric Transmission & Distribution, Natural Gas Distribution, Pipelines and Gathering and Other Operations. The Company's generation operations, which were previously reported in the Electric Generation business segment, are presented as discontinued operations within these Interim Financial Statements. Financial data for the Company's reportable business segments are as follows: FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2004 --------------------------------------------- REVENUES FROM NET EXTERNAL INTERSEGMENT OPERATING CUSTOMERS REVENUES INCOME (LOSS) ------------- ------------ ------------- (IN MILLIONS) Electric Transmission & Distribution .. $ 448(1) $ -- $178 Natural Gas Distribution .............. 1,146 3 (2) Pipelines and Gathering ............... 73 35 35 Other Operations ...................... 2 -- (4) Eliminations .......................... -- (38) -- ------ ---- ---- Consolidated .......................... $1,669 $ -- $207 ====== ==== ==== 30
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005 ----------------------------------------------------- REVENUES FROM NET INTERSEGMENT OPERATING EXTERNAL CUSTOMERS REVENUES INCOME (LOSS) ------------------ ---------------- ------------- (IN MILLIONS) Electric Transmission & Distribution .. $ 484(1) $ -- $183 Natural Gas Distribution .............. 1,651 -- (12) Pipelines and Gathering ............... 81 35 52 Other Operations ...................... 2 2 2 Eliminations .......................... -- (37) -- ------ ---- ---- Consolidated .......................... $2,218 $ -- $225 ====== ==== ==== FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004 -------------------------------------------- REVENUES FROM NET TOTAL ASSETS EXTERNAL INTERSEGMENT OPERATING AS OF CUSTOMERS REVENUES INCOME (LOSS) DECEMBER 31, 2004 ------------- ------------ ------------- ----------------- (IN MILLIONS) Electric Transmission & Distribution .. $1,153(1) $ -- $390 $ 8,783 Natural Gas Distribution .............. 4,522 3 137 4,798 Pipelines and Gathering ............... 217 107 123 2,637 Other Operations ...................... 5 3 (17) 2,794 Discontinued Operations ............... -- -- -- 1,565 Eliminations .......................... -- (113) -- (2,415) ------ ----- ---- ------- Consolidated .......................... $5,897 $ -- $633 $18,162 ====== ===== ==== ======= FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------------- REVENUES FROM NET TOTAL ASSETS EXTERNAL INTERSEGMENT OPERATING AS OF CUSTOMERS REVENUES INCOME (LOSS) SEPTEMBER 30, 2005 ------------- ------------ ------------- ------------------ (IN MILLIONS) Electric Transmission & Distribution .. $1,243(1) $ -- $385 $ 8,355 Natural Gas Distribution .............. 5,408 3 146 5,338 Pipelines and Gathering ............... 252 110 168 2,925 Other Operations ...................... 9 6 (12) 1,853 Eliminations .......................... -- (119) -- (1,959) ------ ----- ---- ------- Consolidated .......................... $6,912 $ -- $687 $16,512 ====== ===== ==== ======= - ---------- (1) Sales to subsidiaries of RRI represented approximately $265 million and $249 million of CenterPoint Houston's transmission and distribution revenues from external customers for the three months ended September 30, 2004 and 2005, respectively, and approximately $666 million and $615 million for the nine months ended September 30, 2004 and 2005, respectively. 31
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES The following discussion and analysis should be read in combination with our Interim Financial Statements contained in this Form 10-Q. EXECUTIVE SUMMARY RECENT EVENTS RECOVERY OF TRUE-UP BALANCE The Texas Electric Choice Plan (Texas electric restructuring law) provides for the Public Utility Commission of Texas (Texas Utility Commission) to conduct a "true-up" proceeding to determine CenterPoint Energy Houston Electric, LLC's (CenterPoint Houston) stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for its recovery of those costs. In March 2004, CenterPoint Houston filed its stranded cost true-up application with the Texas Utility Commission. CenterPoint Houston had requested recovery of $3.7 billion, excluding interest. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. That court held a hearing on the appeal in early August 2005, and on August 26, 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the Texas Utility Commission's order, but reversed two of the Texas Utility Commission's rulings, which would have the effect of restoring approximately $620 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston's initial request. First, the court reversed the Texas Utility Commission's decision to prohibit CenterPoint Houston from recovering $180 million in credits through August 2004 that CenterPoint Houston was ordered to provide to retail electric providers as a result of a stranded cost estimate made by the Texas Utility Commission in 2000 that subsequently proved to be inaccurate. Second, the court reversed the Texas Utility Commission's disallowance of $440 million in transition costs which are recoverable under the Texas Utility Commission's regulations. Additional credits of approximately $30 million paid after August 2004 and interest would be added to these amounts. CenterPoint Houston and other parties appealed the district court decision to the 3rd Court of Appeals in Austin in September 2005. The parties have agreed to a briefing schedule whereby briefs will be filed by the parties on a schedule extending into February 2006. No amounts related to the court's judgment have been recorded in our consolidated financial statements. There are two ways for CenterPoint Houston to recover the true-up balance: by issuing transition bonds to securitize the amounts due and/or by implementing a competition transition charge (CTC). In March 2005, the Texas Utility Commission issued a financing order that authorized the issuance of approximately $1.8 billion of transition bonds. In August 2005, the same Travis County District Court considering the appeal of the True-Up Order affirmed the financing order in all respects. CenterPoint Houston expects to complete the issuance of transition bonds under that order in the fourth quarter of 2005, subject to, among other matters, market conditions and the completion of documentation and rating agency reviews. On July 14, 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC to collect approximately $570 million over 14 years plus interest at an annual rate of 11.075%. The CTC order authorizes CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not covered by the financing order. The CTC order also allows CenterPoint Houston to collect approximately $24 million of rate case expenses over three years through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $600 million and the rate case expenses. Certain other parties appealed the CTC order to the Travis County Court on September 27, 2005. Additionally, during the period from September 13, 2005, the date of implementation of the CTC order, through September 30, 2005, CenterPoint Houston recognized approximately $7 million in CTC revenue, which was partially offset by $5 million in related amortization of the CTC regulatory asset. 32
CenterPoint Houston is entitled to accrue a return on the true-up balance until it is fully recovered. CITY OF HOUSTON FRANCHISE On June 27, 2005, CenterPoint Houston accepted an ordinance granting CenterPoint Houston a new 30-year franchise to use the public rights-of-way to conduct its business in the City of Houston (New Franchise Ordinance). The New Franchise Ordinance took effect on July 1, 2005, and replaced the prior electricity franchise ordinance, which had been in effect since 1957. The New Franchise Ordinance clarifies certain operational obligations of CenterPoint Houston and the City of Houston and provides for streamlined payment and audit procedures and a two- year statute of limitations on claims for underpayment or overpayment under the ordinance. Under the prior electricity franchise ordinance, CenterPoint Houston paid annual franchise fees of $76.6 million to the City of Houston for the year ended December 31, 2004. For the twelve-month period beginning July 1, 2005, the annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance will include a base amount of $88.1 million (Base Amount) and an additional payment of $8.5 million (Additional Amount). The Base Amount and the Additional Amount will be adjusted annually based on the increase, if any, in kWh delivered by CenterPoint Houston within the City of Houston. CenterPoint Houston began paying the new annual franchise fees on July 1, 2005. Pursuant to the New Franchise Ordinance, the Annual Franchise Fee will be reduced prospectively to reflect any portion of the Annual Franchise Fee that is not included in CenterPoint Houston's base rates in any subsequent rate case. In accordance with CenterPoint Houston's rights under the New Franchise Ordinance, CenterPoint Houston filed a request with the City of Houston to implement a tariff rider to collect the Additional Amount, but subsequently asked the City of Houston to abate further consideration of that application. DEBT FINANCING TRANSACTIONS In August 2005, we accepted for exchange approximately $572 million aggregate principal amount of our 3.75% convertible senior notes due 2023 (Old Notes) for an equal amount of our new 3.75% convertible senior notes due 2023 (New Notes). Old Notes of approximately $3 million remain outstanding. We commenced the exchange offer in response to the guidance set forth in Emerging Issues Task Force (EITF) Issue No. 04-8, "Accounting Issues Related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per Share" (EITF 04-8). Under that guidance, because settlement of the principal portion of the New Notes will be made in cash rather than stock, the exchange of New Notes for Old Notes will allow us to exclude the portion of the conversion value of the New Notes attributable to their principal amount from our computation of diluted earnings per share from continuing operations. REPEAL OF THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act). Under that legislation, the Public Utility Holding Company Act of 1935 (1935 Act) is repealed effective February 8, 2006. After the effective date of repeal, we and our subsidiaries will no longer be subject to restrictions imposed under the 1935 Act. Until the repeal is effective, we and our subsidiaries remain subject to the provisions of the 1935 Act and the terms of orders issued by the Securities and Exchange Commission (SEC) under the 1935 Act. The Energy Act grants to the Federal Energy Regulatory Commission (FERC) authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by FERC and state regulatory authorities. The Energy Act requires FERC to issue regulations to implement its jurisdiction under the Energy Act, and on September 16, 2005, FERC issued proposed rules for public comment. It is presently unknown what, if any, specific obligations under those rules may be imposed on us and our subsidiaries as a result of that rulemaking. 33
3RD QUARTER 2005 HIGHLIGHTS Our operating performance for the third quarter of 2005 compared to the third quarter of 2004 was affected by: - increased operating income of $17 million in our Pipelines and Gathering business segment primarily from increased demand for certain transportation and ancillary services and increased throughput and demand for services related to our core gas gathering operations; - continued customer growth, with the addition of 95,000 metered electric and gas customers; - an increase in other income of $35 million for the third quarter of 2005 related to the return on our true-up balance; and - a decrease in interest expense of $15 million. The above increases in operating performance were partially offset by a net reduction of operating income of $10 million in our Natural Gas Distribution business segment primarily due to increased bad debt expense and higher depreciation expense, partially offset by rate increases and continued customer growth. CONSOLIDATED RESULTS OF OPERATIONS All dollar amounts in the tables that follow are in millions, except for per share amounts. THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ------- ------ ------- ------ Revenues ........................................................ $ 1,669 $2,218 $ 5,897 $6,912 Expenses ........................................................ 1,462 1,993 5,264 6,225 ------- ------ ------- ------ Operating Income ................................................ 207 225 633 687 Interest and Other Finance Charges .............................. (192) (177) (583) (548) Other Income, net ............................................... 4 43 18 127 ------- ------ ------- ------ Income From Continuing Operations Before Income Taxes and Extraordinary Item ........................................... 19 91 68 266 Income Tax Expense .............................................. (2) (41) (25) (122) ------- ------ ------- ------ Income From Continuing Operations Before Extraordinary Item ..... 17 50 43 144 Discontinued Operations, net of tax ............................. (259) -- (154) (3) ------- ------ ------- ------ Income (Loss) Before Extraordinary Item ......................... (242) 50 (111) 141 Extraordinary Item, net of tax .................................. (894) -- (894) 30 ------- ------ ------- ------ Net Income (Loss) ............................................... $(1,136) $ 50 $(1,005) $ 171 ======= ====== ======= ====== BASIC EARNINGS PER SHARE: Income From Continuing Operations Before Extraordinary Item .. $ 0.05 $ 0.16 $ 0.14 $ 0.46 Discontinued Operations, net of tax .......................... (0.84) -- (0.50) (0.01) Extraordinary Item, net of tax ............................... (2.90) -- (2.91) 0.10 ------- ------ ------- ------ Net Income (Loss) ............................................ $ (3.69) $ 0.16 $ (3.27) $ 0.55 ======= ====== ======= ====== DILUTED EARNINGS PER SHARE: Income From Continuing Operations Before Extraordinary Item .. $ 0.05 $ 0.15 $ 0.14 $ 0.43 Discontinued Operations, net of tax .......................... (0.83) -- (0.50) (0.01) Extraordinary Item, net of tax ............................... (2.88) -- (2.89) 0.09 ------- ------ ------- ------ Net Income (Loss) ............................................ $ (3.66) $ 0.15 $ (3.25) $ 0.51 ======= ====== ======= ====== 34
THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004 Income from Continuing Operations. We reported income from continuing operations of $50 million ($0.15 per diluted share) for the three months ended September 30, 2005 as compared to $17 million ($0.05 per diluted share) for the same period in 2004. The increase in income from continuing operations of $33 million was primarily due to increased operating income of $17 million in our Pipelines and Gathering business segment resulting from increased demand for certain transportation and ancillary services as well as increased throughput and demand for services related to our core gas gathering operations, $35 million of other income related to a return on the true-up balance of our Electric Transmission & Distribution business segment as a result of the True-Up Order and a $15 million decrease in interest expense due to lower borrowing levels and lower borrowing costs reflecting the replacement of certain of our credit facilities. These increases were partially offset by higher bad debt expense and depreciation expense in our Natural Gas Distribution business segment. Additionally, income tax expense increased in the third quarter of 2005 as discussed below. Income Tax Expense. During the three months ended September 30, 2004 and 2005, our effective tax rate was 11.6% and 45.2%, respectively. The most significant item affecting our effective tax rate in the third quarter of 2005 was an addition to the tax reserve of approximately $10 million relating to the contention of the Internal Revenue Service (IRS) that the current deductions for original issue discount (OID) on our 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) be capitalized, potentially converting what would be ordinary deductions into capital losses at the time the ZENS are settled. We expect the reserve to increase by approximately $13 million in the fourth quarter. NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004 Income from Continuing Operations. We reported income from continuing operations before extraordinary item of $144 million ($0.43 per diluted share) for the nine months ended September 30, 2005 as compared to $43 million ($0.14 per diluted share) for the same period in 2004. The increase in income from continuing operations of $101 million was primarily due to increased operating income of $45 million in our Pipelines and Gathering business segment resulting from increased demand for certain transportation and ancillary services as well as increased throughput and demand for services related to our core gas gathering operations, increased operating income of $9 million in our Natural Gas Distribution business segment primarily due to rate increases, reduced pension and benefit costs and the absence of severance costs recorded in the first quarter of 2004, partially offset by milder weather, decreased throughput and increased depreciation, $104 million of other income related to a return on the true-up balance of our Electric Transmission & Distribution business segment as a result of the True-Up Order, and a $35 million decrease in interest expense due to lower borrowing levels and lower borrowing costs reflecting the replacement of certain of our credit facilities. The above increases were partially offset by decreased operating income of $5 million in our Electric Transmission & Distribution business segment primarily from increased state and local taxes and higher operation and maintenance expenses including the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in the second quarter of 2004 and the absence of an $11 million gain from a land sale recorded in the second quarter of 2004, partially offset by increased usage mainly due to weather, continued customer growth and higher transmission cost recovery. Additionally, income tax expense increased in the nine months ended September 30, 2005 as discussed below. Income Tax Expense. During the nine months ended September 30, 2004 and 2005, our effective tax rate was 36.7% and 45.9%, respectively. The most significant item affecting our effective tax rate in the first nine months of 2005 is an addition to the tax reserve of approximately $32 million relating to the ZENS as discussed above. INTEREST EXPENSE AND OTHER FINANCE CHARGES In accordance with Emerging Issues Task Force Issue No. 87-24 "Allocation of Interest to Discontinued Operations," we have reclassified interest to discontinued operations of Texas Genco based on net proceeds received from the sale of Texas Genco of $2.5 billion, and have applied the proceeds to the amount of debt assumed to be paid down in 2004 according to the terms of the respective credit facilities in effect for that period. In periods where only the term loan was assumed to be repaid, the actual interest paid on the term loan was reclassified. In periods where a portion of the revolver was assumed to be repaid, the percentage of that portion of the revolver to the total 35
outstanding balance was calculated, and that percentage was applied to the actual interest paid in those periods to compute the amount of interest reclassified. Total interest expense incurred was $206 million and $621 million for the three and nine months ended September 30, 2004. We have reclassified $14 million and $38 million of interest expense for the three and nine months ended September 30, 2004 based upon interest expense associated with debt that would have been required to be repaid as a result of our disposition of Texas Genco. EXTRAORDINARY ITEM AND LOSS ON DISPOSAL OF TEXAS GENCO Net income for the nine months ended September 30, 2005 included an after-tax extraordinary gain of $30 million ($0.09 per diluted share) reflecting an adjustment to the extraordinary loss recorded in the last half of 2004 to write-down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission. Net income for the three months ended September 30, 2004 included a net after-tax loss from discontinued operations of Texas Genco of $259 million ($0.83 per diluted share). Net income for the nine months ended September 30, 2004 and 2005 included a net after tax loss from discontinued operations of Texas Genco of $154 million ($0.50 per diluted share) and $3 million ($0.01 per diluted share), respectively. RESULTS OF OPERATIONS BY BUSINESS SEGMENT The following table presents operating income for each of our business segments for the three and nine months ended September 30, 2004 and 2005. Some amounts from the previous year have been reclassified to conform to the 2005 presentation of the financial statements. These reclassifications do not affect consolidated net income. THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ---- ---- ---- ---- (IN MILLIONS) Electric Transmission & Distribution ........... $178 $183 $390 $385 Natural Gas Distribution ....................... (2) (12) 137 146 Pipelines and Gathering ........................ 35 52 123 168 Other Operations ............................... (4) 2 (17) (12) ---- ---- ---- ---- Total Consolidated Operating Income.......... $207 $225 $633 $687 ==== ==== ==== ==== 36
ELECTRIC TRANSMISSION & DISTRIBUTION For information regarding factors that may affect the future results of operations of our Electric Transmission & Distribution business segment, please read "Risk Factors -- Risk Factors Affecting Our Electric Transmission & Distribution Business," " -- Risk Factors Associated with Our Consolidated Financial Condition" and "-- Other Risks" in Item 5 of Part II of this report beginning on page 52. The following tables provide summary data of our Electric Transmission & Distribution business segment for the three and nine months ended September 30, 2004 and 2005: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ----------------------- 2004 2005 2004 2005 ---------- ---------- ---------- ---------- (IN MILLIONS, EXCEPT CUSTOMER DATA) Electric transmission and distribution revenues ............... $ 427 $ 453 $ 1,099 $ 1,164 ---------- ---------- ---------- ---------- Electric transmission and distribution expenses: Operation and maintenance .................................. 136 155 394 446 Depreciation and amortization .............................. 63 69 186 197 Taxes other than income taxes .............................. 59 55 158 163 ---------- ---------- ---------- ---------- Total electric transmission and distribution expenses ... 258 279 738 806 ---------- ---------- ---------- ---------- Operating Income - Electric transmission and distribution utility .................................................... 169 174 361 358 Operating Income - Transition bond company (1) ................ 9 9 29 27 ---------- ---------- ---------- ---------- Total Segment Operating Income ................................ $ 178 $ 183 $ 390 $ 385 ========== ========== ========== ========== Actual gigawatt-hours (GWh) delivered: Residential ................................................ 8,512 8,871 18,714 19,607 Total ...................................................... 22,568 22,351 56,634 57,134 Average number of metered customers: Residential ................................................ 1,645,523 1,690,819 1,633,890 1,675,904 Total ...................................................... 1,870,128 1,921,594 1,856,551 1,904,235 - ---------- (1) Represents the amount necessary to pay interest on the transition bonds. THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004 Our Electric Transmission & Distribution business segment reported operating income of $183 million for the three months ended September 30, 2005, consisting of $174 million for the regulated electric transmission and distribution utility and $9 million for the transition bond company. For the three months ended September 30, 2004, operating income totaled $178 million, consisting of $169 million for the regulated electric transmission and distribution utility and $9 million for the transition bond company. Operating revenues increased primarily due to continued customer growth ($11 million) with the addition of 53,000 metered customers since September 2004, competition transition charge (CTC) recovery of our 2004 true-up balance not covered by the transition bond finance order ($7 million) and higher transmission cost recovery ($5 million). The increase in operating revenues was partially offset by higher transmission costs ($8 million), the absence of a gain from a land sale recorded in the third quarter of 2004 ($11 million), increased amortization related to the CTC regulatory asset resulting from the 2004 true-up balance ($5 million), partially offset by decreased state and local taxes ($4 million). NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004 Our Electric Transmission & Distribution business segment reported operating income of $385 million for the nine months ended September 30, 2005, consisting of $358 million for the regulated electric transmission and distribution utility and $27 million for the transition bond company. For the nine months ended September 30, 2004, operating income totaled $390 million, consisting of $361 million for the regulated electric transmission and distribution utility and $29 million for the transition bond company. Operating revenues increased primarily due to increased usage resulting from warmer weather ($10 million), continued customer growth ($26 million) with the addition of 53,000 metered customers since September 2004, CTC recovery of our 2004 true-up balance not covered by the transition bond finance order ($7 million) and higher transmission cost recovery ($13 million). The increase 37
in operating revenues was more than offset by higher transmission costs ($16 million), the absence of a gain from a land sale recorded in the third quarter of 2004 ($11 million), the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in 2004, higher depreciation and amortization expense ($11 million, including $5 million of amortization related to the CTC regulatory asset resulting from the 2004 true-up balance) and increased state and local taxes ($5 million). In September 2005, CenterPoint Houston's service area in Texas was adversely affected by Hurricane Rita. Although damage to CenterPoint Houston's electric facilities was limited, over 700,000 customers lost power at the height of the storm. Power was restored to over a half million customers within 36 hours and all power was restored in less than five days. The Electric Transmission & Distribution business segment's revenues lost as a result of the storm were more than offset by warmer than normal weather during the quarter. CenterPoint Houston estimates restoration costs in its service area to be in the range of $20 to $30 million, which will be deferred for recovery in a future rate case. NATURAL GAS DISTRIBUTION For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read "Risk Factors -- Risk Factors Affecting Our Natural Gas Distribution and Pipelines and Gathering Businesses," " -- Risk Factors Associated with Our Consolidated Financial Condition" and "-- Other Risks" in Item 5 of Part II of this report beginning on page 52. The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2004 and 2005: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ----------------------- 2004 2005 2004 2005 ---------- ---------- ---------- ---------- (IN MILLIONS, EXCEPT CUSTOMER DATA) Revenues ................................ $ 1,149 $ 1,651 $ 4,525 $ 5,411 ---------- ---------- ---------- ---------- Expenses: Natural gas .......................... 959 1,456 3,776 4,644 Operation and maintenance ............ 133 141 416 414 Depreciation and amortization ........ 36 39 106 116 Taxes other than income taxes ........ 23 27 90 91 ---------- ---------- ---------- ---------- Total expenses .................... 1,151 1,663 4,388 5,265 ---------- ---------- ---------- ---------- Operating Income ........................ $ (2) $ (12) $ 137 $ 146 ========== ========== ========== ========== Throughput (in billion cubic feet (Bcf)): Residential .......................... 15 9 121 107 Commercial and industrial ............ 39 38 171 158 Non-rate regulated ................... 113 160 419 491 Elimination (1) ...................... (32) (26) (105) (104) ---------- ---------- ---------- ---------- Total Throughput .................. 135 181 606 652 ========== ========== ========== ========== Average number of customers: Residential .......................... 2,777,212 2,820,629 2,791,722 2,835,306 Commercial and industrial ............ 242,111 244,249 245,895 246,370 Non-rate regulated ................... 6,249 6,515 6,234 6,520 ---------- ---------- ---------- ---------- Total ............................. 3,025,572 3,071,393 3,043,851 3,088,196 ========== ========== ========== ========== - ---------- (1) Elimination of intrasegment sales. THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004 Our Natural Gas Distribution business segment reported an operating loss of $12 million for the three months ended September 30, 2005 as compared to an operating loss of $2 million for the same period in 2004. Increases in operating income from rate increases ($3 million) and increased margins from our non-rate regulated natural gas sales business ($11 million) were more than offset by the impact of certain derivative transactions as discussed below ($8 million), increases in operation and maintenance expenses ($8 million) primarily related to higher bad debt expense ($5 million), increased depreciation expense primarily due to higher plant balances ($3 million) and higher taxes other than income taxes ($4 million). 38
A portion of CenterPoint Energy Services, Inc.'s (CES) activities include entering into transactions for the physical purchase, transportation and sale of natural gas at different locations (physical contracts). CES attempts to mitigate basis risk associated with these activities by entering into financial derivative contracts (financial contracts or financial basis swaps) to address market price volatility between the purchase and sale delivery points that can occur over the term of the physical contracts. The underlying physical contracts are accounted for on an accrual basis with all associated earnings not recognized until the time of actual physical delivery. The timing of the earnings impacts for the financial contracts differs from the physical contracts because the financial contracts meet the definition of a derivative under SFAS No. 133, "Accounting for Derivative Instruments" (SFAS No. 133), and are recorded at fair value as of each reporting balance sheet date with changes in value reported through earnings. Changes in prices between the delivery points (basis spreads) can and do vary daily resulting in changes to the fair value of the financial contracts. However, the economic intent of the financial contracts is to fix the actual net difference in the natural gas pricing at the different locations for the associated physical purchase and sale contracts throughout the life of the physical contracts and thus, when combined with the physical contracts' terms, provide an expected fixed gross margin on the physical contracts that will ultimately be recognized in earnings at the time of actual delivery of the natural gas. As of September 30, 2005, the mark-to-market value of the financial contracts described above reflected an unrealized loss of $3.6 million; however, the underlying expected fixed gross margin associated with delivery under the physical contracts combined with the price risk management provided through the financial contracts is $2.3 million. As described above, over the term of these financial contracts, the quarterly reported mark-to-market changes in value may vary significantly and the associated unrealized gains and losses will be reflected in CES' earnings. CES also sells physical gas and basis to its end-use customers who desire to lock in a future spread between a specific location and Henry Hub (NYMEX). As a result, CES incurs exposure to commodity basis risk related to these transactions, which it attempts to mitigate by buying offsetting financial basis swaps. Under SFAS No. 133, CES records at fair value and marks-to-market the financial basis swaps as of each reporting balance sheet date with changes in value reported through earnings. However, the associated physical sales contracts are accounted for using the accrual basis, whereby earnings impacts are not recognized until the time of actual physical delivery. Although the timing of earnings recognition for the financial basis swaps differs from the physical contracts, the economic intent of the financial basis swaps is to fix the basis spread over the life of the physical contracts to an amount substantially the same as the portion of the basis spread pricing included in the physical contracts. In so doing, over the period that the financial basis swaps and related physical contracts are outstanding, actual cumulative earnings impacts for changes in the basis spread should be minimal, even though from a timing perspective there could be fluctuations in unrealized gains or losses associated with the changes in fair value recorded for the financial basis swaps. The cumulative earnings impact from the financial basis swaps recognized each reporting period is expected to be offset by the value realized when the related physical sales occur. As of September 30, 2005, the mark-to-market value of the financial basis swaps reflected an unrealized loss of $4.8 million. NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004 Our Natural Gas Distribution business segment reported operating income of $146 million for the nine months ended September 30, 2005 as compared to $137 million for the same period in 2004. Increases in operating income from rate increases ($19 million) and increased margins from our non-rate regulated natural gas sales business ($13 million) were partially offset by the impact of certain derivative transactions as discussed above ($8 million) and the impact of milder weather and decreased throughput net of continued customer growth with the addition of approximately 42,000 customers since September 2004 ($10 million). Operation and maintenance expense decreased $2 million. Excluding an $8 million charge recorded in the first quarter of 2004 for severance costs associated with staff reductions, operation and maintenance expenses increased by $6 million primarily due to increased bad debt expense ($7 million), partially offset by lower claims expense ($5 million) and the capitalization of previously incurred restructuring expenses as allowed by a regulatory order from the Railroad Commission of Texas ($5 million). Additionally, operating income was unfavorably impacted by increased depreciation expense primarily due to higher plant balances ($10 million). During the third quarter of 2005, our east Texas, Louisiana and Mississippi natural gas service areas were affected by Hurricanes Katrina and Rita. Damage to our facilities was limited, but approximately 10,000 homes and businesses were damaged to such an extent that they will not be taking service for the foreseeable future. The impact on the Natural Gas Distribution business segment's operating income was not material. PIPELINES AND GATHERING For information regarding factors that may affect the future results of operations of our Pipelines and Gathering business segment, please read "Risk Factors -- Risk Factors Affecting Our Natural Gas Distribution and Pipelines and Gathering Businesses," " -- Risk Factors Associated with Our Consolidated Financial Condition" and "-- Other Risks" in Item 5 of Part II of this report beginning on page 52. The following table provides summary data of our Pipelines and Gathering business segment for the three and nine months ended September 30, 2004 and 2005: 39
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ------ ------ ------- ------ (IN MILLIONS) Revenues .......................... $108 $116 $324 $362 ---- ---- ---- ---- Expenses: Natural gas .................... 6 -- 33 25 Operation and maintenance ...... 52 47 122 121 Depreciation and amortization .. 11 12 33 34 Taxes other than income taxes .. 4 5 13 14 ---- ---- ---- ---- Total expenses .............. 73 64 201 194 ---- ---- ---- ---- Operating Income .................. $ 35 $ 52 $123 $168 ==== ==== ==== ==== Throughput (in Bcf): Natural Gas Sales .............. 1 -- 8 4 Transportation ................. 181 199 658 700 Gathering ...................... 79 92 233 262 Elimination (1) ................ -- (1) (5) (4) ---- ---- ---- ---- Total Throughput ............ 261 290 894 962 ==== ==== ==== ==== - ---------- (1) Elimination of volumes both transported and sold. THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004 Our Pipelines and Gathering business segment reported operating income of $52 million for the three months ended September 30, 2005 compared to $35 million for the same period in 2004. Operating margins (revenues less natural gas costs) increased by $14 million primarily due to increased demand for certain transportation and ancillary services ($13 million) and increased throughput and demand for services related to our core gas gathering operations ($6 million), partially offset by reductions in project-related revenues ($6 million). Additionally, operation and maintenance expenses decreased by $5 million primarily due to a reduction in project-related expenses ($6 million), offset by increased litigation costs ($4 million) recorded in the third quarter of 2005. NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004 Our Pipelines and Gathering business segment reported operating income of $168 million for the nine months ended September 30, 2005 compared to $123 million for the same period in 2004. Operating margins (revenues less natural gas costs) increased by $46 million primarily due to increased demand for certain transportation and ancillary services ($31 million), increased throughput and demand for services related to our core gas gathering operations ($20 million), partially offset by reductions in project-related revenues ($10 million). Additionally, operation and maintenance expenses decreased by $1 million primarily due to a reduction in project-related expenses ($9 million), offset by increased litigation costs ($4 million) recorded in the third quarter of 2005. 40
OTHER OPERATIONS The following table shows the operating loss of our Other Operations business segment for the three and nine months ended September 30, 2004 and 2005: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ---- ---- ---- ---- (IN MILLIONS) Revenues ................. $ 2 $4 $ 8 $ 15 Expenses ................. 6 2 25 27 --- --- ---- ---- Operating Income (Loss) .. $(4) $2 $(17) $(12) === === ==== ==== DISCONTINUED OPERATIONS In July 2004, we announced our agreement to sell our majority owned subsidiary, Texas Genco, to Texas Genco LLC. On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco, whose principal remaining asset was its ownership interest in a nuclear generating facility, distributed $2.231 billion in cash to us. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to us of $700 million, was completed on April 13, 2005. We recorded an after-tax loss of $259 million and $154 million for the three and nine months ended September 30, 2004, respectively, related to the operations of Texas Genco. We recorded an after-tax loss of $3 million for the nine months ended September 30, 2005. General corporate overhead, previously allocated to Texas Genco from CenterPoint Energy, was $5 million and $15 million for the three and nine months ended September 30, 2004, respectively, and was less than $1 million for the nine months ended September 30, 2005. These amounts will not be eliminated by the sale of Texas Genco and were excluded from income from discontinued operations and reflected as general corporate overhead of CenterPoint Energy in income from continuing operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). The Interim Financial Statements present these operations as discontinued operations in accordance with SFAS No. 144. Interest expense of $14 million and $38 million for the three and nine months ended September 30, 2004, respectively, was reclassified to discontinued operations of Texas Genco related to the applicable amounts of CenterPoint Energy's term loan and revolving credit facility debt that would have been assumed to be paid off with any proceeds from the sale of Texas Genco during those respective periods in accordance with SFAS No. 144. CERTAIN FACTORS AFFECTING FUTURE EARNINGS For information on other developments, factors and trends that may have an impact on our future earnings, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Factors Affecting Future Earnings" in Item 7 of Part II of the Annual Report on Form 10-K of CenterPoint Energy for the year ended December 31, 2004 (CenterPoint Energy Form 10-K), which is incorporated herein by reference, and "Risk Factors" in Item 5 of Part II of this report beginning on page 52. 41
LIQUIDITY AND CAPITAL RESOURCES HISTORICAL CASH FLOWS The following table summarizes the net cash provided by (used in) operating, investing and financing activities from continuing operations for the nine months ended September 30, 2004 and 2005: NINE MONTHS ENDED SEPTEMBER 30, ----------------- 2004 2005 ----- ----- (IN MILLIONS) Cash provided by (used in): Operating activities ...... $ 354 $ 364 Investing activities ...... (304) 204 Financing activities ...... (117) (571) CASH PROVIDED BY OPERATING ACTIVITIES Net cash provided by operating activities in the first nine months of 2005 increased $10 million compared to the same period in 2004 primarily due to increased operating income, higher net accounts receivable/payable primarily due to higher gas prices in 2005 as compared to 2004 and the termination of excess mitigation credits effective April 29, 2005, partially offset by increased tax payments of $481 million, the majority of which related to the tax payment in the second quarter of 2005 associated with the sale of Texas Genco. CASH PROVIDED BY INVESTING ACTIVITIES Net cash provided by investing activities increased $508 million in the first nine months of 2005 as compared to the same period in 2004 primarily due to $700 million in proceeds received from the sale of our remaining interest in Texas Genco in April 2005, partially offset by increased capital expenditures of $138 million and the absence of a dividend from Texas Genco in 2005. CASH USED IN FINANCING ACTIVITIES In the first nine months of 2005, debt payments exceeded net loan proceeds by $483 million. During the first nine months of 2004, debt payments exceeded net loan proceeds by $34 million. Additionally, dividends paid in the first nine months of 2005 were $13 million higher than in the same period of 2004. FUTURE SOURCES AND USES OF CASH Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs, various regulatory actions and appeals relating to such regulatory actions. Our principal cash requirements for the last three months of 2005 include the following: - approximately $223 million of capital expenditures; - dividend payments on CenterPoint Energy common stock and debt service payments; - contributions to benefit plans; and - $1.3 billion of maturing long-term debt. We expect that borrowings under our credit facilities and anticipated cash flows from operations will be sufficient to meet our cash needs for the next twelve months. Cash needs may also be met by issuing securities in the capital markets. CenterPoint Houston's $1.31 billion term loan, maturing in November 2005, requires the proceeds from the issuance of transition bonds to be used to reduce the term loan unless refused by the lenders. CenterPoint Houston expects to utilize its $1.31 billion credit facility to refinance the $1.31 billion term loan at its maturity on November 11, 2005. Under this facility, (i) 100% of the net proceeds from the issuance of transition bonds and (ii) the proceeds, in excess of $200 million, from certain other new net indebtedness for borrowed money incurred by CenterPoint Houston must be used to repay borrowings under the facility. 42
The 1935 Act regulates our financing ability, as more fully described in "-- Certain Contractual and Regulatory Limits on Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock" below. On October 25, 2005, CenterPoint Energy Gas Transmission Company (CEGT), a subsidiary of CERC Corp., executed a definitive Precedent Agreement with XTO Energy Inc. (XTO) for CEGT to transport approximately 600 million cubic feet per day of XTO's natural gas production for ten years. To fulfill the requirements of the agreement, CEGT will construct a new 168-mile pipeline between Carthage, Texas and its Perryville Hub in northeast Louisiana. The $375 million pipeline will have an initial design capacity of approximately one Bcf per day. Pending authorization by FERC, the pipeline could be in service as early as the winter of 2006-2007. This agreement is expected to cause an increase in our estimated capital requirements of approximately $5 million, $353 million and $17 million in 2005, 2006 and 2007, respectively, for our Pipelines and Gathering business segment from what was previously disclosed in the CenterPoint Energy Form 10-K. Off-Balance Sheet Arrangements. Other than operating leases, we have no off-balance sheet arrangements. However, we do participate in a receivables factoring arrangement. CERC Corp. has a bankruptcy remote subsidiary, which we consolidate, which was formed for the sole purpose of buying receivables created by CERC and selling those receivables to an unrelated third-party. This transaction is accounted for as a sale of receivables under the provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," and, as a result, the related receivables are excluded from the Consolidated Balance Sheet. In January 2005, the $250 million facility was extended to January 2006 and temporarily increased, for the period from January 2005 to June 2005, to $375 million. As of September 30, 2005, CERC had $141 million of advances under its receivables facility. Credit Facilities. In June 2005, CERC Corp. replaced its $250 million three-year revolving credit facility with a $400 million five-year revolving credit facility. The new credit facility terminates on June 30, 2010. Borrowings under this facility may be made at the London interbank offered rate (LIBOR) plus 55 basis points, including the facility fee, based on current credit ratings. An additional utilization fee of 10 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. In March 2005, we replaced our $750 million revolving credit facility with a $1 billion five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 87.5 basis points based on current credit ratings. An additional utilization fee of 12.5 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. The facility contains covenants, including a debt to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant and an EBITDA to interest covenant. Borrowings under our credit facility are available upon customary terms and conditions for facilities of this type, including a requirement that we represent, except as described below, that no "material adverse change" has occurred at the time of a new borrowing under this facility. A "material adverse change" is defined as the occurrence of a material adverse change in our ability to perform our obligations under the facility but excludes any litigation related to the True-Up Order. The base line for any determination of a relative material adverse change is our most recently audited financial statements. At any time after the first time our credit ratings reach at least BBB by Standard & Poor's Ratings Services, a division of The McGraw Hill Companies (S&P), and Baa2 by Moody's Investors Service, Inc. (Moody's), BBB+ by S&P and Baa3 by Moody's, or BBB- by S&P and Baa1 by Moody's, or if the drawing is to retire maturing commercial paper, we are not required to represent as a condition to such drawing that no material adverse change has occurred or that no litigation expected to have a material adverse effect has occurred. Due to restrictions imposed on us under our June 29, 2005 financing order under the 1935 Act, we may not be able to draw the full amount of our credit agreement without further authorization from the SEC because such borrowings would reduce our common equity capitalization ratio below its level as of March 31, 2005. We do not expect this limitation to constrain our borrowings beyond the end of 2005 based on current projections. Additionally, these restrictions will no longer be applicable upon the effective date of the repeal of the 1935 Act. -For a discussion of these restrictions, see "-- Certain Contractual and Regulatory Limits on Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock" below. 43
Also in March 2005, CenterPoint Houston established a $200 million five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 75 basis points based on CenterPoint Houston's current credit ratings. An additional utilization fee of 12.5 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. CenterPoint Houston also established a $1.31 billion credit facility in March 2005. This facility can be utilized only to refinance CenterPoint Houston's $1.31 billion term loan maturing on November 11, 2005. Drawings may be made under this credit facility until November 16, 2005, at which time any outstanding borrowings are converted to term loans maturing in November 2007. Under this facility, (i) 100% of the net proceeds from the issuance of transition bonds and (ii) the proceeds, in excess of $200 million, from certain other new net indebtedness for borrowed money incurred by CenterPoint Houston must be used to repay borrowings under the facility. Based on CenterPoint Houston's current credit ratings, borrowings under the facility may be made at LIBOR plus 75 basis points. The interest rate under the term loan which this facility would replace is LIBOR plus 975 basis points. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. Any drawings under this facility must be secured by CenterPoint Houston's general mortgage bonds in the same principal amount and bearing the same interest rate as such drawings. CERC Corp.'s $400 million credit facility contains covenants, including a total debt to capitalization covenant of 65% and an EBITDA to interest covenant. CenterPoint Houston's $200 million and $1.31 billion credit facilities each contain covenants, including a debt (excluding transition bonds) to total capitalization covenant of 68% and an EBITDA to interest covenant. Borrowings under CERC Corp.'s $400 million credit facility and CenterPoint Houston's $200 million credit facility and its $1.31 billion credit facility are available notwithstanding that a material adverse change has occurred or litigation that could be expected to have a material adverse effect has occurred, so long as other customary terms and conditions are satisfied. As of November 1, 2005, we had the following credit facilities (in millions): AMOUNT UTILIZED AT DATE EXECUTED COMPANY SIZE OF FACILITY NOVEMBER 1, 2005 TERMINATION DATE - ------------- ------------------- ---------------- ------------------ ---------------- March 7, 2005 CenterPoint Energy $1,000 $271 (1) March 7, 2010 March 7, 2005 CenterPoint Houston 200 -- March 7, 2010 March 7, 2005 CenterPoint Houston 1,310 -- (2) June 30, 2005 CERC Corp. 400 -- June 30, 2010 - ---------- (1) Includes $27 million of outstanding letters of credit, $40 million outstanding under the revolving credit facility and $204 million of commercial paper backstopped by the credit facility. (2) Revolver until November 2005 with two-year term-out of borrowed moneys. The $1 billion CenterPoint Energy credit facility backstops a $1 billion commercial paper program under which CenterPoint Energy began issuing commercial paper in June 2005. As of September 30, 2005, $187 million of commercial paper was outstanding. The commercial paper is rated "Not Prime" by Moody's, "A-3" by S&P and "F3" by Fitch, Inc. (Fitch). We cannot assure you that these ratings, or the credit ratings set forth below in "-- Impact on Liquidity of a Downgrade in Credit Ratings," will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies. Securities Registered with the SEC. At September 30, 2005, CenterPoint Energy had a shelf registration statement covering senior debt securities, preferred stock and common stock aggregating $1 billion and CERC Corp. had a shelf registration statement covering $500 million principal amount of debt securities. Temporary Investments. On September 30, 2005, we had temporary investments of $116 million. 44
Money Pool. We have a "money pool" through which our participating subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy's revolving credit facility. The terms of the money pool are in accordance with requirements applicable to registered public utility holding companies under the 1935 Act and under an order from the SEC relating to our financing activities and those of our subsidiaries on June 29, 2005 (June 2005 Financing Order). Impact on Liquidity of a Downgrade in Credit Ratings. As of November 1, 2005, Moody's, S&P, and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries: MOODY'S S&P FITCH ------------------- ------------------- ------------------- COMPANY/INSTRUMENT RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3) - ------------------ ------ ---------- ------ ---------- ------ ---------- CenterPoint Energy Senior Unsecured Debt .. Ba1 Stable BBB- Stable BBB- Stable CenterPoint Houston Senior Secured Debt (First Mortgage Bonds) ................. Baa2 Stable BBB Stable BBB+ Stable CERC Corp. Senior Debt .................... Baa3 Stable BBB Stable BBB Stable - ---------- (1) A "stable" outlook from Moody's indicates that Moody's does not expect to put the rating on review for an upgrade or downgrade within 18 months from when the outlook was assigned or last affirmed. (2) An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term. (3) A "stable" outlook from Fitch encompasses a one-to-two-year horizon as to the likely ratings direction. A decline in credit ratings could increase borrowing costs under our $1 billion credit facility, CenterPoint Houston's $200 million credit facility and its $1.31 billion credit facility and CERC's $400 million revolving credit facility. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and would negatively impact our ability to complete capital market transactions. If we were unable to maintain an investment-grade rating from at least one rating agency, as a registered public utility holding company we would be required to obtain further approval from the SEC under the 1935 Act for any additional capital markets transactions as more fully described in "-- Certain Contractual and Regulatory Limits on Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock" below. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce margins of our Natural Gas Distribution business segment. As described above under "-- Credit Facilities," our revolving credit facility contains a "material adverse change" clause that could impact our ability to make new borrowings under this facility. CenterPoint Houston's $200 million credit facility, CenterPoint Houston's $1.3 billion facility and CERC Corp.'s $400 million credit facility do not contain material adverse change clauses with respect to borrowings. In September 1999, we issued 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. Each ZENS note is exchangeable at the holder's option at any time for an amount of cash equal to 95% of the market value of the reference shares of Time Warner Inc. (TW Common) attributable to each ZENS note. If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common that we own or from other sources. We own shares of TW Common equal to 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because deferred tax liabilities related to the ZENS notes and TW Common shares become current tax obligations when ZENS notes are exchanged and TW Common shares are sold. CES, a wholly owned subsidiary of CERC Corp., provides comprehensive natural gas sales and services to industrial and commercial customers, electric generators and natural gas utilities throughout the central United States. In order to hedge its exposure to natural gas prices, CES has agreements with provisions standard for the industry that establish credit thresholds and require a party to provide additional collateral on two business days' notice when that party's rating or the rating of a credit support provider for that party (CERC Corp. in this case) falls below those levels. We 45
estimate that as of September 30, 2005, unsecured credit limits extended to CES by counterparties could aggregate $115 million; however, utilized credit capacity is significantly lower. In addition, CERC and its subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on CERC's S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly. Cross Defaults. Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us or any of our significant subsidiaries will cause a default. Pursuant to the indenture governing our senior notes, a payment default by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million will cause a default. As of November 1, 2005, we had issued six series of senior notes aggregating $1.4 billion in principal amount under this indenture. A default by CenterPoint Energy would not trigger a default under our subsidiaries' debt instruments or bank credit facilities. Other Factors that Could Affect Cash Requirements. In addition to the above factors, our liquidity and capital resources could be affected by: - cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution business segment, particularly given gas price levels and volatility; - acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of suppliers; - increased costs related to the acquisition of gas; - increases in interest expense in connection with debt refinancings and borrowings under credit facilities; - various regulatory actions; - the ability of RRI and its subsidiaries to satisfy their obligations as the principal customers of CenterPoint Houston and in respect of RRI's indemnity obligations to us and our subsidiaries; - slower customer payments and increased write-offs of receivables due to higher gas prices; - cash payments in connection with the exercise of contingent conversion rights of holders of convertible debt; - contributions to benefit plans; - restoration costs and revenue losses resulting from natural disasters such as hurricanes; and - various other risks identified in "Risk Factors" in Item 5 of Part II of this report beginning on page 52. Certain Contractual and Regulatory Limits on Our Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock. The secured term loan and each of the credit facilities of CenterPoint Houston limits CenterPoint Houston's debt, excluding transition bonds, as a percentage of its total capitalization to 68%. CERC Corp.'s bank facility and its receivables facility limit CERC's debt as a percentage of its total capitalization to 65% and contain an EBITDA to interest covenant. Our $1 billion credit facility contains a debt to EBITDA covenant and an EBITDA to interest covenant. CenterPoint Houston's $1.31 billion and $200 million credit facilities also contain an EBITDA to interest covenant. We are a registered public utility holding company under the 1935 Act. The 1935 Act and related rules and regulations impose a number of restrictions on our activities and those of our subsidiaries. The 1935 Act, among other things, limits our ability and the ability of our regulated subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliated service, sales 46
and construction contracts. On August 8, 2005, President Bush signed into law the Energy Act. Under that legislation, the 1935 Act is repealed effective February 8, 2006. After the effective date of repeal, we and our subsidiaries will no longer be subject to restrictions imposed under the 1935 Act. Until the repeal is effective, we and our subsidiaries remain subject to the provisions of the 1935 Act and the terms of orders issued by the SEC under the 1935 Act. The Energy Act grants to FERC authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by FERC and state regulatory authorities. The Energy Act requires FERC to issue regulations to implement its jurisdiction under the Energy Act, and on September 16, 2005, FERC issued proposed rules for public comment. It is presently unknown what, if any, specific obligations under those rules may be imposed on us and our subsidiaries as a result of that rulemaking. The June 2005 Financing Order establishes limits on the amount of external debt and equity securities that can be issued by us and our regulated subsidiaries without additional authorization but generally permits us to refinance our existing obligations and those of our regulated subsidiaries. Each of us and our subsidiaries is in compliance with the authorized limits. Discussed below are the incremental amounts of debt and equity that we are authorized to issue. The order also generally permits utilization of undrawn credit facilities at CenterPoint Energy, CenterPoint Houston and CERC. However, due to the restrictions contained in the order regarding our equity level as described below, we may be unable to draw the full amount of our credit agreement for other than refinancing purposes without further authorization from the SEC. We do not expect this limitation to constrain our borrowings beyond the end of 2005 based on current projections. Unless we obtain a further order from the SEC, as of October 31, 2005: - We are not authorized to issue any additional debt or preferred securities; - CenterPoint Houston is authorized to issue an aggregate $47 million of debt or preferred securities; and - CERC is authorized to issue an additional $367 million of debt or preferred securities. In the June 2005 Financing Order, the SEC "reserved jurisdiction" over a number of matters, meaning that an order will be required from the SEC before we may conduct those activities. However, an order regarding the activities over which the SEC has reserved jurisdiction generally can be issued by the SEC more quickly than orders on other matters, although there is no assurance that a release of jurisdiction will be granted on a given matter or the terms under which such an order may be issued. In the June 2005 Financing Order, the SEC reserved jurisdiction over all authority otherwise granted if our common equity ratio falls below its level as of March 31, 2005 (11.4%, net of securitization debt) or if the common equity ratio of either CERC or CenterPoint Houston (net of securitization debt) falls below 30%. Among the other transactions over which the SEC reserved jurisdiction are: (i) issuance of securities by us or any of our subsidiaries unless our and the issuer's other securities which are rated have an investment grade rating from at least one nationally recognized statistical rating organization, (ii) further investment in inactive subsidiaries and (iii) payment of dividends by us from capital or unearned surplus. The June 2005 Financing Order also contains certain requirements for interest rates, maturities, issuance expenses and use of proceeds in connection with securities issued by us or any of our subsidiaries. So long as our common equity is less than 30% of our capitalization, the SEC also reserved jurisdiction over the use of proceeds from authorized financings for the acquisition of additional energy-related or gas-related companies. Finally, the SEC reserved jurisdiction over the issuance of $500 million in incremental debt by each of us, CenterPoint Houston and CERC. The total authorized amount of debt and preferred securities that could be outstanding during the authorization period, including the amounts over which the SEC has reserved jurisdiction and undrawn amounts under revolving credit facilities, are: $4.334 billion for us, $4.280 billion for CenterPoint Houston and $3.256 billion for CERC. The foregoing and the following restrictions contained in the June 2005 Financing Order, along with other restrictions contained in that order, will cease to apply to us on February 8, 2006. The 1935 Act limits the payment of dividends to payment from current and retained earnings unless specific authorization is obtained to pay dividends from other sources. As discussed above, the SEC has reserved jurisdiction over payment of $300 million of dividends from CenterPoint Energy's unearned surplus or capital. Further authorization would be required to make those payments. As of September 30, 2005, we had a retained deficit on our Consolidated Balance Sheet. On January 26, 2005, our board of directors declared a dividend of $0.10 per share of common stock payable on March 10, 2005 to shareholders of record as of the close of business on February 16, 2005. On March 3, 2005, our board of directors declared a dividend of $0.10 per share of common stock payable on March 31, 2005 to shareholders of record as of the close of business on March 16, 2005. This additional first quarter dividend was declared to address technical restrictions that might have limited our ability to pay a regular dividend 47
during the second quarter of this year. Due to the limitations imposed under the 1935 Act, we may declare and pay dividends only from earnings in the specific quarter in which the dividend is paid, absent specific authorization from the SEC approving payment of the quarterly dividend from capital or unearned surplus. There can be no assurance, however, that the SEC would authorize such payments. On June 2, 2005, our board of directors declared a dividend of $0.07 per share of common stock payable on June 30, 2005 to shareholders of record as of the close of business on June 15, 2005. On August 31, 2005, our board of directors declared a dividend of $0.07 per common share, payable on September 30, 2005, to shareholders of record as of the close of business on September 12, 2005. The dividends declared and paid for the first three quarters of 2005 totaled $0.34 per share versus $0.30 per share for the first three quarters of 2004. On October 24, 2005, our board of directors declared a dividend of $0.06 per common share, payable on December 9, 2005, to shareholders of record as of the close of business on November 16, 2005. In addition, the SEC generally expects registered holding companies to achieve a ratio of common equity to total capitalization of 30%. At September 30, 2005, our ratio was 14% (excluding transition bonds). Accordingly, we may issue equity and take other actions to achieve a future equity capitalization of 30%. The June 2005 Financing Order also requires that CenterPoint Houston and CERC maintain a ratio of common equity to total capitalization of 30%, although the SEC has permitted the percentage to be below this level for other companies taking into account non-recourse securitization debt as a component of capitalization. At September 30, 2005, CenterPoint Houston's and CERC's ratios were 43% (excluding transition bonds) and 57%, respectively. Other Factors Affecting the Upstreaming of Cash from Subsidiaries. CenterPoint Houston's $1.31 billion term loan maturing in November 2005, subject to certain exceptions, limits the application of proceeds, in excess of $200 million, from capital markets transactions and certain other borrowing transactions by CenterPoint Houston to repayment of debt existing in November 2002. If the $1.31 billion credit facility established in March 2005 is drawn in November 2005 to repay the term loan, then (i) 100% of the net proceeds from the issuance of transition bonds and (ii) the proceeds, in excess of $200 million, from certain other new net indebtedness for borrowed money incurred by CenterPoint Houston must be used to repay borrowings under the facility. CenterPoint Houston plans to distribute recovery of the true-up components not used to repay CenterPoint Houston's indebtedness to us through the payment of dividends. CenterPoint Houston requires SEC action to approve any dividends in excess of its current and retained earnings. To maintain CenterPoint Houston's capital structure at the appropriate levels, we may reinvest funds in CenterPoint Houston in the form of equity contributions or intercompany loans. CRITICAL ACCOUNTING POLICIES A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements in the CenterPoint Energy Form 10-K (CenterPoint Energy Notes). We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors. 48
ACCOUNTING FOR RATE REGULATION SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Application of SFAS No. 71 to the electric generation portion of our business was discontinued as of June 30, 1999. Our Electric Transmission & Distribution business continues to apply SFAS No. 71 which results in our accounting for the regulatory effects of recovery of stranded costs and other regulatory assets resulting from the unbundling of the transmission and distribution business from our electric generation operations in our consolidated financial statements. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Significant accounting estimates embedded within the application of SFAS No. 71 with respect to our Electric Transmission & Distribution business segment relate to $2.2 billion of recoverable electric generation-related regulatory assets as of September 30, 2005. These costs are recoverable under the provisions of the Texas electric restructuring law. Based on our analysis of the True-Up Order, we recorded an after-tax charge to earnings in 2004 of approximately $977 million to write-down our electric generation-related regulatory assets to their realizable value, which was reflected as an extraordinary loss. Based on subsequent orders received from the Texas Utility Commission, we recorded an extraordinary gain of $30 million after-tax in the second quarter of 2005 related to the regulatory asset. IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, regulatory matters and operating costs could negatively affect the fair value of our assets and result in an impairment charge. Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques. We perform our goodwill impairment test at least annually and evaluate goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon adoption of SFAS No. 142, we initially selected January 1 as our annual goodwill impairment testing date. Since the time we selected the January 1 date, our year-end closing and reporting process has been truncated in order to meet the accelerated periodic reporting requirements of the SEC resulting in significant constraints on our human resources at year-end and during our first fiscal quarter. Accordingly, in order to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in the third quarter of 2005, we changed the date on which we perform our annual goodwill impairment test from January 1 to July 1. We believe the July 1 alternative date will alleviate the resource constraints that exist during the first quarter and allow us to utilize additional resources in conducting the annual impairment evaluation of goodwill. We performed the test at July 1, 2005, and determined that no impairment charge for goodwill was required. The change is not intended to delay, accelerate or avoid an impairment charge. We believe that this accounting change is an alternative accounting principle that is preferable under the circumstances. UNBILLED ENERGY REVENUES Revenues related to the sale and/or delivery of electricity or natural gas (energy) are generally recorded when energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled electricity delivery revenue is estimated each month based on 49
daily supply volumes, applicable rates and analyses reflecting significant historical trends and experience. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. PENSION AND OTHER RETIREMENT PLANS We sponsor pension and other retirement plans in various forms covering all employees who meet eligibility requirements. We use several statistical and other factors which attempt to anticipate future events in calculating the expense and liability related to our plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, our actuarial consultants use subjective factors such as withdrawal and mortality rates to estimate these factors. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension expense recorded. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations-- Other Significant Matters -- Pension Plan" in Item 7 of the CenterPoint Energy Form 10-K, which is incorporated herein by reference, for further discussion. NEW ACCOUNTING PRONOUNCEMENTS See Note 4 to the Interim Financial Statements for a discussion of new accounting pronouncements that affect us. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK COMMODITY PRICE RISK We assess the risk of our non-trading derivatives (Non-Trading Energy Derivatives) using a sensitivity analysis method. The sensitivity analysis performed on our Non-Trading Energy Derivatives measures the potential loss based on a hypothetical 10% movement in energy prices. A decrease of 10% in the market prices of energy commodities from their September 30, 2005 levels would have decreased the fair value of our Non-Trading Energy Derivatives from their levels on that date by $59 million. The above analysis of the Non-Trading Energy Derivatives utilized for price risk management purposes does not include the favorable impact that the same hypothetical price movement would have on our physical purchases and sales of natural gas to which the hedges relate. The Non-Trading Energy Derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of Non-Trading Energy Derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions. INTEREST RATE RISK We have outstanding long-term debt, bank loans, mandatory redeemable preferred securities of subsidiary trusts holding solely our junior subordinated debentures (trust preferred securities), some lease obligations and our obligations under the ZENS that subject us to the risk of loss associated with movements in market interest rates. Our floating-rate obligations aggregated $1.5 billion at September 30, 2005. If the floating rates were to increase by 10% from September 30, 2005 rates, our combined interest expense to third parties would increase by a total of $1.5 million each month in which such increase continued. At September 30, 2005, we had outstanding fixed-rate debt (excluding indexed debt securities) and trust preferred securities aggregating $6.9 billion in principal amount and having a fair value of $7.5 billion. These 50
instruments are fixed-rate and, therefore, do not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $321 million if interest rates were to decline by 10% from their levels at September 30, 2005. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity. As discussed in Note 6 to the CenterPoint Energy Notes, which note is incorporated herein by reference, upon adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of $109 million at September 30, 2005 is a fixed-rate obligation and, therefore, does not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $17 million if interest rates were to decline by 10% from levels at September 30, 2005. Changes in the fair value of the derivative component will be recorded in our Statements of Consolidated Operations and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from September 30, 2005 levels, the fair value of the derivative component would increase by approximately $5 million, which would be recorded as a loss in our Statements of Consolidated Operations. EQUITY MARKET VALUE RISK We are exposed to equity market value risk through our ownership of 21.6 million shares of TW Common, which we hold to facilitate our ability to meet our obligations under the ZENS. Please read Note 6 to the CenterPoint Energy Notes for a discussion of the effect of adoption of SFAS No. 133 on our ZENS obligation and our historical accounting treatment of our ZENS obligation. A decrease of 10% from the September 30, 2005 market value of TW Common would result in a net loss of approximately $4 million, which would be recorded as a loss in our Statements of Consolidated Operations. ITEM 4. CONTROLS AND PROCEDURES In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2005 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. There has been no change in our internal controls over financial reporting that occurred during the three months ended September 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. 51
PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS For a description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Notes 5 and 11 to our Interim Financial Statements, "Business -- Regulation" and "-- Environmental Matters" in Item 1 of the CenterPoint Energy Form 10-K, "Legal Proceedings" in Item 3 of the CenterPoint Energy Form 10-K and Notes 4 and 11 to the CenterPoint Energy Notes, each of which is incorporated herein by reference. ITEM 5. OTHER INFORMATION RISK FACTORS We are a holding company that conducts all of our business operations through subsidiaries, primarily CenterPoint Houston and CERC. The following summarizes the principal risk factors associated with the businesses conducted by each of these subsidiaries: RISK FACTORS AFFECTING OUR ELECTRIC TRANSMISSION & DISTRIBUTION BUSINESS CENTERPOINT HOUSTON MAY NOT BE SUCCESSFUL IN TIMELY RECOVERING THE FULL VALUE OF ITS TRUE-UP COMPONENTS, WHICH COULD HAVE AN ADVERSE IMPACT ON CENTERPOINT HOUSTON'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. In March 2004, CenterPoint Houston filed its stranded cost true-up application with the Texas Utility Commission. CenterPoint Houston had requested recovery of $3.7 billion, excluding interest. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. That court held a hearing on the appeal in early August 2005, and on August 26, 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the Texas Utility Commission's order, but reversed two of the Texas Utility Commission's rulings, which would have the effect of restoring approximately $620 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston's initial request. First, the court reversed the Texas Utility Commission's decision to prohibit CenterPoint Houston from recovering $180 million in credits through August 2004 that CenterPoint Houston was ordered to provide to retail electric providers as a result of a stranded cost estimate made by the Texas Utility Commission in 2000 that subsequently proved to be inaccurate. Second, the court reversed the Texas Utility Commission's disallowance of $440 million in transition costs which are recoverable under the Texas Utility Commission's regulations. Additional credits of approximately $30 million paid after August 2004 and interest would be added to these amounts. CenterPoint Houston and other parties appealed the district court decision to the 3rd Court of Appeals in Austin in September 2005. The parties have agreed to a briefing schedule whereby briefs will be filed by the parties on a schedule extending into February 2006. No prediction can be made as to the ultimate outcome or timing of such appeals. A failure by CenterPoint Houston to recover the full value of its true-up components may have an adverse impact on CenterPoint Houston's results of operations, financial condition and cash flows. CENTERPOINT HOUSTON'S RECEIVABLES ARE CONCENTRATED IN A SMALL NUMBER OF RETAIL ELECTRIC PROVIDERS, AND ANY DELAY OR DEFAULT IN PAYMENT COULD ADVERSELY AFFECT CENTERPOINT HOUSTON'S CASH FLOWS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS. CenterPoint Houston's receivables from the distribution of electricity are collected from retail electric providers that supply the electricity CenterPoint Houston distributes to their customers. Currently, CenterPoint Houston does business with approximately 65 retail electric providers. Adverse economic conditions, structural problems in the market served by the Electric Reliability Council of Texas, Inc. (ERCOT) or financial difficulties of one or more retail electric providers could impair the ability of these retail providers to pay for CenterPoint Houston's services or could cause them to delay such payments. CenterPoint Houston depends on these retail electric providers to remit 52
payments on a timely basis. Any delay or default in payment could adversely affect CenterPoint Houston's cash flows, financial condition and results of operations. RRI, through its subsidiaries, is CenterPoint Houston's largest customer. Approximately 60% of CenterPoint Houston's $175 million in billed receivables from retail electric providers at September 30, 2005 was owed by subsidiaries of RRI. RATE REGULATION OF CENTERPOINT HOUSTON'S BUSINESS MAY DELAY OR DENY CENTERPOINT HOUSTON'S ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER ITS COSTS. CenterPoint Houston's rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of CenterPoint Houston's costs and enable CenterPoint Houston to earn a reasonable return on its invested capital. DISRUPTIONS AT POWER GENERATION FACILITIES OWNED BY THIRD PARTIES COULD INTERRUPT CENTERPOINT HOUSTON'S SALES OF TRANSMISSION AND DISTRIBUTION SERVICES. CenterPoint Houston depends on power generation facilities owned by third parties to provide retail electric providers with electric power which it transmits and distributes to customers of the retail electric providers. CenterPoint Houston does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, CenterPoint Houston's services may be interrupted, and its results of operations, financial condition and cash flows may be adversely affected. CENTERPOINT HOUSTON'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL. A significant portion of CenterPoint Houston's revenues is derived from rates that it collects from each retail electric provider based on the amount of electricity it distributes on behalf of such retail electric provider. Thus, CenterPoint Houston's revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months. RISK FACTORS AFFECTING OUR NATURAL GAS DISTRIBUTION AND PIPELINES AND GATHERING BUSINESSES RATE REGULATION OF CERC'S BUSINESS MAY DELAY OR DENY CERC'S ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER ITS COSTS. CERC's rates for its local distribution companies are regulated by certain municipalities and state commissions based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CERC is allowed to charge may not match its expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of CERC's costs and enable CERC to earn a reasonable return on its invested capital. CERC'S BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, WHICH COULD LEAD TO LESS NATURAL GAS BEING MARKETED, AND ITS PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE TRANSPORTATION, STORAGE, GATHERING, TREATING AND PROCESSING OF NATURAL GAS, WHICH COULD LEAD TO LOWER PRICES, EITHER OF WHICH COULD HAVE AN ADVERSE IMPACT ON CERC'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. CERC competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with CERC for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CERC's facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC's results of operations, financial condition and cash flows. CERC's two interstate pipelines and its gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. They also compete indirectly with other forms of 53
energy, including electricity, coal and fuel oils. The primary competitive factor is price. The actions of CERC's competitors could lead to lower prices, which may have an adverse impact on CERC's results of operations, financial condition and cash flows. CERC'S NATURAL GAS DISTRIBUTION BUSINESS IS SUBJECT TO FLUCTUATIONS IN NATURAL GAS PRICING LEVELS, WHICH COULD AFFECT THE ABILITY OF CERC'S SUPPLIERS AND CUSTOMERS TO MEET THEIR OBLIGATIONS. CERC is subject to risk associated with price movements of natural gas. Movements in natural gas prices might affect CERC's ability to collect balances due from its customers and, on the regulated side, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC's tariff rates. In addition, a sustained period of high natural gas prices could apply downward demand pressure on natural gas consumption in the areas in which CERC operates and increase the risk that CERC's suppliers or customers fail or are unable to meet their obligations. Additionally, increasing gas prices could create the need for CERC to provide collateral in order to purchase gas. IF CERC WERE TO FAIL TO EXTEND A CONTRACT WITH ONE OF ITS SIGNIFICANT PIPELINE CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON ITS OPERATIONS. CERC's contract with Laclede Gas Company, one of its pipeline's customers, is currently scheduled to expire in 2007. To the extent the pipeline is unable to extend this contract or the contract is renegotiated at rates substantially less than the rates provided in the current contract, there could be an adverse effect on CERC's results of operations, financial condition and cash flows. A DECLINE IN CERC'S CREDIT RATING COULD RESULT IN CERC'S HAVING TO PROVIDE COLLATERAL IN ORDER TO PURCHASE GAS. If CERC's credit rating were to decline, it might be required to post cash collateral in order to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC might be unable to obtain the necessary natural gas to meet its contractual distribution obligations, and its results of operations, financial condition and cash flows would be adversely affected. CERC'S INTERSTATE PIPELINES' AND NATURAL GAS GATHERING AND PROCESSING BUSINESS' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS. CERC's interstate pipelines and natural gas gathering and processing business largely rely on gas sourced in the various supply basins located in the Midcontinent region of the United States. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on CERC's results of operations, financial condition and cash flows. CERC'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL. A substantial portion of CERC's revenues is derived from natural gas sales and transportation. Thus, CERC's revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months. RISK FACTORS ASSOCIATED WITH OUR CONSOLIDATED FINANCIAL CONDITION IF WE ARE UNABLE TO ARRANGE FUTURE FINANCINGS ON ACCEPTABLE TERMS, OUR ABILITY TO REFINANCE EXISTING INDEBTEDNESS COULD BE LIMITED. As of September 30, 2005, we had $8.6 billion of outstanding indebtedness on a consolidated basis. As of September 30, 2005, approximately $1.5 billion principal amount of this debt must be paid through 2006, excluding principal repayments of approximately $54 million on transition bonds. The success of our future financing efforts may depend, at least in part, on: - the timing and amount of our recovery of the true-up components; 54
- general economic and capital market conditions; - credit availability from financial institutions and other lenders; - investor confidence in us and the market in which we operate; - maintenance of acceptable credit ratings; - market expectations regarding our future earnings and probable cash flows; - market perceptions of our ability to access capital markets on reasonable terms; - our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from us; - provisions of relevant tax and securities laws; and - our ability to obtain approval of specific financing transactions under the 1935 Act prior to the effective date of the repeal of the 1935 Act. As of September 30, 2005, our CenterPoint Houston subsidiary had $3.3 billion principal amount of general mortgage bonds outstanding and $253 million of first mortgage bonds outstanding. It may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Although approximately $650 million of additional first mortgage bonds and general mortgage bonds could be issued on the basis of retired bonds and 70% of property additions as of September 30, 2005, CenterPoint Houston has agreed under the $1.3 billion collateralized term loan maturing in November 2005 to not issue, subject to certain exceptions, more than $200 million of any incremental secured or unsecured debt. In addition, CenterPoint Houston is contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds. CenterPoint Houston's $1.3 billion credit facility requires that proceeds from the issuance of transition bonds and certain new net indebtedness for borrowed money issued by CenterPoint Houston in excess of $200 million be used to repay borrowings under such facility. Our capital structure and liquidity will be affected significantly by the securitization of approximately $1.8 billion of costs authorized for recovery in our proceeding regarding the transition to competitive retail markets in Texas. Our current credit ratings are discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Impact on Liquidity of a Downgrade in Credit Ratings" in Item 2 of Part I of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms. AS A HOLDING COMPANY WITH NO OPERATIONS OF OUR OWN, WE WILL DEPEND ON DISTRIBUTIONS FROM OUR SUBSIDIARIES TO MEET OUR PAYMENT OBLIGATIONS, AND PROVISIONS OF APPLICABLE LAW OR CONTRACTUAL RESTRICTIONS COULD LIMIT THE AMOUNT OF THOSE DISTRIBUTIONS. We derive all our operating income from, and hold all our assets through, our subsidiaries. As a result, we will depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends and those under the 1935 Act, limit their ability to make payments or other distributions to us, and they could agree to contractual restrictions on their ability to make distributions. Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary's creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us. AN INCREASE IN SHORT-TERM INTEREST RATES COULD ADVERSELY AFFECT OUR CASH FLOWS AND EARNINGS. As of September 30, 2005, we had $1.5 billion of outstanding floating-rate debt owed to third parties. The interest rate spreads on such debt are substantially above our historical interest rate spreads. In addition, any floating-rate debt issued by us in the future could be at interest rates substantially above our historical borrowing 55
rates. An increase in short-term interest rates could result in higher interest costs and could adversely affect our results of operations, financial condition and cash flows. THE USE OF DERIVATIVE CONTRACTS BY US AND OUR SUBSIDIARIES IN THE NORMAL COURSE OF BUSINESS COULD RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT OUR RESULTS OF OPERATIONS AND THOSE OF OUR SUBSIDIARIES. We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or if a counterparty fails to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. OTHER RISKS WE AND CENTERPOINT HOUSTON COULD INCUR LIABILITIES ASSOCIATED WITH BUSINESSES AND ASSETS THAT WE HAVE TRANSFERRED TO OTHERS. Under some circumstances, we and CenterPoint Houston could incur liabilities associated with assets and businesses we and CenterPoint Houston no longer own. These assets and businesses were previously owned by Reliant Energy, Incorporated directly or through subsidiaries and include: - those transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001; and - those transferred to Texas Genco in connection with its organization and capitalization. In connection with the organization and capitalization of RRI, RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy, Incorporated transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston, with respect to liabilities associated with the transferred assets and businesses. The indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI is unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy, Incorporated has not been released from the liability in connection with the transfer, we or CenterPoint Houston could be responsible for satisfying the liability. RRI's unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event RRI might not honor its indemnification obligations and claims by RRI's creditors might be made against us as its former owner. Reliant Energy, Incorporated and RRI are named as defendants in a number of lawsuits arising out of power sales in California and other West Coast markets and financial reporting matters. Although these matters relate to the business and operations of RRI, claims against Reliant Energy, Incorporated have been made on grounds that include the effect of RRI's financial results on Reliant Energy, Incorporated's historical financial statements and liability of Reliant Energy, Incorporated as a controlling shareholder of RRI. We or CenterPoint Houston could incur liability if claims in one or more of these lawsuits were successfully asserted against us or CenterPoint Houston and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims. In connection with the organization and capitalization of Texas Genco, Texas Genco assumed liabilities associated with the electric generation assets Reliant Energy, Incorporated transferred to it. Texas Genco also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston, with respect to liabilities associated with the transferred assets and businesses. In many cases the liabilities assumed were held by CenterPoint Houston and CenterPoint Houston was not released by third parties from these liabilities. The indemnity provisions were intended generally to place sole financial responsibility on Texas Genco and its subsidiaries for all liabilities associated with the current and historical businesses and 56
operations of Texas Genco, regardless of the time those liabilities arose. In connection with the sale of Texas Genco's fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC, the separation agreement we entered into with Texas Genco in connection with the organization and capitalization of Texas Genco was amended to provide that all of Texas Genco's rights and obligations under the separation agreement relating to its fossil generation assets, including Texas Genco's obligation to indemnify us with respect to liabilities associated with the fossil generation assets and related business, were assigned to and assumed by Texas Genco LLC. In addition, under the amended separation agreement, Texas Genco is no longer liable for, and CenterPoint Energy has assumed and agreed to indemnify Texas Genco LLC against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies or other similar agreements held by CenterPoint Energy. If Texas Genco or Texas Genco LLC were unable to satisfy a liability that had been so assumed or indemnified against, and provided Reliant Energy, Incorporated had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability. WE, TOGETHER WITH OUR SUBSIDIARIES, ARE SUBJECT TO REGULATION UNDER THE 1935 ACT. THE 1935 ACT AND RELATED RULES AND REGULATIONS IMPOSE A NUMBER OF RESTRICTIONS ON OUR ACTIVITIES. We and our subsidiaries are subject to regulation by the SEC under the 1935 Act. The 1935 Act, among other things, limits the ability of a holding company and its regulated subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliated service, sales and construction contracts. We received an order from the SEC under the 1935 Act on June 29, 2005 relating to our financing activities, which is effective until June 30, 2008. Unforeseen events could result in capital needs in excess of currently authorized amounts, necessitating further authorization from the SEC. Approval of filings under the 1935 Act can take extended periods. Under this order, we may not be able to fully utilize our credit facility without prior approval. If our earnings for subsequent quarters are insufficient to pay dividends from current earnings, additional authority would be required from the SEC for payment of the quarterly dividend from capital or unearned surplus, and the SEC may not authorize such payments. The Energy Policy Act of 2005 repeals the 1935 Act effective in 2006. We cannot predict at this time the effect of the repeal on our business. OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT. INSUFFICIENT INSURANCE COVERAGE AND INCREASED INSURANCE COSTS COULD ADVERSELY IMPACT OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows. In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system because CenterPoint Houston believes it to be cost prohibitive. If CenterPoint Houston were to sustain any loss of, or damage to, its transmission and distribution properties, it may not be able to recover such loss or damage through a change in its regulated rates, and any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows. 57
ITEM 6. EXHIBITS The following exhibits are filed herewith: Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing of CenterPoint Energy, Inc. SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- 3.1.1 -- Amended and Restated Articles of Incorporation of CenterPoint Energy's Registration Statement 3-69502 3.1 CenterPoint Energy on Form S-4 3.1.2 -- Articles of Amendment to Amended and Restated CenterPoint Energy's Form 10-K for the year 1-31447 3.1.1 Articles of Incorporation of CenterPoint Energy ended December 31, 2001 3.2 -- Amended and Restated Bylaws of CenterPoint Energy CenterPoint Energy's Form 10-K for the year 1-31447 3.2 ended December 31, 2001 3.3 -- Statement of Resolution Establishing Series of CenterPoint Energy's Form 10-K for the year 1-31447 3.3 Shares designated Series A Preferred Stock of ended December 31, 2001 CenterPoint Energy 4.1 -- Form of CenterPoint Energy Stock Certificate CenterPoint Energy's Registration Statement 3-69502 4.1 on Form S-4 4.2 -- Rights Agreement dated January 1, 2002, between CenterPoint Energy's Form 10-K for the year 1-31447 4.2 CenterPoint Energy and JPMorgan Chase Bank, as ended December 31, 2001 Rights Agent Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy has not filed as exhibits to this Form 10-Q certain long-term debt instruments, including indentures, under which the total amount of securities authorized does not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any such instrument to the SEC upon request. SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- 4.3.1 -- $1,310,000,000 Credit Agreement dated as of CenterPoint Energy's Form 10-K for the 1-31447 4(g)(1) November 12, 2002, among CenterPoint Houston and the year ended December 31, 2002 banks named therein 4.3.2 -- First Amendment to Exhibit 4.1.1, dated as of CenterPoint Energy's Form 10-Q for the 1-31447 10.7 September 3, 2003 quarter ended September 30, 2003 4.3.3 -- Pledge Agreement, dated as of November 12, 2002 CenterPoint Energy's Form 10-K for the 1-31447 4(g)(2) executed in connection with Exhibit 4.1.1 year ended December 31, 2002 4.4 -- $1,000,000,000 Credit Agreement dated as of March 7, CenterPoint Energy's Form 8-K dated 1-31447 4.1 2005, among CenterPoint Energy and the banks named March 7, 2005 therein 4.5 -- $400,000,000 Credit Agreement, dated as of June 30, CenterPoint Energy's Form 8-K dated 1-31447 4.1 2005, among CERC Corp., as Borrower, and the Initial June 29, 2005 Lenders named therein, as Initial Lenders 58
SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- -------------- --------- 4.6 -- $200,000,000 Credit Agreement dated as of March 7, CenterPoint Energy's Form 8-K dated 1-31447 4.2 2005 among CenterPoint Houston and the banks named March 7, 2005 therein 4.7 -- $1,310,000,000 Credit Agreement dated as of March 7, CenterPoint Energy's Form 8-K dated 1-31447 4.3 2005 among CenterPoint Houston and the banks named March 7, 2005 therein +18.1 -- Preferability Letter re: Change in Accounting Principle +31.1 -- Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan +31.2 -- Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock +32.1 -- Section 1350 Certification of David M. McClanahan +32.2 -- Section 1350 Certification of Gary L. Whitlock +99.1 -- Third Amendment to CenterPoint Energy, Inc. Savings Trust, effective as of October 27, 2004 +99.2 -- CenterPoint Energy Savings Plan, as amended and restated effective January 1, 2005. +99.3 -- Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1 "Business--Regulation," "--Environmental Matters," Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations--Certain Factors Affecting Future Earnings" and "--Other Significant Matters--Pension Plan" and Notes 2(d) (Long-Lived Assets and Intangibles), 2(e) (Regulatory Assets and Liabilities), 4 (Regulatory Matters), 5 (Derivative Instruments), 6 (Indexed Debt Securities (ZENS) and Time Warner Securities) and 11 (Commitments and Contingencies) 59
SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CENTERPOINT ENERGY, INC. By: /s/ James S. Brian ------------------------------------ James S. Brian Senior Vice President and Chief Accounting Officer Date: November 3, 2005 60
Exhibit Index SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- 3.1.1 -- Amended and Restated Articles of Incorporation of CenterPoint Energy's Registration Statement 3-69502 3.1 CenterPoint Energy on Form S-4 3.1.2 -- Articles of Amendment to Amended and Restated CenterPoint Energy's Form 10-K for the year 1-31447 3.1.1 Articles of Incorporation of CenterPoint Energy ended December 31, 2001 3.2 -- Amended and Restated Bylaws of CenterPoint Energy CenterPoint Energy's Form 10-K for the year 1-31447 3.2 ended December 31, 2001 3.3 -- Statement of Resolution Establishing Series of CenterPoint Energy's Form 10-K for the year 1-31447 3.3 Shares designated Series A Preferred Stock of ended December 31, 2001 CenterPoint Energy 4.1 -- Form of CenterPoint Energy Stock Certificate CenterPoint Energy's Registration Statement 3-69502 4.1 on Form S-4 4.2 -- Rights Agreement dated January 1, 2002, between CenterPoint Energy's Form 10-K for the year 1-31447 4.2 CenterPoint Energy and JPMorgan Chase Bank, as ended December 31, 2001 Rights Agent SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- 4.3.1 -- $1,310,000,000 Credit Agreement dated as of CenterPoint Energy's Form 10-K for the 1-31447 4(g)(1) November 12, 2002, among CenterPoint Houston and the year ended December 31, 2002 banks named therein 4.3.2 -- First Amendment to Exhibit 4.1.1, dated as of CenterPoint Energy's Form 10-Q for the 1-31447 10.7 September 3, 2003 quarter ended September 30, 2003 4.3.3 -- Pledge Agreement, dated as of November 12, 2002 CenterPoint Energy's Form 10-K for the 1-31447 4(g)(2) executed in connection with Exhibit 4.1.1 year ended December 31, 2002 4.4 -- $1,000,000,000 Credit Agreement dated as of March 7, CenterPoint Energy's Form 8-K dated 1-31447 4.1 2005, among CenterPoint Energy and the banks named March 7, 2005 therein 4.5 -- $400,000,000 Credit Agreement, dated as of June 30, CenterPoint Energy's Form 8-K dated 1-31447 4.1 2005, among CERC Corp., as Borrower, and the Initial June 29, 2005 Lenders named therein, as Initial Lenders 61
SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- -------------- --------- 4.6 -- $200,000,000 Credit Agreement dated as of March 7, CenterPoint Energy's Form 8-K dated 1-31447 4.2 2005 among CenterPoint Houston and the banks named March 7, 2005 therein 4.7 -- $1,310,000,000 Credit Agreement dated as of March 7, CenterPoint Energy's Form 8-K dated 1-31447 4.3 2005 among CenterPoint Houston and the banks named March 7, 2005 therein +18.1 -- Preferability Letter re: Change in Accounting Principle +31.1 -- Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan +31.2 -- Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock +32.1 -- Section 1350 Certification of David M. McClanahan +32.2 -- Section 1350 Certification of Gary L. Whitlock +99.1 -- Third Amendment to CenterPoint Energy, Inc. Savings Trust, effective as of October 27, 2004 +99.2 -- CenterPoint Energy Savings Plan, as amended and restated effective January 1, 2005. +99.3 -- Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1 "Business--Regulation," "--Environmental Matters," Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations--Certain Factors Affecting Future Earnings" and "--Other Significant Matters--Pension Plan" and Notes 2(d) (Long-Lived Assets and Intangibles), 2(e) (Regulatory Assets and Liabilities), 4 (Regulatory Matters), 5 (Derivative Instruments), 6 (Indexed Debt Securities (ZENS) and Time Warner Securities) and 11 (Commitments and Contingencies) 62
EXHIBIT 18.1 November 3, 2005 CenterPoint Energy, Inc. Houston, Texas 77002 Dear Sirs/Madams: At your request, we have read the description included in your Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended September 30, 2005, of the facts relating to the change in the date of annual goodwill impairment tests under Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. We believe, on the basis of the facts so set forth and other information furnished to us by appropriate officials of the Company, that the accounting change described in your Form 10-Q is to an alternative accounting principle that is preferable under the circumstances. We have not audited any consolidated financial statements of CenterPoint Energy, Inc. and its consolidated subsidiaries as of any date or for any period subsequent to December 31, 2004. Therefore, we are unable to express, and we do not express, an opinion on the facts set forth in the above-mentioned Form 10-Q, on the related information furnished to us by officials of the Company, or on the financial position, results of operations, or cash flows of CenterPoint Energy, Inc. and its consolidated subsidiaries as of any date or for any period subsequent to December 31, 2004. Yours truly, /s/ Deloitte & Touche LLP Houston, Texas
EXHIBIT 31.1 CERTIFICATIONS I, David M. McClanahan, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 3, 2005 /s/ David M. McClanahan ---------------------------------------- David M. McClanahan President and Chief Executive Officer
EXHIBIT 31.2 CERTIFICATIONS I, Gary L. Whitlock, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 3, 2005 /s/ Gary L. Whitlock ---------------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer
EXHIBIT 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of CenterPoint Energy, Inc. (the "Company") on Form 10-Q for the period ended September 30, 2005 (the "Report"), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ David M. McClanahan - ------------------------------------ David M. McClanahan President and Chief Executive Officer November 3, 2005
EXHIBIT 32.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of CenterPoint Energy, Inc. (the "Company") on Form 10-Q for the period ended September 30, 2005 (the "Report"), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Gary L. Whitlock - ------------------------------------ Gary L. Whitlock Executive Vice President and Chief Financial Officer November 3, 2005
EXHIBIT 99.1 THIRD AMENDMENT TO CENTERPOINT ENERGY, INC. SAVINGS TRUST THIS AGREEMENT is made effective this 27th day of October 2004, by and between CENTERPOINT ENERGY, INC. (the "Company"), and THE NORTHERN TRUST COMPANY, an Illinois corporation (hereinafter referred to as the "Trustee"); WHEREAS, the Company and the Trustee entered into the CenterPoint Energy, Inc. Savings Trust, effective April 1, 1999, and as thereafter amended (formerly the Reliant Energy, Incorporated Savings Trust and hereinafter referred to as the "Trust"); and WHEREAS the Company and the Trustee desire to amend the Trust pursuant to Section 10.4; NOW, THEREFORE, Section 4.2(h) of the Trust is hereby amended by adding the following sentence to the end thereof and all other sections of the Trust shall remain in full force and effect: "Notwithstanding any provision herein to the contrary, with respect to Texas Genco's transaction agreement, dated as of July 21, 2004, pursuant to which Texas Genco has agreed to be acquired in a multistep transaction by GC Power Acquisition LLC, a newly formed entity owned in equal parts by investment funds affiliated with The Blackstone Group, Hellman & Friedman LLC, Kohlberg Kravis Roberts & Co. L.P. and Texas Pacific Group, the Trustee shall have the responsibility to determine whether to exercise dissenters' rights in connection with Texas Genco's merger with a subsidiary of CenterPoint Energy, Inc. and the conversion of all of Texas Genco's shares of common stock, representing approximately 19% of Texas Genco's outstanding shares, into the right to receive $47.00 per share in cash without interest and less any applicable withholding taxes." IN WITNESS WHEREOF, the Company and the Trustee have caused this Amendment to be executed and attested to by their respective officers, in a number of copies, all of which shall constitute one and the same instrument, which may be sufficiently evidenced by any executed copy hereof, on the day and year first written above. CENTERPOINT ENERGY, INC. By: /s/ David M. McClanahan ----------------------------------- David M. McClanahan President and Chief Executive Officer 1
The undersigned, Richard B. Dauphin, does hereby certify that he is the duly elected, qualified and acting Assistant Secretary of CENTERPOINT ENERGY, INC. (the "Company") and further certifies that the person whose signature appears above is a duly elected, qualified and acting officer of the Company with full power and authority to execute this Trust Amendment on behalf of the Company and to take such other actions and execute such other documents as may be necessary to effectuate this Agreement. /s/ Richard B. Dauphin - ------------------------------------ Richard B. Dauphin Assistant Secretary CENTERPOINT ENERGY, INC. THE NORTHERN TRUST COMPANY By: /s/ Joel J. Malinson ------------------------------------- Its: Vice President 2
EXHIBIT 99.2 CENTERPOINT ENERGY SAVINGS PLAN (As Amended and Restated Effective January 1, 2005)
. . . CENTERPOINT ENERGY SAVINGS PLAN (As Amended and Restated Effective January 1, 2005) INDEX Page ---- ARTICLE I DEFINITIONS.................................................... 3 ARTICLE II ADMINISTRATION OF THE PLAN.................................... 9 2.1 Appointment of Committee....................................... 9 2.2 Records of Committee........................................... 9 2.3 Committee Action............................................... 9 2.4 Committee Disqualification..................................... 9 2.5 Committee Compensation and Expenses............................ 9 2.6 Committee Liability............................................ 9 2.7 Committee Determinations....................................... 10 2.8 Employee Information From Employer............................. 11 2.9 Uniform Administration......................................... 11 2.10 Reporting Responsibilities..................................... 12 2.11 Disclosure Responsibilities.................................... 12 2.12 Statements..................................................... 12 2.13 Allocation of Responsibility Among Fiduciaries for Plan and Trust Administration........................................... 12 2.14 Annual Audit................................................... 12 2.15 Presenting Claims for Benefits................................. 13 2.16 Claims Review Procedure........................................ 13 2.17 Disputed Benefits.............................................. 14 ARTICLE III PARTICIPATION IN THE PLAN.................................... 15 3.1 Eligibility of Employees....................................... 15 3.2 Employee Information........................................... 15 3.3 Application by Participants.................................... 15 3.4 Service Defined................................................ 15 3.5 Commencement and Termination of Service........................ 16 3.6 Transferred Participants....................................... 17 3.7 Qualified Military Service..................................... 18 ARTICLE IV CONTRIBUTIONS TO THE PLAN..................................... 19 4.1 Employer Matching Contributions................................ 19 4.2 Pre-Tax Contributions.......................................... 20 4.3 After-Tax Contributions........................................ 21 4.4 Employer Matching Contributions and Pre-Tax Contributions to be Tax Deductible................................................. 22 4.5 Maximum Allocations............................................ 22 4.6 Refunds to Employer............................................ 22 4.7 Rollover Contributions......................................... 23 -i-
ARTICLE V PARTICIPANT ACCOUNTS........................................... 25 5.1 Trust Accounts................................................. 25 5.2 Valuation of Trust Fund........................................ 25 5.3 Allocations to Accounts........................................ 26 5.4 Maximum Annual Additions....................................... 27 ARTICLE VI PARTICIPANTS' BENEFITS........................................ 33 6.1 Vesting........................................................ 33 6.2 Termination of Service......................................... 33 6.3 Death of Participants.......................................... 33 6.4 In-Service Distributions....................................... 34 6.5 Payments of Benefits........................................... 35 6.6 Payment of Distribution Directly to Eligible Retirement Plan... 37 6.7 Participation Rights Determined as of Valuation Date Coinciding with or Preceding Termination of Employment.................... 39 6.8 Treatment of Non-Vested Account Balances Upon Termination of Service Prior to May 6, 2002................................... 39 6.9 Required Minimum Distributions................................. 40 6.10 Unclaimed Benefits............................................. 41 6.11 Optional Forms of Benefits..................................... 42 ARTICLE VII WITHDRAWALS AND LOANS........................................ 43 7.1 Withdrawal of After-Tax Contributions.......................... 43 7.2 Withdrawal of Pre-Tax Contributions On and After Age 59 1/2.... 43 7.3 Withdrawal From Prior Plan Account and Rollover Account........ 43 7.4 Conditions of Withdrawals...................................... 43 7.5 Loans.......................................................... 44 ARTICLE VIII INVESTMENT DIRECTIONS....................................... 45 8.1 Investment of Trust Fund....................................... 45 8.2 ESOP Company Stock Fund........................................ 46 8.3 Voting of Company Stock; Exercise of Other Rights.............. 46 ARTICLE IX TRUST AGREEMENT AND TRUST FUND................................ 48 9.1 Trust Agreement................................................ 48 9.2 Benefits Paid Solely From Trust Fund........................... 48 9.3 Committee Directions to Trustee................................ 48 9.4 Trustee's Reliance on Committee Instructions................... 48 9.5 Authority of Trustee in Absence of Instructions From the Committee.................................................. 48 9.6 Compliance with Exchange Act Rule 10(b)(18).................... 49 ARTICLE X ADOPTING EMPLOYERS, AMENDMENT AND TERMINATION OF THE PLAN, AND DISCONTINUANCE OF CONTRIBUTIONS TO THE TRUST FUND.............. 50 10.1 Adoption by Employers.......................................... 50 10.2 Continuous Service............................................. 51 10.3 Amendment of the Plan.......................................... 51 10.4 Termination of the Plan........................................ 52 -ii-
10.5 Distribution of Trust Fund on Termination...................... 52 10.6 Effect of Discontinuance of Contributions...................... 52 10.7 Merger of Plan with Another Plan............................... 52 ARTICLE XI TOP-HEAVY PLAN REQUIREMENTS................................... 53 11.1 General Rule................................................... 53 11.2 Vesting Provisions............................................. 53 11.3 Minimum Contribution Percentage................................ 53 11.4 Limitation on Compensation..................................... 54 11.5 Coordination With Other Plans.................................. 54 11.6 Distributions to Certain Key Employees......................... 55 11.7 Determination of Top-Heavy Status.............................. 55 ARTICLE XII TESTING OF CONTRIBUTIONS..................................... 59 12.1 Definitions.................................................... 59 12.2 Actual Deferral Percentage Test................................ 61 12.3 Excess Contributions........................................... 62 12.4 Actual Contribution Percentage Test............................ 63 12.5 Excess Aggregate Contributions................................. 64 12.6 Effective Date................................................. 65 ARTICLE XIII MISCELLANEOUS PROVISIONS.................................... 66 13.1 Not Contract of Employment..................................... 66 13.2 Controlling Law................................................ 66 13.3 Invalidity of Particular Provisions............................ 66 13.4 Non-Alienability of Rights of Participants..................... 66 13.5 Payments in Satisfaction of Claims of Participants............. 67 13.6 Payments Due Minors and Incompetents........................... 67 13.7 Acceptance of Terms and Conditions of Plan by Participants..... 67 13.8 Impossibility of Diversion of Trust Fund....................... 67 -iii-
CENTERPOINT ENERGY SAVINGS PLAN (As Amended and Restated Effective January 1, 2005) Recitals WHEREAS, Houston Industries Incorporated, a Texas corporation ("HII"), established a tax-qualified defined contribution plan, effective July 1, 1973, for the benefit of its eligible employees (the "Saving Plan"), along with a trust, which formed a part of the Savings Plan; and WHEREAS, effective January 1, 1989, the Savings Plan was amended to comply with the requirements of Section 401(a) of the Internal Revenue Code of 1986 (the "Code"), as amended by the Tax Reform Act of 1986, and Section 501(a) of the Code with respect to the underlying Savings Plan trust, and to make certain other changes therein; and WHEREAS, effective October 5, 1990, the Savings Plan was amended and restated to include an employee stock ownership plan ("ESOP") intended to qualify under Sections 401(a) and 4975(e)(7) of the Code, and effective July 1, 1995, the Savings Plan was again amended and restated to make certain additional changes (the Savings Plan, as amended and restated effective July 1, 1995, and as thereafter amended and in effect on March 31, 1999, being herein referred to as the "Prior HII Plan"); and WHEREAS, effective August 6, 1997, as a result of the corporate merger, HII assumed the sponsorship of the NorAm Employee Savings & Investment Plan (the "NorAm Plan") and the Minnegasco Division Employees' Retirement Savings Plan (the "Minnegasco Plan"), and adopted the underlying plan trusts; and WHEREAS, effective April 1, 1999, the NorAm Plan and Minnegasco Plan were merged with and into the Prior HII Plan, and the assets and liabilities under the NorAm Plan and Minnegasco Plan trusts were transferred to the Savings Plan trust, and the Prior HII Plan was amended and restated (1) to reflect the same, (2) to incorporate all prior amendments to the Prior HII Plan, including the amendments incorporating certain changes required by the Retirement Protection Act of 1994 under the General Agreement on Tariffs and Trades, the Uniformed Services Employment and Reemployment Rights Act, the Small Business Job Protection Act of 1996 and the Tax Reform Act of 1997, (3) to reflect the change in the name of the Plan sponsor from Houston Industries Incorporated to Reliant Energy, Incorporated ("REI"), and (4) to make certain other changes to the Prior HII Plan (the "1999 Plan"), with such 1999 Plan subsequently amended to reflect the applicable provisions of the Community Renewal Tax Relief Act of 2000, the Economic Growth and Tax Relief Reconciliation Act of 2001 and the Job Creation and Worker Assistance Act of 2002; and WHEREAS, effective August 31, 2002, in connection with the spin-off of Reliant Resources, Inc. ("RRI"), a subsidiary of REI, and the resulting reorganization of REI, CenterPoint Energy, Inc. (the "Company") became the plan sponsor of the 1999 Plan, which was renamed the CenterPoint Energy, Inc. Savings Plan (and the 1999 Plan trust was renamed the CenterPoint Energy, Inc. Savings Trust); and -1-
WHEREAS, effective January 1, 2005 (the "Effective Date"), the Board of Directors of the Company authorized and directed that the 1999 Plan be amended, restated and continued in order to incorporate all prior amendments to the 1999 Plan, to reflect the final loan payment and end of the leveraged ESOP loan, and to make certain design changes, with the amended and restated 1999 Plan hereinafter referred to as the "Plan" and the 1999 Plan trust hereinafter referred to as the "Savings Trust;" and WHEREAS, the provisions of the Plan shall apply to a participant who continues his "Service" (as defined herein) on and after the Effective Date and, except as otherwise expressly set forth herein, the rights and benefits, if any, of a prior plan participant who terminated his Service prior to the Effective Date shall be determined under the provisions of the applicable prior plan in effect on the date his Service terminated; and WHEREAS, the Plan and the Savings Trust are intended to meet the requirements of Sections 401(a), 401(k), 501(a), and 4975(e)(7) of the Code and the Employee Retirement Income Security Act of 1974, as either may be amended from time to time; NOW, THEREFORE, the Company hereby amends, restates, and continues the 1999 Plan in the form of, and by the adoption of, the CenterPoint Energy Savings Plan as herein set forth, effective January 1, 2005, except as otherwise indicated herein, to read as follows: -2-
ARTICLE I DEFINITIONS As used in the Plan, the following words and phrases shall have the following meanings unless the context clearly requires a different meaning: ACCOUNT: Any of the accounts maintained for a Participant pursuant to Section 5.1, or all such accounts collectively, as the context requires. AFFILIATE: A corporation or other trade or business which, together with an Employer, is "under common control" within the meaning of Section 414(b) or (c), as modified by Section 415(h) of the Code; any organization (whether or not incorporated) which is a member of an "affiliated service group" (within the meaning of Section 414(m) of the Code) which includes the Employer; and any other entity required to be aggregated with the Employer pursuant to regulations under Section 414(o) of the Code. AFTER-TAX CONTRIBUTIONS: Any amount contributed by a Participant to the Trust Fund from his Compensation as "After-Tax Matched Contributions" and "After-Tax Unmatched Contributions" pursuant to Section 4.3. AFTER-TAX CONTRIBUTION ACCOUNT: The account or accounts maintained for each Participant to reflect his After-Tax Matched Contributions and After-Tax Unmatched Contributions, and any allocations and adjustments thereto. BENEFICIARY: Such natural person or persons, or the trustee of an inter vivos trust for the benefit of natural persons, entitled to receive a Participant's death benefits under the Plan, as provided in Section 6.3 hereof. BOARD: The Board of Directors of the Company. CENGAS ACCOUNT: The account maintained to reflect the after-tax contributions of certain Minnegasco Participants made under the Minnegasco, Inc. Retirement Plan for Employees of the Former Cengas Division, and any allocations and adjustments thereto. CODE: The Internal Revenue Code of 1986, as amended. COMMITTEE: The Benefits Committee as described in Article II and, in regard to any provision of this Plan under which an agent has been appointed by the Benefits Committee pursuant to Article II to administer such provision of this Plan, such agent. COMPANY: CenterPoint Energy, Inc., a Texas corporation, or a successor to CenterPoint Energy, Inc. in the ownership of substantially all of its assets. COMPANY STOCK: Common stock or convertible preferred stock of the Company which is readily tradable on an established securities market. -3-
COMPENSATION: The total cash compensation actually paid for personal services to an Employee by the Employer during the applicable payroll period plus any amounts contributed by an Employer pursuant to a salary reduction agreement under Code Section 401(k) and any amounts not includable in gross income of the Participant under Code Sections 132(f) and 125, and shall specifically (i) include salaries, wages, commissions, overtime pay, performance-based bonuses paid in cash, and any other payments of compensation in cash which would be subject to tax under Code Section 3401(a); and (ii) exclude expense allowances, benefits received under the long-term disability plan of an Employer, contributions of the Employer to or benefits under this Plan or any other welfare or deferred compensation plan not expressly included above, any payments made in connection with an Employee's termination of employment or severance pay, and any payments made in connection with an Employee's commencement of, or agreement to, employment with the Employer; provided, however, that Compensation taken into account under the Plan for any Participant during a given Plan Year shall not exceed $200,000 (or such other amount provided under Code Section 401(a)(17)), as adjusted for cost-of-living increases in accordance with Code Section 401(a)(17)(B) (with such amount adjusted to $210,000 for the 2005 Plan Year). The Compensation of the respective Participants as reflected by the books and records of the Employer shall be conclusive. CONTRIBUTION: Any amount contributed to the Trust Fund pursuant to the provisions of this Plan by the Employer or by a Participant from his Compensation, including After-Tax Contributions, Employer Matching Contributions, and Pre-Tax Contributions. DISABILITY: A disability incurred by a Participant that satisfies the requirements of Section 6.2. EFFECTIVE DATE: January 1, 2005, except (i) as otherwise provided in specific provisions of the Plan and (ii) that provisions of the Plan required to have an earlier effective date by application of statute and/or regulation shall be effective as of the required effective date in such statute and/or regulation. EMPLOYEE: Any person employed by an Employer, including any Leased Employee performing services for an Employer. In addition to the above, the term "Employee" shall include any person receiving remuneration for personal services (or who would be receiving such remuneration except for an authorized leave of absence) rendered as an employee of a foreign affiliate (as defined in Code Section 3121(l)(6)) of an Employer to which an agreement extending coverage under the Federal Social Security Act entered into by an Employer under Code Section 3121(l), provided that such person is a citizen or resident of the United States. EMPLOYER: The Company (including its successors) and any other eligible entity or organization that has adopted this Plan pursuant to the provisions of Article X, and the successors, if any, to such entity or organization, with such Employers set forth on Exhibit A to the Plan. EMPLOYER MATCHING ACCOUNT: An account or accounts maintained for each Participant to reflect the interest in his Employer Matching Contributions to the Plan, and any allocations and adjustments thereto. The Employer Matching Account also reflects "Profit -4-
Sharing Contributions" and "Resources Employer Matching Contributions" made to the Trust Fund by a "Resources Employer" on behalf of a Participant who was a "Resources Employee" under the Prior Plan (as each such term is defined under the Prior Plan). EMPLOYER MATCHING CONTRIBUTIONS: Any amount contributed to the Trust Fund by the Employer pursuant to Section 4.1. ERISA: The Employee Retirement Income Security Act of 1974, as amended from time to time. ESOP COMPANY STOCK FUND: The investment fund held by the Trustee, which is intended to constitute an employee stock ownership plan, within the meaning of Section 4975(e)(7) of the Code, that is invested and reinvested in shares of Company Stock. FIDUCIARIES: The Committee, the Trustee, and any other person designated as a Fiduciary with respect to the Plan or the Trust Agreement, but only with respect to the specific responsibilities of each as described in Section 2.13 hereof. HIGHLY COMPENSATED EMPLOYEE: Any Employee and any employee of an Affiliate who is a highly compensated employee under Section 414(q) of the Code, including any Employee and any employee of an Affiliate who was a "5% owner" (as defined in Code Section 416(i)) during the current Plan Year or prior Plan Year or who received Compensation during the prior Plan Year in excess of $80,000, or such other amount as determined by the Secretary of the Treasury or his delegate, excluding Employees described in Code Section 414(q)(8) (such amount adjusted to $95,000 for the 2005 Plan Year). In determining an Employee's status as a Highly Compensated Employee within the meaning of Section 414(q), the entities set forth in Treasury Regulation Section 1.414(q)-1T Q&A-6(a)(1) through (4) must be taken into account as a single employer. A former Employee shall be treated as a Highly Compensated Employee if (i) such former Employee was a Highly Compensated Employee when he separated from Service or (ii) such former Employee was a Highly Compensated Employee in Service at any time after attaining age 55. INVESTMENT FUND: One of the investment funds or investment alternatives designated by the Committee, pursuant to Section 8.1 and the applicable provisions of the Trust Agreement, as alternatives in which Participants may elect to invest the amounts in their Accounts, subject to the provisions and restrictions in Section 8.1. The foregoing notwithstanding, the term "Investment Fund" shall not include, or refer to, the ESOP Company Stock Fund or REI Stock Fund. INVESTMENT MANAGER: The Investment Manager, if any, appointed by the Committee under the Trust Agreement, as such term is defined by Section 3(38) of ERISA. LEASED EMPLOYEE: Each person who is not an employee of the Employer or an Affiliate but who performs services for the Employer or an Affiliate pursuant to a leasing agreement (oral or written) between the Employer or an Affiliate and any leasing organization, provided that such person has performed such services for the Employer or an Affiliate or for related persons (within the meaning of Section 144(a)(3) of the Code) on a substantially full-time basis for a period of at least one year and such services are performed under primary direction or -5-
control by the Employer or an Affiliate. Notwithstanding the preceding sentence, the term "Leased Employee" does not include individuals described in Section 414(n)(5) of the Code. MINNEGASCO PARTICIPANT: A Participant who was participating in the Minnegasco Plan immediately prior to April 1, 1999. MINNEGASCO PLAN: The Minnegasco Division Employees' Retirement Savings Plan as in effect immediately prior to April 1, 1999. NORAM PARTICIPANT: A Participant who was participating in the NorAm Plan immediately prior to April 1, 1999. NORAM PLAN: The NorAm Employee Savings & Investment Plan as in effect immediately prior to April 1, 1999. PARTICIPANT: An Employee who, pursuant to the provisions of Article III hereof, has met the eligibility requirements and is participating in the Plan. A former Employee, Beneficiary, or alternate payee shall be deemed a Participant under the Plan as long as he has an Account in the Trust Fund that has not been forfeited under Section 6.1 hereof and will be entitled to exercise all the rights and privileges granted active Employees who are Participants except as otherwise specifically provided in the case of contributions to the Plan under Article IV and Participant loans under Section 7.5 hereof. PLAN: The CenterPoint Energy Savings Plan set forth herein, which is intended to constitute a profit-sharing plan under Section 401(a)(27) of the Code and an employee stock ownership plan under Section 4975(e)(7) of the Code and includes a cash or deferred arrangement under Section 401(k) of the Code, including all subsequent amendments hereto. PLAN YEAR: The 12-month period commencing on January 1 and ending on December 31. PRE-TAX CONTRIBUTIONS: Any amount deferred by a Participant from his Compensation, pursuant to Section 401(k) of the Code, and contributed to the Trust Fund as "Pre-Tax Matched Contributions" and "Pre-Tax Unmatched Contributions" pursuant to Section 4.2. PRE-TAX CONTRIBUTION ACCOUNT: The account or accounts maintained for each Participant to reflect his Pre-Tax Matched Contributions and Pre-Tax Unmatched Contributions to the Plan, and any allocations and adjustments thereto. PRIOR PLAN: The CenterPoint Energy, Inc. Savings Plan as in effect on December 31, 2004. PRIOR PLAN ACCOUNT: The account or accounts maintained to reflect (i) employer matching contributions to the Minnegasco and NorAm Plans for the period commencing on January 1, 1999 and ending on March 31, 1999 for certain Minnegasco and NorAm Participants, respectively, and any allocations and adjustments thereto (referred to as the "Prior Plan 1999 Matching Account" in the Prior Plan), (ii) ESOP contributions to the Minnegasco and NorAm -6-
Plans prior to January 1, 1999, and any allocations and adjustments thereto (referred to as the "Prior Plan ESOP Account" in the Prior Plan), (iii) employee matching contributions to the Minnegasco and NorAm Plans prior to January 1, 1999 for certain Minnegasco and NorAm Participants, respectively, and any allocations and adjustments thereto (referred to as the "Prior Plan Matching Account" in the Prior Plan), and (iv) the Cengas Account. PRIOR PLAN PARTICIPANT: Any person who is in the employment of an Employer or Affiliate on the Effective Date and was included in and covered by the Prior Plan immediately prior thereto, or who is the alternate payee, Beneficiary, spouse or estate representative of such a person who died or was receiving or entitled to receive benefits under the Prior Plan. QUALIFIED JOINT AND SURVIVOR ANNUITY: With respect to a Participant with a Cengas Account, a monthly annuity for the life of the Participant beginning on the date any distribution is to be made with a survivor annuity equal to 50% of the amount of the annuity which is payable during the joint lives of the Participant and the person who is the spouse of the Participant on the earlier of the date benefits commence or the date the annuity is distributed, and which is purchased from an insurance company with the vested portion of the Participant's Cengas Account determined as of the most recent Valuation Date. The Committee, in its sole discretion, shall select the insurance company from which the annuity shall be purchased. If a Participant is not married, the term "Qualified Joint and Survivor Annuity" shall mean an immediate annuity for the life of the Participant purchased in the same manner as provided above. QUALIFIED MILITARY SERVICE: Any service in the uniformed services (as defined in Chapter 43 of Title 38 of the United States Code or its successor) by an Employee who is entitled to reemployment rights under such chapter with respect to such service. QUALIFIED SURVIVOR ANNUITY: With respect to a Participant with a Cengas Account, an annuity payable for the life of the surviving spouse beginning on the date any distribution is to be made which is purchased from an insurance company with the vested portion of the Participant's Cengas Account determined as of the most recent Valuation Date. The Committee shall have the discretion to determine the insurance company from which the annuity shall be purchased. REI STOCK: Common stock of Reliant Energy, Inc. (formerly Reliant Resources, Inc. prior to April 26, 2004), which is readily tradable on an established securities market. REI STOCK FUND: A frozen investment fund that is invested in REI Stock, which is readily tradable on an established securities market. ROLLOVER CONTRIBUTION: Any amount contributed to the Plan by an Employee or Participant pursuant to Section 4.7. ROLLOVER ACCOUNT: An account maintained for an Employee or Participant to reflect his Rollover Contributions to this Plan, and any allocations and adjustments thereto. SERVICE: An Employee's or Participant's period of employment with an Employer or Affiliate, as determined in accordance with Article III. -7-
STOCK FUNDS: Collectively, the ESOP Company Stock Fund and REI Stock Fund. TRUST AGREEMENT: The CenterPoint Energy Savings Trust as it may hereafter be amended from time to time. TRUST FUND: All contributions of Employers and Participants, and the investments and reinvestments thereof, held by the Trustee under the Trust Agreement, together with all income, profits or increments thereon. TRUSTEE: The Northern Trust Company, an Illinois corporation, or any successor Trustee or Trustees under the relevant Trust Agreement. VALUATION DATE: Any date on which the New York Stock Exchange is open for trading and any date on which the value of the assets of the Trust Fund is determined by the Trustee pursuant to Section 5.2. Words used in this Plan and in the Trust Agreement in the singular shall include the plural and in the plural, the singular, and the gender of words used shall be construed to include whichever may be appropriate under any particular circumstances of the masculine, feminine, or neuter genders. -8-
ARTICLE II ADMINISTRATION OF THE PLAN 2.1 Appointment of Committee: The Board shall appoint a Committee of not less than three persons, who may be Employees of the Company, to perform the administrative duties set forth herein. The Committee shall be the administrator of the Plan for the purposes of ERISA. Each member of the Committee shall serve for such term as the Board may designate or until his death, resignation or removal by the Board. The Board shall promptly appoint successors to fill any vacancies in the Committee. 2.2 Records of Committee: The Committee shall keep appropriate records of its proceedings and the administration of the Plan. The Committee shall make available to Participants and their Beneficiaries for examination, during business hours, such records of the Plan as pertain to the examining person and such documents relating to the Plan as are required by any applicable disclosure acts. 2.3 Committee Action: The Committee may act through the concurrence of a majority of its members expressed either at a meeting of the Committee, or in writing without a meeting. Any member of the Committee, or the Secretary or Assistant Secretary of the Committee (who need not be members of the Committee), may execute on behalf of the Committee any certificate or other written instrument evidencing or carrying out any action approved by the Committee. The Committee may delegate any of its rights, powers and duties to any one or more of its members or to an agent. The Chairman of the Committee shall be the agent of the Plan and the Committee for the service of legal process at the principal office of the Company in Houston, Texas. 2.4 Committee Disqualification: A member of the Committee who may be a Participant shall not vote on any question relating specifically to himself. 2.5 Committee Compensation and Expenses: The members of the Committee shall serve without bond (unless otherwise required by law) and without compensation for their services as such. The Committee may select and authorize the Trustee to suitably compensate such attorneys, agents and representatives as it may deem necessary or advisable to the performance of its duties. Expenses of the Committee that shall arise in connection with the administration of the Plan shall be paid by the Company or, if not paid by the Company, by the Trustee out of the Trust Fund. 2.6 Committee Liability: Except to the extent that such liability is created by ERISA, no member of the Committee shall be liable for any act or omission of any other member of the Committee, nor for any act or omission on his own part except for his gross negligence or willful misconduct, nor for the exercise of any power or discretion in the performance of any duty assumed by him hereunder. The Company shall indemnify and hold harmless each member of the Committee from any and all claims, losses, damages, expenses (including counsel fees approved by the Committee) and liabilities (including any amounts paid in settlement with the Committee's approval, but excluding any excise tax assessed against any member or members of the Committee pursuant to the provisions of Section 4975 of the Code) arising from any act or -9-
omission of such member in connection with duties and responsibilities under the Plan, except where the same is judicially determined to be due to the gross negligence or willful misconduct of such member. 2.7 Committee Determinations: The Committee shall enforce this Plan in accordance with its terms and shall have all powers necessary for the accomplishment of that purpose, including, but not by way of limitation, the following powers: (a) To employ such agents and assistants, such counsel (who may be of counsel to the Company) and such clerical, accounting, administrative, and investment services as the Committee may require in carrying out the provisions of the Plan; (b) To authorize one or more of their number, or any agent, to make payment, or to execute or deliver any instrument, on behalf of the Committee, except that all requisitions for funds from, and requests, directions, notifications, certifications, and instructions to, the Trustee (except as provided in (i) below) or to the Company shall be signed either by a member of the Committee or by the Secretary or Assistant Secretary of the Committee; (c) To determine from the records of the Company the considered Compensation, Service and other pertinent facts regarding Employees and Participants for the purpose of the Plan; (d) To construe and interpret the Plan, decide all questions of eligibility and determine the amount, manner and time of payment of any benefits hereunder; (e) To prescribe forms and procedures to be followed by Employees for participation in the Plan, by Participants or Beneficiaries filing applications for benefits, by Participants applying for withdrawals or loans, and for other occurrences in the administration of the Plan; (f) To prepare and distribute, in such manner as the Committee determines to be appropriate, information explaining the Plan; (g) To furnish the Company and the Participants, upon request, such annual reports with respect to the administration of the Plan as are reasonable and appropriate; (h) To certify to the Trustee the amount and kind of benefits payable to Participants and their Beneficiaries; (i) To authorize all disbursements by the Trustee from the Trust Fund by a written authorization signed either by a member of the Committee or by the Secretary or Assistant Secretary of the Committee; provided, however, that disbursements for ordinary expenses incurred in the administration of the Trust Fund and disbursements to Participants need not be authorized by the Committee; -10-
(j) In the event of any share split, share dividend or combination of outstanding shares of Company Stock or REI Stock, as applicable, to determine the appropriate allocation of shares of each such stock to the portion of the Accounts maintained for the Participants that are invested in such stock, pursuant to the applicable stock fund, and to determine the appropriate number of shares distributable to a Participant under Section 6.5 hereof immediately following such share split, share dividend or combination so as to effectuate the intent and purpose of the Plan (provided, however, that, the foregoing notwithstanding, the Board shall be solely responsible for, and have the sole power to (1) amend, modify, restrict or limit investment in, or terminate, the ESOP Company Stock Fund and REI Stock Fund and (2) amend, modify or terminate any provision of the Plan or Trust related to the administration of the Stock Funds); (k) To interpret and construe all terms, provisions, conditions and limitations of this Plan and to reconcile any inconsistency or supply any omitted detail that may appear in this Plan in such manner and to such extent, consistent with the general terms of this Plan, as the Committee shall deem necessary and proper to effectuate the Plan for the greatest benefit of all parties interested in the Plan; (l) To make and enforce such rules and regulations for the administration of the Plan as are not inconsistent with the terms set forth herein; and (m) In addition to all other powers herein granted, and in general consistent with provisions hereof, the Committee shall have all other rights and powers reasonably necessary to supervise and control the administration of this Plan. 2.8 Employee Information From Employer: To enable the Committee to perform its functions, the Employer shall supply full and timely information to the Committee relating to the dates of employment of its Employees for purposes of determining eligibility of Employees to participate hereunder, the Compensation of all Participants, their termination of employment, death or becoming Disabled, and such other pertinent facts related to an Employee's eligibility to participate and Service as the Committee may require. The Committee shall advise the Trustee of such of the foregoing facts as may be pertinent to the Trustee's administration of the Trust Fund. 2.9 Uniform Administration: Whenever in the administration of the Plan any action is required by the Employer or the Committee, including, but not by way of limitation, action with respect to eligibility of Employees, Contributions, and benefits, such action shall be uniform in nature as applied to all persons similarly situated, and no action shall be taken which will discriminate in favor of Participants who are officers or shareholders of the Employer, highly compensated Employees, or persons whose principal duties consist of supervising the work of others. -11-
2.10 Reporting Responsibilities: The Committee shall file or distribute all reports, returns and notices required under ERISA or other applicable law. 2.11 Disclosure Responsibilities: The Committee shall make available to each Participant and Beneficiary such records, documents and other data as may be required under ERISA, and Participants or Beneficiaries shall have the right to examine such records at reasonable times during business hours. Nothing contained in this Plan shall give any Participant or Beneficiary the right to examine any data or records reflecting the Compensation paid to, or relating to any Account of, any other Participant or Beneficiary, except as may be required under ERISA. 2.12 Statements: No less frequently than annually, the Committee (or its delegate) shall prepare and deliver to each Participant a statement reflecting as of the Valuation Date provided in such statement: (a) Such information applicable to contributions by and for each such Participant and the increase or decrease thereof as a consequence of valuation adjustments as may be pertinent in the premises; and (b) The balance in his Account as of that Valuation Date. 2.13 Allocation of Responsibility Among Fiduciaries for Plan and Trust Administration: The Fiduciaries shall have only those specific powers, duties, responsibilities and obligations as are specifically given them under this Plan or the Trust Agreement. The Board shall have the sole authority to appoint and remove the Trustee and members of the Committee. The Committee shall have the sole responsibility for the administration of the Plan and the sole authority to appoint and remove any Investment Manager which may be provided for under the Trust. The Trustee shall have the sole responsibility for the administration of the Trust Fund and shall have exclusive authority and discretion to manage and control the assets held under the Trust Fund, except to the extent that the authority to manage, acquire and dispose of the assets of the Trust Fund is delegated to an Investment Manager, all as specifically provided in the Trust Agreement. Each Fiduciary may rely upon any such direction, information or action of another Fiduciary as being proper under this Plan or the Trust Agreement and is not required under this Plan or the Trust Agreement to inquire into the propriety of any such direction, information or action. It is intended under this Plan and the Trust Agreement that each Fiduciary shall be responsible for the proper exercise of its own powers, duties, responsibilities and obligations under this Plan and the Trust Agreement and shall not be responsible for any act or failure to act of another Fiduciary. No Fiduciary guarantees the Trust Fund in any manner against investment loss or depreciation in asset value. 2.14 Annual Audit: The Committee shall engage, on behalf of all Participants, an independent certified public accountant who shall conduct an annual examination of any financial statements of the Plan and Trust Fund and of other books and records of the Plan and Trust Fund as the certified public accountant may deem necessary to enable him to form and provide a written opinion as to whether the financial statements and related schedules required to be filed with the Internal Revenue Service, Securities and Exchange Commission, or Department of Labor, or furnished to each Participant are presented fairly and in conformity with generally -12-
accepted accounting principles applied on a basis consistent with that of the preceding Plan Year. If, however, the statements required to be submitted as part of the reports to the Department of Labor are prepared by a bank or similar institution or insurance carrier regulated and supervised and subject to periodic examination by a state or federal agency, and if such statements are, in fact, made a part of the annual report to the Department of Labor and no such audit is required by ERISA, then the audit required by the foregoing provisions of this Section shall be optional with the Committee. 2.15 Presenting Claims for Benefits: Any Participant or any other person claiming under any deceased Participant (collectively, the "Applicant") may submit written application to the Committee (or its delegate) for the payment of any benefit asserted to be due him under the Plan. Such application shall set forth the nature of the claim and such other information as the Committee (or its delegate) may reasonably request. The Committee (or its delegate) shall notify the Applicant of the benefits determination within a reasonable time after receipt of the claim, such time not to exceed 90 days unless special circumstances require an extension of time for processing the application. If such an extension of time for processing is required, written notice of the extension shall be furnished to the Applicant prior to the end of the initial 90-day period. In no event shall such extension exceed a period of 90 days from the end of such initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Committee (or its delegate) expects to render its final decision. Notice of the Committee's (or its delegate's) decision to deny a claim in whole or in part shall be set forth in a manner calculated to be understood by the Applicant and shall contain the following: (a) the specific reason or reasons for the denial; (b) specific reference to the pertinent Plan provisions on which the denial is based; (c) a description of any additional material or information necessary for the Applicant to perfect the claim and an explanation of why such material or information is necessary; and (d) an explanation of the claims review procedures set forth in Section 2.16 hereof, including the Applicant's right to bring a civil action under Section 502(a) of ERISA following a denial on review. Applicants shall be given timely written notice of the time limits set forth herein for determination on claims, appeal of claim denial and decisions on appeal. 2.16 Claims Review Procedure: If an application filed by an Applicant under Section 2.15 above shall result in a denial of the benefit applied for, either in whole or in part, such Applicant shall have the right, to be exercised by written request filed with the Committee within 60 days after receipt of notice of the denial of his application, to request a review of his application and of his entitlement to the benefit for which he applied by the Committee. Such request for review may contain such additional information and comments as the Applicant may wish to present. The Committee shall reconsider the application in light of such additional -13-
information and comments as the Applicant may have presented and, if the Applicant shall have so requested, may grant the Applicant a formal hearing before the Committee in its discretion. The Committee shall also permit the Applicant or his designated representative to review pertinent documents in its possession, including copies of the Plan document and information provided by the Employer relating to the Applicant's entitlement to such benefit. The Committee shall render a decision no later than the date of the Committee meeting next following receipt of the request for review, except that (i) a decision may be rendered no later than the second following Committee meeting if the request is received within 30 days of the first meeting and (ii) under special circumstances which require an extension of time for rendering a decision (including, but not limited to, the need to hold a hearing), the decision may be rendered not later than the date of the third Committee meeting following the receipt of the request for review. If such an extension of time for review is required because of special circumstances, written notice of the extension shall be furnished to the Applicant prior to the commencement of the extension. Notice of the Committee's final decision shall be furnished to the Applicant in writing, in a manner calculated to be understood by him, and if the Applicant's claim on review is denied in whole or in part, the notice shall set forth the specific reason or reasons for the denial and the specific reference to the pertinent plan provisions on which the denial is based, the Applicant's right to receive upon request, free of charge, reasonable access to, and copies of, all relevant documents, records and other information to his claim, and his right to bring a civil action under Section 502(a) of ERISA. Benefits under this Plan will be paid only if the Committee decides in its discretion that the Applicant is entitled to them. Notwithstanding the foregoing or any provision of the Plan to the contrary, an Applicant must exhaust all of his administrative remedies set forth in Section 2.15 and this Section before he may bring any action at law or equity. 2.17 Disputed Benefits: If any dispute shall arise between an Applicant and the Committee after review of a claim for benefits, or in the event any dispute shall develop as to the person to whom the payment of any benefit under the Plan shall be made, the Trustee may withhold the payment of all or any part of the benefits payable hereunder to the Applicant until such dispute has been resolved by a court of competent jurisdiction or settled by the parties involved. -14-
ARTICLE III PARTICIPATION IN THE PLAN 3.1 Eligibility of Employees: An Employee eligible to participate under the Prior Plan immediately preceding the Effective Date shall be eligible to become a Participant in this Plan as of the Effective Date, except as provided below. From and after the Effective Date, except as provided below, each Employee who is not a Participant and who begins Service with an Employer on or after the Effective Date shall be initially eligible to participate in the Plan following the later of (i) the Effective Date or (ii) the date he first begins Service with an Employer. Any Participant who terminates his Service and subsequently recommences his Service with an Employer shall again become eligible to participate in the Plan as soon as practicable following the first date he recommences his Service. Notwithstanding the foregoing, each of the following individuals shall be ineligible to participate in the Plan: (i) an Employee whose employment is covered by a collective bargaining agreement unless, pursuant to good faith bargaining, such agreement provides for participation in the Plan; (ii) an Employee who is a Leased Employee; (iii) an individual who is designated, compensated or otherwise classified or treated as an independent contractor or a leased employee by an Employer or an Affiliate; and (iv) an individual who is a nonresident alien and who receives no United States source earned income from his Employer. 3.2 Employee Information: The Committee shall maintain records which shall reflect as to each Employee his date of birth, all dates reflecting when he entered into or left the employment of any Employer, and his years of Service. The Employer shall make available to the Committee all such information as may be required by the Committee for the purposes of maintaining such information as to each Employee. 3.3 Application by Participants: Each Employee who is eligible to participate in the Plan pursuant to Section 3.1 and who desires to be a Participant must enroll in the Plan, in the form and manner as prescribed by the Committee, pursuant to which the Participant shall (i) elect to make Pre-Tax Contributions and/or After-Tax Contributions to the Plan, as provided in Sections 4.2 and 4.3, and (ii) designate and direct the investment of such contributed amounts and Employer Matching Contributions in or among the Investment Funds and/or the ESOP Company Stock Fund, as provided in Section 8.1. 3.4 Service Defined: For purposes of the Plan, the term "Service" shall mean the following: (a) With respect to Service prior to January 1, 2005, all service determined based on each Participant's "Service" under the Prior Plan immediately prior to the Effective Date. (b) With respect to Service after December 31, 2004, Service shall include all years, months and days of active employment with an Employer or an Affiliate from and after the Effective Date as an Employee, a Participant or a Participant on inactive status who is a Transferred Participant, as described in -15-
Section 3.6, and the following periods of "Authorized Absence" during which a Participant or Transferred Participant is: (i) Absent due to Qualified Military Service (as defined in Section 3.7), provided that such Employee or Participant complies with all prerequisites of applicable federal law and applied for reinstatement of employment pursuant to the procedures and requirements of the Employer and, if applicable, the Committee, to the extent consistent with applicable federal law; or (ii) Absent due to accident or sickness as long as the Employee or Participant is continued on the employment rolls of the Employer and remains eligible to work upon his recovery, provided that such Employee or Participant timely applied for reinstatement of employment following his date of recovery in accordance with the procedures and requirements of the Employer and, if applicable, the Committee; or (iii) Absent due to an authorized leave of absence, subject to such conditions as may be approved by the Committee consistently applied in a uniform and non-discriminatory manner to all Employees similarly situated. (c) An Employee's or Participant's Service shall also include any period required to be included as Service by federal law other than ERISA or the Code, but only under the conditions and to the extent so required by such federal law. In addition, the Committee, in its discretion, may credit an individual with Service based on employment with an entity other than the Employer, but only if and when such individual becomes an Employee eligible to participate in the Plan under this Article III and only if such crediting of Service (i) has a legitimate business reason, (ii) does not by design or operation discriminate significantly in favor of Highly Compensated Employees, and (iii) is applied to all similarly-situated Employees eligible to participate in the Plan under this Article III. Furthermore, in the event that the Plan constitutes a plan of a predecessor employer within the meaning of Section 414(a) of the Code, service for such predecessor employer shall be treated as Service to the extent required by Section 414(a) of the Code. 3.5 Commencement and Termination of Service: (a) An Employee's or Participant's Service shall commence (or recommence) on the date he first performs an "hour of service" within the meaning of Department of Labor Regulation Section 2530.200b-2(a)(1) for an Employer or Affiliate. All periods of Service shall be aggregated so that a one-year period of Service shall be completed as of the date the Employee or Participant completes 365 days of Service. Hours of service and Service will be -16-
credited for employment with other members of an affiliated service group (under Code Section 414(m)), a controlled group of corporations (under Code Section 414(b)), or a group of trades or businesses under common control (under Code Section 414(c)), of which the Employer is a member. (b) Except as otherwise provided in this Article III, a period of Service of an Employee or Participant shall terminate on the date of the first to occur of: (i) His quitting or discharge from employment; (ii) His death; (iii) His deemed date of termination of employment pursuant to his failure to return to work upon the expiration of such an Authorized Absence; or (iv) One year from the date the Employee or Participant is absent from active employment for any reason other than quitting, discharge, Authorized Absence or death. For purposes of clause (iii) immediately above, an Employee's or Participant's deemed date of termination shall be the earlier of (1) the expiration date of such Authorized Absence or (2) one year from the date such Authorized Absence commenced. 3.6 Transferred Participants: For purposes of determining eligibility to participate in the Plan under this Article III, a Participant's Service shall include his employment with an Affiliate after it becomes an Affiliate. If an individual is transferred from an employment classification with an Employer that is not covered by the Plan to an employment classification that is so covered, or from an Affiliate that is not an Employer to an employment classification with an Employer that is so covered, his period of Service prior to the date of transfer shall be considered for purposes of determining his eligibility to become a Participant under Section 3.1. In addition, if such transferred Participant had an account in a qualified defined contribution plan maintained by such Affiliate, such account shall be transferred to the Trust Fund under this Plan if the transfer is permitted by the terms of said plan and if the Committee determines that the transferred account will not fail to satisfy Section 401(a) or 411(d)(6) of the Code. Any transferred account shall be subject to the provisions of this Plan; provided, however, that the vesting provisions of the transferor plan shall continue to apply. If a Participant is transferred to employment with an Employer or Affiliate which is not eligible employment covered by the Plan, his participation in the Plan shall be suspended; provided, however, that during the period of his employment in such ineligible position: (a) He shall be credited with Service in accordance with this Article III; (b) He shall cease to have any right to make Contributions pursuant to Sections 4.2 and 4.3; -17-
(c) His Employer Matching Account shall receive no Employer Matching Contribution allocations under Section 4.1; (d) He shall continue to participate in income allocations of the earnings and/or losses of the Trust Fund pursuant to Section 5.3; (e) No distribution event shall be deemed to have occurred under the Plan; and (f) The loan privileges under Article VII and the investment provisions of Article VIII shall continue to apply. In addition, the Committee may, at its discretion, authorize the transfer of his Accounts under this Plan to the Trust Fund funding the qualified defined contribution plan, if any, of the Affiliate to which the Participant was transferred. In such event, the provisions of the transferee plan shall govern. 3.7 Qualified Military Service: Notwithstanding any provision of this Plan to the contrary, contributions, benefits and service credit with respect to Qualified Military Service will be provided in accordance with Section 414(u) of the Code. -18-
ARTICLE IV CONTRIBUTIONS TO THE PLAN 4.1 Employer Matching Contributions: The Employer shall make an Employer Matching Contribution (subject to adjustments for forfeitures and limitations on annual additions as elsewhere specified in the Plan) in cash in the amount necessary for each payroll period to result in an allocation under Article V to the Employer Matching Account of each Participant who has elected to make Pre-Tax and/or After-Tax Contributions during each such payroll period equal to 75% of the total of his Pre-Tax Matched Contribution and After-Tax Matched Contribution (not to exceed in the aggregate 6% of the Participant's Compensation) for each payroll period. The Employer shall have the sole responsibility for making the Contributions provided for under this Section 4.1. In addition to the foregoing Contribution, for any Plan Year, the Company's Chief Executive Officer, in his sole discretion, may make a discretionary Employer Matching Contribution in cash to the Employer Matching Accounts of the Participants who meet the eligibility requirements set forth below in the amount necessary to result in a total allocation under Article V for such eligible Participants equal to a percentage determined by the Chief Executive Officer, in his sole discretion, of the total of each such eligible Participant's Pre-Tax Matched Contributions and After-Tax Matched Contributions for the Plan Year. A Participant is eligible for a discretionary Employer Matching Contribution for a Plan Year if: (1) The Participant is in an employee group, based on his Employer's employment classification, selected by the Company's Chief Executive Officer, in his sole discretion, to receive a discretionary Employer Matching Contribution; and (2) Meets one of the following requirements: (i) The Participant is an Employee in active Service as of the last day of the applicable Plan Year; (ii) The Participant's Services terminates during the applicable Plan Year other than due to death or Disability and, as of his termination date, he is an Employee who is age 55 or older with five years of Service; or (iii) The Participant's Service terminates during the applicable Plan Year due to his death or Disability and, as of his termination date, he is an Employee. The amount of any discretionary Employer Matching Contribution for a Plan Year may vary among the selected employee groups as determined by the Chief Executive Officer, in his sole discretion. Any discretionary Employer Matching Contribution shall be made as soon as administratively practicable on or after the date the Company's Chief Executive Officer has both selected the employee groups and determined the amount of the Contribution to be made for the applicable Plan Year, but in no event later than the time prescribed by law for filing the federal income tax return of the Company for the applicable Plan Year, including any extension which has been granted for the filing of such tax return. -19-
To the extent specified in Section 5.3(d), any amount attributable to forfeitures will be applied to reduce, to the extent of such forfeitures, the Employer Matching Contributions required to be made under this Section 4.1 next following the determination of any such forfeiture amounts and/or pay incident expenses of the Plan. In the event that a forfeiture is reinstated under Section 6.8 because of the return to the employment of the terminated Participant, or in the event that a forfeiture arising under Section 6.10 is reinstated in accordance with the provisions of Section 6.10 because of an appropriate claim of forfeited unclaimed benefit by the Participant, Beneficiary or other distributee, the Employer shall contribute, within a reasonable time following such reemployment or claim, an amount equal to the forfeiture to be reinstated. 4.2 Pre-Tax Contributions: Each Participant who has elected to defer a portion of his Compensation as a Pre-Tax Matched Contribution to the Plan pursuant to Section 3.3 shall defer as his Pre-Tax Matched Contribution to the Trust Fund 1%, 2%, 3%, 4%, 5% or 6%, as he may designate, of his Compensation. In addition, each Participant may also elect to defer any whole percent, up to a maximum of 10%, of his Compensation as a Pre-Tax Unmatched Contribution. Each Participant's Pre-Tax Matched Contribution and Pre-Tax Unmatched Contribution, if any, shall be contributed to the Trust Fund by the Employer as soon as practicable following each pay period. A Participant's Pre-Tax Contributions under this Plan and all other plans, contracts or arrangements of the Employer shall not exceed a maximum dollar limitation provided under Code Section 402(g), as adjusted by the Secretary of the Treasury or his delegate for cost-of-living increases pursuant to Code Section 402(g), except to the extent permitted under this Section 4.2 with respect to Catch-Up Contributions. In the event a Participant's Pre-Tax Contributions exceed the applicable limit described in the preceding sentence, or in the event the Participant submits a written claim under the Plan, at the time and in the manner prescribed by the Committee, specifying an amount of Pre-Tax Contributions that will exceed the applicable limit of Section 402(g) of the Code when added to the amounts deferred by the Participant in other plans or arrangements, such excess (the "Excess Deferrals"), plus any income and minus any loss allocable to such amount during the Plan Year, shall be returned to the Participant no later than December 31st of the following year. Excess Deferrals not so returned by April 15th of the following year shall be treated as Annual Additions under Section 5.4 of the Plan. Each Participant's Pre-Tax Contribution Account shall be fully vested and non-forfeitable at all times. The Employer shall have the sole responsibility for making the Contributions provided for under this Section 4.2. If during any Plan Year, on the basis of the Pre-Tax Contribution rates elected by Participants for such Plan Year, the Committee determines, in its sole discretion, that neither of the tests contained in (a) or (b) of Section 12.2 will be satisfied, the Committee may reduce the Pre-Tax Contribution rate of any Participant who is among the eligible Highly Compensated Employees to the extent the Committee determines is necessary to reduce the overall Actual Deferral Percentage for such eligible Highly Compensated Employees to a level which will satisfy either (a) or (b) of Section 12.2. The Committee may, in its sole discretion, permit a Participant whose Pre-Tax Contributions are reduced under this Section to contribute a like amount to his After-Tax Contribution Account, subject to the limits provided in this Article IV of the Plan for After-Tax Contributions. If the Committee subsequently determines, in its sole discretion, that a Participant's Pre-Tax Contribution rate was reduced below the level necessary to satisfy either of the tests contained in (a) or (b) of Section 12.2 for the Plan Year, then such -20-
Participant may be eligible to increase his Pre-Tax Contribution rate for the remainder of the Plan Year to a level not in excess of that level which will satisfy the greater of (a) or (b) of Section 12.2. When first electing to participate in the Plan, each Participant shall give advance notification to the Committee or its delegate by electronic, telephonic, written or other such manner as may be prescribed from time to time by the Committee, of the amount he elects to defer as a Pre-Tax Matched Contribution and as a Pre-Tax Unmatched Contribution. Each such election shall continue in effect during subsequent Plan Years unless the Participant shall give timely notice to the Committee or its delegate of his election to change or discontinue his Pre-Tax Matched Contribution or his Pre-Tax Unmatched Contribution in accordance with procedures established from time to time by the Committee. If a Participant's Pre-Tax Contributions exceed the applicable limit described above, unless the Participant elects otherwise, his Contributions to the Plan will automatically continue in the form of After-Tax Contributions (in the same percentage) for the remainder of the Plan Year, subject to the limitations and conditions in the Plan governing After-Tax Contributions. In addition to Pre-Tax Contributions, Employees who are eligible to make Pre-Tax Contributions under this Plan and who have attained age 50 before the close of the Plan Year shall be eligible to make catch-up contributions in accordance with, and subject to the limitations of, Section 414(v) of the Code ("Catch-Up Contributions") in the form and manner prescribed by the Committee. Such Catch-Up Contributions shall not be taken into account for purposes of the provisions of the Plan implementing the required limitations of Sections 402(g) and 415 of the Code. The Plan shall not be treated as failing to satisfy the provisions of the Plan implementing the requirements of Section 401(k)(3), 401(k)(11), 401(k)(12), 410(b), or 416 of the Code, as applicable, by reason of the making of such Catch-Up Contributions. A Participant may change the rate of or discontinue his Pre-Tax Matched Contribution and/or Pre-Tax Unmatched Contribution, with no restrictions on frequency, by electronic, telephonic, written or other such manner as may be prescribed from time to time by the Committee. Any such change or discontinuance in the rate of Pre-Tax Matched and/or Unmatched Contributions shall be effective as soon as reasonably practicable following receipt by the Committee or its delegate of the change or discontinuance of such election. 4.3 After-Tax Contributions: Each Participant who has elected to make a Pre-Tax Matched Contribution of less than 6% of his Compensation may elect to make an After-Tax Matched Contribution to the Plan pursuant to Section 3.3 of 1%, 2%, 3%, 4%, 5% or 6%, as he may designate, of his Compensation, provided that the total of his Pre-Tax Matched Contribution, if any, and his After-Tax Matched Contribution does not exceed 6% of his Compensation. In addition, each Participant who has elected to make a Pre-Tax Unmatched Contribution of less than 10% of his Compensation may elect to contribute to the Plan any whole percent, up to a maximum of 10%, of his Compensation as an After-Tax Unmatched Contribution; provided, however, that the total of his Pre-Tax Unmatched Contribution, if any, and his After-Tax Unmatched Contribution does not exceed 10% of his Compensation. Each Participant's After-Tax Matched Contribution and After-Tax Unmatched Contribution, if any, shall be withheld from each of his paychecks and contributed to the Trust Fund by the Employer as soon as practicable following each pay period. Each Participant's After-Tax Contribution -21-
Account shall be fully vested and non-forfeitable at all times. The Employer shall have the sole responsibility for making the Contributions provided for under this Section 4.3. When first electing to participate in the Plan, each Participant shall give advance notification to the Committee or its delegate by electronic, telephonic, written or other such manner as may be prescribed from time to time by the Committee, of the amount he elects to contribute as an After-Tax Matched Contribution and as an After-Tax Unmatched Contribution. Each such election shall continue in effect during subsequent Plan Years unless the Participant shall give timely notice to the Committee or its delegate of his election to change or discontinue his After-Tax Matched Contribution or his After-Tax Unmatched Contribution in accordance with procedures established from time to time by the Committee. A Participant may change the rate of or discontinue his After-Tax Matched Contribution and/or After-Tax Unmatched Contribution, with no restrictions on frequency, by electronic, telephonic, written or other such manner as may be prescribed from time to time by the Committee. Any such change or discontinuance in the amount of After-Tax Matched or Unmatched Contributions shall be effective as soon as reasonably practicable following receipt by the Committee or its delegate of the change or discontinuance of such election. 4.4 Employer Matching Contributions and Pre-Tax Contributions to be Tax Deductible: Employer Matching Contributions and Pre-Tax Contributions shall not be made in excess of the amount deductible under applicable federal law now or hereafter in effect limiting the allowable deduction for contributions to profit-sharing plans. The Employer Matching Contributions and Pre-Tax Contributions to this Plan, when taken together with all other contributions made by the Employer to other qualified retirement plans, shall not exceed the maximum amount deductible under Section 404 of the Code. 4.5 Maximum Allocations: Notwithstanding the above, the total Annual Additions made to the Account of any Participant shall not exceed the limits prescribed in Section 5.4. 4.6 Refunds to Employer: Once Contributions are made to the Plan by the Employer on behalf of the Participants, they are not refundable to the Employer unless a Contribution: (a) was made by mistake of fact; or (b) was made conditioned upon the contribution being allowed as a deduction and such deduction was disallowed. Any Contribution made by the Employer during any Plan Year in excess of the amount deductible or any Contribution attributable to a good faith mistake of fact shall be refunded to the Employer. The amount which may be returned to the Employer is the excess of the amount contributed over the amount that would have been contributed had there not occurred a mistake of fact or the excess of the amount contributed over the amount deductible, as applicable. A Contribution made by reason of a mistake of fact may be refunded only within one year following the date of payment. Any Contribution to be refunded because it was not deductible under Section 404 of the Code may be refunded only within one year following the date the deduction was disallowed. Earnings attributable to any such excess Contribution may not be withdrawn, but losses attributable thereto must reduce the amount to be returned. In no event -22-
may a refund be due which would cause the Account balance of any Participant to be reduced to less than the Participant's Account balance would have been had the mistaken amount, or the amount determined to be non-deductible, not been contributed. 4.7 Rollover Contributions: Notwithstanding any other provision of the Plan, subject to the terms and conditions set forth in this Section, the Trustee shall be authorized to accept a rollover of an Eligible Rollover Distribution, as defined in Section 6.6, on behalf of or from a person who is (or who will be entitled under Section 3.1 to become) a Participant in the Plan, from an Eligible Retirement Plan, as defined in Section 6.6. Such a transferred distribution is referred to herein as a "Rollover Contribution." The acceptance of Rollover Contributions under this Section shall be subject to the following conditions: (a) No Rollover Contribution shall be in an amount less than $500; (b) Rollover Contributions shall be in cash only; (c) No Rollover Contribution may be transferred to the Plan without the prior approval of the Committee. The Committee shall develop such procedures and may require such information from an Employee desiring to make such a transfer as it deems necessary or desirable. The Committee may act in its sole discretion in determining whether to accept the transfer, and shall act in a uniform, non-discriminatory manner in this regard; (d) Upon approval by the Committee, a Rollover Contribution shall be paid to the Trustee to be held in the Trust Fund; (e) A separate Rollover Account shall be established and maintained for each Employee who has made a Rollover Contribution. A Rollover Account shall share in the earnings and/or losses of the Trust Fund (and component Investment Funds in which such account may be invested) commencing on the Valuation Date coincident with or next following the date on which the transferred amount is placed in the Trust Fund. The Employee's interest in his Rollover Account shall be fully vested and non-forfeitable. If an Employee who is otherwise eligible to participate in the Plan but who has not yet begun participation under Section 3.1 of the Plan makes a Rollover Contribution to the Plan, his Rollover Account shall represent his sole interest in the Plan until he becomes a Participant; and (f) The Committee shall be entitled to rely on the representation of the Employee that the Rollover Contribution is an eligible rollover distribution. If, however, it is determined that a transfer received from or on behalf of an Employee failed to qualify as an eligible rollover distribution within the meaning of Code Section 402(c)(4), then the balance in the Employee's Rollover Account attributable to the ineligible transfer shall, along with any earnings thereon, as soon as is administratively practicable, be: -23-
(1) segregated from all other Plan assets; (2) treated as a non-qualified trust established by and for the benefit of the Participant; and (3) distributed to the Employee. Such an ineligible transfer shall be deemed never to have been a part of the Plan or Trust. -24-
ARTICLE V PARTICIPANT ACCOUNTS 5.1 Trust Accounts: The Committee shall create and maintain adequate records to reflect all transactions of the Trust Fund and to disclose the interest in the Trust Fund of each Participant (whether on active or inactive status), former Participant and Beneficiary. (a) Accounts for Participants: Accounts shall be maintained for a Participant as may be appropriate from time to time to reflect his interest in the Stock Funds and the Investment Funds in which he may be participating at any time, as provided under Section 8.1. The interest in the Investment Funds and the ESOP Company Stock Fund attributable to the Pre-Tax Contributions, After-Tax Contributions, Employer Matching Contributions and Rollover Contributions made by or on behalf of a Participant under the Plan and Prior Plan shall be reflected in a Pre-Tax Contribution Account, After-Tax Contribution Account, Employer Matching Account and Rollover Account for the Participant, respectively. A Prior Plan Account shall be maintained for a Participant, as applicable, as may be appropriate from time to time to reflect his interest in the Stock Funds and the Investment Funds in which he may be participating at any time, as provided under Section 8.1. (b) Rights in Trust Fund: The maintenance of individual Accounts is only for accounting purposes, and a segregation of the assets of the Trust Fund to each Account shall not be required. Distribution and withdrawals made from an Account shall be charged to the Account as of the date paid. 5.2 Valuation of Trust Fund: A valuation of the Trust Fund shall be made as of each Valuation Date. For the purposes of each such valuation, the assets of each Investment Fund and each Stock Fund shall be valued at their respective current market values, and the amount of any obligations for which the Investment Fund or Stock Fund may be liable, as shown on the books of the Trustee, shall be deducted from the total value of the assets. For the purposes of maintenance of books of account in respect of properties comprising the Trust Fund, and of making any such valuation, the Trustee shall account for the transactions of the Trust Fund on an accrual basis. The current market value shall, for the purposes hereof, be determined as follows: (a) Where the properties are securities which are listed on a securities exchange, or which are actively traded over the counter, the value shall be the net asset value, if appropriate, otherwise the last recorded sales price. In the event transactions regarding such property are recorded over more than one such exchange, the Trustee may select the exchange to be used for purposes hereof. Recorded information regarding any such securities published in The Wall Street Journal or any other publication deemed appropriate may be relied upon by the Trustee. If no transactions involving any such securities have been recorded as of a particular Valuation Date, then such securities shall be valued as provided in paragraph (b) below. -25-
(b) Where paragraph (a) hereof shall be inapplicable in the valuation of any properties, the Trustee shall obtain from at least two qualified persons an opinion as to the value of such properties as of the close of business on the particular Valuation Date. The average of such estimates shall be used. 5.3 Allocations to Accounts: (a) Pre-Tax Contributions and After-Tax Contributions: Pre-Tax Contributions and After-Tax Contributions received in the Trust Fund, pursuant to Sections 4.2 and 4.3, shall be allocated and credited as soon as practicable after the close of each applicable payroll period to the respective Pre-Tax Contribution Accounts and After-Tax Contribution Accounts of the Participants, with such Contributions invested in accordance with the Participants' instructions pursuant to Section 8.1 in the Investment Funds and/or the ESOP Company Stock Fund as elected for his Pre-Tax and After-Tax Contributions. (b) Employer Matching Contributions: Employer Matching Contributions, other than discretionary Employer Matching Contributions, received in the Trust Fund, pursuant to Section 4.1, shall be allocated and credited as soon as practicable after the close of each applicable payroll period to such Participants' Employer Matching Accounts in accordance with Section 4.1, with such Contributions invested in accordance with the Participants' instructions pursuant to Section 8.1 in the Investment Funds and/or the ESOP Company Stock Fund as elected for his Employer Matching Contributions. (c) Discretionary Employer Matching Contributions: Discretionary Employer Matching Contributions received in the Trust Fund, pursuant to Section 4.1, shall be allocated and credited as soon as practicable after the end of the applicable Plan Year, but in no event later than the time prescribed by law for the filing of the federal income tax return for the Company for the applicable Plan Year, including any extension which has been granted for the filing of such tax return, to the Employer Matching Accounts of Participants eligible to receive such discretionary contributions in accordance with Section 4.1, with such Contributions invested in accordance with the Participants' instructions pursuant to Section 8.1 in the Investment Funds and/or the ESOP Company Stock Fund as elected for his Employer Matching Contributions. (d) Adjustments: The Accounts of Participants, former Participants and Beneficiaries shall be adjusted in accordance with the following: (i) Earnings of the Investment and Stock Funds: The earnings (or loss) of each Investment Fund and Stock Fund since the preceding Valuation Date (including the appreciation or depreciation in value of the assets of the fund) shall be allocated to the Accounts of Participants (other than a terminated Participant's Accounts which have become current obligations of the Investment Fund) in proportion to the balances in such Accounts invested in -26-
such Investment Fund or Stock Fund on the preceding Valuation Date, but after first reducing each such Account balance by any distribution from such Accounts since the preceding Valuation Date. (ii) Forfeitures: As of each Valuation Date, any previously forfeited Account balances of Participants who have unclaimed benefits, if any, in accordance with Section 6.8, shall be used to reinstate such Accounts, reduce Employer Contributions and/or to pay incident expenses of the Plan. 5.4 Maximum Annual Additions: Notwithstanding anything contained herein to the contrary, the total Annual Additions made to the Account of a Participant for any Plan Year commencing on or after the Effective Date shall be subject to the following limitations: (a) Single Defined Contribution Plan. (i) If an Employer does not maintain any other Code Section 401(a) qualified plan, the amount of Annual Additions which may be allocated under the Plan on a Participant's behalf for a Limitation Year shall not exceed the lesser of the Maximum Permissible Amount or any other limitation contained in this Plan. (ii) Prior to the determination of the Participant's actual Compensation for a Limitation Year, the Maximum Permissible Amount may be determined on the basis of the Participant's estimated annual Compensation for such Limitation Year. Such estimated annual Compensation shall be determined on a reasonable basis and shall be uniformly determined for all Participants similarly situated. Any Employer contributions (including allocation of forfeitures) based on estimated annual Compensation shall be reduced by any Excess Amounts carried over from prior years. (iii) As soon as is administratively feasible after the end of the Limitation Year, the Maximum Permissible Amount for such Limitation Year shall be determined on the basis of the Participant's actual Compensation for such Limitation Year. (iv) If there is an Excess Amount with respect to a Participant for the Limitation Year, such Excess Amount shall be disposed of as follows: -27-
(A) There shall first be returned to the Participant his After-Tax Unmatched Contributions, as defined in Section 4.3, if any, attributable to that Limitation Year to the extent such returned and reduced contributions would reduce the Excess Amount. If any such Excess Amount shall then remain, the Participant's Pre-Tax Unmatched Contributions, as defined in Section 4.2, if any, attributable to that Limitation Year shall be returned to the Participant to the extent such returned contributions would reduce the Excess Amount. If any such Excess Amount shall then remain, the Participant's After-Tax Matched Contributions, as defined in Section 4.3, if any, attributable to that Limitation Year shall be returned to the Participant, and the Employer Matching Contributions made with respect to said After-Tax Matched Contributions shall be reduced and allocated to a suspense account in the manner set forth in paragraph (B) below, both to the extent such returned and reduced contributions would reduce the Excess Amount. If any such Excess Amount shall then remain, the Participant's Pre-Tax Matched Contributions, as defined in Section 4.2, if any, attributable to that Limitation Year shall be returned to the Participant, and the Employer Matching Contributions made with respect to said Pre-Tax Matched Contributions shall be reduced and allocated to a suspense account in the manner set forth in paragraph (B) below, both to the extent such returned and reduced contributions would reduce the Excess Amount. All such amounts shall be adjusted for any income or loss allocated thereon. (B) The amount of the reduction of the Employer Matching Contributions for the Participant shall be reallocated out of the Employer Matching Account of such Participant and shall be held in a suspense account that shall be applied as a part of (and to reduce to such extent what would otherwise be) the Employer Matching Contributions for all Participants required to be made to the Plan during the next subsequent calendar quarter or quarters. No portion of such Excess Amount may be distributed to Participants or former Participants. If a suspense account is in existence at any time during the Limitation Year pursuant to this paragraph (B), such suspense account shall not participate in the allocation of investment gains or losses of the Trust Fund. -28-
(b) Two or More Defined Contribution Plans. (i) If, in addition to this Plan, the Employer maintains any other Code Section 401(a) qualified defined contribution plan, the amount of Annual Additions which may be allocated under this Plan on a Participant's behalf for a Limitation Year shall not exceed the lesser of: (A) the Maximum Permissible Amount, reduced by the sum of any Annual Additions allocated to the Participant's accounts for the same Limitation Year under such other defined contribution plan or plans; or (B) any other limitation contained in the Plan. (ii) Prior to the determination of the Participant's actual Compensation for the Limitation Year, the amount referred to in paragraph (i)(A) above may be determined on the basis of the Participant's estimated annual Compensation for such Limitation Year. Such estimated annual Compensation shall be determined on a reasonable basis and shall be uniformly determined for all Participants similarly situated. Any Employer Contribution (including allocation of forfeitures) based on estimated annual Compensation shall be reduced by any Excess Amounts carried over from prior years. (iii) As soon as is administratively feasible after the end of the Limitation Year, the amounts referred to in paragraph (i)(A) above shall be determined on the basis of the Participant's actual Compensation for such Limitation Year. (iv) If a Participant's Annual Additions under this Plan and all such other defined contribution plans result in an Excess Amount, such Excess Amount shall be deemed to consist of the amounts last allocated. (v) If an Excess Amount was allocated to a Participant on an allocation date of this Plan which coincides with an allocation date of another plan, the Excess Amount attributed to this Plan will be the product of: (A) the total Excess Amount allocated as of such date (including any amount which would have been allocated but for the limitations of Section 415 of the Code); times (B) the ratio of (1) the amount allocated to the Participant as of such date under this Plan, divided by -29-
(2) the total amount allocated as of such date under all qualified defined contribution plans (determined without regard to the limitations of Section 415 of the Code). (vi) Any Excess Amounts attributed to this Plan shall be disposed of as provided in paragraph (a) above. (c) Definitions. For purposes of this Section, the following words and phrases shall have the following meanings: (i) Employer: The Employer that adopts this Plan. In the case of a group of employers which constitutes a controlled group of corporations (as defined in Section 414(b) of the Code as modified by Section 415(h)) or which constitutes trades and businesses (whether or not incorporated) which are under common control (as defined in Section 414(c) as modified by Section 415(h)) or an affiliated service group (as defined in Section 414(m)), all such employers shall be considered a single Employer for purposes of applying the limitations of this Section. (ii) Annual Additions: With respect to each Limitation Year, the total of the Employer Matching Contributions, Pre-Tax Contributions, After-Tax Contributions, forfeitures and amounts described in Sections 415(e)(1) and 419(d)(2) of the Code, which are allocated to the Participant's Account; excluding, however, any amounts contributed to reinstate an amount forfeited or an unclaimed benefit. (iii) Excess Amount: The excess of the Participant's Annual Additions for the Limitation Year over the Maximum Permissible Amount. (iv) Limitation Year: A 12-consecutive-month period ending on December 31. (v) Maximum Permissible Amount: Except to the extent permitted under Section 4.2 with respect to Catch-Up Contributions and Code Section 414(v), if applicable, for a Limitation Year, the Maximum Permissible Amount with respect to any Participant shall be the lesser of: (A) $40,000 (or such other amount as provided in Code Section 415(c), as adjusted by the Secretary of the Treasury or his delegate pursuant to Code Section 415(d) (with such amount adjusted to $42,000 for the 2005 Plan Year); or -30-
(B) 100% of the Participant's Compensation for the Limitation Year. (vi) Compensation: For purposes of applying the limitations of Code Section 415, Compensation shall include the Participant's wages, salaries, fees for professional service and other amounts received (without regard to whether or not an amount is paid in cash) for personal services actually rendered in the course of employment with an Employer maintaining the Plan to the extent that the amounts are includable in gross income (including, but not limited to, commissions paid to salesmen, compensation for services on the basis of a percentage of profits, commissions on insurance premiums, tips, bonuses, fringe benefits, reimbursements and expense allowances) and shall exclude the following: (A) Contributions made by the Employer to a plan of deferred compensation to the extent that, before the application of the Code Section 415 limitations to the Plan, the contributions are not includable in the gross income of the Employee for the taxable year in which contributed, Employer contributions made on behalf of an Employee to a simplified employee pension plan described in Code Section 408(k) to the extent such contributions are excludable from the Employee's gross income, and any distributions from a plan of deferred compensation regardless of whether such amounts are includable in the gross income of the Employee when distributed, except for amounts received by an Employee pursuant to an unfunded non-qualified plan that are includable in the gross income of the Employee; (B) Amounts realized from the exercise of a non-qualified stock option or when restricted stock (or property) held by an Employee either becomes freely transferable or is no longer subject to a substantial risk of forfeiture; (C) Amounts realized from the sale, exchange or other disposition of stock acquired under a qualified stock option; and (D) Other amounts which receive special tax benefits, such as premiums for group life insurance (but only to the extent that the premiums are not includable in the gross income of the Employee), or contributions made by the Employer (whether or not under a salary reduction agreement) towards the purchase of any annuity contract -31-
described in Code Section 403(b) (whether or not the contributions are excludable from the gross income of the Employee). For the purposes of this Section, Compensation shall include any and all items which may be included in compensation under Code Section 415(c)(3), including any elective deferral (as defined in Code Section 402(g)(3)) and any amount which is contributed or deferred by the Employer at the election of the Employee and which is not includable in the gross income of the Employee by reason of Code Section 125, 132(f)(4) or 457, but excluding amounts that would otherwise be excluded from an Employee's gross income by reason of the application of Code Section 402(h)(1)(B) and, in the case of Employer contributions made pursuant to a salary reduction agreement, Code Section 403(b). The foregoing notwithstanding, for purposes of this Section, Compensation shall be limited to $200,000 or such other amount provided under Code Section 401(a)(17), as adjusted for cost-of-living increases in accordance with Code Section 401(a)(17)(B) (with such amount adjusted to $210,000 for the 2005 Plan Year). -32-
ARTICLE VI PARTICIPANTS' BENEFITS 6.1 Vesting: A Participant who is an active Employee and eligible to participate in the Plan on or after the Effective Date shall be 100% and fully vested in the amounts of his Accounts at all times and thus his entire Account balance shall be non-forfeitable at all times. The foregoing notwithstanding, if a Participant's termination of Service occurred prior to the Effective Date, the vesting provisions of the Prior Plan as in effect on such termination of Service date shall govern; provided, however, that if such a Participant is again employed by an Employer or Affiliate on or after the Effective Date, such Participant shall be 100% and fully vested in the amounts in his Accounts as of (and thereafter) such re-employment date (with the reinstatement of forfeited amounts determined as provided in Section 6.8). 6.2 Termination of Service: In the event of termination of Service of a Participant for any reason, including due to death or Disability, such Participant shall, subject to the further provisions of the Plan, be entitled to receive 100% of the values in his Accounts in accordance with Section 6.5. If a Participant satisfies the definition of "Disability" under the Company's long-term disability plan and commences to receive disability benefits thereunder, such Participant shall be entitled to receive the entire amount of his Account as of the date of the Disability in accordance with Section 6.5. The determination of whether a Participant has become "Disabled" under the Company's long-term disability plan by such disability plan's administrator shall be final and binding on all parties concerned. 6.3 Death of Participants: In the event of termination of a Participant's Service due to his death, if a Participant's death occurs prior to filing his election in the form and manner prescribed by the Committee to commence the payment of his benefit under the Plan, after receipt by the Committee of acceptable proof of death, the entire vested amount in the Account of such Participant shall be payable no later than December 31 of the calendar year that contains the fifth anniversary of the Participant's date of death, as follows: (a) The Participant's Account shall be distributed to the Participant's surviving spouse, but if there is no surviving spouse, or if the surviving spouse has previously consented by a qualified election pursuant to Section 6.3(b), to the Beneficiary or Beneficiaries designated by the Participant in the form and manner prescribed by the Committee. If no such designation shall have been so filed, or if no designated Beneficiary survives the Participant or can be located by the Committee, using reasonable diligence, within six months of the Participant's death, then such Participant's Account shall be distributed to the duly appointed and serving personal representative of the Participant's estate, but only if that personal representative can provide the Committee with what the Committee reasonably determines is satisfactory documentary proof of that appointment and of the personal representative's identity (collectively, "Documentary Proof"); if, within six months of the Participant's death, there is no duly appointed and serving personal representative of the Participant's estate who has provided the Committee with Documentary Proof, or if such decedent left no will, then such Participant's Account shall be distributed to the Participant's estate. No -33-
designation of any Beneficiary other than the Participant's surviving spouse shall be effective unless made in the form and manner prescribed by the Committee and received by the Participant's Employer and in no event shall it be effective as of the date prior to such receipt. The former spouse of a Participant shall be treated as a surviving spouse to the extent provided under a qualified domestic relations order as described in Section 414(p) of the Code. (b) The Participant's spouse may waive the right to be the Participant's sole Beneficiary and consent to the Beneficiary designation made by the Participant. The waiver must be in writing and the spouse must acknowledge the effect of the waiver. The spouse's waiver must be witnessed by a Plan representative or a notary public. The Beneficiary designated by the Participant may not be changed without the spouse's consent, unless the consent of the spouse permits designation of Beneficiaries by the Participant without any requirement of further consent by the spouse. The Participant may file a waiver without the spouse's consent if it is established to the satisfaction of the Committee that such written consent may not be obtained because there is no spouse or the spouse may not be located. Any consent under this Section 6.3(b) will be valid only with respect to the spouse who signs the consent. Additionally, a revocation of a prior spousal waiver may be made by a Participant without the consent of the spouse at any time before the distribution of the Account. The number of revocations shall not be limited. 6.4 In-Service Distributions: (a) Distributions of Dividends Payable on Company Stock: A Participant may elect, in such manner and pursuant to such rules and procedures prescribed by the Committee (or its delegate), to have cash dividends paid with respect to shares of Company Stock held in the ESOP Company Stock Fund in which his Account is invested (1) paid in cash to the Participant or (2) paid to the Participant's Account invested in the ESOP Company Stock Fund and reinvested in Company Stock, in accordance with, and subject to, the requirements of Code Section 404(k). Participants shall be provided a reasonable opportunity to change their election at least annually. (b) Other In-Service Distributions: Subject to Section 6.4(a), Section 6.9, Article VII, and Section 10.5 hereof, no distribution or withdrawal of any benefits under the Plan shall be permitted prior to the Participant's "separation from employment, death or disability" within the meaning of Code Section 401(k) and the regulations thereunder other than a distribution authorized under the Plan upon the occurrence of an event described in, and made in accordance with, Code Section 401(k)(10) or any successor provision of the Code. Notwithstanding the foregoing, if there is a transfer of Plan assets and liabilities relating to any portion of a Participant's Account under the Plan to a plan being maintained or created by such Participant's new employer (other than a rollover or elective transfer), then such Participant has not experienced a "severance from employment" for purposes of the Plan. -34-
6.5 Payments of Benefits: Upon a Participant's entitlement to payment of benefits under Section 6.2, he shall file with the Committee or its delegate his election in the form and manner, and subject to such conditions, as the Committee shall prescribe. His election shall specify whether he wishes payment of his benefits to be made or commence as of such entitlement or to be deferred to the extent provided below. If a payment becomes due for any reason other than death or Disability, and if the total amount due from the Participant's Accounts is in excess of $1,000, payment of such amount shall be deferred to the extent provided below unless the Participant consents to earlier payment. Subject to a Participant's election in the form and manner prescribed by the Committee, payment of the Participant's benefit under this Plan shall be made or commence no later than the 60th day after the latest of the end of the Plan Year in which (a) the Participant attains age 65, (b) occurs the tenth anniversary of the year in which the Participant commenced participation in the Plan or (c) the Participant's Service terminates; until the Participant files his election with the Committee or its delegate, in the form and manner prescribed by the Committee, such distribution shall not be made prior to, and shall be deferred, subject to the mandatory distribution requirements in Section 6.9. If the Participant elects an earlier available payment date, such payment shall be made as soon as practicable. Notwithstanding any other provision of this Section or the Plan to the contrary, if the total amount due from the Participant's Accounts does not exceed $1,000, payment of such amounts shall automatically be made in a lump-sum payment as soon as administratively practicable following termination of Service for any reason. In the case of a distribution under Section 6.3 on account of the Participant's death, the Committee shall pay the entire vested amount in the Participant's Accounts to the party or parties entitled thereto under Section 6.3 no later than December 31 of the calendar year that contains the fifth anniversary of the Participant's date of death in a lump-sum distribution (i) in cash or (ii) if timely elected by such party or parties, all or a portion in kind in the shares of Company Stock and/or REI Stock, as applicable, held in an Account invested in the Stock Funds, as applicable. Subject to the requirements of Section 6.9 and except as otherwise provided in this Section, any distribution to be made to a Participant under the provisions of this Article VI following his termination of employment shall be made or commence as soon as administratively practicable after the Participant files his election with the Committee or its delegate, in the form and manner prescribed by the Committee, to receive the amounts in his Accounts. Such amounts shall be paid in one of the following methods, as elected by the Participant: (a) Lump-Sum Distributions: As a lump-sum distribution in cash; provided, however, that no lump-sum distribution may be paid to the Participant unless he has elected such distribution in the form and manner prescribed by the Committee. -35-
(b) Installment Payments: As monthly, quarterly, semi-annual or annual installment payments over a specified term of 10 years or less, as elected by the Participant, in cash ("Installment Payments"); provided, however, that no Installment Payments may be paid to the Participant unless he has elected such payments in the form and manner prescribed by the Committee, with such Installment Payments continuing to the Participant's Beneficiary designated on such election form (or his Beneficiary under the Plan in lieu of a valid election form designation) if the Participant's death occurs during the term of the Installment Payments. After Installment Payments commence, the Participant (or his Beneficiary, as provided above in the event of the Participant's death) shall have the right to elect at any time to convert the remaining balance of his Account to a lump-sum distribution. (c) In-Kind Distributions: As a distribution in kind of the shares of Company Stock and/or REI Stock held in Accounts invested in the applicable Stock Fund. A Participant may elect to receive any whole percentage, up to 100%, of his Accounts invested in a Stock Fund in whole shares of Company Stock and/or REI Stock, as applicable, as either: (1) a lump-sum distribution in whole shares, with any remaining balances in the Stock Fund(s) and the Investment Fund balances distributed in cash as a lump-sum distribution; or (2) Installment Payments in whole shares, with any remaining balances in the Stock Fund(s) and the Investment Fund balances distributed in cash as Installment Payments. If a Participant elects to receive his entire Account balances in the Stock Fund(s) in whole shares of Company Stock and/or REI Stock, as applicable, such Participant shall be entitled to receive a number of whole shares of such stock(s), plus the cash value of any partial shares of such stock(s), necessary to equal the sum of the value in the Stock Fund(s) held in his Accounts as of such Valuation Date. If a Participant elects to receive a percentage which is less than 100% of his Account balances in the Stock Fund(s) in whole shares of the applicable stock, then the result obtained from the preceding formula shall be multiplied by such percentage to obtain the number of whole shares of Company Stock and/or REI Stock, as applicable, and cash for partial shares of such stock(s) to be distributed to such Participant. The foregoing not withstanding, an in-kind distribution may not be paid to the Participant unless he has elected such distribution in the form and manner prescribed by the Committee. (d) Joint and Survivor Annuity: As a Joint and Survivor Annuity solely with respect to the amounts in the Prior Plan Account that represent the Cengas Account of a Minnegasco Participant who, at time of distribution under this Section 6.5, is married or dies before such distribution commences and his spouse survives him until the time such distributions commence. Unless the Participant elects one of the distribution options set forth above in (a) through (c) of this Section 6.5 ("optional forms of benefits"), pursuant to an election in the form and manner prescribed by the Committee, the Participant's benefit provided by assets attributable to his Cengas Account shall be applied to the purchase of a qualified Joint and Survivor Annuity or, if the Participant's death occurs on or before the date payments are to commence, a Qualified Survivor Annuity. The -36-
Committee shall direct the Trustee to purchase an annuity contract based on considerations the Committee in its sole discretion deems appropriate. Once an annuity has been purchased, all benefits due to those assets shall be determined pursuant to the terms of the annuity. In the case of a qualified Joint and Survivor Annuity, the applicable election period is the 90-day period ending on the date Plan distributions commence. Unless the Participant establishes to the satisfaction of the Committee that he has no spouse or his spouse cannot be located, any election in favor of an optional form of benefit must be consented to by the Participant's spouse, with such consent witnessed by a notary public, in order to be valid. The consent will be valid only for the spouse who signs the consent, or in the event of a deemed election, the designated spouse. A Participant may revoke without limit any prior elections of an optional form of payment without the consent of the spouse at any time before the commencement of benefits. If revoked, an optional form cannot be subsequently elected without the spouse's consent as provided above. A Participant may not modify any election consented to by a spouse without the spouse's consent as provided above. A spouse's consent may not be revoked without the written consent of the Participant. In case of a qualified Joint and Survivor Annuity, within a reasonable period prior to the commencement of benefits the Committee shall provide each Participant with a written explanation of (i) the terms and conditions of the qualified Joint and Survivor Annuity; (ii) the Participant's right to make the effect of an election to waive the qualified Joint and Survivor Annuity; (iii) the rights of a Participant's spouse; and (iv) the right to make and the effect of a revocation of a previous election to waive the qualified Joint and Survivor Annuity. All amounts attributable to any excess of the values attributable to the interest in his Accounts that are invested in the Stock Fund(s), over the interest therein provided to be distributed to him in kind, (along with any amounts invested in any Investment Funds), with the exception of the Stock Fund(s), shall be distributed in cash. 6.6 Payment of Distribution Directly to Eligible Retirement Plan: (a) Notwithstanding any provision of the Plan to the contrary that would otherwise limit a Distributee's election under this Section, a Distributee may elect, at the time and in the manner prescribed by the Committee, to have any portion of an Eligible Rollover Distribution paid directly to an Eligible Retirement Plan specified by the Distributee in a Direct Rollover. (b) The terms used in this Section shall have the following meanings: (i) Eligible Rollover Distribution: An Eligible Rollover Distribution is any distribution of all or any portion of the balance to the credit of the Distributee, except that an Eligible Rollover Distribution does not include: any distribution that is one -37-
of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the Distributee or the joint lives (or joint life expectancies) of the Distributee and the Distributee's designated Beneficiary, or for a specified period of 10 years or more; any distribution to the extent that such distribution is required under Section 401(a)(9) of the Code; any hardship distribution made under Section 401(k)(2)(B)(i)(IV) of the Code; and the portion of any distribution that is not includable in gross income (determined without regard to the exclusion for net unrealized appreciation with respect to employer securities). A portion of a distribution shall not fail to be an Eligible Rollover Distribution merely because the portion consists of after-tax contributions that are not includable in gross income; provided, however, that such after-tax portion may be transferred only to (1) an individual retirement account or annuity described in Code Section 408(a) or (b) or (2) a qualified defined contribution plan described in Code Section 401(a) or 403(a) that agrees to separately account for amounts so transferred, including separately accounting for the portion of such distribution which is includable in gross income and the portion of such distribution which is not so includable. (ii) Eligible Retirement Plan: An Eligible Retirement Plan is: (1) an individual retirement account described in Code Section 408(a); (2) an individual retirement annuity described in Code Section 408(b); (3) an annuity plan described in Code Section 403(a); (4) an annuity contract described in Code Section 403(b); (5) a qualified trust described in Code Section 401(a) that is exempt from taxation under Code Section 501(a); or (6) an eligible plan under Code Section 457(b) that is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state and that agrees to separately account for amounts transferred into such plan from the Plan that accepts the Distributee's Eligible Rollover Distribution. The definition of Eligible Retirement Plan shall also apply in the case of a distribution to a surviving spouse, or to a spouse or former spouse who is the alternate payee under a qualified domestic relation order, as defined in Code Section 414(p). (iii) Distributee: A Distributee includes an Employee or former Employee. In addition, the Employee's or former Employee's surviving spouse and the Employee's or former Employee's spouse or former spouse who is the alternate payee under a qualified domestic relations order, as defined in Section 414(p) of the Code, are Distributees with regard to the interest of the spouse or former spouse. -38-
(iv) Direct Rollover: A Direct Rollover is a payment by the Plan to an Eligible Retirement Plan specified by the Distributee. (c) In the event that a Distributee, after receiving the explanation required by Section 402(f) of the Code, does not affirmatively elect a Direct Rollover under this Section, the Distributee shall be deemed to have elected not to have any portion of the Eligible Rollover Distribution paid directly to an Eligible Retirement Plan. (d) Notwithstanding any provisions of this Section to the contrary, a Distributee may not elect a Direct Rollover with respect to Eligible Rollover Distributions under this Plan which are reasonably expected to total less than $200 during any calendar year. 6.7 Participation Rights Determined as of Valuation Date Coinciding with or Preceding Termination of Employment: In the case of any Participant whose employment shall be terminated for any reason, no further credits or charges arising from any source shall be made to the Accounts of any such terminating Participant after the credits or charges made as of the Valuation Date coinciding with or immediately preceding his termination of employment, except for: (a) Pre-Tax Contributions, After-Tax Contributions, and Employer Matching Contributions made subsequent to such Valuation Date; (b) Withdrawals or distributions made subsequent to such Valuation Date; or (c) In the case of a delayed distribution pursuant to a Participant's election as provided in Section 6.5, such subsequent adjustments to the values in the Accounts of such Participant up to the Valuation Date coinciding with or preceding the receipt of the Participant's election for distribution. 6.8 Treatment of Non-Vested Account Balances Upon Termination of Service Prior to May 6, 2002: This Section 6.8 applies only to a Participant (i) who terminated his Service prior to May 6, 2002, and (ii) who was not fully vested at the time of his termination of Service in his Employer Matching Account or Prior Plan Account (a "Prior Plan Non-Vested Participant"). If a Prior Plan Non-Vested Participant receives an actual or deemed distribution under the Plan, then the non-vested portion of his Employer Matching Account and Prior Plan Account shall be forfeited and shall become available for allocation as provided in Section 5.3(d)(ii). If a Prior Plan Non-Vested Participant, who was not fully vested in his Account as of his termination of Service date, does not receive a distribution of his vested benefit, then the non-vested balance in the Prior Plan Non-Vested Participant's Employer Matching Account and Prior Plan Account shall be forfeited and shall become available for allocation as provided in -39-
Section 5.3(d)(ii). However, if such Prior Plan Non-Vested Participant thereafter recommences employment with an Employer and has an Account under the Plan as of his recommencement of employment date, then the previously forfeited amount shall be reinstated to the Participant's Account as of the date he is eligible to recommence participation in the Plan. 6.9 Required Minimum Distributions: (a) General: Notwithstanding any provisions of this Plan to the contrary, for a Participant attaining age 70 1/2, any benefits to which a Participant is entitled shall commence not later than the April 1 following the later of (i) the calendar year in which the Participant attains age 70 1/2 or (ii) the calendar year in which the Participant's employment terminates; provided, however, that clause (ii) of this sentence shall not apply in the case of a Participant who is a 5% owner (as defined in Section 416(i) of the Code) with respect to the Plan Year ending in the calendar year in which such Participant attains age 70 1/2 (such later date the Participant's "Required Beginning Date"). All distributions required under this Section will be made in accordance with the Treasury Regulations under Code Section 401(a)(9). The requirements under Code Section 401(a)(9) will take precedence over any inconsistent provisions of the Plan. (b) Timing and Manner of Distributions: The Participant's entire interest will be distributed, or begin to be distributed, to the Participant no later than the Participant's Required Beginning Date. Upon the death of the Participant, distributions will be made to the Beneficiary in accordance with Section 6.3. (c) Calculation of Required Minimum Distribution: During the Participant's lifetime, the minimum amount that will be distributed for each Distribution Calendar Year is the quotient obtained by dividing the Participant's Account Balance by the distribution period in the Uniform Lifetime Table set forth in Section 1.401(a)(9)-9 of the Treasury Regulations, using the Participant's age as of the Participant's birthday in the Distribution Calendar Year. Required minimum distributions will be determined beginning with the first Distribution Calendar Year and up to and including the Distribution Calendar Year that includes the Participant's date of death. (d) Required Minimum Distributions After or Before Participant's Death: If the Participant dies after or before his Required Beginning Date, his Account balance will be distributed to his Beneficiary as provided in Section 6.3. (e) Definitions: For purposes of this Section 6.9, the following terms shall have the following meanings: (i) Designated Beneficiary: The individual who is designated as the Beneficiary under Section 6.3 and is the "designated beneficiary" under Section 401(a)(9) of the Code and Section 1.401(a)(9)-1, Q&A-4, of the Treasury Regulations. -40-
(ii) Distribution Calendar Year: A calendar year for which a minimum distribution from the Plan is required under Code Section 401(a)(9). For distributions beginning before the Participant's death, the first Distribution Calendar Year is the calendar year immediately preceding the calendar year which contains the Participant's Required Beginning Date. For distributions beginning after the Participant's death, the first Distribution Calendar Year is the calendar year in which distributions are required to begin under this Section. The required minimum distribution for the Participant's first Distribution Calendar Year will be made on or before the Participant's Required Beginning Date. The required minimum distribution for other distribution calendar years, including the required minimum distribution for the Distribution Calendar Year in which the Participant's Required Beginning Date occurs, will be made on or before December 31 of that Distribution Calendar Year. (iii) Participant's Account Balance: The Account balance as of the last Valuation Date in the Valuation Calendar Year increased by the amount of any contributions made and allocated or forfeitures allocated, if any, to the Account balance as of the date in the Valuation Calendar Year after the Valuation Date and decreased by distributions made in the Valuation Calendar Year after the Valuation Date. The Account balance for the Valuation Calendar Year includes any amounts rolled over or transferred to the Plan either in the Valuation Calendar Year or in the Distribution Calendar Year if distributed or transferred in the Valuation Calendar Year. (iv) Valuation Calendar Year: The calendar year immediately preceding the Distribution Calendar Year. 6.10 Unclaimed Benefits: If at, after or during the time when a benefit hereunder is payable to any Participant, Beneficiary or other distributee, the Committee, upon request of the Trustee, or at its own instance, shall mail by registered or certified mail to such distributee, at his last known address, a written demand for his present address or for satisfactory evidence of his continued life, or both, and if such distributee shall fail to furnish the same to the Committee within two years from mailing of such demand, then the Committee may, in its sole discretion, determine that such Participant, Beneficiary or other distributee has forfeited his right to such benefit and may declare such benefit, or any unpaid portion thereof, terminated, as if the death of the distributee (with no surviving Beneficiary) had occurred on the later of the date of the last payment made thereon, or the date such Participant, Beneficiary or other distributee first became entitled to receive benefit payments. Any such forfeited benefit shall be applied as a part of (and to reduce to such extent) the Employer Contributions required to be made next following the date such forfeiture is declared to be forfeited by the Committee. Notwithstanding the provisions of this Section, any such forfeited benefit shall be reinstated if a claim for the same is made by the -41-
Participant, Beneficiary or other distributee at any time thereafter. The reinstatement shall be made by a mandatory contribution by the Company, allocated solely to such reinstatement. 6.11 Optional Forms of Benefits: Notwithstanding anything in the Plan to the contrary, all optional forms of benefits which are "Section 411(d)(6) protected benefits," as described in Treasury Regulations Section 1.411(d)-4, shall continue to be optional forms of benefits for Participants to whom the optional forms apply, notwithstanding any subsequent amendment of the Plan purporting to revise or delete any such optional form of benefit and notwithstanding any contrary provision of this Article VI or Article VII, unless otherwise permitted by applicable law. -42-
ARTICLE VII WITHDRAWALS AND LOANS 7.1 Withdrawal of After-Tax Contributions: Pursuant to advance notice given in the manner prescribed by the Committee from time to time and subject to the conditions of Section 7.4, each Participant may elect to withdraw all or any amounts attributable to his After-Tax Contributions, determined as of the Valuation Date immediately preceding the withdrawal date; provided, however, that, to the extent applicable, a Participant must first withdraw all amounts in his Cengas Account in accordance with Section 7.3 and subject to written consent of his spouse in a manner prescribed by the Committee. Amounts withdrawn under this Section 7.1 shall be charged and withdrawn from a Participant's After-Tax Contribution Account (along with attributable earnings), to the extent applicable, in the following order: (i) After-Tax Unmatched Contributions; and (ii) After-Tax Matched Contributions. 7.2 Withdrawal of Pre-Tax Contributions On and After Age 59 1/2: Pursuant to advance notice given in the manner prescribed by the Committee from time to time and subject to the conditions of Section 7.4, and subject to first withdrawing all amounts that may be available under Sections 7.1 and 7.3, each Participant who is age 59 1/2 or older may elect to withdraw all or any amounts attributable to his Pre-Tax Contributions, determined as of the Valuation Date immediately preceding the withdrawal date. Amounts withdrawn under this Section 7.2 shall be charged and withdrawn from a Participant's Pre-Tax Contribution Account (along with attributable earnings), to the extent applicable, in the following order: (i) Pre-Tax Unmatched Contributions; and (ii) Pre-Tax Matched Contributions. 7.3 Withdrawal From Prior Plan Account and Rollover Account: Pursuant to advance notice given in a manner prescribed by the Committee from time to time and subject to the conditions of Section 7.4, in addition to withdrawals available under Sections 7.1 and 7.2, a Participant, to the extent applicable, may elect to withdraw all or any vested amounts in his Prior Plan Account and his Rollover Account, determined as of the Valuation Date immediately preceding the withdrawal date. Amounts withdrawn under this Section 7.3 shall be charged and withdrawn from a Participant's Accounts (along with attributable earnings), to the extent applicable, in the following order: (i) Cengas Account; (ii) Prior Plan Account (after withdrawal of the Cengas Account); and (iii) Rollover Account. 7.4 Conditions of Withdrawals: Each Participant who is under the age of 59 1/2 and who has less than five years of Service at the time he elects to withdraw all or a portion of his After-Tax Matched Contributions shall be suspended from participation in the Plan from the Valuation Date preceding the distribution of the withdrawal until the date following six full months from the date of such withdrawal, provided the Committee or its agent has received prior to such date the Participant's election (in the form and manner prescribed in Section 3.3 hereof) to commence participation after such suspension. Subject to the conditions under this Section 7.4 and under Sections 7.1, 7.2 and 7.3, as applicable, there shall be no limit on the number of withdrawals a Participant may make from his Pre-Tax Contribution Account, After-Tax Contribution Account, Prior Plan Account and Rollover Account within any 12-month period; provided, however, that the minimum amount that a Participant is permitted to withdraw -43-
shall be the lesser of $500 or the entire balance of his Accounts. Except as provided in Section 7.5 and under Article VI, no withdrawals shall be permitted from a Participant's Employer Matching Account. Notwithstanding any provision in this Article VII to the contrary, to the extent any amounts attributable to a Participant's Account or Accounts collateralizes a loan under Section 7.5, such collateralized amounts shall not be eligible for withdrawal under this Article VII. 7.5 Loans: Any Participant who is an Employee (including any such Participant on an Authorized Absence) may make application to borrow from his vested Accounts in the Trust Fund. In addition to Participants who are Employees (including any such Participant on an Authorized Absence), loans shall be available to any former Participant or any Beneficiary or "alternate payee" with respect to a former Participant, but, if and only if, such person is a "party in interest" with respect to the Plan within the meaning of ERISA Section 3(14) and who must be eligible to obtain a Plan loan in order for exemptions set forth in Department of Labor Regulation Section 2550.408b-1 to apply to the Plan (herein, together with Participants who are Employees and those on Authorized Absence, collectively referred to as "Borrower"). Upon receipt of a loan application from a Borrower, the Committee may in its discretion direct the Trustee to make a loan to such Borrower. Such loans shall be granted in a uniform and non-discriminatory manner pursuant to the terms and conditions of a written loan procedure that shall be established by the Committee and subject to amendment from time to time and at any time by the Committee, with such written procedure hereby incorporated by reference as a part of the Plan. The amount of the loan, when added to the amount of any outstanding loan or loans to the Borrower from any other plan of the Employer or an Affiliate which is qualified under Code Section 401(a), shall not exceed the lesser of (i) $50,000, reduced by the excess, if any, of the highest outstanding balance of loans from all such plans during the one-year period ending on the day before the date on which such loan was made over the outstanding balance of loans from the Plan on the date on which such loan was made or (ii) 50% of the present value of Borrower's vested Account balances under the Plan. The foregoing notwithstanding, any withdrawal from a Participant's Cengas Account shall be subject to the written consent of his spouse in a manner prescribed by the Committee. With respect to clause (i) above, the available loan balance will also be reduced by the amount of any prior loan that is deemed distributed under Code Section 72(p) and that has not been repaid (such as by a plan loan offset). -44-
ARTICLE VIII INVESTMENT DIRECTIONS 8.1 Investment of Trust Fund: Except as provided in Article VII with respect to Plan loans and as otherwise provided below, the Trustee shall divide the Trust Fund into the ESOP Company Stock Fund, REI Stock Fund and the Investment Funds as may be selected from time to time by the Committee, in accordance with the directions of the Participant and following such rules and procedures prescribed by the Committee. The Committee from time to time may revise the number and type of Investment Funds. The ESOP Company Stock Fund and REI Stock Fund may not be revised or terminated, nor may investment in either fund be restricted or limited, except by the Board, in its sole discretion. Subject to such rules and procedures adopted by the Committee, each Participant shall have the right, by electronic, telephonic, written or other such manner as may be prescribed from time to time by the Committee, subject to any restrictions or conditions that may be established by the Committee, to direct the Committee, or any agent appointed by the Committee to administer the investment of the Trust Fund, to instruct the Trustee to invest the amounts in his Pre-Tax Contribution Account, After-Tax Contribution Account, Employer Matching Account, Prior Plan Account, and Rollover Account, in any whole percentages totaling 100% among the Investment Funds and the ESOP Company Stock Fund. The REI Stock Fund is a "frozen" fund and thus a Participant shall not be permitted to direct the investment of the amounts in any Account into the REI Stock Fund. To the extent applicable, each Participant may, by electronic, telephonic, written or other such manner as may be prescribed from time to time by the Committee and subject to any restrictions or conditions (including, but not limited to, trading frequency restrictions and redemption fees) that may be established by the Committee from time to time and communicated to each Participant, direct (1) the investment of his future After-Tax Contributions, Pre-Tax Contributions, Employer Matching Contributions and Rollover Contributions; and (2) the transfer of the current values in his After-Tax Contribution Account, Pre-Tax Contribution Account, Prior Plan Account, Employer Matching Account, and Rollover Account among the various Investment Funds and the ESOP Company Stock Fund in any whole percentages totaling 100%. A Participant shall not be permitted to direct the investment of any Contributions into the REI Stock Fund. Any such change in the Investment Funds and/or ESOP Company Stock Fund shall be effective as soon as reasonably practicable following receipt of the election directing such change, but in no event shall such change be effective earlier than the close of business on the Valuation Date on which such change is received. If a Participant fails to make a proper designation, then his Account shall be invested as soon as administratively feasible in the Stable Value Fund. Notwithstanding any provision of this Section 8.1 or any other provision of the Plan to the contrary, investment in the ESOP Company Stock Fund or REI Stock Fund may not be restricted or limited except by the Board, in its sole discretion. Except as otherwise expressly provided herein and subject to Section 6.5, interest, dividends and other income and all profits and gains produced by each Investment Fund and Stock Fund shall be paid in such Investment Fund and Stock Fund, as applicable, and such interest, dividends and other income, and profits or gains without distinction between principal -45-
and income, shall be invested and reinvested, but only in property of the class hereinabove specified for the particular Investment Fund or Stock Fund, as applicable. All purchases of Company Stock under the ESOP Company Stock Fund shall be made at prices which, in the judgment of the Trustee, do not exceed the fair market value of such Company Stock. Any dividends received in the REI Stock Fund shall be reinvested in the Investment Funds and ESOP Company Stock Fund in accordance with the Participants' investment elections then in effect. Pending such investment or application of cash, the Trustee may retain cash uninvested without liability for interest if it is prudent to do so, or may invest all or any part thereof in Treasury Bills, commercial paper, or like holdings. It is hereby explicitly provided and expressly acknowledged that up to 100% of the assets of the Plan held in the Trust Fund may be invested in Company Stock, as contemplated by the exception provided in Section 407(b) of ERISA. Moreover, it is intended that the Plan meet the requirements of Section 404(c) of ERISA. 8.2 ESOP Company Stock Fund: (a) General: The ESOP Company Stock Fund is intended to be an employee stock ownership plan within the meaning of Section 4975(e)(7) of the Code and is intended to satisfy the applicable requirements under Sections 409 and 4795 of the Code. A Participant may direct the Trustee to invest his Contributions and the amounts in his Investment Funds into the ESOP Company Stock Fund, subject to the provisions of this Article VIII. (b) Diversification: To the extent the Participant is not otherwise permitted to diversify the amounts in his Accounts invested in the ESOP Company Stock Fund, each Qualified Participant (as defined herein) may elect, within 90 days after the close of each Plan Year in the initial election period (as defined herein), to direct the investment of up to 25% of the sum of the balances in his ESOP Company Stock Fund Account into any or all of the Investment Funds and such diversification shall be made no later than as required under Code Section 401(a)(28). In the Plan Year after the initial election period, the percentage shall be 50% instead of 25%. A Qualified Participant is any Participant who has completed at least 10 years of participation in the Plan and who has attained age 55. The initial election period means the five Plan Year period beginning with the first Plan Year on or after January 1, 1992 in which the Participant first became a qualified Participant. 8.3 Voting of Company Stock; Exercise of Other Rights: (a) Voting rights with respect to shares of Company Stock in the ESOP Company Stock Fund allocated to the Accounts of Participants shall be voted by the Trustee in such manner as may be directed by the respective Participants, with fractional shares being voted on a combined basis to the extent possible to reflect the direction of the voting Participants. The Trustee shall vote shares of Company Stock for which the Trustee has not received direction, in the same proportion as directed shares are voted, giving effect to all affirmative -46-
directions by Participants, including directions to vote for or against, to abstain or to withhold the vote, and the Trustee shall have no discretion in such matter. (b) In the event that there is a tender offer or exchange offer for outstanding shares of Company Stock, rights with respect to the tender offer or exchange offer shall be the same as with respect to voting rights described in Section 8.3(a) above. If the Trustee shall not receive timely instruction from a Participant as to the manner in which to respond to such a tender offer, the Trustee shall not tender or exchange any shares of Company Stock with respect to which such Participant has the right to direct, and the Trustee shall have no discretion in such matter. (c) Solicitation of exercise of Participants' voting rights by management of the Company and others under a proxy or consent provision applicable to all holders of Company Stock shall be permitted. Solicitation of exercise of Participant tender or exchange offer rights by management of the Company and others shall be permitted. The Trustee shall notify Participants of each occasion of the exercise of voting rights or rights with respect to a tender offer or exchange offer within a reasonable time before such rights are to be exercised. Such notification shall include all information distributed to shareholders by the Company regarding the exercise of such rights. Copies of Company-written communications to Participants relating to each opportunity for Participant exercise of rights under this Section 8.3 shall be promptly furnished to the Trustee. The instructions received by the Trustee from Participants shall be held by the Trustee in confidence and shall not be divulged or released to any person, including the Committee or officers or employees of the Company or its Affiliates. -47-
ARTICLE IX TRUST AGREEMENT AND TRUST FUND 9.1 Trust Agreement: As part of the Plan, the Company has entered into the Trust Agreement with the Trustee. The provisions of such Trust Agreement are herein incorporated by reference as fully as if set out herein, and the assets held under said Trust Agreement on behalf of this Plan shall constitute the Trust Fund. 9.2 Benefits Paid Solely From Trust Fund: All of the benefits provided to be paid under Article VI hereof shall be paid by the Trustee out of the Trust Fund to be administered under such Trust Agreement. Neither the Employer nor the Trustee shall be responsible or liable in any manner for payment of any such benefits, and all Participants hereunder shall look solely to such Trust Fund and to the adequacy thereof for the payment of any such benefits of any nature or kind which may at any time be payable hereunder. 9.3 Committee Directions to Trustee: Except as otherwise provided in Section 2.7 hereof, the Trustee shall make only such payments out of the Trust Fund as may be directed by the Committee. The Trustee shall not be required to determine or make any investigation to determine the identity or mailing address of any person entitled to any payments out of the Trust Fund and shall have discharged its obligation in that respect when it shall have sent checks or other papers by ordinary mail to such persons and addresses as may be certified to it by the Committee. 9.4 Trustee's Reliance on Committee Instructions: In any case where the Trustee shall be required hereunder to act upon instructions to be received from the Committee, the Trustee shall be protected in relying on any such instructions which shall be in writing and signed by any member of, or Secretary of, the Committee, and the Trustee shall be protected in relying upon the authority to act of any person certified to it by the Company as a member of, or Secretary of, the Committee until a successor to any such person shall be certified to the Trustee by the Company. 9.5 Authority of Trustee in Absence of Instructions From the Committee: If at any time the Committee shall be incapable for any reason of giving any directions, instructions or authorizations to the Trustee as are herein provided for and as may be required incidental to the administration of this Plan, the Trustee may act and shall be completely protected and without liability in so acting without such directions, instructions and authorizations as it in its sole discretion deems appropriate and advisable under the circumstances for the carrying out of the provisions of this Plan. In the event of termination of this Plan for any reason, the Committee shall be authorized to give all such instructions to the Trustee, and the Trustee shall be protected in relying on all such instructions, as may be necessary to make payment to any persons then interested in the Trust Fund of all such amounts as are specified herein to be paid under Section 10.5 hereof upon the termination of this Plan and the Trust Agreement. -48-
9.6 Compliance with Exchange Act Rule 10(b)(18): At any time that the Trustee makes open market purchases of Company Stock, the Trustee will either (i) be an "agent independent of the issuer," as that term is defined in Rule 10(b)(18) promulgated pursuant to the Securities and Exchange Act of 1934, as amended (the "Exchange Act"), or (ii) make such open market purchases in accordance with the provisions, and subject to the restrictions, of Rule 10(b)(18) of the Exchange Act. -49-
ARTICLE X ADOPTING EMPLOYERS, AMENDMENT AND TERMINATION OF THE PLAN, AND DISCONTINUANCE OF CONTRIBUTIONS TO THE TRUST FUND 10.1 Adoption by Employers: Provided it is otherwise eligible by law to participate, the board of directors or non-corporate counterpart of an entity or organization may elect, with such election evidenced by a written instrument authorized by such board of directors or non-corporate counterpart, to participate in the Plan and the Trust as an adopting Employer, subject to the approval of the Board. Such written instrument (i) shall specify the effective date of such participation and, if applicable, the classification of the Employer's Employees who shall be eligible to participate in the Plan, (ii) may incorporate specific provisions relating to the operation of the Plan that apply solely to the adopting Employer and (iii) shall become, as to such Employer and its Employees, a part of the Plan. Each adopting Employer shall be bound by the terms of the Plan and any and all amendments thereto; provided, however, that the terms of the Plan may be modified by the Board so as to increase the obligations of an Employer only with the consent of such Employer, which consent shall be conclusively presumed to have been given by such Employer upon its submission of any information to the Company required by the terms of, or with respect to, the Plan or upon making a contribution to the Trust Fund pursuant to the terms of the Plan following such modification. All adopting Employers shall be set forth on Exhibit A to the Plan, as amended by the Board pursuant to Section 10.3 from time to time as necessary to reflect the addition and/or deletion of adopting Employers. For purposes of the Code and ERISA, the Plan as adopted by the Employers shall constitute a single plan rather than a separate plan of each Employer. All assets in the Trust Fund shall be available to pay benefits to all Participants and their beneficiaries. The provisions of the Plan shall apply separately and equally to each Employer and its Employees in the same manner as is expressly provided for the Company and its Employees, except that the power to appoint or otherwise affect the Committee or the Trustee and the power to amend or terminate the Plan and Trust Agreement shall be exercised solely by the Board. The Board may, in its discretion, terminate an Employer's Plan participation at any time without the consent or approval of such Employer. Any Employer may, by appropriate action of its board of directors or non-corporate counterpart, terminate its participation in the Plan. Upon an Employer's liquidation, bankruptcy, insolvency, sale, consolidation or merger to or with another organization that is not an Employer hereunder, in which such Employer is not the surviving company, all obligations of that Employer hereunder and under the Trust Agreement shall terminate automatically, and the Trust Fund assets attributable to the Employees of such Employer shall be held or distributed as herein provided unless, with the approval of the Board, the successor to that Employer assumes the duties and responsibilities of such Employer, by adopting this Plan and the Trust Agreement, or by establishment of a separate plan and trust to which the assets of the Trust Fund held on behalf of the Employees of such Employer shall be transferred with the consent and agreement of that Employer. Upon the consolidation or merger of two or more of the Employers under this Plan with each other, the surviving Employer or organization shall automatically succeed to all the rights and duties under the Plan and Trust Agreement of the Employers involved. 50
10.2 Continuous Service: The following special provisions shall apply to all Employers: (a) An Employee shall be considered in continuous Service while regularly employed simultaneously or successively by one or more Employers; and (b) The transfer of a Participant from one Employer to another Employer shall not be deemed a termination of Service. 10.3 Amendment of the Plan: Except as otherwise expressly provided in this Section, the Board shall have the right to amend or modify this Plan and the Trust Agreement (with the consent of the Trustee, if required) at any time and from time to time to the extent that it may deem advisable. The Board alone shall have the sole and exclusive right and power to (i) amend, modify, restrict or limit investment in, or terminate the ESOP Company Stock Fund and the REI Stock Fund and (ii) amend, modify or terminate any provision of the Plan or Trust Agreement related to the administration of the ESOP Company Stock Fund and REI Stock Fund. The Committee, whose members shall be acting in their settlor capacity as employees and officers of the Company rather than in their fiduciary capacity, shall have the limited right to amend or modify this Plan and the Trust Agreement (with the consent of the Trustee, if required) (i) to select and remove Investment Funds offered under the Plan as provided in Article VIII, (ii) as required to comply with changes to applicable laws and (iii) as required by the Internal Revenue Service to maintain the qualified status of the Plan and Trust. Any such amendment or modification shall be set out in an instrument in writing duly authorized by the Board and executed by an appropriate officer of the Company or, if applicable, by the Committee and executed by a member of the Committee. The Plan shall be deemed to have been amended or modified in such manner and to such extent and effective as of the date therein provided, and thereupon any and all Participants, whether or not they shall have become such prior to such amendment or modification, shall be bound thereby. No such amendment or modification shall, however, increase the duties or responsibilities of the Trustee without its consent thereto in writing, or have the effect of transferring to or vesting in any Employer any interest or ownership in any properties of the Trust Fund, or of permitting the same to be used for or diverted to purposes other than for the exclusive benefit of the Participants and their Beneficiaries. No such amendment shall decrease the Account of any Participant or shall decrease any Participant's vested interest in his Account. No amendment shall directly or indirectly reduce a Participant's non-forfeitable vested percentage in his benefits under Section 6.1 of this Plan, unless each Participant having not less than three years of Service is permitted to elect to have his non-forfeitable vested percentage in his benefits computed under the provisions of Section 6.1 without regard to the amendment. Such election shall be available during an election period, which shall begin on the date such amendment is adopted, and shall end on the latest of (i) the date 60 days after such amendment is adopted, (ii) the date 60 days after such amendment is effective, or (iii) the date 60 days after such Participant is issued written notice of the amendment by the Employer or, if applicable, by the Committee. Notwithstanding anything herein to the contrary, the Plan or the Trust Agreement may be amended in such manner as may be required at any time to make it conform to the requirements of the Code or of any United States statutes with respect to employees' trusts, or of any amendment thereto, or of any regulations or rulings issued 51
pursuant thereto, and no such amendment shall be considered prejudicial to any then existing rights of any Participant or his Beneficiary under the Plan. 10.4 Termination of the Plan: The Plan may be terminated pursuant to the provisions of, and as of any subsequent date specified in, an instrument in writing executed by the Company, and approved and authorized by the Board, and which said instrument shall be delivered to the Trustee. 10.5 Distribution of Trust Fund on Termination: In the event of a termination of the Plan by the Board, the assets and properties of the Trust Fund shall be valued and allocated as provided in Sections 5.2 and 5.3, and each Participant shall be fully vested in all amounts attributable to his Accounts and, thereafter, each such Participant shall become entitled to distributions in respect of his Accounts in the Plan in the manner as provided in Section 6.5 herein, provided that no Employer or Affiliate then establishes or maintains another defined contribution plan (other than an employee stock ownership plan within the meaning of Code Section 4975(e)(7) or Code Section 409 or a simplified employee pension within the meaning of Code Section 408(k)). 10.6 Effect of Discontinuance of Contributions: If the Company shall discontinue its Contributions to the Trust Fund, or suspend its Contributions to the Trust Fund under such circumstances so as to constitute a discontinuance of Contributions within the purview of the reasoning of Treasury Regulation Section 1.401-6(c), then all amounts theretofore credited to the Accounts of the Participants shall become fully vested, and throughout any such period of discontinuance of Contributions, all other provisions of the Plan shall continue in full force and effect other than the provisions for Contributions by an Employer or Participants. 10.7 Merger of Plan with Another Plan: In the case of any merger or consolidation of the Plan with, or transfer in whole or in part of the assets and liabilities of the Trust Fund to another trust fund held under, any other plan of deferred compensation maintained or to be established for the benefit of all or some of the Participants of this Plan, the assets of the Trust Fund applicable to such Participants shall be transferred to the other trust fund only if: (a) Each Participant would (if either this Plan or the other plan then terminated) receive a benefit immediately after the merger, consolidation or transfer which is equal to or greater than the benefit he would have been entitled to receive immediately before the merger, consolidation or transfer (if this Plan had then terminated); (b) Resolutions of the board of directors of the Employer under this Plan, and of any new or successor employer of the affected Participants, shall authorize such transfer of assets; and, in the case of the new or successor employer of the affected Participants, its resolutions shall include an assumption of liabilities with respect to such Participants' inclusion in the new employer's plan; and (c) Such other plan and trust are qualified under Sections 401(a) and 501(a) of the Code. 52
ARTICLE XI TOP-HEAVY PLAN REQUIREMENTS 11.1 General Rule: For any Plan Year for which the Plan is a Top-Heavy Plan, as defined in Section 11.7, despite any other provisions of the Plan to the contrary, the Plan shall be subject to the provisions of this Article. 11.2 Vesting Provisions: Each Participant who has completed an "hour of service" (within the meaning of Department of Labor Regulation Section 2530.200b-2(a)(1)) after the Plan becomes top-heavy and while the Plan is top-heavy and who has completed the vesting service specified in the following table shall be vested in his Account under the Plan at least as rapidly as is provided in the following schedule; except that the vesting provision set forth in Section 6.1 shall be used at any time in which it provides for more rapid vesting: Years of Vesting Service Vested Percent - ------------------------ -------------- Less than 1 year 0% 1 10% 2 20% 3 45% 4 70% 5 or more 100% If an Account becomes vested by reason of the application of the preceding schedule, it may not thereafter be forfeited by reason of reemployment after retirement pursuant to a suspension of benefits provision, by reason of withdrawal of any mandatory employee contributions to which Employer Contributions were keyed or for any other reason. If the Plan subsequently ceases to be top-heavy, the preceding schedule shall continue to apply with respect to any Participant who had at least three years of service (as defined in Treasury Regulation Section 1.411(a)-8T(b)(3)) as of the close of the last year that the Plan was top-heavy, except that each Participant whose vested percentage in his Account is determined under such amended schedule and who has completed at least three years of service with the Employer, may elect, during the election period, to have the vested percentage in his Account determined without regard to such amendment if his vested percentage under the Plan as amended is, at any time, less than such percentage determined without regard to such amendment. For all other Participants, the vested percentage of their Accounts prior to the date the Plan ceases to be top-heavy shall not be reduced, but future increases in the vested percentage shall be made only in accordance with the vesting provision set forth in Section 6.1. 11.3 Minimum Contribution Percentage: Each Participant who is (i) a Non-Key Employee, as defined in Section 11.7, and (ii) employed on the last day of the Plan Year shall be entitled to have contributions and forfeitures (if applicable) allocated to his Account of not less than 3% (the "Minimum Contribution Percentage") of the Participant's Compensation. This minimum allocation percentage shall be provided without taking a Non-Key Employee's Pre-Tax Contributions into account. Even a Non-Key Employee who has completed less than 1,000 hours of service shall receive a Minimum Contribution Percentage, provided that such Non-Key Employee has not terminated Service by the last day of the Plan Year. A Non-Key Employee may not fail to receive a Minimum Contribution Percentage because of a failure to receive a 53
specified minimum amount of compensation or a failure to make mandatory employee or elective contributions. This Minimum Contribution Percentage will be reduced for any Plan Year to the percentage at which contributions (including pre-tax contributions and forfeitures, if applicable) are made or are required to be made under the Plan for the Plan Year for the Key Employee for whom such percentage is the highest for such Plan Year. For this purpose, the percentage with respect to a Key Employee will be determined by dividing the Contributions (including Pre-Tax Contributions and forfeitures if applicable) made for such Key Employee by his total compensation (as defined in Section 415(c)(3) of the Code) not in excess of $200,000 for the Plan Year, with such amount automatically adjusted in the same manner as the amount set forth in Section 11.4 below (with such amount adjusted to $210,000 for the 2005 Plan Year). Contributions considered under the first paragraph of this Section shall include Employer Contributions under the Plan and under all other defined contribution plans required to be included in an Aggregation Group (as defined in Section 11.7), but will not include Employer Contributions under any plan required to be included in such aggregation group if the plan enables a defined benefit plan required to be included in such group to meet the requirements of the Code prohibiting discrimination as to contributions in favor of employees who are officers, shareholders, or the highly compensated or prescribing the minimum participation standards. If the highest rate allocated to a Key Employee for a year in which the Plan is top heavy is less than 3%, amounts contributed as a result of a salary reduction agreement must be included in determining Contributions made on behalf of Key Employees. Employer Matching Contributions shall be taken into account for purposes of satisfying the Minimum Contribution Percentage of this Section. The preceding sentence shall apply with respect to matching contributions under the Plan or, if the Plan provides that the Minimum Contribution Percentage shall be met in another plan, such other plan. Employer Matching Contributions that are used to satisfy the Minimum Contribution Percentage shall be treated as matching contributions for purposes of the actual contribution percentage test and other requirements of Section 401(m) of the Code. Contributions considered under this Section shall not include any contributions under the Social Security Act or any other federal or state law. 11.4 Limitation on Compensation: The annual compensation of a Participant taken into account under this Article for purposes of computing benefits under the Plan shall not exceed $200,000, with such amount adjusted automatically for each Plan Year to the amount prescribed by the Secretary of the Treasury or his delegate pursuant to Section 401(a)(17)(B) of the Code and regulations for the calendar year in which such Plan Year commences (with such amount adjusted to $210,000 for the 2005 Plan Year). 11.5 Coordination With Other Plans: In the event that another defined contribution or defined benefit plan maintained by a Considered Company provides contributions or benefits on behalf of Participants in the Plan, such other plan shall be treated as a part of the Plan pursuant to principles prescribed by applicable Treasury Regulations or Internal Revenue Service rulings to determine whether the Plan satisfies the requirements of Sections 11.2, 11.3 and 11.4, and to avoid inappropriate omissions or inappropriate duplication. If a Participant is covered both by a top-heavy defined benefit plan and a top-heavy defined contribution plan, a comparability analysis (as prescribed by Revenue Ruling 81-202 or any successor ruling) shall be performed in order to establish that the plans are providing benefits at least equal to the defined benefit 54
minimum. Such determination shall be made upon the advice of counsel by the Committee, which shall, if necessary, cause benefits or contributions to be made sufficient. 11.6 Distributions to Certain Key Employees: Notwithstanding any other provision of the Plan to the contrary, the entire interest in the Plan of each Participant who is a Key Employee and a "5% Owner" (as defined in Section 11.7(d)) in the calendar year in which such individual attains age 70 1/2 shall be distributed to such Participant not later than April 1 following the calendar year in which such individual attains age 70 1/2. 11.7 Determination of Top-Heavy Status: The Plan shall be a Top-Heavy Plan for any Plan Year if, as of the Determination Date, the aggregate of the accounts under the Plan (determined as of the Valuation Date) for Participants (including former Participants) who are Key Employees exceeds 60% of the aggregate of the accounts of all Participants, excluding former Key Employees, or if the Plan is required to be in an Aggregation Group, any such Plan Year in which such Group is a Top-Heavy Group. In determining Top-Heavy status, if an individual has not performed one hour of service for any Considered Company at any time during the 1-year period ending on the Determination Date, any accrued benefit for such individual and the aggregate accounts of such individual shall not be taken into account. For purposes of this Section, the capitalized words have the following meanings: (a) "Aggregation Group" means the group of plans, if any, that includes both the group of plans required to be aggregated and the group of plans permitted to be aggregated. The group of plans required to be aggregated (the "required aggregation group") includes: (i) Each plan of a Considered Company in which a Key Employee is a participant in the Plan Year containing the Determination Date; and (ii) Each other plan, including collectively bargained plans, of a Considered Company which, during this period, enables a plan in which a Key Employee is a participant to meet the requirements of Section 401(a)(4) or 410 of the Code. The group of plans that are permitted to be aggregated (the "permissive aggregation group") includes the required aggregation group plus one or more plans of a Considered Company that is not part of the required aggregation group and that the Considered Company certifies as a plan within the permissive aggregation group. Such plan or plans may be added to the permissive aggregation group only if, after the addition, the aggregation group as a whole continues to satisfy the requirements of Sections 401(a)(4) and 410 of the Code. (b) "Considered Company" means the Company, the Employer or an Affiliate. (c) "Determination Date" means the last day of the immediately preceding Plan Year. 55
(d) "Key Employee" means any Employee or former Employee (including any deceased Employee) under the Plan who, at any time during the Plan Year that includes the Determination Date, is or was one of the following: (i) An officer of a Considered Company having an annual compensation greater than $130,000 (as adjusted under Section 416(i)(1) of the Code); (ii) A person who owns (or is considered as owning, within the meaning of the constructive ownership rules of Section 416(i)(1)(B)(iii) of the Code) more than 5% of the outstanding stock of a Considered Company or stock possessing more than 5% of the combined voting power of all stock of the Considered Company (a "5% Owner"); or (iii) A person who has an annual compensation from the Considered Company of more than $150,000 and who owns (or is considered as owning within the meaning of the constructive ownership rules of Section 416(i)(1)(B) of the Code) more than 1% of the outstanding stock of the Considered Company or stock possessing more than 1% of the total combined voting power of all stock of the Considered Company (a "1% Owner"). For purposes of this subsection (d), (i) whether an individual is an officer shall be determined by the Considered Company on the basis of all the facts and circumstances, such as an individual's authority, duties, and term of office, not on the mere fact that the individual has the title of an officer, (ii) for any Plan Year, no more than 50 Employees (or if less, the greater of 3 or 10% of the Employees) shall be treated as officers, (iii) a Beneficiary of a Key Employee shall be treated as a Key Employee; (iv) in the case of a 5% or 1% Owner determination, each Considered Company is treated separately in determining ownership percentages, but all such Considered Companies shall be considered a single employer in determining the amount of compensation, and (v) compensation means all items includable as compensation for purpose of applying the limitations on annual additions to a Participant's account in a defined contribution plan and the maximum benefit payable under a defined benefit plan under Section 415(c)(3) of the Code. The determination of who is a Key Employee shall be made in accordance with Section 416(i)(1) of the Code and the applicable regulations and other guidance of general applicability issued thereunder. (e) "Non-Key Employee" means any Employee (and any Beneficiary of an Employee) who is not a Key Employee. In any case where an individual is a Non-Key Employee with respect to an applicable plan but was a Key Employee with respect to such plan for any prior Plan Year, any accrued benefit and any account of such Employee shall be altogether disregarded. 56
(f) "Top-Heavy Group" means the Aggregation Group if, as of the applicable Determination Date, the sum of the present value of the cumulative accrued benefits for Key Employees under all defined benefit plans included in the Aggregation Group plus the aggregate of the accounts of Key Employees under all defined contribution plans included in the Aggregation Group exceeds 60% of the sum of the present value of the cumulative accrued benefits for all employees (excluding former Key Employees), as provided in paragraph (i) below, under all such defined benefit plans plus the aggregate accounts for all employees (excluding former Key Employees), as provided in paragraph (i) below, under all such defined contribution plans. In determining Top-Heavy status, if an individual has not performed one hour of service for any Considered Company at any time during the 1-year period ending on the Determination Date, any accrued benefit for such individual and the aggregate accounts of such individual shall not be taken into account. If the Aggregation Group that is a Top-Heavy Group is a required aggregation group, each plan in the group will be a Top-Heavy Plan. If the Aggregation Group that is a Top-Heavy Group is a permissive aggregation group, only those plans that are part of the required aggregation group will be treated as Top-Heavy Plans. If the Aggregation Group is not a Top-Heavy Group, no plan within such group will be a Top-Heavy Plan. In determining whether the Plan constitutes a Top-Heavy Plan, the Committee (or its agent) will make the following adjustments: (i) When more than one plan is aggregated, the Committee shall determine separately for each plan as of each plan's Determination Date the present value of the accrued benefits (for this purpose using the actuarial assumptions set forth in the applicable plan or account balance) or account balance, including distributions to Key Employees and all employees. The results shall then be aggregated by adding the results of each plan as of the Determination Dates for such plans that fall within the same calendar year. The combined results shall indicate whether or not the plans so aggregated are Top-Heavy Plans. (ii) In determining the present value of the cumulative accrued benefit (for this purpose using the actuarial assumptions set forth in the applicable pension plan) or the amount of the account of any employee, such present value or account balance shall be increased by the amount in dollar value of the aggregate distributions made with respect to the employee under the Plan and any plan aggregated with the Plan under Section 416(g)(2) of the Code during the 1-year period ending on the Determination Date. The preceding sentence shall also apply to distributions under a terminated plan which, had it not been terminated, would have been aggregated with the Plan under Section 416(g)(2)(A)(i) of the Code. In the case of a distribution made for a reason other than separation from service, death, or disability, this provision shall be applied by substituting "5-year period" for "1-year period." The amounts will include distributions to employees representing the 57
entire amount credited to their accounts under the applicable plan. The accrued benefits and accounts of any individual who has not performed services for a Considered Company during the 1-year period ending on the Determination Date shall not be taken into account. (iii) Further, in making such determination, such present value or such account balance shall include any rollover contribution (or similar transfer), as follows: (A) If the Rollover Contribution (or similar transfer) is "unrelated" (both initiated by the employee and made to or from a plan maintained by another employer who is not a Considered Company), the plan providing the distribution shall include such distribution in the present value of such account; the plan accepting the distribution shall not include such distribution in the present value of such account unless the plan accepted it before December 31, 1983; and (B) If the Rollover Contribution (or similar transfer) is "related" (either not initiated by the employee or made from a plan maintained by another Considered Company), the plan making the distribution shall not include the distribution in the present value of such account; and the plan accepting the distribution shall include such distribution in the present value of such account. (g) "Valuation Date" means, for purposes for determining the present value of an accrued benefit as of the Determination Date, the date determined as of the most recent valuation date which is within a 12-month period ending on the Determination Date. For the first plan year of a plan, the accrued benefit for a current employee shall be determined either (i) as if the individual terminated service as of the Determination Date or (ii) as if the individual terminated service as of the Valuation Date, but taking into account the estimated accrued benefit as of the Determination Date. The Valuation Date shall be determined in accordance with the principles set forth in Q&A T-25 of Treasury Regulation Section 1.416-1. Except as otherwise provided in this Section, for purposes of this Article, "Compensation" shall have the meaning given to it in Section 5.4(c)(vi) of the Plan. 58
ARTICLE XII TESTING OF CONTRIBUTIONS 12.1 Definitions: For purposes of this Article XII, the following terms, when capitalized, shall be defined as: (a) "Actual Contribution Percentage" or "ACP" shall mean, with respect to a Plan Year, for a specified group of Employees (either Highly Compensated Employees or non-Highly Compensated Employees) the average of the ratios, calculated separately for each Employee, of: (i) The sum of the Aggregate Contributions paid under the Plan on behalf of each Employee for a Plan Year that are made on account of the Employee's Contributions for the Plan Year, which are allocated to the Employee's Account during such Plan year, and are paid to the Trust no later than the end of the next following Plan Year; over (ii) The Employee's Compensation for such Plan Year. An Employee's Actual Contribution Percentage shall be determined after determining his Excess Deferrals and Excess Contributions, if any. The Actual Contribution Percentage of an eligible Employee who does not elect to make After-Tax Contributions for a Plan Year is zero. The individual ratios and Actual Contribution Percentages shall be calculated to the nearest 1/100 of 1% of an Employee's Compensation. (b) "Actual Deferral Percentage" or "ADP" shall mean, with respect to a Plan Year, for a specified group of Employees (either Highly Compensated Employees or non-Highly Compensated Employees) the average of the ratios, calculated separately for each Employee, of: (i) The amount of Employer Contributions actually paid to the Plan on behalf of each such Employee for a Plan Year that relate to Compensation that either would have been received by the Employee in such Plan Year (but for the deferral election) or are attributable to services performed by the Employee in the Plan Year and would have been received by the Employee within 2 1/2 months after the close of the Plan Year (but for the deferral election) and which are allocated to the Employee's Account and are paid to the Trust no later than the end of the next following Plan Year; over (ii) The Employee's Compensation for such Plan Year. The Actual Deferral Percentage of an eligible Employee who does not elect to make Pre-Tax Contributions for a Plan Year is zero. The individual ratios and 59
Actual Deferral Percentages shall be calculated to the nearest 1/100 of 1% of an Employee's Compensation. (c) "Aggregate Contributions" shall mean, as applicable, any of the following: (i) After-Tax Contributions, as provided in Section 4.3 of the Plan; (ii) Employer Matching Contributions, as provided in Section 4.1 of the Plan; (iii) QNECs, as provided in Section 12.2 of the Plan, that have not been included in the ADP test; (iv) Pre-Tax Contributions, as provided in Section 4.2 of the Plan, that are not needed to satisfy the ADP test for the current Plan Year, provided such test is satisfied before and after such Pre-Tax Contributions have been included in the ACP test; and (v) with respect to Highly Compensated Employees, Excess Contributions that have been recharacterized as After-Tax Contributions. Aggregate Contributions shall not include Employer Matching Contributions that are forfeited either to correct Excess Aggregate Contributions or because the contributions to which they relate are Excess Deferrals, Excess Contributions or Excess Aggregate Contributions. (d) "Compensation" shall mean compensation as defined in Treas. Reg. Section 1.414(s)-1(c). (e) "Employee" shall mean all Employees eligible to participate in the Plan in accordance with Section 3.1 of the Plan, including those eligible Employees who do not elect to make Pre-Tax and/or After-Tax Contributions, as defined in Treasury Regulation Section 1.401(k)-6. (f) "Employer Contributions" shall mean, as applicable, any (i) Pre-Tax Contributions, as provided in Section 4.2 of the Plan (other than Catch-Up Contributions, but including any Excess Deferrals made by Highly Compensated Employees), and (ii) QNECs allocated to non-Highly Compensated Employees that have not been used to satisfy the ACP test for the current Plan Year. (g) "Excess Aggregate Contributions" shall mean, with respect to any Plan Year, the excess of: (i) The sum of the Aggregate Contributions actually taken into account in computing the ACP of Highly Compensated Employees for such Plan Year; minus (ii) The maximum amount of Aggregate Contributions permitted by the ACP test for the Plan Year (determined by hypothetically reducing contributions made on behalf of Highly Compensated Employees in order of their ACP beginning with the highest of such percentages). (h) "Excess Contributions" shall mean, with respect to any Plan Year, the excess of: 60
(i) The sum of the Employer Contributions actually taken into account in computing the ADP of Highly Compensated Employees for such Plan Year; minus (ii) The maximum amount of such Contributions permitted by the ADP test for the Plan Year (determined by hypothetically reducing contributions made on behalf of Highly Compensated Employees in order of their ADP, beginning with the highest of such percentages). (i) "Excess Deferrals" shall have the meaning provided in Section 4.2 of the Plan. (j) "QNECs" shall mean discretionary qualified nonelective contributions to the Plan allocated for any Plan Year in any amount determined by the Company necessary to satisfy the ADP or ACP test requirements of Section 12.2 or 12.4, respectively, and in a manner determined by the Company in accordance with Treasury Regulation Section 1.401(k)-2(a)(6), among the Accounts of non-Highly Compensated Employees no later than 12 months after the close of the Plan Year for which they have been allocated. QNECs shall be non-forfeitable and 100% vested at all times, allocated to the Pre-Tax Contribution Account and subject to the same limitations as to withdrawal and distribution as Pre-Tax Contributions. 12.2 Actual Deferral Percentage Test: The ADP for the eligible Highly Compensated Employees for the Plan Year shall not exceed the greater of (a) or (b), as follows: (a) The ADP for the eligible non-Highly Compensated Employees times 1.25; or (b) The lesser of (i) the ADP for the eligible non-Highly Compensated Employees times 2.0 or (ii) the ADP for the eligible non-Highly Compensated Employees plus two percentage (2%) points. The Plan applies the Actual Deferral Percentage test using the "current year testing method" described in Treasury Regulation Section 1.401(k)-2 for Highly Compensated Employees and non-Highly Compensated Employees. The ADP for any Highly Compensated Employee who is eligible to have Pre-Tax Contributions allocated to his account under two or more plans described in Section 401(k) of the Code that are maintained by an Employer or an Affiliate in addition to this Plan shall be determined as if the total of all such contributions were made under a single plan. If a Highly Compensated Employee participates in two or more plans that have different plan years, all Pre-Tax Contributions made during the Plan Year under all such arrangements shall be aggregated. In the event this Plan satisfies the requirements of Code Section 401(k), 401(a)(4), or 410(b) only if aggregated with one or more other plans, or if one or more other plans satisfy the requirements of such sections of the Code only if aggregated with this Plan, then this Section shall be applied by determining the ADP of Employees as if all such plans were a single plan. Plans may be aggregated in order to satisfy Code Section 401(k) only 61
if they have the same plan year and use the same ADP testing method. Pursuant to Treasury Regulation Section 1.401(k)-1(b)(4)(v), the ESOP and non-ESOP portions of the Plan shall be aggregated for purposes of the ADP test. The Company, in its sole discretion, may elect to make QNECs for any Plan Year in any amount it determines is necessary to satisfy or contribute to satisfying the Actual Deferral Percentage test set forth in this Section 12.2 or the Actual Contribution Percentage test set forth in Section 12.4 of the Plan. QNECs may be used in lieu of, or in conjunction with, the distributions or recharaterizations described in Section 12.3 or the forfeitures or distributions described in Section 12.5 of the Plan. QNECs shall be allocated in a manner determined by the Company, in accordance with Treasury Regulation Section 1.401(a)(4)-2, among the Pre-Tax Contribution Accounts of non-Highly Compensated Employees who were eligible to make Pre-Tax Contributions during the Plan Year for which the QNECs are made at any time during the Plan Year or no later than 12 months after the end of the Plan Year. Any portion of the QNECs taken into account for purposes of the Actual Contribution Percentage test in Section 12.4, may not be taken into account for purposes of the Actual Deferral Percentage test in this Section 12.2. 12.3 Excess Contributions: If neither of the tests described in (a) or (b) of Section 12.2 are satisfied, and the Company decides not to make QNECs as a corrective measure, then Excess Contributions, except to the extent such Excess Contributions are classified as Catch-Up Contributions, plus any income and minus any loss attributable thereto, of certain Highly Compensated Employees will be recharacterized or distributed and shall be considered taxable income to such Highly Compensated Employees. Excess Contributions are allocated to the Highly Compensated Employees with the largest amount of Pre-Tax Contributions taken into account in calculating the ADP test for the year in which the excess arose, beginning with the Highly Compensated Employee with the largest amount of such Pre-Tax Contributions and continuing in descending order until all of the Excess Contributions have been allocated. To the extent a Highly Compensated Employee has not reached his Catch-Up Contribution limit under the Plan, Excess Contributions shall be allocated to such Highly Compensated Employee as Catch-Up Contributions (not to exceed the Catch-Up Contribution limit) and such contributions will not be treated as Excess Contributions. If distributed, Excess Contributions shall be distributed first from the Employee's Pre-Tax Unmatched Contributions and second from his Pre-Tax Matched Contributions, if the amount of the Excess Contributions exceeds the amount of his Pre-Tax Unmatched Contributions for the Plan Year, in his Pre-Tax Contribution Account. Excess Contributions shall be treated as Annual Additions under the Plan even if distributed. If, in lieu of distribution, the Committee decides, in its discretion, to correct Excess Contributions through recharacterization of such as After-Tax Contributions, then such amounts recharacterized as After-Tax Contributions, plus any income and minus any loss, shall be transferred to the After-Tax Contribution Accounts of those affected Highly Compensated Employees who have been allocated with Excess Contributions. The amount to be recharacterized will be further reduced by the amount of any Excess Deferrals which may have previously been distributed to the Highly Compensated Employee. Recharacterized amounts will remain nonforfeitable. Amounts may not be recharacterized to the extent that such amount in combination with other After-Tax Contributions made by certain Highly Compensated 62
Employees would exceed the stated limits provided in Section 4.3 of the Plan. Recharacterization must occur no later than 2 1/2 months after the last day of the Plan Year in which such Excess Contributions arose and is deemed to occur no earlier than the date the last affected Highly Compensated Employee is informed in writing of the amount recharacterized and the consequences thereof. If recharacterization is not possible due to Plan limits or if, in its discretion, the Committee decides to correct Excess Contributions through distribution, the amount of Excess Contributions allocated to each Highly Compensated Employees, plus any income and minus any losses calculated up to the date of the distribution, and minus the amount of any Excess Deferrals previously distributed, will be distributed to the affected Highly Compensated Employees as soon as administratively feasible but in no event later than 12 months following the end of such Plan Year during which the Excess Contributions were made. The income or loss attributable to a Highly Compensated Employee's Excess Contributions for the Plan Year shall be determined as the sum of (1) and (2), where (1) is the income or loss attributable to the Highly Compensated Employee's Pre-Tax Contribution Account for the Plan Year multiplied by a fraction, the numerator of which is the Excess Contributions and the denominator of which is the amount of the Highly Compensated Employee's Pre-Tax Contribution Account balance as of the beginning of the Plan Year plus the Employee's Pre-Tax Contribution to the Account during the Plan Year; and (2) (using the safe harbor method) is 10% of the amount determined under (1) multiplied by the number of calendar months between the end of the Plan Year and the date of distribution, counting the month of distribution if distribution occurs after the 15th of such month. If distributions or recharacterizations are made under this Section 12.3, the Actual Deferral Percentage is treated as meeting the nondiscrimination test of Section 401(k)(3) of the Code, regardless of whether the Actual Deferral Percentage, if recalculated after such distributions or recharacterizations, would satisfy Section 401(k)(3) of the Code. The above procedures are used for purposes of distributing Excess Contributions under Section 401(k)(8)(A)(i) of the Code. Excess Contributions shall be treated as Annual Additions under Section 5.4 of the Plan. 12.4 Actual Contribution Percentage Test: The Contribution Percentage for the eligible Employees for any Plan Year who are Highly Compensated Employees shall not exceed the greater of (a) or (b), as follows: (a) The ACP for the eligible non-Highly Compensated Employees times 1.25; or (b) The lesser of (i) the ACP for the eligible non-Highly Compensated Employees times 2.0 or (ii) the ACP for non-Highly Compensated Employees plus two percentage (2%) points. The Plan applies the Actual Contribution Percentage test using the "current year testing method" described in Treasury Regulation Section 1.401(m)-2 for Highly Compensated Employees and non-Highly Compensated Employees. In computing the Actual Contribution 63
Percentage, the Company may elect to take into account Pre-Tax Contributions and QNECs made under this Plan or any other plan of the Company to the extent that (i) Pre-Tax Contributions and/or QNECs used for purposes of calculating the ADP test are not used for purposes of calculating the ACP test, and (ii) Pre-Tax Contributions, including those treated as Aggregate Contributions for purposes of calculating the Actual Contribution Percentage, satisfy the requirements of Code Section 401(k)(3). The ACP for any Highly Compensated Employee who is eligible to have Aggregate Contributions allocated to his account under two or more plans described in Section 401(a) or 401(k) of the Code that are maintained by an Employer or an Affiliate in addition to this Plan shall be determined as if the total of all such contributions were made under a single plan. If a Highly Compensated Employee participates in two or more such plans or arrangements that have different plan years, all Aggregate Contributions made during the Plan Year under all such plans and arrangements shall be aggregated. For purposes of determining whether the ACP limits of this Section 12.4 are satisfied, all Aggregate Contributions that are made under two or more plans that are aggregated for purposes of Code Section 401(a)(4) or 410(b) are to be treated as made under a single plan, and if two or more plans are permissively aggregated for purposes of Code Section 401(m), the aggregated plans must also satisfy Code Sections 401(a)(4) and 410(b) as though they were a single plan. Plans may be aggregated in order to satisfy Code Section 401(m) only if they have the same Plan Year and use the same ACP testing method. Pursuant to Treasury Regulation Section 1.401(m)-1(b)(4)(v), the ESOP and non-ESOP portions of the Plan shall be aggregated for purposes of the ACP test. 12.5 Excess Aggregate Contributions: If neither of the tests described in (a) or (b) of Section 12.4 are satisfied, and the Company decides not to make QNECs as a corrective measure, Excess Aggregate Contributions, plus any income and minus any loss attributable thereto, shall be forfeited or, if not forfeitable, shall be distributed no later than 12 months after the close of a Plan Year to Participants to whose accounts such Excess Aggregate Contributions were allocated. Excess Aggregate Contributions are allocated to the Highly Compensated Employees with the largest Aggregate Contributions taken into account in calculating the ACP test for the year in which the excess arose, beginning with the Highly Compensated Employee with the largest amount of such Aggregate Contributions and continuing in descending order until all the Excess Aggregate Contributions have been allocated. Excess Aggregate Contributions shall be treated as Annual Additions under the Plan even if distributed. The income or loss attributable to the Highly Compensated Employee's Excess Aggregate Contributions for the Plan Year shall be determined as the sum of (1) and (2), where (1) is the income or loss attributable to the Highly Compensated Employee's Employer Matching and After-Tax Contribution Accounts for the Plan Year multiplied by a fraction, the numerator of which is the Excess Aggregate Contribution, and the denominator of which is the amount of the Highly Compensated Employee's Employer Matching and After-Tax Contribution Accounts without regard to any income or loss occurring during such Plan Year; and (2) (using the safe harbor method) is 10% of the amount determined under (1) multiplied by the number of whole calendar months between the end of the Plan Year and the date of distribution, counting the month of distribution if distribution occurs after the 15th of such month. 64
Any Excess Aggregate Contributions allocated to a Highly Compensated Employee shall (i) first be distributed from the Employee's After-Tax Unmatched Contributions and then from his After-Tax Matched Contributions, if the amount of the Excess Aggregate Contributions exceeds the amount of his After-Tax Unmatched Contribution, in his After-Tax Contribution Account; and (ii) second be forfeited from his Employer Matching Contributions in his Employer Matching Account, if the amount of the Excess Aggregate Contributions exceeds the value of his After-Tax Contributions. Any forfeiture of Excess Aggregate Contributions shall be applied to reduce Employer Matching Contributions for the Plan Year in which the excess arose. Should the amount of forfeited Excess Aggregate Contributions exceed the amount of Employer Matching Contributions needed for the Plan Year, such forfeitures shall be allocated, after all other forfeitures under the Plan, to the Employer Matching Contribution Accounts of each non-Highly Compensated Employee who made Pre-Tax Contributions to the Plan, in the ratio that each such Employee's Pre-Tax Contributions for the Plan Year bears to the total Pre-Tax Contributions of all such Employees for such Plan Year. If forfeitures or distributions are made under this Section 12.5, the Actual Contribution Percentage test is treated as meeting the nondiscrimination test of Section 401(m)(2) of the Code, regardless of whether the Actual Contribution Percentage, if recalculated after such forfeitures and/or distributions, would satisfy Section 401(m)(2) of the Code. Excess Aggregate Contributions shall be treated as Annual Additions under Section 5.4 of the Plan. 12.6 Effective Date: This Article XII shall be effective for Plan Years ending after December 29, 2004 (i.e., effective beginning with the 2004 Plan Year) and reflects the Plan's adoption of the final Treasury Regulation Section 1.401(k)-1 et seq. and 1.401(m)-1 et seq. issued December 29, 2004. 65
ARTICLE XIII MISCELLANEOUS PROVISIONS 13.1 Not Contract of Employment: The adoption and maintenance of the provisions of this Plan shall not be deemed to constitute a contract between the Employer and any Employee, or to be a consideration for, or an inducement or condition of, the employment of any person. Nothing herein contained shall be deemed to give to any Employee the right to be retained in the employ of the Employer or to interfere with the right of the Employer to discharge any Employee at any time, nor shall it be deemed to give the Employer the right to require any Employee to remain in its employ, nor shall it interfere with any Employee's right to terminate his employment at any time. 13.2 Controlling Law: This Plan and the Trust shall be construed, regulated and administered under the laws of the State of Texas, subject, however, to such determinations under the Plan as may be governed by ERISA and related provisions of the Code. 13.3 Invalidity of Particular Provisions: In the event any provision of this Plan shall be held illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining provisions of this Plan but shall be fully severable, and this Plan shall be construed and enforced as if said illegal or invalid provisions had never been inserted herein. 13.4 Non-Alienability of Rights of Participants: Except as otherwise provided below and with respect to certain judgments and settlements pursuant to Section 401(a)(13) of the Code, no interest, right or claim in or to the part of the Trust Fund attributable to the Account of any Participant, or any distribution of benefits therefrom, shall be assignable, transferable or subject to sale, mortgage, pledge, hypothecation, commutation, anticipation, garnishment, attachment, execution, claim or levy of any kind, voluntary or involuntary (excluding a levy on an Account, other than the Pre-Tax Contribution Account, for taxes filed upon the Plan by the Internal Revenue Service to the extent valid and enforceable under applicable federal law), including without limitation any claim asserted by a spouse or former spouse of any Participant, and the Trustee shall not recognize any attempt to assign, transfer, sell, mortgage, pledge, hypothecate, commute or anticipate the same. The preceding sentence shall also apply to the creation, assignment or recognition of a right to any benefit payable with respect to a Participant pursuant to a domestic relations order, unless such order is determined to be a qualified domestic relations order, as defined in Section 414(p) of the Code. The Committee shall establish a written procedure to be used to determine the qualified status of such orders and to administer distributions under such orders. Further, to the extent provided under the qualified domestic relations order, a former spouse of a Participant shall be treated as a spouse for all purposes of the Plan. If the Committee receives a qualified domestic relations order with respect to a Participant, the amount assigned to the Participant's former spouse may be immediately distributed, to the extent permitted by law, from the vested portion of the Participant's Account. -66-
13.5 Payments in Satisfaction of Claims of Participants: Any distribution to any Participant or his Beneficiary or legal representative, in accordance with the provisions of the Plan, of the interest in the Trust Fund attributable to his Accounts, shall be in full satisfaction of all claims under the Plan against the Trust Fund, the Trustee, the Company (including the Board) and the Employer. The Trustee may require that any distributee execute and deliver to the Trustee a receipt and a full and complete release of the Employer as a condition precedent to any payment or distribution under the Plan. 13.6 Payments Due Minors and Incompetents: If the Committee determines that any person to whom a payment is due hereunder is a minor or is incompetent by reason of physical or mental disability, the Committee shall have power to cause the payments becoming due such person to be made to the guardian of the minor or the guardian of the estate of the incompetent, or to the County Clerk as allowed under law without the Committee or the Trustee being responsible to see to the application of such payment. Payments made pursuant to such power shall operate as a complete discharge of the Committee, the Trustee and the Employer. 13.7 Acceptance of Terms and Conditions of Plan by Participants: Each Participant, through execution of the application required under the terms of the Plan as a condition of participation herein, for himself, his heirs, executors, administrators, legal representatives and assigns, approves and agrees to be bound by the provisions of this Plan and the Trust Agreement and any subsequent amendments thereto and all actions of the Committee and the Trustee hereunder. In consideration of the adoption of this Plan by the Employer and the Contributions of the Employer to the Trust Fund, each Participant agrees by the execution of his application to participate herein to release and hold harmless to the extent permitted by ERISA the Employer, the Committee and the Trustee from any liability for any act whatsoever, past, present, or future, performed in good faith in such respective capacities pursuant to the provisions of this Plan or the Trust Agreement. 13.8 Impossibility of Diversion of Trust Fund: Notwithstanding any provision herein to the contrary, no part of the corpus or the income of the Trust Fund shall ever be used for or diverted to purposes other than for the exclusive benefit of the Participants or their Beneficiaries or for the payment of expenses of the Plan. 67
IN WITNESS WHEREOF, CENTERPOINT ENERGY, INC. has executed these presents as evidenced by the signatures affixed hereto of its officers hereunto duly authorized, in a number of copies, all of which shall constitute but one and the same instrument, which instrument may be sufficiently evidenced by any such executed copy hereof, this 30th day of August 2005, but effective as of January 1, 2005. CENTERPOINT ENERGY, INC. By: /s/ David M. McClanahan ------------------------------------ David M. McClanahan President and Chief Executive Officer ATTEST: /s/ Richard Dauphin - ------------------------------------ Richard Dauphin Assistant Secretary 68
CENTERPOINT ENERGY SAVINGS PLAN (As Amended and Restated Effective January 1, 2005) EXHIBIT A EMPLOYER LIST In accordance with Section 10.1 of the Plan, this Exhibit A (which forms a part of the Plan) sets forth the list of the Plan's adopting Employers (in addition to the Company) as of January 1, 2005: CenterPoint Energy Field Services, Inc. CenterPoint Energy Gas Services, Inc. CenterPoint Energy Gas Transmission Company CenterPoint Energy Houston Electric, LLC CenterPoint Energy Mississippi River Gas Transmission Corporation CenterPoint Energy Offshore Management Services, LLC (effective as of April 15, 2005) CenterPoint Energy Pipeline Services, Inc. CenterPoint Energy Resources Corp. CenterPoint Energy Service Company, LLC A-1
Exhibit 99.3 ITEM 1. BUSINESS REGULATION We are subject to regulation by various federal, state and local governmental agencies, including the regulations described below. PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 As a registered public utility holding company, we and our subsidiaries are subject to a comprehensive regulatory scheme imposed by the SEC in order to protect customers, investors and the public interest. Although the SEC does not regulate rates and charges under the 1935 Act, it does regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies. In order to obtain financing, acquire additional public utility assets or stock, or engage in other significant transactions, we are generally required to obtain approval from the SEC under the 1935 Act. We received an order from the SEC under the 1935 Act on June 30, 2003 and supplemental orders thereafter relating to our financing activities and those of our regulated subsidiaries, as well as other matters. The orders are effective until June 30, 2005. As of December 31, 2004, the orders generally permitted us and our subsidiaries to issue securities to refinance indebtedness outstanding at June 30, 2003, and authorized us and our subsidiaries to issue certain incremental external debt securities and common and preferred stock through June 30, 2005 in specified amounts, without prior authorization from the SEC. The orders also contain certain requirements regarding ratings of our securities, interest rates, maturities, issuance expenses and use of proceeds. The orders generally require that CenterPoint Houston and CERC maintain a ratio of common equity to total capitalization of at least 30%. We intend to file an application for approval of our post-June 30, 2005 financing activities. Pursuant to requirements of the orders, we formed a service company, CenterPoint Energy Service Company, LLC (Service Company), that began operation as of January 1, 2004, to provide certain corporate and shared services to our subsidiaries. Those services are provided pursuant to service arrangements that are in a form prescribed by the SEC. Services are provided by the Service Company at cost and are subject to oversight and periodic audit from the SEC. 1
The United States Congress from time to time considers legislation that would repeal the 1935 Act. We cannot predict at this time whether this legislation or any variation thereof will be adopted or, if adopted, the effect of any such law on our business. FEDERAL ENERGY REGULATORY COMMISSION The FERC has jurisdiction under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in intrastate commerce that are not first sales. The FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The rates charged by interstate pipelines for interstate transportation and storage services are also regulated by the FERC. Our natural gas pipeline subsidiaries may periodically file applications with the FERC for changes in their generally available maximum rates and charges designed to allow them to recover their costs of providing service to customers (to the extent allowed by prevailing market conditions), including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period and, in some cases, are subject to refund under applicable law until such time as the FERC issues an order on the allowable level of rates. On November 25, 2003, the FERC issued Order No. 2004, the final rule modifying the Standards of Conduct applicable to electric and natural gas transmission providers, governing the relationship between regulated transmission providers and certain of their affiliates. During 2004, the FERC Order was amended three times. The rule significantly changes and expands the regulatory burdens of the Standards of Conduct and applies essentially the same standards to jurisdictional electric transmission providers and natural gas pipelines. On February 9, 2004, our natural gas pipeline subsidiaries filed Implementation Plans required under the new rule. Those subsidiaries were further required to post their Implementation Procedures on their websites by September 22, 2004, and to be in compliance with the requirements of the new rule by that date. CenterPoint Houston is not a "public utility" under the Federal Power Act and therefore is not generally regulated by the FERC, although certain of its transactions are subject to limited FERC jurisdiction. STATE AND LOCAL REGULATION Electric Transmission & Distribution. CenterPoint Houston conducts its operations pursuant to a certificate of convenience and necessity issued by the Texas Utility Commission that covers its present service area and facilities. In addition, CenterPoint Houston holds non-exclusive franchises, typically having a term of 50 years, from the incorporated municipalities in its service territory. These franchises give CenterPoint Houston the right to construct, operate and maintain its transmission and distribution system within the streets and public ways of these municipalities for the purpose of delivering electric service to the municipality, its residents and businesses in exchange for payment of a fee. The franchise for the City of Houston is scheduled to expire in 2007. All retail electric providers in CenterPoint Houston's service area pay the same rates and other charges for transmission and distribution services. CenterPoint Houston's distribution rates charged to retail electric providers for residential customers are based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are based on peak demand. Transmission rates charged to other distribution companies are based on amounts of energy transmitted under "postage stamp" rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay CenterPoint Houston the same rates and other charges for transmission services. The transmission and distribution rates for CenterPoint Houston have been in effect since January 1, 2002, when electric competition began. This regulated delivery charge includes the transmission and distribution rate (which includes costs for nuclear decommissioning and municipal franchise fees), a system benefit fund fee imposed by the Texas electric restructuring law, a transition charge associated 2
with securitization of regulatory assets and an excess mitigation credit imposed by the Texas Utility Commission. Natural Gas Distribution. In almost all communities in which CERC provides natural gas distribution services, it operates under franchises, certificates or licenses obtained from state and local authorities. The terms of the franchises, with various expiration dates, typically range from 10 to 30 years, though franchises in Arkansas are perpetual. None of CERC's material franchises expire in the near term. CERC expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive. Substantially all of CERC's retail natural gas sales by its local distribution divisions are subject to traditional cost-of-service regulation at rates regulated by the relevant state public utility commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and municipalities CERC serves. In 2004, the City of Houston, 28 other cities and the Railroad Commission approved a settlement that increased Houston Gas' base rate and service charge revenues by approximately $14 million annually. In February 2004, the Louisiana Public Service Commission (LPSC) approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in its South Louisiana Division by approximately $2 million annually. In July 2004, Minnesota Gas filed an application for a general rate increase of $22 million with the Minnesota Public Utilities Commission (MPUC). Minnesota Gas and the Minnesota Department of Commerce have agreed to a settlement of all issues, including an annualized increase in the amount of $9 million, subject to approval by the MPUC. A final decision on this rate relief request is expected from the MPUC in the second quarter of 2005. Interim rates of $17 million on an annualized basis became effective on October 1, 2004, subject to refund. In July 2004, the LPSC approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in its North Louisiana Division by approximately $7 million annually. In October 2004, Southern Gas Operations filed an application for a general rate increase of approximately $3 million with the Railroad Commission for rate relief in the unincorporated areas of its Beaumont, East Texas and South Texas Divisions. The Railroad Commission staff has begun its review of the request, and a decision is anticipated in April 2005. In November 2004, Southern Gas Operations filed an application for a general rate increase of approximately $34 million with the Arkansas Public Service Commission (APSC). The APSC staff has begun its review of the request, and a decision is anticipated in the second half of 2005. In December 2004, the OCC approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in Oklahoma by approximately $3 million annually. DEPARTMENT OF TRANSPORTATION In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (the Act). This legislation applies to our interstate pipelines as well as our intrastate pipelines and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires pipeline and distribution companies to assess the integrity of their pipeline transmission facilities in areas of high population concentration or High Consequence Areas (HCA). The legislation further requires companies to perform remediation activities, in accordance with the requirements of the legislation, over a 10-year period. In December 2003, the Department of Transportation Office of Pipeline Safety issued the final regulations to implement the Act. These regulations became effective on February 14, 2004 and provided guidance on, among other things, the areas that should be classified as HCA. Our interstate pipelines developed and implemented a written pipeline integrity management program in 2004, meeting the Depart- 3
ment of Transportation Office of Pipeline Safety requirement of having the program in place by December 17, 2004. Our interstate and intrastate pipelines and our natural gas distribution companies anticipate that compliance with the new regulations will require increases in both capital and operating cost. The level of expenditures required to comply with these regulations will be dependent on several factors, including the age of the facility, the pressures at which the facility operates and the number of facilities deemed to be located in areas designated as HCA. Based on our interpretation of the rules and preliminary technical reviews, we anticipate compliance will require average annual expenditures of approximately $15 to $20 million during the initial 10-year period. ENVIRONMENTAL MATTERS Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines, gas gathering and processing systems, and electric transmission and distribution systems we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as: - restricting the way we can handle or dispose of our wastes; - limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species; - requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and - enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to: - construct or acquire new equipment; - acquire permits for facility operations; - modify or replace existing and proposed equipment; and - clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. In addition, we 4
believe that the various environmental remediation activities in which we are presently engaged will not materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of all material environmental and safety laws and regulations that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations. AIR EMISSIONS Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies. WATER DISCHARGES Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations. HAZARDOUS WASTE Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (RCRA), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements. LIABILITY FOR REMEDIATION The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), also known as "Superfund," and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of 5
hazardous substances at offsite locations such as landfills. Although petroleum as well as natural gas is excluded from CERCLA's definition of "hazardous substance," in the course of our ordinary operations we generate wastes that may fall within the definition of a "hazardous substance." CERCLA authorizes the United States Environmental Protection Agency (EPA) and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies. LIABILITY FOR PREEXISTING CONDITIONS Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. We believe the ultimate cost associated with resolving this matter will not have a material impact on our financial condition or results of operations or that of CERC. Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory. CERC believes that it has no liability with respect to two of these sites. At December 31, 2004, CERC had accrued $18 million for remediation of certain Minnesota sites. At December 31, 2004, the estimated range of possible remediation costs for these sites was $7 million to $42 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of December 31, 2004, CERC has collected or accrued $13 million from insurance companies and ratepayers to be used for future environmental remediation. In addition to the Minnesota sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned or operated by one of its former affiliates. CERC has not been named by these agencies as a PRP for any of those sites. CERC has been named as a defendant in lawsuits under which contribution is sought for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. We are investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of those sites under CERCLA and applicable state statutes, and is vigorously contesting those suits. Mercury Contamination. Our pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been 6
spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by us at some sites in the past, and we have conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on our experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, we believe that the costs of any remediation of these sites will not be material to our financial condition, results of operations or cash flows. Other Environmental. From time to time, we have received notices from regulatory authorities or others regarding our status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Although their ultimate outcome cannot be predicted at this time, we do not believe, based on our experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. Asbestos. A number of facilities that we own contain significant amounts of asbestos insulation and other asbestos-containing materials. We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations we own, but most existing claims relate to facilities previously owned by us but currently owned by Texas Genco LLC. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the separation agreement between us and Texas Genco, ultimate financial responsibility for uninsured losses relating to these claims has been assumed by Texas Genco, but under the terms of our agreement to sell Texas Genco to Texas Genco LLC, we have agreed to continue to defend such claims to the extent they are covered by insurance we maintain, subject to reimbursement of the costs of such defense from Texas Genco LLC. Although their ultimate outcome cannot be predicted at this time, we intend to continue vigorously contesting claims that we do not consider to have merit and do not believe, based on our experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. REGULATORY AND ENVIRONMENTAL MATTERS RELATING TO DISCONTINUED OPERATIONS Nuclear Regulatory Commission. Texas Genco is subject to regulation by the NRC with respect to the operation of the South Texas Project nuclear facility. This regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstrations to the NRC that plant operations meet applicable requirements are also required. The NRC has the ultimate authority to determine whether any nuclear-powered generating unit may operate. Texas Genco and the other owners of the South Texas Project are required by NRC regulations to estimate from time to time the amounts required to decommission that nuclear generating facility and are required to maintain funds to satisfy that obligation when the plant ultimately is decommissioned. CenterPoint Houston currently collects through its electric rates amounts calculated to provide sufficient funds at the time of decommissioning to discharge these obligations. Funds collected are deposited into nuclear decommissioning trusts. The beneficial ownership of the nuclear decommissioning trusts is held by Texas Genco, as a licensee of the facility. While current funding levels exceed NRC minimum requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and waste burial. In the event that funds from the trust are inadequate to decommission the facilities, CenterPoint Houston will be required by the transaction agreement with Texas Genco LLC to collect through rates or other authorized charges all additional amounts required to fund Texas Genco's obligations relating to the decommissioning of the South Texas Project. Nuclear Waste. Under the U.S. Nuclear Waste Policy Act of 1982, the federal government was to create a federal repository for spent nuclear fuel produced by nuclear plants like the South Texas Project. Also 7
pursuant to that legislation a special assessment has been imposed on those nuclear plants to pay for the facility. Consistent with the Act, owners of nuclear facilities, including Texas Genco and the other owners of the South Texas Project, entered into contracts setting out the obligations of the owners and U.S. Department of Energy (DOE). Since 1998, DOE has been in default on its obligations to begin moving spent nuclear fuel from reactors to the federal repository (which still is not completed). In January 2004, Texas Genco and the other owners of the South Texas Project, along with owners of other nuclear plants, filed a breach of contract suit against DOE in order to protect against the running of a statute of limitations. In conjunction with Texas Genco's 30.8% ownership interest in the South Texas Project, Texas Genco bears a proportionate share of responsibility associated with the proper handling and disposal of high-level radioactive waste (spent nuclear fuel) as well as low-level radioactive waste. The South Texas Project has on-site storage facilities with the capability to store the spent nuclear fuel, and currently does store such waste on-site, per the requirements established by the NRC. There is adequate on-site storage at the South Texas Project for high-level radioactive waste over the licensed life of the two generating units. The 1980 Federal Low-Level Radioactive Waste Policy Act directed states to assume responsibility for the disposal of low-level radioactive waste generated within their borders. Texas does not currently have any waste disposal locations available for low-level radioactive waste. Private waste management companies are seeking to develop sites in Texas but Texas Genco cannot predict when such a site may be available. South Carolina and New Mexico operate low-level radioactive waste disposal sites that accept low-level radioactive waste from Texas. The South Texas Project disposes of its low-level radioactive waste in both South Carolina and New Mexico under short-term annual agreements. In the event that both South Carolina and New Mexico stop accepting waste in the future, and until a Texas site is functional, the South Texas Project has storage for at least five years of low-level radioactive waste generated by the project. 8
ITEM 3. LEGAL PROCEEDINGS For a brief description of certain legal and regulatory proceedings affecting us, please read "Regulation" and "Environmental Matters" in Item 1 of this report and Notes 4 and 11(c) to our consolidated financial statements, which information is incorporated herein by reference. 9
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CERTAIN FACTORS AFFECTING FUTURE EARNINGS Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors including: - the timing and amount of our recovery of the true-up components; - the timing and results of the monetization of our remaining interest in Texas Genco; - state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, constraints placed on our activities or business by the 1935 Act, changes in or application of laws or regulations applicable to other aspects of our business and actions with respect to: - allowed rates of return; - rate structures; - recovery of investments; and - operation and construction of facilities; - industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns; - the timing and extent of changes in commodity prices, particularly natural gas; - changes in interest rates or rates of inflation; - weather variations and other natural phenomena; - the timing and extent of changes in the supply of natural gas; - commercial bank and financial market conditions, our access to capital, the cost of such capital, receipt of certain financing approvals under the 1935 Act, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; - actions by rating agencies; - inability of various counterparties to meet their obligations to us; - non-payment for our services due to financial distress of our customers, including RRI; - the outcome of the pending securities lawsuits against us, Reliant Energy and RRI; - the ability of RRI to satisfy its obligations to us, including indemnity obligations; - our ability to control costs; - the investment performance of our employee benefit plans; - our internal restructuring or other restructuring options that may be pursued; - our potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to us; and - other factors discussed in Item 1 of this report under "Risk Factors." 10
OTHER SIGNIFICANT MATTERS Pension Plan. As discussed in Note 9(b) to our consolidated financial statements, we maintain a non-contributory pension plan covering substantially all employees. Employer contributions are based on actuarial computations that establish the minimum contribution required under the Employee Retirement Income Security Act of 1974 (ERISA) and the maximum deductible contribution for income tax purposes. At December 31, 2004, the projected benefit obligation exceeded the market value of plan assets by $53 million; however, the market value of the plan assets exceeded the accumulated benefit obligation by $22 million. Changes in interest rates and the market values of the securities held by the plan during 2005 could materially, positively or negatively, change our funded status and affect the level of pension expense and required contributions in 2006 and beyond. In connection with the sale of our 81% interest in Texas Genco, a separate pension plan was established for Texas Genco on September 1, 2004 and we transferred a net pension liability of approximately $68 million to Texas Genco. In October 2004, Texas Genco received an allocation of assets from our pension plan pursuant to rules and regulations under ERISA. During 2003 and 2004, we have not been required to make contributions to our pension plan. We have made voluntary contributions of $23 million and $476 million in 2003 and 2004, respectively. Under the terms of our pension plan, we reserve the right to change, modify or terminate the plan. Our funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA and the Internal Revenue Code. In accordance with SFAS No. 87, "Employers' Accounting for Pensions," changes in pension obligations and assets may not be immediately recognized as pension costs in the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of benefit payments provided to plan participants. Pension costs were $35 million, $90 million and $80 million for 2002, 2003 and 2004, respectively. For 2002, a pension benefit of $4 million was recorded related to RRI's participants. Pension benefit for RRI's participants is reflected in the Statement of Consolidated Operations as discontinued operations. In addition, included in the costs for 2002, 2003 and 2004 are $15 million, $17 million and $11 million, respectively, of expense related to Texas Genco participants. Pension expense for Texas Genco participants is reflected in the Statement of Consolidated Operations as discontinued operations. Additionally, we maintain a non-qualified benefit restoration plan which allows participants to retain the benefits to which they would have been entitled under our non-contributory pension plan except for the federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. The expense associated with this non-qualified plan was $9 million, $8 million and $6 million in 2002, 2003 and 2004, respectively. Included in the cost for 2002 is $3 million of expense related to RRI's participants, which is reflected in discontinued operations in the Statements of Consolidated Operations. 11
The calculation of pension expense and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate. As of December 31, 2004, the expected long-term rate of return on plan assets was 8.5%, a reduction from the 9.0% rate assumed as of December 31, 2003. We believe that our actual asset allocation, on average, will approximate the targeted allocation and the estimated return on net assets. We regularly review our actual asset allocation and periodically rebalance plan assets as appropriate. As of December 31, 2004, the projected benefit obligation was calculated assuming a discount rate of 5.75%, which is a 0.5% decline from the 6.25% discount rate assumed in 2003. The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of our plan. Pension expense for 2005, including the benefit restoration plan, is estimated to be $37 million based on an expected return on plan assets of 8.5% and a discount rate of 5.75% as of December 31, 2004. If the expected return assumption were lowered by 0.5% (from 8.5% to 8.0%), 2005 pension expense would increase by approximately $8 million. Due to significant funding that occurred during 2004, pension plan assets (excluding the unfunded benefit restoration plan) exceed the accumulated benefit obligation, which enabled us to reverse a charge to comprehensive income of $350 million, net of tax. However, if the discount rate were lowered by 0.5% (from 5.75% to 5.25%), the assumption change would increase our projected benefit obligation, accumulated benefit obligation and 2005 pension expense by approximately $106 million, $100 million and $7 million, respectively. In addition, the assumption change would have significant impacts on our Consolidated Balance Sheet by changing the pension asset recorded as of December 31, 2004 of $610 million to a pension liability of $78 million, offset by a charge to comprehensive income in 2004 of $447 million, net of tax. For the benefit restoration plan, if the discount rate were lowered by 0.5% (from 5.75% to 5.25%), the assumption change would increase our projected benefit obligation, accumulated benefit obligation and 2005 pension expense by approximately $4 million, $3 million, and less than $1 million, respectively. In addition, the assumption change would result in a charge to comprehensive income of approximately $2 million. Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plan will impact our future pension expense and liabilities. We cannot predict with certainty what these factors will be. In October 2004, the American Jobs Creation Act (AJCA) was signed into law. The AJCA made significant changes in the taxation of nonqualified deferred compensation with new Code Section 409A. Non-compliance with Section 409A can result in increased federal income taxes on nonqualified deferred compensation for employees. We are currently analyzing the impact of Section 409A and related guidance issued by the Treasury Department and the Internal Revenue Service, on our non-qualified plans and agreements that provide for deferred compensation. Such plans or agreements may require amendment or modification to comply with the new law. 12
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (2) Summary of Significant Accounting Policies (d) LONG-LIVED ASSETS AND INTANGIBLES The Company records property, plant and equipment at historical cost. The Company expenses repair and maintenance costs as incurred. Property, plant and equipment includes the following:
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Amortization expense for other intangibles for 2002, 2003 and 2004 was $2 million in each year. Estimated amortization expense for the five succeeding fiscal years is as follows (in millions):
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheets as of December 31, 2003 and 2004:
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (4) REGULATORY MATTERS (a) 2004 TRUE-UP PROCEEDING In March 2004, CenterPoint Houston filed the final true-up application required by the Texas electric restructuring law with the Public Utility Commission of Texas (Texas Utility Commission) (2004 True-Up Proceeding). CenterPoint Houston's requested true-up balance was $3.7 billion, excluding interest and net of the retail clawback from RRI described below. In June, July and September 2004, the Texas Utility Commission conducted hearings on, and held public meetings addressing, CenterPoint Houston's true-up application. In December 2004, the Texas Utility Commission approved a final order in CenterPoint Houston's true-up proceeding (2004 Final Order) authorizing CenterPoint Houston to recover $2.3 billion including interest through August 31, 2004, subject to adjustments to reflect the benefit of certain deferred taxes and the accrual of interest and payment of excess mitigation credits after August 31, 2004. As a result of the 2004 Final Order, the Company wrote-off net regulatory assets of $1.5 billion and recorded a related income tax benefit of $526 million, resulting in an after-tax charge of $977 million, which is reflected as an extraordinary loss in the Company's Statements of Consolidated Operations. The Company recorded an expected loss of $894 million in the third quarter of 2004 and increased this amount by $83 million in the fourth quarter of 2004 based on the Company's assessment of the amounts ultimately recoverable. In January 2005, CenterPoint Houston appealed certain aspects of the final order seeking to increase the true-up balance ultimately recovered by CenterPoint Houston. Other parties have also appealed the order, seeking to reduce the amount authorized for CenterPoint Houston's recovery. Although CenterPoint Houston believes it has 16
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) meritorious arguments and that the other parties' appeals are without merit, no prediction can be made as to the ultimate outcome or timing of such appeals. The Company has recorded as a regulatory asset a return of $374 million on the true-up balance for the period from January 1, 2002 through December 31, 2004 as allowed by the Texas Utility Commission's 2004 Final Order. The Company, under the 2004 Final Order, will continue to accrue a return until the true-up balance is recovered by the Company, either from rate payers or through a securitization offering as discussed below. The rate of return is based on CenterPoint Houston's cost of capital, established in the Texas Utility Commission's final order issued in October 2001 (2001 Final Order), which is derived from CenterPoint Houston's cost to finance assets and an allowance for earnings on shareholders' investment. Accordingly, in accordance with SFAS No. 92, "Regulated Enterprises -- Accounting for Phase-in Plans." the rate of return has been bifurcated into components representing a return of costs to finance assets and an allowance for earnings on shareholders' investment. The component representing a return of costs to finance assets of $226 million has been recognized in the fourth quarter of 2004 and is included in other income in the Company's Statements of Consolidated Operations. The component representing a return of costs to finance assets will continue to be recognized as earned going forward. The component representing an allowance for earnings on shareholders' investment of $148 million has been deferred and will be recognized as it is collected through rates in the future. In November 2004, RRI paid $177 million to the Company, representing the "retail clawback" determined by the Texas Utility Commission in the 2004 True-Up Proceeding. The Texas electric restructuring law requires the Texas Utility Commission to determine the retail clawback if the formerly integrated utility's affiliated retail electric provider retained more than 40 percent of its residential price-to-beat customers within the utility's service area as of January 1, 2004 (offset by new customers added outside the service territory). That retail clawback is a credit against the stranded costs the utility is entitled to recover and was reflected in the $2.3 billion recovery authorized. Under the terms of a master separation agreement between RRI and the Company, RRI agreed to pay the Company the amount of the retail clawback determined by the Texas Utility Commission. The payment was used by the Company to reduce outstanding indebtedness. The Texas electric restructuring law provides for the use of special purpose entities to issue transition bonds for the economic value of generation-related regulatory assets and stranded costs. These transition bonds will be amortized over a period not to exceed 15 years through non-bypassable transition charges. In October 2001, a special purpose subsidiary of CenterPoint Houston issued $749 million of transition bonds to securitize certain generation-related regulatory assets. These transition bonds have a final maturity date of September 15, 2015 and are non-recourse to the Company and its subsidiaries other than to the special purpose issuer. Payments on the transition bonds are made solely out of funds from non-bypassable transition charges. In December 2004, CenterPoint Houston filed for approval of a financing order to issue transition bonds to securitize its true-up balance. On March 9, 2005, the Texas Utility Commission issued a financing order allowing CenterPoint Houston to securitize approximately $1.8 billion and requiring that the benefit of certain deferred taxes be reflected as a reduction in the competition transition charge. The Company anticipates that a new special purpose subsidiary of CenterPoint Houston will issue bonds in one or more series through an underwritten offering. Depending on market conditions and the impact of possible appeals of the financing order, among other factors, the Company anticipates completing such an offering in 2005. In January 2005, CenterPoint Houston filed an application for a competition transition charge to recover its true-up balance. CenterPoint Houston will adjust the amount sought through that charge to the extent that it is able to securitize any of such amount. Under the Texas Utility Commission's rules, the unrecovered true-up balance to be recovered through the competition transition charge earns a return until fully recovered. 17
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In the 2001 Final Order, the Texas Utility Commission established the transmission and distribution rates that became effective in January 2002. Based on its 2001 revision of the 1998 stranded cost estimates, the Texas Utility Commission determined that CenterPoint Houston had over-mitigated its stranded costs by redirecting transmission and distribution depreciation and by accelerating depreciation of generation assets as provided under its 1998 transition plan and the Texas electric restructuring law. In the 2001 Final Order, CenterPoint Houston was required to reverse the amount of redirected depreciation and accelerated depreciation taken for regulatory purposes as allowed under the 1998 transition plan and the Texas electric restructuring law. In accordance with the 2001 Final Order, CenterPoint Houston recorded a regulatory liability to reflect the prospective refund of the accelerated depreciation, and in January 2002 CenterPoint Houston began paying excess mitigation credits, which were to be paid over a seven-year period with interest at 7 1/2% per annum. The annual payment of excess mitigation credits is approximately $264 million. In its December 2004 final order in the 2004 True-Up Proceeding, the Texas Utility Commission found that CenterPoint Houston did, in fact, have stranded costs (as originally estimated in 1998). Despite this ruling, the Texas Utility Commission denied CenterPoint Houston recovery of approximately $180 million of the interest portion of the excess mitigation credits already paid by CenterPoint Houston and refused to terminate future excess mitigation credits. In January 2005, CenterPoint Houston filed a writ of mandamus petition with the Texas Supreme Court asking that court to order the Texas Utility Commission to terminate immediately the payment of all excess mitigation credits and to ensure full recovery of all excess mitigation credits. Although CenterPoint Houston believes it has meritorious arguments, a writ of mandamus is an extraordinary remedy and no prediction can be made as to the ultimate outcome or timing of the mandamus petition. If the Supreme Court denies CenterPoint Houston's mandamus petition, it will continue to pursue this issue through regular appellate mechanisms. On March 1, 2005, a non-unanimous settlement was filed in Docket No. 30774, which involves the adjustment of RRI's Price-to-Beat. Under the terms of that settlement, the excess mitigation credits being paid by CenterPoint Houston would be terminated as of April 29, 2005. The Texas Utility Commission approved the settlement on March 9, 2005. (b) FINAL FUEL RECONCILIATION On March 4, 2004, an Administrative Law Judge (ALJ) issued a Proposal for Decision (PFD) relating to CenterPoint Houston's final fuel reconciliation. CenterPoint Houston reserved $117 million, including $30 million of interest, in the fourth quarter of 2003 reflecting the ALJ's recommendation. On April 15, 2004, the Texas Utility Commission affirmed the PFD's finding in part, reversed in part, and remanded one issue back to the ALJ. On May 28, 2004, the Texas Utility Commission approved a settlement of the remanded issue and issued a final order which reduced the disallowance. As a result of the final order, the Company reversed $23 million, including $8 million of interest, of the $117 million reserve recorded in the fourth quarter of 2003. The results of the Texas Utility Commission's final decision are a component of the 2004 True-Up Proceeding. The Company has appealed certain portions of the Texas Utility Commission's final order involving a disallowance of approximately $67 million relating to the final fuel reconciliation plus interest of $10 million. Briefs on this issue were filed on January 5, 2005, and a hearing on this issue is scheduled for April 22, 2005. (c) RATE CASES In 2004, the City of Houston, 28 other cities and the Railroad Commission of Texas (Railroad Commission) approved a settlement that increased Houston Gas' base rate and service charge revenues by approximately $14 million annually. In February 2004, the Louisiana Public Service Commission (LPSC) approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in its South Louisiana Division by approximately $2 million annually. 18
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In July 2004, Minnesota Gas filed an application for a general rate increase of $22 million with the Minnesota Public Utilities Commission (MPUC). Minnesota Gas and the Minnesota Department of Commerce have agreed to a settlement of all issues, including an annualized increase in the amount of $9 million, subject to approval by the MPUC. A final decision on this rate relief request is expected from the MPUC in the second quarter of 2005. Interim rates of $17 million on an annualized basis became effective on October 1, 2004, subject to refund. In July 2004, the LPSC approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in its North Louisiana Division by approximately $7 million annually. In October 2004, Southern Gas Operations filed an application for a general rate increase of approximately $3 million with the Railroad Commission for rate relief in the unincorporated areas of its Beaumont, East Texas and South Texas Divisions. The Railroad Commission staff has begun its review of the request, and a decision is anticipated in April 2005. In November 2004, Southern Gas Operations filed an application for a general rate increase of approximately $34 million with the Arkansas Public Service Commission (APSC). The APSC staff has begun its review of the request, and a decision is anticipated in the second half of 2005. In December 2004, the Oklahoma Corporation Commission approved a settlement that increased Southern Gas Operations' base rate and service charge revenues by approximately $3 million annually. (d) CITY OF TYLER, TEXAS DISPUTE In July 2002, the City of Tyler, Texas, asserted that Southern Gas Operations had overcharged residential and small commercial customers in that city for gas costs under supply agreements in effect since 1992. That dispute has been referred to the Railroad Commission by agreement of the parties for a determination of whether Southern Gas Operations has properly charged and collected for gas service to its residential and commercial customers in its Tyler distribution system in accordance with lawful filed tariffs during the period beginning November 1, 1992, and ending October 31, 2002. In December 2004, the Railroad Commission conducted a hearing on the matter and is expected to issue a ruling in March or April of 2005. In a parallel action now in the Court of Appeals in Austin, Southern Gas Operations is challenging the scope of the Railroad Commission's inquiry which goes beyond the issue of whether Southern Gas Operations had properly followed its tariffs to include a review of Southern Gas Operations' historical gas purchases. The Company believes such a review is not permitted by law and is beyond what the parties requested in the joint petition that initiated the proceeding at the Railroad Commission. The Company believes that all costs for Southern Gas Operations' Tyler distribution system have been properly included and recovered from customers pursuant to Southern Gas Operations' filed tariffs. (5) DERIVATIVE INSTRUMENTS The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative financial instruments such as physical forward contracts, swaps and options (Energy Derivatives) to mitigate the impact of changes in its natural gas businesses on its operating results and cash flows. (a) NON-TRADING ACTIVITIES Cash Flow Hedges. To reduce the risk from market fluctuations associated with purchased gas costs, the Company enters into energy derivatives in order to hedge certain expected purchases and sales of natural gas (non-trading energy derivatives). The Company applies hedge accounting for its non-trading energy derivatives utilized in non-trading activities only if there is a high correlation between price movements in the derivative and the item designated as being hedged. The Company analyzes its physical transaction portfolio 19
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) to determine its net exposure by delivery location and delivery period. Because the Company's physical transactions with similar delivery locations and periods are highly correlated and share similar risk exposures, the Company facilitates hedging for customers by aggregating physical transactions and subsequently entering into non-trading energy derivatives to mitigate exposures created by the physical positions. During 2004, hedge ineffectiveness of $0.4 million was recognized in earnings from derivatives that are designated and qualify as Cash Flow Hedges, and in 2003 and 2002, no hedge ineffectiveness was recognized. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive loss. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Company's Statements of Consolidated Operations under the caption "Natural Gas." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of December 31, 2004, the Company expects $5 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months. The maximum length of time the Company is hedging its exposure to the variability in future cash flows for forecasted transactions on existing financial instruments is primarily two years with a limited amount of exposure up to five years. The Company's policy is not to exceed five years in hedging its exposure. Other Derivative Financial Instruments. The Company also has natural gas contracts which are derivatives which are not hedged. Load following services that the Company offers its natural gas customers create an inherent tendency to be either long or short natural gas supplies relative to customer purchase commitments. The Company measures and values all of its volumetric imbalances on a real time basis to minimize its exposure to commodity price and volume risk. The aggregate Value at Risk (VaR) associated with these operations is calculated daily and averaged $0.2 million with a high of $1 million during 2004. The Company does not engage in proprietary or speculative commodity trading. Unhedged positions are accounted for by adjusting the carrying amount of the contracts to market and recognizing any gain or loss in operating income, net. During 2004, the Company recognized net gains related to unhedged positions amounting to $7 million and as of December 31, 2004 had recorded short-term risk management assets and liabilities of $4 million and $5 million, respectively, included in other current assets and other current liabilities, respectively. Interest Rate Swaps. As of December 31, 2003, the Company had an outstanding interest rate swap with a notional amount of $250 million to fix the interest rate applicable to floating-rate short-term debt. This swap, which expired in January 2004, did not qualify as a cash flow hedge under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), and was marked to market in the Company's Consolidated Balance Sheets with changes in market value reflected in interest expense in the Statements of Consolidated Operations. During 2002, the Company settled forward-starting interest rate swaps having an aggregate notional amount of $1.5 billion at a cost of $156 million, which was recorded in other comprehensive income and is being amortized into interest expense over the life of the designated fixed-rate debt. Amortization of amounts deferred in accumulated other comprehensive income for 2003 and 2004 was $12 million and $25 million, respectively. As of December 31, 2004, the Company expects $31 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months. Embedded Derivative. The Company's $575 million of convertible senior notes, issued May 19, 2003, and $255 million of convertible senior notes, issued December 17, 2003 (see Note 8), contain contingent interest provisions. The contingent interest component is an embedded derivative as defined by SFAS No. 133, and accordingly, must be split from the host instrument and recorded at fair value on the 20
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) balance sheet. The value of the contingent interest components was not material at issuance or at December 31, 2004. (b) CREDIT RISKS In addition to the risk associated with price movements, credit risk is also inherent in the Company's non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the non-trading derivative assets of the Company as of December 31, 2003 and 2004 (in millions):
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (b) ZENS In September 1999, the Company issued its 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. ZENS are exchangeable for cash equal to the market value of a specified number of shares of TW common. The Company pays interest on the ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the shares of TW Common attributable to the ZENS. The principal amount of ZENS is subject to being increased to the extent that the annual yield from interest and cash dividends on the reference shares of TW Common is less than 2.309%. At December 31, 2004, ZENS having an original principal amount of $840 million and a contingent principal amount of $851 million were outstanding and were exchangeable, at the option of the holders, for cash equal to 95% of the market value of 21.6 million shares of TW Common deemed to be attributable to the ZENS. At December 31, 2004, the market value of such shares was approximately $421 million, which would provide an exchange amount of $476 for each $1,000 original principal amount of ZENS. At maturity, the holders of the ZENS will receive in cash the higher of the original principal amount of the ZENS (subject to adjustment as discussed above) or an amount based on the then-current market value of TW Common, or other securities distributed with respect to TW Common. In 2002, holders of approximately 16% of the 17.2 million ZENS originally issued exercised their right to exchange their ZENS for cash, resulting in aggregate cash payments by CenterPoint Energy of approximately $45 million. Exchanges of ZENS subsequent to 2002 aggregate less than one percent of ZENS originally issued. A subsidiary of the Company owns shares of TW Common and elected to liquidate a portion of such holdings to facilitate the Company's making the cash payments for the ZENS exchanged in 2002 through 2004. In connection with the exchanges, the Company received net proceeds of approximately $43 million from the liquidation of approximately 4.1 million shares of TW Common at an average price of $10.56 per share. The Company now holds 21.6 million shares of TW Common which are classified as trading securities under SFAS No. 115 and are expected to be held to facilitate the Company's ability to meet its obligation under the ZENS. Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component (the holder's option to receive the appreciated value of TW Common at maturity). The derivative component was valued at fair value and determined the initial carrying value assigned to the debt component ($121 million) as the difference between the original principal amount of the ZENS ($1 billion) and the fair value of the derivative component at issuance ($879 million). Effective January 1, 2001 the debt component was recorded at its accreted amount of $122 million and the derivative component was recorded at its fair value of $788 million, as a current liability. Subsequently, the debt component accretes through interest charges at 17.5% annually up to the minimum amount payable upon maturity of the ZENS in 2029 (approximately $915 million) which reflects exchanges and adjustments to maintain a 2.309% annual yield, as discussed above. Changes in the fair value of the derivative component are recorded in the Company's Statements of Consolidated Operations. During 2002, 2003 and 2004, the Company recorded a loss of $500 million, a gain of $106 million and a gain of $31 million, respectively, on the Company's investment in TW Common. During 2002, 2003 and 2004, the Company recorded a gain of $480 million, a loss of $96 million and a loss of $20 million, respectively, associated with the fair value of the derivative component of the ZENS obligation. Changes in the fair value of the TW Common held by the Company are expected to substantially offset changes in the fair value of the derivative component of the ZENS. 22
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table sets forth summarized financial information regarding the Company's investment in TW securities and the Company's ZENS obligation (in millions).
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (11) COMMITMENTS AND CONTINGENCIES (a) FUEL COMMITMENTS Fuel commitments, excluding Texas Genco, include natural gas contracts related to the Company's natural gas distribution operations, which have various quantity requirements and durations that are not classified as non-trading derivatives assets and liabilities in the Company's Consolidated Balance Sheets as of December 31, 2004 as these contracts meet the SFAS No. 133 exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Minimum payment obligations for natural gas supply contracts are approximately $807 million in 2005, $401 million in 2006, $193 million in 2007, $29 million in 2008 and $1 million in 2009. 24
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (b) LEASE COMMITMENTS The following table sets forth information concerning the Company's obligations, excluding Texas Genco, under non-cancelable long-term operating leases at December 31, 2004, which primarily consist of rental agreements for building space, data processing equipment and vehicles (in millions):
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) in Clark County, in federal district courts in San Francisco, San Diego, Los Angeles, Fresno, Sacramento and Nevada and before the Ninth Circuit Court of Appeals. However, the Company, CenterPoint Houston and Reliant Energy were not participants in the electricity or natural gas markets in California. The Company and Reliant Energy have been dismissed from certain of the lawsuits, either voluntarily by the plaintiffs or by order of the court and the Company believes it is not a proper defendant in the remaining cases and will continue to seek dismissal from such remaining cases. On July 6, 2004 and on October 12, 2004, the Ninth Circuit affirmed the Company's removal to federal district court of two electric cases brought by the California Attorney General and affirmed the federal court's dismissal of these cases based upon the filed rate doctrine and federal preemption. Other Class Action Lawsuits. Fifteen class action lawsuits filed in May, June and July 2002 on behalf of purchasers of securities of RRI and/or Reliant Energy have been consolidated in federal district court in Houston. RRI and certain of its former and current executive officers are named as defendants. The consolidated complaint also names RRI , Reliant Energy, the underwriters of the initial public offering of RRI's common stock in May 2001 (RRI Offering), and RRI's and Reliant Energy's independent auditors as defendants. The consolidated amended complaint seeks monetary relief purportedly on behalf of purchasers of common stock of Reliant Energy or RRI during certain time periods ranging from February 2000 to May 2002, and purchasers of common stock that can be traced to the RRI Offering. The plaintiffs allege, among other things, that the defendants misrepresented their revenues and trading volumes by engaging in round-trip trades and improperly accounted for certain structured transactions as cash-flow hedges, which resulted in earnings from these transactions being accounted for as future earnings rather than being accounted for as earnings in fiscal year 2001. In January 2004 the trial judge dismissed the plaintiffs' allegations that the defendants had engaged in fraud, but claims based on alleged misrepresentations in the registration statement issued in the RRI Offering remain. In June 2004, the plaintiffs filed a motion for class certification, which the court granted in February 2005. The defendants have appealed the court's order certifying the class. In February 2003, a lawsuit was filed by three individuals in federal district court in Chicago against CenterPoint Energy and certain former officers of RRI for alleged violations of federal securities laws. The plaintiffs in this lawsuit allege that the defendants violated federal securities laws by issuing false and misleading statements to the public, and that the defendants made false and misleading statements as part of an alleged scheme to artificially inflate trading volumes and revenues. In addition, the plaintiffs assert claims of fraudulent and negligent misrepresentation and violations of Illinois consumer law. In January 2004 the trial judge ordered dismissal of plaintiffs' claims on the ground that they did not set forth a claim. The plaintiffs filed an amended complaint in March 2004, which the defendants asked the court to dismiss. On August 18, 2004, the court granted the defendants' motion to dismiss with prejudice. In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by Reliant Energy. Two of the lawsuits have been dismissed without prejudice. Reliant Energy and certain current and former members of its benefits committee are the remaining defendants in the third lawsuit. That lawsuit alleges that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by Reliant Energy, in violation of the Employee Retirement Income Security Act of 1974. The plaintiffs allege that the defendants permitted the plans to purchase or hold securities issued by Reliant Energy when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaint seeks monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held Reliant Energy or RRI securities, as well as restitution. In July 2004, another class action suit was filed in federal court on behalf of the Reliant Energy Savings Plan and a class consisting of participants in that plan against Reliant Energy and the Reliant Energy Benefits Committee. The allegations and the relief sought in the new suit are substantially similar to those in the previously pending suit; however, the new suit also alleges that Reliant Energy and its Benefits Committee breached their fiduciary duties to the Savings Plan and its participants by investing plan funds in 26
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Reliant Energy stock when Reliant Energy or its subsidiaries were allegedly manipulating the California energy market. On October 14, 2004, the plaintiff voluntarily dismissed the newly filed lawsuit. In October 2002, a derivative action was filed in the federal district court in Houston against the directors and officers of the Company. The complaint set forth claims for breach of fiduciary duty, waste of corporate assets, abuse of control and gross mismanagement. Specifically, the shareholder plaintiff alleged that the defendants caused the Company to overstate its revenues through so-called "round trip" transactions. The plaintiff also alleged breach of fiduciary duty in connection with the spin-off of RRI and the RRI Offering. The complaint sought monetary damages on behalf of the Company as well as equitable relief in the form of a constructive trust on the compensation paid to the defendants. The Company's board of directors investigated that demand and similar allegations made in a June 28, 2002 demand letter sent on behalf of a Company shareholder. The second letter demanded that the Company take several actions in response to alleged round-trip trades occurring in 1999, 2000, and 2001. In June 2003, the board determined that these proposed actions would not be in the best interests of the Company. In March 2003, the court dismissed this case on the grounds that the plaintiff did not make an adequate demand on the Company before filing suit. Thereafter, the plaintiff sent another demand asserting the same claims. The Company believes that none of the lawsuits described under Other Class Action Lawsuits has merit because, among other reasons, the alleged misstatements and omissions were not material and did not result in any damages to the plaintiffs. Other Legal Matters Texas Antitrust Actions. In July 2003, Texas Commercial Energy filed in federal court in Corpus Christi, Texas a lawsuit against Reliant Energy, the Company and CenterPoint Houston, as successors to Reliant Energy, Genco LP, RRI, Reliant Energy Solutions, LLC, several other RRI subsidiaries and a number of other participants in the Electric Reliability Council of Texas (ERCOT) power market. The plaintiff, a retail electricity provider with the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws and committed fraud and negligent misrepresentation. The lawsuit sought damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys' fees. The plaintiff's principal allegations had previously been investigated by the Texas Utility Commission and found to be without merit. In June 2004, the federal court dismissed the plaintiff's claims and in July 2004, the plaintiff filed a notice of appeal. The Company is vigorously contesting the appeal. The ultimate outcome of this matter cannot be predicted at this time. In February 2005, Utility Choice Electric filed in federal court in Houston, Texas a lawsuit against the Company, CenterPoint Houston, CenterPoint Energy Gas Services, Inc., CenterPoint Energy Alternative Fuels, Inc., Genco LP and a number of other participants in the ERCOT power market. The plaintiff, a retail electricity provider with the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws, intentionally interfered with prospective business relationships and contracts, and committed fraud and negligent misrepresentation. The plaintiff's principal allegations had previously been investigated by the Texas Utility Commission and found to be without merit. The Company intends to vigorously defend the case. The ultimate outcome of this matter cannot be predicted at this time. Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena (Three Cities) filed suit in state district court in Harris County, Texas for themselves and a proposed class of all similarly situated cities in Reliant Energy's electric service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly owned subsidiary of the Company's predecessor, Reliant Energy) alleging underpayment of municipal franchise fees. The plaintiffs claimed that they were entitled to 4% of all receipts of any kind for business conducted within these cities over the previous four decades. After a jury trial 27
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) involving the Three Cities' claims (but not the class of cities), the trial court entered a judgment on the Three Cities' breach of contract claims for $1.7 million, including interest, plus an award of $13.7 million in legal fees. It also decertified the class. Following this ruling, 45 cities filed individual suits against Reliant Energy in the District Court of Harris County. On February 27, 2003, a state court of appeals in Houston rendered an opinion reversing the judgment against the Company and rendering judgment that the Three Cities take nothing by their claims. The court of appeals held that all of the Three Cities' claims were barred by the jury's finding of laches, a defense similar to the statute of limitations, due to the Three Cities' having unreasonably delayed bringing their claims during the more than 30 years since the alleged wrongs began. The court also held that the Three Cities were not entitled to recover any attorneys' fees. The Three Cities filed a petition for review to the Texas Supreme Court, which declined to hear the case. Thus, the Three Cities' claims have been finally resolved in the Company's favor, but the individual claims of the 45 cities remain pending in the same court. Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in a suit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs, and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs' alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the Btu content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. CERC and its subsidiaries believe that there has been no systematic mismeasurement of gas and that the suits are without merit. CERC does not expect that the ultimate outcome will have a material impact on the financial condition or results of operations of either the Company or CERC. Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CERC, Entex Gas Marketing Company, and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. Subsequently the plaintiffs added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Gas Transmission Company, United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy Pipeline Services, Inc., and CenterPoint Energy Trading and Transportation Group, Inc. The plaintiffs allege that defendants inflated the prices charged to certain consumers of natural gas. In February 2003, a similar suit was filed in state court in Caddo Parish, Louisiana against CERC with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in 28
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) state court in Calcasieu Parish, Louisiana against CERC seeking to recover alleged overcharges for gas or gas services allegedly provided by Southern Gas Operations to a purported class of certain consumers of natural gas and gas service without advance approval by the LPSC. In October 2004, a similar case was filed in district court in Miller County, Arkansas against the Company, CERC, Entex Gas Marketing Company, CenterPoint Energy Gas Transmission Company, CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc., Mississippi River Transmission Corp. and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in at least the states of Arkansas, Louisiana, Mississippi, Oklahoma and Texas. At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish cases have been stayed pending the resolution of the respective proceedings by the LPSC. The plaintiffs in the Miller County case seek class certification, but the proposed class has not been certified. In November 2004, the Miller County case was removed to federal district court in Texarkana, Arkansas. In February 2005, the Wharton County case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs in the Wharton County case moved to dismiss the case and agreed not to refile the claims asserted unless the Miller County case is not certified as a class action or is later decertified. The range of relief sought by the plaintiffs in these cases includes injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages, civil penalties and attorney's fees. In these cases, the Company, CERC and their affiliates deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. The Company and CERC do not anticipate that the outcome of these matters will have a material impact on the financial condition or results of operations of either the Company or CERC. Texas Genco Shareholder Litigation. On July 23, 2004, two plaintiffs, both Texas Genco shareholders, filed virtually identical lawsuits in Harris County, Texas district court. These suits, purportedly brought on behalf of holders of Texas Genco common stock, name Texas Genco and each of that company's directors as defendants. Both plaintiffs allege, among other things, self-dealing and breach of fiduciary duty by the defendants in entering into the July 2004 agreement to sell Texas Genco. As part of their allegations of self-dealing, both plaintiffs claim that the board of directors of Texas Genco is controlled by CenterPoint Energy, that the defendants improperly concealed results of Texas Genco's results of operations for the second quarter of 2004 until after the transaction agreement was announced and that, in order to aid CenterPoint Energy, the Texas Genco board only searched for acquirers who would offer all-cash consideration. Plaintiffs seek to enjoin the transaction or, alternatively, rescind the transaction and/or recover damages in the event that the transaction is consummated. In August 2004, the cases were consolidated in state district court in Harris County, Texas. Although the defendants continue to deny liability, in February 2005, all parties entered into a Memorandum of Understanding to settle the lawsuit based upon supplemental disclosures made by Texas Genco and the extension of the deadline for the exercise of shareholder dissenters' rights. The settlement is subject to the parties' preparation of a stipulation of settlement and court approval of the settlement. ENVIRONMENTAL MATTERS Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. 29
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The Company believes the ultimate cost associated with resolving this matter will not have a material impact on the financial condition or results of operations of either the Company or CERC. Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory. CERC believes that it has no liability with respect to two of these sites. At December 31, 2004, CERC had accrued $18 million for remediation of certain Minnesota sites. At December 31, 2004, the estimated range of possible remediation costs for these sites was $7 million to $42 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of December 31, 2004, CERC has collected or accrued $13 million from insurance companies and ratepayers to be used for future environmental remediation. In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has not been named by these agencies as a PRP for any of those sites. CERC has been named as a defendant in lawsuits under which contribution is sought for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of those sites under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting those suits. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows. Asbestos. A number of facilities owned by the Company contain significant amounts of asbestos insulation and other asbestos-containing materials. The Company or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations owned by the Company, but most existing claims relate to facilities previously owned by the Company but currently owned by Texas Genco LLC. The Company anticipates that additional claims like those received may be 30
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) asserted in the future. Under the terms of the separation agreement between the Company and Texas Genco, ultimate financial responsibility for uninsured losses relating to these claims has been assumed by Texas Genco, but under the terms of its agreement to sell Texas Genco to Texas Genco LLC, the Company has agreed to continue to defend such claims to the extent they are covered by insurance maintained by the Company, subject to reimbursement of the costs of such defense from Texas Genco LLC. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, results of operations or cash flows. Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, results of operations or cash flows. OTHER PROCEEDINGS The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. TEXAS GENCO MATTERS Nuclear Insurance. Texas Genco and the other owners of the South Texas Project maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of the South Texas Project currently maintain $2.75 billion in property damage insurance coverage, which is above the legally required minimum, but is less than the total amount of insurance currently available for such losses. Under the Price Anderson Act, the maximum liability to the public of owners of nuclear power plants was $10.8 billion as of December 31, 2004. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations. Texas Genco and the other owners currently maintain the required nuclear liability insurance and participate in the industry retrospective rating plan under which the owners of the South Texas Project are subject to maximum retrospective assessments in the aggregate per incident of up to $100.6 million per reactor. The owners are jointly and severally liable at a rate not to exceed $10 million per reactor per year per incident. There can be no assurance that all potential losses or liabilities associated with the South Texas Project will be insurable, or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance would have a material effect on Texas Genco's financial condition, results of operations and cash flows. Nuclear Decommissioning. CenterPoint Houston, as collection agent for the nuclear decommissioning charge assessed on its transmission and distribution customers, contributed $2.9 million in 2004 to trusts established to fund Texas Genco's share of the decommissioning costs for the South Texas Project, and expects to contribute $2.9 million in 2005. There are various investment restrictions imposed upon Texas 31
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Genco by the Texas Utility Commission and the NRC relating to Texas Genco's nuclear decommissioning trusts. Texas Genco and CenterPoint Houston have each appointed two members to the Nuclear Decommissioning Trust Investment Committee which establishes the investment policy of the trusts and oversees the investment of the trusts' assets. The securities held by the trusts for decommissioning costs had an estimated fair value of $216 million as of December 31, 2004, of which approximately 36% were fixed-rate debt securities and the remaining 64% were equity securities. In May 2004, an outside consultant estimated Texas Genco's portion of decommissioning costs to be approximately $456 million. While the funding levels currently exceed minimum NRC requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and equipment. Pursuant to the Texas electric restructuring law, costs associated with nuclear decommissioning that were not recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be charged to transmission and distribution customers of CenterPoint Houston or its successor. 32