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) <TABLE> <S> <C> TEXAS (State or other jurisdiction of 74-0694415 incorporation or organization) (I.R.S. Employer Identification No.) </TABLE> <TABLE> <S> <C> 1111 LOUISIANA HOUSTON, TEXAS 77002 (713) 207-1111 (Address and zip code of principal (Registrant's telephone number, executive offices) including area code) </TABLE> ---------- 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 <TABLE> <S> <C> 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 </TABLE> 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) <TABLE> <CAPTION> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ------- ------ ------- ------ <S> <C> <C> <C> <C> 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 ======= ====== ======= ====== </TABLE> See Notes to the Company's Interim Financial Statements 1
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (MILLIONS OF DOLLARS) (UNAUDITED) ASSETS <TABLE> <CAPTION> DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- <S> <C> <C> 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 ======= ======= </TABLE> 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 <TABLE> <CAPTION> DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- <S> <C> <C> 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 ======= ======= </TABLE> See Notes to the Company's Interim Financial Statements 3
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (MILLIONS OF DOLLARS) (UNAUDITED) <TABLE> <CAPTION> NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2004 2005 -------- ------ <S> <C> <C> 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 </TABLE> 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): <TABLE> <CAPTION> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 2004 SEPTEMBER 30, 2004 ------------------ ------------------ <S> <C> <C> 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) </TABLE> 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 <TABLE> <CAPTION> AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST - ------------------------------ ----------------------------------------------- <S> <C> 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. </TABLE> FOR AWARDS GRANTED AS OF AND AFTER JANUARY 1, 2005 <TABLE> <CAPTION> AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST - ------------------------------ ----------------------------------------------- <S> <C> 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. </TABLE> 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 <TABLE> <CAPTION> OUTSTANDING OPTIONS THREE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------- SHARES WEIGHTED-AVERAGE (THOUSANDS) EXERCISE PRICE ----------- ---------------- <S> <C> <C> 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 ====== </TABLE> <TABLE> <CAPTION> NON-VESTED OPTIONS THREE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- <S> <C> <C> Outstanding at June 30, 2005........... 4,032 $1.76 Vested.............................. -- -- Canceled............................ -- -- ----- Outstanding at September 30, 2005...... 4,032 1.76 ===== </TABLE> 8
<TABLE> <CAPTION> OUTSTANDING OPTIONS NINE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------------------- REMAINING WEIGHTED- AVERAGE AGGREGATE AVERAGE CONTRACTUAL INTRINSIC SHARES EXERCISE LIFE VALUE (THOUSANDS) PRICE (YEARS) (MILLIONS) ----------- --------- ----------- ---------- <S> <C> <C> <C> <C> 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 ====== </TABLE> <TABLE> <CAPTION> NON-VESTED OPTIONS NINE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- <S> <C> <C> 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 ====== </TABLE> PERFORMANCE SHARES <TABLE> <CAPTION> OUTSTANDING AND NON-VESTED SHARES THREE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- <S> <C> <C> 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 ===== </TABLE> <TABLE> <CAPTION> OUTSTANDING SHARES NINE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------- REMAINING AVERAGE AGGREGATE CONTRACTUAL INTRINSIC SHARES LIFE VALUE (THOUSANDS) (YEARS) (MILLIONS) ----------- ----------- ---------- <S> <C> <C> <C> 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 ===== </TABLE> <TABLE> <CAPTION> NON-VESTED OPTIONS NINE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- <S> <C> <C> 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 ===== </TABLE> 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 <TABLE> <CAPTION> OUTSTANDING AND NON-VESTED UNITS THREE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE UNITS GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- <S> <C> <C> Outstanding at June 30, 2005................. 35 $100.00 Canceled.................................. (1) -- Vested and released to participants....... -- -- --- Outstanding at September 30, 2005............ 34 100.00 === </TABLE> <TABLE> <CAPTION> 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) ----------- ---------- ----------- ---------- <S> <C> <C> <C> <C> 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 === </TABLE> 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 <TABLE> <CAPTION> OUTSTANDING AND NON-VESTED SHARES THREE MONTHS ENDED SEPTEMBER 30, 2005 ------------------------------------- WEIGHTED-AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------------- <S> <C> <C> 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 === </TABLE> <TABLE> <CAPTION> 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) ----------- ---------- ----------- ---------- <S> <C> <C> <C> <C> 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 === </TABLE> 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: <TABLE> <CAPTION> THREE MONTHS ENDED SEPTEMBER 30, -------------------------------- 2004 2005 ------ ------ <S> <C> <C> Options....................... $ -- $ -- Performance units............. -- -- Performance shares............ -- -- Time-based restricted stock... 11.42 13.34 </TABLE> 10
<TABLE> <CAPTION> NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2004 2005 ------- ----- <S> <C> <C> Options ...................... $ 1.86 $ -- Performance units ............ 100.00 -- Performance shares ........... -- 12.13 Time-based restricted stock .. 10.94 12.25 </TABLE> The total intrinsic value of awards received by participants were as follows for the three and nine months ended September 30, 2004 and 2005: <TABLE> <CAPTION> THREE MONTHS ENDED SEPTEMBER 30, -------------------------------- 2004 2005 ---- ---- (IN MILLIONS) <S> <C> <C> Options exercised... $1 $3 </TABLE> <TABLE> <CAPTION> NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2004 2005 ---- ---- (IN MILLIONS) <S> <C> <C> Options exercised.... $3 $7 Performance shares... 7 5 </TABLE> 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: <TABLE> <CAPTION> THREE MONTHS ENDED SEPTEMBER 30, ----------------------------------------------------- 2004 2005 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN MILLIONS) <S> <C> <C> <C> <C> 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 ==== === ==== === </TABLE> 11
<TABLE> <CAPTION> NINE MONTHS ENDED SEPTEMBER 30, ----------------------------------------------------- 2004 2005 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN MILLIONS) <S> <C> <C> <C> <C> 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 ==== ==== ===== === </TABLE> 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): <TABLE> <CAPTION> DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- <S> <C> <C> Natural Gas Distribution .. $1,085 $1,085 Pipelines and Gathering ... 601 604 Other Operations .......... 55 55 ------ ------ Total .................. $1,741 $1,744 ====== ====== </TABLE> 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: <TABLE> <CAPTION> DECEMBER 31, 2004 SEPTEMBER 30, 2005 ----------------------- ----------------------- CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION -------- ------------ -------- ------------ (IN MILLIONS) <S> <C> <C> <C> <C> Land use rights .................................... $55 $(12) $55 $(13) Other .............................................. 21 (6) 21 (7) --- ---- --- ---- Total ........................................... $76 $(18) $76 $(20) === ==== === ==== </TABLE> 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): <TABLE> <S> <C> 2005 ...... $-- 2006 ...... 3 2007 ...... 3 2008 ...... 3 2009 ...... 3 2010 ...... 2 --- Total .. $14 === </TABLE> (8) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income (net of tax): <TABLE> <CAPTION> FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------------- ------------------------- 2004 2005 2004 2005 ------- ---- ------- ---- (IN MILLIONS) <S> <C> <C> <C> <C> 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 ======= === ======= ==== </TABLE> 18
The following table summarizes the components of accumulated other comprehensive loss: <TABLE> <CAPTION> DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- (IN MILLIONS) <S> <C> <C> 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) ==== ==== </TABLE> (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: <TABLE> <CAPTION> 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) <S> <C> <C> <C> <C> <C> HL&P Capital Trust II... $100 $100 8.257% February 2037 8.257% Junior Subordinated Deferrable Interest Debentures Series B </TABLE> 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: <TABLE> <CAPTION> 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) <S> <C> <C> <C> <C> 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 ============ ============ ============ ============ </TABLE> - ---------- (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: <TABLE> <CAPTION> FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2004 --------------------------------------------- REVENUES FROM NET EXTERNAL INTERSEGMENT OPERATING CUSTOMERS REVENUES INCOME (LOSS) ------------- ------------ ------------- (IN MILLIONS) <S> <C> <C> <C> 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 ====== ==== ==== </TABLE> 30
<TABLE> <CAPTION> FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005 ----------------------------------------------------- REVENUES FROM NET INTERSEGMENT OPERATING EXTERNAL CUSTOMERS REVENUES INCOME (LOSS) ------------------ ---------------- ------------- (IN MILLIONS) <S> <C> <C> <C> 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 ====== ==== ==== </TABLE> <TABLE> <CAPTION> 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) <S> <C> <C> <C> <C> 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 ====== ===== ==== ======= </TABLE> <TABLE> <CAPTION> 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) <S> <C> <C> <C> <C> 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 ====== ===== ==== ======= </TABLE> - ---------- (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. <TABLE> <CAPTION> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ------- ------ ------- ------ <S> <C> <C> <C> <C> 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 ======= ====== ======= ====== </TABLE> 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. <TABLE> <CAPTION> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ---- ---- ---- ---- (IN MILLIONS) <S> <C> <C> <C> <C> 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 ==== ==== ==== ==== </TABLE> 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: <TABLE> <CAPTION> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ----------------------- 2004 2005 2004 2005 ---------- ---------- ---------- ---------- (IN MILLIONS, EXCEPT CUSTOMER DATA) <S> <C> <C> <C> <C> 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 </TABLE> - ---------- (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: <TABLE> <CAPTION> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ----------------------- 2004 2005 2004 2005 ---------- ---------- ---------- ---------- (IN MILLIONS, EXCEPT CUSTOMER DATA) <S> <C> <C> <C> <C> 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 ========== ========== ========== ========== </TABLE> - ---------- (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
<TABLE> <CAPTION> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ------ ------ ------- ------ (IN MILLIONS) <S> <C> <C> <C> <C> 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 ==== ==== ==== ==== </TABLE> - ---------- (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: <TABLE> <CAPTION> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ---- ---- ---- ---- (IN MILLIONS) <S> <C> <C> <C> <C> Revenues ................. $ 2 $4 $ 8 $ 15 Expenses ................. 6 2 25 27 --- --- ---- ---- Operating Income (Loss) .. $(4) $2 $(17) $(12) === === ==== ==== </TABLE> 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: <TABLE> <CAPTION> NINE MONTHS ENDED SEPTEMBER 30, ----------------- 2004 2005 ----- ----- (IN MILLIONS) <S> <C> <C> Cash provided by (used in): Operating activities ...... $ 354 $ 364 Investing activities ...... (304) 204 Financing activities ...... (117) (571) </TABLE> 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): <TABLE> <CAPTION> AMOUNT UTILIZED AT DATE EXECUTED COMPANY SIZE OF FACILITY NOVEMBER 1, 2005 TERMINATION DATE - ------------- ------------------- ---------------- ------------------ ---------------- <S> <C> <C> <C> <C> 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 </TABLE> - ---------- (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: <TABLE> <CAPTION> MOODY'S S&P FITCH ------------------- ------------------- ------------------- COMPANY/INSTRUMENT RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3) - ------------------ ------ ---------- ------ ---------- ------ ---------- <S> <C> <C> <C> <C> <C> <C> 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 </TABLE> - ---------- (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. <TABLE> <CAPTION> SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- <S> <C> <C> <C> <C> <C> 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 </TABLE> 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. <TABLE> <CAPTION> SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- <S> <C> <C> <C> <C> <C> 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 </TABLE> 58
<TABLE> <CAPTION> SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- -------------- --------- <S> <C> <C> <C> <C> <C> 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) </TABLE> 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 <TABLE> <CAPTION> SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- <S> <C> <C> <C> <C> <C> 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 </TABLE> <TABLE> <CAPTION> SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- <S> <C> <C> <C> <C> <C> 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 </TABLE> 61
<TABLE> <CAPTION> SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- -------------- --------- <S> <C> <C> <C> <C> <C> 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) </TABLE> 62