-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, FYrNihp7bGLs+SPXdzZfoof+ketrz8XqRehCtrJw0YPD07MyOw8u1ECiMDRmQRmt kpU2Nq8ivvkAwpYR2jz67w== 0000950129-06-004889.txt : 20060504 0000950129-06-004889.hdr.sgml : 20060504 20060504083437 ACCESSION NUMBER: 0000950129-06-004889 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 20060331 FILED AS OF DATE: 20060504 DATE AS OF CHANGE: 20060504 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTERPOINT ENERGY INC CENTRAL INDEX KEY: 0001130310 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 740694415 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-31447 FILM NUMBER: 06806077 BUSINESS ADDRESS: STREET 1: 1111 LOUISIANA ST. CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7132073000 MAIL ADDRESS: STREET 1: 1111 LOUISIANA ST. CITY: HOUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: RELIANT ENERGY REGCO INC DATE OF NAME CHANGE: 20001220 10-Q 1 h35607e10vq.txt CENTERPOINT ENERGY, INC. - 3/31/2006 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 MARCH 31, 2006 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______________ TO _______________. ---------- Commission file number 1-31447 CENTERPOINT ENERGY, INC. (Exact name of registrant as specified in its charter) TEXAS 74-0694415 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization)
1111 LOUISIANA HOUSTON, TEXAS 77002 (713) 207-1111 (Address and zip code of principal (Registrant's telephone number, executive offices) including area code)
---------- Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] 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 May 1, 2006, CenterPoint Energy, Inc. had 311,378,251 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 MARCH 31, 2006 TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Item 1. Financial Statements...................................... 1 Condensed Statements of Consolidated Income Three Months Ended March 31, 2005 and 2006 (unaudited)...... 1 Condensed Consolidated Balance Sheets December 31, 2005 and March 31, 2006 (unaudited)............ 2 Condensed Statements of Consolidated Cash Flows Three Months Ended March 31, 2005 and 2006 (unaudited)...... 4 Notes to Unaudited Condensed Consolidated Financial Statements.................................................. 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................... 24 Item 3. Quantitative and Qualitative Disclosures about Market Risk................................................... 36 Item 4. Controls and Procedures................................... 37 PART II. OTHER INFORMATION Item 1. Legal Proceedings......................................... 38 Item 1A. Risk Factors............................................. 38 Item 5. Other Information......................................... 38 Item 6. Exhibits.................................................. 38
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, including, in particular, the results of appeals to the courts of determinations on rulings obtained to date; - state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, 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 and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment; - 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, 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 ability of RRI to satisfy its obligations to us, including indemnity obligations; ii - 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 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2005, which is incorporated herein by reference. 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 CONDENSED STATEMENTS OF CONSOLIDATED INCOME (MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
THREE MONTHS ENDED MARCH 31, --------------- 2005 2006 ------ ------ REVENUES ............................................... $2,595 $3,077 ------ ------ EXPENSES: Natural gas ......................................... 1,781 2,193 Operation and maintenance ........................... 313 331 Depreciation and amortization ....................... 130 140 Taxes other than income taxes ....................... 95 107 ------ ------ Total ......................................... 2,319 2,771 ------ ------ OPERATING INCOME ....................................... 276 306 ------ ------ OTHER INCOME (EXPENSE): Loss on Time Warner investment ...................... (41) (14) Gain on indexed debt securities ..................... 39 10 Interest and other finance charges .................. (173) (115) Interest on transition bonds ........................ (9) (33) Return on true-up balance ........................... 34 -- Other, net .......................................... 4 6 ------ ------ Total ......................................... (146) (146) ------ ------ INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES .. 130 160 Income tax expense .................................. (63) (72) ------ ------ INCOME FROM CONTINUING OPERATIONS ...................... 67 88 ------ ------ DISCONTINUED OPERATIONS: Income from Texas Genco, net of tax .............. 14 -- Loss on disposal of Texas Genco, net of tax ...... (14) -- ------ ------ Total ......................................... -- -- ------ ------ NET INCOME ............................................. $ 67 $ 88 ====== ====== BASIC EARNINGS PER SHARE: Income from Continuing Operations ................... $ 0.22 $ 0.28 Discontinued Operations, net of tax ................. -- -- ------ ------ Net Income .......................................... $ 0.22 $ 0.28 ====== ====== DILUTED EARNINGS PER SHARE: Income from Continuing Operations ................... $ 0.20 $ 0.28 Discontinued Operations, net of tax ................. -- -- ------ ------ Net Income .......................................... $ 0.20 $ 0.28 ====== ======
See Notes to the Company's Interim Condensed Financial Statements 1 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (MILLIONS OF DOLLARS) (UNAUDITED) ASSETS
DECEMBER 31, MARCH 31, 2005 2006 ------------ --------- CURRENT ASSETS: Cash and cash equivalents ....................... $ 74 $ 113 Investment in Time Warner common stock .......... 377 363 Accounts receivable, net ........................ 1,098 924 Accrued unbilled revenues ....................... 608 329 Natural gas inventory ........................... 294 106 Materials and supplies .......................... 88 88 Non-trading derivative assets ................... 131 88 Taxes receivable ................................ 53 -- Prepaid expenses and other current assets ....... 168 177 ------- ------- Total current assets ......................... 2,891 2,188 ------- ------- PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment ................... 11,558 11,664 Less accumulated depreciation and amortization .. (3,066) (3,093) ------- ------- Property, plant and equipment, net ........... 8,492 8,571 ------- ------- OTHER ASSETS: Goodwill ........................................ 1,709 1,709 Other intangibles, net .......................... 56 56 Regulatory assets ............................... 2,955 2,934 Non-trading derivative assets ................... 104 70 Other ........................................... 909 888 ------- ------- Total other assets ........................... 5,733 5,657 ------- ------- TOTAL ASSETS .............................. $17,116 $16,416 ======= =======
See Notes to the Company's Interim Condensed Financial Statements 2 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS - (CONTINUED) (MILLIONS OF DOLLARS) (UNAUDITED) LIABILITIES AND SHAREHOLDERS' EQUITY
DECEMBER 31, MARCH 31, 2005 2006 ------------ --------- CURRENT LIABILITIES: Current portion of transition bond long-term debt ..................... $ 73 $ 126 Current portion of other long-term debt ............................... 266 519 Indexed debt securities derivative .................................... 292 283 Accounts payable ...................................................... 1,161 606 Taxes accrued ......................................................... 167 124 Interest accrued ...................................................... 122 138 Non-trading derivative liabilities .................................... 43 66 Accumulated deferred income taxes, net ................................ 385 418 Other ................................................................. 505 385 ------- ------- Total current liabilities .......................................... 3,014 2,665 ------- ------- OTHER LIABILITIES: Accumulated deferred income taxes, net ................................ 2,474 2,440 Unamortized investment tax credits .................................... 46 44 Non-trading derivative liabilities .................................... 35 54 Benefit obligations ................................................... 475 460 Regulatory liabilities ................................................ 728 785 Other ................................................................. 480 392 ------- ------- Total other liabilities ............................................ 4,238 4,175 ------- ------- LONG-TERM DEBT: Transition bonds ...................................................... 2,407 2,335 Other ................................................................. 6,161 5,896 ------- ------- Total long-term debt ............................................... 8,568 8,231 ------- ------- COMMITMENTS AND CONTINGENCIES (NOTE 10) SHAREHOLDERS' EQUITY: Common stock (310,324,739 shares and 311,343,935 shares outstanding at December 31, 2005 and March 31, 2006, respectively) ............. 3 3 Additional paid-in capital ............................................ 2,931 2,944 Accumulated deficit ................................................... (1,600) (1,558) Accumulated other comprehensive loss .................................. (38) (44) ------- ------- Total shareholders' equity ......................................... 1,296 1,345 ------- ------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ...................... $17,116 $16,416 ======= =======
See Notes to the Company's Interim Condensed Financial Statements 3 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (MILLIONS OF DOLLARS) (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ---------------------------- 2005 2006 ----- ----- CASH FLOWS FROM OPERATING ACTIVITIES: Net income ...................................................... $ 67 $ 88 Discontinued operations, net of tax ............................. -- -- ----- ----- Income from continuing operations ............................... 67 88 Adjustments to reconcile income from continuing operations to net cash provided by (used in) operating activities: Depreciation and amortization ................................ 130 140 Amortization of deferred financing costs ..................... 20 14 Deferred income taxes ........................................ 50 6 Investment tax credit ........................................ (2) (2) Unrealized loss on Time Warner investment .................... 41 14 Unrealized gain on indexed debt securities ................... (40) (10) Changes in other assets and liabilities: Accounts receivable and unbilled revenues, net ............ 215 472 Inventory ................................................. 101 129 Taxes receivable .......................................... -- 53 Accounts payable .......................................... (177) (534) Fuel cost over (under) recovery/surcharge ................. 76 63 Non-trading derivatives, net .............................. (56) 19 Margin deposits, net ...................................... (4) (79) Interest and taxes accrued ................................ (464) (27) Net regulatory assets and liabilities ..................... (86) 23 Other current assets ...................................... 43 7 Other current liabilities ................................. (57) (47) Other assets .............................................. (1) 14 Other liabilities ......................................... (40) (51) Other, net ................................................... 4 23 ----- ----- Net cash provided by (used in) operating activities of continuing operations ............................ (180) 315 Net cash used in operating activities of discontinued operations .......................................... (22) -- ----- ----- Net cash provided by (used in) operating activities .... (202) 315 ----- ----- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures ............................................ (131) (186) Decrease in restricted cash of Texas Genco ...................... 383 -- Purchase of minority interest in Texas Genco .................... (383) -- Decrease in cash of Texas Genco ................................. 11 -- Other, net ...................................................... 2 (15) ----- ----- Net cash used in investing activities .................. (118) (201) ----- ----- CASH FLOWS FROM FINANCING ACTIVITIES: Increase in short-term borrowings, net .......................... 75 -- Long-term revolving credit facilities, net ...................... 472 (3) Payments of long-term debt ...................................... (23) (27) Debt issuance costs ............................................. (6) (2) Payment of common stock dividends ............................... (62) (47) Proceeds from issuance of common stock, net ..................... 4 3 Other, net ...................................................... -- 1 ----- ----- Net cash provided by (used in) financing activities .... 460 (75) ----- ----- NET INCREASE IN CASH AND CASH EQUIVALENTS .......................... 140 39 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ................... 165 74 ----- ----- CASH AND CASH EQUIVALENTS AT END OF PERIOD ......................... $ 305 $ 113 ===== ===== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest, net of capitalized interest ........................... $ 183 $ 125 Income taxes (refunds), net ..................................... 435 (1)
See Notes to the Company's Interim Condensed Financial Statements 4 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONDENSED 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 condensed consolidated interim financial statements and notes (Interim Condensed 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, 2005 (CenterPoint Energy Form 10-K). Background. CenterPoint Energy 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 was a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (the 1935 Act). The Energy Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February 8, 2006. The Energy Act includes a new Public Utility Holding Company Act of 2005 (PUHCA 2005), which 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 the FERC and state regulatory authorities in certain circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA 2005 that will require the Company to notify the FERC of its status as a holding company and to maintain certain books and records and make these available to the FERC. On April 24, 2006, the FERC considered motions for rehearing of these rules and proposed to adopt additional rules regarding maintenance of books and records by utility holding companies. 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 March 31, 2006, 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. 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 primarily to commercial and industrial customers and electric and gas utilities. Basis of Presentation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and 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 Condensed Statements of Consolidated Income 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 relate to a new reportable business segment discussed in Note 12 and do not affect net income. 5 (2) DISCONTINUED OPERATIONS In July 2004, the Company announced its agreement to sell its majority owned subsidiary, Texas Genco Holdings, Inc. (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, following receipt of approval from the Nuclear Regulatory Commission (NRC). The Company recorded after-tax income of $13.6 million from Texas Genco's operations in the first quarter of 2005. The Company recorded a loss of $13.2 million to offset these earnings in the first quarter of 2005. General corporate overhead of $0.4 million previously allocated to Texas Genco from the Company, which was not eliminated by the sale of Texas Genco, was excluded from income from discontinued operations in the first quarter of 2005 and was 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 these operations as discontinued operations in accordance with SFAS No. 144. Revenues related to Texas Genco included in discontinued operations for the three months ended March 31, 2005 were $57 million. Income from these discontinued operations for the three months ended March 31, 2005 is reported net of income tax expense of $6 million. (3) EMPLOYEE BENEFIT PLANS The Company's net periodic cost includes the following components relating to pension and postretirement benefits:
THREE MONTHS ENDED MARCH 31, ----------------------------------------------------- 2005 2006 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN MILLIONS) Service cost ........................... $ 9 $ 1 $ 9 $ 1 Interest cost .......................... 23 7 24 6 Expected return on plan assets ......... (34) (3) (35) (3) Amortization of prior service cost ..... (2) -- (2) -- Amortization of net loss ............... 12 -- 11 -- Amortization of transition obligation .. -- 2 -- 2 Benefit enhancement .................... -- -- 8 1 ---- --- ---- --- Net periodic cost ...................... $ 8 $ 7 $ 15 $ 7 ==== === ==== ===
The Company expects to contribute approximately $26 million to its postretirement benefits plan in 2006, of which $6 million had been contributed as of March 31, 2006. Contributions to the pension plan are not required in 2006. 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 for each of the three-month periods ended March 31, 2005 and 2006 was $2 million. On January 5, 2006, the Company offered a Voluntary Early Retirement Program (VERP) to approximately 200 employees who were age 55 or older with at least five years of service as of February 28, 2006. The election period was from January 5, 2006 through February 28, 2006. For those electing to accept the VERP, three years of age and service was added to their qualified pension plan benefit and three years of service was added to their postretirement benefit. An additional pension and postretirement expense of approximately $9 million was recorded in the first quarter of 2006 and is reflected in the table above as a benefit enhancement. 6 (4) REGULATORY MATTERS (a) RECOVERY OF TRUE-UP BALANCE In March 2004, CenterPoint Houston filed its true-up application with the Public Utility Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas electric restructuring law. 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. In August 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the True-Up Order, but reversed two of the Texas Utility Commission's rulings. The judgment would have the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston's initial request. CenterPoint Houston and other parties appealed the district court decisions. Briefs have been filed with the 3rd Court of Appeals in Austin but oral argument has not yet been scheduled. No amounts related to the district court's judgment have been recorded in the consolidated financial statements. Among the issues raised in CenterPoint Houston's appeal of the True-Up Order is the Texas Utility Commission's reduction of CenterPoint Houston's stranded cost recovery by approximately $146 million for the present value of certain deferred tax benefits associated with its former electric generation assets. Such reduction was considered in the Company's recording of an after-tax extraordinary loss of $977 million in the last half of 2004. The Company believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 related to those tax benefits. Those proposed regulations would have allowed utilities which were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes back to customers. However, in December 2005, the IRS withdrew those proposed normalization regulations and issued new proposed regulations that do not include the provision allowing a retroactive election to pass the tax benefits back to customers. If the December 2005 proposed regulations become effective and if the Texas Utility Commission's order on this issue is not reversed on appeal or the amount of the tax benefits is not otherwise restored by the Texas Utility Commission, the IRS is likely to consider that a "normalization violation" has occurred. If so, the IRS could require the Company to pay an amount equal to CenterPoint Houston's unamortized ADITC balance as of the date that the normalization violation was deemed to have occurred. In addition, if a normalization violation is deemed to have occurred, the IRS could also deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits. If a normalization violation should ultimately be found to exist, it could have an adverse impact on the Company's results of operations, financial condition and cash flows. However, the Company and CenterPoint Houston are vigorously pursuing the appeal of this issue and will seek other relief from the Texas Utility Commission to avoid a normalization violation. The Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation. 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). Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed in all respects in August 2005 by the same Travis County District Court considering the appeal of the True-Up Order, in December 2005, a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84 percent to 5.30 percent and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued. In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC which will collect approximately $596 million over 14 years plus interest at an annual rate of 11.075 percent (CTC Order). 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 without a 7 return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. 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. During the three months ended March 31, 2006, CenterPoint Houston recognized approximately $17 million in CTC operating income. As of March 31, 2006, the Company has not recorded an allowed equity return of $245 million on its true-up balance because such return is being recognized as it is recovered in the future. Certain parties appealed the CTC Order to the Travis County Court in September 2005. Oral argument was held in April 2006, and a decision is expected in the second quarter of 2006. 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. In January 2006, the Texas Utility Commission staff (Staff) proposed that the Texas Utility Commission adopt new rules governing the carrying charges on unrecovered true-up balances. If the Texas Utility Commission adopts the rule as the Staff proposed it and the rule is deemed to apply to CenterPoint Houston, the rule would reduce carrying costs on the unrecovered CTC balance prospectively from 11.075 percent to the utility's cost of debt. (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 in 2003 plus interest of $10 million. A judgment was entered by a Travis County court in May 2005 affirming the Texas Utility Commission's decision. CenterPoint Houston filed an appeal to the 3rd Court of Appeals in Austin in June 2005. Oral arguments were held in April 2006, and a decision is expected by the end of 2006. (c) REMAND OF 2001 UNBUNDLED COST OF SERVICE ORDER The 3rd Court of Appeals in Austin remanded to the Texas Utility Commission an issue that was decided by the Texas Utility Commission in CenterPoint Houston's 2001 unbundled cost of service proceeding. In its remand order, the court ruled that the Texas Utility Commission had failed to adequately explain its basis for its determination of certain projected transmission capital expenditures. The Court of Appeals ordered the Texas Utility Commission to reconsider that determination on the basis of the record that existed at the time of the Texas Utility Commission's original order. In April 2006, the Texas Utility Commission indicated its intent to enter an order in the remand proceeding to reduce CenterPoint Houston's rate base associated with those expenditures. The Texas Utility Commission instructed its Staff to quantify the reduction in rate base attributable to the transmission investment and to develop requirements for compliance filings in order to reduce rates going forward and to establish a temporary tariff to return the over-collected amount due to the past inclusion of the full amount for such transmission investment. The Texas Utility Commission's Staff has not yet announced the result of those calculations. CenterPoint Houston anticipates that the indicated ruling by the Texas Utility Commission would reduce its rate base associated with these capital expenditures by approximately $57 million, though it is not possible for CenterPoint Houston to quantify the amount of any refund obligation or reduction to its tariffs until the Staff completes its calculations and the Texas Utility Commission has entered a formal order. The Company and CenterPoint Houston continue to believe that the original record before the Texas Utility Commission supports the rates set by the Texas Utility Commission in its 2001 order. If the Texas Utility Commission ultimately issues an order based on its indicated decision, CenterPoint Houston plans to seek a rehearing of that determination and, if that is unsuccessful, may pursue further judicial review of this matter. No prediction can be made at this time as to the ultimate outcome of this matter on remand or the amount of any rate reduction or refund obligation. If the Texas Utility Commission's indicated ruling on this issue ultimately is entered and upheld on appeal, it could have a material adverse impact on the Company's and CenterPoint Houston's financial condition, results of operations or cash flows. 8 (d) RATE CASES NATURAL GAS DISTRIBUTION SOUTHERN GAS OPERATIONS Louisiana In October 2005, Southern Gas Operations filed for a $2 million Rate Regulation Adjustment (RRA) increase in its South Louisiana service area and a $2 million RRA decrease in its North Louisiana service area. Both adjustments have been implemented, but are subject to review and revision by the Louisiana Public Service Commission. Mississippi In February 2006, the Mississippi Public Service Commission (MPSC) approved a $1 million increase in miscellaneous service charges for Southern Gas Operations and in March 2006, it approved an RRA resulting in a $2 million increase in general service rates. The MPSC is also reviewing a January 2006 application for a one-time recovery of approximately $2 million of costs related to Hurricane Katrina. A decision on the application is expected in the second quarter of 2006. Oklahoma In March 2006, Oklahoma Gas filed and then revised its filing under its performance-based rate change tariff. The revised filing reflected a decrease of approximately $1 million in revenue. The Oklahoma Corporation Commission staff is currently reviewing this filing and a decision is expected in the second quarter of 2006. Texas In April 2005, the Railroad Commission of Texas (Railroad Commission) established new gas tariffs 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 same rates within the incorporated cities located in the two divisions. The proposed rates were approved or became effective by operation of law in all but five of these cities, which cities denied the rate change requests. Southern Gas Operations appealed the actions of these five cities to the Railroad Commission. Additionally, 19 cities where new rates had already gone into effect subsequently challenged the jurisdictional and statutory basis for implementation of those rates. Southern Gas Operations petitioned the Railroad Commission for an order declaring that the new rates had been properly established within these 19 cities. In April 2006, Southern Gas Operations reached tentative agreements with the last of the cities that are parties to the Railroad Commission proceedings. The agreements anticipate the dismissal or settlement of the Railroad Commission actions and the implementation of the settlement rates. Once all settlement rates are implemented in all jurisdictions including unincorporated areas, Southern Gas Operations' base rates and miscellaneous service charges are expected to increase by a total of $17 million annually over the pre-April 2005 levels. Approximately $4 million of this increase was reflected in the Company's 2005 revenues. The Company expects approximately $16 million will be reflected in revenues in 2006, and the total $17 million will be reflected in revenues in 2007. The settlements also provide that these new rates will not change over the next three to five years. MINNESOTA GAS In April 2006, Minnesota Gas revised its gas cost filing for the twelve months ended June 30, 2005, which had not yet been approved by the Minnesota Public Utilities Commission (MPUC). Minnesota Gas refined its unbilled revenue estimate to more accurately reflect the effect of lost and unaccounted for gas. As a result, Minnesota Gas determined that its gas costs for the gas cost years ended June 30, 2001 through June 30, 2005 were understated. Minnesota Gas's revised gas cost filing requested approximately $9 million in 9 additional recovery for the twelve months ended June 30, 2005. The amended filing also requested recovery of approximately $13 million related to the period from July 1, 2000 through June 30, 2004 and a waiver from the MPUC rules allowing recovery of such costs, since the gas costs for those years had been previously approved. The filing proposes recovery of the 2001-2004 costs over a 3-year period beginning in 2007. In November 2005, Minnesota Gas filed a request with the MPUC to increase annual rates by approximately $41 million. In December 2005, the MPUC approved an interim rate increase of approximately $35 million that was implemented January 1, 2006. Any excess of amounts collected under the interim rates over the amounts approved in final rates is subject to refund to customers. A hearing was held in April 2006 and a decision is expected by the MPUC in 2006. In December 2004, the MPUC opened an investigation to determine whether Minnesota Gas' 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. In June 2005, the Minnesota Office of the Attorney General (OAG) issued its report alleging Minnesota Gas had violated the CWR and recommended a $5 million penalty. In addition, in June 2005, CERC was named in a suit filed in the United States District Court, District of Minnesota on behalf of a purported class of customers who allege that Minnesota Gas' conduct under the CWR was in violation of the law. On March 28, 2006 the court gave preliminary approval to a $13.5 million settlement which, if ultimately approved by the court following a hearing, will resolve all claims against Minnesota Gas which have or could have been asserted by residential natural gas customers in the CWR class action. If also approved by the MPUC, the settlement will resolve the claims made by the OAG. During the fourth quarter 2005, CERC established a litigation reserve to cover the anticipated settlement costs under the terms of this settlement. ELECTRIC TRANSMISSION & DISTRIBUTION The Texas Utility Commission requires each electric utility to file 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. In May 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. In October 2005, the Staff filed a memorandum summarizing its review of the Earnings Reports filed by electric utilities. Based on its review, the Staff concluded that continuation of CenterPoint Houston's rates could result in excess retail transmission and distribution revenues of as much as $105 million and excess wholesale transmission revenues of as much as $31 million annually and recommended that the Texas Utility Commission initiate a review of the reasonableness of existing rates. The Staff's analysis was based on a 9.60 percent cost of equity, which is 165 basis points lower than the approved return on equity from CenterPoint Houston's last rate proceeding, the elimination of interest on debt that matured in November 2005 and certain other adjustments to CenterPoint Houston's reported information. Additionally, a hypothetical capital structure of 60 percent debt and 40 percent equity was used which varies materially from the actual capital structure of CenterPoint Houston's regulated transmission and distribution utility as of December 31, 2005 of approximately 50 percent debt and 50 percent equity. In December 2005, the Texas Utility Commission considered the Staff report and agreed to initiate a rate proceeding concerning the reasonableness of CenterPoint Houston's existing rates for transmission and distribution service and to require CenterPoint Houston to make a filing by April 15, 2006 to justify or change those rates. In April 2006, CenterPoint Houston filed cost data and other information that supports a rate increase of $50 million or 3.7 percent to the retail electric providers (REPs) that sell electricity to end-use customers in the Houston area. The filing also supports a $43.1 million increase for CenterPoint Houston's wholesale transmission customers, which include other utilities throughout the state. CenterPoint Houston used a 2005 test year adjusted for updated cost data where appropriate. The data reflects the $700 million that CenterPoint Houston has invested during the last few years for new structures, power lines and related equipment to continue to operate a reliable network as well as certain transmission interconnect projects that are currently in the planning stages. It also includes the increase in franchise fees that CenterPoint Houston is 10 paying the City of Houston under the recently adopted franchise ordinance which allows the company to provide its electric delivery services within the City during the next thirty years. In addition, recognizing the catastrophic damage to the facilities of other electric utilities caused by hurricanes in 2004 and 2005, CenterPoint Houston is proposing an increase to its storm reserve as well as an increase in depreciation rates. Finally, CenterPoint Houston filed testimony supporting its 11.25% return on equity and a 50% debt/50% equity capital structure. A procedural schedule has yet to be set but a final order is expected around mid-October 2006. (e) 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. In May 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. In August 2005, the City of Tyler appealed this order to the Travis County District Court. In April 2006, the Company and the City of Tyler reached a tentative agreement which anticipates the dismissal of the District Court appeal. Once the appeal is dismissed, the Railroad Commission's final order and its findings are not subject to further review or modification. (5) DERIVATIVE INSTRUMENTS The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative financial instruments such as physical forward contracts, swaps and options (Energy Derivatives) to mitigate the impact of changes in its natural gas businesses on its operating results and cash flows. (a) NON-TRADING ACTIVITIES Cash Flow Hedges. During the three months ended March 31, 2006, hedge ineffectiveness was a gain of $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 previously 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 Condensed Statements of Consolidated Income under the "Expense" caption "Natural Gas." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Condensed Statements of Consolidated Cash Flows in the same category as the item being hedged. As of March 31, 2006, the Company expects $4 million ($3 million after-tax) in accumulated other comprehensive loss to be reclassified as an increase in Natural Gas expense during the next twelve months. The maximum length of time the Company is hedging its exposure to the variability in future cash flows using financial instruments is primarily two years with a limited amount of exposure up to ten years. The Company's policy is not to exceed ten years in hedging its exposure. Other Derivative Financial Instruments. 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 enters into physical and financial forward natural gas contracts to manage these load following natural gas supply requirements. These forward natural gas contracts are derivatives which are not designated as hedges and are accounted for on a mark-to-market basis with changes in fair value reported through earnings. While the Company also utilizes derivative instruments to manage physical commodity price risks, it does not engage in proprietary or speculative commodity trading. During the three months ended March 31, 2006, the Company recognized net gains related to these positions amounting to $10 million. As of March 31, 2006, the Company had recorded short-term assets of $14 million and short-term liabilities of $21 million related to these derivative contracts, included in non-trading derivative assets and liabilities, respectively, in the Condensed Consolidated Balance Sheets. 11 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 five-year life of the designated fixed-rate debt. Amortization of amounts deferred in accumulated other comprehensive loss for each of the three-month periods ended March 31, 2005 and 2006 was $8 million. As of March 31, 2006, the Company expects $31 million ($20 million after-tax) in accumulated other comprehensive loss to be amortized during the next twelve months. Embedded Derivative. The Company's 3.75% and 2.875% 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 March 31, 2006. (6) GOODWILL AND INTANGIBLES Goodwill by reportable business segment is as follows (in millions):
DECEMBER 31, MARCH 31, 2005 2006 ------------ --------- Natural Gas Distribution .................... $ 746 $ 746 Pipelines and Field Services ................ 604 604 Competitive Natural Gas Sales and Services .. 339 339 Other Operations ............................ 20 20 ------ ------ Total .................................... $1,709 $1,709 ====== ======
The components of the Company's other intangible assets consist of the following:
DECEMBER 31, 2005 MARCH 31, 2006 ----------------------- ----------------------- CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION -------- ------------ -------- ------------ (IN MILLIONS) Land Use Rights .. $55 $(14) $55 $(14) Other ............ 22 (7) 22 (7) --- ---- --- ---- Total ......... $77 $(21) $77 $(21) === ==== === ====
Amortization expense for other intangibles for each of the three-month periods ended March 31, 2005 and 2006 was less than $1 million. Estimated amortization expense for the remainder of 2006 and the five succeeding fiscal years is as follows (in millions): 2006 ........ $ 2 2007 ........ 3 2008 ........ 3 2009 ........ 2 2010 ........ 2 2011 ........ 2 --- Total .... $14 ===
12 (7) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income (net of tax):
FOR THE THREE MONTHS ENDED MARCH 31, -------------------- 2005 2006 ---- ---- (IN MILLIONS) Net income .......................................... $67 $88 --- --- Other comprehensive income: Net deferred gain (loss) from cash flow hedges ... 9 (3) Reclassification of deferred loss (gain) from cash flow hedges realized in net income ............ 6 (3) --- --- Other comprehensive income (loss) ................... 15 (6) --- --- Comprehensive income ................................ $82 $82 === ===
The following table summarizes the components of accumulated other comprehensive loss:
DECEMBER 31, MARCH 31, 2005 2006 ------------ --------- (IN MILLIONS) Minimum pension liability adjustment ........ $(15) $(15) Net deferred loss from cash flow hedges ..... (23) (29) ---- ---- Total accumulated other comprehensive loss .. $(38) $(44) ==== ====
(8) 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, 2005, 310,324,905 shares of CenterPoint Energy common stock were issued and 310,324,739 shares of CenterPoint Energy common stock were outstanding. At March 31, 2006, 311,344,101 shares of CenterPoint Energy common stock were issued and 311,343,935 shares of CenterPoint Energy common stock were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2005 and March 31, 2006. (9) LONG-TERM DEBT AND RECEIVABLES FACILITY (a) LONG-TERM DEBT Revolving Credit Facilities. In March 2006, the Company, CenterPoint Houston and CERC Corp., entered into amended and restated bank credit facilities. The Company replaced its $1 billion five-year revolving credit facility with a $1.2 billion five-year revolving credit facility. The facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 60 basis points based on the Company's current credit ratings, as compared to LIBOR plus 87.5 basis points for borrowings under the facility it replaced. The facility contains covenants, including a debt to earnings before interest, taxes, depreciation and amortization covenant. CenterPoint Houston replaced its $200 million five-year revolving credit facility with a $300 million five-year revolving credit facility. The facility has a first drawn cost of LIBOR plus 45 basis points based on CenterPoint Houston's current credit ratings, as compared to LIBOR plus 75 basis points for borrowings under the facility it replaced. The facility contains covenants, including a debt, excluding transition bonds, to total capitalization covenant of 65%. CERC Corp. replaced its $400 million five-year revolving credit facility with a $550 million five-year revolving credit facility. The facility has a first drawn cost of LIBOR plus 45 basis points based on CERC Corp.'s current credit ratings, as compared to LIBOR plus 55 basis points for borrowings under the facility it replaced. The facility contains covenants, including a debt to total capitalization covenant of 65%. Under each of the credit facilities, an additional utilization fee of 10 basis points applies to borrowings any time more than 50% of the facility is utilized, and the spread to LIBOR fluctuates based on the borrower's credit rating. 13 Borrowings under each of the facilities are subject to customary terms and conditions. However, there is no requirement that the Company, CenterPoint Houston or CERC Corp. make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the credit facilities are subject to acceleration upon the occurrence of events of default that the Company, CenterPoint Houston or CERC Corp. consider customary. As of March 31, 2006, the Company had no borrowings and approximately $29 million of outstanding letters of credit under its $1.2 billion credit facility, CenterPoint Houston had no borrowings and approximately $3 million of outstanding letters of credit under its $300 million credit facility and CERC Corp. had no borrowings under its $550 million credit facility. Additionally, the Company, CenterPoint Houston and CERC Corp. were in compliance with all covenants as of March 31, 2006. Convertible Debt. On May 19, 2003, the Company issued $575 million aggregate principal amount of convertible senior notes due May 15, 2023 with an interest rate of 3.75%. Holders may convert each of their notes into shares of CenterPoint Energy common stock at a conversion rate of 87.4094 shares of common stock per $1,000 principal amount of notes at any time prior to maturity, under the following circumstances: (1) if 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 previous calendar quarter is greater than or equal to 120% or, following May 15, 2008, 110% of the conversion price per share of CenterPoint Energy common stock on such last trading day, (2) if the notes have been called for redemption, (3) during any period in which the credit ratings assigned to the notes by both Moody's Investors Service, Inc. (Moody's) and Standard & Poor's Ratings Services (S&P), a division of The McGraw-Hill Companies, are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least one of these ratings services or their successors, or (4) upon the occurrence of specified corporate transactions, including the distribution to all holders of CenterPoint Energy common stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at less than the last reported sale price of a share of CenterPoint Energy common stock on the trading day prior to the declaration date of the distribution or the distribution to all holders of CenterPoint Energy common stock of the Company's assets, debt securities or certain rights to purchase the Company's securities, which distribution has a per share value exceeding 15% of the last reported sale price of a share of CenterPoint Energy common stock on the trading day immediately preceding the declaration date for such distribution. The notes originally had a conversion rate of 86.3558 shares of common stock per $1,000 principal amount of notes. However, effective February 16, 2006, the conversion rate increased to 87.4094 in accordance with the terms of the notes due to an increase in the amount of the dividend per common share paid by the Company in the first quarter of 2006. Holders have the right to require the Company to purchase all or any portion of the notes for cash on May 15, 2008, May 15, 2013 and May 15, 2018 for a purchase price equal to 100% of the principal amount of the notes. The convertible senior notes also have a contingent interest feature requiring contingent interest to be paid to holders of notes commencing on or after May 15, 2008, in the event that the average trading price of a note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of the note as of the day immediately preceding the first day of the applicable six-month interest period. For any six-month period, contingent interest will be equal to 0.25% of the average trading price of the note for the applicable five-trading-day period. 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. Under the terms of the New Notes, which are substantially similar to the Old Notes, settlement of the principal portion will be made in cash rather than stock. On December 17, 2003, the Company issued $255 million aggregate principal amount of convertible senior notes due January 15, 2024 with an interest rate of 2.875%. Holders may convert each of their notes into shares of CenterPoint Energy common stock at a conversion rate of 79.0165 shares of common stock per $1,000 principal amount of notes at any time prior to maturity, under the following circumstances: (1) if 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 previous calendar quarter is greater than or equal to 120% of the conversion price per share of CenterPoint Energy common stock on such last trading day, (2) if the notes have been called for redemption, (3) during any period in which the credit ratings assigned to the notes by both Moody's and S&P are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least one of these ratings services or their 14 successors, or (4) upon the occurrence of specified corporate transactions, including the distribution to all holders of CenterPoint Energy common stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at less than the last reported sale price of a share of CenterPoint Energy common stock on the trading day prior to the declaration date of the distribution or the distribution to all holders of CenterPoint Energy common stock of the Company's assets, debt securities or certain rights to purchase the Company's securities, which distribution has a per share value exceeding 15% of the last reported sale price of a share of CenterPoint Energy common stock on the trading day immediately preceding the declaration date for such distribution. The notes originally had a conversion rate of 78.064 shares of common stock per $1,000 principal amount of notes. However, effective February 16, 2006, the conversion rate increased to 79.0165 in accordance with the terms of the notes due to an increase in the amount of the dividend per common share paid by the Company in the first quarter of 2006. Under the original terms of these convertible senior notes, CenterPoint Energy could elect to satisfy part or all of its conversion obligation by delivering cash in lieu of shares of CenterPoint Energy. On December 13, 2004, the Company entered into a supplemental indenture with respect to these convertible senior notes in order to eliminate its right to settle the conversion of the notes solely in shares of its common stock. Holders have the right to require the Company to purchase all or any portion of other the notes for cash on January 15, 2007, January 15, 2012 and January 15, 2017 for a purchase price equal to 100% of the principal amount of the notes. As of March 31, 2006, these notes were classified as current portion of other long-term debt in the Condensed Consolidated Balance Sheets. The convertible senior notes also have a contingent interest feature requiring contingent interest to be paid to holders of notes commencing on or after January 15, 2007, in the event that the average trading price of a note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of the note as of the day immediately preceding the first day of the applicable six-month interest period. For any six-month period, contingent interest will be equal to 0.25% of the average trading price of the note for the applicable five-trading-day period. 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, 2005 and March 31, 2006. 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 March 31, 2006, no interest payments on the junior subordinated debentures had been deferred. The outstanding aggregate liquidation amount, distribution rate and mandatory redemption date of the capital securities of the trust described above and the identity and similar terms of the related series of junior subordinated debentures are as follows:
AGGREGATE LIQUIDATION DISTRIBUTION MANDATORY AMOUNTS AS OF RATE/ REDEMPTION DECEMBER 31, MARCH 31, INTEREST DATE/ TRUST 2005 2006 RATE MATURITY DATE JUNIOR SUBORDINATED DEBENTURES ----- ------------ --------- ------------ ------------- ------------------------------ (IN MILLIONS) HL&P Capital Trust II... $100 $100 8.257% February 2037 8.257% Junior Subordinated Deferrable Interest Debentures Series B
15 (B) RECEIVABLES FACILITY In January 2006, CERC's $250 million receivables facility was extended to January 2007. As of March 31, 2006, CERC had $141 million of advances under its receivables facility. The facility was temporarily increased to $375 million for the period from January 2006 to June 2006 to provide additional liquidity to CERC during the peak heating season of 2006. Advances under the receivables facility averaged $181 million and $141 million for the three months ended March 31, 2005 and 2006, respectively. Sales of receivables were approximately $520 million and $346 million for the three months ended March 31, 2005 and 2006, respectively. (10) COMMITMENTS AND CONTINGENCIES (A) CAPITAL COMMITMENTS In October 2005, CenterPoint Energy Gas Transmission Company (CEGT), a wholly owned subsidiary of CERC Corp., signed a 10-year firm transportation agreement with XTO Energy (XTO) to transport 600 million cubic feet (MMcf) per day of natural gas from Carthage, Texas to CEGT's Perryville hub in Northeast Louisiana. To accommodate this transaction, CEGT filed a certificate application with the FERC in March 2006 to build a 172 mile, 42-inch diameter pipeline, and related compression facilities at an estimated cost of $425 million. The capacity of the pipeline under this filing will be 1.275 billion cubic feet (Bcf) per day. CEGT has signed firm contracts for substantially the full capacity of the pipeline. CERC will consider an expansion of the pipeline pending the outcome of an open season announced in late April 2006. During the four-year period subsequent to the in-service date of the pipeline, XTO can request, and subject to mutual negotiations that meet specific financial parameters, CEGT would construct a 67 mile extension from CEGT's Perryville hub to an interconnect with Texas Eastern Gas Transmission at Union Church, Mississippi. (B) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS 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 Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (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 federal court in California, Nevada and Kansas and in state court 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 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. 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. 16 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 court in San Diego County, in Nevada state court in Clark 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. To date, several of the electricity complaints have been dismissed, and several of the dismissals have been affirmed by appellate courts. Others have been resolved by the settlement described in the following paragraph. Four of the gas complaints have also been dismissed based on defendants' claims of federal preemption and the filed rate doctrine, and these dismissals have been appealed. In June 2005, a San Diego state court refused to dismiss other gas complaints on the same basis. The other gas cases remain in the early procedural stages. On August 12, 2005, RRI reached a settlement with the FERC enforcement staff, 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 has been approved by the FERC and by the California Public Utilities Commission, and now must be approved by the courts in which the class action cases are pending. This approval is expected in the second quarter of 2006. A party in the FERC proceedings has filed a motion for rehearing of the FERC's order approving the settlement, upon which the FERC has yet to rule. 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. 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 were dismissed without prejudice. In the remaining lawsuit, the Company and certain current and former members of its benefits committee are defendants. That lawsuit alleged 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 by permitting 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 sought 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. In January 2006, the federal district judge granted a motion for summary judgment filed by the Company and the individual defendants. The plaintiffs have filed an appeal of the ruling to the Fifth Circuit Court of Appeals. The Company believes that this lawsuit is without merit and will continue to vigorously defend the case. However, the ultimate outcome of this matter cannot be predicted at this time. Other Legal Matters 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 17 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 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 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. 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 4(e). 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. Pursuant to an order from the Minnesota Office of Pipeline Safety, CERC substantially completed removal of certain non-code-compliant components from a portion of its distribution system by December 2, 2005. The components were installed by a predecessor company, which was not affiliated with CERC during the period in which the components were installed. In November 2005, Minnesota Gas filed a request with the MPUC to recover the capitalized expenditures (approximately $39 million) and related expenses, together with a return on the capitalized portion through rates as part of its existing rate case as further discussed in Note 4(d). Minnesota Cold Weather Rule. In December 2004, the MPUC opened an investigation to determine whether Minnesota Gas' practices regarding restoring natural gas service during the Cold Weather Period are in compliance with the MPUC's CWR, which governs disconnection and reconnection of customers during the Cold Weather 18 Period. In June 2005, the Minnesota OAG issued its report alleging Minnesota Gas had violated the CWR, and recommended a $5 million penalty. In addition, in June 2005, CERC was named in a suit filed in the United States District Court, District of Minnesota on behalf of a purported class of customers who allege that Minnesota Gas' conduct under the CWR was in violation of the law. In March 2006, the court gave preliminary approval to a $13.5 million settlement which, if ultimately approved by the court following a hearing, will resolve all claims against Minnesota Gas which have or could have been asserted by residential natural gas customers in the CWR class action. If also approved by the MPUC, the settlement will resolve the claims made by the OAG. During the fourth quarter 2005, CERC established a litigation reserve to cover the anticipated settlement costs under the terms of this settlement. ENVIRONMENTAL MATTERS Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating liquid hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, including the cost of restoring their property to its original condition and damages for diminution of value of their property. In addition, plaintiffs 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 March 31, 2006, CERC had accrued $14 million for remediation of these Minnesota sites. At March 31, 2006, the estimated range of possible remediation costs for these sites was $4 million to $35 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 March 31, 2006, CERC has collected $13 million from insurance companies and rate payers 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 filed in United States District Court, District of Maine and Middle District of Florida, Jacksonville Division 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. 19 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. The Company has found this type of contamination 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 is not known at this time, based on the Company's experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows. Asbestos. Facilities owned by the Company contain or have contained 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 or its subsidiaries. The Company anticipates that additional claims like those received may be asserted in the future. In 2004, the Company sold its generating business, to which most of these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP. Under the terms of the arrangements regarding separation of the generating business from the Company and its sale to Texas Genco LLC, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by Texas Genco LLC and its successor, but 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 the purchaser. 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. 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. TAX CONTINGENCIES CenterPoint Energy's consolidated federal income tax returns have been audited and settled through the 1996 tax year. In the audits of the 1997 through 2003 tax years, the IRS disallowed all deductions for original issue discount (OID) including interest paid relating to the Company's 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS), and the interest paid on the 7% Automatic Common Exchange Securities (ACES), redeemed in 1999. It is the contention of the IRS that (1) those instruments, in combination with the Company's long position in Time Warner Inc. 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 those positions, none of the OID and interest paid on the ZENS and 20 ACES would be currently deductible but would instead be added to the Company's basis in the TW Common it holds. The capitalization of OID and interest 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 disallowance of the ZENS and ACES OID and interest paid, reserves have been established for the tax and interest on this issue totaling $121 million and $135 million as of December 31, 2005 and March 31, 2006, respectively. The Company has also established reserves for other significant tax items including issues relating to prior acquisitions and dispositions of business operations and certain positions taken with respect to state tax filings. The total amount reserved for the other tax items is approximately $60 million and $56 million as of December 31, 2005 and March 31, 2006, respectively. GUARANTEES Prior to CenterPoint Energy's distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI's trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guarantee obligations prior to separation, but when separation occurred in September 2002, RRI had been unable to extinguish all obligations. To secure CenterPoint Energy and CERC against obligations under the remaining guarantees, RRI agreed to provide cash or letters of credit for the benefit of CERC and CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guarantees. The Company's current exposure under the remaining guarantees relates to CERC's guarantee of the payment by RRI of demand charges related to transportation contracts with one counterparty. The demand charges are approximately $53 million per year in 2006 through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018. As a result of changes in market conditions, CenterPoint Energy's potential exposure under that guarantee currently exceeds the security provided by RRI. CenterPoint Energy has requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of CERC's obligations under the guarantee, and CenterPoint Energy and RRI are pursuing other alternatives. RRI continues to meet its obligations under the transportation contracts. NUCLEAR DECOMMISSIONING FUND COLLECTIONS Pursuant to regulatory requirements and its tariff, CenterPoint Houston, as collection agent, collects from its transmission and distribution customers the nuclear decommissioning charge assessed with respect to the 30.8% ownership interest in the South Texas Project which it owned when it was part of an integrated electric utility. Amounts collected are transferred to nuclear decommissioning trusts maintained by the current owner of that interest in the South Texas Project. During 2003 and 2004, $2.9 million was transferred each year and $3.2 million was transferred in 2005. There are various investment restrictions imposed on owners of nuclear generating stations by the Texas Utility Commission and the NRC relating to nuclear decommissioning trusts. Pursuant to the provisions of both a separation agreement and a final order of the Texas Utility Commission, relating to the 2005 transfer of ownership to Texas Genco LLC, (which is now known as NRG Texas LP, or "NRG"), CenterPoint Houston and a subsidiary of NRG are presently jointly administering the decommissioning funds through the Nuclear Decommissioning Trust Investment Committee. NRG and CenterPoint Houston have each appointed two members to the Nuclear Decommissioning Trust Investment Committee which establishes the investment policy of the trusts and oversees the investment of the trusts' assets. As administrators of the decommissioning funds, CenterPoint Houston and NRG are jointly responsible for assuring that the funds are prudently invested in a manner consistent with the rules of the Texas Utility Commission. On February 2, 2006, CenterPoint Houston and a subsidiary of Texas Genco filed a request with the Texas Utility Commission to name the Texas Genco subsidiary as the sole fund administrator. That application is now being pursued in the name of NRG and is currently pending before an Administrative Law Judge. 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. CenterPoint Houston does not collect a nuclear decommissioning charge with respect to the additional 12.8% ownership interest in the South Texas Project that Texas Genco LLC acquired subsequent to its acquisition of the Company's generation facilities. 21 (11) EARNINGS PER SHARE The following table reconciles numerators and denominators of the Company's basic and diluted earnings per share calculations:
THREE MONTHS ENDED MARCH 31, --------------------------- 2005 2006 ------------ ------------ (IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS) Basic earnings per share calculation: Income from continuing operations ................... $ 67 $ 88 Discontinued operations, net of tax ................. -- -- ------------ ------------ Net income .......................................... $ 67 $ 88 ============ ============ Weighted average shares outstanding .................... 308,470,000 310,846,000 ============ ============ Basic earnings per share: Income from continuing operations ................... $ 0.22 $ 0.28 Discontinued operations, net of tax ................. -- -- ------------ ------------ Net income .......................................... $ 0.22 $ 0.28 ============ ============ Diluted earnings per share: Net income .......................................... $ 67 $ 88 Plus: Income impact of assumed conversions: Interest on 3.75% convertible senior notes ....... 4 -- ------------ ------------ Total earnings effect assuming dilution ............. $ 71 $ 88 ============ ============ Weighted average shares outstanding .................... 308,470,000 310,846,000 Plus: Incremental shares from assumed conversions: Stock options (1) ................................ 1,293,000 1,216,000 Restricted stock ................................. 1,189,000 957,000 2.875% convertible senior notes .................. -- 150,000 3.75% convertible senior notes ................... 49,655,000 5,424,000 6.25% convertible trust preferred securities ..... 16,000 -- ------------ ------------ Weighted average shares assuming dilution ........... 360,623,000 318,593,000 ============ ============ Diluted earnings per share: Income from continuing operations ................... $ 0.20 $ 0.28 Discontinued operations, net of tax ................. -- -- ------------ ------------ Net income .......................................... $ 0.20 $ 0.28 ============ ============
- ---------- (1) Options to purchase 9,851,111 and 8,425,822 shares were outstanding for the three months ended March 31, 2005 and 2006, respectively, but were not included in the computation of diluted earnings per share because the options' exercise price was greater than the average market price of the common shares for the respective periods. 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 (subsequent to the August 2005 exchange discussed in Note 9) 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 $12.66 and $11.44, respectively. (12) 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 accounting policies of the business segments 22 are the same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to business segments. The Company uses operating income as the measure of profit or loss for its business segments. The Company's reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Pipelines and Field Services (formerly Pipelines and Gathering) and Other Operations. The electric transmission and distribution function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. The Company reorganized the oversight of its Natural Gas Distribution business segment and, as a result, beginning in the fourth quarter of 2005, the Company established a new reportable business segment, Competitive Natural Gas Sales and Services. Competitive Natural Gas Sales and Services represents the Company's non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. Pipelines and Field Services includes the interstate natural gas pipeline operations and the natural gas gathering and pipeline services businesses. Other Operations consists primarily of other corporate operations which support all of the Company's business operations. All prior period segment information has been reclassified to conform to the 2006 presentation. Long-lived assets include net property, plant and equipment, net goodwill and other intangibles and equity investments in unconsolidated subsidiaries. Intersegment sales are eliminated in consolidation. Financial data for business segments and products and services are as follows (in millions):
FOR THE THREE MONTHS ENDED MARCH 31, 2005 -------------------------------------------------------- TOTAL ASSETS REVENUES FROM NET INTERSEGMENT OPERATING INCOME AS OF DECEMBER 31, EXTERNAL CUSTOMERS REVENUES (LOSS) 2005 ------------------ ---------------- ---------------- ------------------ Electric Transmission & Distribution ........ $ 345(1) $ -- $ 80 $ 8,227 Natural Gas Distribution .................... 1,329 -- 123 4,612 Competitive Natural Gas Sales and Services .. 832 93 16 1,849 Pipelines and Field Services ................ 84 37 64 2,968 Other Operations ............................ 5 2 (7) 2,202(2) Eliminations ................................ -- (132) -- (2,742) ------ ----- ---- ------- Consolidated ................................ $2,595 $ -- $276 $17,116 ====== ===== ==== =======
FOR THE THREE MONTHS ENDED MARCH 31, 2006 -------------------------------------------------------- TOTAL ASSETS REVENUES FROM NET INTERSEGMENT OPERATING INCOME AS OF MARCH 31, EXTERNAL CUSTOMERS REVENUES (LOSS) 2006 ------------------ ---------------- ---------------- --------------- Electric Transmission & Distribution ........ $ 385(1) $ -- $110 $ 8,201 Natural Gas Distribution .................... 1,477 3 103 4,169 Competitive Natural Gas Sales and Services .. 1,126 37 25 1,379 Pipelines and Field Services ................ 87 38 73 2,973 Other Operations ............................ 2 2 (5) 1,970(2) Eliminations ................................ -- (80) -- (2,276) ------ ---- ---- ------- Consolidated ................................ $3,077 $ -- $306 $16,416 ====== ==== ==== =======
- ---------- (1) Sales to subsidiaries of RRI in the three months ended March 31, 2005 and 2006 represented approximately $183 million and $162 million, respectively. (2) Included in total assets of Other Operations as of December 31, 2005 and March 31, 2006 is a pension asset of $654 million and $639 million, respectively. (13) SUBSEQUENT EVENT On April 28, 2006, the Company's board of directors declared a regular quarterly cash dividend of $0.15 per share of common stock payable on June 9, 2006, to shareholders of record as of the close of business on May 16, 2006. 23 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 DEBT FINANCING TRANSACTIONS In March 2006, we, CenterPoint Houston and CERC Corp. entered into amended and restated bank credit facilities. We replaced our $1 billion five-year revolving credit facility with a $1.2 billion five-year revolving credit facility. The facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 60 basis points based on our current credit ratings, as compared to LIBOR plus 87.5 basis points for borrowings under the facility it replaced. CenterPoint Houston replaced its $200 million five-year revolving credit facility with a $300 million five-year revolving credit facility. The facility has a first drawn cost of LIBOR plus 45 basis points based on CenterPoint Houston's current credit ratings, as compared to LIBOR plus 75 basis points for borrowings under the facility it replaced. CERC Corp. replaced its $400 million five-year revolving credit facility with a $550 million five-year revolving credit facility. The facility has a first drawn cost of LIBOR plus 45 basis points based on CERC Corp.'s current credit ratings, as compared to LIBOR plus 55 basis points for borrowings under the facility it replaced. Under each of the credit facilities, an additional utilization fee of 10 basis points applies to borrowings any time more than 50% of the facility is utilized, and the spread to LIBOR fluctuates based on the borrower's credit rating. CONSOLIDATED RESULTS OF OPERATIONS All dollar amounts in the tables that follow are in millions, except for per share amounts.
THREE MONTHS ENDED MARCH 31, --------------- 2005 2006 ------ ------ Revenues ............................................... $2,595 $3,077 Expenses ............................................... 2,319 2,771 ------ ------ Operating Income ....................................... 276 306 Interest and Other Finance Charges ..................... (182) (148) Other Income, net ...................................... 36 2 ------ ------ Income From Continuing Operations Before Income Taxes .. 130 160 Income Tax Expense ..................................... (63) (72) ------ ------ Income From Continuing Operations ...................... 67 88 Discontinued Operations, net of tax .................... -- -- ------ ------ Net Income ............................................. $ 67 $ 88 ====== ====== BASIC EARNINGS PER SHARE: Income From Continuing Operations ................... $ 0.22 $ 0.28 Discontinued Operations, net of tax ................. -- -- ------ ------ Net Income .......................................... $ 0.22 $ 0.28 ====== ====== DILUTED EARNINGS PER SHARE: Income From Continuing Operations ................... $ 0.20 $ 0.28 Discontinued Operations, net of tax ................. -- -- ------ ------ Net Income .......................................... $ 0.20 $ 0.28 ====== ======
24 THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005 Income from Continuing Operations. We reported income from continuing operations of $88 million ($0.28 per diluted share) for the three months ended March 31, 2006 as compared to $67 million ($0.20 per diluted share) for the same period in 2005. The increase in income from continuing operations of $21 million was primarily due to: - increased operating income of $9 million in our Pipelines and Field Services 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 Competitive Natural Gas Sales and Services business segment primarily due to higher sales to utilities and favorable basis differentials over the pipeline capacity that we control, partially offset by a write-down of natural gas inventory to the lower of average cost or market due to the decline in natural gas prices during the first quarter of 2006; - a $7 million increase in operating income from the regulated utility operations of our Electric Transmission & Distribution business segment primarily due to continued customer growth and recovery of our 2004 true-up balance through the competition transition charge (CTC) and a gain from the sale of land, partially offset by milder weather and decreased usage, higher transmission costs, severance associated with staff reductions in the first quarter of 2006 and increased franchise fees paid to the City of Houston; and - a $58 million decrease in interest expense due to lower borrowing costs and borrowing levels, excluding transition bond-related interest expense. These increases in income from continuing operations were partially offset by: - decreased operating income of $20 million in our Natural Gas Distribution business segment primarily due to the impact of milder weather, increased employee-related expenses in connection with an early retirement program offered in the first quarter of 2006 and higher bad debt expense and decreased throughput associated with higher gas prices, partially offset by rate increases; - a decrease of $34 million in other income related to a return on the true-up balance of our Electric Transmission & Distribution business segment recorded in the first quarter of 2005 as a result of the True-Up Order, which was partially offset by the operating income related to the recovery of the true-up balance through the CTC as discussed above; and - an increase in income tax expense of $9 million as discussed below. Income Tax Expense. During the three months ended March 31, 2005 and 2006, our effective tax rate was 48.6% and 45%, respectively. The most significant item affecting our effective tax rate in the first quarter of 2005 and 2006 was an addition to the tax reserve of approximately $11 million and $14 million, respectively, 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. Future changes to the reserve will depend upon a number of variables, including the market price of Time Warner Inc. common stock (TW Common), the amount of ZENS OID, which increases quarterly, our assessment of available capital gains and the ultimate outcome of the dispute with the IRS. 25 RESULTS OF OPERATIONS BY BUSINESS SEGMENT The following table presents operating income for each of our business segments for the three months ended March 31, 2005 and 2006. Some amounts from the previous year have been reclassified to conform to the 2006 presentation of the financial statements. These reclassifications do not affect consolidated net income.
THREE MONTHS ENDED MARCH 31, ---------------------------- 2005 2006 ---- ---- (IN MILLIONS) Electric Transmission & Distribution ........ $ 80 $110 Natural Gas Distribution .................... 123 103 Competitive Natural Gas Sales and Services .. 16 25 Pipelines and Field Services ................ 64 73 Other Operations ............................ (7) (5) ---- ---- Total Consolidated Operating Income ...... $276 $306 ==== ====
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 "-- Risks Common to Our Business and Other Risks" in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2005 (2005 Form 10-K). The following tables provide summary data of our Electric Transmission & Distribution business segment for the three months ended March 31, 2005 and 2006 (in millions, except throughput and customer data):
THREE MONTHS ENDED MARCH 31, ----------------------- 2005 2006 ---------- ---------- Revenues: Electric transmission and distribution utility ........... $ 323 $ 331 Transition bond companies ................................ 22 54 ---------- ---------- Total revenues ........................................ 345 385 ---------- ---------- Expenses: Operation and maintenance ................................ 138 134 Depreciation and amortization ............................ 64 63 Taxes other than income taxes ............................ 50 56 Transition bond companies ................................ 13 22 ---------- ---------- Total expenses ........................................ 265 275 ---------- ---------- Operating Income -- Electric transmission and distribution Utility .................................................. 71 78 Operating Income -- Transition bond companies(1) ............ 9 32 ---------- ---------- Total segment operating income ........................ $ 80 $ 110 ========== ========== Throughput (in gigawatt-hours (GWh)): Residential ........................................... 4,142 3,986 Total ................................................. 15,826 15,987 Average number of metered customers: Residential ........................................... 1,661,320 1,717,836 Total ................................................. 1,887,020 1,950,829
- ---------- (1) Represents the amount necessary to pay interest on the transition bonds. THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005 Our Electric Transmission & Distribution business segment reported operating income of $110 million for the three months ended March 31, 2006, consisting of $78 million for the regulated electric transmission and distribution utility and $32 million for the transition bond company subsidiaries of CenterPoint Houston that issued 26 $749 million and $1.851 billion principal amount of transition bonds in 2001 and the fourth quarter of 2005, respectively. For the three months ended March 31, 2005, operating income totaled $80 million, consisting of $71 million for the regulated electric transmission and distribution utility and $9 million for the transition bond company. Operating revenues for the regulated electric transmission and distribution utility increased primarily due to continued customer growth ($8 million) with the addition of nearly 67,000 metered customers since March 2005 and recovery of our 2004 true-up balance through the CTC ($14 million), partially offset by milder weather and decreased usage ($12 million). Operation and maintenance expense decreased ($4 million) primarily due to a gain on the sale of land ($14 million)for the regulated electric transmission and distribution utility, which was partially offset by higher transmission costs ($4 million) and severance costs associated with staff reductions in the first quarter of 2006 ($4 million). Additionally, taxes other than income taxes increased ($6 million) primarily due to higher franchise fees paid to the City of Houston. 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, Competitive Natural Gas Sales and Services and Pipelines and Field Services Businesses," " - -- Risk Factors Associated with Our Consolidated Financial Condition" and "-- Risks Common to Our Business and Other Risks" in Item 1A of Part I of our 2005 Form 10-K. The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, 2005 and 2006 (in millions, except throughput and customer data):
THREE MONTHS ENDED MARCH 31, ----------------------- 2005 2006 ---------- ---------- Revenues ................................... $ 1,329 $ 1,480 ---------- ---------- Expenses: Natural gas ............................. 997 1,146 Operation and maintenance ............... 135 150 Depreciation and amortization ........... 37 38 Taxes other than income taxes ........... 37 43 ---------- ---------- Total expenses ....................... 1,206 1,377 ---------- ---------- Operating Income ........................... $ 123 $ 103 ========== ========== Throughput (in billion cubic feet (Bcf)): Residential ............................. 77 67 Commercial and industrial ............... 77 72 ---------- ---------- Total Throughput ..................... 154 139 ========== ========== Average number of customers: Residential ............................. 2,851,514 2,889,013 Commercial and industrial ............... 248,826 253,519 ---------- ---------- Total ................................ 3,100,340 3,142,532 ========== ==========
THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005 Our Natural Gas Distribution business segment reported operating income of $103 million for the three months ended March 31, 2006 as compared to $123 million for the three months ended March 31, 2005. Increases in operating margins (revenues less natural gas costs) from rate increases ($12 million) and increased gross receipts taxes resulting from higher revenues ($6 million), were substantially offset by the impact of milder weather and decreased throughput net of continued customer growth with the addition of approximately 42,000 customers since March 2005 ($12 million). Operation and maintenance expense increased $15 million primarily due to increased employee-related expense in connection with an early retirement program offered in the first quarter of 2006 ($6 million), increased bad debt expense associated with higher gas prices ($3 million) and increased contracts and services expenses and corporate services ($4 million). Additionally, taxes other than income taxes increased $6 million primarily due to higher gross receipts taxes, which offset the corresponding increase in revenues as discussed above. 27 COMPETITIVE NATURAL GAS SALES AND SERVICES For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read "Risk Factors -- Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services and Pipelines and Field Services Business," " -- Risk Factors Associated with Our Consolidated Financial Condition" and "-- Risks Common to Our Business and Other Risks" in Item 1A of Part I of our 2005 Form 10-K. The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three months ended March 31, 2005 and 2006 (in millions, except throughput and customer data):
THREE MONTHS ENDED MARCH 31, ------------------ 2005 2006 ------ ------ Revenues .......................... $ 925 $1,163 ------ ------ Expenses: Natural gas .................... 902 1,129 Operation and maintenance ...... 5 8 Depreciation and amortization .. 1 -- Taxes other than income taxes .. 1 1 ------ ------ Total expenses .............. 909 1,138 ------ ------ Operating Income .................. $ 16 $ 25 ====== ====== Throughput (in Bcf): Wholesale - third parties ...... 82 89 Wholesale - affiliates ......... 14 11 Retail ......................... 47 48 Pipeline ....................... 19 10 ------ ------ Total Throughput ............ 162 158 ====== ====== Average number of customers: Wholesale ...................... 136 145 Retail ......................... 6,224 6,517 Pipeline ....................... 153 147 ------ ------ Total ....................... 6,513 6,809 ====== ======
THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005 Our Competitive Natural Gas Sales and Services business segment reported operating income of $25 million for the three months ended March 31, 2006 as compared to $16 million for the three months ended March 31, 2005. The increase in operating income of $9 million was primarily due to increased operating margins (revenues less natural gas costs) related to higher sales to utilities and favorable basis differentials over the pipeline capacity that we control ($23 million) less the impact of an adjustment in the first quarter of 2006 to write-down natural gas inventory to the lower of average cost or market ($13 million), partially offset by higher payroll and benefit related expenses ($1 million) and increased bad debt expense ($1 million). Natural gas that is purchased for inventory is accounted for at the lower of average cost or market price at each balance sheet date. PIPELINES AND FIELD SERVICES For information regarding factors that may affect the future results of operations of our Pipelines and Field Services business segment, please read "Risk Factors -- Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services and Pipelines and Field Services Businesses," " -- Risk Factors Associated with Our Consolidated Financial Condition" and "-- Risks Common to Our Business and Other Risks" in Item 1A of Part I of our 2005 Form 10-K. 28 The following table provides summary data of our Pipelines and Field Services business segment for the three months ended March 31, 2005 and 2006 (in millions, except throughput data):
THREE MONTHS ENDED MARCH 31, ------------ 2005 2006 ---- ---- Revenues .......................... $121 $125 ---- ---- Expenses: Natural gas .................... 7 (4) Operation and maintenance ...... 34 39 Depreciation and amortization .. 11 12 Taxes other than income taxes .. 5 5 ---- ---- Total expenses .............. 57 52 ---- ---- Operating Income .................. $ 64 $ 73 ==== ==== Throughput (in Bcf): Natural Gas Sales .............. 1 -- Transportation ................. 271 274 Gathering ...................... 83 88 Eliminations (1) ............... (1) -- ---- ---- Total Throughput ............ 354 362 ==== ====
- ---------- (1) Elimination of volumes both transported and sold. THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005 Our Pipelines and Field Services business segment reported operating income of $73 million for the three months ended March 31, 2006 as compared to $64 million for the three months ended March 31, 2005. Operating income for the pipeline business for the three months ended March 31, 2006 was $49 million compared to $48 million for the three months ended March 31, 2005. The field services business recorded operating income of $24 million for the three months ended March 31, 2006 compared to $16 million for the three months ended March 31, 2005. Operating income increased by $9 million primarily due to increased revenues from higher demand for transportation and higher demand for ancillary services on the regulated pipelines ($7 million), higher commodity prices and increased throughput and demand for services related to our core gas gathering operations ($11 million), partially offset by increased operation and maintenance expenses ($5 million). Additionally, this business segment has a 50% interest in a jointly-owned gas processing plant. Included in other income for the three months ended March 31, 2005 and 2006 was equity income of $1 million and $2 million, respectively, related to the joint venture. OTHER OPERATIONS The following table shows the operating loss of our Other Operations business segment for the three months ended March 31, 2005 and 2006 (in millions):
THREE MONTHS ENDED MARCH 31, ------------ 2005 2006 ---- ---- Revenues ........ $ 7 $ 4 Expenses ........ 14 9 --- --- Operating Loss .. $(7) $(5) === ===
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 and "Risk Factors" in Item 1A of Part I of our 2005 Form 10-K. 29 LIQUIDITY AND CAPITAL RESOURCES HISTORICAL CASH FLOWS The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2005 and 2006:
THREE MONTHS ENDED MARCH 31, ------------- 2005 2006 ----- ----- (IN MILLIONS) Cash provided by (used in): Operating activities.... $(202) $ 315 Investing activities.... (118) (201) Financing activities.... 460 (75)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES Net cash provided by operating activities in the first quarter of 2006 increased $517 million compared to the same period in 2005 primarily due to decreased tax payments of $436 million, the majority of which related to the tax payment in the first quarter of 2005 associated with the sale of our former electric generation business (Texas Genco), decreases in net regulatory assets/liabilities ($109 million), primarily due to the termination of excess mitigation credits effective April 29, 2005, and decreased cash used in the operations of Texas Genco ($22 million). These increases in cash provided by operating activities were partially offset by decreased net accounts receivable/payable ($100 million) primarily due to higher gas prices in the first quarter of 2006 as compared to the same period in 2005 and decreases in the amount of advances for the purchase of receivables under CERC Corp.'s receivables facility. Additionally, customer margin deposit requirements decreased ($75 million) primarily due to the decline in natural gas prices from December 2005 to March 2006. CASH USED IN INVESTING ACTIVITIES Net cash used in investing activities increased $83 million in the first quarter of 2006 as compared to the same period in 2005 primarily due to increased capital expenditures of $55 million primarily related to our Electric Transmission & Distribution and Pipelines and Field Services business segments. CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES Net cash provided by financing activities in the first quarter of 2006 decreased $535 million compared to the same period in 2005 primarily due to decreased borrowings under our revolving credit facility ($475 million) and the absence of borrowings under Texas Genco's revolving credit facility ($75 million) due to the sale of Texas Genco, partially offset by decreased dividend payments of $15 million. 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 remainder of 2006 include the following: - approximately $859 million of capital expenditures; - dividend payments on CenterPoint Energy common stock and debt service payments; and - long-term debt payments of $199 million, including $54 million of transition bonds. 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. Off-Balance Sheet Arrangements. Other than operating leases and the guarantees described below, we have no off-balance sheet arrangements. However, we do participate in a receivables factoring arrangement. CERC Corp. 30 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 Statement of Financial Accounting Standards (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 Condensed Consolidated Balance Sheet. In January 2006, the $250 million facility, which temporarily increased to $375 million for the period from January 2006 to June 2006, was extended to January 2007. As of March 31, 2006, CERC had $141 million of advances under its receivables facility. Prior to CenterPoint Energy's distribution of its ownership in Reliant Energy, Inc. (formerly named Reliant Resources, Inc.) (RRI) to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI's trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guarantee obligations prior to separation, but when separation occurred in September 2002, RRI had been unable to extinguish all obligations. To secure CenterPoint Energy and CERC against obligations under the remaining guarantees, RRI agreed to provide cash or letters of credit for the benefit of CERC and CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guarantees. Our current exposure under the remaining guarantees relates to CERC's guarantee of the payment by RRI of demand charges related to transportation contracts with one counterparty. The demand charges are approximately $53 million per year in 2006 through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018. As a result of changes in market conditions, CenterPoint Energy's potential exposure under that guarantee currently exceeds the security provided by RRI. CenterPoint Energy has requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of CERC's obligations under the guarantee, and CenterPoint Energy and RRI are pursuing other alternatives. RRI continues to meet its obligations under the transportation contracts. Credit Facilities. In March 2006, we, CenterPoint Houston and CERC Corp., entered into amended and restated bank credit facilities. We replaced our $1 billion five-year revolving credit facility with a $1.2 billion five-year revolving credit facility. The facility has a first drawn cost of LIBOR plus 60 basis points based on our current credit ratings, as compared to LIBOR plus 87.5 basis points for borrowings under the facility it replaced. The facility contains covenants, including a debt to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant. CenterPoint Houston replaced its $200 million five-year revolving credit facility with a $300 million five-year revolving credit facility. The facility has a first drawn cost of LIBOR plus 45 basis points based on CenterPoint Houston's current credit ratings, as compared to LIBOR plus 75 basis points for borrowings under the facility it replaced. The facility contains covenants, including a debt, excluding transition bonds, to total capitalization covenant of 65%. CERC Corp. replaced its $400 million five-year revolving credit facility with a $550 million five-year revolving credit facility. The facility has a first drawn cost of LIBOR plus 45 basis points based on CERC Corp.'s current credit ratings, as compared to LIBOR plus 55 basis points for borrowings under the facility it replaced. The facility contains covenants, including a debt to total capitalization covenant of 65%. Under each of the credit facilities, an additional utilization fee of 10 basis points applies to borrowings any time more than 50% of the facility is utilized, and the spread to LIBOR fluctuates based on the borrower's credit rating. Borrowings under each of the facilities are subject to customary terms and conditions. However, there is no requirement that we, CenterPoint Houston or CERC Corp. make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the credit facilities are subject to acceleration upon the occurrence of events of default that we, CenterPoint Houston or CERC Corp. consider customary. We, CenterPoint Houston and CERC Corp. are currently in compliance with the various business and financial covenants contained in the respective credit facilities. 31 As of May 1, 2006, we had the following credit facilities (in millions):
AMOUNT UTILIZED DATE EXECUTED COMPANY SIZE OF FACILITY AT MAY 1, 2006 TERMINATION DATE - -------------- ------------------- ---------------- --------------- ---------------- March 31, 2006 CenterPoint Energy $1,200 $28(1) March 31, 2011 March 31, 2006 CenterPoint Houston 300 3(1) March 31, 2011 March 31, 2006 CERC Corp. 550 -- March 31, 2011
- ---------- (1) Represents outstanding letters of credit. The $1.2 billion CenterPoint Energy credit facility backstops a $1.0 billion commercial paper program under which CenterPoint Energy began issuing commercial paper in June 2005. As of March 31, 2006, there was no commercial paper outstanding. The commercial paper is rated "Not Prime" by Moody's Investors Service, Inc. (Moody's), "A-3" by Standard & Poor's Rating Services (S&P), a division of The McGraw-Hill Companies, and "F3" by Fitch, Inc. (Fitch) and, as a result, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements. 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 March 31, 2006, 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. As of March 31, 2006, we had external temporary investments of $65 million. As of May 1, 2006, we had external temporary investments of $131 million. 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 or the sale of commercial paper. Impact on Liquidity of a Downgrade in Credit Ratings. As of May 1, 2006, Moody's, S&P, and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:
MOODY'S S&P FITCH ------------------- ------------------- ------------------- COMPANY/INSTRUMENT RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3) - ----------------------------------- ------ ---------- ------ ---------- ------ ---------- CenterPoint Energy Senior Unsecured Debt............................ Ba1 Stable BBB- Stable BBB- Stable CenterPoint Houston Senior Secured Debt (First Mortgage Bonds)..... Baa2 Stable BBB Stable A- Stable CERC Corp. Senior Unsecured Debt... Baa3 Stable BBB Stable BBB Stable
- ---------- (1) A "stable" outlook from Moody's indicates that Moody's does not expect to put the rating on review for an upgrade or downgrade within 18 months from when the outlook was assigned or last affirmed. (2) An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term. (3) A "stable" outlook from Fitch encompasses a one-to-two-year horizon as to the likely ratings direction. 32 A decline in credit ratings could increase borrowing costs under our $1.2 billion credit facility, CenterPoint Houston's $300 million credit facility and CERC's $550 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 could negatively impact our ability to complete capital market transactions. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce margins of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments. In September 1999, we issued 2.0% ZENS having an original principal amount of $1.0 billion of which $840 million remain outstanding. 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 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. CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of CERC Corp. operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to hedge its exposure to natural gas prices, CES uses financial derivatives 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 estimate that as of March 31, 2006, unsecured credit limits extended to CES by counterparties aggregate $131 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 May 1, 2006, 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 and Competitive Natural Gas Sales and Services business segments, 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; 33 - 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 or in connection with the contractual arrangement pursuant to which CERC is a guarantor; - 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 1A of Part I of our 2005 Form 10-K. Certain Contractual Limits on Our Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock. CenterPoint Houston's credit facility limits CenterPoint Houston's debt, excluding transition bonds, as a percentage of its total capitalization to 65 percent. CERC Corp.'s bank facility and its receivables facility limit CERC's debt as a percentage of its total capitalization to 65 percent. The receivables facility also contains an EBITDA to interest covenant. Our $1.2 billion credit facility contains a debt to EBITDA covenant. Additionally, in connection with the issuance of a certain series of general mortgage bonds, CenterPoint Houston agreed not to issue, subject to certain exceptions, additional first mortgage bonds. We were a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (1935 Act). The Energy Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February 8, 2006, and since that date we and our subsidiaries have no longer been subject to restrictions imposed under the 1935 Act. The Energy Act includes a new Public Utility Holding Company Act of 2005 (PUHCA 2005) which 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 the FERC and state regulatory authorities in certain circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA 2005 that will require us to notify the FERC of our status as a holding company and to maintain certain books and records and make these available to the FERC. On April 24, 2006, the FERC considered motions for rehearing of these rules and proposed to adopt additional rules regarding maintenance of books and records by utility holding companies. 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 the consolidated financial statements in our 2005 Form 10-K. 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. 34 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 $328 million of recoverable electric generation-related regulatory assets as of March 31, 2006. These costs are recoverable under the provisions of the 1999 Texas Electric Choice Plan. Based on our analysis of the final order issued by the Public Utility Commission of Texas (Texas Utility Commission), 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. Additionally, a district court in Travis County, Texas issued a judgment that would have the effect of restoring approximately $650 million, plus interest, of disallowed costs. Appeals of the district court's judgment are still pending. No amounts related to the district court's judgment have been recorded in our consolidated financial statements. 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." 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. ASSET RETIREMENT OBLIGATIONS We account for our long-lived assets under SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), and Financial Accounting Standards Board Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations -- An Interpretation of SFAS No. 143" (FIN 47). SFAS No. 143 and FIN 47 require that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47, and costs recovered through the ratemaking process. We estimate the fair value of asset retirement obligations by calculating the discounted cash flows that are dependent upon the following components: - Inflation adjustment -- The estimated cash flows are adjusted for inflation estimates for labor, equipment, materials, and other disposal costs; 35 - Discount rate -- The estimated cash flows include contingency factors that were used as a proxy for the market risk premium; and - Third party markup adjustments -- Internal labor costs included in the cash flow calculation were adjusted for costs that a third party would incur in performing the tasks necessary to retire the asset. Changes in these factors could materially affect the obligation recorded to reflect the ultimate cost associated with retiring the assets under SFAS No. 143 and FIN 47. For example, if the inflation adjustment increased 25 basis points, this would increase the balance for asset retirement obligations by approximately 3.0%. Similarly, an increase in the discount rate by 25 basis points would decrease asset retirement obligations by approximately the same percentage. At March 31, 2006, our estimated cost of retiring these assets is approximately $76 million. 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 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. 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 "-- Other Significant Matters -- Pension Plan" for further discussion. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations-- Other Significant Matters -- Pension Plan" in Item 7 of our 2005 Form 10-K. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK COMMODITY PRICE RISK FROM NON-TRADING ACTIVITIES We measure the commodity risk of our non-trading derivatives (Non-Trading Energy Derivatives) using a sensitivity analysis. The sensitivity analysis performed on our Non-Trading Energy Derivatives measures the potential loss based on a hypothetical 10% movement in energy prices. At March 31, 2006, the recorded fair value of our Non-Trading Energy Derivatives was a net asset of $38 million. A decrease of 10% in the market prices of energy commodities from their March 31, 2006 levels would have decreased the fair value of our Non-Trading Energy Derivatives from their levels on that date by $83 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. Furthermore, 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 36 associated with the hypothetical changes in commodity prices referenced above is expected to be substantially 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. We had no floating-rate obligations at March 31, 2006. At March 31, 2006, we had outstanding fixed-rate debt (excluding indexed debt securities) and trust preferred securities aggregating $8.8 billion in principal amount and having a fair value of $9.1 billion. These 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 $386 million if interest rates were to decline by 10% from their levels at March 31, 2006. 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. 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 $110 million at March 31, 2006 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 March 31, 2006. Changes in the fair value of the derivative component will be recorded in our Condensed Statements of Consolidated Income 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 March 31, 2006 levels, the fair value of the derivative component would increase by approximately $5 million, which would be recorded as a loss in our Condensed Statements of Consolidated Income. 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. A decrease of 10% from the March 31, 2006 market value of TW Common would result in a net loss of approximately $4 million, which would be recorded as a loss in our Condensed Statements of Consolidated Income. 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 March 31, 2006 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 and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure. There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. 37 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS For a description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Notes 4 and 10 to our Interim Financial Statements, each of which is incorporated herein by reference. See also "Business -- Regulation" and " -- Environmental Matters" in Item 1 and "Legal Proceedings" in Item 3 of our 2005 Form 10-K. ITEM 1A. RISK FACTORS There have been no material changes from the risk factors disclosed in our 2005 Form 10-K. ITEM 5. OTHER INFORMATION The ratio of earnings to fixed charges for the three months ended March 31, 2005 and 2006 was 1.69 and 2.04, respectively. ITEM 6. EXHIBITS The following exhibits are filed herewith: Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing of CenterPoint Energy, Inc.
SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - -------- ----------- -------------------------------- ------------ --------- 3.1.1 -- Amended and Restated Articles of CenterPoint Energy's Registration 3-69502 3.1 Incorporation of CenterPoint Energy Statement on Form S-4 3.1.2 -- Articles of Amendment to Amended and CenterPoint Energy's Form 10-K for the 1-31447 3.1.1 Restated Articles of Incorporation of year ended December 31, 2001 CenterPoint Energy 3.2 -- Amended and Restated Bylaws of CenterPoint CenterPoint Energy's Form 10-K for the 1-31447 3.2 Energy year ended December 31, 2001 3.3 -- Statement of Resolution Establishing Series CenterPoint Energy's Form 10-K for the 1-31447 3.3 of Shares designated Series A Preferred year ended December 31, 2001 Stock of CenterPoint Energy 4.1 -- Form of CenterPoint Energy Stock Certificate CenterPoint Energy's Registration 3-69502 4.1 Statement on Form S-4 4.2 -- Rights Agreement dated January 1, 2002, CenterPoint Energy's Form 10-K for the 1-31447 4.2 between CenterPoint Energy and JPMorgan year ended December 31, 2001 Chase Bank, as Rights Agent 4.3 -- $1,200,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.1 Agreement dated as of March 31, 2006, among March 31, 2006 CenterPoint Energy, as Borrower, and the banks named therein 4.4 -- $300,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.2 Agreement dated as of March 31, 2006, among March 31, 2006 CenterPoint Houston, as Borrower, and the Initial Lenders named therein, as Initial Lenders
38
SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - -------- ----------- -------------------------------- ------------ --------- 4.5 -- $550,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.3 Agreement dated as of March 31, 2006 among March 31, 2006 CERC Corp., as Borrower, and the banks named therein +10 -- Letter Agreement dated March 16, 2006 between CenterPoint Energy and John T. Cater +12 -- Computation of Ratios of Earnings to Fixed Charges +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 -- Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A "Risk Factors"
39 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: May 4, 2006 40 Exhibit Index
SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - -------- ----------- -------------------------------- ------------ --------- 3.1.1 -- Amended and Restated Articles of CenterPoint Energy's Registration 3-69502 3.1 Incorporation of CenterPoint Energy Statement on Form S-4 3.1.2 -- Articles of Amendment to Amended and CenterPoint Energy's Form 10-K for the 1-31447 3.1.1 Restated Articles of Incorporation of year ended December 31, 2001 CenterPoint Energy 3.2 -- Amended and Restated Bylaws of CenterPoint CenterPoint Energy's Form 10-K for the 1-31447 3.2 Energy year ended December 31, 2001 3.3 -- Statement of Resolution Establishing Series CenterPoint Energy's Form 10-K for the 1-31447 3.3 of Shares designated Series A Preferred year ended December 31, 2001 Stock of CenterPoint Energy 4.1 -- Form of CenterPoint Energy Stock Certificate CenterPoint Energy's Registration 3-69502 4.1 Statement on Form S-4 4.2 -- Rights Agreement dated January 1, 2002, CenterPoint Energy's Form 10-K for the 1-31447 4.2 between CenterPoint Energy and JPMorgan year ended December 31, 2001 Chase Bank, as Rights Agent 4.3 -- $1,200,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.1 Agreement dated as of March 31, 2006, among March 31, 2006 CenterPoint Energy, as Borrower, and the banks named therein 4.4 -- $300,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.2 Agreement dated as of March 31, 2006, among March 31, 2006 CenterPoint Houston, as Borrower, and the Initial Lenders named therein, as Initial Lenders 4.5 -- $550,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.3 Agreement dated as of March 31, 2006 among March 31, 2006 CERC Corp., as Borrower, and the banks named therein +10 -- Letter Agreement dated March 16, 2006 between CenterPoint Energy and John T. Cater +12 -- Computation of Ratios of Earnings to Fixed Charges +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 -- Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A "Risk Factors"
EX-10 2 h35607exv10.txt LETTER AGREEMENT EXHIBIT 10 (CENTERPOINT ENERGY (TM) LOGO) DAVID M. MCCLANAHAN P.O. Box 1700 President and CEO Houston, TX 77251 CenterPoint Energy 713 207 5899 Fax: 713 207 7021 david.mcclanahan@ CenterPointEnergy.com March 16, 2006 Mr. John T. Cater 2001 Kirby, Suite 313 Houston, Texas 77019 Re: Waiver of Certain Rights under CenterPoint Energy, Inc. 1985 Deferred Compensation Plan Dear John: The purpose of this letter agreement (this "Agreement") is to set forth the terms of your election to forfeit and waive certain rights in connection with your benefits under the CenterPoint Energy, Inc. 1985 Deferred Compensation Plan (the "PLAN"). BENEFITS UNDER PLAN: As a member of the Board of Directors (the "Board") of CenterPoint Energy, Inc. (the "Company"), you deferred compensation under the Plan in 1985, 1986, 1987 and 1988, pursuant to deferred compensation agreements with the Company (the "Deferred Compensation Agreements"). Your deferred compensation account balance under the Plan earns interest at the interest rate specified in your Deferred Compensation Agreements, compounded annually (the "Interest Rate"). Pursuant to those agreements and the terms of the Plan, your account balance under the Plan will be paid to you in 15 annual installments commencing on the later of your (i) attaining age 70 or (ii) termination of membership on the Board, with interest continuing to be earned on your remaining Plan account balance at the Interest Rate during the 15-year installment period. The Company's Bylaws require a member of the Board to resign his or her membership at the annual meeting first occurring after he or she attains age 70, unless the Board determines that such member has special skill, experience or distinction having value to the Company that is not readily available or transferable. While you will attain age 70 by the expected date of the Company's 2006 annual meeting, in accordance with the Company's Bylaws, the Board, at its February 23, 2006 meeting, elected to extend your service as a director until the expiration of your current term on the date of the 2007 annual meeting, which is anticipated to be held in May 2007. WAIVER OF BENEFITS UNDER PLAN: In connection with the extension of your service on the Board, you have agreed to irrevocably forfeit and waive your right to earn interest on your account balance under the Plan at the Interest Rate during the one-year extension period of your membership on the Board (the "Extended Term"). In lieu of the Interest Rate, during the Extended Term your account balance will earn interest based on an interest rate of 8.08% (the "Extended Term Interest Rate"). Moreover, you agree that the amount of interest earned on your account balance during the Extended Term (such amount, the "Extended Term Interest"), shall accrue interest at the Extended Term Interest Rate during the 15-year installment period under the Plan commencing upon your termination of membership on the Board. 1 By executing this Agreement, you agree, represent and acknowledge that you have full knowledge and understanding of the value of your benefits under the Plan pursuant to the application of the Interest Rate during the Extended Term and installment period, and that you forfeit and waive your right to such benefits knowingly, freely and voluntarily and further understand and acknowledge that the effect of this Agreement is a reduction in your benefits under the Plan that you would otherwise have been entitled to receive for the Extended Term and installment period. You also agree, represent and acknowledge that you have sought or have had the opportunity to seek legal and/or financial counsel in connection with your election to forfeit and waive your right to the Interest Rate and the resulting reduction of your benefits under the Plan. WAIVER AND RELEASE: You hereby agree to irrevocably forfeit and waive any and all claims of any kind arising out of or in connection with the Extended Term Interest Rate as set forth in this Agreement and under the Plan and to irrevocably release the Plan, the related trust under the Plan, the Benefits Committee (and its member and delegates), the Company, and any of its officers, directors, employees, subsidiaries or affiliates from liability for any and all claims of any kind arising out of or in connection with the Plan and your waiver of benefits thereunder. MISCELLANEOUS: This Agreement shall be governed by and construed in accordance with the laws of the State of Texas, without reference to principles of conflict of laws. This Agreement may not be amended or modified otherwise than by a written agreement executed by the parties hereto or their respective successors and legal representatives. This Agreement constitutes the entire agreement between the parties with respect to application of the Extended Term Interest Rate and interest earned during the Extended Term and supersedes any and all prior written or oral agreements, arrangements or understandings between you and the Company with respect to the same. Except as expressly provided in this Agreement, the terms and conditions of the Plan shall continue to apply with respect to your benefits under the Plan. If you understand and agree with the foregoing, please execute both copies of this Agreement, retain one original executed copy of this Agreement, and return the other original executed copy of this Agreement to me. Sincerely, /s/ David M. McClanahan ---------------------------------------- David M. McClanahan President and Chief Executive Officer ACCEPTED AND AGREED TO BY: /s/ John T. Cater - ------------------------ John T. Cater Date: March 20, 2006 2 EX-12 3 h35607exv12.txt COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES Exhibit 12 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES (MILLIONS OF DOLLARS)
THREE MONTHS ENDED MARCH 31, -------------------------- 2005 2006 ------------ ------------ Income from continuing operations...................................... $ 67 $ 88 Income taxes for continuing operations................................. 63 72 Capitalized interest................................................... (1) (1) ------------ ------------ 129 159 ------------ ------------ Fixed charges, as defined: Interest............................................................ 183 148 Capitalized interest................................................ 1 1 Interest component of rentals charged to operating income........... 3 4 ------------ ------------ Total fixed charges................................................. 187 153 ------------ ------------ Earnings, as defined................................................... $ 316 $ 312 ============ ============ Ratio of earnings to fixed charges..................................... 1.69 2.04 ============ ============
EX-31.1 4 h35607exv31w1.txt RULE 13A-14A/15D-14A CERTIFICATION OF DAVID M. MCCLANAHAN EXHIBIT 31.1 CERTIFICATIONS I, David M. McClanahan, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 4, 2006 /s/ David M. McClanahan ---------------------------------------- David M. McClanahan President and Chief Executive Officer EX-31.2 5 h35607exv31w2.txt RULE 13A-14A/15D-14A CERTIFICATION OF GARY L. WHITLOCK EXHIBIT 31.2 CERTIFICATIONS I, Gary L. Whitlock, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 4, 2006 /s/ Gary L. Whitlock ---------------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer EX-32.1 6 h35607exv32w1.txt SECTION 1350 CERTIFICATION OF DAVID M. MCCLANAHAN EXHIBIT 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of CenterPoint Energy, Inc. (the "Company") on Form 10-Q for the period ended March 31, 2006 (the "Report"), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ David M. McClanahan - ---------------------------------------- David M. McClanahan President and Chief Executive Officer May 4, 2006 EX-32.2 7 h35607exv32w2.txt SECTION 1350 CERTIFICATION OF GARY L. WHITLOCK EXHIBIT 32.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of CenterPoint Energy, Inc. (the "Company") on Form 10-Q for the period ended March 31, 2006 (the "Report"), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Gary L. Whitlock - ---------------------------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer May 4, 2006 EX-99.1 8 h35607exv99w1.txt ITEMS INCORPORATED BY REFERENCE FROM THE CENTERPOINT ENERGY FORM 10-K EXHIBIT 99.1 ITEM 1A. 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 ULTIMATELY RECOVERING THE FULL VALUE OF ITS TRUE-UP COMPONENTS, WHICH COULD RESULT IN THE ELIMINATION OF CERTAIN TAX BENEFITS AND COULD HAVE AN ADVERSE IMPACT ON CENTERPOINT HOUSTON'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting 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. In August 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the True-Up Order, but reversed two of the Texas Utility Commission's rulings. The judgment would have the effect of restoring approximately $650 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 an inaccurate stranded cost estimate made by the Texas Utility Commission in 2000. Additional credits of approximately $30 million were paid after August 2004. 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. CenterPoint Houston and other parties appealed the district court decisions. Briefs have been filed with the 3rd Court of Appeals in Austin but oral argument has not yet been scheduled. No prediction can be made as to the ultimate outcome or timing of such appeals. Additionally, if the amount of the true-up balance is reduced on appeal to below the amount recovered through the issuance of transition bonds and under the CTC, while the amount of transition bonds outstanding would not be reduced, CenterPoint Houston would be required to refund the over recovery to its customers. Among the issues raised in our appeal of the True-Up Order is the Texas Utility Commission's reduction of our stranded cost recovery by approximately $146 million for the present value of certain deferred tax benefits associated with our former Texas Genco assets. Such reduction was considered in our recording of an after-tax extraordinary loss of $977 million in the last half of 2004. We believe that the Texas Utility Commission based its order on proposed regulations issued by the IRS in March 2003 related to those tax benefits. Those proposed regulations would have allowed utilities which were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of ADITC and EDFIT back to customers. However, in December 2005, the IRS withdrew those proposed normalization regulations and issued new proposed regulations that do not include the provision allowing a retroactive election to pass the tax benefits back to customers. If the December 2005 proposed regulations become effective and if the Texas Utility Commission's order on this issue is not reversed on appeal or the amount of the tax benefits is not otherwise restored by the Texas Utility Commission, the IRS is likely to consider that a "normalization violation" has occurred. If so, the IRS could require us to pay an amount equal to CenterPoint Houston's unamortized ADITC balance as of the date that the normalization violation was deemed to have occurred. In addition, if a normalization violation is deemed to have occurred, the IRS could also deny CenterPoint Houston the ability to elect accelerated depreciation benefits. If a normalization violation should ultimately be found to exist, it could have an adverse impact on our results of operations, financial condition and cash flows. The Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation. 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 66 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 payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a retail electric provider cannot make timely payments. RRI, through its subsidiaries, is CenterPoint Houston's largest customer. Approximately 56% of CenterPoint Houston's $127 million in billed receivables from retail electric providers at December 31, 2005 was owed by subsidiaries of RRI. Any delay or default in payment could adversely affect CenterPoint Houston's cash flows, financial condition and results of operations. 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 by 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 transmits and distributes to customers of retail electric providers electric power that the retail electric providers obtain from power generation facilities owned by third parties. 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 sales of transmission and distribution services may be diminished or 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, COMPETITIVE NATURAL GAS SALES AND SERVICES AND PIPELINES AND FIELD SERVICES 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, and for its interstate pipelines by the FERC, 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 FIELD SERVICES 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 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 AND COMPETITIVE NATURAL GAS SALES AND SERVICES BUSINESSES ARE SUBJECT TO FLUCTUATIONS IN NATURAL GAS PRICING LEVELS, WHICH COULD AFFECT THE ABILITY OF CERC'S SUPPLIERS AND CUSTOMERS TO MEET THEIR OBLIGATIONS OR OTHERWISE ADVERSELY AFFECT CERC'S LIQUIDITY. CERC is subject to risk associated with increases in the price of natural gas, which has been the trend in recent years. Increases 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 obligations to customers, and its results of operations, financial condition and cash flows would be adversely affected. CERC'S PIPELINES' AND FIELD SERVICES' BUSINESS REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS. CERC's pipelines and field services business largely relies 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 December 31, 2005, we had $8.9 billion of outstanding indebtedness on a consolidated basis, which includes $2.5 billion of non-recourse transition bonds. As of December 31, 2005, approximately $665 million principal amount of this debt must be paid through 2008. This amount excludes principal repayments of approximately $379 million on transition bonds, for which a dedicated revenue stream exists. In addition, we have $830 million of outstanding convertible notes on which holders could exercise their "put" rights during this period. Our future financing activities may depend, at least in part, on: - the timing and amount of our recovery of the true-up components, including, in particular, the results of appeals to the courts of determinations on rulings obtained to date; - 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; and - provisions of relevant tax and securities laws. As of December 31, 2005, CenterPoint Houston had outstanding $2.0 billion aggregate principal amount of general mortgage bonds under the General Mortgage, including approximately $527 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated and approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had outstanding approximately $253 million aggregate principal amount of first mortgage bonds under the Mortgage, including approximately $151 million held in trust to secure certain pollution control bonds for which CenterPoint Energy is obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.0 billion 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 December 31, 2005. However, CenterPoint Houston is contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds. 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 7 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, 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. 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 should a counterparty fail 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. RISKS COMMON TO OUR BUSINESSES AND OTHER RISKS WE ARE SUBJECT TO OPERATIONAL AND FINANCIAL RISKS AND LIABILITIES ARISING FROM ENVIRONMENTAL LAWS AND REGULATIONS. Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines and distribution systems, gas gathering and processing systems, and electric transmission and distribution systems we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as: - restricting the way we can handle or dispose of our wastes; - limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species; - requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and - enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to: - construct or acquire new equipment; - acquire permits for facility operations; - modify or replace existing and proposed equipment; and - clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. 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. WE, CENTERPOINT HOUSTON AND CERC 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, a predecessor of CenterPoint Houston, 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 transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston and CERC, 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 has not been released from the liability in connection with the transfer, we, CenterPoint Houston or CERC could be responsible for satisfying the liability. Prior to CenterPoint Energy's distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI's trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guarantee obligations prior to separation, but when separation occurred in September 2002, RRI had been unable to extinguish all obligations. To secure CenterPoint Energy and CERC against obligations under the remaining guarantees, RRI agreed to provide cash or letters of credit for the benefit of CERC and CenterPoint Energy, and undertook to use commercially reasonable efforts to extinguish the remaining guarantees. Our current exposure under the remaining guarantees relates to CERC's guarantee of the payment by RRI of demand charges related to transportation contracts with one counterparty. The demand charges are approximately $53 million per year in 2006 through 2015, $49 million in 2016, $38 million in 2017 and $13 million in 2018. As a result of changes in market conditions, CenterPoint Energy's potential exposure under that guarantee currently exceeds the security provided by RRI. CenterPoint Energy has requested RRI to increase the amount of its existing letters of credit or, in the alternative, to obtain a release of CERC's obligations under the guarantee, and CenterPoint Energy and RRI are pursuing alternatives. RRI continues to meet its obligations under the transportation contracts. 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 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 have been made on grounds that include the effect of RRI's financial results on Reliant Energy's historical financial statements and liability of Reliant Energy 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 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 obligations of 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 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 had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability. We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations we own, but most existing claims relate to facilities previously owned by our subsidiaries but currently owned by Texas Genco LLC. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the separation agreement between us and Texas Genco, ultimate financial responsibility for uninsured losses from claims relating to facilities transferred to Texas Genco has been assumed by Texas Genco, but under the terms of our agreement to sell Texas Genco to Texas Genco LLC, we have agreed to continue to defend such claims to the extent they are covered by insurance we maintain, subject to reimbursement of the costs of such defense from Texas Genco LLC. -----END PRIVACY-ENHANCED MESSAGE-----