UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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 1-13265 CENTERPOINT ENERGY RESOURCES CORP. (Exact name of registrant as specified in its charter) DELAWARE 76-0511406 (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 (Registrant's telephone number, principal executive offices) including area code) ---------- CENTERPOINT ENERGY RESOURCES CORP. MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(A) AND (B) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT. 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 [ ] Accelerated filer [ ] Non-accelerated filer [X] 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 October 31, 2006, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy, Inc.
CENTERPOINT ENERGY RESOURCES CORP. QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2006 TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Item 1. Financial Statements.................................... 1 Condensed Statements of Consolidated Income Three Months and Nine Months Ended September 30, 2005 and 2006 (unaudited)...................... 1 Condensed Consolidated Balance Sheets December 31, 2005 and September 30, 2006 (unaudited).................................... 2 Condensed Statements of Consolidated Cash Flows Nine Months Ended September 30, 2005 and 2006 (unaudited).................................... 4 Notes to Unaudited Condensed Consolidated Financial Statements........................................ 5 Item 2. Management's Narrative Analysis of the Results of Operations........................................... 17 Item 4. Controls and Procedures................................. 27 PART II. OTHER INFORMATION Item 1. Legal Proceedings....................................... 28 Item 1A. Risk Factors............................................ 28 Item 5. Other Information....................................... 28 Item 6. Exhibits................................................ 28 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: - 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; - 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; - the timing and extent of changes in natural gas basis differentials; - 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; - the ability of Reliant Energy, Inc. (formerly Reliant Resources, Inc.) and its subsidiaries to satisfy their obligations to us or in connection with the contractual arrangements pursuant to which we are a guarantor; - the outcome of litigation brought by or against us; - our ability to control costs; - the investment performance of CenterPoint Energy, Inc.'s 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 ii
- 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 and in "Risk Factors' in Item 1A of Part II of this Quarterly Report on Form 10-Q. 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 RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONDENSED STATEMENTS OF CONSOLIDATED INCOME (MILLIONS OF DOLLARS) (UNAUDITED) THREE MONTHS NINE MONTHS ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, --------------- --------------- 2005 2006 2005 2006 ------ ------ ------ ------ REVENUES ............................... $1,587 $1,400 $5,261 $5,474 ------ ------ ------ ------ EXPENSES: Natural gas ......................... 1,277 1,058 4,161 4,286 Operation and maintenance ........... 188 192 532 588 Depreciation and amortization ....... 50 50 149 150 Taxes other than income taxes ....... 32 31 108 116 ------ ------ ------ ------ Total ............................ 1,547 1,331 4,950 5,140 ------ ------ ------ ------ OPERATING INCOME ....................... 40 69 311 334 ------ ------ ------ ------ OTHER INCOME (EXPENSE): Interest and other finance charges .. (39) (43) (136) (125) Other, net .......................... 6 7 18 15 ------ ------ ------ ------ Total ............................ (33) (36) (118) (110) ------ ------ ------ ------ INCOME BEFORE INCOME TAXES ............. 7 33 193 224 Income tax expense .................. (3) (20) (66) (91) ------ ------ ------ ------ NET INCOME ............................. $ 4 $ 13 $ 127 $ 133 ====== ====== ====== ====== See Notes to the Company's Interim Condensed Financial Statements 1
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONDENSED CONSOLIDATED BALANCE SHEETS (MILLIONS OF DOLLARS) (UNAUDITED) ASSETS DECEMBER 31, SEPTEMBER 30, 2005 2006 ------------ ------------- CURRENT ASSETS: Cash and cash equivalents ......................... $ 31 $ 119 Accounts and notes receivable, net ................ 942 519 Accrued unbilled revenue .......................... 500 104 Accounts receivable -- affiliated companies ....... -- 23 Materials and supplies ............................ 29 37 Natural gas inventory ............................. 294 286 Non-trading derivative assets ..................... 131 141 Taxes receivable .................................. 117 59 Deferred tax asset ................................ 17 -- Prepaid expenses and other current assets ......... 130 365 ------ ------ Total current assets ........................... 2,191 1,653 ------ ------ PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment ..................... 4,674 5,020 Less accumulated depreciation and amortization .... (569) (649) ------ ------ Property, plant and equipment, net ............. 4,105 4,371 ------ ------ OTHER ASSETS: Goodwill .......................................... 1,709 1,709 Other intangibles, net ............................ 18 8 Non-trading derivative assets ..................... 104 47 Accounts receivable -- affiliated companies, net .. 9 -- Other ............................................. 165 247 ------ ------ Total other assets ............................. 2,005 2,011 ------ ------ TOTAL ASSETS ......................................... $8,301 $8,035 ====== ====== See Notes to the Company's Interim Condensed Financial Statements 2
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONDENSED CONSOLIDATED BALANCE SHEETS -- (CONTINUED) (MILLIONS OF DOLLARS) (UNAUDITED) LIABILITIES AND STOCKHOLDER'S EQUITY DECEMBER 31, SEPTEMBER 30, 2005 2006 ------------ ------------- CURRENT LIABILITIES: Current portion of long-term debt ............ $ 154 $ 152 Accounts payable ............................. 1,077 492 Accounts and notes payable -- affiliated companies, net ............................ 319 47 Taxes accrued ................................ 67 77 Interest accrued ............................. 46 53 Customer deposits ............................ 62 58 Non-trading derivative liabilities ........... 43 179 Other ........................................ 341 255 ------ ------ Total current liabilities ................. 2,109 1,313 ------ ------ OTHER LIABILITIES: Accumulated deferred income taxes, net ....... 663 672 Non-trading derivative liabilities ........... 35 110 Benefit obligations .......................... 127 117 Other ........................................ 716 719 ------ ------ Total other liabilities ................... 1,541 1,618 ------ ------ LONG-TERM DEBT .................................. 1,838 2,155 ------ ------ COMMITMENTS AND CONTINGENCIES (NOTE 9) STOCKHOLDER'S EQUITY: Common stock ................................. -- -- Paid-in capital .............................. 2,404 2,405 Retained earnings ............................ 398 531 Accumulated other comprehensive income ....... 11 13 ------ ------ Total stockholder's equity ................ 2,813 2,949 ------ ------ TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY ... $8,301 $8,035 ====== ====== See Notes to the Company's Interim Condensed Financial Statements 3
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (MILLIONS OF DOLLARS) (UNAUDITED) NINE MONTHS ENDED SEPTEMBER 30, ------------- 2005 2006 ----- ----- CASH FLOWS FROM OPERATING ACTIVITIES: Net income ............................................. $ 127 $ 133 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ....................... 149 150 Amortization of deferred financing costs ............ 6 6 Deferred income taxes ............................... (2) 33 Write-down of natural gas inventory ................. -- 56 Changes in other assets and liabilities: Accounts receivable and unbilled revenues, net ... 355 828 Accounts receivable/payable, affiliates .......... (10) 3 Inventory ........................................ (140) (52) Taxes receivable ................................. 214 (54) Accounts payable ................................. (10) (625) Fuel cost over (under) recovery/surcharge ........ (69) 106 Interest and taxes accrued ....................... (26) 17 Non-trading derivatives, net ..................... 6 (38) Margin deposits, net ............................. 78 (176) Short-term risk management activities, net ....... (19) 3 Other current assets ............................. (41) (79) Other current liabilities ........................ 65 (12) Other assets ..................................... 6 (16) Other liabilities ................................ -- (8) Other, net .......................................... (2) (14) ----- ----- Net cash provided by operating activities ..... 687 261 ----- ----- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures ................................... (280) (332) Decrease in notes receivable from affiliates ........... 38 -- Other, net ............................................. (5) 18 ----- ----- Net cash used in investing activities ......... (247) (314) ----- ----- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of long-term debt ............... -- 324 Payments of long-term debt ............................. (372) (6) Decrease in notes payable to affiliates ................ (1) (289) Debt issuance costs .................................... (1) (1) Contribution from parent ............................... -- 112 Dividend to parent ..................................... (100) -- Other, net ............................................. -- 1 ----- ----- Net cash provided by (used in) financing activities ................................. (474) 141 ----- ----- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ...... (34) 88 CASH AND CASH EQUIVALENTS AT BEGINNING OF THE PERIOD ...... 141 31 ----- ----- CASH AND CASH EQUIVALENTS AT END OF THE PERIOD ............ $ 107 $ 119 ===== ===== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest, net of capitalized interest .................. $ 142 $ 115 Income taxes (refunds), net ............................ 91 (8) Non-cash transactions: Increase in accounts payable related to capital expenditures ........................................ -- 34 See Notes to the Company's Interim Condensed Financial Statements 4
CENTERPOINT ENERGY RESOURCES CORP. 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 Resources Corp. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC or the Company). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2005 (CERC Corp. Form 10-K). Background. The Company and its operating subsidiaries own and operate natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. The operations of the Company's local distribution companies are conducted through two unincorporated divisions: Minnesota Gas and Southern Gas Operations. Through wholly owned subsidiaries, the Company owns two interstate natural gas pipelines and gas gathering systems and provides various ancillary services. Through a wholly owned subsidiary, the Company also offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. The Company is an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility holding company created on August 31, 2002, as part of a corporate restructuring of Reliant Energy, Incorporated that implemented certain requirements of the Texas Electric Choice Plan. CenterPoint Energy was 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 CenterPoint Energy and its 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. Pursuant to those rules, on June 14, 2006, CenterPoint Energy filed with the FERC the required notification of its status as a public utility holding company. On October 19, 2006, the FERC adopted additional rules regarding maintenance of books and records by utility holding companies and additional reporting and accounting requirements for centralized service companies that make allocations to public utilities regulated by the FERC under the Federal Power Act. Although CenterPoint Energy provides services to its subsidiaries through a service company, its service company is not subject to the service company rules. 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 Condensed 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 the establishment of the Competitive Natural Gas Sales and Services business segment as a new reportable business segment during the fourth quarter of 2005 as discussed in Note 10 and do not affect net income. 5
(2) NEW ACCOUNTING PRONOUNCEMENTS In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, "Fair Value Measurements" (SFAS No. 157). SFAS No. 157 establishes a framework for measuring fair value and requires expanded disclosure about the information used to measure fair value. The statement applies whenever other statements require, or permit, assets or liabilities to be measured at fair value. The statement does not expand the use of fair value accounting in any new circumstances and is effective for the Company for the year ended December 31, 2008 and for interim periods included in that year, with early adoption encouraged. The Company does not expect the adoption of this statement to have a material impact on its financial condition or results of operations. In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans - An Amendment of FASB Statements No. 87, 88, 106 and 132(R)" (SFAS No. 158). SFAS No. 158 requires the Company, as the sponsor of a single employer defined benefit plan, to (a) recognize on its Balance Sheets as an asset a plan's over-funded status or as a liability such plan's under-funded status, (b) measure a plan's assets and obligations that determine its funded status as of the end of the Company's fiscal year and (c) recognize changes in the funded status of a plan in the year in which the changes occur through adjustments to other comprehensive income. SFAS No. 158 is effective for the Company for the year ended December 31, 2006. SFAS No. 158 is expected to require a non-cash charge to the Company's equity to recognize previously unrecognized costs related to its postretirement plan. The amount of the charge is unknown at this time due to possible changes in discount rates and investment returns through year-end. However, if SFAS No. 158 had been adopted as of December 31, 2005, the charge to comprehensive income would have been approximately $13 million (net of tax). The adoption of SFAS No. 158 will not impact the Company's compliance with debt covenants. In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109" (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with FASB Statement No. 109, "Accounting for Income Taxes." FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. The Company expects to adopt FIN 48 in the first quarter of 2007 and is currently evaluating the impact the adoption will have on the Company's financial position. (3) REGULATORY MATTERS (a) Rate Cases. SOUTHERN GAS OPERATIONS South Texas and Beaumont/East 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 annually 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. During the second quarter of 2006, Southern Gas Operations reached settlement agreements with the last of the cities that had denied or appealed the rate change requests. Settlement rates have now been 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. Approximately $3 million of expenditures related to these rate cases was charged to expense during the second quarter of 2006. The settlements also provide that these new rates will not change over the next three to five years. 6
MINNESOTA GAS At September 30, 2006, Minnesota Gas had recorded approximately $45 million as a regulatory asset related to prior years' unrecovered purchased gas costs. Of the total, approximately $24 million relates to the period from July 1, 2004 through June 30, 2006, and approximately $21 million relates to the period from July 1, 2000 through June 30, 2004. The amounts related to periods prior to July 1, 2004 arose as a result of revisions to the calculation of unrecovered purchased gas costs previously approved by the Minnesota Public Utilities Commission (MPUC), and recovery of this regulatory asset is dependent upon obtaining a waiver from the MPUC rules. Minnesota Gas has requested to recover the amounts related to costs prior to July 1, 2004 over a three-year period beginning in 2007. The Minnesota Office of the Attorney General (OAG) and the Minnesota Department of Commerce have filed comments opposing recovery. Any amount not approved by the MPUC will be written off. There is no statutory time frame in which the MPUC must act. 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. On November 2, 2006, the MPUC issued an order approving a rate increase of approximately $21 million. In addition, the MPUC approved a $5 million affordability program to assist low-income customers, the actual cost of which will be recovered in rates in addition to the $21 million rate increase. The proportional share of the excess of the amounts collected in interim rates over the amount allowed by the final order of approximately $8 million has been accrued as of September 30, 2006, and will be refunded to customers in late 2006 or early 2007. 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 OAG issued its report alleging Minnesota Gas had violated the CWR and recommended a $5 million penalty. In addition, in June 2005, the Company 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 August 14, 2006 the court gave final approval to a $13.5 million settlement which resolves all but one small claim against Minnesota Gas which have or could have been asserted by residential natural gas customers in the CWR class action. The agreement was also approved by the MPUC, resolving the claims made by the OAG. During the fourth quarter of 2005, the Company established a litigation reserve to cover the anticipated costs of this settlement. (b) 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 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. The City of Tyler appealed this order to a Travis County District Court, but in April 2006, Southern Gas Operations and the City of Tyler reached a settlement regarding the rates in the City of Tyler and other aspects of the dispute between them. As contemplated by that settlement, the City of Tyler's appeal to the district court was dismissed on July 31, 2006, and the Railroad Commission's final order and findings are no longer subject to further review or modification. (4) 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. 7
Cash Flow Hedges. During each of the three-month and nine-month periods ended September 30, 2005 and 2006, hedge ineffectiveness resulted in a gain of less than $1 million from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses 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 "Expenses" 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 September 30, 2006, the Company expects $18 million ($12 million after-tax) in accumulated other comprehensive income to be reclassified as a decrease 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 up to ten years. The Company's policy is not to exceed ten years in hedging its exposure. Other Derivative Financial Instruments. The Company enters into certain derivative financial instruments to manage physical commodity price risks that do not qualify or are not designated as cash flow or fair value hedges under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). While the Company utilizes these financial instruments to manage physical commodity price risks, it does not engage in proprietary or speculative commodity trading. During the three months ended September 30, 2005 and 2006, the Company recognized unrealized net gains of $2 million and $23 million, respectively, on the derivative financial instruments that had not yet been settled. During the nine months ended September 30, 2005 and 2006, the Company recognized unrealized net gains of $3 million and $37 million, respectively. These derivative gains and losses are included in the Condensed Statements of Consolidated Income under the "Expenses" caption "Natural gas." (5) GOODWILL AND INTANGIBLES Goodwill as of December 31, 2005 and September 30, 2006 by reportable business segment is as follows (in millions): Natural Gas Distribution..................... $ 746 Pipelines and Field Services................. 604 Competitive Natural Gas Sales and Services... 339 Other Operations............................. 20 ------ Total..................................... $1,709 ====== The Company performs its goodwill impairment test at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit's goodwill is determined by allocating the reporting unit's fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference. The Company completed its annual evaluation of goodwill for impairment as of July 1, 2006 and no impairment was indicated. 8
The components of the Company's other intangible assets consist of the following (in millions): DECEMBER 31, 2005 SEPTEMBER 30, 2006 ----------------------- ----------------------- CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION -------- ------------ -------- ------------ Land Use Rights .. $ 7 $ (3) $ 7 $(3) Other ............ 21 (7) 7 (3) --- ---- --- --- Total .......... $28 $(10) $14 $(6) === ==== === === Amortization expense for other intangibles during each of the three-month periods ended September 30, 2005 and 2006 was less than $1 million. Amortization expense for other intangibles during each of the nine-month periods ended September 30, 2005 and 2006 was approximately $1 million. Estimated amortization expense for the remainder of 2006 is less than $1 million and is less than $1 million per year for each of the five succeeding fiscal years. (6) LONG-TERM DEBT AND RECEIVABLES FACILITY (a) Long-Term Debt. In May 2006, the Company issued $325 million aggregate principal amount of senior notes due in May 2016 with an interest rate of 6.15%. The proceeds from the sale of the senior notes will be used for general corporate purposes, including repayment or refinancing of debt (including $145 million of the Company's 8.90% debentures due December 15, 2006), capital expenditures, working capital and loans or advances to affiliates. In March 2006, the Company 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 London Interbank Offered Rate (LIBOR) plus 45 basis points based on the Company'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 the credit facility, 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 Company's credit rating. Borrowings under the facility are subject to customary terms and conditions. However, there is no requirement that the Company 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 the credit facility are subject to acceleration upon the occurrence of events of default that the Company considers customary. As of September 30, 2006, the Company had no borrowings under its $550 million credit facility. The Company was in compliance with all covenants as of September 30, 2006. (b) Receivables Facility. In January 2006, the Company's $250 million receivables facility was extended to January 2007. The facility was temporarily increased to $375 million for the period from January 2006 to June 2006. As of September 30, 2006, no amounts were funded under the Company's receivables facility. Funding under the receivables facility averaged $173 million and $85 million for the nine months ended September 30, 2005 and 2006, respectively. Sales of receivables were approximately $480 million and $-0- million for the three months ended September 30, 2005 and 2006, respectively, and $1.4 billion and $555 million for the nine months ended September 30, 2005 and 2006, respectively. See Note 12 for a discussion of changes to the receivables facility during the fourth quarter of 2006. 9
(7) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income (loss) (net of tax): FOR THE FOR THE THREE MONTHS NINE MONTHS ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, ------------- -------------- 2005 2006 2005 2006 ---- ---- ---- ---- (IN MILLIONS) Net income ................................... $ 4 $13 $127 $133 --- --- ---- ---- Other comprehensive income (loss): Net deferred gain from cash flow hedges ... 1 10 11 5 Reclassification of deferred (gain) loss from cash flow hedges realized in net income ................................. (7) 1 (9) (3) --- --- ---- ---- Other comprehensive income (loss) ............ (6) 11 2 2 --- --- ---- ---- Comprehensive income (loss) .................. $(2) $24 $129 $135 === === ==== ==== The Company had a net deferred gain from cash flow hedges of $11 million and $13 million recorded in accumulated other comprehensive income at December 31, 2005 and September 30, 2006, respectively. (8) RELATED PARTY TRANSACTIONS The Company participates in a "money pool" through which it 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. As of December 31, 2005, the Company had borrowings from the money pool of $289 million, but had no borrowings from the money pool as of September 30, 2006. For the three months ended September 30, 2005 and 2006, the Company had net interest income related to affiliate borrowings of approximately $1 million and $-0-, respectively. For the nine months ended September 30, 2005 and 2006, the Company had net interest income (expense) related to affiliate borrowings of approximately $4 million and $(1) million, respectively. CenterPoint Energy provides some corporate services to the Company. The costs of services have been charged directly to the Company using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment, and proportionate corporate formulas based on assets, operating expenses and employees. These charges are not necessarily indicative of what would have been incurred had the Company not been an affiliate. Amounts charged to the Company for these services were $33 million and $31 million for the three-month periods ended September 30, 2005 and 2006, respectively, and $93 million and $95 million for the nine-month periods ended September 30, 2005 and 2006, respectively, and are included primarily in operation and maintenance expenses. (9) COMMITMENTS AND CONTINGENCIES (a) Natural Gas Supply Commitments. Natural gas supply commitments include natural gas contracts related to the Company's natural gas distribution and competitive natural gas sales and services operations, which have various quantity requirements and durations that are not classified as non-trading derivative assets and liabilities in the Company's Consolidated Balance Sheets as of December 31, 2005 and September 30, 2006 as these contracts meet the SFAS No. 133 exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts which do not meet the definition of a derivative. As of September 30, 2006, minimum payment obligations for natural gas supply commitments are approximately $302 million for the remaining three months in 2006, $724 million in 2007, $230 million in 2008, $131 million in 2009, $130 million in 2010 and $733 million in 2011 and thereafter. (b) 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 10
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. The capacity of the pipeline under this filing will be 1.25 billion cubic feet (Bcf) per day. CEGT has signed firm contracts for the full capacity of the pipeline. On October 2, 2006 the FERC issued CEGT's certificate to construct, own and operate the pipeline and compression facilities. CEGT has begun construction of the facilities and expects to place the facilities in service in the first quarter 2007 at a cost of approximately $455 million. Based on strong interest expressed during an open season held earlier this year, and subject to FERC approval, CEGT expects to expand capacity of the pipeline to 1.5 Bcf per day, which would bring the total estimated capital cost of the project to approximately $510 million. 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 and to FERC approval, CEGT would construct a 67-mile extension from CEGT's Perryville hub to an interconnect with Texas Eastern Gas Transmission at Union Church, Mississippi. Earlier this year, CenterPoint Energy Southeast Pipelines Holding, L.L.C., a wholly owned subsidiary of CERC Corp., signed a joint venture agreement with a subsidiary of Duke Energy Gas Transmission (DEGT) to construct, own and operate a 270-mile pipeline (Southeast Supply Header) that will extend from CEGT's Perryville hub in northeast Louisiana to Gulfstream Natural Gas System, which is 50 percent owned by an affiliate of DEGT. In August 2006, the joint venture signed an agreement with Florida Power & Light Company (FPL) for firm transportation services, which subscribes approximately half of the planned 1 Bcf per day capacity of the pipeline. FPL's commitment is contingent on the approval of the FPL contract by the Florida Public Service Commission in December 2006. Subject to the venture receiving a certificate from the FERC to construct, own and operate the pipeline, subsidiaries of DEGT and CERC Corp. have committed to build the pipeline, for which total costs are estimated to be $700 to $800 million. The pre-filing process with the FERC has been initiated, and an application is expected to be filed in December 2006. Once the project is approved by the FERC, construction is anticipated to begin in the fourth quarter of 2007, with an expected in-service date of June 2008. (c) 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. On October 20, 2006, the judge considering this matter granted defendants' motion to dismiss the suit on the ground that the court lacked subject matter jurisdiction over the claims asserted. In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs' alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two of CERC Corp.'s 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 Corp. and its subsidiaries believe that there has been no systematic mismeasurement of gas and that the suits are without merit. The Company does not expect the ultimate outcome to have a material impact on its financial condition, results of operations or cash flows. Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CenterPoint Energy, Entex Gas Marketing Company, and certain non-affiliated companies 11
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., CEGT, 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 the Company 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 the Company 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, CenterPoint Energy, Entex Gas Marketing Company, CEGT, CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc., CenterPoint Energy - Mississippi River Transmission Corp. (CEMRT) 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. Subsequently, the plaintiffs dropped as defendants CEGT and CEMRT. 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, CenterPoint Energy 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 and municipal regulatory authorities. The allegations in these cases are similar to those asserted in the City of Tyler proceeding as described in Note 3(b). The Company does not expect the outcome of these matters to have a material impact on its financial condition, results of operations or cash flows. Pipeline Safety Compliance. Pursuant to an order from the Minnesota Office of Pipeline Safety, the Company 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 the Company 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. The MPUC's order in the rate case allowed the capitalized expenditures, plus approximately $2 million previously expensed in 2005, to be included in rate base. However, recovery of approximately $4 million of the $41 million is deferred pending the outcome of litigation against the predecessor companies that installed the original service lines. Minnesota Cold Weather Rule. For a discussion of this matter, see Note 3(a). (d) 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 12
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 parties have reached an agreement on terms of a settlement in principle of this matter. That settlement would require approvals from the Louisiana Department of Environmental Quality of an acceptable remediation plan that could be implemented by the Company. The Company currently is seeking that approval. If the currently agreed terms for settlement are ultimately implemented, the Company does not expect the ultimate cost associated with resolving this matter to have a material impact on its financial condition, results of operations or cash flows. Manufactured Gas Plant Sites. The Company and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, the Company has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in the Company's Minnesota service territory. The Company believes that it has no liability with respect to two of these sites. At September 30, 2006, the Company had accrued $14 million for remediation of these Minnesota sites. At September 30, 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. The Company has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of September 30, 2006, the Company 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 the Company or may have been owned by one of its former affiliates. The Company has been named as a defendant in two lawsuits, one filed in United States District Court, District of Maine and the other filed in 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 the Company or its divisions. The Company 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 federal district court considering the suit for contribution in Florida granted the Company's motion to dismiss on the grounds that the Company was not an "operator" of the site as had been alleged. In October 2006, the 11th Circuit Court of Appeals affirmed the court's dismissal of the Company. In June 2006 the federal district court in Maine that is considering the other suit ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing is required to determine if other potentially responsible parties, including the Company, would have to contribute to that remediation. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, the Company believes it is not liable as a former owner or operator of those sites under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting those suits and its designation as a PRP. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. 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. Some facilities formerly owned by the Company's predecessors have contained asbestos insulation and other asbestos-containing materials. The Company or its predecessor companies have been named, along with numerous others, as a defendant in lawsuits filed by certain individuals who claim injury due to exposure to asbestos during work at such formerly owned facilities. The Company anticipates that additional claims like those received may be asserted in the future. 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. 13
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. (e) 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 regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company 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. (f) Guarantees. Prior to CenterPoint Energy's distribution of its ownership in Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (RRI) to its shareholders, the Company 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 the Company against obligations under the remaining guarantees, RRI agreed to provide cash or letters of credit for the benefit of the Company and CenterPoint Energy, and agreed to use commercially reasonable efforts to extinguish the remaining guarantees. CenterPoint Energy and the Company's current exposure under the remaining guarantees relates to the Company'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, the Company'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 the Company's obligations under the guarantee. On June 30, 2006, the RRI trading subsidiary and the Company jointly filed a complaint at the FERC against the counterparty on the Company's guarantee. In the complaint, the RRI trading subsidiary seeks a determination by the FERC that the security held by the counterparty exceeds the level permitted by the FERC's policies. The complaint asks the FERC to require the counterparty to release the Company from its guarantee obligation and, in its place accept (i) a guarantee from RRI of the obligations of the RRI trading subsidiary, and (ii) letters of credit equal to (A) one year of demand charges for a transportation agreement related to a 2003 expansion of the counterparty's pipeline, and (B) three months of demand charges for three other transportation agreements held by the RRI trading subsidiary. On July 20, 2006, the counterparty filed its answer to the complaint, arguing that the Company is contractually bound to continue the guarantee, that the amount of the guarantee does not violate the FERC's policies and that the proposed substitution of credit support is not authorized under the counterparty's financing documents. CenterPoint Energy and the RRI trading subsidiary have filed a reply to that answer and, in response to a FERC order, the counterparty has submitted financing documents for FERC review. It is presently unknown what action the FERC may take on the complaint. The RRI trading subsidiary continues to meet its obligations under the transportation contracts. (g) Tax Contingencies. The Company has established reserves for certain 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 these tax items was approximately $32 million and $28 million as of December 31, 2005 and September 30, 2006, respectively. (10) REPORTABLE BUSINESS SEGMENTS Because the Company is an indirect wholly owned subsidiary of CenterPoint Energy, the Company's determination of reportable business segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale 14
or retail customers in differing regulatory environments. The accounting policies of the business segments 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: Natural Gas Distribution, Competitive Natural Gas Sales and Services, Pipelines and Field Services and Other Operations. 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. The following tables summarize financial data for the Company's reportable business segments (in millions): FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005 ---------------------------------------- REVENUES FROM NET OPERATING EXTERNAL INTERSEGMENT INCOME CUSTOMERS REVENUES (LOSS) ------------- ------------ --------- Natural Gas Distribution ..................... $ 532 $ 3 $(16) Competitive Natural Gas Sales and Services ... 974 39 4 Pipelines and Field Services ................. 81 35 52 Other Operations ............................. -- 2 -- Eliminations ................................. -- (79) -- ------ ---- ---- Consolidated ................................. $1,587 $ -- $ 40 ====== ==== ==== FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2006 ---------------------------------------- REVENUES FROM NET OPERATING EXTERNAL INTERSEGMENT INCOME CUSTOMERS REVENUES (LOSS) ------------- ------------ --------- Natural Gas Distribution ..................... $ 483 $ 2 $(11) Competitive Natural Gas Sales and Services ... 813 17 12 Pipelines and Field Services ................. 104 37 69 Other Operations ............................. -- -- (1) Eliminations ................................. -- (56) -- ------ ---- ---- Consolidated ................................. $1,400 $ -- $ 69 ====== ==== ==== FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005 ---------------------------------------- REVENUES FROM NET OPERATING TOTAL ASSETS EXTERNAL INTERSEGMENT INCOME AS OF CUSTOMERS REVENUES (LOSS) DECEMBER 31, 2005 ------------- ------------ --------- ----------------- Natural Gas Distribution ..................... $2,399 $ 6 $116 $ 4,612 Competitive Natural Gas Sales and Services ... 2,607 176 30 1,849 Pipelines and Field Services ................. 252 110 168 2,968 Other Operations ............................. 3 6 (3) 743 Eliminations ................................. -- (298) -- (1,871) ------ ----- ---- ------- Consolidated ................................. $5,261 $ -- $311 $ 8,301 ====== ===== ==== ======= 15
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2006 ---------------------------------------- REVENUES FROM NET OPERATING TOTAL ASSETS EXTERNAL INTERSEGMENT INCOME AS OF CUSTOMERS REVENUES (LOSS) SEPTEMBER 30, 2006 ------------- ------------ --------- ------------------ Natural Gas Distribution ..................... $2,506 $ 8 $ 90 $ 4,260 Competitive Natural Gas Sales and Services ... 2,681 62 44 1,402 Pipelines and Field Services ................. 287 114 203 3,157 Other Operations ............................. -- 4 (3) 473 Eliminations ................................. -- (188) -- (1,257) ------ ----- ---- ------- Consolidated ................................. $5,474 $ -- $334 $ 8,035 ====== ===== ==== ======= (11) EMPLOYEE BENEFIT PLANS The Company's employees participate in CenterPoint Energy's postretirement benefits plan. The Company's net periodic cost includes the following components relating to postretirement benefits: THREE MONTHS NINE MONTHS ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, ------------- ------------- 2005 2006 2005 2006 ---- ---- ---- ---- (IN MILLIONS) Service cost ......................... $-- $-- $ 1 $ 1 Interest cost ........................ 2 2 6 5 Expected return on plan assets ....... -- -- (1) (1) Amortization of prior service cost ... -- -- 1 1 Benefit enhancement .................. -- -- -- 1 Other ................................ 1 -- 1 -- --- --- --- --- Net periodic cost ................. $ 3 $ 2 $ 8 $ 7 === === === === The Company expects to contribute approximately $13 million to CenterPoint Energy's postretirement benefits plan in 2006, of which $12 million had been contributed as of September 30, 2006. (12) SUBSEQUENT EVENT In October 2006, the Company extended the termination date of its receivables facility to October 30, 2007. The facility size is $250 million until December 2006, $375 million from December 2006 to May 2007 and ranges from $150 million to $325 million during the period from May 2007 to the termination date of the facility. 16
ITEM 2. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS The following narrative analysis should be read in combination with our Interim Condensed Financial Statements contained in Item 1 of this report. We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management's Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three and nine months ended September 30, 2005 and 2006. Reference is made to "Management's Narrative Analysis of the Results of Operations" in Item 7 of the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2005 (CERC Corp. Form 10-K). RECENT EVENTS Carthage to Perryville Pipeline. In October 2005, CenterPoint Energy Gas Transmission Company (CEGT), a wholly owned subsidiary of CenterPoint Energy Resources Corp. (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 Federal Energy Regulatory Commission (FERC) in March 2006 to build a 172-mile, 42-inch diameter pipeline and related compression facilities. The capacity of the pipeline under this filing will be 1.25 billion cubic feet (Bcf) per day. CEGT has signed firm contracts for the full capacity of the pipeline. On October 2, 2006 the FERC issued CEGT's certificate to construct, own and operate the pipeline and compression facilities. CEGT has begun construction of the facilities and expects to place the facilities in service in the first quarter 2007 at a cost of approximately $455 million. Based on strong interest expressed during an open season held earlier this year, and subject to FERC approval, CEGT expects to expand capacity of the pipeline to 1.5 Bcf per day, which would bring the total estimated capital cost of the project to approximately $510 million. 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 and to FERC approval, CEGT would construct a 67-mile extension from CEGT's Perryville hub to an interconnect with Texas Eastern Gas Transmission at Union Church, Mississippi. Pipeline Joint Venture with Duke Energy Subsidiary. Earlier this year, CenterPoint Energy Southeast Pipelines Holding, L.L.C., a wholly owned subsidiary of CERC Corp., signed a joint venture agreement with a subsidiary of Duke Energy Gas Transmission (DEGT) to construct, own and operate a 270-mile pipeline (Southeast Supply Header) that will extend from CEGT's Perryville hub in northeast Louisiana to Gulfstream Natural Gas System, which is 50 percent owned by an affiliate of DEGT. In August 2006, the joint venture signed an agreement with Florida Power & Light Company (FPL) for firm transportation services, which subscribes approximately half of the planned 1 Bcf per day capacity of the pipeline. FPL's commitment is contingent on the approval of the FPL contract by the Florida Public Service Commission in December 2006. Subject to the venture receiving a certificate from the FERC to construct, own and operate the pipeline, subsidiaries of DEGT and CERC Corp. have committed to build the pipeline, for which total costs are estimated to be $700 to $800 million. The pre-filing process with the FERC has been initiated, and an application is expected to be filed in December 2006. Once the project is approved by the FERC, construction is anticipated to begin in the fourth quarter of 2007, with an expected in-service date of June 2008. CONSOLIDATED RESULTS OF OPERATIONS Our results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities. Our results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates we charge, competition in our various business operations, debt service costs and income tax expense. For more information regarding factors that may affect the future results of operations of our business, please read "Risk Factors" in Item 1A of Part I of the CERC Corp. Form 10-K and "Risk Factors" in Item 1A of Part II of this Quarterly Report on Form 10-Q. 17
The following table sets forth our consolidated results of operations for the three months and nine months ended September 30, 2005 and 2006, followed by a discussion of the results of operations by business segment based on operating income. We have provided a reconciliation of consolidated operating income to net income below. THREE MONTHS NINE MONTHS ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, --------------- --------------- 2005 2006 2005 2006 ------ ------ ------ ------ (IN MILLIONS) Revenues ............................. $1,587 $1,400 $5,261 $5,474 ------ ------ ------ ------ Expenses: Natural gas ....................... 1,277 1,058 4,161 4,286 Operation and maintenance ......... 188 192 532 588 Depreciation and amortization ..... 50 50 149 150 Taxes other than income taxes ..... 32 31 108 116 ------ ------ ------ ------ Total Expenses ................. 1,547 1,331 4,950 5,140 ------ ------ ------ ------ Operating Income ..................... 40 69 311 334 Interest and Other Finance Charges ... (39) (43) (136) (125) Other Income, net .................... 6 7 18 15 ------ ------ ------ ------ Income Before Income Taxes ........... 7 33 193 224 Income Tax Expense ................... (3) (20) (66) (91) ------ ------ ------ ------ Net Income ........................... $ 4 $ 13 $ 127 $ 133 ====== ====== ====== ====== THREE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2005 Net Income.. We reported net income of $13 million for the three months ended September 30, 2006 as compared to $4 million for the same period in 2005. As discussed below, the increase in net income of $9 million was primarily due to: - a $17 million increase in operating income from our Pipelines and Field Services business segment; - an $8 million increase in operating income from our Competitive Natural Gas Sales and Services business segment; and - a $5 million decrease in operating loss from our Natural Gas Distribution business segment. These increases were partially offset by: - a $17 million increase in income taxes resulting from higher income and deferred state taxes; and - a $4 million increase in interest expense. NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2005 Net Income.. We reported net income of $133 million for the nine months ended September 30, 2006 as compared to $127 million for the same period in 2005. As discussed below, the increase in net income of $6 million was primarily due to: - a $35 million increase in operating income from our Pipelines and Field Services business segment; - a $14 million increase in operating income from our Competitive Natural Gas Sales and Services business segment; and - an $11 million decrease in interest expense. These increases were partially offset by: - a $26 million decrease in operating income from our Natural Gas Distribution business segment; and - a $25 million increase in income taxes resulting from higher income and deferred state taxes. 18
RESULTS OF OPERATIONS BY BUSINESS SEGMENT 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. Revenues by segment include intersegment sales, which are eliminated in consolidation. NATURAL GAS DISTRIBUTION The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2005 and 2006 (in millions, except throughput and customer data): THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ----------------------- 2005 2006 2005 2006 ---------- ---------- ---------- ---------- Revenues ................................ $ 535 $ 485 $ 2,405 $ 2,514 ---------- ---------- ---------- ---------- Expenses: Natural gas .......................... 355 298 1,693 1,787 Operation and maintenance ............ 132 137 393 429 Depreciation and amortization ........ 39 38 115 113 Taxes other than income taxes ........ 25 23 88 95 ---------- ---------- ---------- ---------- Total expenses .................... 551 496 2,289 2,424 ---------- ---------- ---------- ---------- Operating Income (Loss) ................. $ (16) $ (11) $ 116 $ 90 ========== ========== ========== ========== Throughput (in billion cubic feet (Bcf)): Residential .......................... 9 14 107 98 Commercial and industrial ............ 38 44 158 160 ---------- ---------- ---------- ---------- Total Throughput .................. 47 58 265 258 ========== ========== ========== ========== Average number of customers: Residential .......................... 2,820,629 2,849,040 2,835,306 2,864,999 Commercial and industrial ............ 244,249 253,063 246,370 253,357 ---------- ---------- ---------- ---------- Total ............................. 3,064,878 3,102,103 3,081,676 3,118,356 ========== ========== ========== ========== THREE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2005 Our Natural Gas Distribution business segment reported an operating loss of $11 million for the three months ended September 30, 2006 as compared to an operating loss of $16 million for the three months ended September 30, 2005. Due to seasonal impacts, the third quarter for this business segment is typically one of the weakest of the year. Higher operating margins (revenues less natural gas costs) from rate increases and rate design changes, along with the addition of nearly 43,000 customers since September 2005 ($7 million) were partially offset by increased operation and maintenance expenses driven primarily by higher bad debt expense due to high natural gas prices ($5 million). NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2005 Our Natural Gas Distribution business segment reported operating income of $90 million for the nine months ended September 30, 2006 as compared to $116 million for the nine months ended September 30, 2005. Increased operating margins from rate increases and rate design changes, along with the addition of nearly 43,000 customers since September 2005 ($26 million) and increased gross receipts taxes resulting from higher revenues ($6 million), were partially offset by decreased customer usage and unfavorable weather ($20 million). Operation and maintenance expenses increased primarily due to costs associated with staff reductions ($12 million), increased bad debt expense due to high natural gas prices ($11 million), increased contracts and services expenses and corporate services ($8 million) and a write-off of certain rate case expenses ($3 million). Additionally, taxes other than income taxes increased ($7 million) primarily due to higher gross receipts taxes ($6 million), which offset the corresponding increase in revenues discussed above. 19
COMPETITIVE NATURAL GAS SALES AND SERVICES The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three and nine months ended September 30, 2005 and 2006 (in millions, except throughput and customer data): THREE MONTHS NINE MONTHS ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, --------------- --------------- 2005 2006 2005 2006 ------ ------ ------ ------ Revenues ........................... $1,013 $ 830 $2,783 $2,743 ------ ------ ------ ------ Expenses: Natural gas ..................... 998 809 2,728 2,673 Operation and maintenance ....... 9 8 21 23 Depreciation and amortization ... -- -- 1 1 Taxes other than income taxes ... 2 1 3 2 ------ ------ ------ ------ Total expenses ............... 1,009 818 2,753 2,699 ------ ------ ------ ------ Operating Income ................... $ 4 $ 12 $ 30 $ 44 ====== ====== ====== ====== Throughput (in Bcf): Wholesale - third parties ....... 81 90 235 251 Wholesale - affiliates .......... 11 8 46 27 Retail .......................... 31 31 112 110 Pipeline ........................ 10 9 41 28 ------ ------ ------ ------ Total Throughput ............. 133 138 434 416 ====== ====== ====== ====== Average number of customers: Wholesale ....................... 144 140 143 140 Retail .......................... 6,225 6,213 6,203 6,416 Pipeline ........................ 147 138 154 138 ------ ------ ------ ------ Total ........................ 6,516 6,491 6,500 6,694 ====== ====== ====== ====== THREE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2005 Our Competitive Natural Gas Sales and Services business segment reported operating income of $12 million for the three months ended September 30, 2006 as compared to $4 million for the three months ended September 30, 2005. The increase was primarily driven by increased sales of gas from inventory ($9 million), reduced bad debt expenses ($2 million) and a favorable variance related to mark-to-market accounting for non-trading financial derivatives used to lock in the economic value associated with basis differentials ($21 million). These positive variances were partially offset by a write-down of natural gas inventory to the lower of average cost or market ($26 million). Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales. Due to the inventory write-downs, operating income in the future periods, when these sales of inventory occur, is expected to be higher. NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2005 Our Competitive Natural Gas Sales and Services business segment reported operating income of $44 million for the nine months ended September 30, 2006 as compared to $30 million for the nine months ended September 30, 2005. The increase included improved margins ($38 million) and a favorable variance related to mark-to-market accounting ($34 million), which was partially offset by a write-down of natural gas inventory ($56 million). 20
PIPELINES AND FIELD SERVICES The following table provides summary data of our Pipelines and Field Services business segment for the three and nine months ended September 30, 2005 and 2006 (in millions, except throughput data): THREE MONTHS NINE MONTHS ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, ------------- ------------- 2005 2006 2005 2006 ---- ---- ---- ---- Revenues ..................................... $116 $141 $362 $401 ---- ---- ---- ---- Expenses: Natural gas ............................... -- 7 25 10 Operation and maintenance ................. 47 47 121 136 Depreciation and amortization ............. 12 12 34 36 Taxes other than income taxes ............. 5 6 14 16 ---- ---- ---- ---- Total expenses ......................... 64 72 194 198 ---- ---- ---- ---- Operating Income ............................. $ 52 $ 69 $168 $203 ==== ==== ==== ==== Operating Income - Pipeline business ......... $ 36 $ 48 $119 $137 Operating Income - Field Services business ... 16 21 49 66 ---- ---- ---- ---- Total segment operating income ......... $ 52 $ 69 $168 $203 ==== ==== ==== ==== Throughput (in Bcf): Natural Gas Sales ......................... -- 1 4 3 Transportation ............................ 199 204 700 718 Gathering ................................. 92 97 262 279 Elimination (1) ........................... (1) (1) (4) (2) ---- ---- ---- ---- Total Throughput ....................... 290 301 962 998 ==== ==== ==== ==== - ---------- (1) Elimination of volumes both transported and sold. THREE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2005 Our Pipelines and Field Services business segment reported operating income of $69 million for the three months ended September 30, 2006 as compared to $52 million for the three months ended September 30, 2005. This segment's businesses continue to benefit from favorable dynamics in the markets for natural gas gathering and transportation services in the Gulf Coast and Mid-Continent regions. Within this segment, the pipeline business achieved higher operating income of $48 million for the three months ended September 30, 2006 as compared to $36 million for the same period in 2005. This $12 million increase was largely attributable to a pre-tax gain of $13 million associated with the FERC authorized sale of cushion gas which is no longer required for operational purposes as the result of certain capital improvements to enhance working gas capacity and deliverability at one of our storage facilities. The field services business achieved higher operating income of $21 million for the three months ended September 30, 2006 as compared to $16 million for the same period in 2005 primarily driven by increased throughput ($7 million). In addition, this business segment recorded equity income of $1 million and $2 million for the three months ended September 30, 2005 and 2006, respectively, from its 50 percent interest in a jointly-owned gas processing plant. These amounts are included in Other - net under the Other Income (Expense) caption in our Condensed Statements of Consolidated Income. NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2005 Our Pipelines and Field Services business segment reported operating income of $203 million for the nine months ended September 30, 2006 as compared to $168 million for the nine months ended September 30, 2005. The pipeline business achieved operating income of $137 million for the nine months ended September 30, 2006 as compared to $119 million for the same period in 2005. This $18 million increase is attributable to the gain on the sale of cushion gas ($13 million) discussed above, increased demand for transportation due to favorable basis differentials across the system ($9 million), higher demand for ancillary services ($6 million) and increased project-related revenues ($5 million). These favorable variances were partially offset by increased operating expenses related to increased project-related expenses ($4 million), increased labor-related costs ($3 million) and increased costs associated with normal pipeline maintenance, compliance with pipeline integrity regulations and normal price 21
level increases ($8 million). The field services business achieved operating income of $66 million for the nine months ended September 30, 2006 as compared to $49 million for the same period in 2005 driven by increased throughput ($14 million), higher commodity prices ($7 million) and higher demand for ancillary services ($2 million), partially offset by increased operation and maintenance expenses ($6 million). Equity income from the jointly-owned gas processing plant discussed above was $4 million and $7 million for the nine months ended September 30, 2005 and 2006, respectively. CERTAIN FACTORS AFFECTING FUTURE EARNINGS For information on other developments, factors and trends that may have an impact on our future earnings, please read "Risk Factors" in Item 1A of Part I and "Management's Narrative Analysis of Results of Operations -- Certain Factors Affecting Future Earnings" in Item 7 of Part II of the CERC Corp. Form 10-K and "Risk Factors" in Item 1A of Part II of this Quarterly Report on Form 10-Q. LIQUIDITY AND CAPITAL RESOURCES Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, and working capital needs. Our principal cash requirements for the remaining three months of 2006 are: - approximately $325 million of capital expenditures, including approximately $200 million related to our Carthage to Perryville pipeline project discussed above; and - long-term debt payments of $145 million. We expect that borrowings under our credit facility, liquidation of temporary investments, the issuance of securities in the capital markets and anticipated cash flows from operations will be sufficient to meet our cash needs for the next twelve months. Contractual Obligations. We negotiated new natural gas transportation contracts during 2006 which was the primary reason for a $933 million increase in the amount of other commodity commitments from the contractual obligations reported in the CERC Corp. Form 10-K. Minimum payment obligations for natural gas supply and related transportation contracts are approximately $302 million for the remaining three months in 2006, $724 million in 2007, $230 million in 2008, $131 million in 2009, $130 million in 2010 and $733 million in 2011 and thereafter. Arkansas Public Service Commission, Affiliate Transaction Rulemaking Proceeding. On August 10, 2006, the Arkansas Public Service Commission (APSC) instituted a rulemaking proceeding to promulgate rules governing affiliate transactions involving public utilities operating in Arkansas. The proposed rules would treat as affiliate transactions all transactions between our Arkansas utility operations and other divisions, as well as transactions between the Arkansas utility operations and our affiliates. All such affiliate transactions would have to be priced under an asymmetrical pricing formula under which the Arkansas utility operations would benefit from any difference between the cost of providing goods and services to or from the Arkansas utility operations and the market value of those goods or services. The Arkansas utility operations could not participate in any financing other than to finance retail utility operations in Arkansas, which would preclude continuation of existing financing arrangements in which we finance our divisions and subsidiaries, including our Arkansas utility operations. Currently, we provide financing for all regulated gas distribution divisions in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas and for our pipeline, field services, gas services and other unregulated businesses. Under the proposed rules, utilities operating in Arkansas would be required to provide annual certifications from the utility's chief executive and chief financial officers that the rules have been complied with during the previous year, and the utility would be required to fund, without recovery through rates or otherwise, the cost of an annual audit of the utility's compliance with the requirements of the affiliated transactions rules. The utility would be restricted in the level of its non-utility activities and could be required to terminate relationships with affiliates (including its parent) if the APSC were to find that a downgrade of the utility's bond ratings below investment grade would not have occurred but for its relationship with that affiliate. The utility or its parent utility holding company 22
would also be required to file an annual report, signed by its president, certifying that the utility is in compliance with the rules regarding non-utility ownership and providing financial information necessary to demonstrate compliance. No prediction can be made at this time as to whether, or in what form, the proposed Arkansas affiliate transaction rules will be adopted. However, if the rules are adopted as proposed, the rules would have significant adverse effects on our ability to operate our utility operations in Arkansas. At a minimum, a restructuring would be required to create a legal separation of our Arkansas utility operations from our other utility and non-utility activities. Financing separate from the financing that we currently provide for our utility and non-utility operations would be required for the Arkansas utility operations. Further, it is still unclear whether we would be able to restructure our organization and financing arrangements in order to comply with the proposed rules. It is also unclear whether, even after such a restructuring, the Arkansas utility operations could provide cost-effective utility service in Arkansas. Under the procedural schedule established by the APSC, comments on the proposed rules were filed with the APSC by us and other interested persons on October 6, 2006 and reply comments were filed October 27, 2006. A hearing on the adoption of the proposed rules is scheduled for November 8, 2006. We are vigorously contesting the adoption of the proposed rules by the APSC in their current form on the grounds that (i) the proposed rules exceed the statutory authority granted to APSC on the matters covered by the proposed rules, (ii) their implementation would violate the Interstate Commerce Clause of the U.S. Constitution, and (iii) the rules would adversely affect service provided to Arkansas consumers. 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. We have a bankruptcy remote subsidiary, which we consolidate, which was formed for the sole purpose of buying receivables created by us 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 October 2006, the termination date of our receivables facility was extended to October 2007. As of September 30, 2006, no amounts were funded under such facility. The facility size is $250 million until December 2006, $375 million from December 2006 to May 2007 and ranges from $150 million to $325 million during the period from May 2007 to the termination date of the facility. Prior to CenterPoint Energy's distribution of its ownership in Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (RRI) to its shareholders, we 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 us against obligations under the remaining guarantees, RRI agreed to provide cash or letters of credit for our benefit and that of CenterPoint Energy, and agreed to use commercially reasonable efforts to extinguish the remaining guarantees. CenterPoint Energy's and our current exposure under the remaining guarantees relates to our 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, our 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 our obligations under the guarantee. On June 30, 2006, we and the RRI trading subsidiary jointly filed a complaint at the FERC against the counterparty on our guarantee. In the complaint, the RRI trading subsidiary seeks a determination by the FERC that the security held by the counterparty exceeds the level permitted by the FERC's policies. The complaint asks the FERC to require the counterparty to release us from our guarantee obligation and, in its place accept (i) a guarantee from RRI of the obligations of the RRI trading subsidiary, and (ii) letters of credit equal to (A) one year of demand charges for a transportation agreement related to a 2003 expansion of the counterparty's pipeline, and (B) three months of demand charges for three other transportation agreements held by the RRI trading subsidiary. On July 20, 2006, the counterparty filed its answer to the complaint, arguing that we are contractually bound to continue the guarantee and that the amount of the guarantee does not violate the FERC's policies. The complaint is in its beginning stages, and it is presently unknown what action the FERC may take on the complaint. The RRI trading subsidiary continues to meet its obligations under the transportation contracts. 23
Senior Notes. In May 2006, we issued $325 million aggregate principal amount of senior notes due in May 2016 with an interest rate of 6.15%. The proceeds from the sale of the senior notes will be used for general corporate purposes, including repayment or refinancing of debt (including $145 million of our 8.90% debentures due December 15, 2006), capital expenditures, working capital and loans or advances to affiliates. Credit Facilities. In March 2006, we replaced our $400 million five-year revolving credit facility with a $550 million five-year revolving credit facility. The facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 45 basis points based on our 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 the credit facility, 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 our credit rating. Borrowings under the facility are subject to customary terms and conditions. However, there is no requirement that we 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 the credit facility are subject to acceleration upon the occurrence of events of default that we consider customary. We are currently in compliance with the various business and financial covenants contained in the credit facility. As of October 31, 2006, we had no borrowings and approximately $4 million of outstanding letters of credit under our credit facility. Securities Registered with the SEC. At September 30, 2006, we had a shelf registration statement covering $500 million principal amount of debt securities. Temporary Investments. As of October 31, 2006, we had external temporary investments of $91 million. Money Pool. We participate in a "money pool" through which we and certain of our affiliates 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. At October 31, 2006, we had no borrowings from the money pool. The money pool may not provide sufficient funds to meet our cash needs. Impact on Liquidity of a Downgrade in Credit Ratings. As of October 31, 2006, Moody's Investors Service, Inc. (Moody's), Standard & Poor's Ratings Services, a division of The McGraw-Hill Companies (S&P) and Fitch, Inc. (Fitch) had assigned the following credit ratings to our senior unsecured debt: MOODY'S S&P FITCH - ------------------- ------------------- ------------------- RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3) - ------ ---------- ------ ---------- ------ ---------- 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. We cannot assure you that these 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, the willingness of suppliers to extend credit lines to us on an unsecured basis and the execution of our commercial strategies. 24
A decline in credit ratings could increase borrowing costs under our $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. 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, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the mark-to-market exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. Should the credit ratings of CERC Corp. (the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral on two business days' notice up to the amount of its previously unsecured credit limit. We estimate that as of September 30, 2006, unsecured credit limits extended to CES by counterparties aggregate $133 million; however, utilized credit capacity is significantly lower. In addition, CERC Corp. and its subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on CERC Corp.'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. In connection with the development of the Southeast Supply Header, CERC Corp. has committed that it will advance funds to the joint venture or cause funds to be advanced, up to $400 million, for its 50 percent share of the cost to construct the pipeline. CERC Corp. also agreed to provide a letter of credit in the amount of its share of funds which have not been advanced in the event S&P reduces CERC Corp.'s bond rating below investment grade after November 30, 2006 and before CERC Corp. has advanced the required construction funds. However, CERC Corp. is relieved of these commitments (i) to the extent of 50 percent of any borrowing agreements that the joint venture has obtained and maintains for funding the construction of the pipeline and (ii) to the extent CERC Corp. or its subsidiary participating in the joint venture obtains committed borrowing agreements pursuant to which funds may be borrowed and used for the construction of the pipeline. A similar commitment has been provided by the other party to the joint venture. Cross Defaults. Under CenterPoint Energy's revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us will cause a default. Pursuant to the indenture governing CenterPoint Energy's senior notes, a payment default by us, 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 October 31, 2006, CenterPoint Energy 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 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 natural gas suppliers; - increased costs related to the acquisition of natural gas; - increases in interest expense in connection with debt refinancings and borrowings under credit facilities; - various regulatory actions; 25
- the ability of RRI and its subsidiaries to satisfy their obligations to us or in connection with the contractual arrangement pursuant to which we are a guarantor; - slower customer payments and increased write-offs of receivables due to higher gas prices; - the outcome of litigation brought by and against us; - 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 the CERC Corp. Form 10-K and in "Risk Factors" in Item 1A of Part II of this Quarterly Report on Form 10-Q. Certain Contractual Limits on Ability to Issue Securities and Pay Dividends. Our bank facility and our receivables facility limit our debt as a percentage of our total capitalization to 65 percent. Relationship with CenterPoint Energy. We are an indirect wholly owned subsidiary of CenterPoint Energy. As a result of this relationship, the financial condition and liquidity of our parent company could affect our access to capital, our credit standing and our financial condition. 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 the CERC Corp. 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 of CenterPoint Energy. 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 annually for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible Assets." No impairment of goodwill was indicated based on our annual analysis as of July 1, 2006. 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. 26
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; - 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 4%. Similarly, an increase in the discount rate by 25 basis points would decrease asset retirement obligations by approximately 3%. At September 30, 2006, our estimated cost of retiring these assets was approximately $66 million. UNBILLED REVENUES Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of 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 natural gas delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. 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. NEW ACCOUNTING PRONOUNCEMENTS See Note 2 to the Interim Condensed Financial Statements for a discussion of new accounting pronouncements that affect us. ITEM 4. CONTROLS AND PROCEDURES In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 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 September 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. 27
PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS For a discussion of material legal and regulatory proceedings affecting us, please read Notes 3 and 9 to our Interim Condensed 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 the CERC Corp. Form 10-K. ITEM 1A. RISK FACTORS Other than with respect to the risk factor related to our Pipelines and Field Services business segment set forth below, there have been no material changes from the risk factors disclosed in the CERC Corp. Form 10-K. THE ACTUAL CONSTRUCTION COSTS OF OUR PROPOSED PIPELINES AND RELATED COMPRESSION FACILITIES MAY BE SIGNIFICANTLY HIGHER THAN OUR CURRENT ESTIMATES. The construction of new pipelines and related compression facilities requires the expenditure of significant amounts of capital, which may exceed our estimates. If we undertake these projects, they may not be completed at the budgeted cost, on schedule or at all. The construction of new pipeline or compression facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials, such as steel and nickel, labor shortages or delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase the anticipated cost of the project. As a result, there is the risk that the new facilities may not be able to achieve our expected investment return, which could adversely affect our financial condition, results of operations or cash flows. ITEM 5. OTHER INFORMATION Our ratio of earnings to fixed charges for the nine months ended September 30, 2005 and 2006 was 2.33 and 2.58, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicators of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission. 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 as indicated. SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- 3.1.1 - Certificate of Incorporation of RERC Corp. Form 10-K for the year ended December 31, 1-13265 3(a)(1) 1997 3.1.2 - Certificate of Merger merging former NorAm Form 10-K for the year ended December 31, 1-13265 3(a)(2) Energy Corp. with and into HI Merger, Inc. dated 1997 August 6, 1997 3.1.3 - Certificate of Amendment changing the name to Form 10-K for the year ended December 31, 1-13265 3(a)(3) Reliant Energy Resources Corp. 1998 3.1.4 - Certificate of Amendment changing the name to Form 10-Q for the quarter ended 1-13265 3(a)(4) CenterPoint Energy Resources Corp. June 30, 2003 28
SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- 3.2 - Bylaws of RERC Corp. Form 10-K for the year ended December 31, 1-13265 3(b) 1997 4.1 - $550,000,000 Credit Agreement dated as of March CERC Corp.'s Form 8-K dated March 31, 2006 1-13265 4.3 31, 2006, among CERC Corp., as Borrower, and the banks named therein +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 CERC Corp. Form 10-K. Item 1A "--Risk Factors." 29
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 RESOURCES CORP. By: /s/ James S. Brian ------------------------------------ James S. Brian Senior Vice President and Chief Accounting Officer Date: November 7, 2006 30
EXHIBIT INDEX 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 as indicated. SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ----------- -------------------------------- ------------ --------- 3.1.1 - Certificate of Incorporation of RERC Corp. Form 10-K for the year ended December 31, 1-13265 3(a)(1) 1997 3.1.2 - Certificate of Merger merging former NorAm Form 10-K for the year ended December 31, 1-13265 3(a)(2) Energy Corp. with and into HI Merger, Inc. dated 1997 August 6, 1997 3.1.3 - Certificate of Amendment changing the name to Form 10-K for the year ended December 31, 1-13265 3(a)(3) Reliant Energy Resources Corp. 1998 3.1.4 - Certificate of Amendment changing the name to Form 10-Q for the quarter ended 1-13265 3(a)(4) CenterPoint Energy Resources Corp. June 30, 2003 3.2 - Bylaws of RERC Corp. Form 10-K for the year ended December 31, 1-13265 3(b) 1997 4.1 - $550,000,000 Credit Agreement dated as of March CERC Corp.'s Form 8-K dated March 31, 2006 1-13265 4.3 31, 2006, among CERC Corp., as Borrower, and the banks named therein +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 CERC Corp. Form 10-K. Item 1A "--Risk Factors."
Exhibit 12 CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES (MILLIONS OF DOLLARS)