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 JUNE 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 incorporation or organization) Identification No.) 1111 LOUISIANA (713) 207-1111 HOUSTON, TEXAS 77002 (Registrant's telephone number, (Address and zip code of including area code) principal executive offices) ---------- 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 August 1, 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 JUNE 30, 2006 TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Item 1. Financial Statements ........................................... 1 Condensed Statements of Consolidated Income Three Months and Six Months Ended June 30, 2005 and 2006 (unaudited) .............................................. 1 Condensed Consolidated Balance Sheets December 31, 2005 and June 30, 2006 (unaudited) .......... 2 Condensed Statements of Consolidated Cash Flows Six Months Ended June 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 ... 15 Item 4. Controls and Procedures ........................................ 23 PART II. OTHER INFORMATION Item 1. Legal Proceedings ............................................. 24 Item 1A. Risk Factors .................................................. 24 Item 5. Other Information ............................................. 24 Item 6. Exhibits ...................................................... 24 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; ii
- our potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or to have the anticipated benefits to us; and - other factors we discuss in "Risk Factors" in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2005, which is incorporated herein by reference. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement. iii
PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONDENSED STATEMENTS OF CONSOLIDATED INCOME (MILLIONS OF DOLLARS) (UNAUDITED) THREE MONTHS SIX MONTHS ENDED JUNE 30, ENDED JUNE 30, --------------- --------------- 2005 2006 2005 2006 ------ ------ ------ ------ REVENUES ............................... $1,426 $1,384 $3,674 $4,074 ------ ------ ------ ------ EXPENSES: Natural gas ......................... 1,103 1,035 2,884 3,228 Operation and maintenance ........... 171 199 344 396 Depreciation and amortization ....... 50 50 99 100 Taxes other than income taxes ....... 33 35 76 85 ------ ------ ------ ------ Total ............................ 1,357 1,319 3,403 3,809 ------ ------ ------ ------ OPERATING INCOME ....................... 69 65 271 265 ------ ------ ------ ------ OTHER INCOME (EXPENSE): Interest and other finance charges .. (52) (42) (97) (82) Other, net .......................... 8 5 12 8 ------ ------ ------ ------ Total ............................ (44) (37) (85) (74) ------ ------ ------ ------ INCOME BEFORE INCOME TAXES ............. 25 28 186 191 Income tax (expense) benefit ........ 2 (5) (63) (71) ------ ------ ------ ------ NET INCOME ............................. $ 27 $ 23 $ 123 $ 120 ====== ====== ====== ====== 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, JUNE 30, 2005 2006 ------------ -------- CURRENT ASSETS: Cash and cash equivalents ............................... $ 31 $ 226 Accounts and notes receivable, net ...................... 942 570 Accrued unbilled revenue ................................ 500 91 Accounts receivable -- affiliated companies ............. -- 4 Materials and supplies .................................. 29 37 Natural gas inventory ................................... 294 205 Non-trading derivative assets ........................... 131 107 Taxes receivable ........................................ 117 45 Deferred tax asset ...................................... 17 1 Prepaid expenses and other current assets ............... 130 186 ------ ------ Total current assets ................................. 2,191 1,472 ------ ------ PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment ........................... 4,674 4,825 Less accumulated depreciation and amortization .......... (569) (598) ------ ------ Property, plant and equipment, net ................... 4,105 4,227 ------ ------ OTHER ASSETS: Goodwill ................................................ 1,709 1,709 Other intangibles, net .................................. 18 18 Non-trading derivative assets ........................... 104 79 Accounts receivable -- affiliated companies, net ........ 9 29 Other ................................................... 165 199 ------ ------ Total other assets ................................... 2,005 2,034 ------ ------ TOTAL ASSETS ............................................... $8,301 $7,733 ====== ====== 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, JUNE 30, 2005 2006 ------------ -------- CURRENT LIABILITIES: Current portion of long-term debt ........................ $ 154 $ 153 Accounts payable ......................................... 1,077 406 Accounts and notes payable -- affiliated companies, net .. 319 24 Taxes accrued ............................................ 67 58 Interest accrued ......................................... 46 47 Customer deposits ........................................ 62 60 Non-trading derivative liabilities ....................... 43 103 Other .................................................... 341 237 ------ ------ Total current liabilities ............................. 2,109 1,088 ------ ------ OTHER LIABILITIES: Accumulated deferred income taxes, net ................... 663 639 Accounts payable -- affiliated companies ................. -- 21 Non-trading derivative liabilities ....................... 35 89 Benefit obligations ...................................... 127 118 Other .................................................... 716 698 ------ ------ Total other liabilities ............................... 1,541 1,565 ------ ------ 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 ........................................ 398 518 Accumulated other comprehensive income ................... 11 2 ------ ------ Total stockholder's equity ............................ 2,813 2,925 ------ ------ TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY ............... $8,301 $7,733 ====== ====== 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) SIX MONTHS ENDED JUNE 30, ------------------------- 2005 2006 ----- ----- CASH FLOWS FROM OPERATING ACTIVITIES: Net income .......................................................... $ 123 $ 120 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization .................................... 99 100 Amortization of deferred financing costs ......................... 4 4 Deferred income taxes ............................................ (23) 1 Write-down of natural gas inventory .............................. -- 30 Changes in other assets and liabilities: Accounts receivable and unbilled revenues, net ................ 575 784 Accounts receivable/payable, affiliates ....................... (3) (9) Inventory ..................................................... 4 59 Taxes receivable .............................................. 139 (40) Accounts payable .............................................. (293) (684) Fuel cost recovery ............................................ (47) 76 Interest and taxes accrued .................................... (18) (8) Non-trading derivatives, net .................................. 1 12 Margin deposits, net .......................................... 7 (113) Other current assets .......................................... 5 (81) Other current liabilities ..................................... 24 2 Other assets .................................................. 4 (29) Other liabilities ............................................. (20) 7 Other, net ....................................................... (1) (2) ----- ----- Net cash provided by operating activities .................. 580 229 ----- ----- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures ................................................ (149) (166) Increase in notes receivable from affiliates ........................ (98) -- Other, net .......................................................... (5) (9) ----- ----- Net cash used in investing activities ...................... (252) (175) ----- ----- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of long-term debt ............................ -- 324 Payments of long-term debt .......................................... (42) (6) Decrease in notes payable to affiliates ............................. (1) (289) Debt issuance costs ................................................. -- (1) Contribution from parent ............................................ 54 112 Dividend to parent .................................................. (100) -- Other, net .......................................................... -- 1 ----- ----- Net cash provided by (used in) financing activities ........ (89) 141 ----- ----- NET INCREASE IN CASH AND CASH EQUIVALENTS .............................. 239 195 CASH AND CASH EQUIVALENTS AT BEGINNING OF THE PERIOD ................... 141 31 ----- ----- CASH AND CASH EQUIVALENTS AT END OF THE PERIOD ......................... $ 380 $ 226 ===== ===== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest, net of capitalized interest ............................... $ 91 $ 78 Income taxes (refunds), net ......................................... 84 (9) Non-cash transactions: Increase in accounts payable related to capital expenditures ........ -- 13 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. and its subsidiaries (collectively, CERC Corp. 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, provides various ancillary services, and offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. 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 April 24, 2006, the FERC proposed 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, CenterPoint Energy Service Company, LLC, its service company would not be 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 primarily relate to a new reportable business segment discussed in Note 10 and do not affect net income. (2) NEW ACCOUNTING PRONOUNCEMENTS In July 2006, the Financial Accounting Standards Board (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. The new FASB interpretation 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 5
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 Mississippi. In February 2006, the Mississippi Public Service Commission (MPSC) approved a $1 million annual increase in miscellaneous service charges for Southern Gas Operations, and in March 2006, the MPSC approved a Rate Regulation Adjustment resulting in a $2 million annual increase in general service rates. In June 2006, the MPSC approved a January 2006 application for a one-time recovery of approximately $2 million of costs related to Hurricane Katrina. 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. The proposed rates were approved or became effective by operation of law in all but five of these cities, which cities denied the rate change requests. Southern Gas Operations appealed the actions of these five cities to the Railroad Commission. Additionally, 19 cities where new rates had already gone into effect subsequently challenged the jurisdictional and statutory basis for implementation of those rates. Southern Gas Operations petitioned the Railroad Commission for an order declaring that the new rates had been properly established within these 19 cities. During the second quarter of 2006, Southern Gas Operations reached settlement agreements with the last of the cities that were parties to the Railroad Commission proceedings. Once all settlement rates are implemented in all jurisdictions including unincorporated areas, Southern Gas Operations' base rates and miscellaneous service charges are expected to increase by a total of $17 million annually over the pre-April 2005 levels. Approximately $4 million of this increase was reflected in the Company's 2005 revenues. The Company expects approximately $16 million will be reflected in revenues in 2006, and the total $17 million will be reflected in revenues in 2007. 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. MINNESOTA GAS In April 2006, Minnesota Gas revised its gas cost filing for the twelve months ended June 30, 2005, which had not yet been approved by the Minnesota Public Utilities Commission (MPUC). Minnesota Gas refined its unbilled revenue estimate to more accurately reflect the effect of lost and unaccounted for gas. As a result, Minnesota Gas determined that its gas costs for the years ended June 30, 2001 through June 30, 2005 were understated. Minnesota Gas' revised gas cost filing requested approximately $9 million in additional recovery for the twelve months ended June 30, 2005. The amended filing also requested recovery of approximately $13 million related to the period from July 1, 2000 through June 30, 2004 and a waiver from the MPUC rules allowing recovery of such costs, since the gas costs for those years had been previously approved. The filing proposes recovery of the 2001-2004 costs over a 3-year period beginning in 2007. In November 2005, Minnesota Gas filed a request with the MPUC to increase annual rates by approximately $41 million. In December 2005, the MPUC approved an interim rate increase of approximately $35 million that was implemented January 1, 2006. Any excess of amounts collected under the interim rates over the amounts approved in final rates is subject to refund to customers. Hearings were held in April and June 2006 and a decision by the MPUC is expected in late 2006. In December 2004, the MPUC opened an investigation to determine whether Minnesota Gas' practices regarding restoring natural gas service during the period between October 15 and April 15 (Cold Weather Period) are in compliance with the MPUC's Cold Weather Rule (CWR), which governs disconnection and reconnection of customers during the Cold Weather Period. In June 2005, the Minnesota Office of the Attorney General (OAG) issued its report alleging Minnesota Gas had violated the CWR and recommended a $5 million penalty. In addition, in June 2005, the Company was named in a suit filed in the United States District Court, District of Minnesota on 6
behalf of a purported class of customers who allege that Minnesota Gas' conduct under the CWR was in violation of the law. On March 28, 2006 the court gave preliminary approval to a $13.5 million settlement which, if ultimately approved by the court following a hearing, will resolve all but one small claim against Minnesota Gas which have or could have been asserted by residential natural gas customers in the CWR class action. A further hearing by the court to consider approval of this settlement is expected during the third quarter of 2006. If also approved by the MPUC, the settlement will resolve the claims made by the OAG. During the fourth quarter 2005, the Company established a litigation reserve to cover the anticipated settlement costs under the terms 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. Cash Flow Hedges. During each of the six month periods ended June 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 June 30, 2006, the Company expects $1 million ($0.6 million after-tax) in accumulated other comprehensive loss to be reclassified as an increase in Natural gas expense during the next twelve months. The maximum length of time the Company is hedging its exposure to the variability in future cash flows using financial instruments is primarily two years with a limited amount of exposure up to ten years. The Company's policy is not to exceed ten years in hedging its exposure. Other Derivative Financial Instruments. 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 June 30, 2005 and 2006, the Company recognized net gains of $4 million and net losses of less than $1 million, respectively, on these derivative financial instruments which are included in the Condensed Statements of Consolidated Income under the "Expenses" caption "Natural gas." During the six months ended June 30, 2005 and 2006, the Company recognized net gains of $6 million and net losses of $8 million, respectively. 7
(5) GOODWILL AND INTANGIBLES Goodwill as of December 31, 2005 and June 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 components of the Company's other intangible assets consist of the following (in millions): DECEMBER 31, 2005 JUNE 30, 2006 ----------------------- ----------------------- CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION -------- ------------ -------- ------------ Land Use Rights.. $ 7 $ (3) $ 7 $ (3) Other............ 21 (7) 22 (8) --- ---- --- ---- Total......... $28 $(10) $29 $(11) === ==== === ==== Amortization expense for other intangibles during each of the three-month periods ended June 30, 2005 and 2006 was less than $1 million. Amortization expense for other intangibles during each of the six-month periods ended June 30, 2005 and 2006 was $1 million. Estimated amortization expense for the remainder of 2006 is approximately $1 million and is approximately $2 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 June 30, 2006, the Company had no borrowings under its $550 million credit facility. The Company was in compliance with all covenants as of June 30, 2006. (b) Receivables Facility. In January 2006, the Company's $250 million receivables facility was extended to January 2007. As of June 30, 2006, no amounts were funded under the Company's receivables facility. The facility was temporarily increased to $375 million for the period from January 2006 to June 2006. Funding under the receivables facility averaged $181 million and $121 million for the six months ended June 30, 2005 and 2006, respectively. Sales of receivables were approximately $424 million and $209 million for the three months ended June 30, 2005 and 2006, respectively, and $944 million and $555 million for the six months ended June 30, 2005 and 2006, respectively. 8
(7) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income (net of tax): FOR THE THREE MONTHS FOR THE SIX MONTHS ENDED JUNE 30, ENDED JUNE 30, -------------------- ------------------ 2005 2006 2005 2006 ---- ---- ---- ---- (IN MILLIONS) Net income................................................ $27 $23 $123 $120 --- --- ---- ---- Other comprehensive income: Net deferred gain (loss) from cash flow hedges......... 1 (2) 10 (5) Reclassification of deferred (gain) loss from cash flow hedges realized in net income....................... (3) 5 (2) (4) --- --- ---- ---- Other comprehensive income (loss)......................... (2) 3 8 (9) --- --- ---- ---- Comprehensive income...................................... $25 $26 $131 $111 === === ==== ==== The Company had a net deferred gain from cash flow hedges of $11 million and $2 million recorded in accumulated other comprehensive income at December 31, 2005 and June 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 June 30, 2006. For the three months ended June 30, 2005 and 2006, the Company had net interest income related to affiliate borrowings of approximately $2 million and $-0- million, respectively. For the six months ended June 30, 2005 and 2006, the Company had net interest income (expense) related to affiliate borrowings of approximately $3 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 $31 million for each of the three-month periods ended June 30, 2005 and 2006, and $60 million and $64 million for the six-month periods ended June 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 derivatives assets and liabilities in the Company's Consolidated Balance Sheets as of December 31, 2005 and June 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. Minimum payment obligations for natural gas supply contracts are approximately $367 million for the remaining six months in 2006, $627 million in 2007, $174 million in 2008, $118 million in 2009, $118 million in 2010 and $721 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 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 9
mile, 42-inch diameter pipeline, and related compression facilities at an estimated cost of $425 million. The capacity of the pipeline under this filing will be 1.275 billion cubic feet (Bcf) per day. CEGT has signed firm contracts for substantially the full capacity of the pipeline. Based on strong interest expressed in 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. During the four-year period subsequent to the in-service date of the pipeline, XTO can request, and subject to mutual negotiations that meet specific financial parameters, CEGT would construct a 67 mile extension from CEGT's Perryville hub to an interconnect with Texas Eastern Gas Transmission at Union Church, Mississippi. (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. 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 the Company'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. The Company 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 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 10
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 through rates as part of its existing rate case as further discussed in Note 3(a). 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 plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, including the cost of restoring their property to its original condition and damages for diminution of value of their property. In addition, plaintiffs seek damages for trespass, punitive, and exemplary damages. The Company does not expect the ultimate cost associated with resolving this matter to have a material impact on 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 June 30, 2006, the Company had accrued $14 million for remediation of these Minnesota sites. At June 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 June 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 11
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. The plaintiff in that case has filed an appeal of 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. 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'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, and CenterPoint Energy and RRI are pursuing other alternatives. On June 30, 2006, the Company 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 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 12
answer to the complaint, arguing that the Company is 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. (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 June 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 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 JUNE 30, 2005 ---------------------------------------- REVENUES FROM NET EXTERNAL INTERSEGMENT OPERATING CUSTOMERS REVENUES INCOME (LOSS) --------- ------------ ------------- Natural Gas Distribution ..................... $ 538 $ 3 $ 9 Competitive Natural Gas Sales and Services ... 801 44 10 Pipelines and Field Services ................. 87 38 52 Other Operations ............................. -- 1 (2) Eliminations ................................. -- (86) -- ------ ---- --- Consolidated ................................. $1,426 $ -- $69 ====== ==== === FOR THE THREE MONTHS ENDED JUNE 30, 2006 ---------------------------------------- REVENUES FROM NET EXTERNAL INTERSEGMENT OPERATING CUSTOMERS REVENUES INCOME (LOSS) --------- ------------ ------------- Natural Gas Distribution ..................... $ 546 $ 3 $(2) Competitive Natural Gas Sales and Services ... 742 8 7 Pipelines and Field Services ................. 96 39 61 Other Operations ............................. -- 2 (1) Eliminations ................................. -- (52) -- ------ ---- --- Consolidated ................................. $1,384 $ -- $65 ====== ==== === 13
FOR THE SIX MONTHS ENDED JUNE 30, 2005 ---------------------------------------- REVENUES FROM NET TOTAL ASSETS EXTERNAL INTERSEGMENT OPERATING AS OF CUSTOMERS REVENUES INCOME (LOSS) DECEMBER 31, 2005 --------- ------------ ------------- ----------------- Natural Gas Distribution ..................... $1,867 $ 3 $132 $ 4,612 Competitive Natural Gas Sales and Services ... 1,633 137 26 1,849 Pipelines and Field Services ................. 171 75 116 2,968 Other Operations ............................. 3 3 (3) 743 Eliminations ................................. -- (218) -- (1,871) ------ ----- ---- ------- Consolidated ................................. $3,674 $ -- $271 $ 8,301 ====== ===== ==== ======= FOR THE SIX MONTHS ENDED JUNE 30, 2006 ---------------------------------------- REVENUES FROM NET TOTAL ASSETS EXTERNAL INTERSEGMENT OPERATING AS OF CUSTOMERS REVENUES INCOME (LOSS) JUNE 30, 2006 --------- ------------ ------------- ------------- Natural Gas Distribution ..................... $2,023 $ 6 $101 $ 3,959 Competitive Natural Gas Sales and Services ... 1,868 45 32 1,259 Pipelines and Field Services ................. 183 77 134 3,057 Other Operations ............................. -- 4 (2) 665 Eliminations ................................. -- (132) -- (1,207) ------ ----- ---- ------- Consolidated ................................. $4,074 $ -- $265 $ 7,733 ====== ===== ==== ======= (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 SIX MONTHS ENDED JUNE 30, ENDED JUNE 30, -------------- -------------- 2005 2006 2005 2006 ---- ---- ---- ---- (IN MILLIONS) Service cost ........................ $ 1 $ 1 $ 1 $ 1 Interest cost ....................... 2 1 4 3 Expected return on plan assets ...... (1) (1) (1) (1) Amortization of prior service cost .. -- 1 1 1 Other ............................... -- -- -- 1 --- --- --- --- Net periodic cost ................ $ 2 $ 2 $ 5 $ 5 === === === === The Company expects to contribute approximately $13 million to CenterPoint Energy's postretirement benefits plan in 2006, of which $8 million had been contributed as of June 30, 2006. 14
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 six months ended June 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). 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. The following table sets forth our consolidated results of operations for the three months and six months ended June 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 SIX MONTHS ENDED JUNE 30, ENDED JUNE 30, --------------- --------------- 2005 2006 2005 2006 ------ ------ ------ ------ (IN MILLIONS) Revenues ............................. $1,426 $1,384 $3,674 $4,074 ------ ------ ------ ------ Expenses: Natural gas ....................... 1,103 1,035 2,884 3,228 Operation and maintenance ......... 171 199 344 396 Depreciation and amortization ..... 50 50 99 100 Taxes other than income taxes ..... 33 35 76 85 ------ ------ ------ ------ Total Expenses ................. 1,357 1,319 3,403 3,809 ------ ------ ------ ------ Operating Income ..................... 69 65 271 265 Interest and Other Finance Charges ... (52) (42) (97) (82) Other Income, net .................... 8 5 12 8 ------ ------ ------ ------ Income Before Income Taxes ........... 25 28 186 191 Income Tax (Expense) Benefit ......... 2 (5) (63) (71) ------ ------ ------ ------ Net Income ........................... $ 27 $ 23 $ 123 $ 120 ====== ====== ====== ====== 15
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 six months ended June 30, 2005 and 2006 (in millions, except throughput and customer data): THREE MONTHS SIX MONTHS ENDED JUNE 30, ENDED JUNE 30, ----------------------- ----------------------- 2005 2006 2005 2006 ---------- ---------- ---------- ---------- Revenues ................................ $ 541 $ 549 $ 1,870 $ 2,029 ---------- ---------- ---------- ---------- Expenses: Natural gas .......................... 341 343 1,338 1,489 Operation and maintenance ............ 126 142 261 292 Depreciation and amortization ........ 39 37 76 75 Taxes other than income taxes ........ 26 29 63 72 ---------- ---------- ---------- ---------- Total expenses .................... 532 551 1,738 1,928 ---------- ---------- ---------- ---------- Operating Income (Loss) ................. $ 9 $ (2) $ 132 $ 101 ========== ========== ========== ========== Throughput (in billion cubic feet (Bcf)): Residential .......................... 21 17 98 84 Commercial and industrial ............ 43 44 120 116 ---------- ---------- ---------- ---------- Total Throughput .................. 64 61 218 200 ========== ========== ========== ========== Average number of customers: Residential ........................... 2,833,773 2,860,802 2,842,645 2,872,978 Commercial and industrial ............. 246,032 253,725 247,429 253,505 ---------- ---------- ---------- ---------- Total ............................. 3,079,805 3,114,527 3,090,074 3,126,483 ========== ========== ========== ========== THREE MONTHS ENDED JUNE 30, 2006 COMPARED TO THREE MONTHS ENDED JUNE 30, 2005 Our Natural Gas Distribution business segment reported an operating loss of $2 million for the three months ended June 30, 2006 as compared to operating income of $9 million for the three months ended June 30, 2005. Increases in operating margins (revenues less natural gas costs) from rate increases and rate design changes, along with the addition of nearly 32,000 customers since June 2005 ($6 million) and increased gross receipts taxes resulting from higher revenues ($3 million), were partially offset by decreased customer usage and unfavorable weather ($5 million). Operation and maintenance expenses increased primarily due to costs associated with staff reductions ($5 million), increased bad debt expense due to high natural gas prices ($3 million) and a write-off of certain rate case expenses ($3 million). Additionally, taxes other than income taxes increased $3 million primarily due to higher gross receipts taxes, which offset the corresponding increase in revenues discussed above. SIX MONTHS ENDED JUNE 30, 2006 COMPARED TO SIX MONTHS ENDED JUNE 30, 2005 Our Natural Gas Distribution business segment reported operating income of $101 million for the six months ended June 30, 2006 as compared to $132 million for the six months ended June 30, 2005. Increases in operating margins from rate increases and rate design changes, along with the addition of nearly 32,000 customers since June 2005 ($20 million) and increased gross receipts taxes resulting from higher revenues ($9 million), were partially offset by decreased customer usage and unfavorable weather ($21 million). Operation and maintenance expenses increased primarily due to costs associated with staff reductions ($11 million), increased bad debt expense due to high natural gas prices ($6 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 $9 million primarily due to higher gross receipts taxes, which offset the corresponding increase in revenues discussed above. 16
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 six months ended June 30, 2005 and 2006 (in millions, except throughput and customer data): THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------ ---------------- 2005 2006 2005 2006 ------ ------ ------ ------ Revenues ................................ $ 845 $ 750 $1,770 $1,913 ------ ------ ------ ------ Expenses: Natural gas .......................... 828 735 1,730 1,864 Operation and maintenance ............ 7 7 12 15 Depreciation and amortization ........ -- 1 1 1 Taxes other than income taxes ........ -- -- 1 1 ------ ------ ------ ------ Total expenses .................... 835 743 1,744 1,881 ------ ------ ------ ------ Operating Income ........................ $ 10 $ 7 $ 26 $ 32 ====== ====== ====== ====== Throughput (in Bcf): Wholesale - third parties ............ 72 72 154 161 Wholesale - affiliates ............... 21 8 35 19 Retail ............................... 34 31 81 79 Pipeline ............................. 12 10 31 20 ------ ------ ------ ------ Total Throughput .................. 139 121 301 279 ====== ====== ====== ====== Average number of customers: Wholesale ............................ 135 132 130 138 Retail ............................... 6,237 6,468 6,207 6,501 Pipeline ............................. 145 136 151 138 ------ ------ ------ ------ Total ............................. 6,517 6,736 6,488 6,777 ====== ====== ====== ====== THREE MONTHS ENDED JUNE 30, 2006 COMPARED TO THREE MONTHS ENDED JUNE 30, 2005 Our Competitive Natural Gas Sales and Services business segment reported operating income of $7 million for the three months ended June 30, 2006 as compared to $10 million for the three months ended June 30, 2005. Increased operating income from higher sales to utilities and favorable basis differentials across the pipeline capacity that we control ($12 million) was more than offset by a charge of $17 million to reflect the write-down of natural gas inventory to the lower of average cost or market. Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet future sales requirements and enters into derivative contracts to hedge the economic value of the future sales. Therefore, operating income in future periods when these sales occur is expected to be higher as a result of the inventory write-down taken in this quarter. SIX MONTHS ENDED JUNE 30, 2006 COMPARED TO SIX MONTHS ENDED JUNE 30, 2005 Our Competitive Natural Gas Sales and Services business segment reported operating income of $32 million for the six months ended June 30, 2006 as compared to $26 million for the six months ended June 30, 2005. Increased operating income from higher sales to utilities and favorable basis differentials across the pipeline capacity that we control ($35 million) was partially offset by a charge of $30 million to reflect the write-downs of natural gas inventory to the lower of average cost or market. Therefore, operating income in future periods when these sales occur is expected to be higher as a result of the inventory write-downs taken in the first two quarters of this year. 17
PIPELINES AND FIELD SERVICES The following table provides summary data of our Pipelines and Field Services business segment for the three and six months ended June 30, 2005 and 2006 (in millions, except throughput data): THREE MONTHS SIX MONTHS ENDED JUNE 30, ENDED JUNE 30, -------------- -------------- 2005 2006 2005 2006 ---- ---- ---- ---- Revenues .................................... $125 $135 $246 $260 ---- ---- ---- ---- Expenses: Natural gas .............................. 18 7 25 3 Operation and maintenance ................ 40 50 74 89 Depreciation and amortization ............ 11 12 22 24 Taxes other than income taxes ............ 4 5 9 10 ---- ---- ---- ---- Total expenses ........................ 73 74 130 126 ---- ---- ---- ---- Operating Income ............................ $ 52 $ 61 $116 $134 ==== ==== ==== ==== Operating Income - Pipeline business ........ 35 40 83 89 Operating Income - Field Services business .. 17 21 33 45 ---- ---- ---- ---- Total segment operating income ........ $ 52 $ 61 $116 $134 ==== ==== ==== ==== Throughput (in Bcf): Natural Gas Sales ........................ 3 2 4 2 Transportation ........................... 230 240 501 514 Gathering ................................ 87 94 170 182 Elimination (1) .......................... (2) (1) (3) (1) ---- ---- ---- ---- Total Throughput ...................... 318 335 672 697 ==== ==== ==== ==== - ---------- (1) Elimination of volumes both transported and sold. THREE MONTHS ENDED JUNE 30, 2006 COMPARED TO THREE MONTHS ENDED JUNE 30, 2005 Our Pipelines and Field Services business segment reported operating income of $61 million for the three months ended June 30, 2006 as compared to $52 million for the three months ended June 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 where they operate. Within this segment, the pipeline business achieved higher operating income of $40 million for the three months ended June 30, 2006 as compared to $35 million for the same period in 2005 resulting from increased demand for transportation due to favorable basis differentials across the system ($5 million), higher demand for ancillary services ($3 million) and increased project-related revenues ($5 million), offset by a corresponding increase in project-related expenses ($5 million) and higher operation and maintenance expenses ($3 million). The field services business achieved higher operating income of $21 million for the three months ended June 30, 2006 as compared to $17 million for the same period in 2005 driven by increased throughput ($3 million) and higher commodity prices ($2 million). Additionally, this business segment recorded equity income of $1 million and $2 million for the three months ended June 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. SIX MONTHS ENDED JUNE 30, 2006 COMPARED TO SIX MONTHS ENDED JUNE 30, 2005 Our Pipelines and Field Services business segment reported operating income of $134 million for the six months ended June 30, 2006 as compared to $116 million for the six months ended June 30, 2005. The pipeline business achieved operating income of $89 million for the six months ended June 30, 2006 as compared to $83 million for the same period in 2005 resulting from increased demand for transportation due to favorable basis differentials across the system ($11 million), higher demand for ancillary services ($4 million) and increased project-related revenues ($6 million), partially offset by a corresponding increase in project-related expenses ($5 million) and increased operation and maintenance expenses ($6 million). The field services business achieved operating income of $45 million for the six months ended June 30, 2006 as compared to $33 million for the same period in 2005 driven by increased throughput ($7 million), higher commodity prices ($7 million) and higher 18
demand for ancillary services ($2 million), partially offset by increased operation and maintenance expenses ($4 million). In addition, this business segment recorded equity income of $3 million and $5 million for the six months ended June 30, 2005 and 2006, respectively, from its 50 percent interest in a jointly-owned gas processing plant as discussed above. 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. 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 remainder of 2006 are approximately $500 million of capital expenditures and $145 million principal amount of maturing debt. 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 the second quarter of 2006 which was the primary reason for an $809 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 $367 million for the remaining six months in 2006, $627 million in 2007, $174 million in 2008, $118 million in 2009, $118 million in 2010 and $721 million in 2011 and thereafter. 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 January 2006, our $250 million facility was extended to January 2007. As of June 30, 2006, no amounts were funded under our receivables facility. The facility was temporarily increased to $375 million for the period from January 2006 to June 2006. Prior to the 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 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, and CenterPoint Energy and RRI are pursuing other alternatives. 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 19
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. 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 August 1, 2006, the credit facility was not utilized. Securities Registered with the SEC. After giving effect to our issuance of $325 million aggregate principal amount of senior notes due in May 2016, as discussed above under "--Senior Notes," at June 30, 2006, we had a shelf registration statement covering $175 million principal amount of debt securities. Temporary Investments. As of August 1, 2006, we had external temporary investments of $275 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 August 1, 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 August 1, 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. 20
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 that establish credit thresholds and require a party to provide additional collateral on two business days' notice when that party's rating or the rating of a credit support provider for that party (CERC Corp. in this case) falls below those levels. We estimate that as of June 30, 2006, unsecured credit limits extended to CES by counterparties aggregate $133 million; however, utilized credit capacity is significantly lower. In addition, we and our subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on our S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly. Cross Defaults. Under 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 August 1, 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 suppliers; - increased costs related to the acquisition of gas; - increases in interest expense in connection with debt refinancings and borrowings under credit facilities; - various regulatory actions; - the ability of RRI and its subsidiaries to satisfy their obligations 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. 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. 21
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." Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, regulatory matters and operating costs could negatively affect the fair value of our assets and result in an impairment charge. Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques. ASSET RETIREMENT OBLIGATIONS We account for our long-lived assets under SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), and Financial Accounting Standards Board Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations - An Interpretation of SFAS No. 143" (FIN 47). SFAS No. 143 and FIN 47 require that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47, and costs recovered through the ratemaking process. We estimate the fair value of asset retirement obligations by calculating the discounted cash flows that are dependent upon the following components: - Inflation adjustment - The estimated cash flows are adjusted for inflation estimates for labor, equipment, materials, and other disposal costs; - 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 22
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 June 30, 2006, our estimated cost of retiring these assets was approximately $65 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 June 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 June 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. 23
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 There have been no material changes from the risk factors disclosed in the CERC Corp. Form 10-K. ITEM 5. OTHER INFORMATION Our ratio of earnings to fixed charges for the six months ended June 30, 2005 and 2006 was 2.79 and 3.10, respectively. We do not believe that the ratios for these six month periods are necessarily indicators of the ratios for the twelve month period 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. REPORT OR SEC FILE OR EXHIBIT REGISTRATION REGISTRATION EXHIBIT NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE - ------- ------------------------------------ ------------------------------- ------------ --------- 3.1.1 - Certificate of Incorporation of Form 10-K for the year ended 1-13265 3(a)(1) RERC Corp. December 31, 1997 3.1.2 - Certificate of Merger merging Form 10-K for the year ended 1-13265 3(a)(2) former NorAm Energy Corp. with and December 31, 1997 into HI Merger, Inc. dated August 6, 1997 3.1.3 - Certificate of Amendment changing Form 10-K for the year ended 1-13265 3(a)(3) the name to Reliant Energy December 31, 1998 Resources Corp. 3.1.4 - Certificate of Amendment changing Form 10-Q for the quarter ended 1-13265 3(a)(4) the name to CenterPoint Energy June 30, 2003 Resources Corp. 3.2 - Bylaws of RERC Corp. Form 10-K for the year ended 1-13265 3(b) December 31, 1997 4.1 - $550,000,000 Credit Agreement dated CERC Corp.'s Form 8-K dated 1-13265 4.3 as of March 31, 2006, among CERC March 31, 2006 Corp., as Borrower, and the banks named therein 4.2 - Indenture, dated as of February 1, CERC Corp.'s Form 8-K dated 1-13265 4.1 1998, between CERC Corp. (formerly February 5, 1998 NorAm Energy Corp.) and JPMorgan Chase Bank, National Association (successor to Chase Bank of Texas, National Association), as trustee (the "Indenture") 4.3 - Supplemental Indenture No. 9 to the CenterPoint Energy's Form 10-Q 1-31447 4.7 Indenture, dated as of May 18, for the quarter ended June 30, 2006, providing for the issuance of 2006 CERC Corp.'s 6.15% Senior Notes due 2016. +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." 24
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: August 8, 2006 25
INDEX TO EXHIBITS 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. REPORT OR SEC FILE OR EXHIBIT REGISTRATION REGISTRATION EXHIBIT NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE - ------- ------------------------------------ ------------------------------- ------------ --------- 3.1.1 - Certificate of Incorporation of Form 10-K for the year ended 1-13265 3(a)(1) RERC Corp. December 31, 1997 3.1.2 - Certificate of Merger merging Form 10-K for the year ended 1-13265 3(a)(2) former NorAm Energy Corp. with and December 31, 1997 into HI Merger, Inc. dated August 6, 1997 3.1.3 - Certificate of Amendment changing Form 10-K for the year ended 1-13265 3(a)(3) the name to Reliant Energy December 31, 1998 Resources Corp. 3.1.4 - Certificate of Amendment changing Form 10-Q for the quarter ended 1-13265 3(a)(4) the name to CenterPoint Energy June 30, 2003 Resources Corp. 3.2 - Bylaws of RERC Corp. Form 10-K for the year ended 1-13265 3(b) December 31, 1997 4.1 - $550,000,000 Credit Agreement dated CERC Corp.'s Form 8-K dated 1-13265 4.3 as of March 31, 2006, among CERC March 31, 2006 Corp., as Borrower, and the banks named therein 4.2 - Indenture, dated as of February 1, CERC Corp.'s Form 8-K dated 1-13265 4.1 1998, between CERC Corp. (formerly February 5, 1998 NorAm Energy Corp.) and JPMorgan Chase Bank, National Association (successor to Chase Bank of Texas, National Association), as trustee (the "Indenture") 4.3 - Supplemental Indenture No. 9 to the CenterPoint Energy's Form 10-Q 1-31447 4.7 Indenture, dated as of May 18, for the quarter ended June 30, 2006, providing for the issuance of 2006 CERC Corp.'s 6.15% Senior Notes due 2016. +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." 26
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) SIX MONTHS ENDED JUNE 30, ---------------- 2005 2006 ----- ----- Net Income .................................................... $ 123 $ 120 Income taxes .................................................. 63 71 Capitalized interest .......................................... (1) (1) ----- ----- 185 190 ----- ----- Fixed charges, as defined: Interest ................................................... 97 82 Capitalized interest ....................................... 1 1 Interest component of rentals charged to operating income .. 6 7 ----- ----- Total fixed charges ........................................ 104 90 ----- ----- Earnings, as defined .......................................... $ 289 $ 280 ===== ===== Ratio of earnings to fixed charges ............................ 2.79 3.10 ===== =====
EXHIBIT 31.1 CERTIFICATIONS I, David M. McClanahan, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy Resources Corp.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2006 /s/ David M. McClanahan ---------------------------------------- David M. McClanahan President and Chief Executive Officer
EXHIBIT 31.2 CERTIFICATIONS I, Gary L. Whitlock, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy Resources Corp.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 8, 2006 /s/ Gary L. Whitlock ---------------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer
EXHIBIT 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the "Company") on Form 10-Q for the period ended June 30, 2006 (the "Report"), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ David M. McClanahan - ------------------------------------- David M. McClanahan President and Chief Executive Officer August 8, 2006
EXHIBIT 32.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the "Company") on Form 10-Q for the period ended June 30, 2006 (the "Report"), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Gary L. Whitlock - ------------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer August 8, 2006
EXHIBIT 99.1 ITEM 1A. RISK FACTORS RISK FACTORS AFFECTING OUR BUSINESSES RATE REGULATION OF OUR BUSINESS MAY DELAY OR DENY OUR ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER OUR COSTS. Our rates for our local distribution companies are regulated by certain municipalities and state commissions, and for our interstate pipelines by the FERC, based on an analysis of our invested capital and our expenses in a test year. Thus, the rates that we are allowed to charge may not match our expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of our costs and enable us to earn a reasonable return on our invested capital. OUR BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, WHICH COULD LEAD TO LESS NATURAL GAS BEING MARKETED, AND OUR PIPELINES AND FIELD SERVICES BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE TRANSPORTATION, STORAGE, GATHERING, TREATING AND PROCESSING OF NATURAL GAS, WHICH COULD LEAD TO LOWER PRICES, EITHER OF WHICH COULD HAVE AN ADVERSE IMPACT ON OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. We compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with us for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by us as a result of competition may have an adverse impact on our results of operations, financial condition and cash flows. Our two interstate pipelines and our gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. They also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price. The actions of our competitors could lead to lower prices, which may have an adverse impact on our results of operations, financial condition and cash flows. OUR NATURAL GAS DISTRIBUTION AND COMPETITIVE NATURAL GAS SALES AND SERVICES BUSINESSES ARE SUBJECT TO FLUCTUATIONS IN NATURAL GAS PRICING LEVELS, WHICH COULD AFFECT THE ABILITY OF OUR SUPPLIERS AND CUSTOMERS TO MEET THEIR OBLIGATIONS OR OTHERWISE ADVERSELY AFFECT OUR LIQUIDITY.
We are subject to risk associated with increases in the price of natural gas, which has been the trend in recent years. Increases in natural gas prices might affect our ability to collect balances due from our customers and, on the regulated side, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into our tariff rates. In addition, a sustained period of high natural gas prices could apply downward demand pressure on natural gas consumption in the areas in which we operate and increase the risk that our suppliers or customers fail or are unable to meet their obligations. Additionally, increasing gas prices could create the need for us to provide collateral in order to purchase gas. IF WE WERE TO FAIL TO EXTEND A CONTRACT WITH ONE OF OUR SIGNIFICANT PIPELINE CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON OUR OPERATIONS. Our contract with Laclede Gas Company, one of our pipeline's customers, is currently scheduled to expire in 2007. To the extent the pipeline is unable to extend this contract or the contract is renegotiated at rates substantially less than the rates provided in the current contract, there could be an adverse effect on our results of operations, financial condition and cash flows. A DECLINE IN OUR CREDIT RATING COULD RESULT IN US HAVING TO PROVIDE COLLATERAL IN ORDER TO PURCHASE GAS. If our credit rating were to decline, we might be required to post cash collateral in order to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, we might be unable to obtain the necessary natural gas to meet our obligations to customers, and our results of operations, financial condition and cash flows would be adversely affected. OUR PIPELINES' AND FIELD SERVICES' BUSINESS REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS. Our pipelines and field services business largely relies on gas sourced in the various supply basins located in the Midcontinent region of the United States. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on our results of operations, financial condition and cash flows. OUR REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL. A substantial portion of our revenues is derived from natural gas sales and transportation. Thus, our revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months.
RISK FACTORS ASSOCIATED WITH OUR CONSOLIDATED FINANCIAL CONDITION IF WE ARE UNABLE TO ARRANGE FUTURE FINANCINGS ON ACCEPTABLE TERMS, OUR ABILITY TO REFINANCE EXISTING INDEBTEDNESS COULD BE LIMITED. As of December 31, 2005, we had $2 billion of outstanding indebtedness on a consolidated basis. As of December 31, 2005, approximately $465 million principal amount of this debt must be paid through 2008. Our future financing activities may depend, at least in part, on: - - general economic and capital market conditions; - - credit availability from financial institutions and other lenders; - - investor confidence in us and the market in which we operate; - - maintenance of acceptable credit ratings; - - market expectations regarding our future earnings and probable cash flows; - - market perceptions of our ability to access capital markets on reasonable terms; and - - provisions of relevant tax and securities laws. Our current credit ratings are discussed in "Management's Narrative Analysis of Results of Operations -- Liquidity -- Impact on Liquidity of a Downgrade in Credit Ratings" in Item 7 of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms. THE FINANCIAL CONDITION AND LIQUIDITY OF OUR PARENT COMPANY COULD AFFECT OUR ACCESS TO CAPITAL, OUR CREDIT STANDING AND OUR FINANCIAL CONDITION. Our ratings and credit may be impacted by CenterPoint Energy's credit standing. As of December 31, 2005, CenterPoint Energy and its other subsidiaries have approximately $200 million principal amount of debt required to be paid through 2008. This amount excludes amounts related to capital leases, securitization debt and indexed debt securities obligations. In addition, CenterPoint Energy has $830 million of outstanding convertible notes on which holders could exercise their "put" rights during this period. We cannot assure you that CenterPoint Energy and its other subsidiaries will be able to pay or refinance these amounts. If CenterPoint Energy were to experience a deterioration in its credit standing or liquidity difficulties, our access to credit and our credit ratings could be adversely affected.
WE ARE AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY. CENTERPOINT ENERGY CAN EXERCISE SUBSTANTIAL CONTROL OVER OUR DIVIDEND POLICY AND BUSINESS AND OPERATIONS AND COULD DO SO IN A MANNER THAT IS ADVERSE TO OUR INTERESTS. We are managed by officers and employees of CenterPoint Energy. Our management will make determinations with respect to the following: - - our payment of dividends; - - decisions on our financings and our capital raising activities; - - mergers or other business combinations; and - - our acquisition or disposition of assets. There are no contractual restrictions on our ability to pay dividends to CenterPoint Energy. Our management could decide to increase our dividends to CenterPoint Energy to support its cash needs. This could adversely affect our liquidity. However, under our credit facility and our receivables facility, our ability to pay dividends is restricted by a covenant that debt as a percentage of total capitalization may not exceed 65%. THE USE OF DERIVATIVE CONTRACTS BY US AND OUR SUBSIDIARIES IN THE NORMAL COURSE OF BUSINESS COULD RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT OUR RESULTS OF OPERATIONS AND THOSE OF OUR SUBSIDIARIES. We use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. We could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions could affect the reported fair value of these contracts. RISKS COMMON TO OUR BUSINESSES AND OTHER RISKS WE ARE SUBJECT TO OPERATIONAL AND FINANCIAL RISKS AND LIABILITIES ARISING FROM ENVIRONMENTAL LAWS AND REGULATIONS. Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines and distribution systems, gas gathering and processing systems, and electric transmission and distribution systems we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
- - restricting the way we can handle or dispose of our wastes; - - limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species; - - requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and - - enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to: - - construct or acquire new equipment; - - acquire permits for facility operations; - - modify or replace existing and proposed equipment; and - - clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT. INSUFFICIENT INSURANCE COVERAGE AND INCREASED INSURANCE COSTS COULD ADVERSELY IMPACT OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.
WE AND CENTERPOINT ENERGY COULD INCUR LIABILITIES ASSOCIATED WITH BUSINESSES AND ASSETS THAT WE HAVE TRANSFERRED TO OTHERS. In connection with the organization and capitalization of RRI, RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, CenterPoint Energy and its subsidiaries, including us, with respect to liabilities associated with the transferred assets and businesses. The indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI is unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy has not been released from the liability in connection with the transfer, we or CenterPoint Energy could be responsible for satisfying the liability. Prior to CenterPoint Energy's distribution of its ownership in 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 guaranty 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 undertook to use commercially reasonable efforts to extinguish the remaining guarantees. Our current exposure under the remaining guarantees relates to our guaranty 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 guaranty currently exceeds the security provided by RRI. We have 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 guaranty, and we and RRI are pursuing alternatives. RRI continues to meet its obligations under the transportation contracts. RRI's unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event RRI might not honor its indemnification obligations and claims by RRI's creditors might be made against us as its former owner.