UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2004 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 incorporation or organization) (I.R.S. Employer Identification No.) 1111 LOUISIANA HOUSTON, TEXAS 77002 (713) 207-1111 (Address and zip code of principal executive offices) (Registrant's telephone number, including area code) ------------------------------ CENTERPOINT ENERGY RESOURCES CORP. MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(A) AND (B) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT. Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X] As of May 1, 2004, 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 MARCH 31, 2004 TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Item 1. Financial Statements............................................................ 1 Statements of Consolidated Income Three Months Ended March 31, 2003 and 2004 (unaudited)........................... 1 Consolidated Balance Sheets December 31, 2003 and March 31, 2004 (unaudited)................................. 2 Statements of Consolidated Cash Flows Three Months Ended March 31, 2003 and 2004 (unaudited)........................... 4 Notes to Unaudited Consolidated Financial Statements................................ 5 Item 2. Management's Narrative Analysis of the Results of Operations.................... 13 Item 4. Controls and Procedures......................................................... 18 PART II. OTHER INFORMATION Item 1. Legal Proceedings............................................................... 19 Item 6. Exhibits and Reports on Form 8-K................................................ 19 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, constraints placed on our activities or business by the Public Utility Holding Company Act of 1935, as amended (1935 Act) and changes in or application of laws or regulations applicable to other aspects of our business; - timely rate increases, including recovery of costs; - industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns; - the timing and extent of changes in commodity prices, particularly natural gas; - changes in interest rates or rates of inflation; - weather variations and other natural phenomena; - the timing and extent of changes in the supply of natural gas; - commercial bank and financial market conditions, our access to capital, the costs of such capital, receipt of certain approvals under the 1935 Act, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; - actions by rating agencies; - inability of various counterparties to meet their obligations to us; - non-payment of our services due to financial distress of our customers; and - other factors we discuss in "Risk Factors" beginning on page 9 of the CenterPoint Energy Resources Corp. Annual Report on Form 10-K for the year ended December 31, 2003. Additional risk factors are described in other documents we file with the Securities and Exchange Commission. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement. ii
PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) STATEMENTS OF CONSOLIDATED INCOME (THOUSANDS OF DOLLARS) (UNAUDITED) THREE MONTHS ENDED MARCH 31, ---------------------------------- 2003 2004 -------------- -------------- REVENUES............................................................... $ 2,094,020 $ 2,196,585 -------------- -------------- EXPENSES: Natural gas.......................................................... 1,655,120 1,762,240 Operation and maintenance............................................ 177,666 181,845 Depreciation and amortization........................................ 43,910 46,526 Taxes other than income taxes........................................ 45,176 45,394 -------------- -------------- Total............................................................ 1,921,872 2,036,005 -------------- -------------- OPERATING INCOME....................................................... 172,148 160,580 -------------- -------------- OTHER INCOME (EXPENSE): Interest and other finance charges................................... (35,826) (42,282) Other, net........................................................... 1,060 2,612 -------------- -------------- Total............................................................ (34,766) (39,670) -------------- -------------- INCOME BEFORE INCOME TAXES............................................. 137,382 120,910 Income Tax Expense.................................................. 49,210 46,719 -------------- -------------- NET INCOME............................................................. $ 88,172 $ 74,191 ============== ============== See Notes to the Company's Interim Financial Statements 1
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) (UNAUDITED) ASSETS DECEMBER 31, MARCH 31, 2003 2004 -------------- -------------- CURRENT ASSETS: Cash and cash equivalents................................................. $ 34,447 $ 184,800 Accounts and notes receivable, net........................................ 462,988 392,006 Accrued unbilled revenue.................................................. 323,844 175,911 Accounts and notes receivable - affiliated companies, net................. -- 157,941 Materials and supplies.................................................... 26,859 27,008 Natural gas inventory..................................................... 160,367 68,648 Non-trading derivative assets............................................. 45,897 48,993 Taxes receivable.......................................................... 32,023 -- Prepaid expenses.......................................................... 11,104 11,773 Other..................................................................... 71,597 44,760 -------------- -------------- Total current assets.................................................... 1,169,126 1,111,840 -------------- -------------- PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment............................................. 4,086,750 4,126,166 Less accumulated depreciation............................................. (351,189) (378,241) -------------- -------------- Property, plant and equipment, net...................................... 3,735,561 3,747,925 -------------- -------------- OTHER ASSETS: Goodwill.................................................................. 1,740,510 1,740,510 Other intangibles, net.................................................... 20,101 19,696 Non-trading derivative assets............................................. 11,273 11,391 Accounts and notes receivable - affiliated companies, net................. 33,929 26,097 Other..................................................................... 142,162 144,609 -------------- -------------- Total other assets...................................................... 1,947,975 1,942,303 -------------- -------------- TOTAL ASSETS................................................................ $ 6,852,662 $ 6,802,068 ============== ============== See Notes to the Company's Interim Financial Statements 2
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONSOLIDATED BALANCE SHEETS -- (CONTINUED) (THOUSANDS OF DOLLARS) (UNAUDITED) LIABILITIES AND STOCKHOLDER'S EQUITY DECEMBER 31, MARCH 31, 2003 2004 -------------- -------------- CURRENT LIABILITIES: Short-term borrowings..................................................... $ 63,000 $ -- Accounts payable.......................................................... 528,394 468,490 Accounts and notes payable - affiliated companies, net.................... 23,351 -- Taxes accrued............................................................. 65,636 132,461 Interest accrued.......................................................... 58,505 52,795 Customer deposits......................................................... 58,372 59,730 Non-trading derivative liabilities........................................ 6,537 9,626 Accumulated deferred income taxes, net.................................... 8,856 20,371 Other..................................................................... 125,132 96,238 -------------- -------------- Total current liabilities........................................... 937,783 839,711 -------------- -------------- OTHER LIABILITIES: Accumulated deferred income taxes, net.................................... 645,125 625,834 Non-trading derivative liabilities........................................ 3,330 1,676 Benefit obligations....................................................... 130,980 129,555 Other..................................................................... 571,005 561,714 -------------- -------------- Total other liabilities............................................... 1,350,440 1,318,779 -------------- -------------- LONG-TERM DEBT.............................................................. 2,370,974 2,370,515 -------------- -------------- COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 9) STOCKHOLDER'S EQUITY: Common stock.............................................................. 1 1 Paid-in capital........................................................... 1,985,254 1,985,275 Retained earnings......................................................... 173,682 247,873 Accumulated other comprehensive income.................................... 34,528 39,914 -------------- -------------- Total stockholder's equity............................................ 2,193,465 2,273,063 -------------- -------------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY............................... $ 6,852,662 $ 6,802,068 ============== ============== See Notes to the Company's Interim Financial Statements 3
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) STATEMENTS OF CONSOLIDATED CASH FLOWS (THOUSANDS OF DOLLARS) (UNAUDITED) THREE MONTHS ENDED MARCH 31, --------------------------------- 2003 2004 -------------- -------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income............................................................... $ 88,172 $ 74,191 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization.......................................... 43,910 46,526 Amortization of deferred financing costs............................... 408 2,814 Deferred income taxes.................................................. 23,598 (10,770) Changes in other assets and liabilities: Accounts and notes receivable, net................................... (251,918) 219,183 Accounts receivable/payable, affiliates.............................. (11,156) 1,626 Inventory............................................................ 72,791 91,570 Taxes receivable..................................................... 23,286 32,023 Accounts payable..................................................... 215,309 (59,904) Fuel cost recovery................................................... 7,056 -- Interest and taxes accrued........................................... (14,519) 61,115 Net non-trading derivative assets and liabilities.................... (1,362) 6,487 Other current assets................................................. 29,864 26,168 Other current liabilities............................................ (22,831) (27,536) Other assets......................................................... (4,489) (3,667) Other liabilities.................................................... 18,061 (14,545) Other, net............................................................. (7,037) (459) -------------- -------------- Net cash provided by operating activities.......................... 209,143 444,822 -------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures..................................................... (50,732) (52,126) Decrease (increase) in notes receivable from affiliates, net............. 926 (175,065) Other, net............................................................... (2,424) (2,416) -------------- -------------- Net cash used in investing activities.............................. (52,230) (229,607) -------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES: Payments of long-term debt............................................... (260,008) -- Proceeds from long-term debt............................................. 650,000 -- Debt issuance costs...................................................... (51,798) (1,862) Decrease in short-term borrowings, net................................... (347,000) (63,000) Decrease in notes with affiliates, net................................... (74,096) -- -------------- -------------- Net cash used in financing activities.............................. (82,902) (64,862) -------------- -------------- NET INCREASE IN CASH AND CASH EQUIVALENTS................................... 74,011 150,353 CASH AND CASH EQUIVALENTS AT BEGINNING OF THE PERIOD........................ 9,237 34,447 -------------- -------------- CASH AND CASH EQUIVALENTS AT END OF THE PERIOD.............................. $ 83,248 $ 184,800 ============== ============== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest................................................................. $ 54,930 $ 46,126 Income taxes............................................................. 793 14,968 See Notes to the Company's Interim Financial Statements 4
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (1) BACKGROUND AND BASIS OF PRESENTATION General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy Resources Corp. (CERC Corp., together with its subsidiaries, the Company), are the Company's consolidated interim financial statements and notes (Interim Financial Statements) including its wholly owned and majority owned subsidiaries. The Interim 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, 2003 (CERC Corp. Form 10-K). Background. 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 (Reliant Energy). CenterPoint Energy is a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (1935 Act). The 1935 Act and related rules and regulations impose a number of restrictions on the activities of CenterPoint Energy and those of its subsidiaries. The 1935 Act, among other things, limits the ability of CenterPoint Energy and its regulated subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliate transactions. Basis of Presentation. The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company's Interim Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Company's 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 do not affect net income. Note 2(e)(Regulatory Assets and Liabilities), Note 3 (Regulatory Matters), Note 5 (Derivative Instruments) and Note 9 (Commitments and Contingencies) to the consolidated annual financial statements in the CERC Corp. Form 10-K (CERC Corp. 10-K Notes) relate to certain contingencies. These notes, as updated herein, are incorporated herein by reference. For information regarding environmental matters and legal proceedings, see Note 9 to the Interim Financial Statements. (2) NEW ACCOUNTING PRONOUNCEMENTS In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. (FIN) 46 "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. On December 24, 2003, the FASB issued a revision to FIN 46 (FIN 46-R). For special-purpose entities (SPE's) created before February 1, 2003, the Company applied the provisions of FIN 46 or FIN 46-R as of December 31, 2003. The revised FIN 46-R is effective for all other entities for financial periods ending after March 15, 2004. The Company has a subsidiary trust that has Mandatorily Redeemable Preferred Securities outstanding. The trust was determined to be a variable interest entity under FIN 46-R and the Company also determined that it is 5
not the primary beneficiary of the trust. As of December 31, 2003, the Company deconsolidated the trust and instead reports its junior subordinated debentures due to the trust as long-term debt. On December 23, 2003, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 132 (Revised 2003), "Employer's Disclosures about Pensions and Other Postretirement Benefits" (SFAS No. 132(R)) which increases the existing disclosure requirements by requiring more details about pension plan assets, benefit obligations, cash flows, benefit costs and related information. Companies are required to segregate plan assets by category, such as debt, equity and real estate, and to provide certain expected rates of return and other informational disclosures. SFAS No. 132(R) also requires companies to disclose various elements of pension and postretirement benefit costs in interim-period financial statements for quarters beginning after December 15, 2003. The Company has adopted the disclosure requirements of SFAS No. 132(R) in Note 11(a) to these Interim Financial Statements. In December 2003, Congress passed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) which will become effective in 2006. The Act contains incentives for the Company, if it continues to provide prescription drug benefits for its retirees, through the provision of a non-taxable reimbursement to the Company of specified costs. The Company has many different alternatives available under the Act, and, until clarifying regulations are issued with respect to the Act, the Company is unable to determine the financial impact the Act will have on the Company. On January 12, 2004, the FASB issued FASB Staff Position (FSP) FAS 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" (FAS 106-1). In accordance with FSP FAS 106-1, the Company's postretirement benefits obligations and net periodic postretirement benefit cost in the financial statements and accompanying notes do not reflect the effects of the legislation. Specific authoritative guidance on the accounting for the legislation is pending, and that guidance, when issued, may require the Company to change previously reported information. (3) REGULATORY MATTERS (a) Rate Cases. On January 6, 2004, new rates went into effect in the City of Houston in accordance with a rate settlement between CenterPoint Energy Entex (Entex) and the City. These settlement rates were subsequently filed with the 28 remaining cities in the Houston Division and with the Railroad Commission of Texas (Texas Railroad Commission). The settlement rates went into effect in 12 of the 28 cities on February 1, 2004 and went into effect for ten additional cities on May 1, 2004. The Texas Railroad Commission is expected to render a decision associated with the unincorporated environs in the near future. Once all remaining regulatory approvals are received, the annualized effect of this multi-jurisdictional rate increase will be approximately $14 million. (b) Other Regulatory Proceedings. City of Tyler, Texas Dispute. In July 2002, the City of Tyler, Texas, asserted that Entex had overcharged residential and small commercial customers in that city for excessive gas costs under supply agreements in effect since 1992. That dispute has been referred to the Texas Railroad Commission by agreement of the parties for a determination of whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending October 31, 2002. The Company believes that all costs for Entex's Tyler distribution system have been properly included and recovered from customers pursuant to Entex's filed tariffs. (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 to mitigate the impact of changes in cash flows of its natural gas businesses on its operating results and cash flows. Cash Flow Hedges. During the three months ended March 31, 2004, there was no hedge ineffectiveness recognized in earnings 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. As of March 31, 2004, 6
the Company expects $54 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months. For additional information regarding the Company's use of derivatives, see Note 5 to the CERC Corp. 10-K Notes, which is incorporated herein by reference. (5) GOODWILL AND INTANGIBLES Goodwill as of December 31, 2003 and March 31, 2004 by reportable business segment is as follows (in millions): Natural Gas Distribution....... $ 1,085 Pipelines and Gathering........ 601 Other Operations............... 55 ------------ Total........................ $ 1,741 ============ The Company completed its annual evaluation of goodwill for impairment as of January 1, 2004 and no impairment was indicated. The components of the Company's other intangible assets consist of the following: DECEMBER 31, 2003 MARCH 31, 2004 -------------------------- --------------------------- CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION ----------- ------------ ----------- ------------ (IN MILLIONS) Land use rights.......................... $ 7 $ (3) $ 7 $ (3) Other.................................... 20 (4) 20 (4) ----------- ---------- ----------- ---------- Total.................................... $ 27 $ (7) $ 27 $ (7) =========== ========== =========== ========== The Company recognizes specifically identifiable intangibles when specific rights and contracts are acquired. The Company has no intangible assets with indefinite lives recorded as of March 31, 2004. The Company amortizes other acquired intangibles on a straight-line basis over the lesser of their contractual or estimated useful lives that range from 47 to 75 years for land use rights and 4 to 25 years for other intangibles. Amortization expense for other intangibles for the three months ended March 31, 2003 and 2004 was $0.3 million and $0.4 million, respectively. Estimated amortization expense for the remainder of 2004 is approximately $1.5 million and is approximately $0.5 million per year for the five succeeding fiscal years. (6) LONG-TERM DEBT AND RECEIVABLES FACILITY (a) Long-Term Debt. Credit Facilities. As of March 31, 2004, the Company had a revolving credit facility that provided for an aggregate of $250 million in committed credit. The revolving credit facility terminates on March 23, 2007. Fully-drawn rates for borrowings under this facility, including the facility fee, are London interbank offered rate (LIBOR) plus 150 basis points based on current credit ratings and the applicable pricing grid. As of March 31, 2004, such credit facility was not utilized. Junior Subordinated Debentures (Trust Preferred Securities). In June 1996, a Delaware statutory business trust created by CERC Corp. (CERC Trust) issued $173 million aggregate amount of convertible preferred securities to the public. CERC Trust used the proceeds of the offering to purchase convertible junior subordinated debentures issued by CERC Corp. having an interest rate and maturity date that correspond to the distribution rate and mandatory redemption date of the convertible preferred securities. The convertible junior subordinated debentures represent CERC Trust's sole asset and its entire operations. CERC Corp. considers its obligation under the Amended and Restated Declaration of Trust, Indenture and Guaranty Agreement relating to the convertible preferred securities, taken together, to constitute a full and unconditional guarantee by CERC Corp. of CERC Trust's obligations with respect to the convertible preferred securities. As discussed in Note 2, upon the Company's 7
adoption of FIN 46, the junior subordinated debentures discussed above are included in long-term debt as of December 31, 2003 and March 31, 2004. The convertible preferred securities are mandatorily redeemable upon the repayment of the convertible junior subordinated debentures at their stated maturity or earlier redemption. Effective January 7, 2003, the convertible preferred securities are convertible at the option of the holder into $33.62 of cash and 2.34 shares of CenterPoint Energy common stock for each $50 of liquidation value. As of December 31, 2003 and March 31, 2004, $0.4 million liquidation amount of convertible preferred securities were outstanding. The securities, and their underlying convertible junior subordinated debentures, bear interest at 6.25% and mature in June 2026. Subject to some limitations, CERC Corp. has the option of deferring payments of interest on the convertible junior subordinated debentures. During any deferral or event of default, CERC Corp. may not pay dividends on its common stock to CenterPoint Energy. As of March 31, 2004, no interest payments on the convertible junior subordinated debentures had been deferred. (b) Receivables Facility. On January 21, 2004, the Company replaced its $100 million receivables facility with a $250 million receivables facility. The $250 million receivables facility terminates on January 19, 2005. As of March 31, 2004, the Company had fully utilized its receivables facility. (7) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income: FOR THE THREE MONTHS ENDED MARCH 31, --------------------- 2003 2004 -------- -------- (IN MILLIONS) Net income......................................................................... $ 88 $ 74 -------- -------- Other comprehensive income: Net deferred gain (loss) from cash flow hedges................................... (1) 8 Reclassification of deferred loss (gain) from cash flow hedges realized in net income......................................................................... 1 (3) -------- -------- Other comprehensive income......................................................... -- 5 -------- -------- Comprehensive income............................................................... $ 88 $ 79 ======== ======== 8
(8) RELATED PARTY TRANSACTIONS The following table summarizes receivables from, or payables to, CenterPoint Energy or its subsidiaries: DECEMBER 31, MARCH 31, 2003 2004 ------------ ---------- (IN MILLIONS) Accounts receivable from affiliates......................................... $ 6 $ 11 Accounts payable to affiliates.............................................. (29) (36) --------- ---------- Accounts payable -- affiliated companies, net............................. (23) (25) --------- ---------- Note receivable from affiliates(1).......................................... -- 183 --------- ---------- Accounts and notes receivable/(payable) -- affiliated companies, net... $ (23) $ 158 ========= ========== Long-term accounts receivable from affiliates............................... $ -- $ 64 Long-term accounts payable to affiliates.................................... -- (43) --------- ---------- Long-term accounts receivable -- affiliated companies, net................ -- $ 21 --------- ---------- Long-term notes receivable from affiliates.................................. 67 $ 5 Long-term notes payable to affiliates....................................... (33) -- --------- ---------- Long-term notes receivable -- affiliated companies, net................... 34 $ 5 --------- ---------- Long-term accounts and notes receivable -- affiliated companies, net... $ 34 $ 26 ========= ========== - ---------- (1) This represents money pool investments. For the three months ended March 31, 2003 and 2004, the Company had net interest income (expense) related to affiliate borrowings of $(0.1) million and $1.6 million, respectively. The 1935 Act generally prohibits borrowings by CenterPoint Energy from its subsidiaries, including the Company, either through the money pool or otherwise. For the three months ended March 31, 2003 and 2004, sales and services provided by the Company to CenterPoint Energy and its subsidiaries totaled $5 million and $7 million, respectively. CenterPoint Energy provides some corporate services to the Company. The costs of services have been directly charged 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 and $27 million for the three months ended March 31, 2003 and 2004, respectively, and are included primarily in operation and maintenance expenses. (9) COMMITMENTS AND CONTINGENCIES (a) 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. 9
In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs' alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the Btu content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. The Company believes that there has been no systematic mismeasurement of gas and that the suits are without merit. The Company does not expect that their ultimate outcome would have a material impact on the Company's financial condition or results of operations. Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against CenterPoint Energy, the Company, Entex Gas Marketing Company, and others 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. The plaintiffs seek class certification, but no class has been certified. The plaintiffs allege that defendants inflated the prices charged to certain consumers of natural gas. In February 2003, a similar suit was filed against the Company in state court in Caddo Parish, Louisiana purportedly on behalf of a class of residential or business customers in Louisiana who allegedly have been overcharged for gas or gas service provided by the Company. In February 2004, another suit was filed against the Company in Calcasieu Parish, Louisiana, seeking to recover alleged overcharges for gas or gas services allegedly provided by Entex without advance approval by the Louisiana Public Service Commission. The plaintiffs in these cases seek injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages and civil penalties. In these cases, CenterPoint Energy, the Company and Entex Gas Marketing Company deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. The Company does not anticipate that the outcome of these matters will have a material impact on the Company's financial condition or results of operations. (b) Environmental Matters. Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The quantity of monetary damages sought is unspecified. The Company is unable to estimate the monetary damages, if any, that the plaintiffs may be awarded in these matters. Manufactured Gas Plant Sites. The Company and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in the Company's Minnesota service territory, two of which it believes were neither owned nor operated by the Company, and for which it believes it has no liability. 10
At March 31, 2004, the Company had accrued $19 million for remediation of certain Minnesota sites. At March 31, 2004, the estimated range of possible remediation costs for these sites was $8 million to $44 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. The Company has collected or accrued $12 million as of March 31, 2004 to be used for environmental remediation. The Company has received notices from the United States Environmental Protection Agency and others regarding its status as a PRP for other sites. The Company has been named as a defendant in lawsuits under which contribution is sought for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of the Company or its divisions. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. Based on current information, the Company has not been able to quantify a range of potential environmental expenditures for such sites. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows. 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 as a defendant in litigation related to such sites. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims that it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, results of operations or cash flows. (c) Other Proceedings. The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. (10) REPORTABLE BUSINESS SEGMENTS Because CERC Corp. is an indirect wholly owned subsidiary of CenterPoint Energy, the Company's determination of reportable 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 Company has identified the following reportable business segments: Natural Gas Distribution, Pipelines and Gathering, and Other Operations. For descriptions of the reportable business segments, see Note 12 to the CERC Corp. 10-K Notes, which is incorporated herein by reference. 11
The following table summarizes financial data for the Company's reportable business segments: AS OF DECEMBER 31, FOR THE THREE MONTHS ENDED MARCH 31, 2003 2003 ------------------------------------------------- ------------ REVENUES FROM NET THIRD PARTIES AND INTERSEGMENT OPERATING AFFILIATES REVENUES INCOME TOTAL ASSETS ----------------- ------------ ----------- ------------ (IN MILLIONS) Natural Gas Distribution............. $ 2,028 $ 17 $ 129 $ 4,661 Pipelines and Gathering.............. 61 48 43 2,519 Other Operations..................... -- 2 -- 388 Sales to Affiliates.................. 5 -- -- -- Eliminations......................... -- (67) -- (715) ------------ ----------- ----------- ----------- Consolidated......................... $ 2,094 $ -- $ 172 $ 6,853 ============ =========== =========== =========== AS OF MARCH 31, FOR THE THREE MONTHS ENDED MARCH 31, 2004 2004 ------------------------------------------------- ------------ REVENUES FROM NET THIRD PARTIES AND INTERSEGMENT OPERATING AFFILIATES REVENUES INCOME TOTAL ASSETS ----------------- ------------ ----------- ------------ (IN MILLIONS) Natural Gas Distribution............. $ 2,124 $ 7 $ 117 $ 4,691 Pipelines and Gathering.............. 65 37 45 2,481 Other Operations..................... -- 3 (2) 539 Sales to Affiliates.................. 7 -- -- -- Eliminations......................... -- (47) -- (909) ------------ ----------- ----------- ----------- Consolidated......................... $ 2,196 $ -- $ 160 $ 6,802 ============ =========== =========== =========== (11) EMPLOYEE BENEFIT PLANS AND SEVERANCE COSTS (a) Employee Benefit Plans. The Company's employees participate in CenterPoint Energy's postretirement benefit plan. The Company's net periodic cost includes the following components relating to postretirement benefits: THREE MONTHS ENDED MARCH 31, --------------------------- 2003 2004 ----------- ------------ (IN MILLIONS) Service cost..................................... $ -- $ -- Interest cost.................................... 2 2 Expected return on plan assets................... -- -- Net amortization................................. 1 1 Other ........................................... -- 1 ----------- ------------ Net periodic cost.......................... $ 3 $ 4 =========== ============ The Company previously disclosed in its financial statements for the year ended December 31, 2003, that it expected to contribute $15 million to its postretirement benefits plan in 2004. As of March 31, 2004, $3 million has been contributed. (b) Severance Costs. The Company recorded an $8 million charge for severance costs associated with staff reductions in its Natural Gas Distribution business segment during the three months ended March 31, 2004. 12
ITEM 2. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS The following narrative analysis should be read in combination with our Interim Financial Statements contained in Item 1 of this report. We are 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 (Reliant Energy). CenterPoint Energy is a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (1935 Act). For information about the 1935 Act, please read " -- Liquidity -- Certain Contractual and Regulatory Limits on Ability to Issue Securities and Pay Dividends." 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 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities), 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 months ended March 31, 2003 and the three months ended March 31, 2004. 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, 2003 (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 municipal 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 "Business - -- Risk Factors" in Item 1 of the CERC Corp. Form 10-K and "Management's Narrative Analysis of the Results of Operations -- Certain Factors Affecting Future Earnings" in Item 7 of the CERC Corp. Form 10-K, which are incorporated herein by reference. The following table sets forth our consolidated results of operations for the three months ended March 31, 2003 and 2004, followed by a discussion of our consolidated results of operations based on operating income. We have provided a reconciliation of consolidated operating income to net income below. THREE MONTHS ENDED MARCH 31, ------------------------------ 2003 2004 ------------ ------------ Revenues............................................................... $ 2,094 $ 2,196 ------------ ------------ Expenses: Natural gas......................................................... 1,655 1,762 Operation and maintenance........................................... 178 182 Depreciation and amortization....................................... 44 47 Taxes other than income taxes....................................... 45 45 ------------ ------------ Total Expenses............................................... 1,922 2,036 ------------ ------------ Operating Income....................................................... 172 160 Interest and Other Finance Charges..................................... (36) (42) Other Income, net...................................................... 1 3 ------------ ------------ Income Before Income Taxes............................................. 137 121 Income Tax Expense..................................................... (49) (47) ------------ ------------ Net Income........................................................... $ 88 $ 74 ============ ============ THREE MONTHS ENDED MARCH 31, 2004 COMPARED TO THREE MONTHS ENDED MARCH 31, 2003 We reported operating income of $160 million for the three months ended March 31, 2004 as compared to $172 million for the same period in 2003. Continued customer growth, with the addition of over 38,000 customers in our Natural Gas Distribution business segment since March 2003, higher revenues of $3 million from rate increases, 13
higher utilization of storage services, higher interruptible transportation margins, increased throughput and enhanced services related to our gas gathering operations and lower natural gas prices were more than offset by the impact of milder weather of $10 million and reduced contributions from our competitive commercial and industrial sales business. Operation and maintenance expense increased $4 million for the three months ended March 31, 2004 compared to the same period in 2003 primarily due to an $8 million charge for severance costs associated with staff reductions in our Natural Gas Distribution business segment, which will reduce costs in future periods. Excluding this charge, operation and maintenance expenses decreased by $4 million. CERTAIN FACTORS AFFECTING FUTURE EARNINGS For information on other developments, factors and trends that may have an impact on our future earnings, please read "Management's Narrative Analysis of Results of Operations -- Certain Factors Affecting Future Earnings" in Item 7 of Part II of the CERC Corp. Form 10-K and "Risk Factors" in Item 1 of Part I of the CERC Corp. Form 10-K, each of which is incorporated herein by reference. LIQUIDITY Off-Balance Sheet Arrangements. Other than operating leases, we have no off-balance sheet arrangements. However, we do participate in a receivables factoring arrangement. On January 21, 2004, we replaced our $100 million receivables facility with a $250 million receivables facility. The $250 million receivables facility terminates on January 19, 2005. As of March 31, 2004, we had fully utilized our receivables facility. Long-Term Debt. As of March 31, 2004, we had the following revolving credit facility: SIZE OF AMOUNT FACILITY AT OUTSTANDING AT MARCH 31, MARCH 31, DATE EXECUTED COMPANY 2004 2004 TERMINATION DATE - ------------- ---------- ----------- -------------- ---------------- (IN MILLIONS) March 23, 2004 CERC Corp. $ 250 $ -- March 23, 2007 On March 23, 2004, we replaced our $200 million revolving credit facility with a $250 million revolving credit facility that terminates on March 23, 2007. Fully-drawn rates for borrowings under this facility, including the facility fee, are London interbank offered rate (LIBOR) plus 150 basis points based on current credit ratings and the applicable pricing grid. As of March 31, 2004, we had $160 million in external temporary investments. At March 31, 2004, we had a shelf registration statement covering $50 million principal amount of debt securities. Cash Requirements in 2004. Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, and working capital needs. Our principal remaining cash requirements during 2004 include approximately $256 million of capital expenditures. We expect that revolving credit borrowings, anticipated cash flows from operations, the liquidation of our temporary investments and borrowings from affiliates will be sufficient to meet our cash needs for 2004. Impact on Liquidity of a Downgrade in Credit Ratings. As of May 1, 2004, 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) - ------ ---------- ------ ---------- ------ ---------- Ba1 Stable BBB Negative BBB Negative - ---------- (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. 14
(2) An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term. (3) A "negative" outlook from Fitch encompasses a one-to-two year horizon as to the likely ratings direction. On April 30, 2004, Moody's announced that it had changed our outlook to stable from negative. Moody's explained in its announcement that the action was to reflect the mitigation of concerns that underlay its negative outlook including our establishment of a steady operating track record as a subsidiary of CenterPoint Energy, our establishment of adequate stand-alone liquidity, our progress made in addressing certain regulatory issues and greater comfort with the ringfencing protections provided to us by the 1935 Act. 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. A decline in credit ratings would increase borrowing costs under our $250 million revolving credit facility. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and would negatively impact our ability to complete capital market transactions as more fully described in " -- Certain Contractual and Regulatory Limits on Ability to Issue Securities and Pay Dividends" below. Additionally, a decline in credit ratings could increase cash collateral requirements that could exist in connection with certain contracts relating to gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution business segment. Our revolving credit facility contains a "material adverse change" clause that could impact our ability to make new borrowings under this facility. The "material adverse change" clause in our revolving credit facility relates to any material adverse change in the business, condition, operations, performance or properties of the borrower or the borrower and its subsidiaries taken as a whole. CenterPoint Energy Gas Services, Inc. (CEGS), a wholly owned subsidiary of CERC Corp., provides comprehensive natural gas sales and services to industrial and commercial customers, which are primarily located within or near the territories served by our pipelines and natural gas distribution subsidiaries. In order to hedge its exposure to natural gas prices, CEGS has agreements with provisions standard for the industry that establish credit thresholds and require a party to provide additional collateral on two business days' notice when that party's rating or the rating of a credit support provider for that party (CERC Corp. in this case) falls below those levels. As of December 31, 2003, the senior unsecured debt of CERC Corp. was rated BBB by S&P and Ba1 by Moody's. We estimate that as of March 31, 2004, unsecured credit limits related to hedge instruments extended to CEGS by counterparties could aggregate $82 million; however, utilized credit capacity is significantly lower. Cross Defaults. Our debentures and borrowings generally provide that a default on obligations by CenterPoint Energy does not cause a default under our debentures, revolving credit facility or receivables facility. Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $35 million by us or any of our significant subsidiaries will cause a default. 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 on $922 million aggregate principal amount of our senior notes. A payment default on, or a non-payment default that permits acceleration of, any indebtedness at CERC Corp. exceeding $50 million will cause a default under CenterPoint Energy's $2.3 billion credit facility entered into in October 2003. 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 on senior debt of CenterPoint Energy aggregating $1.4 billion. Pension Plan. As discussed in Note 7(a) to the consolidated annual financial statements in the CERC Corp. Form 10-K (CERC Corp. 10-K Notes), which is incorporated herein by reference, we participate in CenterPoint Energy's qualified non-contributory pension plan 15
covering substantially all employees. Pension expense for 2004 is estimated to be $31 million based on an expected return on plan assets of 9.0% and a discount rate of 6.25% as of December 31, 2003. Future changes in plan asset returns, assumed discount rates and various other factors related to the pension will impact our future pension expense. We cannot predict with certainty what these factors will be in the future. Other Factors that Could Affect Cash Requirements. In addition to the above factors, our liquidity and capital resources could be affected by: - cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution business segment, particularly given gas price levels and volatility; - acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of suppliers; - increased costs related to the acquisition of gas for storage; and - various regulatory actions. 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 money pool's net funding requirements are generally met by borrowings of CenterPoint Energy. The terms of the money pool are in accordance with requirements applicable to registered public utility holding companies under the 1935 Act and under an order from the SEC dated June 30, 2003 (June 2003 Financing Order) relating to our financing activities. Our money pool borrowing limit under such financing order is $600 million. At March 31, 2004, we had $183 million invested in the money pool. The money pool may not provide sufficient funds to meet our cash needs. Certain Contractual and Regulatory Limits on Ability to Issue Securities and Pay Dividends. Factors affecting our ability to issue securities, pay dividends on our common stock or take other actions to adjust our capitalization include: - covenants and other provisions in our credit facility and receivables facility; and - limitations imposed on us under the 1935 Act. Our bank facility and our receivables facility limit our debt as a percentage of our total capitalization to 60% and contain an earnings before interest, taxes, depreciation and amortization (EBITDA) to interest covenant. We are in compliance with such covenants. Our parent, CenterPoint Energy, is a registered public utility holding company under the 1935 Act. The 1935 Act and related rules and regulations impose a number of restrictions on our parent's activities and those of its subsidiaries, including us. The 1935 Act, among other things, limits our parent's ability and the ability of its regulated subsidiaries, including us, to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliate transactions. The June 2003 Financing Order is effective until June 30, 2005. Additionally, CenterPoint Energy has received several subsequent orders which provide additional financing authority. These orders establish limits on the amount of external debt and equity securities that can be issued by CenterPoint Energy and its regulated subsidiaries, including us, without additional authorization but generally permit CenterPoint Energy and its subsidiaries, including us, to refinance our existing obligations. We are in compliance with the authorized limits. The orders also permit our utilization of undrawn credit facilities. As of April 30, 2004, we are authorized to issue an additional $2 million of debt and an additional aggregate $250 million of preferred stock and preferred securities after giving effect to our capital market transactions in 2003 and the first four months of 2004. The SEC has reserved jurisdiction over, and must take further action to permit, the issuance of $430 million of additional debt by us. 16
The orders require that if CenterPoint Energy or any of its regulated subsidiaries, including us, issue any securities that are rated by a nationally recognized statistical rating organization (NRSRO), the security to be issued must obtain an investment grade rating from at least one NRSRO and, as a condition to such issuance, all outstanding rated securities of the issuer and of CenterPoint Energy must be rated investment grade by at least one NRSRO. The orders also contain certain requirements for interest rates, maturities, issuance expenses and use of proceeds. The 1935 Act limits the payment of dividends to payment from current and retained earnings unless specific authorization is obtained to pay dividends from other sources. The June 2003 Financing Order requires us to maintain a ratio of common equity to total capitalization of at least 30%. 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 CERC Corp. 10-K Notes. We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors 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 Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." No impairment of goodwill was indicated based on our analysis as of January 1, 2004. 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. 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 17
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 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 March 31, 2004 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2004 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. 18
PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS For a description of certain legal and regulatory proceedings affecting us, please review Notes 3 and 9 to our Interim Financial Statements, "Business - -- Regulation" and " -- Environmental Matters" in Item 1 of the CERC Corp. Form 10-K, Item 3 of the CERC Corp. Form 10-K and Notes 3, 9(c) and (d) to the CERC Corp. 10-K Notes, each of which is incorporated herein by reference. ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K (a) 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 Resources December 31, 1998 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 10.1 - $250,000,000 Credit Agreement, Form 8-K dated March 31, 2004 1-13265 4.1 dated as of March 23, 2004, among CERC Corp., as Borrower, and the Initial Lenders named therein, as Initial Lenders +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 19
REPORT OR SEC FILE OR EXHIBIT REGISTRATION REGISTRATION EXHIBIT NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE - ------- ----------------------------------------- ---------------------------- ------------- --------- +99.1 - Items incorporated by reference from the CERC Corp. Form 10-K. Item 1 "Business -- Regulation," "-- Environmental Matters," and "-- Risk Factors," Item 3 "Legal Proceedings" and Item 7 "Management's Narrative Analysis of the Results of Operations -- Certain Factors Affecting Future Earnings" and Notes 2(e) (Regulatory Assets and Liabilities), 3 (Regulatory Matters), 5 (Derivative Instruments), 7(a) (Pension Plans), 9 (Commitments and Contingencies) and 12 (Reportable Segments). (b) Reports on Form 8-K. On March 3, 2004, we filed a Current Report on Form 8-K dated March 3, 2004 to furnish under Item 9 of that form a slide presentation we expect will be presented to various members of the financial and investment community from time to time. On April 1, 2004, we filed a Current Report on Form 8-K dated March 31, 2004 to report that we had entered into a new three-year, $250 million credit agreement with a group of lenders. On April 1, 2004, we filed a Current Report on Form 8-K dated April 1, 2004 to furnish under Item 9 of that form a slide presentation we expect will be presented to various members of the financial and investment community from time to time. 20
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: May 7, 2004 21
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 Resources December 31, 1998 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 10.1 - $250,000,000 Credit Agreement, Form 8-K dated March 31, 2004 1-13265 4.1 dated as of March 23, 2004, among CERC Corp., as Borrower, and the Initial Lenders named therein, as Initial Lenders +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 1 "Business -- Regulation," "-- Environmental Matters," and "-- Risk Factors," Item 3 "Legal Proceedings" and Item 7 "Management's Narrative Analysis of the Results of Operations -- Certain Factors Affecting Future Earnings" and Notes 2(e) (Regulatory Assets and Liabilities), 3 (Regulatory Matters), 5 (Derivative Instruments), 7(a) (Pension Plans, 9 (Commitments and Contingencies) and 12 (Reportable Segments). 22
EXHIBIT 31.1 CERTIFICATION 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 officers 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 officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 7, 2004 By: /s/ David M. McClanahan ----------------------------------------------- David M. McClanahan Chairman, President and Chief Executive Officer
EXHIBIT 31.2 CERTIFICATION 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 officers 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 officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: May 7, 2004 By: /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 March 31, 2004 (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 Chairman, President and Chief Executive Officer May 7, 2004
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 March 31, 2004 (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 Chairman, President and Chief Executive Officer May 7, 2004
EXHIBIT 99.1 ITEM 1. BUSINESS REGULATION We are subject to regulation by various federal, state and local governmental agencies, including the regulations described below. PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 As a subsidiary of a registered public utility holding company, we are subject to a comprehensive regulatory scheme imposed by the Securities and Exchange Commission (SEC) in order to protect customers, investors and the public interest. Although the SEC does not regulate rates and charges under the 1935 Act, it does regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies. In order to obtain financing, acquire additional public utility assets or stock, or engage in other significant transactions, we are required to obtain approval from the SEC under the 1935 Act. CenterPoint Energy received an order from the SEC under the 1935 Act on June 30, 2003 and supplemental orders thereafter relating to its financing activities and those of its regulated subsidiaries, including us, as well as other matters. The orders are effective until June 30, 2005. As of December 31, 2003, the orders generally permitted CenterPoint Energy and its subsidiaries, including us, to issue securities to refinance indebtedness outstanding at June 30, 2003, and authorized CenterPoint Energy and its subsidiaries, including us, to issue certain incremental external debt securities and common and preferred stock through June 30, 2005, without prior authorization from the SEC. The orders also contain certain requirements regarding ratings of CenterPoint Energy's securities, interest rates, maturities, issuance expenses and use of proceeds. The orders require that we maintain a ratio of common equity to total capitalization of at least 30%. FEDERAL ENERGY REGULATORY COMMISSION The transportation and sale or resale of natural gas in interstate commerce is subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended. The FERC has jurisdiction over, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The rates charged by interstate pipelines for interstate transportation and storage services are also regulated by the FERC. Our natural gas pipeline subsidiaries may periodically file applications with the FERC for changes in their generally available maximum rates and charges designed to allow them to recover their costs of providing service to customers (to the extent allowed by prevailing market conditions), including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period and, in some cases, are subject to refund under applicable law until such time as the FERC issues an order on the allowable level of rates. On November 25, 2003, the FERC issued Order No. 2004, the final rule modifying the Standards of Conduct applicable to electric and natural gas transmission providers, governing the relationship between regulated transmission providers and certain of their affiliates. The rule significantly changes and expands the regulatory burdens of the Standards of Conduct and applies essentially the same standards to jurisdictional electric transmission providers and natural gas pipelines. On February 9, 2004, our natural gas pipeline subsidiaries filed Implementation Plans required under the new rule. Those subsidiaries are further required to post their Implementation Procedures on their websites by June 1, 2004, and to be in compliance with the requirements of the new rule by that date. STATE AND LOCAL REGULATION In almost all communities in which we provide natural gas distribution services, we operate under franchises, certificates or licenses obtained from state and local authorities. The terms of the franchises, with various expiration dates, typically range from 10 to 30 years, though franchises in Arkansas are perpetual. None of our material franchises expire in the near term. We expect to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive. 1
Substantially all of our retail natural gas sales by our local distribution divisions are subject to traditional cost-of-service regulation at rates regulated by the relevant state public utility commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and municipalities we serve. In August 2002, a settlement was approved by the APSC that resulted in an increase in the base rate and service charge revenues of Arkla of approximately $27 million annually. In addition, the APSC approved a gas main replacement surcharge that provided $2 million of additional revenue in 2003 and is expected to provide additional amounts in subsequent years. In December 2002, a settlement was approved by the Oklahoma Corporation Commission that resulted in an increase in the base rate and service charge revenues of Arkla of approximately $6 million annually. In November 2003, Arkla filed a request with the Louisiana Public Service Commission (LPSC) for a $16 million increase to its base rate and service charge revenues in Louisiana. The case is expected to be resolved in mid-2004. In December 2003, a settlement was approved by the City of Houston that will result in an increase in the base rate and service charge revenues of Entex of approximately $7 million annually. Entex has submitted these settlement rates to the 28 other cities within its Houston Division and the Railroad Commission for consideration and approval. If all regulatory approvals are received from these 29 jurisdictions, Entex's base rate and service charge revenues are expected to increase by approximately $7 million annually in addition to the $7 million increase discussed above. On February 10, 2004, a settlement was approved by the LPSC that is expected to result in an increase in Entex's base rate and service charge revenues of approximately $2 million annually. Our gas distribution divisions generally recover the cost of gas provided to customers through gas cost adjustment mechanisms prescribed in their tariffs that are approved by the appropriate regulatory authority. Recently, our Arkla and Entex divisions have been involved in both litigation and regulatory proceedings in which parties have challenged the gas costs that have been recovered from customers. In response to a claim by the City of Tyler, Texas that excessive costs, ranging from $2.8 million to $39.2 million, may have been incurred for gas purchased by Entex for resale to residential and small commercial customers, Entex and the City of Tyler have requested that the Railroad Commission determine whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending October 31, 2002. Similarly, a complaint has been filed with the LPSC by a private party alleging that certain gas costs recovered from Entex customers in Louisiana were excessive and/or were not properly authorized by the LPSC. Additionally, certain private litigants have filed suit in Louisiana state courts, alleging that inappropriate or excessive gas costs have been recovered from Arkla's customers. DEPARTMENT OF TRANSPORTATION In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (the Act). This legislation applies to our interstate pipelines as well as our intrastate pipelines and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires pipeline and distribution companies to assess the integrity of their pipeline transmission facilities in areas of high population concentration or High Consequence Areas (HCA). The legislation further requires companies to perform remediation activities, in accordance with the requirements of the legislation over a 10-year period. In December 2003, the Department of Transportation Office of Pipeline Safety issued the final regulations to implement the Act. These regulations became effective on February 14, 2004. These regulations provided guidance on, among other things, the areas that should be classified as HCA. Our Pipelines and Gathering business segment and our natural gas distribution companies anticipate that compliance with the new regulations will require increases in both capital and operating cost. The level of expenditures required to comply with these regulations will be dependent on several factors, including the age of the facility, the pressures at which the facility operates and the number of facilities deemed to be located in areas designated as HCA. Based on our interpretation of the rules and preliminary technical reviews, we anticipate compliance will require average annual expenditures of approximately $15 to $20 million during the initial 10-year period. 2
ENVIRONMENTAL MATTERS We are subject to a number of federal, state and local laws and regulations relating to the protection of the environment and the safety and health of company personnel and the public. These requirements relate to a broad range of our activities, including: - the discharge of pollutants into the air, water and soil; - the identification, generation, storage, handling, transportation, disposal, record keeping, labeling and reporting of, and the emergency response in connection with, hazardous and toxic materials and wastes, associated with our operations; - noise emissions from our facilities; and - safety and health standards, practices and procedures that apply to the workplace and the operation of our facilities. 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; - 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. If we do not comply with environmental requirements that apply to our operations, regulatory agencies could seek to impose on us civil, administrative and/or criminal liabilities as well as seek to curtail our operations. Under some statutes, private parties could also seek to impose upon us civil fines or liabilities for property damage, personal injury and possibly other costs. Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), owners and operators of facilities from which there has been a release or threatened release of hazardous substances, together with those who have transported or arranged for the disposal of those substances, are liable for: - the costs of responding to that release or threatened release; and - the restoration of natural resources damaged by any such release. LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATION Hydrocarbon Contamination. We and certain of our subsidiaries are among some of 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 ours. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The quantity of monetary damages sought is unspecified. We are unable to estimate the monetary damages, if any, that the plaintiffs may be awarded in these matters. 3
Manufactured Gas Plant Sites. We and our predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in our Minnesota service territory, two of which we believe were neither owned nor operated by us, and for which we believe we have no liability. At December 31, 2003, we had accrued $19 million for remediation of certain Minnesota sites. At December 31, 2003, the estimated range of possible remediation costs for these sites was $8 million to $44 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. We have utilized an environmental expense tracker mechanism in our rates in Minnesota to recover estimated costs in excess of insurance recovery. We have collected or accrued $12.5 million as of December 31, 2003 to be used for environmental remediation. We have received notices from the United States Environmental Protection Agency and others regarding our status as a PRP for other sites. We have been named as a defendant in lawsuits under which contribution is sought for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of ours or our divisions. We are investigating details regarding these sites and the range of environmental expenditures for potential remediation. Based on current information, we have not been able to quantify a range of environmental expenditures for such sites. Mercury Contamination. Our pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by us at some sites in the past, and we have conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on our experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, we believe that the costs of any remediation of these sites will not be material to our financial condition, results of operations or cash flows. Other Environmental. From time to time, we have received notices from regulatory authorities or others regarding our status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Although their ultimate outcome cannot be predicted at this time, we do not believe, based on our experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. RISK FACTORS PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES RATE REGULATION OF OUR BUSINESS MAY DELAY OR DENY FULL RECOVERY OF OUR COSTS. Our rates for natural gas distribution are regulated by certain municipalities and state commissions based on an analysis of our invested capital and our expenses incurred in a test year. Thus, the rates that we are allowed to charge may not match our expenses at any given time. While rate regulation is, generally, premised on providing a reasonable opportunity to recover reasonable and necessary operating expenses and to earn a reasonable return on invested capital, there can be no assurance that the municipalities and state commissions will judge all of our costs to be reasonable or necessary or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs. 4
OUR BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, AND OUR PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE TRANSPORTATION AND STORAGE OF NATURAL GAS. 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 BUSINESS IS SUBJECT TO FLUCTUATIONS IN NATURAL GAS PRICING LEVELS. We are subject to risk associated with price movements of natural gas. Movements in natural gas prices might affect our ability to collect balances due from our customers and 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 our service territory. Additionally, increasing gas prices could create the need for us to provide collateral in order to purchase gas. WE MAY INCUR CARRYING COSTS ASSOCIATED WITH PASSING THROUGH CHANGES IN THE COSTS OF NATURAL GAS. Generally, the regulations of the states in which we operate allow us to pass through changes in the costs of natural gas to our customers through purchased gas adjustment provisions in the applicable tariffs. There is, however, a timing difference between our purchases of natural gas and the ultimate recovery of these costs. Consequently, we may incur carrying costs as a result of this timing difference that are not recoverable from our customers. The failure to recover those additional carrying costs may have an adverse effect on our results of operations, financial condition and cash flows. IF WE FAIL TO EXTEND CONTRACTS WITH TWO OF OUR SIGNIFICANT PIPELINE CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON OUR OPERATIONS. Contracts with two of our significant pipeline customers, Arkla and Laclede, are currently scheduled to expire in 2005 and 2007, respectively. To the extent the pipelines are unable to extend these contracts or the contracts are renegotiated at rates substantially different than the rates provided in the current contracts, there could be an adverse effect on our results of operations, financial condition and cash flows. OUR INTERSTATE PIPELINES' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS. Our interstate pipelines largely rely on gas sourced in the various supply basins located in the Midcontinent region of the United States. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on our results of operations, financial condition and cash flows. OUR REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL. A substantial portion of our revenues are 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. 5
RISK FACTORS ASSOCIATED WITH OUR FINANCIAL CONDITION IF WE ARE UNABLE TO ARRANGE FUTURE FINANCINGS ON ACCEPTABLE TERMS, OUR ABILITY TO FUND FUTURE CAPITAL EXPENDITURES AND REFINANCE EXISTING INDEBTEDNESS COULD BE LIMITED. As of December 31, 2003, we had $2.4 billion of outstanding indebtedness. Approximately $518 million principal amount of this debt must be paid through 2006. In addition, the capital constraints and other factors currently impacting our parent company's and our businesses may require our future indebtedness to include terms that are more restrictive or burdensome than those of our current or historical indebtedness. These terms may negatively impact our ability to operate our business or adversely affect our financial condition and results of operations. The success of our future financing efforts 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 markets in which we operate; - maintenance of acceptable credit ratings by us and by CenterPoint Energy; - market expectations regarding our future earnings and probable cash flows; - market perceptions of our ability to access capital markets on reasonable terms; - provisions of relevant tax and securities laws; and - our ability to obtain approval of specific financing transactions under the 1935 Act. Our current credit ratings are discussed in "Management's Narrative Analysis of the Results of Operations -- Liquidity -- Impact on Liquidity of a Downgrade in Credit Ratings" in Item 7 of Part II of this report. We cannot assure you that these credit ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. 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. CenterPoint Energy and its subsidiaries other than us have approximately $3.0 billion principal amount of debt required to be paid through 2006. This amount excludes amounts related to capital leases, securitization debt and indexed debt securities obligations. 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 ratings could be adversely affected. WE ARE A 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; 6
- 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. Under the 1935 Act, our ability to pay dividends is restricted by the SEC's requirement that common equity as a percentage of total capitalization must be at least 30% after the payment of any dividend. OTHER RISKS WE, AS A SUBSIDIARY OF CENTERPOINT ENERGY, A HOLDING COMPANY, ARE SUBJECT TO REGULATION UNDER THE 1935 ACT. THE 1935 ACT AND RELATED RULES AND REGULATIONS IMPOSE A NUMBER OF RESTRICTIONS ON OUR ACTIVITIES. CenterPoint Energy and certain of its subsidiaries, including us, are subject to regulation by the SEC under the 1935 Act. The 1935 Act, among other things, limits the ability of a holding company and its regulated subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliate transactions. CenterPoint Energy received an order from the SEC under the 1935 Act on June 30, 2003 relating to its financing activities, which is effective until June 30, 2005. CenterPoint Energy must seek a new order before the expiration date. Although authorized levels of financing, together with current levels of liquidity, are believed to be adequate during the period the order is effective, unforeseen events could result in capital needs in excess of authorized amounts, necessitating further authorization from the SEC. Approval of filings under the 1935 Act can take extended periods. The United States Congress is currently considering legislation that has a provision that would repeal the 1935 Act. We cannot predict at this time whether this legislation or any variation thereof will be adopted or, if adopted, the effect of any such law on our business. 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. We cannot assure you that insurance coverage will be available in the future at current costs or on commercially reasonable terms or that the insurance proceeds received for any loss of or any damage to any of our facilities will be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows. ITEM 3. LEGAL PROCEEDINGS For a brief description of certain legal and regulatory proceedings affecting us, please read "Regulation" and "Environmental Matters" in Item 1 of this report and Notes 3, 9(c) and 9(d) to our consolidated financial statements, which information is incorporated herein by reference. 7
ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS CERTAIN FACTORS AFFECTING FUTURE EARNINGS Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors including: - state and federal legislative and regulatory actions or developments, constraints placed on our activities or business by the 1935 Act, changes in or application of laws or regulations applicable to other aspects of our business; - timely rate increases, including recovery of costs; - industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns; - the timing and extent of changes in commodity prices, particularly natural gas; - changes in interest rates or rates of inflation; - weather variations and other natural phenomena; - the timing and extent of changes in the supply of natural gas; - commercial bank and financial market conditions, our access to capital, the costs of such capital, receipt of certain approvals under the 1935 Act, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; - actions by rating agencies; - inability of various counterparties to meet their obligations to us; - non-payment of our services due to financial distress of our customers; and - other factors discussed in Item 1 of this report under "Risk Factors." 8
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (e) REGULATORY ASSETS AND LIABILITIES The Company applies the accounting policies established in SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the accounts of the utility operations of Natural Gas Distribution and MRT. As of December 31, 2002 and 2003, the Company had recorded $31 million and $34 million of regulatory assets, respectively, which are included in other long-term assets on our Consolidated Balance Sheets. As of December 31, 2002 and 2003, the Company had recorded $19 million and $434 million of regulatory liabilities, respectively, which are included in other long-term liabilities on our Consolidated Balance Sheets. Included in regulatory liabilities at December 31, 2003, is $415 million of removal costs that resulted from a reclassification of removal costs from accumulated depreciation in accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). For further information, see Note 2(n). If events were to occur that would make recovery of these assets and liabilities no longer probable, the Company would be required to write off or write down these regulatory assets and liabilities. In addition, the Company would be required to determine any impairment of the carrying costs of plant and inventory assets. 3. REGULATORY MATTERS (a) RATE CASES In August 2002, a settlement was approved by the Arkansas Public Service Commission (APSC) that resulted in an increase in the base rate and service charge revenues of Arkla of approximately $27 million annually. In addition, the APSC approved a gas main replacement surcharge that provided $2 million of additional revenue in 2003 and is expected to provide additional amounts in subsequent years. In December 2002, a settlement was approved by the Oklahoma Corporation Commission that resulted in an increase in the base rate and service charge revenues of Arkla of approximately $6 million annually. In November 2003, Arkla filed a request with the Louisiana Public Service Commission (LPSC) for a $16 million increase to its base rate and service charge revenues in Louisiana. The case is expected to be resolved in mid-2004. In December 2003, a settlement was approved by the City of Houston that will result in an increase in the base rate and service charge revenues of Entex of approximately $7 million annually. Entex has submitted these settlement rates to the 28 other cities within its Houston Division and the Railroad Commission of Texas for consideration and approval. If all regulatory approvals are received from these 29 jurisdictions, Entex's base rate and service charge revenues are expected to increase by approximately $7 million annually in addition to the $7 million increase discussed above. On February 10, 2004, a settlement was approved by the LPSC that is expected to result in an increase in Entex's base rate and service charge revenues of approximately $2 million annually. (b) OTHER REGULATORY PROCEEDINGS City of Tyler, Texas Dispute. In July 2002, the City of Tyler, Texas, asserted that Entex had overcharged residential and small commercial customers in that city for excessive gas costs under supply agreements in effect since 1992. That dispute has been referred to the Texas Railroad Commission by agreement of the parties for a determination of whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending October 31, 2002. The Company believes that all costs for Entex's Tyler distribution system have been properly included and recovered from customers pursuant to Entex's filed tariffs. FERC Contract Inquiry. On September 15, 2003, the Federal Energy Regulatory Commission (FERC) issued a Show Cause Order to CEGT, one of the Company's natural gas pipeline subsidiaries. In its Show Cause Order, the FERC contended that CEGT failed to file with the FERC and post on the internet certain information relating to negotiated rate contracts that CEGT had entered into pursuant to 1996 FERC orders. Those orders authorized CEGT to enter into negotiated rate contracts that deviate from the rates prescribed under CEGT's filed FERC tariffs. The FERC also alleged that certain of the contracts contain provisions that CEGT was not authorized to negotiate under the terms of the 1996 orders. Following issuance of the Show Cause Order, CEGT made certain compliance filings, met with members of the FERC's staff and provided additional information relating to the FERC's Show Cause Order. On March 4, 2004, the FERC issued orders accepting CEGT's compliance filings and approving a Stipulation and Consent Agreement with CEGT that resolved the issues raised by the Show Cause Order. The resolution of these issues did not have a material impact on our results of operations, financial condition and cash flows. 9
5. DERIVATIVE INSTRUMENTS The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative financial instruments such as physical forward contracts, swaps and options to mitigate the impact of changes and cash flows of its natural gas businesses on its operating results and cash flows. (a) NON-TRADING ACTIVITIES. Cash Flow Hedges. To reduce the risk from market fluctuations associated with purchased gas costs, the Company enters into energy derivatives in order to hedge certain expected purchases and sales of natural gas (non-trading energy derivatives). The Company applies hedge accounting for its non-trading energy derivatives utilized in non-trading activities only if there is a high correlation between price movements in the derivative and the item designated as being hedged. The Company analyzes its physical transaction portfolio to determine its net exposure by delivery location and delivery period. Because the Company's physical transactions with similar delivery locations and periods are highly correlated and share similar risk exposures, the Company facilitates hedging for customers by aggregating physical transactions and subsequently entering into non-trading energy derivatives to mitigate exposures created by the physical positions. During 2003, no hedge ineffectiveness was recognized in earnings from derivatives that are designated and qualify as Cash Flow Hedges. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive income. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive income is reclassified and included in the Company's Statements of Consolidated Income under the caption "Natural Gas." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of December 31, 2003, the Company expects $39 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months. The maximum length of time the Company is hedging its exposure to the variability in future cash flows for forecasted transactions on existing financial instruments is primarily two years with a limited amount of exposure up to three years. The Company's policy is not to exceed five years in hedging its exposure. 10
(b) CREDIT RISKS. In addition to the risk associated with price movements, credit risk is also inherent in the Company's non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the non-trading derivative assets of the Company as of December 31, 2002 and 2003: DECEMBER 31, 2002 DECEMBER 31, 2003 ----------------------- ------------------------ INVESTMENT INVESTMENT GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL (3) ----------- ------ ----------- --------- Energy marketers............... $ 7 $ 22 $ 24 $ 35 Financial institutions......... 9 9 21 21 Other.......................... -- -- -- 1 ------ ------ ------- --------- Total........................ $ 16 $ 31 $ 45 $ 57 ====== ====== ======= ========= ---------- (1) "Investment grade" is primarily determined using publicly available credit ratings along with the consideration of credit support (such as parent company guarantees) and collateral, which encompasses cash and standby letters of credit. (2) For unrated counterparties, the Company performs financial statement analysis, considering contractual rights and restrictions and collateral, to create a synthetic credit rating. (3) The $35 million non-trading derivative asset includes an $11 million asset due to trades with Reliant Energy Services, a former affiliate. As of December 31, 2003, Reliant Energy Services did not have an investment grade rating. (c) GENERAL POLICY. CenterPoint Energy has established a Risk Oversight Committee comprised of corporate and business segment officers that oversees commodity price and credit risk activities, including the trading, marketing, risk management services and hedging activities of CenterPoint Energy and its subsidiaries, including us. The committee's duties are to establish commodity risk policies, allocate risk capital within limits established by CenterPoint Energy's board of directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with CenterPoint Energy's risk management policies and procedures and trading limits established by CenterPoint Energy's board of directors. CenterPoint Energy's policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument. 11
7. EMPLOYEE BENEFIT PLANS (a) PENSION PLANS Substantially all of the Company's employees participate in CenterPoint Energy's qualified non-contributory pension plan. Under the cash balance formula, participants accumulate a retirement benefit based upon 4% of eligible earnings and accrued interest. Prior to 1999, the pension plan accrued benefits based on years of service, final average pay and covered compensation. As a result, certain employees participating in the plan as of December 31, 1998 are eligible to receive the greater of the accrued benefit calculated under the prior plan through 2008 or the cash balance formula. CenterPoint Energy's funding policy is to review amounts annually in accordance with applicable regulations in order to achieve adequate funding of projected benefit obligations. Pension expense is allocated to the Company based on covered employees. This calculation is intended to allocate pension costs in the same manner as a separate employer plan. Assets of the plan are not segregated or restricted by CenterPoint Energy's participating subsidiaries. The Company recognized pension expense of $1 million, $13 million and $36 million for the years ended December 31, 2001, 2002 and 2003, respectively. In addition to the Plan, the Company participates in CenterPoint Energy's non-qualified pension plan, which allows participants to retain the benefits to which they would have been entitled under the qualified pension plan except for federally mandated limits on these benefits or on the level of salary on which these benefits may be calculated. The expense associated with the non-qualified pension plan was $5 million, $2 million and $3 million for the years ended December 31, 2001, 2002 and 2003, respectively. 9. COMMITMENTS AND CONTINGENCIES (A) COMMITMENTS Environmental Capital Commitments. The Company has various commitments for capital and environmental expenditures. The Company anticipates no significant capital and other special project expenditures between 2004 and 2008 for environmental compliance. Fuel Commitments. Fuel commitments include several long-term natural gas contracts related to the Company's natural gas distribution operations, which have various quantity requirements and durations that are not classified as non-trading derivative assets and liabilities in the Company's Consolidated Balance Sheets as of December 31, 2003 as these contracts meet the SFAS No. 133 exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Minimum payment obligations for natural gas supply contracts are approximately $1 billion in 2004, $565 million in 2005, $344 million in 2006, $171 million in 2007 and $24 million in 2008. (B) LEASE COMMITMENTS The following table sets forth information concerning the Company's obligations under non-cancelable long-term operating leases, principally consisting of rental agreements for building space, data processing equipment and vehicles, including major work equipment (in millions): 2004................ $ 25 2005................ 10 2006................ 8 2007................ 4 2008................ 3 2009 and beyond..... 10 ------- Total..... $ 60 ======= Total rental expense for all operating leases was $31 million, $31 million and $28 million in 2001, 2002 and 2003, respectively. (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 against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs' alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the Btu content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. 12
Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against CenterPoint Energy, the Company, Entex Gas Marketing Company, and others 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. The plaintiffs seek class certification, but no class has been certified. The plaintiffs allege that defendants inflated the prices charged to certain consumers of natural gas. In February 2003, a similar suit was filed against the Company in state court in Caddo Parish, Louisiana purportedly on behalf of a class of residential or business customers in Louisiana who allegedly have been overcharged for gas or gas service provided by the Company. In February 2004, another suit was filed against the Company in Calcasieu Parish, Louisiana, seeking to recover alleged overcharges for gas or gas services allegedly provided by Entex without advance approval by the LPSC. The plaintiffs in these cases seek injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages and civil penalties. In these cases, CenterPoint Energy, the Company and Entex Gas Marketing Company deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. (D) ENVIRONMENTAL MATTERS Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among some of the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The quantity of monetary damages sought is unspecified. The Company is unable to estimate the monetary damages, if any, that the plaintiffs may be awarded in these matters. Manufactured Gas Plant Sites. The Company and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in the Company's Minnesota service territory, two of which it believes were neither owned nor operated by the Company, and for which it believes it has no liability. At December 31, 2003, the Company had accrued $19 million for remediation of certain Minnesota sites. At December 31, 2003, the estimated range of possible remediation costs for these sites was $8 million to $44 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. The Company has collected or accrued $12.5 million as of December 31, 2003 to be used for environmental remediation. 13
The Company has received notices from the United States Environmental Protection Agency and others regarding its status as a PRP for other sites. The Company has been named as a defendant in lawsuits under which contribution is sought for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of the Company or its divisions. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. Based on current information, the Company has not been able to quantify a range of environmental expenditures for such sites. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows. 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. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims which it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, results of operations or cash flows. Other Proceedings The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. 12. REPORTABLE SEGMENTS Because CERC Corp. is an indirect wholly owned subsidiary of CenterPoint Energy, the Company's determination of reportable 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 Company's reportable business segments include the following: Natural Gas Distribution, Pipelines and Gathering and Other Operations. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers, and some non-rate regulated retail gas marketing operations. Pipelines and Gathering includes the interstate natural gas pipeline operations and natural gas gathering and pipeline services. Other Operations includes unallocated general corporate expenses and non-operating investments. All of the Company's long-lived assets are in the United States. 14
Financial data for business segments and products and services are as follows: NATURAL GAS PIPELINES AND OTHER RECONCILING SALES TO DISTRIBUTION GATHERING OPERATIONS ELIMINATIONS AFFILIATES CONSOLIDATED ------------ --------- ---------- ------------ ---------- ------------ AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2001: Revenues from external customers(1)................... 4,737 307 -- -- -- 5,044 Intersegment revenues............ 5 108 -- (113) -- -- Depreciation and amortization.... 147 58 2 -- -- 207 Operating income (loss).......... 130 137 (1) -- -- 266 Total assets..................... 4,083 2,379 101 (182) -- 6,381 Expenditures for long-lived assets......................... 209 54 -- -- -- 263 AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2002: Revenues from external customers(1)................... 3,927 253 -- -- 28 4,208 Intersegment revenues............ 33 121 -- (154) -- -- Depreciation and amortization.... 126 41 -- -- -- 167 Operating income................. 198 153 2 -- -- 353 Total assets..................... 4,428 2,500 206 (685) -- 6,449 Expenditures for long-lived assets......................... 196 70 -- -- -- 266 AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2003: Revenues from external customers...................... 5,378 241 -- -- 31 5,650 Intersegment revenues............ 57 166 9 (232) -- -- Depreciation and amortization.... 136 40 -- -- -- 176 Operating income (loss).......... 202 158 (1) -- -- 359 Total assets..................... 4,661 2,519 388 (715) -- 6,853 Expenditures for long-lived assets......................... 199 66 -- -- -- 265 - ---------- (1) Included in revenues from external customers are revenues from sales to Reliant Resources, a former affiliate, of $181 million and $42 million for the years ended December 31, 2001 and 2002, respectively. YEAR ENDED DECEMBER 31, ---------------------------------- 2001 2002 2003 --------- --------- --------- (IN MILLIONS) REVENUES BY PRODUCTS AND SERVICES: Retail gas sales................................................... $ 4,645 $ 3,857 $ 5,310 Gas transportation................................................. 307 255 244 Energy products and services....................................... 92 96 96 --------- --------- --------- Total............................................................ $ 5,044 $ 4,208 $ 5,650 ========= ========= ========= 15