- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE TRANSITION PERIOD FROM _________ TO _____________.
----------
Commission file number 1-13265
CENTERPOINT ENERGY RESOURCES CORP.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0511406
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1111 LOUISIANA
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
(713) 207-1111
(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 August 4, 2003, all 1,000 shares of CenterPoint Energy Resources Corp.
common stock were held by Utility Holding, LLC, a wholly owned subsidiary of
CenterPoint Energy, Inc.
CENTERPOINT ENERGY RESOURCES CORP.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2003
TABLE OF CONTENTS
<Table>
PART I FINANCIAL INFORMATION
Item 1. Financial Statements .................................................................................1
Statements of Consolidated Income
Three and Six Months Ended June 30, 2002 and 2003 (unaudited) ........................................1
Consolidated Balance Sheets
December 31, 2002 and June 30, 2003 (unaudited) ......................................................2
Statements of Consolidated Cash Flows
Six Months Ended June 30, 2002 and 2003 (unaudited) ..................................................4
Notes to Unaudited Consolidated Financial Statements ....................................................5
Item 2. Management's Narrative Analysis of the Results of Operations of
CenterPoint Energy Resources Corp. and Subsidiaries ....................................................15
Item 4. Controls and Procedures .............................................................................24
PART II OTHER INFORMATION
Item 1. Legal Proceedings ...................................................................................25
Item 5. Other Information ...................................................................................25
Item 6. Exhibits and Reports on Form 8-K ....................................................................28
</Table>
i
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
From time to time we make statements concerning our expectations, beliefs,
plans, objectives, goals, strategies, future events or performance and
underlying assumptions and other statements that are not historical facts. These
statements are "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995. Actual results may differ materially
from those expressed or implied by these statements. You can generally identify
our forward-looking statements by the words "anticipate," "believe," "continue,"
"could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective,"
"plan," "potential," "predict," "projection," "should," "will," or other similar
words.
We have based our forward-looking statements on our management's beliefs
and assumptions based on information available to our management at the time the
statements are made. We caution you that assumptions, beliefs, expectations,
intentions and projections about future events may and often do vary materially
from actual results. Therefore, we cannot assure you that actual results will
not differ materially from those expressed or implied by our forward-looking
statements.
The following are some of the factors that could cause actual results to
differ materially from those expressed or implied in forward-looking statements:
o 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 and actions;
o timely rate increases, including recovery of costs;
o the successful and timely completion of our capital projects;
o industrial, commercial and residential growth in our service territory
and changes in market demand and demographic patterns;
o our pursuit of potential business strategies, including acquisitions
or dispositions of assets;
o changes in business strategy or development plans;
o the timing and extent of changes in commodity prices, particularly
natural gas;
o changes in interest rates or rates of inflation;
o unanticipated changes in operating expenses and capital expenditures;
o weather variations and other natural phenomena;
o the timing and extent of changes in the supply of natural gas;
o 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;
o actions by rating agencies;
o legal and administrative proceedings and settlements;
o changes in tax laws;
o inability of various counterparties to meet their obligations with
respect to our financial instruments;
o any lack of effectiveness of our disclosure controls and procedures;
ii
o changes in technology;
o significant changes in our relationship with our employees, including
the availability of qualified personnel and potential adverse effects
if labor disputes or grievances were to occur;
o significant changes in critical accounting policies;
o acts of terrorism or war, including any direct or indirect effect on
our business resulting from terrorist attacks such as occurred on
September 11, 2001 or any similar incidents or responses to those
incidents;
o the availability and price of insurance;
o political, legal, regulatory and economic conditions and developments
in the United States; and
o other factors we discuss in this report, including those outlined in
Item 5 in Part II under "Risk Factors."
You should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement, and we undertake no obligation to publicly update or revise any
forward-looking statements.
iii
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)
<Table>
<Caption>
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
---------------------------- ----------------------------
2002 2003 2002 2003
----------- ----------- ----------- -----------
REVENUES .................................... $ 868,471 $ 1,031,595 $ 2,110,750 $ 3,125,616
----------- ----------- ----------- -----------
EXPENSES:
Natural gas .............................. 583,526 735,658 1,445,105 2,390,778
Operation and maintenance ................ 164,788 161,793 329,501 339,460
Depreciation and amortization ............ 41,981 44,281 82,252 88,191
Taxes other than income taxes ............ 29,800 22,928 62,320 68,104
----------- ----------- ----------- -----------
Total ................................ 820,095 964,660 1,919,178 2,886,533
----------- ----------- ----------- -----------
OPERATING INCOME ............................ 48,376 66,935 191,572 239,083
----------- ----------- ----------- -----------
OTHER INCOME (EXPENSE):
Interest expense ......................... (38,056) (48,326) (73,633) (84,145)
Distribution on trust preferred securities (7) (6) (13) (12)
Other, net ............................... 3,598 2,380 5,854 3,439
----------- ----------- ----------- -----------
Total ................................ (34,465) (45,952) (67,792) (80,718)
----------- ----------- ----------- -----------
INCOME BEFORE INCOME TAXES .................. 13,911 20,983 123,780 158,365
Income Tax Expense ....................... 6,164 6,325 46,864 55,535
----------- ----------- ----------- -----------
NET INCOME .................................. $ 7,747 $ 14,658 $ 76,916 $ 102,830
=========== =========== =========== ===========
</Table>
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
<Table>
<Caption>
DECEMBER 31, JUNE 30,
2002 2003
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents .......................................................... $ 9,237 $ 21,245
Accounts and notes receivable, principally customers, (net of allowance for doubtful
accounts of $19,568 and $24,587, respectively) .................................. 380,317 352,052
Accrued unbilled revenue ........................................................... 284,112 135,265
Accounts and notes receivable - affiliated companies, net .......................... -- 45,001
Materials and supplies ............................................................. 32,264 33,555
Natural gas inventory .............................................................. 103,443 106,341
Non-trading derivative assets ...................................................... 27,275 21,953
Taxes receivable ................................................................... 61,512 17,405
Prepaid expenses ................................................................... 20,767 4,471
Other .............................................................................. 29,998 25,911
----------- -----------
Total current assets ............................................................. 948,925 763,199
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment ...................................................... 3,885,820 3,964,268
Less accumulated depreciation ...................................................... (650,148) (705,122)
----------- -----------
Property, plant and equipment, net ............................................... 3,235,672 3,259,146
----------- -----------
OTHER ASSETS:
Goodwill ........................................................................... 1,740,510 1,740,510
Other intangibles, net ............................................................. 19,878 20,253
Non-trading derivative assets ...................................................... 3,866 14,352
Notes receivable - affiliated companies, net ....................................... 39,097 37,421
Other .............................................................................. 55,571 126,971
----------- -----------
Total other assets ............................................................... 1,858,922 1,939,507
----------- -----------
TOTAL ASSETS .......................................................................... $ 6,043,519 $ 5,961,852
=========== ===========
</Table>
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
<Table>
<Caption>
DECEMBER 31, JUNE 30,
2002 2003
------------ ----------
CURRENT LIABILITIES:
Short-term borrowings ................................................................ $ 347,000 $ --
Current portion of long-term debt .................................................... 517,616 142,145
Accounts payable, principally trade .................................................. 465,694 329,959
Accounts and notes payable - affiliated companies, net ............................... 101,231 --
Interest accrued ..................................................................... 49,084 61,621
Taxes accrued ........................................................................ 57,057 54,058
Customer deposits .................................................................... 54,081 52,383
Non-trading derivative liabilities ................................................... 9,973 2,469
Accumulated deferred income taxes, net ............................................... 6,557 7,422
Other ................................................................................ 102,510 67,300
---------- ----------
Total current liabilities ........................................................ 1,710,803 717,357
---------- ----------
OTHER LIABILITIES:
Accumulated deferred income taxes, net ............................................... 589,332 599,940
Benefit obligations .................................................................. 132,434 130,737
Non-trading derivative liabilities ................................................... 873 2,873
Other ................................................................................ 125,876 151,129
---------- ----------
Total other liabilities .......................................................... 848,515 884,679
---------- ----------
LONG-TERM DEBT .......................................................................... 1,441,264 2,206,922
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 9)
COMPANY OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED SECURITIES OF SUBSIDIARY
TRUST HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF THE COMPANY ................... 508 508
---------- ----------
STOCKHOLDER'S EQUITY:
Common stock ......................................................................... 1 1
Paid-in capital ...................................................................... 1,986,364 1,985,254
Retained earnings .................................................................... 44,804 147,634
Accumulated other comprehensive income ............................................... 11,260 19,497
---------- ----------
Total stockholder's equity ....................................................... 2,042,429 2,152,386
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY ........................................... $6,043,519 $5,961,852
========== ==========
</Table>
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)
<Table>
<Caption>
SIX MONTHS ENDED JUNE 30,
-------------------------
2002 2003
--------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................................................ $ 76,916 $ 102,830
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization ...................................................... 82,252 88,191
Deferred income taxes .............................................................. (71,963) 6,117
Changes in other assets and liabilities:
Accounts and notes receivable, net ............................................... 329,596 177,452
Accounts receivable/payable, affiliates .......................................... (79,064) (113,374)
Inventory ........................................................................ 39,339 (4,189)
Taxes receivable ................................................................. (21,406) 44,107
Accounts payable ................................................................. (296) (136,845)
Fuel cost recovery ............................................................... 32,030 (844)
Interest and taxes accrued ....................................................... (7,112) 9,539
Net non-trading derivative assets and liabilities ................................ (2,231) 2,696
Other current assets ............................................................. 7,654 20,382
Other current liabilities ........................................................ (41,902) (36,908)
Other assets ..................................................................... 10,990 (2,120)
Other liabilities ................................................................ (37,575) 23,785
Other, net ....................................................................... (1,253) (11,330)
--------- ---------
Net cash provided by operating activities ..................................... 315,975 169,489
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures .................................................................. (117,991) (111,864)
Other, net ............................................................................ 3,192 (176)
--------- ---------
Net cash used in investing activities ......................................... (114,799) (112,040)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of long-term debt ............................................................ (6,633) (367,008)
Proceeds from long-term debt .......................................................... -- 768,525
Debt issuance costs ................................................................... -- (68,776)
Decrease in short-term borrowings, net ................................................ (197,856) (347,000)
Increase (decrease) in notes with affiliates, net ..................................... 17,270 (31,182)
--------- ---------
Net cash used in financing activities ......................................... (187,219) (45,441)
--------- ---------
NET INCREASE IN CASH AND CASH EQUIVALENTS ................................................ 13,957 12,008
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE PERIOD ..................................... 16,425 9,237
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF THE PERIOD ........................................... $ 30,382 $ 21,245
========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest .............................................................................. $ 84,976 $ 72,183
Income taxes .......................................................................... 153,360 4,305
</Table>
See Notes to the Company's Interim Financial Statements
4
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
(1) BACKGROUND AND BASIS OF PRESENTATION
Included in this Quarterly Report on Form 10-Q of CenterPoint Energy
Resources Corp. (CERC Corp.), together with its wholly owned and majority owned
subsidiaries (the Company), are the Company's consolidated interim financial
statements and notes (Interim Financial Statements). The Company has filed a
Current Report on Form 8-K dated June 16, 2003 (June 16 Form 8-K). The June 16
Form 8-K gives retroactive effect of the adoption of Emerging Issues Task Force
(EITF) No. 02-03 "Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Contracts Involved in Energy Trading and Risk
Management Activities" (EITF No. 02-03). The Company's adoption of EITF No.
02-03 only impacted the year ended December 31, 2000. The Interim Financial
Statements are unaudited, omit certain financial statement disclosures and
should be read with the June 16 Form 8-K, including the exhibits thereto, and
the Quarterly Report on Form 10-Q of CERC Corp. for the quarter ended March 31,
2003.
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 (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 its subsidiaries. The 1935 Act, among other
things, limits the ability of the holding company and its subsidiaries to issue
debt and equity securities without prior authorization, restricts the source of
dividend payments to funds from 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 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.
The following notes to the consolidated annual financial statements
included in Exhibit 99.2 to the June 16 Form 8-K (CERC Corp. 8-K Notes) relate
to certain contingencies. These notes, as updated herein, are incorporated
herein by reference:
Notes to Consolidated Financial Statements: Note 3(e) (Regulatory Matters),
Note 5 (Derivative Instruments) and Note 10 (Commitments and
Contingencies).
For information regarding environmental matters and legal proceedings, see
Note 9.
5
(2) NEW ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2003, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement
Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of an asset
retirement obligation to be recognized as a liability is incurred and
capitalized as part of the cost of the related tangible long-lived assets. Over
time, the liability is accreted to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset.
Retirement obligations associated with long-lived assets included within the
scope of SFAS No. 143 are those for which a legal obligation exists under
enacted laws, statutes and written or oral contracts, including obligations
arising under the doctrine of promissory estoppel. SFAS No. 143 is effective for
fiscal years beginning after June 15, 2002. SFAS No. 143 requires entities to
record a cumulative effect of change in accounting principle in the income
statement in the period of adoption.
The Company has identified no asset retirement obligations. The Company's
rate-regulated businesses have previously recognized removal costs as a
component of depreciation expense in accordance with regulatory treatment. As of
June 30, 2003, these previously recognized removal costs of $391 million do not
represent SFAS No. 143 asset retirement obligations, but rather embedded
regulatory liabilities.
In April 2002, the Financial Accounting Standards Board (FASB) issued SFAS
No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB
Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145
eliminates the current requirement that gains and losses on debt extinguishment
must be classified as extraordinary items in the income statement. Instead, such
gains and losses will be classified as extraordinary items only if they are
deemed to be unusual and infrequent. SFAS No. 145 also requires that capital
leases that are modified so that the resulting lease agreement is classified as
an operating lease be accounted for as a sale-leaseback transaction. The changes
related to debt extinguishment are effective for fiscal years beginning after
May 15, 2002, and the changes related to lease accounting are effective for
transactions occurring after May 15, 2002. The Company has applied this guidance
as it relates to lease accounting and the accounting provisions related to debt
extinguishment. Upon adoption of SFAS No. 145, any gain or loss on
extinguishment of debt that was classified as an extraordinary item in prior
periods is required to be reclassified. No such reclassification was required in
the three month or six month period ended June 30, 2002.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
nullifies EITF Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)" (EITF No. 94-3). The principal difference
between SFAS No. 146 and EITF No. 94-3 relates to the requirements for
recognition of a liability for costs associated with an exit or disposal
activity. SFAS No. 146 requires that a liability be recognized for a cost
associated with an exit or disposal activity when it is incurred. A liability is
incurred when a transaction or event occurs that leaves an entity little or no
discretion to avoid the future transfer or use of assets to settle the
liability. Under EITF No. 94-3, a liability for an exit cost was recognized at
the date of an entity's commitment to an exit plan. In addition, SFAS No. 146
also requires that a liability for a cost associated with an exit or disposal
activity be recognized at its fair value when it is incurred. SFAS No. 146 is
effective for exit or disposal activities that are initiated after December 31,
2002. The Company adopted the provisions of SFAS No. 146 on January 1, 2003.
In June 2002, the EITF reached a consensus on EITF No. 02-03 that all
mark-to-market gains and losses on energy trading contracts should be shown net
in the income statement whether or not settled physically. An entity should
disclose the gross transaction volumes for those energy-trading contracts that
are physically settled. The EITF did not reach a consensus on whether
recognition of dealer profit, or unrealized gains and losses at inception of an
energy-trading contract, is appropriate in the absence of quoted market prices
or current market transactions for contracts with similar terms. The FASB staff
indicated that until such time as a consensus is reached, the FASB staff will
continue to hold the view that previous EITF consensus do not allow for
recognition of dealer profit, unless evidenced by quoted market prices or other
current market transactions for energy trading contracts with similar terms and
counterparties. The consensus on presenting gains and losses on energy trading
contracts net is effective for financial statements issued for periods ending
after July 15, 2002. Upon application of the consensus, comparative financial
statements for prior periods should be reclassified to conform to the consensus.
The Company's adoption of EITF No. 02-03 on January 1, 2003 only impacted the
year ended December 31, 2000 and had no effect on the Interim Financial
Statements.
In November 2002, the FASB issued FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 requires that a
liability be recorded in the guarantor's balance sheet upon issuance of certain
guarantees. In
6
addition, FIN 45 requires disclosures about the guarantees that an entity has
issued. The provision for initial recognition and measurement of the liability
will be applied on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure provisions of FIN 45 are effective for
financial statements of interim or annual periods ending after December 15,
2002. The adoption of FIN 45 did not materially affect the Company's
consolidated financial statements.
In January 2003, the FASB issued 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. FIN 46 is
effective for all new variable interest entities created or acquired after
January 31, 2003. For variable interest entities created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period beginning after June 15, 2003. The Company is currently
assessing the impact that this statement will have on its consolidated financial
statements.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS No. 149). SFAS No. 149
clarifies when a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133 and when a
derivative contains a financing component. SFAS No. 149 also amends certain
existing pronouncements, which will result in more consistent reporting of
contracts as either derivative or hybrid instruments. SFAS No. 149 is effective
for contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003, and should be applied
prospectively. Certain paragraphs of this statement that relate to forward
purchases or sales of when-issued securities or other securities that do not yet
exist should be applied to both existing contracts and new contracts entered
into after June 30, 2003. The provisions of this statement that relate to SFAS
No. 133 implementation issues that have been effective for fiscal quarters that
began prior to June 15, 2003 should continue to be applied in accordance with
their respective effective dates. The adoption of SFAS No. 149 will not have a
material effect on the Company's consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS
No. 150). SFAS No. 150 establishes standards for how an issuer classifies and
measures certain financial instruments with characteristics of both liabilities
and equity. It requires that an issuer classify a financial instrument that is
within its scope as a liability (or an asset in some circumstances). Many of
those instruments were previously classified as equity. SFAS No. 150 is
effective for financial instruments entered into or modified after May 31, 2003
and otherwise is effective at the beginning of the first interim period
beginning after June 15, 2003. It is to be implemented by reporting the
cumulative effect of a change in an accounting principle with no restatement of
prior period information permitted. The Company is currently assessing the
impact that this statement will have on its consolidated financial statements.
(3) DERIVATIVE INSTRUMENTS
The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business. The Company utilizes
derivative financial instruments such as physical forward contracts, swaps and
options (Energy Derivatives) to mitigate the impact of changes and cash flows of
its natural gas businesses on its operating results and cash flows.
Cash Flow Hedges. During the six months ended June 30, 2003, there was no
hedge ineffectiveness 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.
During the six months ended June 30, 2003, there was no effect on earnings as a
result of the discontinuance of cash flow hedges. As of June 30, 2003, the
Company expects $19.5 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. 8-K Notes, which is incorporated herein by reference.
7
(4) GOODWILL AND INTANGIBLES
Goodwill as of December 31, 2002 and June 30, 2003 by reportable business
segment is as follows (in millions):
<Table>
Natural Gas Distribution ............................................ $1,085
Pipelines and Gathering ............................................. 601
Other Operations .................................................... 55
------
Total ............................................................ $1,741
======
</Table>
The components of the Company's other intangible assets consist of the
following:
<Table>
<Caption>
DECEMBER 31, 2002 JUNE 30, 2003
------------------------ --------------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Land use rights .... $ 7 $(2) $ 7 $(3)
Other .............. 18 (3) 19 (3)
--- --- --- ---
Total .............. $25 $(5) $26 $(6)
=== === === ===
</Table>
The Company recognizes specifically identifiable intangibles when specific
rights and contracts are acquired. The Company amortizes other acquired
intangibles on a straight-line basis over the lesser of their contractual or
estimated useful lives. The Company has no intangible assets with indefinite
lives recorded as of June 30, 2003. 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 June
30, 2002 and 2003 was $0.3 million and $0.4 million, respectively. Amortization
expense for other intangibles for the six months ended June 30, 2002 and 2003
was $0.5 million and $0.7 million, respectively. Estimated amortization expense
for the remainder of 2003 is approximately $0.7 million and is approximately
$2.1 million per year for the five succeeding fiscal years.
(5) SHORT-TERM BORROWINGS, LONG-TERM DEBT AND RECEIVABLES FACILITY
(a) Short-Term Borrowings
Credit Facilities. As of June 30, 2003, CERC Corp. had a revolving credit
facility that provided for an aggregate of $200 million in committed credit. As
of June 30, 2003, the revolving credit facility was not utilized. The revolving
credit facility terminates on March 23, 2004. Rates for borrowings under this
facility, including the facility fee, are LIBOR plus 250 basis points based on
current credit ratings and the applicable pricing grid. The revolving credit
facility contains various business and financial covenants. CERC Corp. is
currently in compliance with the covenants.
(b) Long-Term Debt
On March 25 and April 14, 2003, the Company issued $650 million and $112
million aggregate principal amount, respectively, of 7.875% senior unsecured
notes due in 2013. A portion of the proceeds was used to refinance $360 million
aggregate principal amount of the Company's 6 3/8% Term Enhanced ReMarketable
Securities (TERM Notes) and to pay costs associated with the refinancing.
Proceeds were also used to repay approximately $340 million of bank borrowings
under the Company's $350 million revolving credit facility prior to its
expiration on March 31, 2003. The remaining $140 million aggregate principal
amount of TERM Notes are expected to be refinanced or remarketed in November
2003.
(c) Receivables Facility
In connection with the Company's November 2002 amendment and extension of
its $150 million receivables facility, CERC Corp. formed a bankruptcy remote
subsidiary for the sole purpose of buying and selling receivables created by the
Company. This transaction is accounted for as a sale of receivables under the
provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities," and, as a result, the related
receivables are excluded from the Consolidated Balance Sheets. Effective June
25, 2003, the
8
Company elected to reduce the purchase limit under the receivables facility from
$150 million to $100 million. As of December 31, 2002 and June 30, 2003, the
Company had utilized $107 million and $73 million of its receivables facility,
respectively.
The bankruptcy remote subsidiary purchases receivables with cash and
subordinated notes. In July 2003, the subordinated notes owned by the Company
were pledged to a gas supplier to secure obligations incurred in connection with
the purchase of gas by the Company.
(6) TRUST PREFERRED SECURITIES
A statutory business trust created by CERC Corp. has issued convertible
preferred securities. 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, 2002 and June 30, 2003, $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.
The sole asset of the trust consists of convertible junior subordinated
debentures of CERC Corp. having an interest rate and maturity date that
correspond to the distribution rate and mandatory redemption date of the
convertible preferred securities, and a principal amount corresponding to the
common and convertible preferred securities issued by the trust. For additional
information regarding the convertible preferred securities, see Note 7 to the
CERC Corp. 8-K Notes, which is incorporated herein by reference.
(7) COMPREHENSIVE INCOME
The following table summarizes the components of total comprehensive
income:
<Table>
<Caption>
FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS
JUNE 30, ENDED JUNE 30,
-------------------------- ------------------
2002 2003 2002 2003
-------- ------- ---- ----
(IN MILLIONS)
Net income ........................................... $ 8 $ 15 $ 77 $103
---- ---- ---- ----
Other comprehensive income (loss):
Net deferred gain (loss) from cash flow hedges..... (12) 9 34 7
Reclassification of deferred loss (gain) on
derivatives realized in net income .............. (2) (1) 3 1
---- ---- ---- ----
Other comprehensive income (loss) .................... (14) 8 37 8
---- ---- ---- ----
Comprehensive income (loss) .......................... $ (6) $ 23 $114 $111
==== ==== ==== ====
</Table>
(8) RELATED PARTY TRANSACTIONS
From time to time, the Company has receivables from, or payables to,
CenterPoint Energy or its subsidiaries. As of December 31, 2002, the Company had
net short-term borrowings, included in accounts and notes payable-affiliated
companies, of $74 million and net accounts payable of $27 million. As of June
30, 2003, the Company had net accounts receivable of $45 million included in
accounts and notes receivable-affiliated companies. As of December 31, 2002 and
June 30, 2003, the Company had net long-term receivables, included in notes
receivable-affiliated companies, totaling $39 million and $37 million,
respectively. For the three months ended June 30, 2002 and 2003, the Company had
net interest income related to affiliate borrowings of $0.4 million and $2.5
million, respectively. For the six months ended June 30, 2002 and 2003, the
Company had net interest income related to affiliate borrowings of $0.3 million
and $2.4 million, respectively.
The 1935 Act generally prohibits borrowings by CenterPoint Energy from its
subsidiaries, including the Company, either through the money pool or otherwise.
In 2002, the Company supplied natural gas to Reliant Energy Services, Inc.
(Reliant Energy Services), a subsidiary of Reliant Resources, which was an
affiliate through September 30, 2002. For the three and six months
9
ended June 30, 2002, the sales and services by the Company to Reliant Resources
and its subsidiaries totaled $11 million and $25 million, respectively. For the
three and six months ended June 30, 2002, the sales and services by the Company
to CenterPoint Energy and its affiliates totaled $16 million and $17 million,
respectively. For the three and six months ended June 30, 2003, the sales and
services by the Company to CenterPoint Energy and its affiliates totaled $5
million and $10 million, respectively. Purchases of natural gas by the Company
from Reliant Resources and its subsidiaries were $51 million and $158 million
for the three and six months ended June 30, 2002, 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 $25 million
and $51 million for the three and six months ended June 30, 2002, respectively,
and $26 million and $57 million for the three and six months ended June 30,
2003, respectively, and are included primarily in operation and maintenance
expenses.
(9) ENVIRONMENTAL MATTERS AND LEGAL PROCEEDINGS
(a) Environmental Matters.
Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are
among numerous defendants in class action suits 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." 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 the Company believes were neither owned nor operated by the Company, and
for which it believes it has no liability.
At June 30, 2003, the Company had accrued $19 million for remediation of
the Minnesota sites. At June 30, 2003, the estimated range of possible
remediation costs 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 $12.4 million at
June 30, 2003 to be used for future environmental remediation.
The Company has received notices from the United States Environmental
Protection Agency and others regarding its status as a PRP for sites in other
states. 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
10
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. Considering the information currently known about
such sites and the involvement of the Company in activities at these sites, the
Company does not believe that these matters will have a material adverse effect
on its financial position, results of operations or cash flows.
(b) Department of Transportation
In December 2002, Congress enacted the Pipeline Safety Improvement Act of
2002. This legislation applies to the Company's interstate pipelines as well as
its intra-state pipelines and local distribution companies. The legislation
imposes several requirements related to ensuring pipeline safety and integrity.
It requires companies to assess the integrity of their pipeline transmission and
distribution facilities in areas of high population concentration and further
requires companies to perform remediation activities, in accordance with the
requirements of the legislation, over a 10-year period.
In January 2003, the U.S. Department of Transportation published a notice
of proposed rulemaking to implement provisions of the legislation. The
Department of Transportation is expected to issue final rules by the end of
2003.
While the Company anticipates that increased capital and operating expenses
will be required to comply with the requirements of the legislation, it will not
be able to quantify the level of spending required until the Department of
Transportation's final rules are issued.
(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 a
class action filed in May 1999 against approximately 245 pipeline companies and
their affiliates. The plaintiffs in the case purport to represent a class of
natural gas producers and fee royalty owners who allege that they have been
subject to systematic gas mismeasurement by the defendants for more than 25
years. The plaintiffs seek compensatory damages, along with statutory penalties,
treble damages, interest, costs and fees. The action is currently pending in
state court in Stevens County, Kansas.
City of Tyler, Texas, Gas Costs Review. By letter to CenterPoint Energy
Entex (Entex) dated July 31, 2002, the City of Tyler, Texas, forwarded various
computations of what it believes to be excessive costs ranging from $2.8
11
million to $39.2 million for gas purchased by Entex for resale to residential
and small commercial customers in that city under supply agreements in effect
since 1992. Entex's gas costs for its Tyler system are recovered from customers
pursuant to tariffs approved by the city and filed with both the city and the
Railroad Commission of Texas (the Railroad Commission). Pursuant to an
agreement, on January 29, 2003, Entex and the city filed a Joint Petition for
Review of Charges for Gas Sales (Joint Petition) with the Railroad Commission.
The Joint Petition requests 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. 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 and that
the city has no legal or factual support for the statements made in its letter.
Gas Cost Recovery Suits. 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 Utility 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. The plaintiffs in
both cases seek restitution for the alleged overcharges, exemplary damages and
penalties. In both cases, the Company denies that it has overcharged any of its
customers for natural gas and believes that the amounts recovered for purchased
gas have been in accordance with what is permitted by state regulatory
authorities.
Other Proceedings. The Company is involved in other proceedings before
various courts, regulatory commissions and governmental agencies regarding
matters arising in the ordinary course of business. The Company's management
currently believes that the disposition of these matters will not have a
material adverse effect on the Company's financial position, 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's reportable business segments include the following: Natural
Gas Distribution, Pipelines and Gathering, and Other Operations. For
descriptions of the reportable business segments, see Note 13 to the CERC Corp.
8-K Notes, which is incorporated herein by reference.
In the second quarter of 2003, the Company began to evaluate business
segment performance on an operating income basis. Operating income is shown
because it is the measure currently used by the chief operating decision maker
to evaluate performance and allocate resources. Additionally, it is a widely
accepted measure of financial performance prepared in accordance with GAAP.
Prior to the second quarter of 2003, the Company evaluated performance on an
earnings before interest expense, distribution on trust preferred securities and
income taxes (EBIT) basis. Historically, the difference between EBIT and
operating income has not been material.
12
The following table summarizes financial data for the reportable business
segments:
<Table>
<Caption>
FOR THE THREE MONTHS ENDED JUNE 30, 2002
-----------------------------------------------
REVENUES FROM NET
THIRD PARTIES AND INTERSEGMENT OPERATING
AFFILIATES(1) REVENUES INCOME(LOSS)
----------------- ------------ ------------
(IN MILLIONS)
Natural Gas Distribution ..... $780 $ 17 $ 11
Pipelines and Gathering ...... 72 30 39
Other Operations ............. -- -- (2)
Sales to Affiliates .......... 16 -- --
Eliminations ................. -- (47) --
---- ---- ----
Consolidated ................. $868 $ -- $ 48
==== ==== ====
</Table>
<Table>
<Caption>
FOR THE THREE MONTHS ENDED JUNE 30, 2003
---------------------------------------------------
REVENUES FROM NET
THIRD PARTIES AND INTERSEGMENT OPERATING
AFFILIATES REVENUES INCOME
----------------- ------------ ---------
(IN MILLIONS)
Natural Gas Distribution .... $954 $ 17 $ 21
Pipelines and Gathering ..... 73 49 42
Other Operations ............ -- 4 4
Sales to Affiliates ......... 5 -- --
Eliminations ................ -- (70) --
------ ------ ----
Consolidated ................ $1,032 $ -- $ 67
====== ====== ====
</Table>
<Table>
<Caption>
AS OF
DECEMBER 31,
FOR THE SIX MONTHS ENDED JUNE 30, 2002 2002
--------------------------------------------------- ------------
REVENUES FROM NET
THIRD PARTIES AND INTERSEGMENT OPERATING
AFFILIATES(1) REVENUES INCOME(LOSS) TOTAL ASSETS
----------------- ------------ ------------ ------------
(IN MILLIONS)
Natural Gas Distribution ..... $1,960 $ 17 $ 118 $ 4,051
Pipelines and Gathering ...... 134 60 76 2,481
Other Operations ............. -- -- (2) 206
Sales to Affiliates .......... 17 -- -- --
Eliminations ................. -- (77) -- (694)
------- ------ ------ -------
Consolidated ................. $ 2,111 $ -- $ 192 $ 6,044
======= ====== ====== =======
</Table>
<Table>
<Caption>
AS OF
JUNE 30,
FOR THE SIX MONTHS ENDED JUNE 30, 2003 2003
------------------------------------------------ ------------
REVENUES FROM NET
THIRD PARTIES AND INTERSEGMENT OPERATING
AFFILIATES REVENUES INCOME TOTAL ASSETS
----------------- ------------ --------- ------------
(IN MILLIONS)
Natural Gas Distribution ....... $ 2,982 $ 33 $ 151 $ 4,169
Pipelines and Gathering ........ 134 97 85 2,458
Other Operations ............... -- 6 3 234
Sales to Affiliates ............ 10 -- -- --
Eliminations ................... -- (136) -- (899)
------- ------- ------- -------
Consolidated ................... $ 3,126 $ -- $ 239 $ 5,962
======= ======= ======= =======
</Table>
(1) Included in revenues from third parties are revenues from sales to
Reliant Resources, a former affiliate, of $11 million and $25 million
for the three and six months ended June 30, 2002.
13
Reconciliation of Operating Income to Net Income:
<Table>
<Caption>
FOR THE THREE MONTHS ENDED JUNE 30, FOR THE SIX MONTHS ENDED JUNE 30,
----------------------------------- ---------------------------------
2002 2003 2002 2003
----------- ----------- ----------- ---------
(IN MILLIONS)
Operating Income ............. $ 48 $ 67 $ 192 $ 239
Other Income, net ............ 4 2 6 3
Interest Expense ............. (38) (48) (74) (84)
----- ----- ----- -----
Income Before Income Taxes ... 14 21 124 158
Income Tax Expense ........... (6) (6) (47) (55)
----- ----- ----- -----
Net Income ................... $ 8 $ 15 $ 77 $ 103
===== ===== ===== =====
</Table>
14
ITEM 2. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
The following narrative analysis should be read in combination with our
interim financial statements and notes 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 (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 its subsidiaries. The 1935 Act, among other
things, limits the ability of the holding company and its subsidiaries to issue
debt and equity securities without prior authorization, restricts the source of
dividend payments to funds from current and retained earnings without prior
authorization, regulates sales and acquisitions of certain assets and businesses
and governs affiliate transactions. CenterPoint Energy and its subsidiaries,
including us, received an order from the Securities and Exchange Commission
(SEC) under the 1935 Act on June 30, 2003 (June 2003 Financing Order) relating
to financing and other activities, which is effective until June 30, 2005.
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 and Use of Proceeds), Item 3
(Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of
Security Holders). The following discussion explains material changes in the
amount of our revenue and expense items between the three months and six months
ended June 30, 2003 and the three months and six months ended June 30, 2002.
Reference is made to "Management's Narrative Analysis of the Results of
Operations" in Exhibit 99.1 to the Current Report on Form 8-K dated June 16,
2003 (June 16 Form 8-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 "Risk
Factors" in Item 5 of Part II of this report and "Management's Narrative
Analysis of the Results of Operations -- Certain Factors Affecting Future
Earnings" in Exhibit 99.1 to the June 16 Form 8-K, each of which is incorporated
herein by reference.
In the second quarter of 2003, we began to evaluate performance on an
operating income basis. Operating income is shown because it is the measure
currently used by the chief operating decision maker to evaluate performance and
allocate resources. Additionally, it is a widely accepted measure of financial
performance prepared in accordance with generally accepted accounting principles
in the United States of America (GAAP). Prior to the second quarter of 2003, we
evaluated performance on an earnings before interest expense, distribution on
trust preferred securities and income taxes (EBIT) basis. Historically, the
difference between EBIT and operating income has not been material.
The following table sets forth our consolidated results of operations for
the three and six months ended June 30, 2002 and 2003, 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.
15
<Table>
<Caption>
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- --------------------------
2002 2003 2002 2003
------- --------- -------- --------
(IN MILLIONS)
Operating Revenues ............................. $ 868 $ 1,032 $ 2,111 $ 3,126
------- ------- ------- -------
Operating Expenses:
Natural gas and fuel ........................ 583 736 1,445 2,391
Operation and maintenance ................... 165 162 330 340
Depreciation and amortization ............... 42 44 82 88
Taxes other than income taxes ............... 30 23 62 68
------- ------- ------- -------
Total Operating Expenses ............. 820 965 1,919 2,887
------- ------- ------- -------
Operating Income, net .......................... 48 67 192 239
Other Income, net .............................. 4 2 6 3
Interest Expense and Distribution on Trust
Preferred Securities ........................ (38) (48) (74) (84)
------- ------- ------- -------
Income Before Income Taxes ..................... 14 21 124 158
Income Tax Expense ............................. (6) (6) (47) (55)
------- ------- ------- -------
Net Income ................................... $ 8 $ 15 $ 77 $ 103
======= ======= ======= =======
</Table>
THREE MONTHS ENDED JUNE 30, 2003 COMPARED TO THREE MONTHS ENDED JUNE 30, 2002
For the three months ended June 30, 2003, operating income increased $19
million as compared to the same period in 2002. Operating margins (revenues less
natural gas and fuel costs) for the three months ended June 30, 2003 were $11
million higher than in the same period in 2002 primarily because of:
o higher revenues from rate increases late in 2002 ($9 million);
o improved margins from new transportation contracts to power plants ($4
million);
o improved margins from our unregulated commercial and industrial sales
($3 million);
o improved margins from enhanced services in our gas gathering
operations ($2 million);
o higher commodity prices ($2 million); and
o continued customer growth ($1 million).
These increases were partially offset by reduced project-related revenues
($10 million) and a one-time refund of a tax on fuel in 2002 ($3 million).
Operation and maintenance expense decreased $3 million for the three months
ended June 30, 2003 as compared to the same period in 2002. The decrease in
operation and maintenance expense was primarily due to a decrease in
project-related costs ($10 million) and a decrease in bad debt expense ($3
million), partially offset by:
o higher employee benefit expenses, primarily due to increased pension
costs ($8 million); and
o certain costs being included in operating expense subsequent to the
amendment of a receivables facility in November 2002 as compared with
being included in interest expense in the prior year ($3 million).
Depreciation and amortization expense increased $2 million for the three
months ended June 30, 2003 as compared to the same period in 2002 primarily as a
result of increases in plant in service.
Taxes other than income taxes decreased $7 million for the three months
ended June 30, 2003 as compared to the same period in 2002, primarily due to
decreased gross receipt taxes ($4 million).
16
SIX MONTHS ENDED JUNE 30, 2003 COMPARED TO SIX MONTHS ENDED JUNE 30, 2002
For the six months ended June 30, 2003, operating income increased $47
million as compared to the same period in 2002. Operating margins (revenues less
natural gas and fuel costs) for the six months ended June 30, 2003 were $69
million higher than in the same period in 2002 primarily because of:
o higher revenues from rate increases late in 2002 ($20 million);
o improved margins from our unregulated commercial and industrial sales
($12 million);
o franchise fees billed to customers ($7 million);
o higher commodity prices ($6 million);
o continued customer growth ($5 million);
o improved margins from new transportation contracts ($5 million);
o colder weather ($4 million); and
o improved margins from enhanced services in our gas gathering
operations ($3 million).
These increases were partially offset by reduced project-related revenues
($15 million) and a one-time refund of a tax on fuel in 2002 ($3 million).
Operation and maintenance expense increased $10 million for the six months
ended June 30, 2003 as compared to the same period in 2002. The increase in
operation and maintenance expense was primarily due to:
o higher employee benefit expenses primarily due to increased pension
costs ($12 million);
o certain costs being included in operating expense subsequent to the
amendment of a receivables facility in November 2002 as compared with
being included in interest expense in the prior year ($7 million); and
o increased bad debt expense primarily due to colder weather and higher
gas prices ($2 million).
The increases in operation and maintenance expense were partially offset by
a decrease in project-related costs ($15 million).
Depreciation and amortization expense increased $6 million for the six
months ended June 30, 2003 as compared to the same period in 2002 primarily as a
result of increases in plant in service.
Taxes other than income taxes increased $6 million for the six months ended
June 30, 2003 as compared to the same period in 2002, primarily due to increased
franchise fees resulting from higher revenue ($7 million).
LIQUIDITY
The June 2003 Financing Order limits the amount of external debt and equity
securities that we can issue without additional authorization and permits
refinancing. We are in compliance with these limits.
Under the June 2003 Financing Order, we are permitted to utilize the
undrawn portion of our bank facility as of June 30, 2003 as well as to issue an
additional $250 million of preferred stock and preferred securities.
17
The SEC has reserved jurisdiction over the issuance of $500 million
additional debt by us. We would need an additional order from the SEC for
authority to issue this debt.
Long-Term Debt and Trust Preferred Securities. Of the $2.3 billion of
long-term debt and trust preferred securities outstanding at June 30, 2003,
approximately $2.2 billion aggregate principal amount is senior and unsecured,
and approximately $77.4 million aggregate principal amount with a final maturity
of 2012 is subordinated and unsecured. In addition, the debentures relating to
$0.4 million of trust preferred securities issued by our statutory
business-trust subsidiary are subordinated.
The issuance of secured debt by us is limited under the terms of various
debt instruments aggregating $907 million and having a final maturity of 2013
which provide for equal and ratable security for such debt in the event debt
secured by "principal property" (as defined in the debt instruments) is issued.
Additionally, our $200 million credit agreement expiring in March 2004 prohibits
the issuance of debt secured by "principal property." The definition is similar
to that contained in the debt instruments described above. Finally, our ability
to issue secured debt is limited under the terms of agreements entered into by
CenterPoint Energy. Any pledge of assets as security for our debt is subject to
SEC approval under the 1935 Act. The June 2003 Financing Order allows us to
issue debt secured by a pledge of the stock of our nonutility subsidiaries.
In 2003, we completed several capital market and bank financing
transactions which, collectively, increased our borrowing capacity, converted a
portion of our interest payment obligations from floating rates to fixed rates
and reduced current maturities of long-term debt from $518 million at December
31, 2002 to $142 million at June 30, 2003.
On February 28, 2003, CenterPoint Energy reached agreement with a syndicate
of banks on a second amendment to its bank facility. The amendment provides that
net proceeds from capital stock or indebtedness issued or incurred by us must be
applied (subject to a $200 million basket for us and another $250 million basket
for borrowings by CenterPoint Energy, certain permitted refinancings of existing
debt and other limited exceptions) to repay bank loans and permanently reduce
the bank facility. Outstanding borrowings under our $200 million credit
facility (see Note 5(a)) would count against the $200 million basket for us. As
of June 30, 2003, this facility was not utilized. Cash proceeds from issuances
of indebtedness to refinance indebtedness existing on October 10, 2002 are not
subject to this limitation.
In March and April 2003, we issued $762 million aggregate principal amount
of our 7.875% senior notes due 2013, the proceeds from which were used to
refinance $360 million aggregate principal amount of our $500 million aggregate
principal amount of 6 3/8% Term Enhanced ReMarketable Securities (TERM Notes)
maturing in November 2003, pay the cost of terminating a remarketing option
relating to those securities and repay approximately $340 million of bank
borrowings bearing interest at 1.575% under our $350 million credit facility
having a termination date of March 31, 2003. We replaced the matured credit
facility with a new $200 million revolving credit facility that matures in March
2004.
Short-Term Debt and Receivables Facility. Our revolver and receivables
facility are scheduled to terminate on the dates indicated below.
<Table>
<Caption>
AMOUNT
OUTSTANDING
AMOUNT OF AS OF
TYPE OF FACILITY TERMINATION DATE FACILITY JUNE 30, 2003
---------------- ---------------- -------- -------------
(IN MILLIONS)
Receivables ... November 14, 2003 $100 $ 73
Revolver ...... March 23, 2004 200 --
---- ----
Total .... $300 $ 73
==== ====
</Table>
Rates for borrowings under the revolving credit facility, including the
facility fee, are LIBOR plus 250 basis points based on current credit ratings
and the applicable pricing grid.
Effective June 25, 2003, we elected to reduce the purchase limit under our
receivables facility from $150 million to $100 million. The bankruptcy remote
subsidiary established to purchase and subsequently sell receivables makes such
purchases with a combination of cash and subordinated notes. In July 2003, the
subordinated notes owned by us were pledged to a gas supplier to secure
obligations incurred in connection with the purchase of gas by us.
18
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 with the June 2003 Financing Order. The money pool may
not provide sufficient funds to meet our cash needs. Our money pool borrowing
limit under the June 2003 Financing Order is $600 million. At June 30, 2003, we
had invested $61.5 million in the money pool.
Cash Requirements in 2003. Our liquidity and capital requirements are
affected primarily by our results of operations, capital expenditures, debt
service requirements, and working capital needs. Our principal cash requirements
during the last six months of 2003 include the following:
o approximately $152 million of capital expenditures; and
o remarketing or refinancing of $140 million of TERM Notes, plus the
possible payment of option termination costs, which will be determined
at the time of remarketing or refinancing (estimated to be $23 million
as of June 30, 2003).
We expect that our current liquidity, along with anticipated cash flows
from operations, revolving credit borrowings and proceeds from capital market
transactions, will be sufficient to meet our cash needs for the remainder of
2003. If we are unable to obtain external financings to meet our future capital
requirements on terms that are acceptable to us, our financial condition and
future results of operations could be materially and adversely affected. In
addition, the capital constraints currently impacting our businesses may require
our future indebtedness to include terms that are more restrictive or burdensome
than those of our current indebtedness. Such terms may negatively impact our
ability to operate our business or may restrict dividends.
At June 30, 2003, we had a shelf registration statement covering $50
million of debt securities. The amount of any debt security or any security
having equity characteristics that we can issue, whether registered or
unregistered, or whether debt is secured or unsecured, is expected to be
affected by:
o general economic and capital market conditions;
o credit availability from financial institutions and other lenders;
o investor confidence in us and the market in which we operate;
o maintenance of acceptable credit ratings;
o market expectations regarding our future earnings and probable cash
flows;
o market perceptions of our ability to access capital markets on
reasonable terms;
o provisions of relevant tax and securities laws; and
o our ability to obtain approval of specific financing transactions
under the 1935 Act.
Proceeds from the sales of securities are expected to be used primarily to
refinance debt. We may access the bank and capital markets to refinance debt
that is not scheduled to mature in the next twelve months.
Impact on Liquidity of a Downgrade in Credit Ratings. As of July 31, 2003,
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:
19
<Table>
<Caption>
MOODY'S S&P FITCH
---------------------- -------------------- --------------------
RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3)
------ ---------- ------ ---------- ------ ----------
Ba1 Negative BBB Stable BBB Stable
</Table>
- ----------
(1) A "negative" outlook from Moody's reflects concerns over the next 12
to 18 months which will either lead to a review for a potential
downgrade or a return to a stable outlook.
(2) A "stable" outlook from S&P indicates that the rating is not likely to
change over the intermediate to longer term.
(3) A "stable" outlook from Fitch indicates the direction a rating is
likely to move over a one- to two-year period.
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 facility fees and borrowing
costs under our existing 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.
Our bank facility contains a "material adverse change" clause that could
impact our ability to borrow under this facility. The "material adverse change"
clause in our revolving credit facility applies to new borrowings under the
facility, other than borrowings being used to repay commercial paper, and
relates to changes since December 31, 2002 in our business, condition (financial
or otherwise), operations, performance or properties.
Our $100 million receivables facility requires the maintenance of credit
ratings of at least BB from S&P and Ba2 from Moody's. Receivables would cease to
be sold in the event a credit rating fell below the threshold.
CenterPoint Energy Gas Resources Corp., a wholly owned subsidiary, provides
comprehensive natural gas sales and services to industrial and commercial
customers that 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, CenterPoint Energy Gas Resources Corp. has
agreements with provisions standard for the industry that establish credit
thresholds and then require a party to provide additional collateral on two
business days' notice when that party's credit rating or the rating of a credit
support provider for that party (CenterPoint Energy Resources Corp. in this
case) falls below those levels. As of July 31, 2003, our senior unsecured debt
was rated BBB by S&P and Ba1 by Moody's. Based on these ratings, we estimate
that unsecured credit limits extended to CenterPoint Energy Gas Resources Corp.
by counterparties could aggregate $50 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. A payment default
on, or a non-payment default that permits acceleration of, any indebtedness at
CenterPoint Energy Resources Corp. exceeding $50 million will cause a default
under CenterPoint Energy's $2.85 billion bank facility entered into on February
28, 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 CenterPoint Energy's
3.75% senior convertible notes due 2023, its 5.875% senior notes due 2008 and
its 6.85% senior notes due 2015.
Pension Plan. As discussed in Note 8(a) of the notes to the consolidated
financial statements included in Exhibit 99.2 to the June 16 Form 8-K (CERC
Corp. 8-K Notes), which is incorporated herein by reference, we
20
participate in CenterPoint Energy's qualified non-contributory pension plan
covering substantially all employees. Pension expense for 2003 is estimated to
be $36 million based on an expected return on plan assets of 9.0% and a discount
rate of 6.75% as of December 31, 2002. Pension expense for the year ended
December 31, 2002 was $13 million. 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:
o cash collateral requirements that could exist in connection with
certain contracts, including our gas purchases, gas price hedging and
gas storage activities of our Natural Gas Distribution business
segment, particularly given gas price levels and volatility;
o acceleration of payment dates on certain gas supply contracts under
certain circumstances, as a result of increased gas prices and
concentration of suppliers;
o increased costs related to the acquisition of gas for storage;
o increases in interest expense in connection with debt refinancings;
and
o various regulatory actions.
Capitalization. Factors affecting our capitalization include:
o covenants and other provisions in our bank facility, receivables
facility and other borrowing agreements; and
o 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.
Our bank facility contains a provision that could, under certain circumstances,
limit the amount of dividends that could be paid by us.
The June 2003 Financing Order requires that if we 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 ours and of CenterPoint Energy must be so rated by at least one NRSRO. The
June 2003 Financing Order also contains certain requirements for interest rates,
maturities, issuance expenses and use of proceeds. Under the June 2003 Financing
Order, our common equity as a percentage of total capitalization must be 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
21
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. We
believe the following accounting policies involve the application of critical
accounting estimates.
IMPAIRMENT OF LONG-LIVED ASSETS
Long-lived assets recorded in our Consolidated Balance Sheets primarily
consist of property, plant and equipment (PP&E). Net PP&E comprises $3.3 billion
or 55% of our total assets as of June 30, 2003. We make judgments and estimates
in conjunction with the carrying value of these assets, including amounts to be
capitalized, depreciation and amortization methods and useful lives. We evaluate
our PP&E for impairment whenever indicators of impairment exist. During 2002, no
such indicators of impairment existed. Accounting standards require that if the
sum of the undiscounted expected future cash flows from a company's asset is
less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. The amount of impairment recognized is
calculated by subtracting the fair value of the asset from the carrying value of
the asset.
IMPAIRMENT OF GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS
We evaluate our goodwill and other indefinite-lived intangible assets for
impairment at least annually and more frequently when indicators of impairment
exist. Accounting standards require that if the fair value of a reporting unit
is less than its carrying value, including goodwill, a charge for impairment of
goodwill must be recognized. To measure the amount of the impairment loss, we
compare the implied fair value of the reporting unit's goodwill with its
carrying value.
We recorded goodwill associated with the acquisition of our Natural Gas
Distribution and Pipelines and Gathering operations in 1997. We reviewed our
goodwill for impairment as of January 1, 2003. We computed the fair value of the
Natural Gas Distribution and the Pipelines and Gathering operations as the sum
of the discounted estimated net future cash flows applicable to each of these
operations. We determined that the fair value for each of the Natural Gas
Distribution operations and the Pipelines and Gathering operations exceeded
their corresponding carrying value, including unallocated goodwill. We also
concluded that no interim impairment indicators existed subsequent to this
initial evaluation. As of June 30, 2003, we had recorded $1.7 billion of
goodwill. Future evaluations of the carrying value of goodwill could be
significantly impacted by our estimates of cash flows associated with our
Natural Gas Distribution and Pipelines and Gathering operations, regulatory
matters, and estimated operating costs.
UNBILLED REVENUES
Revenues related to the sale and/or delivery of natural gas are generally
recorded when natural gas is delivered to customers. However, the determination
of sales to individual customers is based on the reading of their meters, which
is performed on a systematic basis throughout the month. At the end of each
month, amounts of natural gas delivered to customers since the date of the last
meter reading are estimated and the corresponding unbilled revenue is estimated.
Unbilled natural gas sales are estimated based on estimated purchased gas
volumes, estimated lost and unaccounted for gas and tariffed rates in effect.
Accrued unbilled revenues recorded in the Consolidated Balance Sheets as of
December 31, 2002 and June 30, 2003 were $284 million and $135 million,
respectively, related to our Natural Gas Distribution business segment.
NEW ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2003, we adopted Statement of Financial Accounting
Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations" (SFAS
No. 143). SFAS No. 143 requires the fair value of an asset retirement obligation
to be recognized as a liability is incurred and capitalized as part of the cost
of the related tangible long-lived assets. Over time, the liability is accreted
to its present value each period, and the capitalized cost is depreciated over
the useful life of the related asset. Retirement obligations associated with
long-lived assets included within the scope of SFAS No. 143 are those for which
a legal obligation exists under enacted laws, statutes and written or oral
contracts, including obligations arising under the doctrine of promissory
estoppel. SFAS No. 143 is effective for fiscal years beginning after June 15,
2002. SFAS No. 143 requires entities to record a cumulative effect of change in
accounting principle in the income statement in the period of adoption.
22
We have identified no asset retirement obligations. Our rate-regulated
businesses have previously recognized removal costs as a component of
depreciation expense in accordance with regulatory treatment. As of June 30,
2003, these previously recognized removal costs of $391 million do not represent
SFAS No. 143 asset retirement obligations, but rather embedded regulatory
liabilities.
In April 2002, the Financial Accounting Standards Board (FASB) issued SFAS
No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB
Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145
eliminates the current requirement that gains and losses on debt extinguishment
must be classified as extraordinary items in the income statement. Instead, such
gains and losses will be classified as extraordinary items only if they are
deemed to be unusual and infrequent. SFAS No. 145 also requires that capital
leases that are modified so that the resulting lease agreement is classified as
an operating lease be accounted for as a sale-leaseback transaction. The changes
related to debt extinguishment are effective for fiscal years beginning after
May 15, 2002, and the changes related to lease accounting are effective for
transactions occurring after May 15, 2002. We have applied this guidance as it
relates to lease accounting and the accounting provisions related to debt
extinguishment. Upon adoption of SFAS No. 145, any gain or loss on
extinguishment of debt that was classified as an extraordinary item in prior
periods is required to be reclassified. No such reclassification was required
in the three month or six month period ended June 30, 2002.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)" (EITF No. 94-3).
The principal difference between SFAS No. 146 and EITF No. 94-3 relates to the
requirements for recognition of a liability for costs associated with an exit or
disposal activity. SFAS No. 146 requires that a liability be recognized for a
cost associated with an exit or disposal activity when it is incurred. A
liability is incurred when a transaction or event occurs that leaves an entity
little or no discretion to avoid the future transfer or use of assets to settle
the liability. Under EITF No. 94-3, a liability for an exit cost was recognized
at the date of an entity's commitment to an exit plan. In addition, SFAS No. 146
also requires that a liability for a cost associated with an exit or disposal
activity be recognized at its fair value when it is incurred. SFAS No. 146 is
effective for exit or disposal activities that are initiated after December 31,
2002. We adopted the provisions of SFAS No. 146 on January 1, 2003.
In June 2002, the EITF reached a consensus on EITF No. 02-03, "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF No.
02-3) that all mark-to-market gains and losses on energy trading contracts
should be shown net in the income statement whether or not settled physically.
An entity should disclose the gross transaction volumes for those energy-trading
contracts that are physically settled. The EITF did not reach a consensus on
whether recognition of dealer profit, or unrealized gains and losses at
inception of an energy-trading contract, is appropriate in the absence of quoted
market prices or current market transactions for contracts with similar terms.
The FASB staff indicated that until such time as a consensus is reached, the
FASB staff will continue to hold the view that previous EITF consensus do not
allow for recognition of dealer profit, unless evidenced by quoted market prices
or other current market transactions for energy trading contracts with similar
terms and counterparties. The consensus on presenting gains and losses on energy
trading contracts net is effective for financial statements issued for periods
ending after July 15, 2002. Upon application of the consensus, comparative
financial statements for prior periods should be reclassified to conform to the
consensus. Our adoption of EITF No. 02-03 on January 1, 2003 only impacted the
year ended December 31, 2000 and had no effect on our interim financial
statements.
In November 2002, the FASB issued FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 requires that a
liability be recorded in the guarantor's balance sheet upon issuance of certain
guarantees. In addition, FIN 45 requires disclosures about the guarantees that
an entity has issued. The provision for initial recognition and measurement of
the liability will be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure provisions of FIN 45 are
effective for financial statements of interim or annual periods ending after
December 15, 2002. The adoption of FIN 45 did not materially affect our
consolidated financial statements.
In January 2003, the FASB issued 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
23
additional subordinated financial support from other parties. FIN 46 is
effective for all new variable interest entities created or acquired after
January 31, 2003. For variable interest entities created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period beginning after June 15, 2003. We are currently assessing the
impact that this statement will have on our consolidated financial statements.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS No. 149). SFAS No. 149
clarifies when a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133 and when a
derivative contains a financing component. SFAS No. 149 also amends certain
existing pronouncements, which will result in more consistent reporting of
contracts as either derivative or hybrid instruments. SFAS No. 149 is effective
for contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003, and should be applied
prospectively. Certain paragraphs of this statement that relate to forward
purchases or sales of when-issued securities or other securities that do not yet
exist should be applied to both existing contracts and new contracts entered
into after June 30, 2003. The provisions of this statement that relate to SFAS
No. 133 implementation issues that have been effective for fiscal quarters that
began prior to June 15, 2003 should continue to be applied in accordance with
their respective effective dates. The adoption of SFAS No. 149 will not have a
material effect on our consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS
No. 150). SFAS No. 150 establishes standards for how an issuer classifies and
measures certain financial instruments with characteristics of both liabilities
and equity. It requires that an issuer classify a financial instrument that is
within its scope as a liability (or an asset in some circumstances). Many of
those instruments were previously classified as equity. SFAS No. 150 is
effective for financial instruments entered into or modified after May 31, 2003
and otherwise is effective at the beginning of the first interim period
beginning after June 15, 2003. It is to be implemented by reporting the
cumulative effect of a change in an accounting principle with no restatement of
prior period information permitted. We are currently assessing the impact that
this statement will have on our consolidated financial statements.
ITEM 4. CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our principal executive officer and principal financial officer, of
the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls
and procedures were effective as of June 30, 2003 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 June 30, 2003 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
24
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
For a description of certain legal and regulatory proceedings affecting us,
please review Note 9 to our Interim Financial Statements, "Business --
Regulation" and "Business -- Environmental Matters" in Item 1 of the Annual
Report on Form 10-K of CERC Corp. (CERC Corp. 10-K) for the year ended December
3, 2002, "Legal Proceedings" in Item 3 of the CERC Corp. 10-K and Notes 10(c)
and (d) to the CERC Corp. 8-K Notes, all of which are incorporated herein by
reference.
ITEM 5. OTHER INFORMATION.
RISK FACTORS
PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES
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 consumers 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 INTERSTATE
PIPELINES' CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON OUR OPERATIONS.
Contracts with two of our interstate pipelines' significant customers,
CenterPoint Energy Arkla and LaClede Gas Company, 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
25
provided in the current contracts, it could have an adverse effect on our
results of operations, financial condition and cash flows.
OUR INTERSTATE PIPELINES 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 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.
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 FINANCE EXISTING
INDEBTEDNESS COULD BE LIMITED.
As of June 30, 2003, we had $2.3 billion of outstanding indebtedness and
trust preferred securities, including approximately $140 million of debt that
must be refinanced in 2003. 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:
o general economic and capital market conditions,
o credit availability from financial institutions and other lenders,
o investor confidence in us and the market in which we operate,
o maintenance of acceptable credit ratings,
o market expectations regarding our future earnings and probable cash
flows,
o market perceptions of our ability to access capital markets on
reasonable terms,
o our exposure to Reliant Resources in connection with its
indemnification obligations arising in connection with its separation
from CenterPoint Energy,
o provisions of relevant tax and securities laws, and
o our ability to obtain approval of financing transactions under the
1935 Act.
Our current credit ratings are discussed in "Management's Narrative
Analysis of the Results of Operations of CenterPoint Energy Resources Corp. and
Subsidiaries -- Liquidity -- Impact on Liquidity of a Downgrade in Credit
Ratings" in Item 2 of Part I 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.
26
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 $153 million of debt, including capital leases, required to be
paid in 2003. 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:
o our payment of dividends;
o decisions on our financings and our capital raising activities;
o mergers or other business combinations; and
o 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 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 subsidiaries to issue debt and
equity securities without prior authorization, restricts the source of dividend
payments to funds from retained earnings absent specific authorization,
regulates sales and acquisitions of certain assets and businesses and governs
affiliate transactions. Approval of filings under the 1935 Act can take extended
periods.
CenterPoint Energy and its subsidiaries, including us, received an order
from the SEC under the 1935 Act on June 30, 2003 relating to financing
activities, which is effective until June 30, 2005. We 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.
The United States Congress is currently considering legislation which 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 effect 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 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. The
costs of our insurance coverage have increased significantly in recent months
and may continue to increase in the future.
27
OUR REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO RISKS THAT ARE BEYOND
OUR CONTROL, INCLUDING BUT NOT LIMITED TO FUTURE TERRORIST ATTACKS OR
RELATED ACTS OF WAR.
The cost of repairing damage to our operating subsidiaries' facilities due
to storms, natural disasters, wars, terrorist acts and other catastrophic
events, in excess of reserves established for such repairs, may adversely impact
our results of operations, financial condition and cash flows. The occurrence or
risk of occurrence of future terrorist activity may impact our results of
operations, financial condition and cash flows in unpredictable ways. These
actions could also result in adverse changes in the insurance markets and
disruptions of power and fuel markets. In addition, our natural gas distribution
and pipeline and gathering facilities could be directly or indirectly harmed by
future terrorist activity. The occurrence or risk of occurrence of future
terrorist attacks or related acts of war could also adversely affect the United
States economy. A lower level of economic activity could result in a decline in
energy consumption, which could adversely affect our revenues and margins and
limit our future growth prospects. Also, these risks could cause instability in
the financial markets and adversely affect our ability to access capital.
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.
<Table>
<Caption>
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
- ---------- ---------------------------------------------- ------------------------------------- -------------- -----------
3(a)(1) - Certificate of Incorporation of RERC Form 10-K for the year ended December 1-3187 3(a)(1)
Corp. 31, 1997
3(a)(2) - Certificate of Merger merging former Form 10-K for the year ended December 1-3187 3(a)(2)
NorAm Energy Corp. with and into HI 31, 1997
Merger, Inc. dated August 6, 1997
3(a)(3) - Certificate of Amendment changing the Form 10-K for the year ended December 1-3187 3(a)(3)
name to Reliant Energy Resources Corp. 31, 1998
+3(a)(4) - Certificate of Amendment changing the
name to CenterPoint Energy Resources
Corp.
3(b) - Bylaws of RERC Corp. Form 10-K for the year ended December 1-3187 3(b)
31, 1997
4(a) - Indenture, dated as of February 1, 1998, Form 8-K dated February 5, 1998 1-13265 4.1
between RERC Corp. and Chase Bank of
Texas, National Association, as Trustee
4(b) - Supplemental Indenture No. 1 to Exhibit Form 8-K dated February 5, 1998 1-13265 4.2
4(a), dated as of February 1, 1998,
providing for the issuance of RERC
Corp.'s 6 1/2% Debentures due February
1, 2008
4(c) - Supplemental Indenture No. 2 to Exhibit Form 8-K dated November 9, 1998 1-13265 4.1
4(a), dated as of November 1, 1998,
providing for the issuance of RERC
Corp.'s 6 3/8% Term Enhanced
ReMarketable Securities
4(d) - Supplemental Indenture No. 3 to Exhibit Registration Statement on Form S-4 333-49162 4.2
4(a), dated as of July 1, 2000,
providing for the issuance of RERC
Corp.'s 8.125% Notes due 2005
4(e) - Supplemental Indenture No. 4 to Exhibit Form 8-K dated February 21, 2001 1-13265 4.1
4(a), dated as of February 15, 2001,
providing for the issuance of RERC
Corp.'s 7.75% Notes due 2011
</Table>
28
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
- ---------- ---------------------------------------------- ------------------------------------- -------------- -----------
4(f) - Supplemental Indenture No. 5 to Exhibit Form 8-K dated March 18, 2003 1-3187 4.1
4(a), dated as of March 25, 2003,
providing for the issuance of CERC
Corp.'s 7.75% Senior Notes due 2013
4(g) - Supplemental Indenture No. 6 to Exhibit Form 8-K dated April 7, 2003 1-3187 4.2
4(a), dated as of April 14, 2003,
providing for the issuance of additional
CERC Corp. 7.875% Senior Notes due 2013
+4(h) - Registration Rights Agreement, dated as
of March 25, 2003, among CERC Corp. and
the initial purchasers named therein
relating to CERC Corp.'s 7.875% Senior
Notes due 2013
+4(i) - Registration Rights Agreement, dated as
of April 14, 2003, among CERC Corp. and
the initial purchasers named therein
relating to CERC Corp.'s 7.875% Senior
Notes due 2013
+31(a) - Section 302 Certification of David M.
McClanahan
+31(b) - Section 302 Certification of Gary L.
Whitlock
+32(a) - Section 906 Certification of David M.
McClanahan
+32(b) - Section 906 Certification of Gary L.
Whitlock
+99(a) - Items incorporated by reference from
the CERC Corp. Form 10-K.
Item 1 "Business -- Regulation" and
"Business -- Environmental Matters"
and Item 3 "Legal Proceedings."
+99(b) - Items incorporated by reference from
the Current Report on Form 8-K dated
June 16, 2003. Exhibit 99.1 "Management's
Narrative Analysis of the Results of
Operations -- Certain Factors Affecting
Future Earnings" and the following Notes
from Exhibit 99.2: 3(e) (Regulatory
Matters), 5 (Derivative Instruments),
7 (Trust Preferred Securities),
8(a) (Pension Plans), 10 (Commitments
and Contingencies) and 13 (Reportable
Segments).
</Table>
(b) Reports on Form 8-K.
On April 8, 2003, we filed a Current Report on Form 8-K dated April 8,
2003, to furnish information under Item 9 of that form regarding our external
debt balances as of March 31, 2003.
On May 1, 2003, we filed a Current Report on Form 8-K dated April 7, 2003,
announcing the pricing and closing of $112 million of senior notes which will be
added to and form a single series with our prior existing 7.875% senior notes
due on April 1, 2013, in a private placement with institutions pursuant to Rule
144A under the Securities Act of 1933, as amended.
29
On June 16, 2003, we filed a Current Report on Form 8-K dated June 16,
2003, to provide information giving effect to a reclassification within our
historical consolidated financial statements and Management's Narrative Analysis
of Results of Operations as reported in our Annual Report on Form 10-K for the
year ended December 31, 2002.
30
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CENTERPOINT ENERGY RESOURCES CORP.
By: /s/ James S. Brian
--------------------------------------------
James S. Brian
Senior Vice President and Chief Accounting Officer
Date: August 13, 2003
31
INDEX TO 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.
<Table>
<Caption>
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
- ---------- ---------------------------------------------- ------------------------------------- -------------- -----------
3(a)(1) - Certificate of Incorporation of RERC Form 10-K for the year ended December 1-3187 3(a)(1)
Corp. 31, 1997
3(a)(2) - Certificate of Merger merging former Form 10-K for the year ended December 1-3187 3(a)(2)
NorAm Energy Corp. with and into HI 31, 1997
Merger, Inc. dated August 6, 1997
3(a)(3) - Certificate of Amendment changing the Form 10-K for the year ended December 1-3187 3(a)(3)
name to Reliant Energy Resources Corp. 31, 1998
+3(a)(4) - Certificate of Amendment changing the
name to CenterPoint Energy Resources
Corp.
3(b) - Bylaws of RERC Corp. Form 10-K for the year ended December 1-3187 3(b)
31, 1997
4(a) - Indenture, dated as of February 1, 1998, Form 8-K dated February 5, 1998 1-13265 4.1
between RERC Corp. and Chase Bank of
Texas, National Association, as Trustee
4(b) - Supplemental Indenture No. 1 to Exhibit Form 8-K dated February 5, 1998 1-13265 4.2
4(a), dated as of February 1, 1998,
providing for the issuance of RERC
Corp.'s 6 1/2% Debentures due February
1, 2008
4(c) - Supplemental Indenture No. 2 to Exhibit Form 8-K dated November 9, 1998 1-13265 4.1
4(a), dated as of November 1, 1998,
providing for the issuance of RERC
Corp.'s 6 3/8% Term Enhanced
ReMarketable Securities
4(d) - Supplemental Indenture No. 3 to Exhibit Registration Statement on Form S-4 333-49162 4.2
4(a), dated as of July 1, 2000,
providing for the issuance of RERC
Corp.'s 8.125% Notes due 2005
4(e) - Supplemental Indenture No. 4 to Exhibit Form 8-K dated February 21, 2001 1-13265 4.1
4(a), dated as of February 15, 2001,
providing for the issuance of RERC
Corp.'s 7.75% Notes due 2011
4(f) - Supplemental Indenture No. 5 to Exhibit Form 8-K dated March 18, 2003 1-3187 4.1
4(a), dated as of March 25, 2003,
providing for the issuance of CERC
Corp.'s 7.75% Senior Notes due 2013
4(g) - Supplemental Indenture No. 6 to Exhibit Form 8-K dated April 7, 2003 1-3187 4.2
4(a), dated as of April 14, 2003,
providing for the issuance of additional
CERC Corp. 7.875% Senior Notes due 2013
</Table>
<Table>
<Caption>
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
- ---------- -------------------------------------------------------------------- ------------ ------------ ---------
+4(h) - Registration Rights Agreement, dated as of March 25, 2003,
among CERC Corp. and the initial purchasers named therein
relating to CERC Corp.'s 7.875% Senior
Notes due 2013
+4(i) - Registration Rights Agreement, dated as of April 14, 2003,
among CERC Corp. and the initial purchasers named therein
relating to CERC Corp.'s 7.875% Senior
Notes due 2013
+31(a) - Section 302 Certification of David M. McClanahan
+31(b) - Section 302 Certification of Gary L. Whitlock
+32(a) - Section 906 Certification of David M. McClanahan
+32(b) - Section 906 Certification of Gary L. Whitlock
+99(a) - Items incorporated by reference from the CERC Corp. Form 10-K.
Item 1 "Business -- Regulation" and "Business -- Environmental
Matters" and Item 3 "Legal Proceedings."
+99(b) - Items incorporated by reference from the Current Report on
Form 8-K dated June 16, 2003. Exhibit 99.1 "Management's
Narrative Analysis of the Results of Operations -- Certain
Factors Affecting Future Earnings" and the following Notes
from Exhibit 99.2: 3(e) (Regulatory Matters), 5 (Derivative
Instruments), 7 (Trust Preferred Securities), 8(a) (Pension
Plans), 10 (Commitments and Contingencies) and 13 (Reportable
Segments).
</Table>