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 1-31447
CENTERPOINT ENERGY, INC.
(Exact name of registrant as specified in its charter)
TEXAS 74-0694415
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1111 LOUISIANA
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
(713) 207-1111
(Registrant's telephone number, including area code)
----------------------------
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
As of August 4, 2003, CenterPoint Energy, Inc. had 305,773,503 shares of common
stock outstanding, including 838,177 ESOP shares not deemed outstanding for
financial statement purposes and excluding 166 shares held as treasury stock.
CENTERPOINT ENERGY, INC.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2003
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.................................................................1
Statements of Consolidated Income
Three Months 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 Discussion and Analysis of Financial Condition and Results of
Operations of CenterPoint Energy and Subsidiaries.......................................31
Item 3. Quantitative and Qualitative Disclosures about Market Risk..........................56
Item 4. Controls and Procedures.............................................................57
PART II. OTHER INFORMATION
Item 1. Legal Proceedings...................................................................58
Item 2. Changes in Securities and Use of Proceeds...........................................58
Item 4. Submission of Matters to a Vote of Security Holders.................................58
Item 5. Other Information...................................................................59
Item 6. Exhibits and Reports on Form 8-K....................................................71
i
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
From time to time, we make statements concerning our expectations, beliefs,
plans, objectives, goals, strategies, future events or performance and
underlying assumptions and other statements, that are not historical facts.
These statements are "forward-looking statements" within the meaning of the
Private Securities Litigation Reform Act of 1995. Actual results may differ
materially from those expressed or implied by these statements. You can
generally identify our forward-looking statements by the words "anticipate,"
"believe," "continue," "could," "estimate," "expect," "forecast," "goal,"
"intend," "may," "objective," "plan," "potential," "predict," "projection,"
"should," "will," or other similar words.
We have based our forward-looking statements on our management's beliefs
and assumptions based on information available to our management at the time the
statements are made. We caution you that assumptions, beliefs, expectations,
intentions and projections about future events may and often do vary materially
from actual results. Therefore, we cannot assure you that actual results will
not differ materially from those expressed or implied by our forward-looking
statements.
The following are some of the factors that could cause actual results to
differ materially from those expressed or implied in forward-looking statements:
- state and federal legislative and regulatory actions or developments,
including deregulation, re-regulation and restructuring of the
electric utility industry, constraints placed on our activities or
business by the Public Utility Holding Company Act of 1935, as amended
(1935 Act), changes in or application of laws or regulations
applicable to other aspects of our business and actions with respect
to:
- recovery of stranded costs;
- allowed rates of return;
- rate structures;
- recovery of investments; and
- operation and construction of facilities;
- non-payment for our services due to financial distress of our
customers, including Reliant Resources, Inc. (Reliant Resources);
- the successful and timely completion of our capital projects;
- industrial, commercial and residential growth in our service territory
and changes in market demand and demographic patterns;
- changes in business strategy or development plans;
- the timing and extent of changes in commodity prices, particularly
natural gas;
- changes in interest rates or rates of inflation;
- unanticipated changes in operating expenses and capital expenditures;
- weather variations and other natural phenomena;
- commercial bank and financial market conditions, our access to
capital, the cost of such capital, receipt of certain approvals under
the 1935 Act, and the results of our financing and refinancing
efforts, including availability of funds in the debt capital markets;
- actions by rating agencies;
- legal and administrative proceedings and settlements;
- changes in tax laws;
ii
- inability of various counterparties to meet their obligations with
respect to our financial instruments;
- any lack of effectiveness of our disclosure controls and procedures;
- changes in technology;
- 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;
- significant changes in critical accounting policies;
- 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;
- the availability and price of insurance;
- the outcome of the pending lawsuits against us, Reliant Energy,
Incorporated and Reliant Resources;
- the ability of Reliant Resources to satisfy its indemnity obligations
to us;
- the reliability of the systems, procedures and other infrastructure
necessary to operate the retail electric business in our service
territory, including the systems owned and operated by the independent
system operator in the market served by the Electric Reliability
Council of Texas, Inc.;
- political, legal, regulatory and economic conditions and developments
in the United States; and
- other factors we discuss in this report including those outlined in
Item 5 of 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, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------------- -----------------------------
2002 2003 2002 2003
----------- ----------- ----------- -----------
REVENUES ...................................................... $ 1,798,424 $ 2,090,900 $ 3,875,814 $ 4,991,068
----------- ----------- ----------- -----------
EXPENSES:
Fuel and cost of gas sold ................................... 862,058 1,080,857 1,904,620 2,940,003
Purchased power ............................................. 4,258 22,974 52,624 34,968
Operation and maintenance ................................... 372,505 393,085 760,467 805,961
Depreciation and amortization ............................... 151,072 157,263 299,481 309,544
Taxes other than income taxes ............................... 119,134 90,691 217,285 193,535
----------- ----------- ----------- -----------
Total ................................................... 1,509,027 1,744,870 3,234,477 4,284,011
----------- ----------- ----------- -----------
OPERATING INCOME .............................................. 289,397 346,030 641,337 707,057
----------- ----------- ----------- -----------
OTHER INCOME (EXPENSE):
Gain (loss) on AOL Time Warner investment ................... (230,214) 113,178 (447,811) 64,704
Gain (loss) on indexed debt securities ...................... 218,723 (98,253) 421,956 (55,550)
Interest expense ............................................ (139,847) (215,087) (257,599) (439,081)
Distribution on trust preferred securities .................. (13,850) (13,899) (27,749) (27,797)
Other, net .................................................. 7,664 1,629 14,788 4,788
----------- ----------- ----------- -----------
Total ................................................... (157,524) (212,432) (296,415) (452,936)
----------- ----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES,
MINORITY INTEREST AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE 131,873 133,598 344,922 254,121
Income Tax Expense .......................................... (45,744) (44,346) (113,914) (85,455)
Minority Interest ........................................... (7) (6,295) 4 (4,229)
----------- ----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE ........................................... 86,122 82,957 231,012 164,437
Discontinued Operations:
Income from Reliant Resources, net of tax ................. 147,849 -- 34,450 --
Income (loss) from Other Operations, net of tax ........... 1,674 (403) 1,788 (865)
Loss on disposal of Other Operations, net of tax .......... -- (19,331) -- (11,989)
Cumulative Effect of Accounting Change, net of minority
interest and tax .......................................... -- -- -- 80,072
----------- ----------- ----------- -----------
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS ................ $ 235,645 $ 63,223 $ 267,250 $ 231,655
=========== =========== =========== ===========
BASIC EARNINGS PER SHARE:
Income from Continuing Operations before Cumulative Effect of
Accounting Change ......................................... $ 0.29 $ 0.27 $ 0.78 $ 0.54
Discontinued Operations:
Income from Reliant Resources, net of tax ................. 0.49 -- 0.11 --
Income (loss) from Other Operations, net of tax ........... 0.01 -- 0.01 --
Loss on disposal of Other Operations, net of tax .......... -- (0.06) -- (0.04)
Cumulative Effect of Accounting Change, net of minority
interest and tax ............................................ -- -- -- 0.27
----------- ----------- ----------- -----------
Net Income Attributable to Common Shareholders .............. $ 0.79 $ 0.21 $ 0.90 $ 0.77
=========== =========== =========== ===========
DILUTED EARNINGS PER SHARE:
Income from Continuing Operations before Cumulative Effect of
Accounting Change ......................................... $ 0.29 $ 0.27 $ 0.78 $ 0.54
Discontinued Operations:
Income from Reliant Resources, net of tax ................. 0.49 -- 0.11 --
Income (loss) from Other Operations, net of tax ........... 0.01 -- 0.01 --
Loss on disposal of Other Operations, net of tax ......... -- (0.06) -- (0.04)
Cumulative Effect of Accounting Change, net of minority
interest and tax ............................................ -- -- -- 0.26
----------- ----------- ----------- -----------
Net Income Attributable to Common Shareholders .............. $ 0.79 $ 0.21 $ 0.90 $ 0.76
=========== =========== =========== ===========
See Notes to the Company's Interim Financial Statements
1
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
ASSETS
DECEMBER 31, JUNE 30,
2002 2003
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents .................... $ 304,281 $ 50,164
Investment in AOL Time Warner common stock ... 283,486 348,190
Accounts receivable, net ..................... 558,328 659,134
Accrued unbilled revenues .................... 354,497 220,311
Fuel stock and petroleum products ............ 166,742 185,207
Materials and supplies ....................... 185,074 182,151
Non-trading derivative assets ................ 27,275 21,953
Taxes receivable ............................. 72,027 102,968
Current assets of discontinued operations .... 12,505 5,113
Prepaid expenses and other current assets .... 71,138 55,970
------------ ------------
Total current assets ....................... 2,035,353 1,831,161
------------ ------------
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment ................ 19,852,729 19,757,347
Less accumulated depreciation and amortization (8,487,612) (8,617,144)
------------ ------------
Property, plant and equipment, net ......... 11,365,117 11,140,203
------------ ------------
OTHER ASSETS:
Goodwill, net ................................ 1,740,510 1,740,510
Other intangibles, net ....................... 65,880 65,943
Regulatory assets ............................ 4,000,646 4,537,864
Non-trading derivative assets ................ 3,866 14,352
Non-current assets of discontinued operations 50,272 22,103
Other ........................................ 444,860 537,339
------------ ------------
Total other assets ......................... 6,306,034 6,918,111
------------ ------------
TOTAL ASSETS ............................. $ 19,706,504 $ 19,889,475
============ ============
See Notes to the Company's Interim Financial Statements
2
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (CONTINUED)
(THOUSANDS OF DOLLARS)
(UNAUDITED)
LIABILITIES AND SHAREHOLDERS' EQUITY
DECEMBER 31, JUNE 30,
2002 2003
------------ ------------
CURRENT LIABILITIES:
Short-term borrowings ................................................ $ 347,000 $ --
Current portion of long-term debt .................................... 810,325 295,541
Indexed debt securities derivative ................................... 224,881 280,430
Accounts payable ..................................................... 621,528 558,730
Taxes accrued ........................................................ 192,570 126,395
Interest accrued ..................................................... 197,274 171,690
Non-trading derivative liabilities ................................... 26,387 12,697
Regulatory liabilities ............................................... 168,173 176,554
Accumulated deferred income taxes, net ............................... 285,214 290,940
Deferred revenues .................................................... 48,940 95,638
Current liabilities of discontinued operations ....................... 2,856 --
Other ................................................................ 286,005 235,449
------------ ------------
Total current liabilities .......................................... 3,211,153 2,244,064
------------ ------------
OTHER LIABILITIES:
Accumulated deferred income taxes, net ............................... 2,445,133 2,664,677
Unamortized investment tax credits ................................... 230,037 221,352
Non-trading derivative liabilities ................................... 873 2,873
Benefit obligations .................................................. 832,152 873,880
Regulatory liabilities ............................................... 959,421 730,246
Non-current liabilities of discontinued operations ................... 6,912 --
Other ................................................................ 698,121 739,697
------------ ------------
Total other liabilities ............................................ 5,172,649 5,232,725
------------ ------------
LONG-TERM DEBT .......................................................... 9,194,320 10,085,949
------------ ------------
COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 12)
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES ......................... 292 169,622
------------ ------------
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF THE
COMPANY .............................................................. 706,140 706,361
------------ ------------
SHAREHOLDERS' EQUITY:
Common stock (300,101,587 shares and 304,643,167 shares outstanding
at December 31, 2002 and June 30, 2003, respectively) .............. 3,050 3,057
Additional paid-in capital ........................................... 3,046,043 2,869,943
Unearned ESOP stock .................................................. (78,049) (17,012)
Retained deficit ..................................................... (1,062,083) (929,129)
Accumulated other comprehensive loss ................................. (487,011) (476,105)
------------ ------------
Total shareholders' equity ......................................... 1,421,950 1,450,754
------------ ------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ....................... $ 19,706,504 $ 19,889,475
============ ============
See Notes to the Company's Interim Financial Statements
3
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
SIX MONTHS ENDED JUNE 30,
-----------------------------
2002 2003
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income attributable to common shareholders ........................ $ 267,250 $ 231,655
Add: Loss (income) from discontinued operations, net of tax ........... (36,238) 865
Add: Loss on disposal of discontinued operations, net of tax .......... -- 11,989
Less: Cumulative effect of accounting change, net of minority interest
and tax .............................................................. -- (80,072)
----------- -----------
Income from continuing operations before cumulative effect of ......... 231,012 164,437
accounting change
Adjustments to reconcile income from continuing operations to net cash
provided by operating activities:
Depreciation and amortization ....................................... 299,481 309,544
Fuel-related amortization ........................................... 13,407 9,725
Deferred income taxes ............................................... 90,290 196,208
Investment tax credits .............................................. (9,228) (8,685)
Loss (gain) on AOL Time Warner investment ........................... 447,811 (64,704)
Loss (gain) on indexed debt securities .............................. (421,956) 55,550
Minority interest ................................................... (4) 4,229
Changes in other assets and liabilities:
Accounts receivable and accrued unbilled revenues, net ............ (90,474) 33,721
Inventory ......................................................... 61,118 (15,542)
Taxes receivable .................................................. -- (30,941)
Accounts payable .................................................. (58,927) (62,798)
Fuel cost over recovery ........................................... 166,176 5
Net non-trading derivative assets and liabilities ................. (2,117) (430)
Interest and taxes accrued ........................................ (124,672) (51,692)
Net regulatory assets and liabilities ............................. (408,926) (355,795)
Other current assets .............................................. 11,285 16,605
Other current liabilities ......................................... (88,460) (34,433)
Other assets ...................................................... (15,396) 34,961
Other liabilities ................................................. (53,878) 26,109
Other, net .......................................................... 36,170 17,535
----------- -----------
Net cash provided by operating activities ....................... 82,712 243,609
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures .................................................. (450,983) (296,561)
Decrease (increase) in restricted cash ................................ 2,961 (1,437)
Other, net ............................................................ 23,105 (2,712)
----------- -----------
Net cash used in investing activities ........................... (424,917) (300,710)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt, net ..................................... 3,097 3,748,267
Increase (decrease) in short-term borrowing, net ...................... 891,424 (347,000)
Payments of long-term debt ............................................ (107,337) (3,362,255)
Payment of common stock dividends ..................................... (222,538) (61,043)
Payment of common stock dividends by subsidiary ....................... -- (7,618)
Proceeds from issuance of common stock ................................ 6,803 4,504
Debt issuance costs ................................................... -- (185,760)
Other, net ............................................................ 176 270
----------- -----------
Net cash provided by (used in) financing activities ............... 571,625 (210,635)
----------- -----------
NET CASH PROVIDED BY DISCONTINUED OPERATIONS ............................ 8,312 13,619
----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS .................... 237,732 (254,117)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ........................ 17,608 304,281
----------- -----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD .............................. $ 255,340 $ 50,164
=========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest .............................................................. $ 250,659 $ 316,679
Income taxes .......................................................... 78,058 4,311
See Notes to the Company's Interim Financial Statements
4
CENTERPOINT ENERGY, INC. 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, Inc.
(CenterPoint Energy), together with its subsidiaries (collectively, the
Company), are the Company's consolidated interim financial statements and notes
(Interim Financial Statements) including these companies' wholly owned and
majority owned subsidiaries. The Company has filed a Current Report on Form 8-K
dated May 12, 2003 (May 12 Form 8-K). The May 12 Form 8-K gives effect to
certain reclassifications that have been made to the Company's historical
financial statements as presented in the Annual Report on Form 10-K of
CenterPoint Energy (CenterPoint Energy Form 10-K) for the year ended December
31, 2002. The Interim Financial Statements are unaudited, omit certain financial
statement disclosures and should be read with the May 12 Form 8-K, including the
exhibits thereto, and the Quarterly Report on Form 10-Q of CenterPoint Energy
for the quarter ended March 31, 2003 (First Quarter 10-Q).
RESTRUCTURING
CenterPoint Energy is a public utility holding company, created on August
31, 2002 as part of a corporate restructuring of Reliant Energy, Incorporated
(Reliant Energy) that implemented certain requirements of the Texas electric
restructuring law described below. In December 2000, Reliant Energy transferred
a significant portion of its unregulated businesses to Reliant Resources, Inc.
(Reliant Resources), which, at the time, was a wholly owned subsidiary of
Reliant Energy. Reliant Resources conducted an initial public offering of
approximately 20% of its common stock in May 2001 (the Reliant Resources
Offering). In December 2001, Reliant Energy's shareholders approved an agreement
and plan of merger pursuant to which the following steps occurred on August 31,
2002 (the Restructuring):
- CenterPoint Energy became the holding company for the Reliant Energy
group of companies;
- Reliant Energy and its subsidiaries became subsidiaries of CenterPoint
Energy; and
- each share of Reliant Energy common stock was converted into one share
of CenterPoint Energy common stock.
On September 30, 2002, CenterPoint Energy distributed all of the shares of
Reliant Resources common stock owned by CenterPoint Energy to its common
shareholders on a pro rata basis (the Reliant Resources Distribution).
CenterPoint Energy is the successor to Reliant Energy for financial
reporting purposes under the Securities Exchange Act of 1934. The Company's
operating subsidiaries own and operate electric transmission and distribution
facilities, natural gas distribution facilities, natural gas pipelines and
electric generating plants. 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 the Company. 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.
As of June 30, 2003, the Company's indirect wholly owned subsidiaries
include:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
engages in Reliant Energy's former electric transmission and
distribution business in a 5,000-square mile area of the Texas Gulf
Coast that includes Houston; and
- CenterPoint Energy Resources Corp. (CERC Corp., and, together with its
subsidiaries, CERC), which owns
5
gas distribution systems that together form one of the United States'
largest natural gas distribution operations in terms of number of customers
served. Through wholly owned subsidiaries, CERC owns two interstate natural
gas pipelines and gas gathering systems and provides various ancillary
services.
CenterPoint Energy also has an approximately 81% ownership interest in
Texas Genco Holdings, Inc. (Texas Genco), which owns and operates the Texas
generating plants formerly belonging to the integrated electric utility that was
a part of Reliant Energy. CenterPoint Energy distributed approximately 19% of
the 80 million outstanding shares of common stock of Texas Genco to CenterPoint
Energy's shareholders on January 6, 2003. As a result of the distribution of
Texas Genco common stock, CenterPoint Energy recorded an impairment charge of
$396 million, which is reflected as a regulatory asset representing stranded
costs in the Consolidated Balance Sheets as of June 30, 2003. This impairment
charge represents the excess of the carrying value of CenterPoint Energy's net
investment in Texas Genco over the market value of the Texas Genco common stock
that was distributed. The financial impact of this impairment was offset by
recording a $396 million regulatory asset reflecting CenterPoint Energy's
expectation of stranded cost recovery of such impairment. See Note 4(c) for a
discussion of generation related regulatory assets. Additionally, in connection
with the distribution, CenterPoint Energy recorded minority interest ownership
in Texas Genco of $146 million in its Consolidated Balance Sheets in the first
quarter of 2003.
BASIS OF PRESENTATION
The preparation of financial statements in conformity with accounting
principles generally accepted 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.
Subsequent to December 31, 2002, the Company sold all of its remaining
Latin America operations. The Interim Financial Statements present these
remaining Latin America operations as discontinued operations in accordance with
Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).
The Company is negotiating to sell a component of its Other Operations
business segment that provides district cooling services in the Houston, Texas
central business district and related complementary energy services to district
cooling customers and others. The assets and liabilities of this business have
been classified in the Consolidated Balance Sheets as discontinued operations.
Accordingly, the Interim Financial Statements reflect these operations as
discontinued operations.
The Interim Financial Statements have been prepared to reflect the effects
of the Restructuring and the Reliant Resources Distribution as described above
on the CenterPoint Energy financial statements. The Interim Financial Statements
present the Reliant Resources businesses (previously reported as the Wholesale
Energy, European Energy, and Retail Energy business segments and related
corporate costs) as discontinued operations, in accordance with SFAS No. 144.
The following notes to the consolidated annual financial statements
included in Exhibit 99.2 to the May 12 Form 8-K (CenterPoint Energy Notes)
relate to certain contingencies. These notes, as updated herein, are
incorporated herein by reference.
6
CenterPoint Energy Notes: Note 3(d) (Long-Lived Assets and Intangibles),
Note 3(e) (Regulatory Assets and Liabilities), Note 4 (Regulatory Matters),
Note 5 (Derivative Instruments), Note 7 (Indexed Debt Securities (ACES and
ZENS) and AOL Time Warner Securities) and Note 13 (Commitments and
Contingencies).
For information regarding certain legal, tax and regulatory proceedings and
environmental matters, see Note 12.
(2) DISCONTINUED OPERATIONS
Latin America. In February 2003, the Company sold its interest in Argener,
a cogeneration facility in Argentina, for $23.1 million. The carrying value of
this investment was approximately $11 million as of December 31, 2002. The
Company recorded an after-tax gain of $7 million from the sale of Argener in the
first quarter of 2003. In April 2003, the Company sold its final remaining
investment in Argentina, a 90 percent interest in Empresa Distribuidora de
Electricidad de Santiago del Estero S.A. (Edese). The Company recorded an
after-tax loss of $3 million in the second quarter of 2003 related to its Latin
American operations.
Revenues related to the Company's Latin America operations included in
discontinued operations for the three months ended June 30, 2002 and 2003 were
$3.9 million and $0.5 million, respectively. Income from these discontinued
operations for the three months ended June 30, 2002 and 2003 is reported net of
income tax expense (benefit) of $(2.1) million and $1.9 million, respectively.
Revenues related to the Company's Latin America operations included in
discontinued operations for the six months ended June 30, 2002 and 2003 were
$8.4 million and $2.2 million, respectively. Income from these discontinued
operations for the six months ended June 30, 2002 and 2003 is reported net of
income tax expense of $1.1 million and $1.9 million, respectively.
CenterPoint Energy Management Services, Inc. As discussed in Note 1, the
Company is negotiating to sell a component of its Other Operations business
segment, CenterPoint Energy Management Services, Inc. (CEMS), that provides
district cooling services in the Houston, Texas central business district and
related complementary energy services to district cooling customers and others.
The Company recorded an after-tax loss in discontinued operations of $16.2
million ($25.0 million pre-tax) during the three months ended June 30, 2003 to
record the impairment of the long-lived asset based on the impending sale and to
record one-time employee termination benefits. Revenues related to CEMS included
in discontinued operations for the three months ended June 30, 2002 and 2003
were $2.2 million and $2.6 million, respectively. Revenues related to CEMS
included in discontinued operations for the six months ended June 30, 2002 and
2003 were $4.0 million and $4.7 million, respectively. Income from these
discontinued operations for the three months ended June 30, 2002 and 2003 is
reported net of income tax benefit of $0.5 million and $0.8 million,
respectively. Income from these discontinued operations for the six months ended
June 30, 2002 and 2003 is reported net of income tax benefit of $0.9 million and
$1.7 million, respectively.
Reliant Resources. On September 30, 2002, CenterPoint Energy distributed to
its shareholders its 83% ownership interest in Reliant Resources by means of a
tax-free spin-off in the form of a dividend. Holders of CenterPoint Energy
common stock on the record date received 0.788603 shares of Reliant Resources
common stock for each share of CenterPoint Energy stock that they owned on the
record date. The Reliant Resources Distribution was recorded in the third
quarter of 2002.
Reliant Resources' revenues included in discontinued operations for the
three months and six months ended June 30, 2002 were $2.3 billion and $4.1
billion, respectively, as reported in Reliant Resources' Annual Report on Form
10-K/A, Amendment No. 1, filed with the SEC on May 1, 2003. Income from these
discontinued operations for the three months and six months ended June 30, 2002
is reported net of income tax expense of $104 million and $146 million,
respectively. These amounts have been restated to reflect Reliant Resources'
adoption of Emerging Issues Task Force (EITF) Issue No. 02-3, "Issues Related to
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities".
(3) NEW ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2003, the Company adopted 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
7
for which a legal obligation exists under enacted laws, statutes and written or
oral contracts, including obligations arising under the doctrine of promissory
estoppel.
The Company has identified retirement obligations for nuclear
decommissioning at the South Texas Project Electric Generating Station (South
Texas Project) and for lignite mine operations at the Jewett mine supplying the
Limestone electric generation facility. Prior to adoption of SFAS No. 143, the
Company had recorded liabilities for nuclear decommissioning and the reclamation
of the lignite mine. Liabilities were recorded for estimated decommissioning
obligations of $139.7 million and $39.7 million for reclamation of the lignite
at December 31, 2002. Upon adoption of SFAS No. 143 on January 1, 2003, the
Company reversed the $139.7 million previously accrued for the nuclear
decommissioning of the South Texas Project and recorded a plant asset of $99.1
million offset by accumulated depreciation of $35.8 million as well as a
retirement obligation of $186.7 million. The $16.3 million difference between
amounts previously recorded and the amounts recorded upon adoption of SFAS No.
143 is being deferred as a liability due to regulatory requirements. The Company
also reversed the $39.7 million it had previously recorded for the Jewett mine
reclamation and recorded a plant asset of $1.9 million offset by accumulated
depreciation of $0.4 million as well as a retirement obligation of $3.8 million.
The $37.4 million difference between amounts previously recorded and the amounts
recorded upon adoption of SFAS No. 143 was recorded as a cumulative effect of
accounting change. The Company has also identified other asset retirement
obligations that cannot be estimated because the assets associated with the
retirement obligations have an indeterminate life.
The following represents the balances of the asset retirement obligation as
of January 1, 2003 and the additions and accretion of the asset retirement
obligation for the six months ended June 30, 2003:
BALANCE, LIABILITIES LIABILITIES CASH FLOW BALANCE,
JANUARY 1, 2003 INCURRED SETTLED ACCRETION REVISIONS JUNE 30, 2003
--------------- -------- ------- --------- --------- -------------
(IN MILLIONS)
Nuclear decommissioning.. $186.7 -- -- $ 4.5 -- $191.2
Jewett lignite mine ..... 3.8 -- -- 0.2 -- 4.0
--------------- -------- ------- --------- --------- -------------
$190.5 -- -- $ 4.7 -- $195.2
=============== ======== ======= ========= ========= =============
The following represents the pro-forma effect on the Company's net income
for the three months and six months ended June 30, 2002, as if the Company had
adopted SFAS No. 143 as of January 1, 2002:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
------------- -------------
(IN THOUSANDS)
Income from continuing operations before cumulative effect of
accounting change as reported .................................................... $ 86,122 $ 231,012
Pro-forma income from continuing operations before cumulative effect
of accounting change ............................................................. 86,102 230,972
Net income as reported .............................................................. 235,645 267,250
Pro-forma net income ................................................................ 235,625 267,210
DILUTED EARNINGS PER SHARE:
Income from continuing operations before cumulative effect of
accounting change as reported .................................................... $ 0.29 $ 0.78
Pro-forma income from continuing operations before cumulative effect
of accounting change ............................................................. 0.29 0.78
Net income as reported .............................................................. 0.79 0.90
Pro-forma net income ................................................................ 0.79 0.90
8
The following represents the Company's asset retirement obligations on a
pro-forma basis as if it had adopted SFAS No. 143 as of December 31, 2002:
AS REPORTED PRO-FORMA
------------------------ -----------------------
(IN MILLIONS)
Nuclear decommissioning................................ $ 139.7 $ 186.7
Jewett lignite mine.................................... 39.7 3.8
------------------------ -----------------------
Total................................................ $ 179.4 $ 190.5
======================== =======================
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
$644 million do not represent SFAS No. 143 asset retirement obligations, but
rather embedded regulatory liabilities. The Company's non-rate regulated
businesses have also previously recognized removal costs as a component of
depreciation expense. The Company reversed $115 million during the three months
ended March 31, 2003 of previously recognized removal costs with respect to
these non-rate regulated businesses as a cumulative effect of accounting change.
The total cumulative effect of accounting change from adoption of SFAS No. 143
was $152 million. Excluded from the $80 million after-tax cumulative effect of
accounting change recorded for the three months ended March 31, 2003, is
minority interest of $19 million related to the Texas Genco stock not owned by
CenterPoint Energy.
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 provision 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. The Company has
reclassified the $26 million loss on debt extinguishment related to the fourth
quarter of 2002 from an extraordinary item to interest expense.
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 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 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
9
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 has
added additional criteria which were effective on July 1, 2003 for new,
acquired, or newly modified forward contracts. The Company engages in forward
contracts for the sale of power. The majority of these forward contracts are
entered into either through state mandated Public Utility Commission of Texas
(Texas Utility Commission) auctions or auctions mandated by an agreement with
Reliant Resources. All of the Company's contracts resulting from these auctions
specify the product types, the plant or group of plants from which the auctioned
products are derived, the delivery location and specific delivery requirements,
and pricing for each of the products. The Company has applied the criteria from
current accounting literature, including SFAS No. 133 Implementation Issue No.
C-15 - "Scope Exceptions: Normal Purchases and Normal Sales Exception for
Option-Type Contracts and Forward Contracts in Electricity", to both the state
mandated and the contractually mandated auction contracts and believes they meet
the definition of capacity contracts. Accordingly, the Company considers these
contracts as normal sales contracts rather than as derivatives. The Company has
evaluated its forward commodity contracts under the new requirements of SFAS No.
149. The adoption of SFAS No. 149 will not change previous accounting
conclusions relating to forward power sales contracts entered into in connection
with the state mandated or contractually mandated auctions, and will not have a
material effect on the Company's 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.
(4) REGULATORY MATTERS
(a) Excess Cost Over Market (ECOM) True-Up.
--------------------------------------
Texas Genco sells, through auctions, entitlements to substantially all of
its installed electric generation capacity, excluding reserves for planned and
forced outages. From September 2001 through July 2003, it conducted auctions as
required by the Texas Utility Commission and by the Company's master separation
agreement with Reliant Resources.
The capacity auctions continue to be consummated at market-based prices
that are substantially below the estimate of those prices made by the Texas
Utility Commission in the spring of 2001. The Texas electric restructuring law
allows recovery, in a "true-up" proceeding in 2004 (2004 True-Up Proceeding), of
the difference between the prices for power sold in state mandated auctions and
earlier estimates of market power prices by the Texas Utility Commission. This
calculation (the ECOM Calculation) calculates the difference between (1) an
imputed margin that reflects the actual market power prices received in the
state mandated auctions, actual fuel expense and generation, and (2) the margin
included in the Texas Utility Commission's estimates of power prices, fuel
expense and generation in the ECOM model developed by the Texas Utility
Commission (the ECOM Margin). The difference is the ECOM True-Up amount.
The ECOM model from which the ECOM Margin is derived provides only annual
estimates of power prices, fuel expense and generation. Accordingly, the Company
must form its own quarterly allocation estimates during 2002-2003 for the
purpose of determining ECOM True-Up revenue.
10
Beginning January 1, 2002, the Company allocated the ECOM Margin in the
Company's ECOM Calculation based on annual estimated forecasts of power prices,
fuel expense and generation. In the second quarter of 2003, the Company began
using a cumulative methodology for allocating ECOM Margin. This methodology uses
revenue amounts based on the actual state mandated auction price results and
actual generation for historical periods, as well as forecasted amounts for the
balance of 2003, rather than forecasted amounts for the two-year period
allocated on an annual basis. Changes in estimates that affect the allocation of
ECOM Margin will have an effect on the amount of ECOM True-Up revenue recorded
in a specific period, but will not affect the total amount of ECOM True-Up
revenue recorded during the two-year period ending December 31, 2003.
In accordance with the Texas Utility Commission's rules regarding the ECOM
True-Up, for the three months ended June 30, 2002 and 2003, CenterPoint Energy
recorded approximately $170 million and $101 million, respectively, in non-cash
revenue related to the right to subsequent cost recovery of the difference
between the market power prices and the Texas Utility Commission's earlier
estimates. In accordance with the Texas Utility Commission's rules regarding the
ECOM True-Up, for the six months ended June 30, 2002 and 2003, CenterPoint
Energy recorded approximately $311 million and $233 million, respectively, in
non-cash revenue related to the right to subsequent cost recovery of the
difference between the market power prices and the Texas Utility Commission's
earlier estimates. For additional information regarding the capacity auctions
and the related true-up proceeding, please read Notes 3(e) and 4(a) to the
CenterPoint Energy Notes, which are incorporated herein by reference.
(b) Generation Asset Impairment Contingency.
---------------------------------------
The Company evaluates the recoverability of its long-lived assets in
accordance with SFAS No. 144. As of June 30, 2003, no impairment had been
indicated in its Texas generation assets. The Company anticipates that future
events, such as changes in the market value of the Texas Genco stock, a change
in the estimated holding period of the Texas generation assets, or a change in
market demand for electricity, will require the Company to re-evaluate these
assets for impairment between now and 2004. If an impairment is indicated, it
could be material and may not be fully recoverable through the 2004 True-Up
Proceeding.
The Texas electric restructuring law provides for the Company to recover
the regulatory book value of its Texas generating assets (as defined in the
Texas electric restructuring law) to the extent the regulatory book value
exceeds the estimated market value. If the Texas generating assets are sold in
the future, a loss on sale of these assets, or an impairment of the recorded
recoverable electric generation plant mitigation regulatory asset, will occur to
the extent the recorded book value of the Texas generating assets exceeds the
regulatory book value. As of June 30, 2003, the recorded book value was $491
million in excess of the regulatory book value. This amount declines as the
recorded book value is depreciated and increases by the amount of capital
expenditures incurred, excluding certain environmental capital expenditures
allowable prior to May 1, 2003. For further discussion of the difference between
the regulatory book value and the recorded book value, see Note 4(a) to the
CenterPoint Energy Notes.
(c) Regulatory Assets Contingency.
-----------------------------
As of June 30, 2003, in contemplation of the 2004 True-Up Proceeding,
CenterPoint Houston has recorded a regulatory asset of $2.5 billion representing
the estimated future recovery of previously incurred costs. This estimated
recovery is based upon current projections of the market value of the Company's
Texas generation assets to be covered by the 2004 True-Up Proceeding
calculations. This estimated recovery amount includes:
- $1.1 billion of previously recorded accelerated depreciation (an
amount equal to earnings above a stated overall annual rate of
return on invested capital that was used to recover the Company's
investment in generation assets);
- $841 million of redirected depreciation; and
- $396 million related to the Texas Genco distribution as discussed
in Note 1.
Offsetting this regulatory asset is an $880 million regulatory liability
relating to an order issued by the Texas Utility Commission in 2001 to refund
amounts relating to prior mitigation of anticipated stranded costs. The Texas
Utility Commission ruled that those amounts should be refunded based on its
conclusion that those amounts would result in an over-mitigation of stranded
costs unless they were refunded. CenterPoint Houston began refunding those
amounts (excess mitigation credits) with January 2002 bills and is scheduled to
continue to refund those credits over a seven-
11
year period.
Because GAAP requires CenterPoint Houston to estimate fair market values in
advance of the final reconciliation, the financial impacts of the Texas electric
restructuring law with respect to the final determination of stranded costs in
the 2004 True-Up Proceeding are subject to material changes. Factors affecting
such changes may include estimation risk, uncertainty of future energy and
commodity prices and the economic lives of the plants. If events were to occur
that made the recovery of some of the remaining generation-related regulatory
assets no longer probable, the Company would write off the unrecoverable balance
of such assets as a charge against earnings.
On June 26, 2003, CenterPoint Houston filed a petition with the Texas
Utility Commission seeking to cease refunding excess mitigation credits on the
ground that continuation of that refund in light of current projections of
stranded costs only increases the amount of stranded costs that CenterPoint
Houston will seek to recover in the 2004 True-Up Proceeding. The excess
mitigation credits amount to approximately $19 million per month. This
proceeding is currently pending before the Texas Utility Commission.
(d) Fuel Reconciliation Contingency.
-------------------------------
CenterPoint Houston and Texas Genco filed their joint application to
reconcile fuel revenues and expenses with the Texas Utility Commission on July
1, 2002. This final fuel reconciliation filing covers reconcilable fuel revenue,
fuel expense and interest of approximately $8.5 billion incurred from August 1,
1997 through January 30, 2002. Also included in this amount is an under-recovery
of $94 million, which was the balance at July 31, 1997 as approved in
CenterPoint Houston's last fuel reconciliation. On March 3, 2003, a settlement
agreement was filed under which certain items totaling $24 million were written
off during the fourth quarter of 2002 and items totaling $203 million will be
carried forward for resolution by the Texas Utility Commission in late 2003 or
early 2004. A hearing is scheduled to begin in September 2003.
(e) 2004 True-Up Proceeding.
-----------------------
Under the Texas electric restructuring law, the Texas Utility Commission is
required to conduct true-up proceedings for each investor-owned utility whose
generation assets were "unbundled" from its transmission and distribution assets
in order to quantify and reconcile the amount of stranded costs, ECOM True-Up,
unreconciled fuel costs, "price to beat" clawback component (See Note 12(g)) and
other regulatory assets associated with electric generation operations (true-up
costs). On June 18, 2003, the Texas Utility Commission ruled that CenterPoint
Houston's filing for recovery of its true-up costs will be made on March 31,
2004. CenterPoint Houston had requested, and the Texas Utility Commission had
initially proposed, a filing date of January 12, 2004. The law requires a final
order to be issued by the Texas Utility Commission not more than 150 days after
a proper filing is made by the regulated utility.
Any delay in the final order date will result in a delay in the
securitization of CenterPoint Houston's stranded costs and the start of recovery
of certain carrying costs through non-bypassable charges to CenterPoint
Houston's customers.
In addition, the delay in CenterPoint Houston's filing for recovery of its
true-up costs means that the calculation of the market value per share of the
Texas Genco common stock for purposes of the Texas Utility Commission's stranded
cost determination might be more or less than the purchase price per share
calculated under the option held by Reliant Resources to purchase CenterPoint
Energy's 81% ownership interest in Texas Genco. Under the option, the purchase
price will be based on market prices during the 120 trading days ending on
January 9, 2004, but under the filing schedule prescribed by the Texas Utility
Commission, the value of that ownership interest for the stranded cost
determination will be based on market prices during the 120 trading days ending
on March 30, 2004. If Reliant Resources exercises its option at a lower price
than the market value used by the Texas Utility Commission, CenterPoint Houston
would be unable to recover the difference.
We expect that upon completion of the 2004 True-Up Proceeding, CenterPoint
Houston will seek to securitize its stranded costs, any regulatory assets not
previously securitized by the October 2001 issuance of transition bonds and, to
the extent permitted by the Texas Utility Commission, the balance of the other
true-up components. Under the Texas electric restructuring law, CenterPoint
Houston is entitled to recover any portion of the true-up balance not
securitized by transition bonds through a non-bypassable competition transition
charge assessed to its customers.
12
(f) CenterPoint Energy Entex Rate Increase Filing.
---------------------------------------------
On June 13, 2003, CenterPoint Energy Entex (Entex) filed a rate increase
request with the City of Houston which, if approved, would yield approximately
$17 million in additional annual revenue. The Company is seeking a return on
common equity of 11.25% and an overall return of 8.87% on its rate base. The
filing does not affect the rates under special contracts with certain industrial
customers. The city has suspended the rate request until October 16, 2003. Upon
resolution of its rate filing with the City of Houston, Entex will seek to
implement new rates in adjacent cities and their surrounding areas. The Company
expects that new rates will become effective in these jurisdictions in the
fourth quarter of 2003 and first quarter of 2004.
(5) DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business. The Company utilizes
derivative financial instruments such as physical forward contracts, swaps and
options (Energy Derivatives) to mitigate the impact of changes in 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, no hedge
ineffectiveness was recognized in earnings from derivatives that are designated
and qualify as cash flow hedges. No component of the derivative instruments'
gain or loss was excluded from the assessment of effectiveness. 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
$9.3 million in accumulated other comprehensive income to be reclassified into
net income during the next twelve months.
Interest Rate Swaps. As of June 30, 2003, the Company had outstanding
interest rate swaps with an aggregate notional amount of $750 million to fix the
interest rate applicable to floating rate long-term debt. These swaps do not
qualify as cash flow hedges under SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133), and are marked to market in
the Company's Consolidated Balance Sheets with changes reflected in interest
expense in the Statements of Consolidated Income.
During 2002, the Company settled its forward-starting interest rate swaps
having a notional amount of $1.5 billion at a cost of $156 million, which was
recorded in other comprehensive income, and reclassified $36 million to interest
expense in 2002. The remaining $120 million in other comprehensive income is
being amortized into interest expense in the same period during which the
interest payments are made for the designated fixed-rate debt. Amortization of
amounts deferred in accumulated other comprehensive income for the three months
ended June 30, 2003, was $3.1 million and is expected to amount to $11.9 million
in 2003.
Embedded Derivative. The Company's $575 million of convertible senior
notes, issued May 19, 2003 (see Note 9), contain a contingent interest
provision. The contingent interest component is an embedded derivative as
defined by SFAS No. 133, and accordingly, must be split from the host instrument
and recorded at fair value on the balance sheet. The value of the contingent
interest component was not material at issuance or at June 30, 2003.
(6) GOODWILL AND INTANGIBLES
Goodwill as of December 31, 2002 and June 30, 2003 by reportable business
segment is as follows (in millions):
Natural Gas Distribution.... $1,085
Pipelines and Gathering..... 601
Other Operations ........... 55
------
Total .................... $1,741
======
13
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2002 JUNE 30, 2003
------------------------------- -------------------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
--------------- --------------- --------------- ---------------
(IN MILLIONS)
Land use rights.................................... $ 61 $ (12) $ 61 $ (13)
Other.............................................. 19 (2) 21 (3)
--------------- --------------- --------------- ---------------
Total.......................................... $ 80 $ (14) $ 82 $ (16)
=============== =============== =============== ===============
The Company recognizes specifically identifiable intangibles, including
land use rights and permits, when specific rights and contracts are acquired.
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 40 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 $0.4 million and $0.6 million, respectively. Amortization
expense for other intangibles for the six months ended June 30, 2002 and 2003
was $0.9 million and $1.1 million, respectively. Estimated amortization expense
for the remainder of 2003 and the five succeeding fiscal years is as follows (in
millions):
2003........................................ $ 1.1
2004........................................ 2.4
2005........................................ 2.6
2006........................................ 2.8
2007........................................ 3.0
2008........................................ 3.3
--------------
Total..................................... $ 15.2
==============
(7) COMPREHENSIVE INCOME
The following table summarizes the components of total comprehensive
income:
FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------- ------------------------------
2002 2003 2002 2003
--------------- --------------- ------------------------------
(IN MILLIONS)
Net income attributable to common shareholders....... $ 236 $ 63 $ 267 $ 232
Other comprehensive income:
Net deferred gain (loss) from cash flow hedges..... (60) 9 (12) 7
Reclassification of deferred loss (gain) from cash
flow hedges realized in net income............... (1) 2 2 3
Other comprehensive income from discontinued
operations....................................... 107 -- 232 1
--------------- --------------- ------------------------------
Other comprehensive income........................... 46 11 222 11
--------------- --------------- ------------------------------
Comprehensive income ................................ $ 282 $ 74 $ 489 $ 243
=============== =============== ==============================
(8) CAPITAL STOCK
CenterPoint Energy has 1,020,000,000 authorized shares of capital stock,
comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000
shares of $0.01 par value preferred stock. At December 31, 2002, 305,017,330
shares of CenterPoint Energy common stock were issued and 300,101,587 shares of
CenterPoint Energy common stock were outstanding. At June 30, 2003, 305,715,039
shares of CenterPoint Energy common stock were issued and 304,643,167 shares of
CenterPoint Energy common stock were outstanding. Outstanding common shares
exclude (a) shares pledged to secure a loan to CenterPoint Energy's Employee
Stock Ownership Plan (4,915,577 and 1,071,706 at December 31, 2002 and June 30,
2003, respectively) and (b) treasury shares (166 at both December 31, 2002 and
June 30, 2003). Reliant Energy declared a dividend of $0.375 per share in each
of the first and second quarters of 2002 and CenterPoint Energy declared a
dividend of $0.10 per share in the first
14
quarter of 2003 and $0.20 per share in the second quarter of 2003, which
includes the third quarter dividend declared on June 18, 2003 payable on
September 10, 2003.
(9) 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, this revolving credit facility was not utilized. This
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 under the credit agreement.
On February 28, 2003, the Company's $3.85 billion bank facility was amended
and extended to June 2005 as discussed below in Note 9 (b). Loans under this
facility are recorded as long-term debt in the Consolidated Balance Sheets at
both December 31, 2002 and June 30, 2003.
(b) Long-term Debt.
---------------
On February 28, 2003, the Company reached agreement with a syndicate of
banks on a second amendment to its bank facility (Second Amendment). Under the
Second Amendment, the maturity date of the bank facility was extended from
October 2003 to June 30, 2005, and the $1.2 billion in mandatory prepayments
that would have been required in 2003 were eliminated. At the time of the Second
Amendment, the facility consisted of a $2.35 billion term loan and a $1.5
billion revolver. Repayments of the term loan of $50 million in March 2003 and
$954 million in May 2003 (collectively, the Term Loan Reduction) reduced the
term loan to $1.35 billion as of June 30, 2003. At June 30, 2003, $1.0 billion
was borrowed under the $1.5 billion revolver. Borrowings bear interest based on
LIBOR rates under a pricing grid tied to the Company's credit rating. The drawn
cost for the facility at the Company's current ratings is LIBOR plus 450 basis
points. The Company has agreed to pay the banks an extension fee of 75 basis
points on the aggregate amount of unused commitments and loans under the bank
facility on October 9, 2003. In connection with the Second Amendment, the
Company paid $41 million in fees that were due on February 28, 2003, along with
$20 million in fees that were to become due on June 30, 2003.
On May 28, 2003, the Company granted the banks a security interest in its
81% stock ownership of Texas Genco. Granting the security interest in the stock
of Texas Genco eliminated a 25 basis point increase in the borrowing costs under
the bank facility that would have been effective after May 28, 2003. The
security interest is to be released at the time of the sale of Texas Genco.
Proceeds from such sale are required to be used to reduce the bank facility.
In the Second Amendment, the Company agreed, subject to regulatory
approval, to grant to the banks warrants to purchase up to 10%, on a fully
diluted basis, of its common stock at a price equal to the greater of $6.56 per
share or 110% of the closing price on the New York Stock Exchange on the date of
issuance of the warrants. The Second Amendment provided for extinguishment of
the warrants if the Company reduced the term loans by specified amounts in 2003.
The reduction of the term loan to $1.35 billion discussed above extinguished the
obligation to provide the warrants.
In the Second Amendment, the Company agreed that the quarterly common stock
dividend declared and paid will not exceed $0.10 per share per quarter. During
the second quarter of 2003, the Company eliminated an additional common stock
dividend limitation contained in the Second Amendment by repaying at least $400
million of term loans, with at least $200 million of such repayment made with
the proceeds of the issuance of equity-linked securities.
The Second Amendment provides that net proceeds from capital stock or
indebtedness issued or incurred by the Company and its subsidiaries must be
applied (subject to a $200 million basket for CERC and another $250 million
basket for borrowings by the Company, certain permitted refinancings of existing
debt and other limited exceptions) to repay bank loans and permanently reduce
the bank facility. Outstanding borrowings under the $200 million CERC credit
facility (see Note 9(a)) would count against the $200 million basket for CERC.
As of June 30, 2003, this facility was not utilized. The capacity represented by
the second basket of $250 million was utilized in
15
connection with the March 18, 2003 debt financing at CenterPoint Houston
described below. Similarly, net cash proceeds from the sale of assets of more
than $30 million or, if less, a group of sales aggregating more than $100
million, must be applied to repay bank loans and reduce the bank facility,
except that proceeds of up to $120 million can be reinvested in the Company's
businesses.
On March 18, 2003, CenterPoint Houston issued $762.3 million aggregate
principal amount of general mortgage bonds composed of $450 million principal
amount of 10-year bonds with an interest rate of 5.7% and $312.3 million
principal amount of 30-year bonds with an interest rate of 6.95%. Proceeds were
used to redeem approximately $312.3 million aggregate principal amount of
CenterPoint Houston's first mortgage bonds and to repay $429 million of
intercompany notes payable to CenterPoint Energy by CenterPoint Houston.
Proceeds from the note repayment were ultimately used by CenterPoint Energy to
repay $150 million aggregate principal amount of medium-term notes maturing on
April 21, 2003, to repay borrowings under its $3.85 billion credit facility and
for $50 million of the Term Loan Reduction.
On March 25 and April 14, 2003, CERC issued $650 million aggregate
principal amount and $112 million aggregate principal amount, respectively, of
7.875% senior unsecured notes due in 2013. A portion of the proceeds were used
to refinance $360 million aggregate principal amount of CERC'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 CERC'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 due in November 2003 and are expected to be refinanced
or remarketed at such time.
On April 9, 2003, the Company remarketed $175 million aggregate principal
amount of pollution control bonds that it had owned since the fourth quarter of
2002. Remarketed bonds maturing in 2029 have a principal amount of $75 million
and an interest rate of 8%. Remarketed bonds maturing in 2018 have a principal
amount of $100 million and an interest rate of 7.75%. Proceeds from the
remarketing were used to repay bank debt. At December 31, 2002, the $175 million
of bonds owned by the Company were not reflected as outstanding debt in the
Company's Consolidated Balance Sheets.
On May 19, 2003, CenterPoint Energy issued $575 million aggregate principal
amount of convertible senior notes due May 15, 2023 with an interest rate of
3.75%. Holders may convert each of their notes into shares of CenterPoint Energy
common stock, initially at a conversion rate of 86.3558 shares of common stock
per $1,000 principal amount of notes at any time prior to maturity, under the
following circumstances: (1) if the last reported sale price of CenterPoint
Energy common stock for at least 20 trading days during the period of 30
consecutive trading days ending on the last trading day of the previous calendar
quarter is greater than or equal to 120% or, following May 15, 2008, 110% of the
conversion price per share of CenterPoint Energy common stock on such last
trading day, (2) if the notes have been called for redemption, (3) during any
period in which the credit ratings assigned to the notes by both Moody's
Investors Service, Inc. and Standard & Poor's Ratings Services, a division of
The McGraw-Hill Companies, are lower than Ba2 and BB, respectively, or the notes
are no longer rated by at least one of these ratings services or their
successors, or (4) upon the occurrence of specified corporate transactions,
including the distribution to all holders of CenterPoint Energy common stock of
certain rights entitling them to purchase shares of CenterPoint Energy common
stock at less than the last reported sale price of a share of CenterPoint Energy
common stock on the trading day prior to the declaration date of the
distribution or the distribution to all holders of CenterPoint Energy common
stock of the Company's assets, debt securities or certain rights to purchase the
Company's securities, which distribution has a per share value exceeding 15% of
the last reported sale price of a share of CenterPoint Energy common stock on
the trading day immediately preceding the declaration date for such
distribution. The convertible senior notes also have a contingent interest
feature requiring contingent interest to be paid to holders of notes commencing
on or after May 15, 2008, in the event that the average trading price of a note
for the applicable five trading day period equals or exceeds 120% of the
principal amount of the note as of the day immediately preceding the first day
of the applicable six-month interest period. Contingent interest will be equal
to 0.25% of the average trading price of the note for the applicable five
trading day period. Proceeds from the issuance of the convertible senior notes
were used for the Term Loan Reduction and to repay revolver borrowings under the
Company's bank facility in the amount of $557 million and $0.75 million,
respectively.
On May 23, 2003, CenterPoint Houston issued $200 million aggregate
principal amount of 20-year general mortgage bonds with an interest rate of
5.6%. Proceeds were used to redeem, on July 1, 2003, $200 million
16
aggregate principal amount of CenterPoint Houston's 7.5% first mortgage bonds
due 2023 at 103.51% of their principal amount. Funds for the redemption were
deposited in trust on May 23, 2003, and the first mortgage bonds were legally
extinguished.
On May 27, 2003, CenterPoint Energy issued $400 million aggregate principal
amount of senior notes composed of $200 million principal amount of 5-year notes
with an interest rate of 5.875% and $200 million principal amount of 12-year
notes with an interest rate of 6.85%. Proceeds in the amount of $397 million
were used for the Term Loan Reduction.
In July 2003, CenterPoint Energy remarketed two series of insurance-backed
pollution control bonds aggregating $150.9 million, reducing the interest rate
from 5.8% to 4%. Of the total amount of bonds remarketed, $92.0 million mature
on August 1, 2015 and $58.9 million mature on October 15, 2015.
(c) Receivables Facility.
--------------------
In connection with CERC'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 CERC. 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, CERC
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, CERC 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 CERC were
pledged to a gas supplier to secure obligations incurred in connection with the
purchase of gas by CERC.
(10) TRUST PREFERRED SECURITIES
(a) CenterPoint Energy.
------------------
Statutory business trusts created by CenterPoint Energy have issued trust
preferred securities, the terms of which, and the related series of junior
subordinated debentures, are described below (in millions):
AGGREGATE
LIQUIDATION
AMOUNTS AS OF
DECEMBER 31, MANDATORY
2002 AND JUNE DISTRIBUTION REDEMPTION
30, 2003 RATE/ DATE/
TRUST (IN MILLIONS) INTEREST RATE MATURITY DATE JUNIOR SUBORDINATED DEBENTURES
------------------------- ------------- ------------- --------------- -------------------------------
REI Trust I.............. $ 375 7.20% March 2048 7.20% Junior Subordinated
Debentures
HL&P Capital Trust I..... $ 250 8.125% March 2046 8.125% Junior Subordinated
Deferrable Interest Debentures
Series A
HL&P Capital Trust II.... $ 100 8.257% February 2037 8.257% Junior Subordinated
Deferrable Interest Debentures
Series B
For additional information regarding these securities, see Note 10 to the
CenterPoint Energy Notes, which note is incorporated herein by reference. The
sole asset of each trust consists of junior subordinated debentures of
CenterPoint Energy having interest rates and maturity dates that correspond to
the distribution rates and the mandatory redemption dates for each series of
preferred securities or capital securities, and the principal amounts
corresponding to the common and preferred securities or capital securities
issued by that trust.
17
(b) CERC Corp.
---------
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 having an interest rate and maturity date that correspond to
the distribution rate and the mandatory redemption date of the convertible
preferred securities, and the principal amount corresponding to the common and
convertible preferred securities issued by the trust. For additional information
regarding these securities, see Note 10 to the CenterPoint Energy Notes, which
note is incorporated herein by reference.
(11) STOCK-BASED INCENTIVE COMPENSATION PLANS
In accordance with SFAS No. 123, "Accounting for Stock-Based Compensation"
(SFAS No. 123), and SFAS No. 148, "Accounting for Stock-Based Compensation,
Transition and Disclosure-- an Amendment of SFAS No. 123," the Company applies
the guidance contained in Accounting Principles Board Opinion No. 25 and
discloses the required pro forma effect on net income of the fair value based
method of accounting for stock compensation.
Pro forma information for the three months and six months ended June 30,
2002 and 2003 is provided to take into account the amortization of stock-based
compensation to expense on a straight-line basis over the vesting period. Had
compensation costs been determined as prescribed by SFAS No. 123, the Company's
net income and earnings per share would have been as follows:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2002 2003 2002 2003
------- ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Net Income:
As reported ........................... $ 236 $ 63 $ 267 $ 232
Total stock-based employee compensation
determined under the fair value based
method .............................. (2) (2) (4) (6)
------- ------- ------- -------
Pro forma ............................. $ 234 $ 61 $ 263 $ 226
======= ======= ======= =======
Basic Earnings Per Share:
As reported ........................... $ 0.79 $ 0.21 $ 0.90 $ 0.77
Pro forma ............................. $ 0.78 $ 0.20 $ 0.89 $ 0.75
Diluted Earnings Per Share:
As reported ........................... $ 0.79 $ 0.21 $ 0.90 $ 0.76
Pro forma ............................. $ 0.78 $ 0.20 $ 0.88 $ 0.74
(12) COMMITMENTS AND CONTINGENCIES
(a) Legal Matters.
-------------
The Company's predecessor, Reliant Energy, and certain of its former
subsidiaries are named as defendants in several lawsuits described below. Under
a master separation agreement between Reliant Energy and Reliant Resources, the
Company and its subsidiaries are entitled to be indemnified by Reliant Resources
for any losses, including attorneys' fees and other costs, arising out of the
lawsuits described under "California Electricity and Gas Market Cases," "Western
States Class Action," "Long-Term Contract Class Action," "Washington and Oregon
Class Actions," "Bustamante Price Reporting Class Action," "Gas Trading Cases,"
"Trading and Marketing Activities" and "Other Class Action Lawsuits." Pursuant
to the indemnification obligation, Reliant Resources is
18
defending the Company and its subsidiaries to the extent named in these
lawsuits. The ultimate outcome of these matters cannot be predicted at this
time.
California Electricity and Gas Market Cases. Reliant Energy, Reliant
Resources, Reliant Energy Power Generation, Inc. (REPG) and several other
subsidiaries of Reliant Resources, as well as three former officers of some of
these companies, have been named as defendants in class action lawsuits and
other lawsuits filed against a number of companies that own generation plants in
California and other sellers of electricity in California markets. While the
plaintiffs allege various violations by the defendants of antitrust laws and
state laws against unfair and unlawful business practices, each of the lawsuits
is grounded on the central allegation that the defendants conspired to drive up
the wholesale price of electricity. In addition to injunctive relief, the
plaintiffs in these lawsuits seek treble the amount of damages alleged,
restitution of alleged overpayments, disgorgement of alleged unlawful profits
for sales of electricity, costs of suit and attorneys' fees. The first six of
these suits originally were filed in state courts in San Diego, San Francisco
and Los Angeles Counties. The suits in San Diego and Los Angeles Counties were
consolidated and removed to the federal district court in San Diego, but on
December 13, 2002, that court remanded the suits to the state courts. Prior to
the remand, Reliant Energy was voluntarily dismissed from two of the suits.
Several parties, including the Reliant defendants, have appealed the judge's
remand decision. The United States court of appeals stayed the remand order
pending the appeal.
In March and April 2002, the California Attorney General filed three
complaints, two in state court in San Francisco and one in the federal district
court in San Francisco, against Reliant Energy, Reliant Resources, Reliant
Energy Services (a wholesale energy marketing subsidiary of Reliant Resources)
and other subsidiaries of Reliant Resources alleging, among other matters,
violations by the defendants of state laws against unfair and unlawful business
practices arising out of transactions in the markets for ancillary services run
by the California independent systems operator, charging unjust and unreasonable
prices for electricity, in violation of antitrust laws in connection with the
acquisition in 1998 of electric generating facilities located in California. The
complaints variously seek restitution and disgorgement of alleged unlawful
profits for sales of electricity, civil penalties and fines, injunctive relief
against unfair competition, divestment of Reliant Resources' generation capacity
and undefined equitable relief. Reliant Resources removed the two state court
cases to the federal district court in San Francisco. In August 2002, the
district court dismissed the two cases originally filed in state court and also
dismissed the damages claims asserted in the antitrust case. The Attorney
General has appealed the dismissal of these cases to the court of appeals.
Following the filing of the Attorney General cases, seven additional class
action cases were filed in state courts in Northern California. Each of these
purports to represent the same class of California ratepayers, assert the same
claims as asserted in the other California class action cases, and in some
instances repeat as well the allegations in the Attorney General cases. All of
these cases have been removed and consolidated in federal district court in San
Diego. The defendants have filed a motion to dismiss on grounds that the claims
are barred by federal preemption of regulation of wholesale rates by the Federal
Energy Regulatory Commission and the filed rate doctrine.
In July 2003, the City of Los Angeles Attorney filed suit against the
Company, Reliant Energy, Reliant Resources, Reliant Energy Services and one of
Reliant Resources' employees in federal court in Los Angeles. The lawsuit
alleges that the defendants conspired to manipulate the price for natural gas in
breach of Reliant Energy Services' contract to supply the Los Angeles Department
of Water and Power (LADWP) with natural gas in violation of federal and state
antitrust laws, the federal Racketeer Influenced and Corrupt Organization Act
and the California False Claims Act. The lawsuit seeks treble damages for the
alleged overcharges for gas purchased by LADWP of an estimated $218 million,
interest, costs of suit and attorneys' fees. The Company has not yet been served
with the complaint.
Western States Class Action. In May 2003, a class action lawsuit was filed
against Reliant Resources, Reliant Energy and various market participants in
state court in San Diego County, California. The plaintiffs allege that Reliant
Resources and Reliant Energy engaged in unfair, unlawful and fraudulent business
practices and violations of the California antitrust laws by manipulating energy
markets in California and the West. The action is brought on behalf of all
persons and businesses residing in Oregon, Washington, Utah, Nevada, Idaho, New
Mexico, Arizona and Montana. The lawsuit seeks injunctive relief, treble
damages, restitution, costs of suit and attorney's fees. In May 2003, the case
was removed to federal court in San Diego. The plaintiffs have moved to remand
the case back to state court and the Reliant defendants have filed a petition
with the Federal Judicial Panel on Multidistrict Litigation to transfer the case
to San Francisco where certain of the cases described under "California
Electricity and
19
Gas Market Cases" described above are already pending and the judge is not a
putative class member. Neither the remand motion nor the motion to transfer has
been heard.
Long-Term Contract Class Action. In October 2002, a class action was filed
in state court in Los Angeles against Reliant Energy and several subsidiaries of
Reliant Resources. The complaint in this case repeats the allegations asserted
in the California class actions as well as the Attorney General cases and also
alleges misconduct related to long-term contracts purportedly entered into by
the California Department of Water Resources. None of the Reliant entities,
however, has a long-term contract with the Department of Water Resources. This
case has been removed to federal district court in San Diego. The Reliant
defendants intend to file motions to dismiss on grounds that the claims are
barred by federal preemption and the filed rate doctrine.
Washington and Oregon Class Actions. In December 2002, a lawsuit was filed
in Circuit Court of the State of Oregon for the County of Multnomah on behalf of
a class of all Oregon purchasers of electricity and natural gas. Reliant Energy,
Reliant Resources and several Reliant Resources subsidiaries were named as
defendants, along with many other electricity generators and marketers. Like the
lawsuits filed in California, the plaintiffs claimed the defendants manipulated
wholesale power prices in violation of state and federal law. The plaintiffs
sought injunctive relief and payment of damages based on alleged overcharges for
electricity. Also in December 2002, a nearly identical lawsuit on behalf of
consumers in the State of Washington was filed in federal district court in
Seattle. Reliant Resources removed the Oregon suit to federal district court in
Portland. The plaintiffs in both cases voluntarily dismissed their lawsuits.
Bustamante Price Reporting Class Action. In November 2002, California
Lieutenant Governor Cruz Bustamante filed a lawsuit in state court in Los
Angeles on behalf of a class of purchasers of gas and power alleging violations
of state antitrust laws and state laws against unfair and unlawful business
practices based on an alleged conspiracy to report and publish false and
fraudulent natural gas prices with an intent to affect the market prices of
natural gas and electricity in California. Reliant Energy, Reliant Resources and
several Reliant Resources subsidiaries were named as defendants, along with
various market participants and publishers of some of the price indices. The
complaint sought injunctive relief, compensatory and punitive damages,
restitution of alleged overpayment, disgorgement of all profits and funds
acquired by the alleged unlawful conduct, costs of suit and attorneys' fees. In
June 2003, the plaintiffs dismissed their claims against Reliant Energy.
Gas Trading Cases. The Company, Reliant Resources and Reliant Energy have
been named as defendants in two lawsuits filed on behalf of a class of
purchasers of natural gas alleging violations of state antitrust laws and state
laws against unfair and unlawful business practices based on an alleged
conspiracy with Enron Corp. to manipulate the California natural gas markets in
2000 and 2001. One lawsuit was filed in April 2003 in state court in Los Angeles
County, California, and the other was filed in May 2003 in state court in San
Diego County, California. The complaints are based on certain conclusions in a
report by the staff of the Federal Energy Regulatory Commission that has not
been subject to procedures designed to allow parties to either discover or test
the basis for the conclusions. The complaint seeks injunctive and declaratory
relief, compensatory and punitive damages, restitution, costs of suit and
attorneys' fees. The complaint alleges that there were "well over one billion
dollars in excess charges to California consumers during the 2000 through 2001
time period." The plaintiffs are seeking a trebling of any damages award.
Reliant Resources removed both cases to federal court and the plaintiffs in both
cases have moved to remand the cases back to state court. The plaintiffs in the
San Diego case have also filed a petition with the Federal Judicial Panel on
Multidistrict Litigation to transfer the case to federal court in Nevada. The
defendants have filed their own motion with the Panel to transfer the case to
the Southern District of New York. Neither the remand nor the transfer motions
have been heard. While Reliant Resources has not yet filed an answer, the
Company understands that Reliant Resources intends to deny both the alleged
violation of any laws and the participation in a conspiracy with Enron. Neither
the Company nor Reliant Energy was a party in the proceedings in which the
report was submitted. Only former subsidiaries of the predecessor to the Company
engaged in gas trading activities in California; however, neither the Company
nor any of its current subsidiaries has ever engaged in gas trading in
California.
20
Trading and Marketing Activities. Reliant Energy has been named as a party
in several lawsuits and regulatory proceedings relating to the trading and
marketing activities of its former subsidiary, Reliant Resources.
In June 2002, the SEC advised Reliant Resources and Reliant Energy that it
had issued a formal order in connection with its investigation of Reliant
Resources' and Reliant Energy's financial reporting, internal controls and
related matters. The investigation was focused on Reliant Resources' same-day
commodity trading transactions involving purchases and sales with the same
counterparty for the same volume at substantially the same price and certain
structured transactions. These matters were previously the subject of an
informal inquiry by the SEC. On May 12, 2003, the SEC advised Reliant Resources
and Reliant Energy that it had issued a formal order in connection with this
investigation. Reliant Energy, through its successor and our subsidiary,
CenterPoint Houston, has entered into a settlement with the SEC that concludes
this investigation. Under the settlement, Reliant Resources and Reliant Energy
consented to the entry of an administrative cease-and-desist order with respect
to future violations of certain provisions of the Securities Act of 1933 and the
Securities Exchange Act of 1934, without admitting or denying the SEC's findings
that violations of these laws had occurred. The SEC did not assess monetary
penalties or fines against Reliant Energy, us or any of our subsidiaries.
In connection with the Texas Utility Commission's industry-wide
investigation into potential manipulation of the ERCOT market on and after July
31, 2001, Reliant Energy and Reliant Resources have provided information to the
Texas Utility Commission concerning their scheduling and trading activities.
Other Class Action Lawsuits. Fifteen class action lawsuits filed in May,
June and July 2002 on behalf of purchasers of securities of Reliant Resources
and/or Reliant Energy have been consolidated in federal district court in
Houston. Reliant Resources and certain of its former and current executive
officers are named as defendants. Reliant Energy is also named as a defendant in
seven of the lawsuits. Two of the lawsuits also name as defendants the
underwriters of the Reliant Resources Offering. One lawsuit names Reliant
Resources' and Reliant Energy's independent auditors as a defendant. The
consolidated amended complaint seeks monetary relief purportedly on behalf of
three classes: (1) purchasers of Reliant Energy common stock from February 3,
2000 to May 13, 2002; (2) purchasers of Reliant Resources common stock on the
open market from May 1, 2001 to May 13, 2002; and (3) purchasers of Reliant
Resources common stock in the Reliant Resources Offering or purchasers of shares
that are traceable to the Reliant Resources Offering. The plaintiffs allege,
among other things, that the defendants misrepresented their revenues and
trading volumes by engaging in round-trip trades and improperly accounted for
certain structured transactions as cash-flow hedges, which resulted in earnings
from these transactions being accounted for as future earnings rather than being
accounted for as earnings in fiscal year 2001.
In February 2003, a lawsuit was filed by three individuals in federal
district court in Chicago against CenterPoint Energy and certain former and
current officers of Reliant Resources for alleged violations of federal
securities laws. The plaintiffs in this lawsuit allege that the defendants
violated federal securities laws by issuing false and misleading statements to
the public, and that the defendants made false and misleading statements as part
of an alleged scheme to inflate artificially trading volumes and revenues. In
addition, the plaintiffs assert claims of fraudulent and negligent
misrepresentation and violations of Illinois consumer law.
In May 2002, three class action lawsuits were filed in federal district
court in Houston on behalf of participants in various employee benefits plans
sponsored by Reliant Energy. Reliant Energy and its directors are named as
defendants in all of the lawsuits. Two of the lawsuits have been dismissed
without prejudice. The remaining lawsuit alleges that the defendants breached
their fiduciary duties to various employee benefits plans, directly or
indirectly sponsored by Reliant Energy, in violation of the Employee Retirement
Income Security Act. The plaintiffs allege that the defendants permitted the
plans to purchase or hold securities issued by Reliant Energy when it was
imprudent to do so, including after the prices for such securities became
artificially inflated because of alleged securities fraud engaged in by the
defendants. The complaints seek monetary damages for losses suffered by a
putative class of plan participants whose accounts held Reliant Energy or
Reliant Resources securities, as well as equitable relief in the form of
restitution.
In October 2002, a derivative action was filed in the federal district
court in Houston, against the directors and officers of the Company. The
complaint sets forth claims for breach of fiduciary duty, waste of corporate
assets, abuse
21
of control and gross mismanagement. Specifically, the shareholder plaintiff
alleges that the defendants caused the Company to overstate its revenues through
so-called "round trip" transactions. The plaintiff also alleges breach of
fiduciary duty in connection with the spin-off and the Reliant Resources
Offering. The complaint seeks monetary damages on behalf of the Company as well
as equitable relief in the form of a constructive trust on the compensation paid
to the defendants. In March 2003, the court dismissed this case on the grounds
that the plaintiff did not make an adequate demand on the Company before filing
suit. Thereafter, the plaintiff sent another demand asserting the same claims.
The Company's board of directors investigated that demand and similar
allegations made in a June 28, 2002 demand letter sent on behalf of a Company
shareholder. The latter letter demanded that the Company take several actions in
response to alleged round-trip trades occurring in 1999, 2000, and 2001. In June
2003, the Board determined that these proposed actions would not be in the best
interests of the Company.
The Company believes that none of these lawsuits has merit because, among
other reasons, the alleged misstatements and omissions were not material and did
not result in any damages to any of the plaintiffs.
Texas Action. In July 2003, Texas Commercial Energy filed a lawsuit against
Reliant Energy, Reliant Resources, Reliant Electric Solutions, LLC, several
other Reliant Resources subsidiaries and several other participants in the
Electric Reliability Council of Texas, Inc. (ERCOT) power market in federal
court in Corpus Christi, Texas. The plaintiff, a retail electricity provider in
the Texas market served by ERCOT, alleges that the defendants conspired to
illegally fix and artificially increase the price of electricity in violation of
state and federal antitrust laws and committed fraud and negligent
misrepresentation. The lawsuit seeks damages in excess of $500 million,
exemplary damages, treble damages, interest, costs of suit and attorneys' fees.
The Company has not yet been served with the complaint.
Reliant Energy Municipal Franchise Fee Lawsuits. In February 1996, the
cities of Wharton, Galveston and Pasadena (Three Cities) filed suit, for
themselves and a proposed class of all similarly situated cities in Reliant
Energy's electric service area, against Reliant Energy and Houston Industries
Finance, Inc. (formerly a wholly owned subsidiary of Reliant Energy) alleging
underpayment of municipal franchise fees. The plaintiffs claim that they are
entitled to 4% of all receipts of any kind for business conducted within these
cities over the previous four decades. A jury trial of the original claimant
cities (but not the class of cities) in the 269th Judicial District Court for
Harris County, Texas, ended in April 2000 (the Three Cities case). Although the
jury found for Reliant Energy on many issues, it found in favor of the original
claimant cities on three issues, and assessed a total of $4 million in actual
and $30 million in punitive damages. However, the jury also found in favor of
Reliant Energy on the affirmative defense of laches, a defense similar to a
statute of limitations defense, due to the original claimant cities having
unreasonably delayed bringing their claims during the 43 years since the alleged
wrongs began. The trial court in the Three Cities case granted most of Reliant
Energy's motions to disregard the jury's findings. The trial court's rulings
reduced the judgment to $1.7 million, including interest, plus an award of $13.7
million in legal fees. In addition, the trial court granted Reliant Energy's
motion to decertify the class. Following this ruling, 45 cities filed individual
suits against Reliant Energy in the District Court of Harris County.
On February 27, 2003, the state court of appeals in Houston rendered an
opinion reversing the judgment against the Company and rendering judgment that
the Three Cities take nothing by their claims. The court of appeals found that
the jury's finding of laches barred all of the Three Cities' claims and that the
Three Cities were not entitled to recovery of any attorneys' fees. The Three
Cities have filed a petition for review at the Texas Supreme Court, where the
matter remains pending.
The extent to which issues in the Three Cities case may affect the claims
of the other cities served by Reliant Energy cannot be assessed until judgments
are final and no longer subject to appeal. However, the court of appeals' ruling
appears to be consistent with Texas Supreme Court opinions. The Company
estimates the range of possible outcomes for recovery by the plaintiffs in the
Three Cities case to be between $-0- and $18 million inclusive of interest and
attorneys' fees.
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
22
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 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 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 the Company, CERC, 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 CERC 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 CERC. 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.
Supplier Suits. Texas Genco is currently engaged in a dispute with its fuel
supplier at its Limestone electric generation facility over the terms and
pricing for fuel supplied to that facility under a 1999 settlement agreement
between the parties and under ancillary obligations. Texas Genco has filed suit
for a declaratory judgment and damages against the supplier, Northwestern
Resources Co. (NWR), in Harris County, Texas, and NWR has filed an amended
petition seeking a declaratory judgment in an action previously filed against
Reliant Energy in Limestone County, Texas. NWR claims Texas Genco has breached
its obligations by modifying its generation facility to burn coal from the
Powder River Basin and by purchasing coal from the Powder River Basin without
first giving NWR a right of first refusal to supply lignite at a price that is
equal to or less than the coal from the Powder River Basin. NWR also contends
that Texas Genco is not entitled to certain production royalties. In its suit,
Texas Genco seeks rulings that it has not breached its obligations regarding the
modification of its facilities and the burning of Powder River Basin coal but
that, instead, NWR has breached its obligations by failing to pay production
royalties and in other respects.
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 condition, results of
operations or cash flows.
(b) Environmental Matters.
---------------------
Clean Air Standards. The Texas electric restructuring law and regulations
adopted by the Texas Commission on Environmental Quality in 2001 require
substantial reductions in emission of oxides of nitrogen (NOx) from electric
generating units. The Company is currently installing cost-effective controls at
its generating plants to comply with these requirements. Through June 30, 2003,
the Company has invested $610 million for NOx emission control, and plans to
make expenditures of up to approximately $181 million for the remainder of 2003
through 2007. The Texas electric restructuring law provides for stranded cost
recovery for expenditures incurred before May 1, 2003 to achieve the NOx
reduction requirements. Incurred costs include costs for which contractual
obligations have been made. The Texas Utility Commission has determined that the
Company's emission control plan is the most cost-effective option for achieving
compliance with applicable air quality standards for the Company's generating
23
facilities and the final amount for recovery will be determined in the 2004
True-Up Proceeding.
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. CERC 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 CERC's Minnesota service territory, two of which
CERC believes were neither owned nor operated by CERC, and for which CERC
believes it has no liability.
At June 30, 2003, CERC 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. CERC has utilized an environmental expense tracker mechanism in
its rates in Minnesota to recover estimated costs in excess of insurance
recovery. CERC has collected or accrued $12.4 million at June 30, 2003 to be
used for future environmental remediation.
CERC has received notices from the United States Environmental Protection
Agency and others regarding its status as a PRP for other sites. CERC 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 CERC or its divisions. The Company is investigating details
regarding these sites and the range of environmental expenditures for potential
remediation. Based on current information, the Company has not been able to
quantify a range of environmental expenditures for such sites.
Mercury Contamination. The Company's pipeline and distribution operations
have in the past employed elemental mercury in measuring and regulating
equipment. It is possible that small amounts of mercury may have been spilled in
the course of normal maintenance and replacement operations and that these
spills may have contaminated the immediate area with elemental mercury. This
type of contamination has been found by the Company at some sites in the past,
and the Company has conducted remediation at these sites. It is possible that
other contaminated sites may exist and that remediation costs may be incurred
for these sites. Although the total amount of these costs cannot be known at
this time, based on experience by the Company and that of others in the natural
gas industry to date and on the current regulations regarding remediation of
these sites, the Company believes that the costs of any remediation of these
sites will not be material to the Company's financial condition, results of
operations or cash flows.
Other Environmental. From time to time the Company has received notices
from regulatory authorities or others regarding its status as a PRP in
connection with sites found to require remediation due to the presence of
environmental contaminants. In addition, the Company has been named as a
defendant in litigation related to such sites and in recent years has been
named, along with numerous others, as a defendant in several lawsuits filed by a
large number of individuals who claim injury due to exposure to asbestos while
working at sites along the Texas Gulf Coast. Most of these claimants have been
workers who participated in construction of various industrial facilities,
including power
24
plants, and some of the claimants have worked at locations owned by the Company.
The Company anticipates that additional claims like those received may be
asserted in the future and intends to continue vigorously contesting claims
which it does not consider to have merit. Although their ultimate outcome cannot
be predicted at this time, the Company does not believe, based on its experience
to date, that these matters, either individually or in the aggregate, will have
a material adverse effect on the Company's financial condition, results of
operations or cash flows.
(c) 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.
(d) Other Proceedings.
-----------------
The Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company's management
regularly analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters. The Company's
management believes that the disposition of these matters will not have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.
(e) Nuclear Insurance.
-----------------
Texas Genco and the other owners of the South Texas Project maintain
nuclear property and nuclear liability insurance coverage as required by law and
periodically review available limits and coverage for additional protection. The
owners of the South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.
Pursuant to the Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $9.3 billion as of June 30, 2003. Owners are
required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. Texas Genco and the other owners of the
South Texas Project currently maintain the required nuclear liability insurance
and participate in the industry retrospective rating plan under which the owners
of the South Texas Project are subject to maximum retrospective assessments in
the aggregate per incident of up to $88 million per reactor. The owners are
jointly and severally liable at a rate not to exceed $10 million per incident
per year. In addition, the security procedures at this facility have recently
been enhanced to provide additional protection against terrorist attacks.
There can be no assurance that all potential losses or liabilities will be
insurable, or that the amount of insurance will be sufficient to cover them. Any
substantial losses not covered by insurance would have a material effect on the
Company's financial condition, results of operations and cash flows.
25
(f) Nuclear Decommissioning.
-----------------------
Texas Genco contributed $2.9 million in 2002 to trusts established to fund
its share of the decommissioning costs for the South Texas Project, and expects
to contribute $2.9 million in 2003. There are various investment restrictions
imposed upon Texas Genco by the Texas Utility Commission and the United States
Nuclear Regulatory Commission (NRC) relating to Texas Genco's nuclear
decommissioning trusts. Texas Genco and CenterPoint Energy have each appointed
two members to the Nuclear Decommissioning Trust Investment Committee which
establishes the investment policy of the trusts and oversees the investment of
the trusts' assets. The securities held by the trusts for decommissioning costs
had an estimated fair value of $174 million as of June 30, 2003, of which
approximately 40% were fixed-rate debt securities and the remaining 60% were
equity securities. For a discussion of the accounting treatment for the
securities held in the nuclear decommissioning trust, see Note 3(k) to the
CenterPoint Energy Notes, which note is incorporated herein by reference. In
July 1999, an outside consultant estimated Texas Genco's portion of
decommissioning costs to be approximately $363 million. While the funding levels
currently exceed minimum NRC requirements, no assurance can be given that the
amounts held in trust will be adequate to cover the actual decommissioning costs
of the South Texas Project. Such costs may vary because of changes in the
assumed date of decommissioning and changes in regulatory requirements,
technology and costs of labor, materials and equipment. Pursuant to the Texas
electric restructuring law, costs associated with nuclear decommissioning that
have not been recovered as of January 1, 2002, will continue to be subject to
cost-of-service rate regulation and will be included in a charge to transmission
and distribution customers. CenterPoint Energy is contractually obligated to
indemnify Texas Genco from and against any obligations relating to the
decommissioning not otherwise satisfied through collections by CenterPoint
Houston. For information regarding the effect of the business separation plan on
funding of the nuclear decommissioning trust fund, see Note 4(b) to the
CenterPoint Energy Notes, which note is incorporated herein by reference.
(g) "Price to Beat" Clawback Component.
----------------------------------
In connection with the implementation of the Texas electric restructuring
law, the Texas Utility Commission has set a "price to beat" that retail electric
providers affiliated or formerly affiliated with a former integrated utility
must charge residential and small commercial customers within their affiliated
electric utility's service area. The true-up provides for a clawback of "price
to beat" in excess of the market price of electricity if 40% of the "price to
beat" load is not served by a non-affiliated retail electric provider by January
1, 2004. Pursuant to the Texas electric restructuring law and the master
separation agreement between Reliant Energy and Reliant Resources, Reliant
Resources is obligated to pay CenterPoint Houston for the clawback component of
the true-up. The clawback may not exceed $150 times the number of customers
served by the affiliated retail electric provider in the transmission and
distribution utility's service territory, less the number of customers served by
the affiliated retail electric provider outside the transmission and
distribution utility's service territory, on January 1, 2004.
26
(13) EARNINGS PER SHARE
The following table presents the Company's basic and diluted earnings per
share (EPS) calculation:
FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------- -------------------------------
2002 2003 2002 2003
--------------- --------------- --------------- ---------------
(IN MILLIONS, EXCEPT SHARE AND
PER SHARE AMOUNTS)
Basic EPS Calculation:
Income from continuing operations before cumulative
effect of accounting change........................... $ 86 $ 83 $ 231 $ 165
Discontinued Operations:
Income from Reliant Resources, net of tax............. 148 -- 34 --
Income (loss) from Other Operations, net of tax....... 2 (1) 2 (1)
Loss on disposal of Other Operations, net of tax ..... -- (19) -- (12)
Cumulative effect of accounting change, net of minority
interest and tax...................................... -- -- -- 80
--------------- --------------- --------------- ---------------
Net income attributable to common shareholders.......... $ 236 $ 63 $ 267 $ 232
=============== =============== =============== ===============
Weighted average shares outstanding....................... 297,696,000 304,046,000 296,963,000 302,373,000
=============== =============== =============== ===============
Basic EPS:
Income from continuing operations before cumulative
effect of accounting change........................... $ 0.29 $ 0.27 $ 0.78 $ 0.54
Discontinued Operations:
Income from Reliant Resources, net of tax............. 0.49 -- 0.11 --
Income (loss) from Other Operations, net of tax....... 0.01 -- 0.01 --
Loss on disposal of Other Operations, net of tax...... -- (0.06) -- (0.04)
Cumulative effect of accounting change, net of minority
interest and tax.................................... -- -- -- 0.27
--------------- --------------- --------------- ---------------
Net income attributable to common shareholders.......... $ 0.79 $ 0.21 $ 0.90 $ 0.77
=============== =============== =============== ===============
Diluted EPS Calculation:
Net income attributable to common shareholders.......... $ 236 $ 63 $ 267 $ 232
Plus: Income impact of assumed conversions:
Interest on 61/4% convertible trust preferred
securities............................................ -- -- -- --
--------------- --------------- --------------- ---------------
Total earnings effect assuming dilution................. $ 236 $ 63 $ 267 $ 232
=============== =============== =============== ===============
Weighted average shares outstanding....................... 297,696,000 304,046,000 296,963,000 302,373,000
Plus: Incremental shares from assumed conversions (1):
Stock options......................................... 10,000 909,000 206,000 627,000
Restricted stock...................................... 752,000 1,131,000 752,000 1,131,000
61/4% convertible trust preferred securities.......... 13,000 18,000 13,000 18,000
--------------- --------------- --------------- ---------------
Weighted average shares assuming dilution............... 298,471,000 306,104,000 297,934,000 304,149,000
=============== =============== =============== ===============
Diluted EPS:
Income from continuing operations before cumulative
effect of accounting change........................... $ 0.29 $ 0.27 $ 0.78 $ 0.54
Discontinued Operations:
Income from Reliant Resources, net of tax............. 0.49 -- 0.11 --
Income (loss) from Other Operations, net of tax..... 0.01 -- 0.01 --
Loss on disposal of Other Operations, net of tax ..... -- (0.06) -- (0.04)
Cumulative effect of accounting change, net of minority
interest and tax...................................... -- -- -- 0.26
--------------- --------------- --------------- ---------------
Net income attributable to common shareholders.......... $ 0.79 $ 0.21 $ 0.90 $ 0.76
=============== =============== =============== ===============
27
(1) For the three months ended June 30, 2002 and 2003, the computation of
diluted EPS excludes 5,693,413 and 10,205,812 purchase options,
respectively, for shares of common stock that have exercise prices (ranging
from $22.19 to $50.00 per share and $12.13 to $32.26 per share for the
second quarter 2002 and 2003, respectively) greater than the per share
average market price for the period and would thus be anti-dilutive if
exercised.
For the six months ended June 30, 2002 and 2003, the computation of diluted
EPS excludes 5,597,490 and 10,244,822 purchase options, respectively, for
shares of common stock that have exercise prices (ranging from $22.44 to
$50.00 per share and $7.56 to $32.26 per share for the first six months of
2002 and 2003, respectively) greater than the per share average market
price for the period and would thus be anti-dilutive if exercised.
(14) REPORTABLE BUSINESS SEGMENTS
The Company's determination of reportable business segments considers the
strategic operating units under which the Company manages sales, allocates
resources and assesses performance of various products and services to wholesale
or retail customers in differing regulatory environments. The Company has
identified the following reportable business segments: Electric Transmission &
Distribution, Electric Generation, Natural Gas Distribution, Pipelines and
Gathering and Other Operations. Reportable business segments presented herein do
not include Wholesale Energy, European Energy, Retail Energy and related
corporate costs as these business segments operated within Reliant Resources,
which is presented as discontinued operations within these consolidated
financial statements. Additionally, the Company's Latin America operations and
its energy management services business, which were previously reported in the
Other Operations business segment, are presented as discontinued operations
within these consolidated financial statements. Reportable business segments for
all prior periods presented have been restated to conform to the 2003
presentation.
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 that the chief operating decision maker uses 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, minority interest and income taxes (EBIT)
basis. Historically, the difference between EBIT reported on a segment basis and
operating income on a segment basis has not been material.
Financial data for the Company's reportable business segments are as
follows:
FOR THE THREE MONTHS ENDED JUNE 30, 2002
-------------------------------------------------
NET
REVENUES FROM INTERSEGMENT OPERATING
NON-AFFILIATES REVENUES INCOME (LOSS)
----------------- --------------- ---------------
(IN MILLIONS)
Electric Transmission & Distribution (1)........ $ 528 (2) $ -- $ 275
Electric Generation............................. 417 (3) (4) (29)
Natural Gas Distribution........................ 780 17 11
Pipelines and Gathering......................... 72 30 39
Other Operations................................ 1 6 (7)
Eliminations.................................... -- (49) --
----------------- --------------- ---------------
Consolidated.................................... $ 1,798 $ -- $ 289
================= =============== ===============
28
FOR THE THREE MONTHS ENDED JUNE 30, 2003
-------------------------------------------------
NET
REVENUES FROM INTERSEGMENT OPERATING
NON-AFFILIATES REVENUES INCOME (LOSS)
----------------- --------------- ---------------
(IN MILLIONS)
Electric Transmission & Distribution............ $ 482 (2) $ -- $ 235
Electric Generation............................. 578 (3) -- 50
Natural Gas Distribution........................ 954 17 21
Pipelines and Gathering......................... 73 49 42
Other Operations................................ 4 5 (2)
Eliminations.................................... -- (71) --
----------------- --------------- ---------------
Consolidated.................................... $ 2,091 $ -- $ 346
================= =============== ===============
AS OF
FOR THE SIX MONTHS ENDED JUNE 30, 2002 DECEMBER 31, 2002
------------------------------------------------ -------------------
NET
REVENUES FROM INTERSEGMENT OPERATING
NON-AFFILIATES REVENUES INCOME (LOSS) TOTAL ASSETS
----------------- --------------- -------------- -------------------
(IN MILLIONS)
Electric Transmission & Distribution (1)........ $ 1,096 (4) $ -- $ 528 $ 9,098
Electric Generation............................. 683 (5) 56 (81) 4,416
Natural Gas Distribution........................ 1,960 17 118 4,051
Pipelines and Gathering......................... 134 60 76 2,481
Other Operations................................ 3 11 -- 1,345
Discontinued Operations......................... -- -- -- 63
Eliminations.................................... -- (144) -- (1,747)
----------------- --------------- -------------- ------------------
Consolidated.................................... $ 3,876 $ -- $ 641 $ 19,707
================= =============== ============== ==================
AS OF
FOR THE SIX MONTHS ENDED JUNE 30, 2003 JUNE 30, 2003
----------------- --------------- -------------- -------------------
NET
REVENUES FROM INTERSEGMENT OPERATING
NON-AFFILIATES REVENUES INCOME (LOSS) TOTAL ASSETS
----------------- --------------- ----------------------------------
(IN MILLIONS)
Electric Transmission & Distribution ........... $ 929 (4) $ -- $ 440 $ 9,609
Electric Generation............................. 937 (5) -- 33 4,694
Natural Gas Distribution........................ 2,982 33 151 4,169
Pipelines and Gathering......................... 134 97 85 2,458
Other Operations................................ 9 9 (2) 1,149
Discontinued Operations......................... -- -- -- 28
Eliminations.................................... -- (139) -- (2,218)
----------------- --------------- -------------- ------------------
Consolidated.................................... $ 4,991 $ -- $ 707 $ 19,889
================= =============== ============== ==================
(1) Retail customers remained regulated customers of Reliant Energy HL&P, then
an unincorporated division of Reliant Energy, through the date of their
first meter reading in January 2002. Sales of electricity to retail
customers in 2002 prior to this meter reading are reflected in the Electric
Transmission & Distribution business segment.
(2) Sales to subsidiaries of Reliant Resources for the three months ended June
30, 2002 and 2003 represented approximately $246 million and $225 million,
respectively, of CenterPoint Houston's transmission and distribution
revenues since deregulation began in 2002.
(3) Sales to subsidiaries of Reliant Resources for the three months ended June
30, 2002 and 2003 represented approximately 76% and 72%, respectively, of
Texas Genco's total revenues. Sales to a major customer for the
29
three months ended June 30, 2002 and 2003 represented approximately 11% and
10%, respectively, of Texas Genco's total revenues.
(4) Sales to subsidiaries of Reliant Resources for the six months ended June
30, 2002 and 2003 represented approximately $363 million and $437 million,
respectively, of CenterPoint Houston's transmission and distribution
revenues since deregulation began in 2002.
(5) Sales to subsidiaries of Reliant Resources for the six months ended June
30, 2002 and 2003 represented approximately 66% and 70%, respectively, of
Texas Genco's total revenues. Sales to a major customer for each of the six
months ended June 30, 2002 and 2003 represented approximately 10% of Texas
Genco's total revenues.
Reconciliation of Operating Income to Net Income Attributable to Common
Shareholders:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------- ------------------------------
2002 2003 2002 2003
--------------- --------------- --------------- ---------------
(IN MILLIONS)
Operating income..................................... $ 289 $ 346 $ 641 $ 707
Gain (loss) on AOL Time Warner investment............ (230) 113 (448) 65
Gain (loss) on indexed debt securities............... 219 (98) 422 (56)
Interest expense..................................... (140) (215) (257) (439)
Distribution on trust preferred securities........... (14) (14) (28) (28)
Other income, net.................................... 8 1 15 5
Income tax expense................................... (46) (44) (114) (85)
Minority interest.................................... -- (6) -- (4)
--------------- --------------- --------------- ---------------
Income from continuing operations before cumulative
effect of accounting change........................ 86 83 231 165
Discontinued Operations:
Income from Reliant Resources, net of tax.......... 148 -- 34 --
Income (loss) from Other Operations, net of tax.... 2 (1) 2 (1)
Loss on disposal of Other Operations, net of tax... -- (19) -- (12)
Cumulative effect of accounting change, net of
minority interest and tax.......................... -- -- -- 80
--------------- --------------- --------------- ---------------
Net income attributable to common shareholders....... $ 236 $ 63 $ 267 $ 232
=============== =============== =============== ===============
(15) SUBSEQUENT EVENT
On July 15, 2003, a steam line ruptured at Texas Genco's W.A. Parish coal
facility damaging one of the facility's units and temporarily taking another
unit offline. Texas Genco anticipates that the unit will be out of service
through September 2003. A thorough root cause analysis process is underway and a
detailed repair plan is being implemented. An estimated cost for damage repair
is being developed.
30
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS OF CENTERPOINT ENERGY AND SUBSIDIARIES
The following discussion and analysis should be read in combination with
our Interim Financial Statements contained in this report.
OVERVIEW
We are a public utility holding company, created on August 31, 2002 as part
of a corporate restructuring of Reliant Energy, Incorporated (Reliant Energy) in
compliance with requirements of the Texas electric restructuring law. We are the
successor to Reliant Energy for financial reporting purposes under the
Securities Exchange Act of 1934. Our operating subsidiaries own and operate
electric generation plants, electric transmission and distribution facilities,
natural gas distribution facilities and natural gas pipelines. We are a
registered holding company under the Public Utility Holding Company Act of 1935,
as amended (1935 Act). For information about the 1935 Act, see "Liquidity and
Capital Resources -- Future Sources and Uses of Cash Flows -- Capitalization."
Our indirect wholly owned subsidiaries include:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
engages in our electric transmission and distribution business in the
Texas Gulf Coast area; and
- CenterPoint Energy Resources Corp. (CERC Corp., and together with its
subsidiaries, CERC), which owns and operates our local gas
distribution companies, gas gathering systems and interstate
pipelines.
We also have an approximately 81% ownership interest in Texas Genco
Holdings, Inc. (Texas Genco), which owns and operates the Texas generating
plants formerly belonging to the integrated electric utility that was a part of
Reliant Energy. We distributed the remaining 19% of the outstanding common stock
of Texas Genco to our shareholders on January 6, 2003.
At the time of Reliant Energy's corporate restructuring, it owned an 83%
interest in Reliant Resources, Inc. (Reliant Resources), which conducts
non-utility wholesale and retail energy operations primarily in North America
and Western Europe. On September 30, 2002, we distributed that interest to our
shareholders (the Reliant Resources Distribution).
In this section we discuss our results from continuing operations on a
consolidated basis and individually for each of our business segments. We also
discuss our liquidity, capital resources and critical accounting policies. Our
reportable business segments include the following:
- Electric Transmission & Distribution;
- Electric Generation (Texas Genco);
- Natural Gas Distribution;
- Pipelines and Gathering; and
- Other Operations.
Effective with the full deregulation of sales of electric energy to retail
customers in Texas beginning in January 2002, power generators and retail
electric providers in Texas ceased to be subject to traditional cost-based
regulation. Since that date, we have sold generation capacity, energy and
ancillary services related to power generation at prices determined by the
market. Our transmission and distribution services remain subject to rate
regulation. Although our former retail sales business is no longer conducted by
us, retail customers remained regulated customers of our former integrated
electric utility, Reliant Energy HL&P, through the date of their first
31
meter reading in 2002. Sales of electricity to retail customers in 2002 prior to
this meter reading are reflected in the Electric Transmission & Distribution
business segment. For business segment reporting information, please read Notes
1 and 14 to our Interim Financial Statements.
Subsequent to December 31, 2002, we sold our remaining Latin America
operations. The Interim Financial Statements present these Latin America
operations as discontinued operations in accordance with Statement of Financial
Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets" (SFAS No. 144).
We are negotiating to sell a component of our Other Operations business
segment, CenterPoint Energy Management Services, Inc. (CEMS), that provides
district cooling services in the Houston, Texas central business district and
related complementary energy services to district cooling customers and others.
The assets and liabilities of this business have been classified in the
Consolidated Balance Sheets as discontinued operations. We recorded an after-tax
loss in discontinued operations of $16.2 million ($25.0 million pre-tax) during
the three months ended June 30, 2003 to record the impairment of the long-lived
asset based on the impending sale and to record one-time employee termination
benefits. The Interim Financial Statements present these operations as
discontinued operations in accordance with SFAS No. 144.
The Interim Financial Statements have been prepared to reflect the effect
of the Reliant Resources Distribution on the CenterPoint Energy financial
statements. The Interim Financial Statements present the Reliant Resources
businesses (previously reported as Wholesale Energy, European Energy and Retail
Energy business segments and related corporate costs) as discontinued
operations, in accordance with SFAS No. 144.
RECENT DEVELOPMENTS
On July 15, 2003, a steam line ruptured at Texas Genco's W.A. Parish coal
facility damaging one of the facility's units and temporarily taking another
unit offline. Texas Genco anticipates that the unit will be out of service
through September 2003. A thorough root cause analysis process is underway and a
detailed repair plan is being implemented. An estimated cost for damage repair
is being developed.
During a routine refueling and maintenance outage in early April 2003,
engineers found a small quantity of residue from reactor cooling water in the
South Texas Project Electric Generating Station (South Texas Project) Unit 1
reactor containment building. Upon discovery of the residue, South Texas Project
officials immediately reported their findings to the Nuclear Regulatory
Commission (NRC). The South Texas Project staff completed repairs on South Texas
Project Unit 1 and the unit was returned to operation on August 9, 2003
following NRC approval.
32
CONSOLIDATED RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------- ------------------------------
2002 2003 2002 2003
--------------- --------------- ------------------------------
(IN MILLIONS, EXCEPT PER SHARE DATA)
Revenues............................................. $ 1,798 $ 2,091 $ 3,876 $ 4,991
Operating Expenses................................... 1,509 1,745 3,235 4,284
--------------- --------------- ------------------------------
Operating Income..................................... 289 346 641 707
Gain (Loss) on AOL Time Warner Investment............ (230) 113 (448) 65
Gain (Loss) on Indexed Debt Securities............... 219 (98) 422 (56)
Interest Expense..................................... (140) (215) (257) (439)
Distribution on Trust Preferred Securities........... (14) (14) (28) (28)
Other, net........................................... 8 1 15 5
Income Tax Expense................................... (46) (44) (114) (85)
Minority Interest.................................... -- (6) -- (4)
--------------- --------------- ------------------------------
Income From Continuing Operations Before Cumulative 86 83 231 165
Effect of Accounting Change........................
Discontinued Operations:
Income From Reliant Resources, net of tax.......... 148 -- 34 --
Income (Loss) From Other Operations, net of tax.... 2 (1) 2 (1)
Loss on Disposal of Other Operations, net of tax.. -- (19) -- (12)
Cumulative Effect of Accounting Change, net of
minority interest and tax......................... -- -- -- 80
--------------- --------------- ------------------------------
Net Income Attributable to Common Shareholders....... $ 236 $ 63 $ 267 $ 232
=============== =============== ==============================
BASIC EARNINGS PER SHARE:
Income From Continuing Operations Before
Cumulative Effect of Accounting Change..........
Income From Continuing Operations Before Cum.... $ 0.29 $ 0.27 $ 0.78 $ 0.54
Discontinued Operations:
Income From Reliant Resources, net of tax........ 0.49 -- 0.11 --
Income (Loss) From Other Operations, net of tax.. 0.01 -- 0.01 --
Loss on Disposal of Other Operations, net of tax -- (0.06) -- (0.04)
Cumulative Effect of Accounting Change, net of
minority interest and tax....................... -- -- -- 0.27
--------------- --------------- ------------------------------
Net Income Attributable to Common Shareholders....... $ 0.79 $ 0.21 $ 0.90 $ 0.77
=============== =============== ==============================
DILUTED EARNINGS PER SHARE:
Income From Continuing Operations Before
Cumulative Effect of Accounting Change........... $ 0.29 $ 0.27 $ 0.78 $ 0.54
Discontinued Operations:
Income From Reliant Resources, net of tax........ 0.49 -- 0.11 --
Income (Loss) From Other Operations, net of tax.. 0.01 -- 0.01 --
Loss on Disposal of Other Operations, net of tax. -- (0.06) -- (0.04)
Cumulative Effect of Accounting Change, net of
minority interest and tax....................... -- -- -- 0.26
--------------- --------------- ------------------------------
Net Income Attributable to Common Shareholders....... $ 0.79 $ 0.21 $ 0.90 $ 0.76
=============== =============== ==============================
THREE MONTHS ENDED JUNE 30, 2003 COMPARED TO THREE MONTHS ENDED JUNE 30, 2002
Income from Continuing Operations. We reported income from continuing
operations before cumulative effect of accounting change of $83 million ($0.27
per diluted share) for the three months ended June 30, 2003 as compared to $86
million ($0.29 per diluted share) for the same period in 2002. The decrease in
income from continuing operations of $3 million was primarily due to the
following:
- a $75 million increase in interest expense due to higher borrowing and
financing costs and increased debt levels;
33
- a $40 million decrease in operating income from our Electric
Transmission & Distribution business segment primarily due to a
reduction in ECOM revenue discussed below; and
- a $6 million change in minority interest.
The above items were partially offset by:
- a $79 million increase in operating income from our Electric
Generation business segment;
- a net gain of $15 million in our AOL Time Warner investment and our
related indexed debt securities in 2003 as compared to a net loss of
$11 million in 2002;
- a $10 million increase in operating income from our Natural Gas
Distribution business segment;
- a $5 million decrease in operating loss from our Other Operations
business segment; and
- a $3 million increase in operating income from our Pipelines and
Gathering business segment.
Income Tax Expense. During the three months ended June 30, 2003 and 2002,
our effective tax rates were 33.2% and 34.7%, respectively. The decrease in the
effective tax rate for 2003 compared to 2002 is primarily the result of a
decrease in state tax expense offset by a decrease to benefits related to the
employee stock ownership plan.
SIX MONTHS ENDED JUNE 30, 2003 COMPARED TO SIX MONTHS ENDED JUNE 30, 2002
Income from Continuing Operations. We reported income from continuing
operations before cumulative effect of accounting change of $165 million ($0.54
per diluted share) for the six months ended June 30, 2003 as compared to $231
million ($0.78 per diluted share) for the same period in 2002. The decrease in
income from continuing operations of $66 million was primarily due to the
following:
- a $182 million increase in interest expense due to higher borrowing
costs and increased debt levels and financing costs;
- an $88 million decrease in operating income from our Electric
Transmission & Distribution business segment primarily due to a
reduction in ECOM revenue discussed below; and
- a $10 million decrease in other income.
The above items were partially offset by:
- a $114 million increase in operating income from our Electric
Generation business segment;
- a $33 million increase in operating income from our Natural Gas
Distribution business segment;
- a net gain of $9 million in our AOL Time Warner investment and our
related indexed debt securities in 2003 as compared to a net loss of
$26 million in 2002; and
- a $29 million decrease in income tax expense.
Income Tax Expense. During the six months ended June 30, 2003 and 2002, our
effective tax rates were 33.6% and 33.0%, respectively.
Cumulative Effect of Accounting Change. In connection with the adoption of
SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), we
have completed an assessment of the applicability and implications of SFAS No.
143. As a result of the assessment, we have identified retirement obligations
for nuclear decommissioning at the South Texas Project and for lignite mine
operations at the Jewett mine supplying the
34
Limestone electric generation facility. The net difference between the amounts
determined under SFAS No. 143 and the previous method of accounting for
estimated mine reclamation costs was $37 million and has been recorded as a
cumulative effect of accounting change. Upon adoption of SFAS No. 143, we
reversed $115 million of previously recognized removal costs with respect to our
non-rate regulated businesses as a cumulative effect of accounting change. The
total cumulative effect of accounting change from adoption of SFAS No. 143 was
$152 million. Excluded from the $80 million after-tax cumulative effect of
accounting change recorded during the three months ended March 31, 2003, is
minority interest of $19 million related to the Texas Genco stock not owned by
CenterPoint Energy. For additional discussion of the adoption of SFAS No. 143,
please read Note 3 to our Interim Financial Statements.
OPERATING INCOME (LOSS) BY BUSINESS SEGMENT
In the second quarter of 2003, we began to evaluate business segment
performance on an operating income basis. Operating income is shown because it
is the measure 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, we evaluated performance on an earnings before interest
expense, minority interest and income taxes (EBIT) basis. Historically, the
difference between EBIT reported on a segment basis and operating income on a
segment basis has not been material.
The following table presents operating income (loss) for each of our
business segments for the three and six months ended June 30, 2002 and 2003.
Some amounts from the previous year have been reclassified to conform to the
2003 presentation of the financial statements. These reclassifications do not
affect consolidated net income.
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------- -------------------------------
2002 2003 2002 2003
--------------- --------------- --------------- ---------------
(IN MILLIONS)
Electric Transmission & Distribution............... $ 275 $ 235 $ 528 $ 440
Electric Generation................................ (29) 50 (81) 33
Natural Gas Distribution........................... 11 21 118 151
Pipelines and Gathering............................ 39 42 76 85
Other Operations................................... (7) (2) -- (2)
--------------- --------------- --------------- ---------------
Total Consolidated Operating Income.......... $ 289 $ 346 $ 641 $ 707
=============== =============== =============== ===============
ELECTRIC TRANSMISSION & DISTRIBUTION
For information regarding factors that may affect the future results of
operations of our Electric Transmission & Distribution business segment, please
read "Risk Factors -- Principal Risk Factors Associated with Our Businesses --
Risk Factors Affecting Our Electric Transmission & Distribution Business," " --
Risk Factors Associated with Our Consolidated Financial Condition" and "-- Other
Risks" in Item 5 of Part II of this report, each of which is incorporated herein
by reference.
35
The following tables provide summary data of our Electric Transmission &
Distribution business segment for the three months and six months ended June 30,
2002 and 2003:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------- -------------------------------
2002 2003 2002 2003
--------------- --------------- --------------- ---------------
(IN MILLIONS)
Operating Revenues:
Electric Revenues................................ $ 358 $ 381 $ 785 $ 696
ECOM True-Up..................................... 170 101 311 233
--------------- --------------- --------------- ---------------
Total Operating Revenues....................... 528 482 1,096 929
--------------- --------------- --------------- ---------------
Operating Expenses:
Purchased Power.................................. (4) -- 56 --
Operation and Maintenance........................ 130 126 270 259
Depreciation and Amortization.................... 66 68 130 133
Taxes Other than Income Taxes.................... 61 53 112 97
--------------- --------------- --------------- ---------------
Total Operating Expenses....................... 253 247 568 489
--------------- --------------- --------------- ---------------
Operating Income................................... $ 275 $ 235 $ 528 $ 440
=============== =============== =============== ===============
Residential throughput (in gigawatt-hours
(GWh))(1)........................................ 6,296 6,490 10,769 11,049
- -------------
(1) This table no longer reflects usage volumes (KWh) for commercial and
industrial customers because the majority of these customers are
billed on a peak demand (KW) basis and, as a result, revenues do not
vary based on consumption.
THREE MONTHS ENDED JUNE 30, 2003 COMPARED TO THREE MONTHS ENDED JUNE 30, 2002
Our Electric Transmission & Distribution business segment reported
operating income of $235 million for the three months ended June 30, 2003,
consisting of $134 million for the regulated electric transmission and
distribution utility and non-cash operating income of $101 million associated
with generation-related regulatory assets, or Excess Cost Over Market (ECOM), as
described below. For the three months ended June 30, 2002, operating income was
$275 million, consisting of $105 million for the regulated electric transmission
and distribution utility and non-cash operating income of $170 million
associated with ECOM. Although our former retail sales business is no longer
conducted by us, retail customers remained regulated customers of the regulated
utility through the date of their first meter reading in 2002. Purchased power
activity of $4 million for the three months ended June 30, 2002 relates to
operation of the regulated utility during this transition period.
The regulated electric transmission and distribution utility continues to
benefit from solid customer growth. Revenues increased from the addition of over
51,000 metered customers since June 2002 ($13 million) as well as the positive
impact of weather ($5 million).
Under the Texas electric restructuring law, a regulated utility may
recover, in its 2004 stranded cost true-up proceeding, any difference between
market prices received through the state mandated auctions and the Texas Utility
Commission's earlier estimates of those market prices. During 2002 and 2003,
this difference, referred to as ECOM, produced non-cash operating income and is
recorded as a regulatory asset. The reduction in ECOM True-Up revenue of $69
million from 2002 to 2003 is primarily a result of lower margins derived from
the ECOM model for this period in 2003 compared to the same period in 2002.
Operation and maintenance expense decreased $4 million for the three months
ended June 30, 2003 as compared to the same period in 2002 primarily due to
reduced staffing levels as a result of process improvements ($4 million) and
decreased transmission cost of service ($2 million), partially offset by
increased pension expense ($4 million).
Depreciation and amortization expense increased $2 million for the three
months ended June 30, 2003 as compared to the same period in 2002 due to
increases in plant in service.
36
Taxes other than income taxes decreased $8 million for the three months
ended June 30, 2003 as compared to the same period in 2002 primarily due to
decreased city franchise fees ($6 million) and decreased state franchise taxes
($4 million), partially offset by increased property taxes ($2 million).
SIX MONTHS ENDED JUNE 30, 2003 COMPARED TO SIX MONTHS ENDED JUNE 30, 2002
Our Electric Transmission & Distribution business segment reported
operating income of $440 million for the six months ended June 30, 2003,
consisting of $207 million for the regulated electric transmission and
distribution utility and non-cash operating income of $233 million associated
with ECOM. For the six months ended June 30, 2002, operating income was $528
million, consisting of $217 million for the regulated electric transmission and
distribution utility and non-cash operating income of $311 million associated
with ECOM. The purchased power costs of $56 million for the six months ended
June 30, 2002 relate to operation of the regulated utility during the transition
period discussed above.
Increased revenues from customer growth ($20 million) and positive impacts
of weather ($5 million) were more than offset by transition period revenues in
2002 ($97 million) and decreased industrial demand.
The reduction in ECOM True-Up revenue of $78 million from 2002 to 2003
primarily resulted from lower margins derived from the ECOM model for this
period in 2003 compared to the same period in 2002.
Operation and maintenance expense decreased $11 million for the six months
ended June 30, 2003 as compared to the same period in 2002. The decrease was
primarily due to a reduction in bad debt expense related to the 2002 transition
period revenues ($15 million), decreased transmission cost of service ($4
million) and the termination of a factoring program ($3 million). These
decreases were partially offset by increased employee benefit expenses primarily
due to increased pension costs ($9 million) and increased insurance expenses ($3
million).
Depreciation and amortization expense increased $3 million for the six
months ended June 30, 2003 as compared to the same period in 2002 primarily due
to increases in plant in service ($5 million), partially offset by decreased
amortization on securitized assets ($2 million).
Taxes other than income taxes decreased $15 million for the six months
ended June 30, 2003 as compared to the same period in 2002 primarily due to
gross receipts tax associated with transition period revenue in the first
quarter of 2002 ($9 million) and decreased state franchise taxes ($6 million).
ELECTRIC GENERATION
For information regarding factors that may affect the future results of
operations of our Electric Generation business segment, please read "Risk
Factors -- Principal Risk Factors Associated with Our Businesses -- Risk Factors
Affecting Our Electric Generation Business," " -- Risk Factors Associated with
Our Consolidated Financial Condition" and "-- Other Risks" in Item 5 of Part II
of this report, each of which is incorporated herein by reference.
37
The following tables provide summary data of our Electric Generation
business segment for the three months and six months ended June 30, 2002 and
2003:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------- -------------------------------
2002 2003 2002 2003
--------------- --------------- --------------- ---------------
(IN MILLIONS)
Operating Revenues:
Energy Revenues.................................. $ 307 $ 378 $ 547 $ 602
Capacity and Other Revenues...................... 107 200 192 335
--------------- --------------- --------------- ---------------
Total Operating Revenues....................... 414 578 739 937
--------------- --------------- --------------- ---------------
Operating Expenses:
Fuel and Purchased Power......................... 299 372 528 592
Operation and Maintenance........................ 79 105 174 211
Depreciation and Amortization.................... 39 39 79 78
Taxes Other than Income Taxes.................... 26 12 39 23
--------------- --------------- --------------- ---------------
Total Operating Expenses....................... 443 528 820 904
--------------- --------------- --------------- ---------------
Operating Income (Loss)............................ $ (29) $ 50 $ (81) $ 33
=============== =============== =============== ===============
Power Sales (in GWh)............................... 14,644 12,517 26,447 21,794
=============== =============== =============== ===============
THREE MONTHS ENDED JUNE 30, 2003 COMPARED TO THREE MONTHS ENDED JUNE 30, 2002
Our Electric Generation business segment reported operating income of $50
million for the three months ended June 30, 2003 compared to a loss of $29
million for the three months ended June 30, 2002. The $79 million improvement
was primarily attributable to increased margins from higher capacity and energy
revenues as a result of higher capacity auction prices driven by higher natural
gas prices, offset by increased fuel costs due to higher natural gas prices and
purchased power costs. Due to the operating flexibility of some of the gas
units, Texas Genco was able to partially mitigate the higher cost of natural gas
by switching from natural gas to fuel oil.
Operation and maintenance expense increased $26 million for the three
months ended June 30, 2003 as compared to the same period in 2002. Approximately
$6 million was associated with higher pension and employee benefits, $6 million
with scheduled plant outages, $4 million with repairs to South Texas Project
Unit 1 and $5 million associated with the timing of technical support costs.
Taxes other than income taxes decreased $14 million for the three months
ended June 30, 2003 as compared to the same period in 2002. This decrease was
primarily attributable to a reduction in state franchise taxes which are no
longer applicable in 2003.
SIX MONTHS ENDED JUNE 30, 2003 COMPARED TO SIX MONTHS ENDED JUNE 30, 2002
Our Electric Generation business segment reported operating income of $33
million for the six months ended June 30, 2003 compared to a loss of $81 million
for the six months ended June 30, 2002. The $114 million improvement was
primarily attributable to increased margins from higher capacity and energy
revenues as a result of higher capacity auction prices driven by higher natural
gas prices, offset by increased fuel costs due to higher natural gas prices and
purchased power costs. Due to the operating flexibility of some of the gas
units, Texas Genco was able to partially mitigate the higher cost of natural gas
by switching from natural gas to fuel oil.
Operation and maintenance expense increased $37 million for the six months
ended June 30, 2003 as compared to the same period in 2002. The increase was
primarily due to repairs on South Texas Project Unit 1 ($4 million), an
unplanned outage on South Texas Project Unit 2 ($4 million), a planned refueling
outage on South Texas Project Unit 1 without a comparable outage in 2002 ($6
million), higher pension and employee benefit costs ($4 million), timing of
technical support expenses ($9 million) and increased insurance and other
expenses ($7 million).
38
Taxes other than income taxes decreased $16 million for the six months
ended June 30, 2003 as compared to the same period in 2002. This decrease was
primarily attributable to a reduction in state franchise taxes that are no
longer applicable in 2003 and a reduction in property taxes due to lower
valuations.
NATURAL GAS DISTRIBUTION
Our Natural Gas Distribution business segment's operations consist of
natural gas sales to, and natural gas transportation for, residential,
commercial and industrial customers in Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma, and Texas. This business segment's operations also
include non-rate regulated natural gas sales to and transportation services for
commercial and industrial customers in the six states listed above as well as
several other Midwestern states.
For information regarding factors that may affect the future results of
operations of our Natural Gas Distribution business segment, please read "Risk
Factors -- Principal Risk Factors Associated with Our Businesses -- Risk Factors
Affecting Our Natural Gas Distribution and Pipelines and Gathering Businesses,"
" -- Risk Factors Associated with Our Consolidated Financial Condition" and "--
Other Risks" in Item 5 of Part II of this report, each of which is incorporated
herein by reference.
The following table provides summary data of our Natural Gas Distribution
business segment for the three months and six months ended June 30, 2002 and
2003:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------- -------------------------------
2002 2003 2002 2003
--------------- --------------- --------------- ---------------
(IN MILLIONS)
Operating Revenues................................. $ 797 $ 971 $ 1,977 $ 3,015
--------------- --------------- --------------- ---------------
Operating Expenses:
Natural Gas...................................... 604 761 1,488 2,455
Operation and Maintenance........................ 125 137 256 284
Depreciation and Amortization.................... 32 34 62 67
Taxes Other than Income Taxes.................... 25 18 53 58
--------------- --------------- --------------- ---------------
Total Operating Expenses....................... 786 950 1,859 2,864
--------------- --------------- --------------- ---------------
Operating Income................................... $ 11 $ 21 $ 118 $ 151
=============== =============== =============== ===============
Throughput (in billion cubic feet (Bcf)):
Residential and Commercial....................... 49 36 181 192
Industrial....................................... 13 12 24 24
Transportation................................... 13 11 28 26
Non-rate Regulated Commercial and Industrial..... 96 111 217 245
--------------- --------------- --------------- ---------------
Total Throughput............................... 171 170 450 487
=============== =============== =============== ===============
THREE MONTHS ENDED JUNE 30, 2003 COMPARED TO THREE MONTHS ENDED JUNE 30, 2002
Our Natural Gas Distribution business segment's operating income increased
$10 million for the three months ended June 30, 2003 as compared to the same
period in 2002. Operating margins (revenues less fuel costs) for the three
months ended June 30, 2003 were $17 million higher than in the same period in
2002 primarily because of:
- higher revenues from rate increases late in 2002 ($9 million);
- improved margins from our unregulated commercial and industrial sales
($3 million); and
- continued customer growth ($1 million).
These increases were partially offset by increased operating expenses as
discussed below.
Operation and maintenance expense increased $12 million for the three
months ended June 30, 2003 as compared to the same period in 2002. The increase
in operations and maintenance expense was primarily due to:
39
- higher employee benefit expenses primarily due to increased pension
costs ($8 million); and
- 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).
SIX MONTHS ENDED JUNE 30, 2003 COMPARED TO SIX MONTHS ENDED JUNE 30, 2002
Our Natural Gas Distribution business segment's operating income increased
$33 million for the six months ended June 30, 2003 as compared to the same
period in 2002. Operating margins (revenues less fuel costs) for the six months
ended June 30, 2003 were $71 million higher than in the same period in 2002
primarily because of:
- higher revenues from rate increases late in 2002 ($20 million);
- improved margins from our unregulated commercial and industrial
sales ($12 million);
- franchise fees billed to customers ($7 million);
- continued customer growth ($5 million); and
- colder weather ($4 million).
These increases were partially offset by increased operating expenses as
discussed below.
Operation and maintenance expense increased $28 million for the six months
ended June 30, 2003 as compared to the same period in 2002. The increase in
operations and maintenance expense was primarily due to:
- higher employee benefit expenses primarily due to increased pension
costs ($12 million);
- 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
- increased bad debt expense primarily due to colder weather and
higher gas prices ($2 million).
Depreciation and amortization expense increased $5 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 $5 million for the six months ended
June 30, 2003 as compared to the same period in 2002, primarily due to franchise
fees resulting from higher revenue ($7 million).
40
PIPELINES AND GATHERING
Our Pipelines and Gathering business segment operates two interstate
natural gas pipelines and provides gathering and pipeline services.
For information regarding factors that may affect the future results of
operations of our Pipelines and Gathering business segment, please read "Risk
Factors -- Principal Risk Factors Associated with Our Businesses -- Risk Factors
Affecting Our Natural Gas Distribution and Pipelines and Gathering Businesses,"
" -- Risk Factors Associated with Our Consolidated Financial Condition" and "--
Other Risks" in Item 5 of Part II of this report, each of which is incorporated
herein by reference.
The following table provides summary data of our Pipelines and Gathering
business segment for the three months and six months ended June 30, 2002 and
2003:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------- -------------------------------
2002 2003 2002 2003
--------------- --------------- --------------- ---------------
(IN MILLIONS)
Operating Revenues................................. $ 102 $ 122 $ 194 $ 231
--------------- --------------- --------------- ---------------
Operating Expenses:
Natural Gas...................................... 10 35 17 56
Operation and Maintenance........................ 38 30 72 60
Depreciation and Amortization.................... 10 11 20 21
Taxes Other than Income Taxes.................... 5 4 9 9
--------------- --------------- --------------- ---------------
Total Operating Expenses....................... 63 80 118 146
--------------- --------------- --------------- ---------------
Operating Income................................... $ 39 $ 42 $ 76 $ 85
=============== =============== =============== ===============
Throughput (in Bcf):
Sales ........................................... 5 4 10 8
Transportation................................... 205 203 443 471
Gathering........................................ 70 74 141 146
Elimination (1).................................. (1) (2) (1) (4)
--------------- --------------- --------------- ---------------
Total Throughput................................... 279 279 593 621
=============== =============== =============== ===============
- -------------
(1) Elimination of volumes both transported and sold.
THREE MONTHS ENDED JUNE 30, 2003 COMPARED TO THREE MONTHS ENDED JUNE 30, 2002
Our Pipelines and Gathering business segment's operating income for the
three months ended June 30, 2003 compared to the same period in 2002 increased
$3 million. Operating margins (revenues less natural gas costs) were $5 million
lower for the three months ended June 30, 2003 than in the same period in 2002
primarily due to:
- reduced project-related revenues ($10 million); and
- a one-time refund of a tax on fuel in 2002 ($3 million),
partially offset by;
- improved margins from new transportation contracts to power plants
($4 million);
- improved margins from enhanced services in our gas gathering
operations ($2 million); and
- higher commodity prices ($2 million).
Operation and maintenance expenses decreased $8 million for the three
months ended June 30, 2003 compared to the same period in 2002 primarily due to
the decrease in project-related costs ($10 million).
41
SIX MONTHS ENDED JUNE 30, 2003 COMPARED TO SIX MONTHS ENDED JUNE 30, 2002
Our Pipelines and Gathering business segment's operating income for the six
months ended June 30, 2003 compared to the same period in 2002 increased $9
million. Operating margins (revenues less natural gas costs) were $2 million
lower for the six months ended June 30, 2003 than in the same period in 2002
primarily due to:
- reduced project-related revenues ($15 million); and
- a one-time refund of a tax on fuel in 2002 ($3 million), partially
offset by;
- higher commodity prices ($6 million);
- higher commodity prices ($6 million);
- improved margins from new transportation contracts to power plants
($5 million); and
- improved margins from enhanced services in our gas gathering
operations ($3 million).
Operation and maintenance expenses decreased $12 million for the six months
ended June 30, 2003 compared to the same period in 2002 primarily due to the
decrease in project-related costs ($15 million).
OTHER OPERATIONS
Our Other Operations business segment includes other corporate operations
which support all of our business operations.
The following table provides summary data of our Other Operations business
segment for the three months and six months ended June 30, 2002 and 2003:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------- -------------------------------
2002 2003 2002 2003
--------------- --------------- --------------- ---------------
(IN MILLIONS)
Operating Revenues................................. $ 7 $ 9 $ 14 $ 18
Operating Expenses................................. 14 11 14 20
--------------- --------------- --------------- ---------------
Operating Loss..................................... $ (7) $ (2) $ -- $ (2)
=============== =============== =============== ===============
DISCONTINUED OPERATIONS
In February 2003, we sold our interest in Argener, a cogeneration facility
in Argentina, for $23 million. The carrying value of this investment was
approximately $11 million as of December 31, 2002. We recorded an after-tax gain
of $7 million from the sale of Argener in the first quarter of 2003. In April
2003, we sold our final remaining investment in Argentina, a 90 percent interest
in Empresa Distribuidora de Electricidad de Santiago del Estero S.A. (Edese). We
recorded an after-tax loss of $3 million in the second quarter of 2003 related
to our Latin America operations. We have completed our strategy of exiting Latin
America. The Interim Financial Statements present these operations as
discontinued operations in accordance with SFAS No. 144.
On September 30, 2002, we distributed to our shareholders on a pro rata
basis all of the shares of Reliant Resources common stock owned by us. The
Interim Financial Statements have been prepared to reflect the effect of the
Reliant Resources Distribution as described above on our Interim Financial
Statements. The Interim Financial Statements present the Reliant Resources
businesses (Wholesale Energy, European Energy, Retail Energy and related
corporate costs) as discontinued operations. We recorded after-tax income from
discontinued operations of $148 million and $34 million for the three months and
six months ended June 30, 2002, respectively, related to the operations of
Reliant Resources.
We are negotiating to sell a component of our Other Operations business
segment, CEMS, that provides district cooling services in the Houston, Texas
central business district and related complementary energy services to district
cooling customers and others. The assets and liabilities of this business have
been classified in the Consolidated Balance Sheets as discontinued operations.
We recorded an after-tax loss in discontinued operations of $16 million ($25
million pre-tax) during the three months ended June 30, 2003 to record the
impairment of the long-lived asset
42
based on the impending sale and to record one-time termination benefits. The
Interim Financial Statements present these operations as discontinued operations
in accordance with SFAS No. 144.
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
For information on other developments, factors and trends that may have an
impact on our future earnings, please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations and Selected Financial Data --
Certain Factors Affecting Future Earnings" in Exhibit 99.1 to the Current Report
on Form 8-K dated May 12, 2003 (May 12 Form 8-K), and "Risk Factors" in Item 5
of Part II of this report, each of which is incorporated herein by reference.
In addition to these factors, increased borrowing costs and increased
pension expense are expected to negatively impact our earnings in 2003.
Additionally, please read the discussion of the South Texas Project Unit 1 and
W.A. Parish facility forced outages under "-- Overview -- Recent Developments."
LIQUIDITY AND CAPITAL RESOURCES
HISTORICAL CASH FLOWS
The following table summarizes the net cash provided by (used in)
operating, investing and financing activities for the six months ended June 30,
2002 and 2003:
SIX MONTHS ENDED JUNE 30,
--------------------------------------
2002 2003
------------------ -------------------
(IN MILLIONS)
Cash provided by (used in):
Operating activities..................................................... $ 83 $ 244
Investing activities..................................................... (425) (301)
Financing activities..................................................... 572 (211)
Net cash provided by operating activities during the six months ended June
30, 2003 increased $161 million compared to the same period in 2002 primarily
due to decreases in accounts receivable and accrued unbilled revenues and
accrued taxes and interest, partially offset by recovery of fuel by our Electric
Transmission & Distribution business segment in 2002.
Net cash used in investing activities decreased $124 million during the six
months ended June 30, 2003 compared to the same period in 2002 primarily due to
lower capital expenditures in 2003 related to our Electric Transmission &
Distribution and Electric Generation business segments.
Net cash used in financing activities increased $783 million during the six
months ended June 30, 2003 compared to the same period in 2002 primarily due to
a decrease in short-term borrowings, partially offset by an increase in net
proceeds from long-term debt.
FUTURE SOURCES AND USES OF CASH FLOWS
The 1935 Act regulates our financing ability, as more fully described in "--
Capitalization" below.
Long-Term Debt. Our long-term debt consists of our obligations and
obligations of our subsidiaries, including transition bonds issued by an
indirect wholly owned subsidiary (transition bonds).
In 2003, we and our subsidiaries completed several capital market and bank
financing transactions which, collectively, converted a significant amount of
our interest payment obligations from floating rates to fixed rates and reduced
current maturities of long-term debt (excluding maturities of transition bonds
issued by a special purpose entity) from $792 million at December 31, 2002 to
$269 million at June 30, 2003. Certain of the capital market transactions
enabled us to permanently reduce the term loan due 2005 under our bank facility,
which currently bears interest at LIBOR plus 450 basis points, from $2.35
billion to $1.35 billion, to eliminate an obligation under our bank facility to
issue the lenders warrants for our common stock and to eliminate a limitation on
common stock dividends that would have become applicable in 2004. Repayments of
the term loan permanently reduce the size of our bank
43
facility, whereas repayments of the revolver component of our bank facility do
not. Our 2003 capital market transactions included the following:
- In May, we issued $575 million aggregate principal amount of 3.75%
convertible senior notes due 2023, $200 million aggregate principal
amount of 5.875% senior notes due 2008 and $200 million aggregate
principal amount of 6.85% senior notes due 2015. In addition, in
April, we remarketed $175 million aggregate principal amount of
pollution control tax-exempt bonds that we had owned since the
fourth quarter of 2002, consisting of $100 million bearing interest
at 7.75% due 2018 and $75 million bearing interest at 8% due 2029.
Proceeds from these financings were used to repay portions of our
borrowings under our bank facility, including a $954 million
permanent reduction in our term loan due in 2005. In July, we
remarketed $151 million aggregate principal amount of
insurance-backed pollution control bonds due 2015, reducing the
interest rate from 5.8% to 4%.
- In March and May, CenterPoint Houston issued $962.3 million
aggregate principal amount of its general mortgage bonds, consisting
of $450 million bearing interest at 5.70% due 2013, $312.3 million
bearing interest at 6.95% due 2033 and $200 million bearing interest
at 5.60% due 2023. Proceeds were used by CenterPoint Houston to
redeem $512.3 million aggregate principal amount of its first
mortgage bonds ($250 million at 7.75% due 2023, $62.3 million at
8.75% due 2022 and $200 million at 7.5% due 2023) and to repay $429
million of intercompany notes payable to us and bearing interest at
a weighted average rate of 6.11%. We used proceeds from the
intercompany note repayment to repay $150 million of 6.5% medium
term notes due in April 2003, $229 million of revolving credit
borrowings under our bank facility and $50 million of the term loan
under our bank facility.
- In March and April, CERC issued $762 million aggregate principal
amount of its 7.875% senior notes due 2013, the proceeds from which
were used to refinance $360 million aggregate principal amount of
CERC's $500 million aggregate principal amount of 6?% Term Enhanced
ReMarketable Securities 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 CERC's $350 million credit facility having a
termination date of March 31, 2003. CERC replaced the matured credit
facility with a new $200 million revolving credit facility that
matures in March 2004.
We have $840 million of outstanding 2.0% Zero-Premium Exchangeable
Subordinated Notes due 2029 (ZENS) that may be exchanged for cash at any time.
Holders of ZENS submitted for exchange are entitled to receive a cash payment
equal to 95% of the market value of the reference shares of AOL Time Warner
common stock (AOL TW Common). There are 1.5 reference shares of AOL TW Common
for each of the 17.2 million ZENS units originally issued (of which
approximately 16% were exchanged for cash of approximately $45 million in 2002).
The exchange market value is calculated using the average closing price per
share of AOL TW Common on the New York Stock Exchange on one or more trading
days following the notice date for the exchange. One of our subsidiaries owns
the reference shares of AOL TW Common and generally liquidates such holdings to
the extent of ZENS exchanged. Cash proceeds from such liquidations are used to
fund ZENS exchanged for cash. Although proceeds from the sale of AOL TW Common
offset the cash paid on exchanges, ZENS exchanges result in a cash outflow
because deferred tax liabilities related to the ZENS and AOL TW Common become
current tax obligations when ZENS are exchanged and AOL TW Common is sold. There
have been no ZENS exchanges in 2003.
CenterPoint Houston has outstanding approximately $499 million aggregate
principal amount of first mortgage bonds and approximately $2.8 billion
aggregate principal amount of general mortgage bonds, of which approximately
$924 million combined aggregate principal amount of first mortgage bonds and
general mortgage bonds collateralizes debt of CenterPoint Energy. The lien of
the general mortgage indenture (under which the general mortgage bonds are
issued) is junior to that of the first mortgage indenture (under which the first
mortgage bonds are issued). While the aggregate amount of additional general
mortgage bonds and first mortgage bonds that could be issued is approximately
$680 million based on estimates of the value of CenterPoint Houston's property
encumbered by the general mortgage, the cost of such property and the 70%
bonding ratio contained in the general mortgage, as a result of contractual
limitations on CenterPoint Houston and CenterPoint Energy expiring in November
2005, the aggregate amount of first mortgage and general mortgage bonds cannot
be increased above current levels.
44
The Texas electric restructuring law allows the former integrated utility to
recover its stranded costs in order to fully recover its generation investment
in a "true-up" proceeding to be held in 2004 (2004 True-Up Proceeding).
Following the unbundling of the integrated utility into its components,
CenterPoint Houston remains a regulated transmission and distribution utility
through which stranded investment is recovered. Since CenterPoint Houston does
not own the once-regulated generating assets, it is obligated to distribute
recovery of stranded investment to CenterPoint Energy, the ultimate owner of
these generation assets.
The $396 million impairment that was recorded in the first quarter of 2003
related to the partial distribution of our investment in Texas Genco. Since
this amount is expected to be recovered in the 2004 True-Up Proceeding,
CenterPoint Houston has recorded a regulatory asset reflecting its right to
recover this amount and an associated payable to us. Any additional impairment
or loss that CenterPoint Energy incurs on its Texas Genco investment that
CenterPoint Houston expects to recover as stranded investment will be recorded
in the same manner.
One of our indirect finance subsidiaries, CenterPoint Energy Transition Bond
Company, LLC, has $729 million aggregate principal amount of outstanding
transition bonds that were issued in 2001 in accordance with the Texas electric
restructuring law. Classes of the transition bonds have final maturity dates of
September 15, 2007, September 15, 2009, September 15, 2011 and September 15,
2015 and bear interest at rates of 3.84%, 4.76%, 5.16% and 5.63%, respectively.
The transition bonds are secured by "transition property," as defined in the
Texas electric restructuring law, which includes the irrevocable right to
recover, through non-bypassable transition charges payable by retail electric
customers, qualified costs provided in the Texas electric restructuring law. The
transition bonds are reported as our long-term debt, although the holders of the
transition bonds have recourse only to the assets or revenues of the transition
bond company, and our other creditors have no recourse to any assets or revenues
(including, without limitation, the transition charges) of the transition bond
company. CenterPoint Houston, the transition bond company's direct parent
company, has no payment obligations with respect to the transition bonds except
to remit collections of transition charges as set forth in a servicing agreement
between CenterPoint Houston and the transition bond company and in an
intercreditor agreement among CenterPoint Houston, the transition bond company
and other parties.
Short-Term Debt and Receivables Facility. CERC's revolver and receivables
facility are scheduled to terminate on the dates indicated. Please read Note
9(c) to our Interim Financial Statements regarding CERC's receivables facility.
AMOUNT
OUTSTANDING AS OF
BORROWER/ SELLER TYPE OF FACILITY AMOUNT OF FACILITY JUNE 30, 2003 TERMINATION DATE
---------------- ---------------- ------------------ ------------- ----------------
(IN MILLIONS)
CERC Receivables $ 100 $ 73 November 14, 2003
CERC Corp. Revolver 200 -- March 23, 2004
------ ------
Total $ 300 $ 73
====== ======
Rates for borrowings under CERC Corp.'s 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 the
CERC 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 CERC were pledged to a gas supplier to
secure obligations incurred in connection with the purchase of gas by CERC.
45
On June 30, 2003, we had no temporary investments.
Refunds to CenterPoint Houston Customers. An order issued by the Texas
Utility Commission on October 3, 2001 established the transmission and
distribution rates that became effective in January 2002. The Texas Utility
Commission determined that CenterPoint Houston had overmitigated its stranded
costs by redirecting transmission and distribution depreciation and by
accelerating depreciation of generation assets (an amount equal to earnings
above a stated overall rate of return on rate base that was used to recover our
investment in generation assets) as provided under the 1998 transition plan and
the Texas electric restructuring law. In this final order, CenterPoint Houston
was required to reverse the amount of redirected depreciation and accelerated
depreciation taken for regulatory purposes as allowed under the transition plan
and the Texas electric restructuring law. In accordance with the October 3, 2001
order, CenterPoint Houston recorded a regulatory liability to reflect the
prospective refund of the accelerated depreciation and in January 2002
CenterPoint Houston began refunding excess mitigation credits, which are to be
refunded over a seven-year period. The annual refund of excess mitigation
credits is approximately $237 million. Under the Texas electric restructuring
law, a final determination of these stranded costs will occur in the 2004
True-Up Proceeding. CenterPoint Houston is currently seeking authority from the
Texas Utility Commission to terminate these refunds based on preliminary
estimates of what that final determination will be.
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:
- approximately $386 million of capital expenditures;
- an estimated $126 million in refunds of excess mitigation credit
described above;
- remarketing or refinancing of $140 million of CERC Corp. debt, 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) as discussed in "Quantitative
and Qualitative Disclosures About Market Risk -- Interest Rate Risk"
in Item 3 of this report;
- dividend payments on CenterPoint Energy common stock; and
- $16.6 million of maturing long-term debt (excluding approximately
$12.4 million of expected repayments on transition bonds issued by a
special purpose subsidiary of CenterPoint Houston).
We expect that our current liquidity, along with anticipated cash flows from
operations, revolving credit borrowings and, to the extent permitted by our bank
facility and the external debt agreements of our subsidiaries, proceeds from
possible capital market transactions, will be sufficient to meet our cash needs
for the remainder of 2003. Currently, these agreements limit application of the
proceeds from capital markets transactions to the refinancing of debt existing
in the fall of 2002. 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
distributions from our subsidiaries.
46
At June 30, 2003, CenterPoint Energy had a shelf registration statement
covering 15 million shares of common stock and CERC Corp. 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:
- general economic and capital market conditions;
- credit availability from financial institutions and other lenders;
- investor confidence in us and the market in which we operate;
- maintenance of acceptable credit ratings;
- market expectations regarding our future earnings and probable cash
flows;
- market perceptions of our ability to access capital markets on
reasonable terms;
- our exposure to Reliant Resources in connection with its
indemnification obligations arising in connection with its
separation from us;
- provisions of relevant tax and securities laws; and
- our ability to obtain approval of specific financing transactions
under the 1935 Act.
We may access the bank and capital markets to refinance debt that is not
scheduled to mature in the next twelve months.
Principal Factors Affecting Cash Requirements in 2004 and 2005. We
anticipate selling our 81% ownership interest in Texas Genco in 2004. Should
Reliant Resources decline to exercise its option to purchase our interest in
Texas Genco, we will explore other alternatives to monetize Texas Genco's
assets, including possible sale of our ownership interest in Texas Genco or of
its individual generating assets, which may significantly affect the timing of
any cash proceeds. Proceeds from that sale, plus proceeds from the
securitization in 2004 or 2005 of stranded costs related to generating assets of
Texas Genco and generation-related regulatory assets, are expected to aggregate
in excess of $5 billion based on the current stock price of Texas Genco and
Texas Utility Commission rules.
We expect that upon completion of the 2004 True-Up Proceeding, CenterPoint
Houston will issue securitization bonds to monetize and recover its stranded
costs, any regulatory assets not previously securitized by the October 2001
issuance of transition bonds and, to the extent permitted by the Texas Utility
Commission, the balance of the other true-up components. The issuance will be
done pursuant to a financing order to be issued by the Texas Utility Commission.
As with the debt of our existing transition bond company, payments on these new
securitization bonds would also be made from funds obtained through
non-bypassable charges assessed to retail electric providers required to take
delivery service from CenterPoint Houston. The holders of the new securitization
bonds would have recourse only to the assets or revenues of the issuer of the
new securitization bonds, and our other creditors would not have recourse to any
assets or revenues of that issuer. All or a portion of the proceeds from the
issuance of securitization bonds remaining after repayment of CenterPoint
Houston's $1.3 billion collateralized term loan are expected to be utilized to
retire other existing debt.
47
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 senior debt of CenterPoint Energy and
certain subsidiaries:
MOODY'S S&P FITCH
------------------ ------------------- ------------------
COMPANY/INSTRUMENT RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3)
------------------ ------ ---------- ------ ---------- ------ ----------
CenterPoint Energy Senior Unsecured Debt... Ba1 Negative BBB- Stable BBB- Stable
CenterPoint Houston Senior Secured Debt
(First Mortgage Bonds)..................... Baa2 Stable BBB Stable BBB+ Stable
CERC Corp. Senior Debt..................... Ba1 Negative BBB Stable BBB Stable
- ----------
(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. A "stable" outlook from Moody's indicates that
Moody's does not expect to put the rating on review for an upgrade or
downgrade within 18 months from when the outlook was assigned or last
affirmed.
(2) 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 and the
execution of our commercial strategies.
A decline in credit ratings would increase facility fees and borrowing costs
under our existing bank credit facilities. 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 facilities contain "material adverse change" clauses that could
impact our ability to make new borrowings under these facilities. The "material
adverse change" clauses in our bank facilities generally relate to an event,
development or circumstance that has or would reasonably be expected to have a
material adverse effect on (a) the business, financial condition or operations
of the borrower and its subsidiaries taken as a whole, or (b) the legality,
validity or enforceability of the loan documents.
The $100 million receivables facility of CERC 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.
Each ZENS note is exchangeable at the holder's option at any time for an
amount of cash equal to 95% of the market value of the reference shares of AOL
TW Common attributable to each ZENS note. If our creditworthiness were to drop
such that ZENS note holders thought our liquidity was adversely affected or the
market for the ZENS notes were to become illiquid, some ZENS holders might
decide to exchange their ZENS for cash. Funds for the payment of cash upon
exchange could be obtained from the sale of the AOL TW Common that we own or
from other sources. We own shares of AOL TW Common equal to 100% of the
reference shares used to calculate our obligation to the holders of the ZENS
notes. ZENS exchanges result in a cash outflow because deferred tax liabilities
related to the ZENS and AOL TW Common become current tax obligations when ZENS
are exchanged and AOL TW Common is sold.
48
CenterPoint Energy Gas Resources Corp., a wholly owned subsidiary of CERC
Corp., provides comprehensive natural gas sales and services to industrial and
commercial customers who 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 require a party to provide additional collateral on two business
days' notice when that party's rating or the rating of a credit support provider
for that party (CERC Corp. in this case) falls below those levels. As of July
31, 2003, the senior unsecured debt of CERC Corp. 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. Under our bank facility, a payment default on, or a
non-payment default that permits acceleration of, any indebtedness exceeding $50
million by us or any of our significant subsidiaries will cause a default.
Pursuant to our indenture dated as of May 19, 2003 with JPMorgan Chase Bank, as
supplemented, a payment default by us, CERC Corp. or CenterPoint Houston in
respect of, or an acceleration of, borrowed money and certain other specified
types of obligations in the aggregate principal amount of $50 million will
cause a default. Our 3.75% senior convertible notes due 2023, our 5.875% senior
notes due 2008 and our 6.85% senior notes due 2015 are issued under this
indenture. A default by CenterPoint Energy would not trigger a default under our
subsidiaries' debt instruments.
Pension Plan. As discussed in Note 11(b) of the notes to the consolidated
financial statements included in Exhibit 99.2 to the May 12 Form 8-K
(CenterPoint Energy Notes), which is incorporated herein by reference, we
maintain a non-contributory pension plan covering substantially all employees.
At December 31, 2002, the projected benefit obligation exceeded the market value
of plan assets by $496 million. We are not required to make, and do not
anticipate making, any contributions to our pension plan prior to 2004. Changes
in interest rates and the market values of the securities held by the plan
during 2003 could materially, positively or negatively, change our underfunded
status and affect the level of pension expense and required contributions in
2004 and beyond. For example, every .5% difference in our actual 2003 asset
returns versus our assumed 9% long-term asset return rate would increase or
decrease the underfunded status of our plans by approximately $5 million and our
2004 pension expense by approximately $1 million. Similarly, a .5% change in the
discount rate used to value pension liabilities at December 31, 2003, could
increase or decrease the underfunded status of our plans by approximately $100
million and 2004 pension expense by approximately $14 million. Actual investment
returns and changes in the discount rate during 2003 will have no effect on our
2003 pension expense. Additionally, we expect that a separate pension plan will
be established for Texas Genco in 2004. Texas Genco would receive an allocation
of assets from the CenterPoint Energy pension plan pursuant to rules and
regulations under the Employee Retirement Income Security Act of 1974 and record
its pension obligations in accordance with SFAS No. 87, "Employer's Accounting
for Pensions." It is anticipated that a plan established for Texas Genco would
be underfunded and that such underfunding could be significant. Changes in
interest rates and the market values of the securities held by the CenterPoint
Energy pension plan during 2003 could materially, positively or negatively,
change the funding status of a plan established for Texas Genco.
Other Factors that Could Affect Cash Requirements. In addition to the
above factors, our liquidity and capital resources could be affected by:
- cash collateral requirements that could exist in connection with
certain contracts, including our gas purchases, gas price hedging
and gas storage activities of our Natural Gas Distribution business
segment particularly given gas price levels and volatility;
- acceleration of payment dates on certain gas supply contracts under
certain circumstances, as a result of increased gas prices and
concentration of suppliers;
- increased costs related to the acquisition of gas for storage;
- increases in interest expense in connection with debt refinancings;
- various regulatory actions; and
- the ability of Reliant Resources and its subsidiaries to satisfy
their obligations as the principal customers of
49
CenterPoint Houston and Texas Genco and in respect of its indemnity
obligations to us.
Money Pool. We have a "money pool" through which our participating
subsidiaries can borrow or invest on a short-term basis. Funding needs are
aggregated and external borrowing or investing is based on the net cash
position. The money pool's net funding requirements are expected to be met with
bank loans. The terms of the money pool are in accordance with requirements
applicable to registered public utility holding companies under the 1935 Act and
the June 2003 Financing Order. Currently, Texas Genco participates in our money
pool. If Texas Genco obtains certification by the Federal Energy Regulatory
Commission as an "exempt wholesale generator" (which certification we plan to
seek), under the 1935 Act it will no longer be able to participate with our
utility subsidiaries in the same money pool and will be required to maintain its
own liquidity facility or participate in a separate money pool from the
regulated utilities.
Capitalization. Factors affecting our capitalization include:
- covenants and other provisions in our and our subsidiaries' bank
facilities and other borrowing agreements; and
- limitations imposed on us as a registered public utility holding
company under the 1935 Act.
The collateralized term loan of CenterPoint Houston limits CenterPoint
Houston's debt, excluding transition bonds, as a percentage of its total
capitalization to 68%. CERC Corp.'s bank facility and its receivables facility
limit CERC's debt as a percentage of its total capitalization to 60% and contain
an earnings before interest, taxes, depreciation and amortization (EBITDA) to
interest covenant. CERC Corp.'s bank facility also contains a provision that
could, under certain circumstances, limit the amount of dividends that could be
paid by CERC Corp. Our $2.85 billion credit agreement limits dividend payments
as described above, contains a debt to EBITDA covenant, an EBITDA to interest
covenant and restrictions on the use of proceeds from debt issuances and asset
sales.
We are a registered public utility holding company under the 1935 Act. The
1935 Act and related rules and regulations impose a number of restrictions on
our activities and those of our subsidiaries. The 1935 Act, among other things,
limits our ability to issue debt and equity securities without prior
authorization, restricts the source of dividend payments to current and retained
earnings without prior authorization, regulates sales and acquisitions of
certain assets and businesses and governs affiliate transactions.
We received an order from the SEC relating to our financing activities and
those of our subsidiaries on June 30, 2003 (June 2003 Financing Order), which is
effective until June 30, 2005. On August 1, 2003, the SEC issued a supplemental
order (August 2003 Financing Order, and together with the June 2003 Financing
Order, the Orders) permitting CenterPoint Houston to issue an additional $250
million of debt securities. The SEC had reserved jurisdiction over this
additional amount in the June 2003 Financing Order. Those amounts are included
in the financing discussion below.
The Orders establish limits on the amount of external debt and equity
securities that can be issued by us and certain of our subsidiaries without
additional authorization and permits refinancing. Each of us and our
subsidiaries is in compliance with the authorized limits. Discussed below are
the incremental amounts of debt and equity that we are authorized to issue in
addition to amounts outstanding at June 30, 2003. The June 2003 Financing Order
also permits utilization of undrawn bank facilities at CenterPoint Energy and
CERC at June 30, 2003.
- CenterPoint Energy is authorized to issue an additional aggregate
$250 million of preferred stock, preferred securities and
equity-linked securities and 200 million shares of common stock;
- CenterPoint Houston is authorized to issue an additional aggregate
$500 million of debt and an aggregate $250 million of preferred
stock and preferred securities;
- CERC is authorized to issue an additional aggregate $250 million of
preferred stock and preferred securities; and
- Texas Genco is authorized to issue an aggregate $250 million of
debt.
In the June 2003 Financing Order, the SEC reserved jurisdiction over the
issuance of $478 million additional debt at CenterPoint Energy and $500 million
additional debt at CERC. Further action would be needed from the SEC for
authority to issue this debt.
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The June 2003 Financing Order requires that if we or any of our
subsidiaries issues 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 that issuer 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.
The 1935 Act requires the payment of dividends out of current and retained
earnings without specific authorization to pay dividends from other funds. The
SEC has reserved jurisdiction over payment of $500 million of dividends from
CenterPoint Energy's unearned surplus or capital. Further authority would be
required for authorization to make those payments. As of June 30, 2003, we had
negative retained earnings. We expect to pay dividends out of current earnings.
The June 2003 Financing Order requires that CenterPoint Houston, CERC and Texas
Genco maintain a ratio of equity to total capitalization of 30%.
In July 2003, we requested authority from the SEC to issue debt that is
secured by Texas Genco stock in an amount of up to $2.85 billion in connection
with any extension or refinancing of our existing obligations under our bank
facility. That request is pending.
Security Interests in Receivables of Reliant Resources. Pursuant to a Master
Power Purchase and Sale Agreement (as amended) with a subsidiary of Reliant
Resources related to ERCOT power sales, Texas Genco has been granted a
security interest in accounts receivable and/or notes associated with the
accounts receivable of certain subsidiaries of Reliant Resources to secure up to
$250 million in purchase obligations.
CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one that is both important to the
presentation of our financial condition and results of operations and requires
management to make difficult, subjective or complex accounting estimates. An
accounting estimate is an approximation made by management of a financial
statement element, item or account in the financial statements. Accounting
estimates in our historical consolidated financial statements measure the
effects of past business transactions or events, or the present status of an
asset or liability. The accounting estimates described below require us to make
assumptions about matters that are highly uncertain at the time the estimate is
made. Additionally, different estimates that we could have used or changes in an
accounting estimate that are reasonably likely to occur could have a material
impact on the presentation of our financial condition or results of operations.
The circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be predicted with certainty. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes. We believe the following critical accounting policies involve the
application of accounting estimates for which a change in the estimate is
inseparable from the effect of a change in accounting principle. Accordingly,
these accounting policies have been reviewed and discussed with the audit
committee of the board of directors.
ACCOUNTING FOR RATE REGULATION
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS No. 71), provides that rate-regulated entities account for and report
assets and liabilities consistent with the recovery of those incurred costs in
rates if the rates established are designed to recover the costs of providing
the regulated service and if the competitive environment makes it probable that
such rates can be charged and collected. Application of SFAS No. 71 to the
electric generation portion of our business was discontinued as of June 30,
1999. Our Electric Transmission & Distribution business continues to apply SFAS
No. 71 which results in our accounting for the regulatory effects of recovery of
"stranded costs" and other "regulatory assets" resulting from the unbundling of
the transmission and distribution business from our electric generation
operations in our consolidated financial statements. Certain expenses and
revenues subject to utility regulation or rate determination normally reflected
in income are deferred on the balance sheet and are recognized in income as the
related amounts are included in service rates and recovered from or refunded to
customers. Regulatory assets reflected in our Consolidated Balance Sheets
aggregated $4.0 billion and $4.5 billion as
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of December 31, 2002 and June 30, 2003, respectively. Additionally, regulatory
liabilities reflected in our consolidated Balance Sheets aggregated $1.1 billion
and 0.9 billion at December 31, 2002 and June 30, 2003, respectively.
Significant accounting estimates embedded within the application of SFAS No. 71
with respect to our Electric Transmission & Distribution business segment relate
to $2.5 billion of recoverable electric generation plant mitigation assets
(stranded costs) and $929 million of ECOM true-up as of June 30, 2003. The
stranded costs are comprised of $1.1 billion of previously recorded accelerated
depreciation and $841 million of previously redirected depreciation as well as
$396 million related to the Texas Genco distribution. These stranded costs are
recoverable under the provisions of the Texas electric restructuring law. The
ultimate amount of stranded cost recovery is subject to a final determination,
which will occur in 2004, and is contingent upon the market value of Texas
Genco. Any significant changes in our accounting estimate of stranded costs as a
result of current market conditions or changes in the regulatory recovery
mechanism currently in place could result in a material write-down of all or a
portion of these regulatory assets.
The Texas electric restructuring law allows recovery of the difference
between the prices for power sold in state mandated auctions and earlier
estimates of market power prices by the Texas Utility Commission. This
calculation (the ECOM Calculation) compares (1) an imputed margin that reflects
the difference between actual market power prices received in the state mandated
auctions, actual fuel expense and generation, and (2) the margin resulting from
the Texas Utility Commission's estimates of power prices, fuel expense and
generation in the ECOM model developed by the Texas Utility Commission (the ECOM
Margin). The difference between those two amounts is the ECOM True-Up amount,
which is the non-cash revenue related to the cost recovery.
The ECOM model from which the ECOM Margin is derived provides only annual
estimates of power prices, fuel expense and generation. Accordingly, we must
form our own quarterly allocation estimates during 2002-2003 for the purpose of
determining ECOM True-Up revenue.
Beginning January 1, 2002, we allocated the ECOM Margin in our ECOM
Calculation based on annual estimated forecasts of power prices, fuel expense
and generation. In the second quarter of 2003, we began using a cumulative
methodology for allocating ECOM Margin. This methodology uses revenue amounts
based on the actual state mandated auction price results and actual generation
for historical periods, as well as forecasted amounts for the balance of 2003,
rather than forecasted amounts for the two-year period allocated on an annual
basis. Changes in estimates that affect the allocation of ECOM Margin will have
an effect on the amount of ECOM True-Up revenue recorded in a specific period,
but will not affect the total amount of ECOM True-Up revenue recorded during the
two-year period ending December 31, 2003.
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 $11.1
billion or 56% 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. 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.
As a result of the distribution of approximately 19% of Texas Genco's common
stock to our shareholders on January 6, 2003, we re-evaluated our electric
generation assets for impairment as of December 31, 2002. This analysis required
us to make long-term estimates of future cash receipts associated with the
operation or sale of these electric generation assets and related cash outflows.
These forecasts require assumptions about demand for electricity within the
ERCOT market, future ERCOT market conditions, commodity prices and regulatory
developments. As of December 31, 2002, no impairment had been indicated because
the estimated cash flows associated with the operations of the assets exceeded
their carrying value. However, a change in our estimated holding period of Texas
Genco's generating assets, the effects of competition within the ERCOT market,
the results of our capacity auctions, and the timing and extent of changes in
commodity prices, particularly natural gas prices, could have a significant
effect on our future cash flows and, therefore, affect any future determination
of asset impairment.
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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
would 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 ENERGY REVENUES
Revenues related to the sale and/or delivery of electricity or natural gas
(energy) are generally recorded when energy is delivered to customers. However,
the determination of energy sales to individual customers is based on the
reading of their meters, which is performed on a systematic basis throughout the
month. At the end of each month, amounts of energy delivered to customers since
the date of the last meter reading are estimated and the corresponding unbilled
revenue is estimated. Unbilled electric delivery revenue is estimated each month
based on daily supply volumes, applicable rates and analyses reflecting
significant historical trends and experience. Unbilled natural gas sales are
estimated based on estimated purchased gas volumes, estimated lost and
unaccounted for gas and tariffed rates in effect. Accrued unbilled revenues
recorded in the Consolidated Balance Sheets as of December 31, 2002 were $70
million related to our Electric Transmission & Distribution business segment and
$284 million related to our Natural Gas Distribution business segment. Accrued
unbilled revenues recorded in the Consolidated Balance Sheets as of June 30,
2003 were $85 million related to our Electric Transmission & Distribution
business segment and $135 million related to our Natural Gas Distribution
business segment.
NEW ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2003, we adopted 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.
We have identified retirement obligations for nuclear decommissioning at the
South Texas Project and for lignite mine operations at the Jewett mine supplying
the Limestone electric generation facility. Prior to adoption of SFAS No. 143,
we had recorded liabilities for nuclear decommissioning and the reclamation of
the lignite mine. Liabilities were recorded for estimated decommissioning
obligations of $139.7 million and $39.7 million for reclamation of the lignite
at December 31, 2002. Upon adoption of SFAS No. 143 on January 1, 2003, we
reversed the $139.7 million previously accrued for the nuclear decommissioning
of the South Texas Project and recorded a plant asset of $99.1 million offset by
accumulated depreciation of $35.8 million as well as a retirement obligation of
$186.7 million. The $16.3 million difference between amounts previously recorded
and the amounts recorded upon adoption of SFAS No. 143 is being deferred as a
liability due to regulatory requirements. We also reversed the $39.7 million we
had previously recorded for the Jewett mine reclamation and recorded a plant
asset of $1.9 million offset by accumulated depreciation of $0.4 million as well
as a retirement obligation of $3.8 million. The $37.4 million difference between
amounts previously recorded and the amounts recorded upon adoption of SFAS No.
143 was recorded as a cumulative effect of accounting change. We have also
identified other asset retirement obligations that cannot be calculated because
the assets associated with the retirement obligations have an indeterminate
life.
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The following represents the balances of the asset retirement obligation as
of January 1, 2003 and the additions and accretion of the asset retirement
obligation for the six months ended June 30, 2003:
BALANCE, LIABILITIES LIABILITIES CASH FLOW BALANCE,
JANUARY 1, 2003 INCURRED SETTLED ACCRETION REVISIONS JUNE 30, 2003
--------------- -------- ------- --------- --------- -------------
(IN MILLIONS)
Nuclear decommissioning.........$ 186.7 -- -- $ 4.5 -- $ 191.2
Jewett lignite mine............. 3.8 -- -- 0.2 -- 4.0
------- -------- ----- ------- ------ ----------
$ 190.5 -- -- $ 4.7 -- $ 195.2
======= ======== ===== ======= ====== ==========
The following represents the pro-forma effect on our net income for the
three months and six months ended June 30, 2002, as if we had adopted SFAS No.
143 as of January 1, 2002:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2002 JUNE 30, 2002
-------------------- -------------------
(IN THOUSANDS)
Income from continuing operations before cumulative effect of
accounting change as reported......................................... $ 86,122 $ 231,012
Pro-forma income from continuing operations before cumulative effect
of accounting change.................................................. 86,102 230,972
Net income as reported................................................... 235,645 267,250
Pro-forma net income..................................................... 235,625 267,210
DILUTED EARNINGS PER SHARE:
Income from continuing operations before cumulative effect of
accounting change as reported......................................... $ 0.29 $ 0.78
Pro-forma income from continuing operations before cumulative effect
of accounting change.................................................. 0.29 0.78
Net income as reported................................................... 0.79 0.90
Pro-forma net income..................................................... 0.79 0.90
The following represents our asset retirement obligations on a pro-forma
basis as if we had adopted SFAS No. 143 as of December 31, 2002:
AS REPORTED PRO-FORMA
------------------------ -----------------------
(IN MILLIONS)
Nuclear decommissioning................................ $ 139.7 $ 186.7
Jewett lignite mine.................................... 39.7 3.8
------------------------ -----------------------
Total................................................ $ 179.4 $ 190.5
======================== =======================
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 $644 million do not
represent SFAS No. 143 asset retirement obligations, but rather embedded
regulatory liabilities. Our non-rate regulated businesses have also previously
recognized removal costs as a component of depreciation expense. We reversed
$115 million in the three months ended March 31, 2003 of previously recognized
removal costs with respect to these non-rate regulated businesses as a
cumulative effect of accounting change. The total cumulative effect of
accounting change from adoption of SFAS No. 143 was $152 million. Excluded from
the $80 million after-tax cumulative effect of accounting change recorded for
the three months ended March 31, 2003, is minority interest of $19 million
related to the Texas Genco stock not owned by us.
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,
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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 provision 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. We have reclassified the $26 million loss on
debt extinguishment related to the fourth quarter of 2002 from an extraordinary
item to interest expense.
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 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
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 has
added additional criteria which were effective on July 1, 2003 for new,
acquired, or newly modified forward contracts. We engage in forward contracts
for the sale of power. The majority of these forward contracts are entered into
either through state mandated Texas Utility Commission auctions or auctions
mandated by an agreement with Reliant Resources. All of our contracts resulting
from these auctions specify the product types, the plant or group of plants from
which the auctioned products are derived, the delivery location and specific
delivery requirements, and pricing for each of the products. We have applied the
criteria from current accounting literature, including SFAS No. 133
Implementation Issue No. C-15 - "Scope Exceptions: Normal Purchases and Normal
Sales Exception for Option-Type Contracts and Forward Contracts in Electricity",
to both the state mandated and the contractually mandated auction contracts and
believe they meet the definition of capacity contracts. Accordingly, we consider
these contracts as normal sales contracts rather than as derivatives. We have
evaluated our forward commodity contracts under the new requirements of SFAS No.
149. The adoption of SFAS No. 149 will not change previous accounting
conclusions relating to forward power sales contracts entered into in connection
with the state mandated or contractually mandated auctions, and will not have a
material effect on our 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
55
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 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
We assess the risk of our non-trading derivatives (Energy Derivatives)
using a sensitivity analysis method.
The sensitivity analysis performed on our Energy Derivatives measures the
potential loss based on a hypothetical 10% movement in energy prices. A decrease
of 10% in the market prices of energy commodities from their June 30, 2003
levels would have decreased the fair value of our Energy Derivatives from their
levels on that date by $55 million.
The above analysis of the Energy Derivatives utilized for hedging purposes
does not include the favorable impact that the same hypothetical price movement
would have on our physical purchases and sales of natural gas to which the
hedges relate. Furthermore, the Energy Derivative portfolio is managed to
complement the physical transaction portfolio, reducing overall risks within
limits. Therefore, the adverse impact to the fair value of the portfolio of
Energy Derivatives held for hedging purposes associated with the hypothetical
changes in commodity prices referenced above would be offset by a favorable
impact on the underlying hedged physical transactions.
INTEREST RATE RISK
We have outstanding long-term debt, bank loans, mandatory redeemable
preferred securities of subsidiary trusts holding solely our junior subordinated
debentures (Trust Preferred Securities), securities held in our nuclear
decommissioning trusts, some lease obligations and our obligations under the
ZENS that subject us to the risk of loss associated with movements in market
interest rates. We utilize interest-rate swaps in order to hedge a portion of
our floating-rate debt.
Our floating-rate obligations to third parties aggregated $3.7 billion at
June 30, 2003. If the floating rates were to increase by 10% from June 30, 2003
rates, our combined interest expense to third parties would increase by a total
of $2.5 million each month in which such increase continued.
At June 30, 2003, we had outstanding fixed-rate debt (excluding indexed
debt securities) and Trust Preferred Securities aggregating $7.3 billion in
principal amount and having a fair value of $7.8 billion. These instruments are
fixed-rate and, therefore, do not expose us to the risk of loss in earnings due
to changes in market interest rates. However, the fair value of these
instruments would increase by approximately $422 million if interest rates were
to decline by 10% from their levels at June 30, 2003. In general, such an
increase in fair value would impact earnings and cash flows only if we were to
reacquire all or a portion of these instruments in the open market prior to
their maturity.
As discussed in Note 13(f) to the CenterPoint Energy Notes, which note is
incorporated herein by reference, beginning in 2002, we have contributed $2.9
million per year to trusts established to fund our share of the decommissioning
costs for the South Texas Project. The securities held by the trusts for
decommissioning costs had an estimated fair value of $174 million as of June 30,
2003, of which approximately 40% were debt securities that subject us to risk of
loss of fair value with movements in market interest rates. If interest rates
were to increase by 10% from their levels at June 30, 2003, the fair value of
the fixed-rate debt securities would decrease by approximately $1 million. Any
unrealized gains or losses are accounted for as a long-term asset/liability as
we will not benefit from any gains, and losses will be recovered through the
rate making process. For further discussion regarding the recovery of
decommissioning costs pursuant to the Texas electric restructuring law, please
read Note 4(a) to the CenterPoint Energy Notes, which is incorporated herein by
reference.
As discussed in Note 9(b) to the CenterPoint Energy Notes, which note is
incorporated herein by reference, CERC
56
Corp.'s $140 million aggregate principal amount of TERM Notes outstanding at
June 30, 2003, include an embedded option to remarket the securities. The option
is expected to be exercised in the event that the ten-year Treasury rate is
below 5.66%. At June 30, 2003, we could terminate the option at a cost of $23
million. A decrease of 10% in the June 30, 2003 level of interest rates would
increase the cost of termination of the option by approximately $5 million.
As discussed in Note 7 to the CenterPoint Energy Notes, which note is
incorporated herein by reference, upon adoption of SFAS No. 133 effective
January 1, 2001, the ZENS obligation was bifurcated into a debt component and a
derivative component. The debt component of $105 million at June 30, 2003 is a
fixed-rate obligation and, therefore, does not expose us to the risk of loss in
earnings due to changes in market interest rates. However, the fair value of the
debt component would increase by approximately $15 million if interest rates
were to decline by 10% from levels at June 30, 2003. Changes in the fair value
of the derivative component will be recorded in our Statements of Consolidated
Income and, therefore, we are exposed to changes in the fair value of the
derivative component as a result of changes in the underlying risk-free interest
rate. If the risk-free interest rate were to increase by 10% from June 30, 2003
levels, the fair value of the derivative component would increase by
approximately $5 million, which would be recorded as a loss in our Statements of
Consolidated Income.
As of June 30, 2003, we have interest rate swaps with an aggregate notional
amount of $750 million that fix the interest rate applicable to floating rate
short-term debt. At June 30, 2003, the swaps relating to short-term debt could
be terminated at a cost of $10 million. These swaps do not qualify as cash flow
hedges under SFAS No. 133, and are marked to market in the Company's
Consolidated Balance Sheets with changes reflected in interest expense in the
Statements of Consolidated Income. A decrease of 10% in the June 30, 2003 level
of interest rates would increase the cost of terminating the swaps at June 30,
2003 by $2 million.
EQUITY MARKET VALUE RISK
We are exposed to equity market value risk through our ownership of
approximately 22 million shares of AOL TW common stock, which we hold to
facilitate our ability to meet our obligations under the ZENS. Please read Note
7 to the CenterPoint Energy Notes for a discussion of the effect of adoption of
SFAS No. 133 on our ZENS obligation and our historical accounting treatment of
our ZENS obligation. Subsequent to adoption of SFAS No. 133, a decrease of 10%
from the June 30, 2003 market value of AOL Time Warner common stock would result
in a net loss of approximately $3 million, which would be recorded as a loss in
our Statements of Consolidated Income.
As discussed above under "-- Interest Rate Risk," we contribute to trusts
established to fund our share of the decommissioning costs for the South Texas
Project, which held debt and equity securities as of June 30, 2003. The equity
securities expose us to losses in fair value. If the market prices of the
individual equity securities were to decrease by 10% from their levels at June
30, 2003, the resulting loss in fair value of these securities would be
approximately $10 million. Currently, the risk of an economic loss is mitigated
as discussed above under "-- Interest Rate Risk."
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.
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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
For a description of certain legal and regulatory proceedings affecting
CenterPoint Energy, please read Note 12 to our Interim Financial Statements,
"Business -- Environmental Matters" in Item 1 of the CenterPoint Energy 10-K,
"Legal Proceedings" in Item 3 of the CenterPoint Energy Form 10-K and Notes 4
and 13 to the CenterPoint Energy Notes, each of which is incorporated herein by
reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.
The information set forth in Note 9(b) of the Notes to our Interim
Financial Statements and in Management's Discussion and Analysis of Financial
Condition and Results of Operations of CenterPoint Energy and Subsidiaries in
Item 2 of Part I of this report regarding the issuance on May 19, 2003 of $575
million aggregate principal amount of our 3.75% convertible senior notes due
2023 is incorporated by reference herein. We have been advised by Citigroup
Global Markets Inc., Banc of America Securities LLC and J.P. Morgan Securities
Inc., the representatives of the initial purchasers of the notes, that the notes
were issued only to "qualified institutional buyers" in reliance on Rule 144A
under the Securities Act of 1933 and outside the United States in accordance
with Regulation S under the Securities Act of 1933. The notes were issued at
100% of the principal amount thereof, plus accrued interest. The initial
purchasers purchased the notes from us at 97% of the principal amount thereof,
plus accrued interest.
The notes are convertible into shares of our common stock at a conversion
rate of 86.3558 shares per $1,000 principal amount of notes (which is equal to a
conversion price of $11.58 per share), subject to adjustment, but only in
certain specified circumstances. The notes also have a contingent interest
feature requiring contingent interest to be paid to holders of the notes in
certain specified circumstances.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
At the annual meeting of CenterPoint Energy's shareholders held on May 7,
2003, the matters voted upon and the number of votes cast for, against or
withheld, as well as the number of abstentions and broker non-votes as to such
matters (including a separate tabulation with respect to each nominee for
office) were as stated below:
The following nominees for Class I directors were elected to serve a
three-year term expiring 2006 (there were no broker non-votes):
For Withheld
----------- ----------
Derrill Cody 253,620,181 11,996,061
David M. McClanahan 253,399,938 12,216,304
The following nominee for Class III director was elected to serve a
two-year term expiring 2005 (there were no broker non-votes):
For Withheld
----------- ----------
Thomas F. Madison 250,165,251 15,450,991
The following directors' terms continued after the meeting and expire when
indicated:
Milton Carroll (2004),
John T. Cater (2004),
Michael E. Shannon (2004), and
O. Holcombe Crosswell (2005).
58
The amendment and restatement of the Director Stock Plan in the form of the
CenterPoint Energy, Inc. Stock Plan for Outside Directors was approved with
233,262,994 votes for, 27,985,496 votes against, 4,367,752 abstentions and no
broker non-votes.
The ratification of the appointment of Deloitte & Touche LLP as independent
accountants and auditors for CenterPoint Energy for 2003 was approved with
252,436,634 votes for, 9,985,842 votes against, 3,193,766 abstentions and no
broker non-votes.
The shareholder proposal requiring that all future stock option grants to
senior executives be indexed to an industry peer group stock performance index
was not approved with 159,981,998 votes against, 46,428,042 votes for, 5,533,887
abstentions and 53,672,315 broker non-votes.
The shareholder proposal to amend CenterPoint Energy's written equal
employment opportunity policy was not approved with 124,208,128 votes against,
59,028,314 votes for, 28,707,485 abstentions and 53,672,315 broker non-votes.
ITEM 5. OTHER INFORMATION.
RISK FACTORS
PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES
We are a holding company that conducts all of our business operations
through subsidiaries, primarily CenterPoint Houston, CERC and Texas Genco. The
following summarizes the principal risk factors associated with the businesses
conducted by each of these subsidiaries:
RISK FACTORS AFFECTING OUR ELECTRIC TRANSMISSION & DISTRIBUTION BUSINESS
CENTERPOINT HOUSTON MAY NOT BE SUCCESSFUL IN RECOVERING THE FULL VALUE OF ITS
STRANDED COSTS AND REGULATORY ASSETS RELATED TO GENERATION.
CenterPoint Houston is entitled to recover its stranded costs (the excess
of regulatory net book value of generation assets, as defined by the Texas
electric restructuring law, over the market value of those assets) and its
regulatory assets related to generation. CenterPoint Houston expects to make a
filing on March 31, 2004 in a true-up proceeding provided for by the Texas
electric restructuring law. The purpose of this proceeding will be to quantify
and reconcile:
- the amount of stranded costs,
- regulatory assets that were not previously recovered through the
issuance of transition bonds by a subsidiary,
- differences in the prices achieved in the state mandated auctions of
Texas Genco's generation capacity and Texas Utility Commission
estimates,
- fuel over- or under-recovery, and
- the "price to beat" clawback.
CenterPoint Houston will be required to establish and support the amounts
of these costs in order to recover them. CenterPoint Houston expects these costs
to be substantial. We cannot assure you that CenterPoint Houston will be able to
successfully establish and support its estimates of the value of these costs.
CenterPoint Houston's $1.3 billion collateralized term loan that matures in
November 2005 is expected to be repaid or refinanced with the proceeds from the
issuance of transition bonds to recover its stranded costs and the balance of
its regulatory assets. If CenterPoint Houston does not receive the proceeds on
or before the maturity date, its ability to repay or refinance this term loan
will be adversely affected.
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The Texas Utility Commission's ruling that the true-up proceeding filing
will be made on March 31, 2004 means that the calculation of the market value of
a share of Texas Genco common stock for purposes of the Texas Utility
Commission's stranded cost determination might be more or less than the per
share purchase price calculated under the option held by Reliant Resources to
purchase our 81% ownership interest in Texas Genco. The purchase price under the
option will be based on market prices during the 120 trading days ending on
January 9, 2004, but under the filing schedule prescribed by the Texas Utility
Commission, the value of that ownership interest for the stranded cost
determination will be based on market prices during the 120 trading days ending
on March 30, 2004. If Reliant Resources exercises its option at a lower price
than the market value used by the Texas Utility Commission, CenterPoint Houston
would be unable to recover the difference.
CENTERPOINT HOUSTON'S RECEIVABLES ARE CONCENTRATED IN A SMALL NUMBER OF
RETAIL ELECTRIC PROVIDERS.
CenterPoint Houston's receivables from the distribution of electricity are
collected from retail electric providers that supply the electricity CenterPoint
Houston distributes to their customers. Currently, CenterPoint Houston does
business with approximately 31 retail electric providers. Adverse economic
conditions, structural problems in the new ERCOT market or financial
difficulties of one or more retail electric providers could impair the ability
of these retail providers to pay for CenterPoint Houston's services or could
cause them to delay such payments. CenterPoint Houston depends on these retail
electric providers to remit payments timely to it. Any delay or default in
payment could adversely affect CenterPoint Houston's cash flows, financial
condition and results of operations. Approximately 78% of CenterPoint Houston's
$119 million in receivables from retail electric providers at June 30, 2003 was
owed by subsidiaries of Reliant Resources. CenterPoint Houston's financial
condition may be adversely affected if Reliant Resources is unable to meet these
obligations. Reliant Resources, through its subsidiaries, is CenterPoint
Houston's largest customer. Pursuant to the Texas electric restructuring law,
Reliant Resources may be obligated to make a large "price to beat" clawback
payment to CenterPoint Houston in 2004. CenterPoint Houston expects the
clawback, if any, to be applied against any stranded cost recovery to which
CenterPoint Houston is entitled or, if no stranded costs are recoverable, to be
refunded to retail electric providers.
RATE REGULATION OF CENTERPOINT HOUSTON'S BUSINESS MAY DELAY OR DENY
CENTERPOINT HOUSTON'S FULL RECOVERY OF ITS COSTS.
CenterPoint Houston's rates are regulated by certain municipalities and the
Texas Utility Commission based on an analysis of its invested capital and its
expenses incurred in a test year. Thus, the rates CenterPoint Houston is allowed
to charge may not match its expenses at any given time. While rate regulation in
Texas is premised on providing a reasonable opportunity to recover reasonable
and necessary operating expenses and to earn a reasonable return on its invested
capital, there can be no assurance that the Texas Utility Commission will judge
all of CenterPoint Houston's costs to be reasonable or necessary or that the
regulatory process in which rates are determined will always result in rates
that will produce full recovery of CenterPoint Houston's costs.
DISRUPTIONS AT POWER GENERATION FACILITIES OWNED BY THIRD PARTIES COULD
INTERRUPT CENTERPOINT HOUSTON'S SALES OF TRANSMISSION AND DISTRIBUTION
SERVICES.
CenterPoint Houston depends on power generation facilities owned by third
parties to provide retail electric providers with electric power which it
transmits and distributes. CenterPoint Houston does not own or operate any power
generation facilities. If power generation is disrupted or if power generation
capacity is inadequate, CenterPoint Houston's services may be interrupted, and
its results of operations, financial condition and cash flows may be adversely
affected.
CENTERPOINT HOUSTON'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.
A portion of CenterPoint Houston's revenues is derived from rates that it
collects from each retail electric provider based on the amount of electricity
it distributes on behalf of each retail electric provider. Thus, CenterPoint
Houston's revenues and results of operations are subject to seasonality, weather
conditions and other changes in electricity usage, with revenues being higher
during the warmer months.
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RISK FACTORS AFFECTING OUR ELECTRIC GENERATION BUSINESS
TEXAS GENCO'S REVENUES AND RESULTS OF OPERATIONS ARE IMPACTED BY MARKET RISKS
THAT ARE BEYOND ITS CONTROL.
Texas Genco sells electric generation capacity, energy and ancillary
services in the ERCOT market. The ERCOT market consists of the majority of the
population centers in the State of Texas and represents approximately 85% of the
demand for power in the state. Under the Texas electric restructuring law, Texas
Genco and other power generators in Texas are not subject to traditional
cost-based regulation and, therefore, may sell electric generation capacity,
energy and ancillary services to wholesale purchasers at prices determined by
the market. As a result, Texas Genco is not guaranteed any rate of return on its
capital investments through mandated rates, and its revenues and results of
operations depend, in large part, upon prevailing market prices for electricity
in the ERCOT market. Market prices for electricity, generation capacity, energy
and ancillary services may fluctuate substantially. Texas Genco's gross margins
are primarily derived from the sale of capacity entitlements associated with its
large, solid fuel base-load generating units, including its coal and lignite
fueled generating stations and the South Texas Project. The gross margins
generated from payments associated with the capacity of these units are directly
impacted by natural gas prices. Since the fuel costs for Texas Genco's base-load
units are largely fixed under long-term contracts, they are generally not
subject to significant daily and monthly fluctuations. However, the market price
for power in the ERCOT market is directly affected by the price of natural gas.
Because natural gas is the marginal fuel for facilities serving the ERCOT market
during most hours, its price has a significant influence on the price of
electric power. As a result, the price customers are willing to pay for
entitlements to Texas Genco's solid fuel-fired base-load capacity generally
rises and falls with natural gas prices.
Market prices in the ERCOT market may also fluctuate substantially due to
other factors. Such fluctuations may occur over relatively short periods of
time. Volatility in market prices may result from:
- oversupply or undersupply of generation capacity,
- power transmission or fuel transportation constraints or
inefficiencies,
- weather conditions,
- seasonality,
- availability and market prices for natural gas, crude oil and refined
products, coal, enriched uranium and uranium fuels,
- changes in electricity usage,
- additional supplies of electricity from existing competitors or new
market entrants as a result of the development of new generation
facilities or additional transmission capacity,
- illiquidity in the ERCOT market,
- availability of competitively priced alternative energy sources,
- natural disasters, wars, embargoes, terrorist attacks and other
catastrophic events, and
- federal and state energy and environmental regulation and legislation.
THERE IS CURRENTLY A SURPLUS OF GENERATING CAPACITY IN THE ERCOT MARKET AND
WE EXPECT THE MARKET FOR WHOLESALE POWER TO BE HIGHLY COMPETITIVE.
The amount by which power generating capacity exceeded peak demand (reserve
margin) in the ERCOT market has exceeded 20% since 2001, and the Texas Utility
Commission and the ERCOT Independent System Operator (ISO) have forecasted the
reserve margin for 2003 to continue to exceed 20%. The commencement of
commercial operation of new facilities in the ERCOT market will increase the
competitiveness of the wholesale
61
power market, which could have a material adverse effect on Texas Genco's
results of operations, financial condition, cash flows and the market value of
Texas Genco's assets.
Texas Genco's competitors include generation companies affiliated with
Texas-based utilities, independent power producers, municipal and co-operative
generators and wholesale power marketers. The unbundling of vertically
integrated utilities into separate generation, transmission and distribution,
and retail businesses pursuant to the Texas electric restructuring law could
result in a significant number of additional competitors participating in the
ERCOT market. Some of Texas Genco's competitors may have greater financial
resources, lower cost structures, more effective risk management policies and
procedures, greater ability to incur losses, greater potential for profitability
from ancillary services, and greater flexibility in the timing of their sale of
generating capacity and ancillary services than Texas Genco does.
TEXAS GENCO IS SUBJECT TO OPERATIONAL AND MARKET RISKS ASSOCIATED WITH ITS
CAPACITY AUCTIONS.
Texas Genco is obligated to sell substantially all of its available
capacity and related ancillary services through 2003 pursuant to capacity
auctions. In these auctions, Texas Genco sells firm entitlements on a forward
basis to capacity and ancillary services dispatched within specified operational
constraints. Although Texas Genco has reserved a portion of its aggregate net
generation capacity from its capacity auctions for planned or forced outages at
its facilities, unanticipated plant outages or other problems with its
generation facilities could result in its firm capacity and ancillary services
commitments exceeding its available generation capacity. As a result, Texas
Genco could be required to obtain replacement power from third parties in the
open market to satisfy its firm commitments that could result in significant
additional costs. In addition, an unexpected outage at one of Texas Genco's
lower cost facilities could require it to run one of its higher cost plants in
order to satisfy its obligations even though the energy payments for the
dispatched power are based on the cost at the lower-cost facility.
The mechanics, regulations and agreements governing Texas Genco's capacity
auctions are complex. The state mandated auctions require, among other things,
Texas Genco's capacity entitlements to be sold in pre-determined amounts. The
characteristics of the capacity entitlements Texas Genco sells in state mandated
auctions are defined by rules adopted by the Texas Utility Commission and,
therefore, cannot be changed to respond to market demands or operational
requirements without approval by the Texas Utility Commission.
THE OPERATION OF TEXAS GENCO'S POWER GENERATION FACILITIES INVOLVES RISKS
THAT COULD ADVERSELY AFFECT ITS REVENUES, COSTS, RESULTS OF OPERATIONS,
FINANCIAL CONDITION AND CASH FLOWS.
Texas Genco is subject to various risks associated with operating its power
generation facilities, any of which could adversely affect its revenues, costs,
results of operations, financial condition and cash flows. These risks include:
- operating performance below expected levels of output or efficiency,
- breakdown or failure of equipment or processes,
- disruptions in the transmission of electricity,
- shortages of equipment, material or labor,
- labor disputes,
- fuel supply interruptions,
- limitations that may be imposed by regulatory requirements, including,
among others, environmental standards,
- limitations imposed by the ERCOT ISO,
- violations of permit limitations,
- operator error, and
62
- catastrophic events such as fires, hurricanes, explosions, floods,
terrorist attacks or other similar occurrences.
A significant portion of Texas Genco's facilities were constructed many
years ago. Older generation equipment, even if maintained in accordance with
good engineering practices, may require significant capital expenditures to keep
it operating at high efficiency and to meet regulatory requirements. This
equipment is also likely to require periodic upgrading and improvement. Any
unexpected failure to produce power, including failure caused by breakdown or
forced outage, could result in increased costs of operations and reduced
earnings.
TEXAS GENCO RELIES ON POWER TRANSMISSION FACILITIES THAT IT DOES NOT OWN OR
CONTROL AND THAT ARE SUBJECT TO TRANSMISSION CONSTRAINTS WITHIN THE ERCOT
MARKET. IF THESE FACILITIES FAIL TO PROVIDE TEXAS GENCO WITH ADEQUATE
TRANSMISSION CAPACITY, IT MAY NOT BE ABLE TO DELIVER WHOLESALE ELECTRIC POWER
TO ITS CUSTOMERS AND IT MAY INCUR ADDITIONAL COSTS.
Texas Genco depends on transmission and distribution facilities owned and
operated by CenterPoint Houston and by others to deliver the wholesale electric
power it sells from its power generation facilities to its customers, who in
turn deliver power to the end users. If transmission is disrupted, or if
transmission capacity infrastructure is inadequate, Texas Genco's ability to
sell and deliver wholesale electric energy may be adversely impacted.
The single control area of the ERCOT market is currently organized into
four congestion zones. Transmission congestion between the zones could impair
Texas Genco's ability to schedule power for transmission across zonal
boundaries, which are defined by the ERCOT ISO, thereby inhibiting Texas Genco's
efforts to match its facility scheduled outputs with its customer scheduled
requirements. In addition, power generators participating in the ERCOT market
could be liable for congestion costs associated with transferring power between
zones.
TEXAS GENCO'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD
BE ADVERSELY IMPACTED BY A DISRUPTION OF ITS FUEL SUPPLIES.
Texas Genco relies primarily on natural gas, coal, lignite and uranium to
fuel its generation facilities. Texas Genco purchases its fuel from a number of
different suppliers under long-term contracts and on the spot market. Under
Texas Genco's capacity auctions, it sells firm entitlements to capacity and
ancillary services. Therefore, any disruption in the delivery of fuel could
prevent Texas Genco from operating its facilities, or force Texas Genco to enter
into alternative arrangements at higher than prevailing market prices, to meet
its auction commitments, which could adversely affect its results of operations,
financial condition and cash flows.
TO DATE, TEXAS GENCO HAS SOLD A SUBSTANTIAL PORTION OF ITS AUCTIONED CAPACITY
ENTITLEMENTS TO SUBSIDIARIES OF RELIANT RESOURCES. ACCORDINGLY, TEXAS GENCO'S
RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE ADVERSELY
AFFECTED IF RELIANT RESOURCES DECLINED TO PARTICIPATE IN TEXAS GENCO'S FUTURE
AUCTIONS OR FAILED TO MAKE PAYMENTS WHEN DUE UNDER RELIANT RESOURCES'
PURCHASED ENTITLEMENTS.
Subsidiaries of Reliant Resources purchased entitlements to 63% of Texas
Genco's available 2002 capacity and through July 2003 had purchased 71% of Texas
Genco's available 2003 capacity. Reliant Resources made these purchases either
through the exercise of its contractual rights to purchase 50% of the
entitlements Texas Genco auctions in its contractually mandated auctions or
through the submission of bids. In the event Reliant Resources declined to
participate in Texas Genco's future auctions or failed to make payments when
due, Texas Genco's results of operations, financial condition and cash flows
could be adversely affected. As of June 30, 2003, Reliant Resources' securities
ratings are below investment grade. Texas Genco has been granted a security
interest in accounts receivable and/or securitization notes associated with the
accounts receivable of certain subsidiaries of Reliant Resources to secure up to
$250 million in purchase obligations.
TEXAS GENCO MAY INCUR SUBSTANTIAL COSTS AND LIABILITIES AS A RESULT OF ITS
OWNERSHIP OF NUCLEAR FACILITIES.
Texas Genco owns a 30.8% interest in the South Texas Project, a nuclear
powered generation facility. As a result, Texas Genco is subject to risks
associated with the ownership and operation of nuclear facilities. These risks
include:
- the potential harmful effects on the environment and human health
resulting from the operation of nuclear
63
facilities and the storage, handling and disposal of radioactive
materials,
- limitations on the amounts and types of insurance commercially
available to cover losses that might arise in connection with nuclear
operations, and
- uncertainties with respect to the technological and financial aspects
of decommissioning nuclear plants at the end of their licensed lives.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines, shut
down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could necessitate substantial capital expenditures at nuclear plants.
In addition, although we have no reason to anticipate a serious nuclear incident
at the South Texas Project, if an incident did occur, it could have a material
adverse effect on Texas Genco's results of operations, financial condition and
cash flows.
TEXAS GENCO'S OPERATIONS ARE SUBJECT TO EXTENSIVE REGULATION, INCLUDING
ENVIRONMENTAL REGULATION. IF TEXAS GENCO FAILS TO COMPLY WITH APPLICABLE
REGULATIONS OR OBTAIN OR MAINTAIN ANY NECESSARY GOVERNMENTAL PERMIT OR
APPROVAL, IT MAY BE SUBJECT TO CIVIL, ADMINISTRATIVE AND/OR CRIMINAL
PENALTIES THAT COULD ADVERSELY IMPACT ITS RESULTS OF OPERATIONS, FINANCIAL
CONDITION AND CASH FLOWS.
Texas Genco's operations are subject to complex and stringent energy,
environmental and other governmental laws and regulations. The acquisition,
ownership and operation of power generation facilities require numerous permits,
approvals and certificates from federal, state and local governmental agencies.
These facilities are subject to regulation by the Texas Utility Commission
regarding non-rate matters. Existing regulations may be revised or
reinterpreted, new laws and regulations may be adopted or become applicable to
Texas Genco or any of its generation facilities or future changes in laws and
regulations may have a detrimental effect on its business.
Operation of the South Texas Project is subject to regulation by the NRC.
This regulation involves testing, evaluation and modification of all aspects of
plant operation in light of NRC safety and environmental requirements.
Continuous demonstrations to the NRC that plant operations meet applicable
requirements are also required. The NRC has the ultimate authority to determine
whether any nuclear powered generating unit may operate.
Water for certain of Texas Genco's facilities is obtained from public water
authorities. New or revised interpretations of existing agreements by those
authorities or changes in price or availability of water may have a detrimental
effect on Texas Genco's business.
Texas Genco's business is subject to extensive environmental regulation by
federal, state and local authorities. Texas Genco is required to comply with
numerous environmental laws and regulations and to obtain numerous governmental
permits in operating its facilities. Texas Genco may incur significant
additional costs to comply with these requirements. If Texas Genco fails to
comply with these requirements or with any other regulatory requirements that
apply to its operations, it could be subject to administrative, civil and/or
criminal liability and fines, and regulatory agencies could take other actions
seeking to curtail its operations. These liabilities or actions could adversely
impact its results of operations, financial condition and cash flows.
Existing environmental regulations could be revised or reinterpreted, new
laws and regulations could be adopted or become applicable to Texas Genco or its
facilities, and future changes in environmental laws and regulations could
occur, including potential regulatory and enforcement developments related to
air emissions. If any of these events occurs, Texas Genco's business, results of
operations, financial condition and cash flows could be adversely affected.
Texas Genco may not be able to obtain or maintain from time to time all
required environmental regulatory approvals. If there is a delay in obtaining
any required environmental regulatory approvals or if Texas Genco fails to
obtain and comply with them, it may not be able to operate its facilities or it
may be required to incur additional costs. Texas Genco is generally responsible
for all on-site liabilities associated with the environmental condition of its
power generation facilities, regardless of when the liabilities arose and
whether the liabilities are known or unknown. These liabilities may be
substantial.
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RISK FACTORS AFFECTING OUR NATURAL GAS DISTRIBUTION AND PIPELINES AND GATHERING
BUSINESSES
CERC'S BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, AND ITS
PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE
TRANSPORTATION AND STORAGE OF NATURAL GAS.
CERC competes primarily with alternate energy sources such as electricity
and other fuel sources. In some areas, intrastate pipelines, other natural gas
distributors and marketers also compete directly with CERC for natural gas sales
to end-users. In addition, as a result of federal regulatory changes affecting
interstate pipelines, natural gas marketers operating on these pipelines may be
able to bypass CERC's facilities and market, sell and/or transport natural gas
directly to commercial and industrial customers. Any reduction in the amount of
natural gas marketed, sold or transported by CERC as a result of competition may
have an adverse impact on CERC's results of operations, financial condition and
cash flows.
CERC's two interstate pipelines and its gathering systems compete with
other interstate and intrastate pipelines and gathering systems in the
transportation and storage of natural gas. The principal elements of competition
are rates, terms of service, and flexibility and reliability of service. They
also compete indirectly with other forms of energy, including electricity, coal
and fuel oils. The primary competitive factor is price. The actions of CERC's
competitors could lead to lower prices, which may have an adverse impact on
CERC's results of operations, financial condition and cash flows.
CERC'S NATURAL GAS DISTRIBUTION BUSINESS IS SUBJECT TO FLUCTUATIONS IN
NATURAL GAS PRICING LEVELS.
CERC is subject to risk associated with price movements of natural gas.
Movements in natural gas prices might affect CERC's ability to collect balances
due from its customers and could create the potential for uncollectible accounts
expense to exceed the recoverable levels built into CERC's tariff rates. In
addition, a sustained period of high natural gas prices could apply downward
demand pressure on natural gas consumption in CERC's service territory.
Additionally, increasing gas prices could create the need for CERC to provide
collateral in order to purchase gas.
CERC MAY INCUR CARRYING COSTS ASSOCIATED WITH PASSING THROUGH CHANGES IN THE
COSTS OF NATURAL GAS.
Generally, the regulations of the states in which CERC operates allow it to
pass through changes in the costs of natural gas to its customers through
purchased gas adjustment provisions in the applicable tariffs. There is,
however, a timing difference between its purchases of natural gas and the
ultimate recovery of these costs. Consequently, CERC may incur carrying costs as
a result of this timing difference that are not recoverable from its customers.
The failure to recover those additional carrying costs may have an adverse
effect on CERC's results of operations, financial condition and cash flows.
IF CERC FAILS TO EXTEND CONTRACTS WITH TWO OF ITS SIGNIFICANT INTERSTATE
PIPELINES' CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON ITS 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 provided in the current contracts, it could have an
adverse effect on CERC's results of operations, financial condition and cash
flows.
CERC'S INTERSTATE PIPELINES ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS.
CERC's 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 CERC's results of operations, financial condition and cash
flows.
CERC'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.
A portion of CERC's revenues are derived from natural gas sales and
transportation. Thus, CERC's revenues and results of operations are subject to
seasonality, weather conditions and other changes in natural gas usage, with
revenues being higher during the winter months.
65
RISK FACTORS ASSOCIATED WITH OUR CONSOLIDATED 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 $11.1 billion of outstanding indebtedness and
trust preferred securities, including approximately $157 million of debt that
must be refinanced in 2003. In addition, the capital constraints and other
factors currently impacting 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, adversely affect our financial condition and
results of operations or severely restrict or prohibit distributions from our
subsidiaries. The success of our future financing efforts may depend, at least
in part, on:
- general economic and capital market conditions,
- credit availability from financial institutions and other lenders,
- investor confidence in us and the market in which we operate,
- maintenance of acceptable credit ratings,
- market expectations regarding our future earnings and probable cash
flows,
- market perceptions of our ability to access capital markets on
reasonable terms,
- our exposure to Reliant Resources in connection with its
indemnification obligations arising in connection with its separation
from us,
- provisions of relevant tax and securities laws, and
- our ability to obtain approval of financing transactions under the
1935 Act.
As of June 30, 2003, our CenterPoint Houston subsidiary had $2.8 billion of
general mortgage bonds outstanding. It may issue additional general mortgage
bonds on the basis of retired bonds, 70% of property additions or cash deposited
with the trustee. Although approximately $680 million of additional general
mortgage bonds could be issued on the basis of property additions as of June 30,
2003, CenterPoint Houston has agreed under the $1.3 billion collateralized term
loan maturing in 2005 to not issue, subject to certain exceptions, any
incremental secured or unsecured debt. In addition, CenterPoint Houston is
contractually prohibited, subject to certain exceptions, from issuing additional
first mortgage bonds.
Our current credit ratings are discussed in "Management's Discussion and
Analysis of Financial Condition and Results of Operations of CenterPoint Energy
and Subsidiaries -- Liquidity and Capital Resources -- Future Sources and Uses
of Cash Flows -- 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.
AS A HOLDING COMPANY WITH NO OPERATIONS OF OUR OWN, WE WILL DEPEND ON
DISTRIBUTIONS FROM OUR SUBSIDIARIES TO MEET OUR PAYMENT OBLIGATIONS, AND
PROVISIONS OF APPLICABLE LAW OR CONTRACTUAL RESTRICTIONS COULD LIMIT THE
AMOUNT OF THOSE DISTRIBUTIONS.
We derive substantially all our operating income from, and hold
substantially all our assets through, our subsidiaries. As a result, we will
depend on distributions from our subsidiaries in order to meet our payment
obligations. In general, these subsidiaries are separate and distinct legal
entities and will have no obligation to provide us with funds for our payment
obligations, whether by dividends, distributions, loans or otherwise. In
66
addition, provisions of applicable law, such as those limiting the legal sources
of dividends and those under the 1935 Act, limit their ability to make payments
or other distributions to us, and they could agree to contractual restrictions
on their ability to make distributions.
Our right to receive any assets of any subsidiary, and therefore the right
of our creditors to participate in those assets, will be effectively
subordinated to the claims of that subsidiary's creditors, including trade
creditors. In addition, even if we were a creditor of any subsidiary, our rights
as a creditor would be subordinated to any security interest in the assets of
that subsidiary and any indebtedness of the subsidiary senior to that held by
us.
AN INCREASE IN SHORT-TERM INTEREST RATES COULD ADVERSELY AFFECT OUR CASH
FLOWS.
As of June 30, 2003, we had $3.7 billion of outstanding floating-rate debt
owed to third parties. Because of capital constraints impacting our business at
the time some of this floating-rate debt was entered into, the interest rates
are substantially above our historical borrowing rates. In addition, any
floating-rate debt issued by us in the future could be at interest rates
substantially above our historical borrowing rates. While we may seek to use
interest rate swaps in order to hedge portions of our floating-rate debt, we may
not be successful in obtaining hedges on acceptable terms. Any increase in
short-term interest rates would result in higher interest costs and could
adversely affect our results of operations, financial condition and cash flows.
OTHER RISKS
WE AND CENTERPOINT HOUSTON COULD INCUR LIABILITIES ASSOCIATED WITH BUSINESSES
AND ASSETS THAT WE HAVE TRANSFERRED TO OTHERS.
Under some circumstances, we and CenterPoint Houston could incur
liabilities associated with assets and businesses we and CenterPoint Houston no
longer own. These assets and businesses were previously owned by Reliant Energy
directly or through subsidiaries and include:
- those transferred to Reliant Resources or its subsidiaries in
connection with the organization and capitalization of Reliant
Resources prior to its initial public offering in 2001,
- those transferred to Texas Genco in connection with its organization
and capitalization, and
- those transferred to CenterPoint Energy in connection with the
Restructuring.
In connection with the organization and capitalization of Reliant
Resources, Reliant Resources and its subsidiaries assumed liabilities associated
with various assets and businesses Reliant Energy transferred to them. Reliant
Resources also agreed to indemnify, and cause the applicable transferee
subsidiaries to indemnify, us and our subsidiaries, including CenterPoint
Houston, with respect to liabilities associated with the transferred assets and
businesses. The indemnity provisions were intended to place sole financial
responsibility on Reliant Resources and its subsidiaries for all liabilities
associated with the current and historical businesses and operations of Reliant
Resources, regardless of the time those liabilities arose. If Reliant Resources
is unable to satisfy a liability that has been so assumed in circumstances in
which Reliant Energy has not been released from the liability in connection with
the transfer, we or CenterPoint Houston could be responsible for satisfying the
liability.
Reliant Resources reported in its Quarterly Report on Form 10-Q for the
quarterly period ended March 31, 2003 that as of March 31, 2003 it had $7.9
billion of total debt and its unsecured debt ratings are currently below
investment grade. If Reliant Resources is unable to meet its obligations, it
would need to consider, among various options, restructuring under the
bankruptcy laws, in which event Reliant Resources might not honor its
indemnification obligations and claims by Reliant Resources' creditors might be
made against us as its former owner.
Reliant Energy and Reliant Resources are named as defendants in a number of
lawsuits arising out of power sales in California and other West Coast markets
and financial reporting matters. Although these matters relate to the business
and operations of Reliant Resources, claims against Reliant Energy have been
made on grounds that include the effect of Reliant Resources' financial results
on Reliant Energy's historical financial statements and liability of Reliant
Energy as a controlling shareholder of Reliant Resources. We or CenterPoint
Houston could incur liability if claims in one or more of these lawsuits were
successfully asserted against us or CenterPoint
67
Houston and indemnification from Reliant Resources were determined to be
unavailable or if Reliant Resources were unable to satisfy indemnification
obligations owed with respect to those claims.
In connection with the organization and capitalization of Texas Genco,
Texas Genco assumed liabilities associated with the electric generation assets
Reliant Energy transferred to it. Texas Genco also agreed to indemnify, and
cause the applicable transferee subsidiaries to indemnify, us and our
subsidiaries, including CenterPoint Houston, with respect to liabilities
associated with the transferred assets and businesses. In many cases the
liabilities assumed were held by CenterPoint Houston and CenterPoint Houston was
not released by third parties from these liabilities. The indemnity provisions
were intended generally to place sole financial responsibility on Texas Genco
and its subsidiaries for all liabilities associated with the current and
historical businesses and operations of Texas Genco, regardless of the time
those liabilities arose. If Texas Genco were unable to satisfy a liability that
had been so assumed or indemnified against, and provided Reliant Energy had not
been released from the liability in connection with the transfer, CenterPoint
Houston could be responsible for satisfying the liability.
IF THE ERCOT MARKET DOES NOT FUNCTION IN THE MANNER CONTEMPLATED BY THE TEXAS
ELECTRIC RESTRUCTURING LAW, TEXAS GENCO'S AND CENTERPOINT HOUSTON'S BUSINESS,
PROSPECTS, RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE
ADVERSELY IMPACTED.
The competitive electric market in Texas became fully operational in
January 2002, and none of CenterPoint Houston, Texas Genco, the Texas Utility
Commission, ERCOT or other market participants has any significant operating
history under the market framework created by the Texas electric restructuring
law. The initiatives under the Texas electric restructuring law have had a
significant impact on the nature of the electric power industry in Texas and the
manner in which participants in the ERCOT market conduct their business. These
changes are ongoing, and we cannot predict the future development of the ERCOT
market or the ultimate effect that this changing regulatory environment will
have on the businesses of CenterPoint Houston or Texas Genco.
Some restructured markets in other states have experienced supply problems
and extreme price volatility. If the ERCOT market does not function as intended
by the Texas electric restructuring law, Texas Genco's and CenterPoint Houston's
results of operations, financial condition and cash flows could be adversely
affected. In addition, any market failures could lead to revisions or
reinterpretations of the Texas electric restructuring law, the adoption of new
laws and regulations applicable to Texas Genco or CenterPoint Houston or their
respective facilities and other future changes in laws and regulations that may
have a detrimental effect on Texas Genco's and CenterPoint Houston's businesses.
WE, TOGETHER WITH OUR SUBSIDIARIES, ARE SUBJECT TO REGULATION UNDER THE 1935
ACT. THE 1935 ACT AND RELATED RULES AND REGULATIONS IMPOSE A NUMBER OF
RESTRICTIONS ON OUR ACTIVITIES.
We and our subsidiaries 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 current
and retained earnings without prior 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.
We received an order from the SEC under the 1935 Act on June 30, 2003
relating to our 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,
68
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.
Texas Genco and the other owners of the South Texas Project maintain
nuclear property and nuclear liability insurance coverage as required by law and
periodically review available limits and coverage for additional protection. The
owners of the South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.
Under the federal Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $9.3 billion as of June 30, 2003. Owners are
required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. Texas Genco and the other owners of the
South Texas Project currently maintain the required nuclear liability insurance
and participate in the industry retrospective rating plan. In addition, the
security procedures at this facility have recently been enhanced to provide
additional protection against terrorist attacks. All potential losses or
liabilities associated with the South Texas Project may not be insurable, and
the amount of insurance may not be sufficient to cover them. In particular,
Texas Genco's insurance policies are subject to certain limits and deductibles
and do not include business interruption coverage.
In common with other companies in its line of business that serve coastal
regions, CenterPoint Houston does not have insurance covering its transmission
and distribution system because CenterPoint Houston believes it to be cost
prohibitive. If CenterPoint Houston were to sustain any loss of or damage to its
transmission and distribution properties, it would be entitled to seek to
recover such loss or damage through a change in its regulated rates, although
there is no assurance that CenterPoint Houston ultimately would obtain any such
rate recovery or that any such rate recovery would be timely granted. Therefore,
we cannot assure you that CenterPoint Houston will be able to restore any loss
of or damage to its transmission and distribution properties without negative
impact on our results of operations, financial condition and cash flows.
CHANGES IN TECHNOLOGY MAY ADVERSELY AFFECT OUR REVENUES AND RESULTS OF
OPERATIONS.
A significant portion of Texas Genco's generation facilities were
constructed many years ago and rely on older technologies. Some of Texas Genco's
competitors may have newer generation facilities and technologies that allow
them to produce and sell power more efficiently, which could adversely affect
Texas Genco's results of operations, financial condition and cash flows. In
addition, research and development activities are ongoing to improve alternate
technologies to produce electricity, including fuel cells, microturbines,
windmills and photovoltaic (solar) cells. It is possible that advances in these
or other technologies will reduce the current costs of electricity production
utilizing newer facilities to a level that is below that of Texas Genco's
generation facilities. If this occurs, Texas Genco's generation facilities will
be less competitive and the value of its power plants could be significantly
impaired. Also, electricity demand could be reduced by increased conservation
efforts and advances in technology that could likewise significantly reduce the
value of Texas Genco's power generation facilities.
The continuous process of technological development may result in the
introduction to retail customers of economically attractive alternatives to
purchasing electricity through CenterPoint Houston's distribution facilities.
Manufacturers of self-generation facilities continue to develop smaller-scale,
more-fuel-efficient generating units that can be cost-effective options for some
retail customers with smaller electric energy requirements. Any reduction in the
amount of electric energy CenterPoint Houston distributes as a result of these
technologies may have an adverse impact on its results of operations, financial
condition and cash flows in the future.
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 electric transmission
and distribution, electric generation, 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
69
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.
70
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 of CenterPoint Energy, Inc.
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
- ----------- ------------------------------------------- ----------------------------------------------------- --------------
3.1 -- Amended and Restated Articles of CenterPoint Energy's Registration 3-69502 3.1
Incorporation of CenterPoint Energy Statement on Form S-4
3.2 -- Articles of Amendment to Amended CenterPoint Energy's Form 10-K for the 1-31447 3.1.1
and Restated Articles of year ended December 31, 2001
Incorporation of CenterPoint Energy
3.3 -- Amended and Restated Bylaws of CenterPoint Energy's Form 10-K for the 1-31447 3.2
CenterPoint Energy year ended December 31, 2001
3.4 -- Statement of Resolution CenterPoint Energy's Form 10-K for the 1-31447 3.3
Establishing Series of Shares year ended December 31, 2001
designated Series A Preferred Stock
of CenterPoint Energy
4.1 -- Form of CenterPoint Energy Stock CenterPoint Energy's Registration 3-69502 4.1
Certificate Statement on Form S-4
4.2 -- Rights Agreement dated January CenterPoint Energy's Form 10-K for the 1-31447 4.2
1, 2002 between CenterPoint Energy year ended December 21, 2001
and JPMorgan Chase Bank, as Rights
Agent
4.3.1 -- General Mortgage Indenture, CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(1)
dated as of October 10, 2002, quarter ended September 30, 2002
between CenterPoint Houston and
JPMorgan Chase Bank, as Trustee
4.3.2 -- First Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(2)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.3 -- Second Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(3)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.4 -- Third Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(4)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.5 -- Fourth Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(5)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.6 -- Fifth Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(6)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.7 -- Sixth Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(7)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.8 -- Seventh Supplemental Indenture CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(8)
to Exhibit 4.3.1, dated as of quarter ended September 30, 2002
October 10, 2002
4.3.9 -- Eighth Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(9)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.10 -- Ninth Supplemental Indenture to CenterPoint Energy's Form 10-K for the 1-31447 4(e)(10)
Exhibit 4.3.1, dated as of November year ended December 31, 2002
12, 2002
4.3.11 -- Tenth Supplemental Indenture to CenterPoint Energy's Form 8-K dated 1-31447 4.1
Exhibit 4.3.1, dated as of March 18, March 13, 2003
2003
71
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
- ----------- ------------------------------------------- ----------------------------------------------------- --------------
4.3.12 -- Eleventh Supplemental Indenture CenterPoint Energy's Form 8-K dated May 1-31447 4.1
to Exhibit 4.3.1, dated as of May 16, 2003
23, 2003
--
4.3.13 -- Officer's Certificate dated CenterPoint Energy's Form 8-K dated 1-31447 4.2
March 18, 2003 setting forth the March 13, 2003
form, terms and provisions of the
Tenth Series and Eleventh Series
of general mortgage bonds
+4.3.14 -- Registration Rights Agreement,
dated as of March 18, 2003, among
CenterPoint Houston and the
representatives of the initial
purchasers named therein relating
to Tenth Series and Eleventh Series
of general mortgage bonds.
4.3.15 -- Officer's Certificate dated May CenterPoint Energy's Form 8-K dated 1-31447 4.2
23, 2003 setting forth the form, May 16, 2003
terms and provisions of the Twelfth
Series of general mortgage bonds
+4.3.16 -- Registration Rights Agreement, dated
as of May 23, 2003, among CenterPoint
Houston and the representatives of the
initial purchasers named therein
relating to Twelfth Series of general
mortgage bonds
4.4.1 -- Indenture, dated as of February CERC's Form 8-K dated February 5, 1998 1-13265 4.1
1, 1998, between RERC Corp. and
Chase Bank of Texas, National
Association, as Trustee
4.4.2 -- Supplemental Indenture No. 1 to CERC's Form 8-K dated February 5, 1998 1-13265 4.2
Exhibit 4.4.1, dated as of February
1, 1998, providing for the issuance
of RERC Corp.'s 6 1/2% Debentures
due February 1, 2008
4.4.3 -- Supplemental Indenture No. 2 to CERC's Form 8-K dated November 9, 1998 1-13265 4.1
Exhibit 4.4.1, dated as of November
1, 1998, providing for the issuance
of RERC Corp.'s 6 3/8% Term
Enhanced ReMarketable Securities
4.4.4 -- Supplemental Indenture No. 3 to CERC's Registration Statement on Form 333-49162 4.2
Exhibit 4.4.1, dated as of July 1, S-4
2000, providing for the issuance of
RERC Corp.'s 8.125% Notes due 2005
4.4.5 -- Supplemental Indenture No. 4 to CERC's Form 8-K dated February 21, 2001 1-13265 4.1
Exhibit 4.4.1, dated as of February
15, 2001, providing for the
issuance of RERC Corp.'s 7.75%
Notes due 2011
4.4.6 -- Supplemental Indenture No. 5 to CenterPoint Energy's Form 8-K dated 1-31447 4.1
Exhibit 4.4.1, dated as of March 25, March 18, 2003 2003,
providing for the issuance of CERC
Corp.'s 7.875% Senior Notes due
2013
4.4.7 -- Supplemental Indenture No. 6 to CenterPoint Energy's Form 8-K dated 1-31447 4.2
Exhibit 4.4.1, dated as of April 14, April 7, 2003
2003, providing for the issuance of
additional CERC Corp. 7.875% Senior
Notes due 2013
+4.4.8 -- Registration Rights Agreement, dated
as of March 25, 2003, among CERC and
the initial purchasers named therein
relating to CERC Corp.'s 7.875% Senior
Notes due 2013
+4.4.9 -- Registration Rights Agreement dated as
of April 14, 2003, among CERC and the
initial purchasers names therein
relating to CERC Corp.'s 7.875% Senior
Notes due 2013
72
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
- ----------- ------------------------------------------- ----------------------------------------------------- --------------
4.5.1 -- Indenture, dated as of May 19, CenterPoint Energy's Form 8-K dated May 1-31447 4.1
2003, between CenterPoint Energy and 19, 2003
JPMorgan Chase Bank, as Trustee
4.5.2 -- Supplemental Indenture No. 1 to CenterPoint Energy's Form 8-K dated May 1-31447 4.2
Exhibit 4.5.1, dated as of May 19, 19, 2003
2003 providing for the issuance of
CenterPoint Energy's 3.75%
Convertible Senior Notes due 2023
4.5.3 -- Supplemental Indenture No. 2 to CenterPoint Energy's Form 8-K dated May 1-31447 4.3
Exhibit 4.5.1, dated as of May 27, 19, 2003 2003 providing for
the issuance of CenterPoint Energy's
5.875% Senior Notes due 2008 and
6.85% Senior Notes due 2015
+4.5.4 -- Registration Rights Agreement, dated
as of May 19, 2003, among CenterPoint
Energy and the representatives of the
initial purchasers named therein
relating to CenterPoint Energy's 3.75%
Convertible Senior Notes due 2023
+4.5.5 -- Registration Rights Agreement, dated
as of May 27, 2003, among CenterPoint
Energy and the representatives of the
initial purchasers named therein
relating to CenterPoint Energy's
5.875% Senior Notes due 2008 and 6.85%
Senior Notes due 2015
+10.1 -- Pledge Agreement dated as of May 28,
2003, by Utility Holding, LLC, in
favor of JP Morgan Chase Bank, as
administrative agent
--
+31.1 -- Section 302 Certification of David M.
McClanahan
+31.2 -- Section 302 Certification of Gary L.
Whitlock
+32.1 -- Section 906 Certification of David M.
McClanahan
+32.2 -- Section 906 Certification of Gary L.
Whitlock
+99.1 -- Items incorporated by reference from
the CenterPoint Energy Form 10-K: Item
1 "Business - Environmental Matters,"
Item 3 "Legal Proceedings".
+99.2 -- Items incorporated by reference from
the CenterPoint Energy Current Report
on Form 8-K dated May 12, 2003:
Exhibit 99.1 "Management's Discussion
and Analysis of Financial Condition
and Results of Operations and Selected
Financial Data - Certain Factors
Affecting Future Earnings" and the
following Notes from Exhibit 99.2:
Notes 3(d) (Long-Lived Assets and
Intangibles), 3(e) (Regulatory Assets
and Liabilities), 3(k) (Investment in
Other Debt and Equity Securities), 4
(Regulatory Matters), 5 (Derivative
Instruments), 7 (Indexed Debt
Securities (ACES and ZENS) and AOL
Time Warner Securities), 9(b)
(Long-term Debt), 10 (Trust Preferred
Securities), 11 (Stock-Based Incentive
Compensation Plans and Employee
Benefit Plans) and 13 (Commitments and
Contingencies).
73
(b) Reports on Form 8-K.
On April 8, 2003, we filed a Current Report on Form 8-K to furnish
information under Item 9 of that form regarding our external debt balances as of
March 31, 2003.
On April 23, 2003, we filed a Current Report on Form 8-K dated April 16,
2003, reporting the filing of a class action lawsuit in California against
CenterPoint Energy, Inc. and others and the shutdown of a reactor at the South
Texas Project Nuclear Generating Station.
On April 24, 2003, we filed a Current Report on Form 8-K dated April 24,
2003, in which we announced first quarter 2003 earnings.
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 of our
subsidiary, CenterPoint Energy Resources Corp., which will be added to and form
a single series with its 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. We also furnished under Item 9 and Item 12
of Form 8-K transcripts of the earnings conference call held on April 24, 2003.
On May 12, 2003, we filed a Current Report on Form 8-K dated May 12, 2003,
to provide information giving effect to certain reclassifications within our
historical consolidated financial statements, Selected Financial Data, and
Management's Discussion and Analysis of Financial Condition and Results of
Operations as reported on our Annual Report on Form 10-K for the year ended
December 31, 2002.
On May 16, 2003, we filed a Current Report on Form 8-K dated May 12, 2003,
announcing our intent to sell $400 million aggregate principal amount of
convertible senior notes in a private offering, announcing the pricing of $500
million of 3.75% Convertible Senior Notes due 2023 in a private placement with
institutions pursuant to Rule 144A under the Securities Act of 1933, as amended,
and reporting the filing of an additional class action lawsuit in California
against CenterPoint Energy, Inc. and others.
On May 30, 2003, we filed a Current Report on Form 8-K dated May 30, 2003,
announcing that we had permanently reduced our bank credit facility by
approximately $1 billion to $2.846 billion, resulting in the extinguishment of
the rights granted to the lenders under our credit facility to receive warrants
to purchase up to 10% of our common stock. This reduction also eliminated an
additional limitation on dividends that would have been applicable under the
credit facility in 2004. Additionally, we reported that we had received approval
from the SEC to pledge the Texas Genco Holdings, Inc. stock we own as security
for the credit facility.
On June 3, 2003, we filed a Current Report on Form 8-K dated May 19, 2003,
announcing the closing of $575 million of 3.75% Convertible Senior Notes due
2023 and the pricing and closing of $400 million aggregate principal amount of
senior notes in a private placement with institutions pursuant to Rule 144A
under the Securities Act of 1933, as amended. Of the $400 million aggregate
principal amount of senior notes, $200 million, at an interest rate of 5.875
percent, will be due June 1, 2008 and the remaining $200 million, with an
interest rate of 6.85 percent, will be due on June 1, 2015.
On June 11, 2003, we filed a Current Report on Form 8-K dated June 2, 2003,
to furnish information under Item 9 of that form regarding a slide presentation
and information regarding our external debt balances to be presented to various
members of the utility industry and the financial and investment community at
the Deutsche Bank Electric Power conference.
On June 20, 2003, we filed a Current Report on Form 8-K dated May 16, 2003,
announcing the pricing and closing of $200 million aggregate principal amount of
general mortgage bonds of our subsidiary, CenterPoint Energy Houston Electric,
LLC, in a private placement with institutions pursuant to Rule 144A under the
Securities Act of 1933, as amended. The bonds bear interest at a rate of 5.60
percent and will be due July 1, 2023.
On June 20, 2003, we filed a Current Report on Form 8-K dated June 18,
2003, announcing that the Public Utility Commission of Texas (Texas Utility
Commission) ruled that the filing by our subsidiary CenterPoint Energy Houston
Electric, LLC, for recovery of its stranded costs and regulatory assets as
provided by the Texas electric restructuring law will be made on March 31, 2004.
The law requires a final order to be issued by the Texas Utility Commission not
more than 150 days after a proper filing is made by the regulated utility.
74
On July 29, 2003, we filed a Current Report on Form 8-K dated July 29,
2003, in which we announced second quarter 2003 earnings.
75
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CENTERPOINT ENERGY, INC.
By: /s/ James S. Brian
----------------------------------------
James S. Brian
Senior Vice President and Chief Accounting Officer
Date: August 13, 2003
76
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 of CenterPoint Energy, Inc.
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
- ----------- ------------------------------------------- ----------------------------------------------------- --------------
3.1 -- Amended and Restated Articles of CenterPoint Energy's Registration 3-69502 3.1
Incorporation of CenterPoint Energy Statement on Form S-4
3.2 -- Articles of Amendment to Amended CenterPoint Energy's Form 10-K for the 1-31447 3.1.1
and Restated Articles of year ended December 31, 2001
Incorporation of CenterPoint Energy
3.3 -- Amended and Restated Bylaws of CenterPoint Energy's Form 10-K for the 1-31447 3.2
CenterPoint Energy year ended December 31, 2001
3.4 -- Statement of Resolution CenterPoint Energy's Form 10-K for the 1-31447 3.3
Establishing Series of Shares year ended December 31, 2001
designated Series A Preferred Stock
of CenterPoint Energy
4.1 -- Form of CenterPoint Energy Stock CenterPoint Energy's Registration 3-69502 4.1
Certificate Statement on Form S-4
4.2 -- Rights Agreement dated January CenterPoint Energy's Form 10-K for the 1-31447 4.2
1, 2002 between CenterPoint Energy year ended December 21, 2001
and JPMorgan Chase Bank, as Rights
Agent
4.3.1 -- General Mortgage Indenture, CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(1)
dated as of October 10, 2002, quarter ended September 30, 2002
between CenterPoint Houston and
JPMorgan Chase Bank, as Trustee
4.3.2 -- First Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(2)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.3 -- Second Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(3)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.4 -- Third Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(4)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.5 -- Fourth Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(5)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.6 -- Fifth Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(6)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.7 -- Sixth Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(7)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.8 -- Seventh Supplemental Indenture CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(8)
to Exhibit 4.3.1, dated as of quarter ended September 30, 2002
October 10, 2002
4.3.9 -- Eighth Supplemental Indenture to CenterPoint Houston's Form 10-Q for the 1-3187 4(j)(9)
Exhibit 4.3.1, dated as of October quarter ended September 30, 2002
10, 2002
4.3.10 -- Ninth Supplemental Indenture to CenterPoint Energy's Form 10-K for the 1-31447 4(e)(10)
Exhibit 4.3.1, dated as of November year ended December 31, 2002
12, 2002
4.3.11 -- Tenth Supplemental Indenture to CenterPoint Energy's Form 8-K dated 1-31447 4.1
Exhibit 4.3.1, dated as of March 18, March 13, 2003
2003
77
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
- ----------- ------------------------------------------- ----------------------------------------------------- --------------
4.3.12 -- Eleventh Supplemental Indenture CenterPoint Energy's Form 8-K dated May 1-31447 4.1
to Exhibit 4.3.1, dated as of May 16, 2003
23, 2003
--
4.3.13 -- Officer's Certificate dated CenterPoint Energy's Form 8-K dated 1-31447 4.2
March 18, 2003 setting forth the March 13, 2003
form, terms and provisions of the
Tenth Series and Eleventh Series
of general mortgage bonds
+4.3.14 -- Registration Rights Agreement,
dated as of March 18, 2003, among
CenterPoint Houston and the
representatives of the initial
purchasers named therein relating
to Tenth Series and Eleventh Series
of general mortgage bonds.
4.3.15 -- Officer's Certificate dated May CenterPoint Energy's Form 8-K dated 1-31447 4.2
23, 2003 setting forth the form, May 16, 2003
terms and provisions of the Twelfth
Series of general mortgage bonds
+4.3.16 -- Registration Rights Agreement, dated
as of May 23, 2003, among CenterPoint
Houston and the representatives of the
initial purchasers named therein
relating to Twelfth Series of general
mortgage bonds
4.4.1 -- Indenture, dated as of February CERC's Form 8-K dated February 5, 1998 1-13265 4.1
1, 1998, between RERC Corp. and
Chase Bank of Texas, National
Association, as Trustee
4.4.2 -- Supplemental Indenture No. 1 to CERC's Form 8-K dated February 5, 1998 1-13265 4.2
Exhibit 4.4.1, dated as of February
1, 1998, providing for the issuance
of RERC Corp.'s 6 1/2% Debentures
due February 1, 2008
4.4.3 -- Supplemental Indenture No. 2 to CERC's Form 8-K dated November 9, 1998 1-13265 4.1
Exhibit 4.4.1, dated as of November
1, 1998, providing for the issuance
of RERC Corp.'s 6 3/8% Term
Enhanced ReMarketable Securities
4.4.4 -- Supplemental Indenture No. 3 to CERC's Registration Statement on Form 333-49162 4.2
Exhibit 4.4.1, dated as of July 1, S-4
2000, providing for the issuance of
RERC Corp.'s 8.125% Notes due 2005
4.4.5 -- Supplemental Indenture No. 4 to CERC's Form 8-K dated February 21, 2001 1-13265 4.1
Exhibit 4.4.1, dated as of February
15, 2001, providing for the
issuance of RERC Corp.'s 7.75%
Notes due 2011
4.4.6 -- Supplemental Indenture No. 5 to CenterPoint Energy's Form 8-K dated 1-31447 4.1
Exhibit 4.4.1, dated as of March 25, March 18, 2003 2003,
providing for the issuance of CERC
Corp.'s 7.875% Senior Notes due
2013
4.4.7 -- Supplemental Indenture No. 6 to CenterPoint Energy's Form 8-K dated 1-31447 4.2
Exhibit 4.4.1, dated as of April 14, April 7, 2003
2003, providing for the issuance of
additional CERC Corp. 7.875% Senior
Notes due 2013
+4.4.8 -- Registration Rights Agreement, dated
as of March 25, 2003, among CERC and
the initial purchasers named therein
relating to CERC Corp.'s 7.875% Senior
Notes due 2013
+4.4.9 -- Registration Rights Agreement dated as
of April 14, 2003, among CERC and the
initial purchasers names therein
relating to CERC Corp.'s 7.875% Senior
Notes due 2013
78
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
- ----------- ------------------------------------------- ----------------------------------------------------- --------------
4.5.1 -- Indenture, dated as of May 19, CenterPoint Energy's Form 8-K dated May 1-31447 4.1
2003, between CenterPoint Energy and 19, 2003
JPMorgan Chase Bank, as Trustee
4.5.2 -- Supplemental Indenture No. 1 to CenterPoint Energy's Form 8-K dated May 1-31447 4.2
Exhibit 4.5.1, dated as of May 19, 19, 2003
2003 providing for the issuance of
CenterPoint Energy's 3.75%
Convertible Senior Notes due 2023
4.5.3 -- Supplemental Indenture No. 2 to CenterPoint Energy's Form 8-K dated May 1-31447 4.3
Exhibit 4.5.1, dated as of May 27, 19, 2003 2003 providing for
the issuance of CenterPoint Energy's
5.875% Senior Notes due 2008 and
6.85% Senior Notes due 2015
+4.5.4 -- Registration Rights Agreement, dated
as of May 19, 2003, among CenterPoint
Energy and the representatives of the
initial purchasers named therein
relating to CenterPoint Energy's 3.75%
Convertible Senior Notes due 2023
+4.5.5 -- Registration Rights Agreement, dated
as of May 27, 2003, among CenterPoint
Energy and the representatives of the
initial purchasers named therein
relating to CenterPoint Energy's
5.875% Senior Notes due 2008 and 6.85%
Senior Notes due 2015
+10.1 -- Pledge Agreement dated as of May 28,
2003, by Utility Holding, LLC, in
favor of JP Morgan Chase Bank, as
administrative agent
--
+31.1 -- Section 302 Certification of David M.
McClanahan
+31.2 -- Section 302 Certification of Gary L.
Whitlock
+32.1 -- Section 906 Certification of David M.
McClanahan
+32.2 -- Section 906 Certification of Gary L.
Whitlock
+99.1 -- Items incorporated by reference from
the CenterPoint Energy Form 10-K: Item
1 "Business - Environmental Matters,"
Item 3 "Legal Proceedings".
+99.2 -- Items incorporated by reference from
the CenterPoint Energy Current Report
on Form 8-K dated May 12, 2003:
Exhibit 99.1 "Management's Discussion
and Analysis of Financial Condition
and Results of Operations and Selected
Financial Data - Certain Factors
Affecting Future Earnings" and the
following Notes from Exhibit 99.2:
Notes 3(d) (Long-Lived Assets and
Intangibles), 3(e) (Regulatory Assets
and Liabilities), 3(k) (Investment in
Other Debt and Equity Securities), 4
(Regulatory Matters), 5 (Derivative
Instruments), 7 (Indexed Debt
Securities (ACES and ZENS) and AOL
Time Warner Securities), 9(b)
(Long-term Debt), 10 (Trust Preferred
Securities), 11 (Stock-Based Incentive
Compensation Plans and Employee
Benefit Plans) and 13 (Commitments and
Contingencies).
79