UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q/A
AMENDMENT NO. 1
(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, 2005
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 (713) 207-1111
(Address and zip code of (Registrant's telephone number,
principal executive offices) 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
----- -----
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes No X
----- -----
As of August 1, 2005, CenterPoint Energy, Inc. had 309,549,770 shares of common
stock outstanding, excluding 166 shares held as treasury stock.
EXPLANATORY NOTE
CenterPoint Energy, Inc. (CenterPoint Energy or the Company) hereby amends
Items 1, 2, and 4 of Part I and Item 6 of Part II of its Quarterly Report on
Form 10-Q for the period ended June 30, 2005 as originally filed on August 8,
2005 (Form 10-Q) to reflect the restatement of the Company's unaudited condensed
consolidated financial statements as discussed in Note 14. In addition, the
Company has modified the presentation of discontinued operations in its
condensed statements of consolidated cash flows as discussed in Note 1.
Contemporaneously with the filing of this Amendment No. 1 to the Form 10-Q on
this Form 10-Q/A, the Company is filing Amendment No. 2 to its Annual Report on
Form 10-K/A for the year ended December 31, 2004.
For purposes of this Form 10-Q/A, and in accordance with Rule 12b-15 under
the Securities Exchange Act of 1934, as amended, each item of the Form 10-Q that
was affected by the restatement has been amended to the extent affected and
restated in its entirety. NO ATTEMPT HAS BEEN MADE IN THIS FORM 10-Q/A TO UPDATE
OTHER DISCLOSURES AS PRESENTED IN THE FORM 10-Q EXCEPT AS REQUIRED TO REFLECT
THE EFFECTS OF THE RESTATEMENT. ACCORDINGLY, THIS FORM 10-Q/A SHOULD BE READ IN
CONJUNCTION WITH THE COMPANY'S SEC FILINGS MADE SUBSEQUENT TO THE FILING OF THE
FORM 10-Q, INCLUDING ANY AMENDMENTS OF THOSE FILINGS. IN ADDITION, THIS FORM
10-Q/A INCLUDES UPDATED CERTIFICATIONS FROM THE COMPANY'S CEO AND CFO AS
EXHIBITS 31.1, 31.2, 32.1 AND 32.2.
i
CENTERPOINT ENERGY, INC.
QUARTERLY REPORT ON FORM 10-Q/A
FOR THE QUARTER ENDED JUNE 30, 2005
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements........................................ 1
Condensed Statements of Consolidated Income
Three Months and Six Months Ended June 30, 2004 and 2005
(unaudited) (as restated).................................. 1
Condensed Consolidated Balance Sheets
December 31, 2004 and June 30, 2005 (unaudited)
(as restated).............................................. 2
Condensed Statements of Consolidated Cash Flows
Six Months Ended June 30, 2004 and 2005 (unaudited)
(as restated).............................................. 4
Notes to Unaudited Condensed Consolidated Financial Statements... 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations of CenterPoint Energy, Inc.
and Subsidiaries................................................. 31
Item 4. Controls and Procedures..................................... 47
PART II. OTHER INFORMATION
Item 6. Exhibits.................................................... 49
ii
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:
- the timing and amount of our recovery of the true-up components;
- state and federal legislative and regulatory actions or
developments, including deregulation, re-regulation, constraints
placed on our activities or business by the Public Utility
Holding Company Act of 1935, as amended (1935 Act), the impact of
the repeal of the 1935 Act, changes in or application of laws or
regulations applicable to other aspects of our business and
actions with respect to:
- allowed rates of return;
- rate structures;
- recovery of investments; and
- operation and construction of facilities;
- timely rate increases, including recovery of costs;
- industrial, commercial and residential growth in our service
territory and changes in market demand and demographic patterns;
- the timing and extent of changes in commodity prices,
particularly natural gas;
- changes in interest rates or rates of inflation;
- weather variations and other natural phenomena;
- the timing and extent of changes in the supply of natural gas;
- commercial bank and financial market conditions, our access to
capital, the cost of such capital, receipt of certain financing
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;
- effectiveness of our risk management activities;
- inability of various counterparties to meet their obligations to
us;
- non-payment for our services due to financial distress of our
customers, including Reliant Energy, Inc. (formerly named Reliant
Resources, Inc.) (RRI);
- the outcome of the pending lawsuits against us, Reliant Energy,
Incorporated and RRI;
iii
- the ability of RRI to satisfy its obligations to us, including
indemnity obligations;
- our ability to control costs;
- the investment performance of our employee benefit plans;
- our internal restructuring or other restructuring options that
may be pursued;
- our potential business strategies, including acquisitions or
dispositions of assets or businesses, which cannot be assured to
be completed or to have the anticipated benefits to us; and
- other factors discussed under "Risk Factors" beginning on page 51
in Item 5 of Part II of our Quarterly Report on Form 10-Q for the
period ended June 30, 2005 filed on August 8, 2005.
Additional risk factors are described in other documents we file with the
Securities and Exchange Commission.
You should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement.
iv
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------- -----------------------
2004 2005 2004 2005
---------- ---------- ---------- ----------
(AS RESTATED, SEE NOTE 14)
REVENUES ....................................................... $1,593,801 $1,841,799 $3,995,089 $4,436,503
---------- ---------- ---------- ----------
EXPENSES:
Natural gas ................................................. 904,032 1,102,169 2,539,379 2,883,401
Operation and maintenance ................................... 297,638 324,776 613,480 637,847
Depreciation and amortization ............................... 120,074 135,837 236,292 265,610
Taxes other than income taxes ............................... 86,176 92,705 180,164 187,366
---------- ---------- ---------- ----------
Total .................................................... 1,407,920 1,655,487 3,569,315 3,974,224
---------- ---------- ---------- ----------
OPERATING INCOME ............................................... 185,881 186,312 425,774 462,279
---------- ---------- ---------- ----------
OTHER INCOME (EXPENSE):
Gain (loss) on Time Warner investment ....................... 15,581 (18,177) (8,872) (59,291)
Gain (loss) on indexed debt securities ...................... (17,891) 23,819 9,123 63,348
Interest and other finance charges .......................... (188,984) (179,652) (371,957) (352,992)
Interest on transition bonds ................................ (9,547) (9,077) (19,221) (18,297)
Return on true-up balance ................................... -- 35,475 -- 69,557
Other, net .................................................. 12,425 6,936 13,932 10,748
---------- ---------- ---------- ----------
Total .................................................... (188,416) (140,676) (376,995) (286,927)
---------- ---------- ---------- ----------
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM .......................................... (2,535) 45,636 48,779 175,352
Income Tax Expense .......................................... (191) (17,931) (22,607) (80,995)
---------- ---------- ---------- ----------
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY
ITEM ........................................................ (2,726) 27,705 26,172 94,357
DISCONTINUED OPERATIONS:
Income (Loss) from Texas Genco, net of tax .................. 75,636 (2,988) 131,922 10,685
Minority Interest in Income from Texas Genco ................ (15,258) -- (26,855) --
Loss on Disposal of Texas Genco, net of tax ................ -- (735) -- (13,972)
---------- ---------- ---------- ----------
Total .................................................... 60,378 (3,723) 105,067 (3,287)
---------- ---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM ............................... 57,652 23,982 131,239 91,070
EXTRAORDINARY ITEM, NET OF TAX ................................. -- 30,441 -- 30,441
---------- ---------- ---------- ----------
NET INCOME ..................................................... $ 57,652 $ 54,423 $ 131,239 $ 121,511
========== ========== ========== ==========
BASIC EARNINGS PER SHARE:
Income (Loss) from Continuing Operations .................... $ (0.01) $ 0.09 $ 0.09 $ 0.30
Discontinued Operations, net of tax ......................... 0.20 (0.01) 0.34 (0.01)
Extraordinary Item, net of tax .............................. -- 0.10 -- 0.10
---------- ---------- ---------- ----------
Net Income .................................................. $ 0.19 $ 0.18 $ 0.43 $ 0.39
========== ========== ========== ==========
DILUTED EARNINGS PER SHARE:
Income (Loss) from Continuing Operations .................... $ (0.01) $ 0.09 $ 0.08 $ 0.28
Discontinued Operations, net of tax ......................... 0.20 (0.01) 0.34 (0.01)
Extraordinary Item, net of tax .............................. -- 0.08 -- 0.08
---------- ---------- ---------- ----------
Net Income .................................................. $ 0.19 $ 0.16 $ 0.42 $ 0.35
========== ========== ========== ==========
See Notes to the Company's Interim Financial Statements
1
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
ASSETS
DECEMBER 31, JUNE 30,
2004 2005
------------ -------------
(AS RESTATED,
SEE NOTE 14)
CURRENT ASSETS:
Cash and cash equivalents .................... $ 164,645 $ 408,162
Investment in Time Warner common stock ....... 420,882 361,590
Accounts receivable, net ..................... 674,355 460,885
Accrued unbilled revenues .................... 576,252 271,779
Natural gas inventory ........................ 175,784 168,672
Materials and supplies ....................... 77,902 77,674
Non-trading derivative assets ................ 50,219 67,638
Taxes receivable ............................. -- 6,368
Current assets of discontinued operations .... 513,768 --
Prepaid expenses and other current assets .... 116,909 112,226
----------- -----------
Total current assets ...................... 2,770,716 1,934,994
----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment ................ 10,963,569 11,182,282
Less accumulated depreciation and
amortization .............................. (2,777,176) (2,908,991)
----------- -----------
Property, plant and equipment, net ........ 8,186,393 8,273,291
----------- -----------
OTHER ASSETS:
Goodwill, net ................................ 1,740,510 1,744,252
Other intangibles, net ....................... 58,068 57,062
Regulatory assets ............................ 3,349,944 2,928,968
Non-trading derivative assets ................ 17,682 56,349
Non-current assets of discontinued
operations ................................ 1,051,158 --
Other ........................................ 921,678 844,972
----------- -----------
Total other assets ........................ 7,139,040 5,631,603
----------- -----------
TOTAL ASSETS ........................... $18,096,149 $15,839,888
=========== ===========
See Notes to the Company's Interim Financial Statements
2
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS - (CONTINUED)
(THOUSANDS OF DOLLARS)
(UNAUDITED)
LIABILITIES AND SHAREHOLDERS' EQUITY
DECEMBER 31, JUNE 30,
2004 2005
------------ -------------
(AS RESTATED,
SEE NOTE 14)
CURRENT LIABILITIES:
Current portion of transition bond long-term debt ..................... $ 46,806 $ 49,352
Current portion of other long-term debt ............................... 1,789,182 1,748,083
Indexed debt securities derivative .................................... 341,575 278,227
Accounts payable ...................................................... 802,215 496,459
Taxes accrued ......................................................... 609,025 117,313
Interest accrued ...................................................... 151,365 158,282
Non-trading derivative liabilities .................................... 26,323 13,124
Regulatory liabilities ................................................ 225,158 --
Accumulated deferred income taxes, net ................................ 260,958 286,357
Current liabilities of discontinued operations ........................ 448,974 --
Other ................................................................. 419,811 440,659
----------- -----------
Total current liabilities .......................................... 5,121,392 3,587,856
----------- -----------
OTHER LIABILITIES:
Accumulated deferred income taxes, net ................................ 2,415,143 2,472,727
Unamortized investment tax credits .................................... 53,690 49,937
Non-trading derivative liabilities .................................... 6,413 5,873
Benefit obligations ................................................... 440,110 451,562
Regulatory liabilities ................................................ 1,081,370 744,260
Non-current liabilities of discontinued operations .................... 420,393 --
Other ................................................................. 259,120 295,637
----------- -----------
Total other liabilities ............................................ 4,676,239 4,019,996
----------- -----------
LONG-TERM DEBT:
Transition bonds ...................................................... 628,903 610,462
Other ................................................................. 6,564,113 6,440,756
----------- -----------
Total long-term debt ............................................... 7,193,016 7,051,218
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 11)
SHAREHOLDERS' EQUITY:
Common stock (308,045,215 shares and 309,396,223 shares outstanding
at December 31, 2004 and June 30, 2005, respectively) .............. 3,080 3,094
Additional paid-in capital ............................................ 2,891,335 2,907,227
Accumulated deficit ................................................... (1,727,571) (1,689,435)
Accumulated other comprehensive loss .................................. (61,342) (40,068)
----------- -----------
Total shareholders' equity ......................................... 1,105,502 1,180,818
----------- -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ...................... $18,096,149 $15,839,888
=========== ===========
See Notes to the Company's Interim Financial Statements
3
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
SIX MONTHS ENDED JUNE 30,
-------------------------
2004 2005
--------- ---------
(AS RESTATED, SEE NOTE 14)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................................... $ 131,239 $ 121,511
Discontinued operations, net of tax .......................................... (105,067) 3,287
Extraordinary item, net of tax ............................................... -- (30,441)
--------- ---------
Income from continuing operations ............................................ 26,172 94,357
Adjustments to reconcile income from continuing operations to net cash
provided by operating activities:
Depreciation and amortization ............................................. 236,292 265,610
Amortization of deferred financing costs .................................. 43,665 39,521
Deferred income taxes ..................................................... 56,696 48,074
Investment tax credit ..................................................... (3,753) (3,753)
Unrealized loss on Time Warner investment ................................. 8,872 59,291
Unrealized gain on indexed debt securities ................................ (9,123) (63,348)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net ......................... 350,204 559,110
Inventory .............................................................. 28,651 9,438
Taxes receivable ....................................................... 48,304 (6,368)
Accounts payable ....................................................... (152,840) (305,469)
Fuel cost over (under) recovery/surcharge .............................. 53,376 (47,220)
Non-trading derivatives, net ........................................... (9,847) 1,252
Interest and taxes accrued ............................................. (40,026) (483,381)
Excess tax deduction related to share-based payment arrangements ....... -- (1,447)
Net regulatory assets and liabilities .................................. (157,728) (132,876)
Other current assets ................................................... 16,210 4,683
Other current liabilities .............................................. (14,867) (8,426)
Other assets ........................................................... (8,540) 1,753
Other liabilities ...................................................... (5,463) 18,117
Other, net ................................................................ 21,045 6,166
--------- ---------
Net cash provided by operating activities of continuing operations .. 487,300 55,084
Net cash provided by (used in) operating activities of
discontinued operations .......................................... 204,797 (38,119)
--------- ---------
Net cash provided by operating activities ........................... 692,097 16,965
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ......................................................... (246,111) (310,279)
Proceeds from sale of Texas Genco ............................................ -- 700,000
Decrease in restricted cash of Texas Genco ................................... -- 383,132
Purchase of minority interest in Texas Genco ................................. -- (383,132)
Decrease (increase) in cash of Texas Genco.................................... (140,002) 23,170
Other, net ................................................................... (10,566) (1,106)
--------- ---------
Net cash provided by (used in) investing activities ................. (396,679) 411,785
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings, net ............................ (63,000) 75,000
Long-term revolving credit facilities, net ................................... 137,500 (119,000)
Proceeds from long-term debt ................................................. 229,050 --
Payments of long-term debt ................................................... (513,927) (61,303)
Debt issuance costs .......................................................... (13,504) (6,231)
Payment of common stock dividends ............................................ (61,366) (83,338)
Payment of common stock dividends by subsidiary .............................. (7,618) --
Proceeds from issuance of common stock, net .................................. 6,879 8,192
Excess tax deduction related to share-based payment arrangements ............. -- 1,447
Other, net ................................................................... (2) --
--------- ---------
Net cash used in financing activities ............................... (285,988) (185,233)
--------- ---------
NET INCREASE IN CASH AND CASH EQUIVALENTS ....................................... 9,430 243,517
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ................................ 86,922 164,645
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ...................................... $ 96,352 $ 408,162
========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest ..................................................................... $ 365,799 $ 328,817
Income taxes ................................................................. 34,159 457,008
See Notes to the Company's Interim Financial Statements
4
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(1) BACKGROUND AND BASIS OF PRESENTATION
General. Included in this Quarterly Report on Form 10-Q/A (Form 10-Q/A) of
CenterPoint Energy, Inc. are the condensed consolidated interim financial
statements and notes (Interim Financial Statements) of CenterPoint Energy, Inc.
and its subsidiaries (collectively, CenterPoint Energy, or the Company). The
Interim Financial Statements are unaudited, omit certain financial statement
disclosures and should be read with the Annual Report on Form 10-K of
CenterPoint Energy for the year ended December 31, 2004 filed on March 16, 2005
(CenterPoint Energy Form 10-K), as amended by Amendment No. 1 thereto filed on
August 29, 2005, and as amended by Amendment No. 2 thereto filed on January 10,
2006 (CenterPoint Energy Form 10-K/A).
Background. CenterPoint Energy, Inc. 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 Choice Plan (Texas electric restructuring law).
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 and those of its subsidiaries. The 1935 Act, among
other things, limits the ability of the Company and its subsidiaries to issue
debt and equity securities without prior authorization, restricts the source of
dividend payments to current and retained earnings without prior authorization,
regulates sales and acquisitions of certain assets and businesses and governs
affiliated service, sales and construction contracts. On July 29, 2005, Congress
passed the Energy Policy Act of 2005 (Energy Act), which President Bush is
expected to sign in early August. Under that legislation, the 1935 Act is
repealed six months after the enactment of the Energy Act. After the effective
date of repeal, the Company and its subsidiaries will no longer be subject to
restrictions imposed under the 1935 Act. Until the repeal is effective, the
Company and its subsidiaries remain subject to the provisions of the 1935 Act
and the terms of orders issued by the Securities and Exchange Commission (SEC)
under the 1935 Act. The Energy Act transfers to the Federal Energy Regulatory
Commission (FERC) certain functions performed by the SEC under the 1935 Act,
including the requirement that holding companies and their subsidiaries maintain
certain books and records and make them available for review by FERC and,
through FERC, to state regulatory authorities. The Energy Act requires FERC to
issue regulations to implement its jurisdiction under the Energy Act. It is
presently unknown what, if any, specific obligations under those rules may be
imposed on the Company and its subsidiaries as result of that rulemaking.
The Company's operating subsidiaries own and operate electric transmission
and distribution facilities, natural gas distribution facilities, interstate
pipelines and natural gas gathering, processing and treating facilities. As of
June 30, 2005, the Company's indirect wholly owned subsidiaries included:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
engages in the 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 gas distribution systems. The
operations of its local distribution companies are conducted through
three unincorporated divisions: Houston Gas, Minnesota Gas and
Southern Gas Operations. Through wholly owned subsidiaries, CERC owns
two interstate natural gas pipelines and gas gathering systems,
provides various ancillary services, and offers variable and fixed
price physical natural gas supplies to commercial and industrial
customers and natural gas distributors.
On April 13, 2005, the Company sold Texas Genco Holdings, Inc. (Texas
Genco), whose primary remaining asset was its ownership interest in a nuclear
generating facility, to Texas Genco LLC in exchange for a cash payment to the
Company of $700 million. See Note 2 for further discussion.
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
5
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
The Company's Interim Financial Statements reflect all normal recurring
adjustments that are, in the opinion of management, necessary to present fairly
the financial position and results of operations for the respective periods.
Amounts reported in the Company's Condensed Statements of Consolidated Income
are not necessarily indicative of amounts expected for a full-year period due to
the effects of, among other things, (a) seasonal fluctuations in demand for
energy and energy services, (b) changes in energy commodity prices, (c) timing
of maintenance and other expenditures and (d) acquisitions and dispositions of
businesses, assets and other interests. In addition, certain amounts from the
prior year have been reclassified to conform to the Company's presentation of
financial statements in the current year. These reclassifications do not affect
net income. The Company has also modified the presentation of its Condensed
Statements of Consolidated Cash Flows to reflect cash flows of discontinued
operations within the respective categories of operating, investing and
financing activities to conform to the presentation in its annual financial
statements. This reclassification did not affect the Company's total net change
in cash and cash equivalents.
Note 2(d) (Long-Lived Assets and Intangibles), Note 2(e) (Regulatory Assets
and Liabilities), Note 4 (Regulatory Matters), Note 5 (Derivative Instruments),
Note 6 (Indexed Debt Securities (ZENS) and Time Warner Securities) and Note 11
(Commitments and Contingencies) to the consolidated annual financial statements
in the CenterPoint Energy Form 10-K/A (CenterPoint Energy 10-K/A Notes) relate
to certain contingencies. These notes, as updated herein, should be read with
this Form 10-Q/A.
For information regarding certain legal and regulatory proceedings and
environmental matters, see Note 11 to the Interim Financial Statements.
(2) DISCONTINUED OPERATIONS
In July 2004, the Company announced its agreement to sell its
majority-owned generating subsidiary, Texas Genco, to Texas Genco LLC. On
December 15, 2004, Texas Genco completed the sale of its fossil generation
assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813
billion in cash. Following the sale, Texas Genco distributed $2.231 billion in
cash to the Company. Following that sale, Texas Genco's principal remaining
asset was its ownership interest in a nuclear generating facility. The final
step of the transaction, the merger of Texas Genco with a subsidiary of Texas
Genco LLC in exchange for an additional cash payment to the Company of $700
million, was completed on April 13, 2005.
The Company recorded after-tax income of $60 million and $105 million for
the three and six months ended June 30, 2004, respectively, related to the
operations of Texas Genco. The Company recorded an after-tax loss of $3 million
for each of the three and six month periods ended June 30, 2005. General
corporate overhead, previously allocated to Texas Genco from the Company, was $5
million and $10 million for the three and six months ended June 30, 2004,
respectively, and was less than $1 million for each of the three and six month
periods ended June 30, 2005. These amounts will not be eliminated by the sale of
Texas Genco and were excluded from income from discontinued operations and
reflected as general corporate overhead of the Company in income from continuing
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 Interim Financial Statements present these operations as
discontinued operations in accordance with SFAS No. 144. Interest expense of $12
million and $24 million for the three and six months ended June 30, 2004,
respectively, was reclassified to discontinued operations of Texas Genco related
to the applicable amounts of CenterPoint Energy's term loan and revolving credit
facility debt that would have been assumed to be paid off with any proceeds from
the sale of Texas Genco during those respective periods in accordance with SFAS
No. 144.
Revenues related to Texas Genco included in discontinued operations for the
three and six months ended June 30, 2004 were $553 million and $992 million,
respectively. Revenues for the three and six months ended June 30, 2005 were $5
million and $62 million, respectively. Income from these discontinued operations
for the three and six months ended June 30, 2004 is reported net of income tax
expense of $41 million and $71 million, respectively. Income from these
discontinued operations for the three and six months ended June 30, 2005 is
reported net of income tax expense (benefit) of $(2) million and $4 million,
respectively.
(3) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS
(a) Stock-Based Incentive Compensation Plans.
The Company has long-term incentive compensation plans (LICPs) that provide
for the issuance of stock-based incentives, including performance-based shares,
performance-based units, restricted shares and stock options to
6
directors, officers and key employees. A maximum of approximately 37 million
shares of CenterPoint Energy common stock are authorized to be issued under
these plans.
Performance-based shares, performance-based units and restricted shares are
granted to employees without cost to the participants. The performance shares
and units vest three years after the grant date based upon the performance of
the Company over a three-year cycle. The restricted shares vest at various times
ranging from one-year to the end of a three-year period. Upon vesting, the
shares are issued to the plan participants.
Option awards are generally granted with an exercise price equal to the
average of the high and low sales price of the Company's stock at the date of
grant. These options awards generally become exercisable in one-third increments
on each of the first through third anniversaries of the grant date and have
10-year contractual terms. No options were granted during the three and six
months ended June 30, 2005.
Effective January 1, 2005, the Company adopted SFAS No. 123 (Revised 2004),
"Share-Based Payment" (SFAS 123(R)) using the modified prospective transition
method. Under this method, the Company records compensation expense at fair
value for all awards it grants after the date it adopts the standard. In
addition, the Company is required to record compensation expense at fair value
(as previous awards continue to vest) for the unvested portion of previously
granted stock option awards that were outstanding as of the date of adoption.
Pre-adoption awards of time-based restricted stock and performance-based
restricted stock will continue to be expensed using the guidance contained in
SFAS No. 123. The adoption of SFAS 123(R) did not have a material impact on the
Company's results of operations, financial condition or cash flows.
The Company recorded LICP compensation expense of $2 million and $4 million
for the three and six months ended June 30, 2004, respectively. LICP
compensation expense for the three and six months ended June 30, 2005 was $2
million and $6 million, respectively.
The total income tax benefit recognized related to such arrangements was $1
million and $2 million for the three and six months ended June 30, 2004,
respectively. Income tax benefit for the three and six months ended June 30,
2005 was $1 million and $2 million, respectively. No compensation cost was
capitalized as a part of inventory and fixed assets in either of the three or
six month periods ended June 30, 2004 and 2005.
Pro forma information for the three and six months ended June 30, 2004 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 (in millions, except per share
amounts):
THREE MONTHS SIX MONTHS
ENDED ENDED
JUNE 30, 2004 JUNE 30, 2004
------------- -------------
Net Income:
As reported ................................................ $ 58 $ 131
Add: stock-based compensation as recorded .................. 1 2
Less: total stock-based employee compensation determined
under the fair value based method ....................... (1) (4)
----- -----
Pro forma .................................................. $ 58 $ 129
===== =====
Basic Earnings Per Share:
As reported ................................................ $0.19 $0.43
Pro forma .................................................. 0.19 0.42
Diluted Earnings Per Share:
As reported ................................................ 0.19 0.42
Pro forma .................................................. 0.19 0.42
7
The following tables summarize the methods used to measure compensation
cost for the various types of awards granted under the LICPs:
FOR AWARDS GRANTED BEFORE JANUARY 1, 2005
AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST
--------------------------- -------------------------------------------
Performance shares Initially measured using fair value and
expected achievement levels on the date of
grant. Compensation cost is then
periodically adjusted to reflect changes in
market prices and achievement through the
settlement date.
Performance units Initially measured using the award's target
unit value of $100 that reflects expected
achievement levels on the date of grant.
Compensation cost is then periodically
adjusted to reflect changes in achievement
through the settlement date.
Time-based restricted stock Measured using fair value on the grant date.
Stock options Estimated using the Black-Scholes option
valuation method.
FOR AWARDS GRANTED AS OF AND AFTER JANUARY 1, 2005
AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST
--------------------------- -------------------------------------------
Performance shares Measured using fair value and expected
achievement levels on the grant date.
Time-based restricted stock Measured using fair value on the grant date.
For awards granted before January 1, 2005, forfeitures of awards were
measured upon their occurrence. For awards granted as of and after January 1,
2005, forfeitures are estimated on the date of grant and are adjusted as
required through the remaining vesting period.
The following tables summarize the Company's LICP activity for the three
and six months ended June 30, 2005:
STOCK OPTIONS
OUTSTANDING OPTIONS
THREE MONTHS ENDED JUNE 30, 2005
--------------------------------
WEIGHTED-
AVERAGE
SHARES EXERCISE
(THOUSANDS) PRICE
----------- ---------
Outstanding at March 31, 2005........ 15,693 $15.62
Canceled.......................... (509) 16.28
Exercised......................... (296) 6.33
------
Outstanding at June 30, 2005......... 14,888 15.78
======
NON-VESTED OPTIONS
THREE MONTHS ENDED JUNE 30, 2005
---------------------------------
WEIGHTED-
AVERAGE
SHARES GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------
Outstanding at March 31, 2005........ 4,032 $1.76
Vested............................ -- --
Canceled.......................... -- --
-----
Outstanding at June 30, 2005......... 4,032 1.76
=====
8
OUTSTANDING OPTIONS
SIX MONTHS ENDED JUNE 30, 2005
---------------------------------------------------
REMAINING
WEIGHTED- AVERAGE AGGREGATE
AVERAGE CONTRACTUAL INTRINSIC
SHARES EXERCISE LIFE VALUE
(THOUSANDS) PRICE (YEARS) (MILLIONS)
----------- ---------- ----------- ----------
Outstanding at December 31, 2004 .. 16,159 $15.42
Canceled ....................... (663) 15.74
Exercised ...................... (608) 6.35
------
Outstanding at June 30, 2005 ...... 14,888 15.78 4.6 $30
======
Exercisable at June 30, 2005 ...... 12,931 16.78 4.0 22
======
NON-VESTED OPTIONS
SIX MONTHS ENDED JUNE 30, 2005
------------------------------
WEIGHTED-
AVERAGE
SHARES GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------
Outstanding at December 31, 2004 .. 6,854 $1.61
Vested ......................... (2,770) 1.40
Canceled ....................... (52) 1.90
-----
Outstanding at June 30, 2005 ...... 4,032 1.76
=====
PERFORMANCE SHARES
OUTSTANDING AND NON-VESTED SHARES
THREE MONTHS ENDED JUNE 30, 2005
----------------------------------
WEIGHTED-
AVERAGE
SHARES GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------
Outstanding at March 31, 2005 ............ 1,594 $9.25
Granted ............................... -- --
Canceled .............................. (5) 5.64
Vested and released to participants ... (2) 5.64
-----
Outstanding at June 30, 2005 ............. 1,587 9.27
=====
OUTSTANDING SHARES
SIX MONTHS ENDED JUNE 30, 2005
--------------------------------------
REMAINING
AVERAGE AGGREGATE
CONTRACTUAL INTRINSIC
SHARES LIFE VALUE
(THOUSANDS) (YEARS) (MILLIONS)
----------- ----------- ----------
Outstanding at December 31, 2004 ......... 1,169
Granted ............................... 945
Canceled .............................. (154)
Vested and released to participants ... (373)
-----
Outstanding at June 30, 2005 ............. 1,587 1.6 $16
=====
NON-VESTED OPTIONS
SIX MONTHS ENDED JUNE 30, 2005
------------------------------
WEIGHTED-
AVERAGE
SHARES GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------
Outstanding at December 31, 2004 .......... 756 $ 5.70
Granted ................................ 945 12.13
Canceled ............................... (94) 10.19
Vested and released to participants .... (20) 5.64
-----
Outstanding at June 30, 2005 .............. 1,587 9.27
=====
9
The non-vested and outstanding shares displayed in the above tables assume
that shares are issued at the maximum performance level (150%). In addition, the
aggregate intrinsic value reflects the impacts of current expectations of
achievement and stock price.
PERFORMANCE-BASED UNITS
OUTSTANDING AND NON-VESTED UNITS
THREE MONTHS ENDED JUNE 30, 2005
--------------------------------
WEIGHTED-
AVERAGE
UNITS GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------
Outstanding at March 31, 2005 ............ 35 $100.00
Canceled .............................. -- --
Vested and released to participants ... -- --
---
Outstanding at June 30, 2005 ............. 35 100.00
===
OUTSTANDING AND NON-VESTED UNITS
SIX MONTHS ENDED JUNE 30, 2005
---------------------------------------------------
REMAINING
WEIGHTED- AVERAGE AGGREGATE
AVERAGE CONTRACTUAL INTRINSIC
UNITS GRANT DATE LIFE VALUE
(THOUSANDS) FAIR VALUE (YEARS) (MILLIONS)
----------- ---------- ---------- ----------
Outstanding at December 31, 2004 ......... 37 $100.00
Canceled .............................. (1) 100.00
Vested and released to participants ... (1) 100.00
---
Outstanding at June 30, 2005 ............. 35 100.00 1.5 $3
===
The aggregate intrinsic value reflects the value of the performance units
given current expectations of performance through the end of the cycle.
TIME-BASED RESTRICTED STOCK
OUTSTANDING AND NON-VESTED SHARES
THREE MONTHS ENDED JUNE 30, 2005
---------------------------------
WEIGHTED-
AVERAGE
SHARES GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------
Outstanding at March 31, 2005 ............ 986 $8.71
Granted ............................... -- --
Canceled .............................. (3) 7.01
Vested and released to participants ... (9) 7.60
---
Outstanding at June 30, 2005 ............. 974 8.72
===
OUTSTANDING AND NON-VESTED SHARES
SIX MONTHS ENDED JUNE 30, 2005
---------------------------------------------------
REMAINING
WEIGHTED- AVERAGE AGGREGATE
AVERAGE CONTRACTUAL INTRINSIC
SHARES GRANT DATE LIFE VALUE
(THOUSANDS) FAIR VALUE (YEARS) (MILLIONS)
----------- ---------- ----------- ----------
Outstanding at December 31, 2004 ......... 769 $ 7.49
Granted ............................... 277 12.13
Canceled .............................. (43) 9.75
Vested and released to participants ... (29) 6.92
---
Outstanding at June 30, 2005 ............. 974 8.72 1.4 $13
===
10
The weighted-average grant-date fair values of awards granted were as
follows for the three and six months ended June 30, 2004 and 2005:
THREE MONTHS ENDED JUNE 30,
---------------------------
2004 2005
------- ----
Options....................... $ -- $--
Performance units............. 100.00 --
Performance shares............ -- --
Time-based restricted stock... 11.29 --
SIX MONTHS ENDED JUNE 30,
-------------------------
2004 2005
------- ------
Options....................... $ 1.86 $ --
Performance units............. 100.00 --
Performance shares............ -- 12.13
Time-based restricted stock... 10.91 12.13
The total intrinsic value of awards received by participants were as
follows for the three and six months ended June 30, 2004 and 2005:
THREE MONTHS ENDED JUNE 30,
---------------------------
2004 2005
---- ----
(IN MILLIONS)
Options exercised............. $1 $2
SIX MONTHS ENDED JUNE 30,
-------------------------
2004 2005
---- ----
(IN MILLIONS)
Options exercised............. $2 $4
Performance shares............ 7 5
As of June 30, 2005, there was $17 million of total unrecognized
compensation cost related to non-vested LICP arrangements. That cost is expected
to be recognized over a weighted-average period of 2 years.
Cash received from LICPs was less than $1 million and $2 million for the
three and six months ended June 30, 2004, respectively. Cash received from LICPs
was $2 million and $4 million for the three and six months ended June 30, 2005,
respectively.
The actual tax benefit realized for tax deductions related to LICPs totaled
$1 million and $4 million for the three and six months ended June 30, 2004,
respectively. Tax benefits realized for the three and six months ended June 30,
2005 was $1 million and $4 million, respectively.
The Company has a policy of issuing new shares in order to satisfy
share-based payments related to LICPs.
For further information, please read Note 9 to the CenterPoint Energy
10-K/A Notes.
11
(b) Employee Benefit Plans.
The Company's net periodic cost includes the following components relating
to pension and postretirement benefits:
THREE MONTHS ENDED JUNE 30,
-----------------------------------------------------
2004 2005
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
Service cost...................... $ 10 $ 1 $ 8 $--
Interest cost..................... 25 8 25 7
Expected return on plan assets.... (26) (3) (35) (3)
Net amortization.................. 10 3 9 3
Other............................. 3 -- -- --
---- --- ---- ---
Net periodic cost................. $ 22 $ 9 $ 7 $ 7
==== === ==== ===
SIX MONTHS ENDED JUNE 30,
-----------------------------------------------------
2004 2005
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
Service cost...................... $ 20 $ 2 $ 17 $ 1
Interest cost..................... 51 16 48 14
Expected return on plan assets.... (52) (6) (69) (6)
Net amortization.................. 19 6 19 5
Other............................. 3 2 -- --
---- --- ---- ---
Net periodic cost................. $ 41 $20 $ 15 $14
==== === ==== ===
Included in the net periodic cost for the three and six months ended June
30, 2004 is $4 million and $8 million, respectively, of expense related to Texas
Genco's participants, which is reflected in discontinued operations in the
Statements of Consolidated Income.
Contributions to the pension plan are not required in 2005; however, the
Company expects to make a contribution. The Company previously disclosed in its
consolidated financial statements for the year ended December 31, 2004, that it
expected to contribute $29 million to its postretirement benefits plan in 2005.
As of June 30, 2005, $11 million of contributions have been made.
In addition to the Company's non-contributory pension plan, the Company
maintains a non-qualified benefit restoration plan. The net periodic cost
associated with this plan for the three months ended June 30, 2004 and 2005 was
$1 million and $2 million, respectively, and $3 million for each of the six
months ended June 30, 2004 and 2005.
(4) NEW ACCOUNTING PRONOUNCEMENTS
In May 2005, the Financial Accounting Standards Board (FASB) issued SFAS
No. 154, "Accounting Changes and Error Corrections, a replacement of APB Opinion
No. 20 and FASB Statement No. 3" (SFAS No. 154). SFAS No. 154 provides guidance
on the accounting for and reporting of accounting changes and error corrections.
It establishes, unless impracticable, retrospective application as the required
method for reporting a change in accounting principle in the absence of explicit
transition requirements specific to the newly adopted accounting principle. The
correction of an error in previously issued financial statements is not an
accounting change and must be reported as a prior-period adjustment by restating
previously issued financial statements. SFAS No. 154 is effective for accounting
changes and corrections of errors made in fiscal years beginning after December
15, 2005.
In March 2005, the FASB issued FASB Interpretation No. (FIN) 47,
"Accounting for Conditional Asset Retirement Obligations" (FIN 47). FIN 47
clarifies that an entity must record a liability for a "conditional" asset
retirement obligation if the fair value of the obligation can be reasonably
estimated. FIN 47 is effective no later than the end of fiscal years ending
after December 15, 2005. The Company does not expect the adoption of this
standard to have a material effect on its financial position, results of
operations or cash flows.
12
(5) REGULATORY MATTERS
(a) Recovery of True-Up Balance.
The Texas electric restructuring law provides for the Public Utility
Commission of Texas (Texas Utility Commission) to conduct a "true-up" proceeding
to determine CenterPoint Houston's stranded costs and certain other costs
resulting from the transition to a competitive retail electric market and to
provide for its recovery of those costs. In March 2004, CenterPoint Houston
filed its stranded cost true-up application with the Texas Utility Commission.
CenterPoint Houston had requested recovery of $3.7 billion, excluding interest.
In December 2004, the Texas Utility Commission issued its final order (True-Up
Order) allowing CenterPoint Houston to recover a true-up balance of
approximately $2.3 billion, which included interest through August 31, 2004, and
providing for adjustment of the amount to be recovered to include interest on
the balance until recovery, the principal portion of additional excess
mitigation credits returned to customers after August 31, 2004 and certain other
matters. Both CenterPoint Houston and other parties filed appeals of the True-Up
Order, and those appeals remain pending before a state district court in Travis
County, Texas. The court held a hearing on the appeal in early August 2005, with
a decision currently expected in the near future.
There are two ways for CenterPoint Houston to recover the true-up balance:
by issuing transition bonds to securitize the amounts due and/or by implementing
a competition transition charge (CTC). In March 2005, the Texas Utility
Commission issued a financing order that authorized the issuance of transition
bonds. Although several parties originally appealed the financing order, only
two have maintained appeals. CenterPoint Houston will not be able to issue
transition bonds while an appeal is pending. Prior to the appeal, it had been
expected that approximately $1.8 billion in transition bonds could be issued by
mid-2005 under the terms of the financing order. On August 4, 2005, the District
Court affirmed the financing order. Texas law provides for any further appeals
to be filed directly with the Texas Supreme Court within 15 days.
On July 14, 2005, CenterPoint Houston received an order from the Texas
Utility Commission allowing it to implement a CTC to collect approximately $570
million over 14 years plus interest at an annual rate of 11.075%. Based on the
accrual of interest provided for in the CTC order, CenterPoint Houston expects
that this amount will increase to approximately $600 million by the end of the
third quarter which is when the CTC is expected to be implemented. The CTC order
also allows CenterPoint Houston to collect approximately $24 million of rate
case expenses over three years. The CTC order authorizes CenterPoint Houston to
impose a charge on retail electric providers to recover the portion of the
true-up balance not covered by the financing order. CenterPoint Houston cannot
implement the CTC until the Texas Utility Commission takes final action on the
motions for rehearing.
Under the True-Up Order, CenterPoint Houston is allowed a return until the
true-up balance is recovered. The rate of return is based on CenterPoint
Houston's cost of capital, established in the Texas Utility Commission's final
order issued in October 2001, which is derived from CenterPoint Houston's cost
to finance assets (debt return) and an allowance for earnings on shareholders'
investment (equity return). Consequently, in accordance with SFAS No. 92,
"Regulated Enterprises -- Accounting for Phase-in Plans," the rate of return has
been bifurcated into a debt return component and an equity return component.
CenterPoint Houston was allowed a return on the true-up balance of $65 million
and $127 million for the three months and six months ended June 30, 2005,
respectively. The debt return of $35 million and $69 million for the three
months and six months ended June 30, 2005, respectively, was accrued and
included in other income in the Company's Statements of Consolidated Income. The
debt return will continue to be recognized as earned going forward. The equity
return of $30 million and $58 million for the three months and six months ended
June 30, 2005, respectively, will be recognized in income as it is collected
through rates in the future. As of June 30, 2005, the Company has recorded a
regulatory asset of $296 million related to the debt return on its true-up
balance and has not recorded an allowed equity return of $205 million on its
true-up balance because such return will be recognized as it is collected
through rates in the future.
Net income for both the three months and six months ended June 30, 2005
included an after-tax extraordinary gain of $30 million ($0.08 per diluted
share) reflecting an adjustment to the extraordinary loss recorded in the last
half of 2004 to write down generation-related regulatory assets as a result of
the final orders issued by the Texas Utility Commission.
As a result of a settlement reached in a separate proceeding involving
Reliant Energy, Inc.'s (RRI) Price-to-Beat, excess mitigation credits were
terminated as of April 29, 2005. As a result of this settlement, the Company
13
has applied the remaining unrefunded excess mitigation credits of approximately
$522 million to reduce the regulatory asset related to stranded costs as of June
30, 2005.
(b) Final Fuel Reconciliation.
The results of the Texas Utility Commission's final decision related to
CenterPoint Houston's final fuel reconciliation are a component of the True-Up
Order. CenterPoint Houston has appealed certain portions of the True-Up Order
involving a disallowance of approximately $67 million relating to the final fuel
reconciliation plus interest of $10 million. A hearing on this issue was held
before a district court in Travis County on April 22, 2005 and a judgment was
entered from the district court on May 13, 2005 affirming the Texas Utility
Commission's decision. CenterPoint Houston filed an appeal to the Court of
Appeals on June 9, 2005.
(c) Rate Cases.
In November 2004, Southern Gas Operations filed an application for a
general rate increase with the Arkansas Public Service Commission (APSC).
Southern Gas Operations' adjusted request, if approved, would increase base
rates by approximately $28 million annually. The APSC staff has made a
recommendation to the APSC for a rate decrease of $13 million. Hearings in the
rate case are scheduled to begin in early August 2005 with billings under new
rates expected to begin in the fourth quarter.
In April 2005, the Railroad Commission of Texas (Railroad Commission)
approved a settlement that increased Southern Gas Operations' base rate and
service revenues by a combined $2 million in the unincorporated environs of its
Beaumont/East Texas and South Texas Divisions. In June 2005, Southern Gas
Operations filed a request to implement these rates within substantially all of
the incorporated cities located in its Beaumont/East Texas and South Texas
Divisions. If these rates are approved as requested, Southern Gas Operations'
base rate and service revenues are expected to increase by an additional $16
million annually.
In June 2005, the Minnesota Public Utilities Commission (MPUC) approved a
settlement which increases Minnesota Gas' base rates by approximately $9 million
annually. An interim rate increase of $17 million had been implemented in
October 2004. A liability has been recorded for the excess of amounts collected
in interim rates over those approved in the final settlement, which excess will
be refunded to customers in the third quarter.
(d) City of Tyler, Texas Dispute.
In July 2002, the City of Tyler, Texas, asserted that Southern Gas
Operations had overcharged residential and small commercial customers in that
city for gas costs under supply agreements in effect since 1992. That dispute
was referred to the Railroad Commission by agreement of the parties for a
determination of whether Southern Gas Operations has properly charged and
collected for gas service to its residential and commercial customers in its
Tyler distribution system in accordance with lawful filed tariffs during the
period beginning November 1, 1992, and ending October 31, 2002. In December
2004, the Railroad Commission conducted a hearing on the matter. On May 25,
2005, the Railroad Commission issued a final order finding that the Company had
complied with its tariffs, acted prudently in entering into its gas supply
contracts, and prudently managed those contracts. An appeal from this order
could be taken by the City of Tyler to the Court of Appeals and ultimately to
the Texas Supreme Court, but no appeal has been filed to date.
(e) City of Houston Franchise.
On June 27, 2005, CenterPoint Houston accepted an ordinance granting
CenterPoint Houston a new 30-year franchise to use the public rights-of-way to
conduct its business in the City of Houston (New Franchise Ordinance). The New
Franchise Ordinance took effect on July 1, 2005, and replaced the prior
electricity franchise ordinance, which had been in effect since 1957. The New
Franchise Ordinance clarifies certain operational obligations of CenterPoint
Houston and the City of Houston and provides for streamlined payment and audit
procedures and a two-year statute of limitations on claims for underpayment or
overpayment under the ordinance. Under the prior electricity franchise
ordinance, CenterPoint Houston paid annual franchise fees of $76.6 million to
the City of Houston for the year ended December 31, 2004. For the twelve-month
period beginning July 1, 2005, the annual franchise fee (Annual Franchise Fee)
under the New Franchise Ordinance will include a base amount of $88.1 million
(Base Amount) and an additional payment of $8.5 million (Additional Amount). The
Base Amount and the Additional Amount will be adjusted annually based on the
annual increase or decrease in kWh delivered by CenterPoint Houston within the
City of Houston.
14
The New Franchise Ordinance requires the City of Houston to modify
CenterPoint Houston's tariff to allow CenterPoint Houston to recover the
Additional Amount from retail electric providers serving end-use retail electric
customers within the City of Houston boundaries. CenterPoint Houston filed a
request with the City of Houston to implement a tariff rider to collect the
Additional Amount, but subsequently asked the City of Houston to abate further
consideration of that application pending a review by counsel for the City of
Houston and CenterPoint Houston regarding the implementation of the New
Franchise Ordinance.
CenterPoint Houston began paying the new annual franchise fees on July 1,
2005. Pursuant to the New Franchise Ordinance, CenterPoint Houston retains the
right to recover from the City of Houston any portion of the Additional Amount
paid (or to refuse to pay any portion not yet paid) for which CenterPoint
Houston is denied recovery by any regulatory authority. Additionally, the New
Franchise Ordinance provides that the Annual Franchise Fee will be reduced
prospectively to reflect any portion of the Annual Franchise Fee that is not
included in CenterPoint Houston's base rates in any subsequent rate case.
(f) Settlement of FERC Audit.
On June 27, 2005, CenterPoint Energy Gas Transmission Company (CEGT), a
subsidiary of CERC Corp., received an Order from FERC accepting the terms of a
settlement agreed upon by CEGT with the Staff of the FERC's Office of Market
Oversight and Investigations (OMOI). The settlement brought to a conclusion an
investigation of CEGT initiated by OMOI in August 2003. Among other things, the
investigation involved a comprehensive review of CEGT's relationship with its
marketing affiliates and compliance with various FERC record-keeping and
reporting requirements covering the period from January 1, 2001 through
September 22, 2004.
OMOI Staff took the position that some of CEGT's actions resulted in a
limited number of violations of FERC's affiliate regulations or were in
violation of certain record-keeping and administrative requirements. OMOI did
not find any systematic violations of its rules governing communications or
other relationships among affiliates.
The settlement included two remedies: a payment of a $270,000 civil penalty
and the execution of a compliance plan, applicable to both CEGT and its sister
pipeline, CenterPoint Energy-Mississippi River Transmission Corporation (MRT).
The compliance plan consists of a detailed set of Implementation Procedures that
will facilitate compliance with FERC's Order No. 2004, the Standards of Conduct,
which regulate behavior between regulated entities and their affiliates. The
Company does not believe the compliance plan will have any material effect on
CEGT's or MRT's ability to conduct their business.
(6) 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 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, 2004 and 2005, hedge
ineffectiveness was less than $1 million from derivatives that qualify for and
are designated as cash flow hedges. No component of the derivative instruments'
gain or loss was excluded from the assessment of effectiveness. If it becomes
probable that an anticipated transaction will not occur, the Company realizes in
net income the deferred gains and losses recognized in accumulated other
comprehensive loss. Once the anticipated transaction occurs, the accumulated
deferred gain or loss recognized in accumulated other comprehensive loss is
reclassified and included in the Company's Statements of Consolidated Operations
under the caption "Natural Gas." Cash flows resulting from these transactions in
non-trading energy derivatives are included in the Statements of Consolidated
Cash Flows in the same category as the item being hedged. As of June 30, 2005,
the Company expects $12 million in accumulated other comprehensive income to be
reclassified into net income during the next twelve months.
Other Derivative Financial Instruments. The Company also has natural gas
contracts that are derivatives which are not hedged. Load following services
that the Company offers its natural gas customers create an inherent tendency
for the Company to be either long or short natural gas supplies relative to
customer purchase commitments. The Company measures and values all of its
volumetric imbalances on a real-time basis to minimize its exposure to commodity
price and volume risk. The aggregate Value at Risk (VaR) associated with these
operations is calculated daily and averaged $0.3 million with a high of $1
million during the first six months of 2005. The Company does not engage in
proprietary or speculative commodity trading. Unhedged positions are
15
accounted for by adjusting the carrying amount of the contracts to market and
recognizing any gain or loss in operating income, net. During the six months
ended June 30, 2004 and 2005, the Company recognized net gains (losses) related
to unhedged positions amounting to $(2) million and $6 million, respectively. As
of December 31, 2004, the Company had recorded short-term risk management assets
and liabilities of $4 million and $5 million, respectively, included in other
current assets and other current liabilities, respectively. As of June 30, 2005,
the Company had recorded short-term risk management assets and liabilities of $3
million and $3 million, respectively, included in other current assets and other
current liabilities, respectively.
Interest Rate Swaps. During 2002, the Company settled forward-starting
interest rate swaps having an aggregate notional amount of $1.5 billion at a
cost of $156 million, which was recorded in other comprehensive loss and is
being amortized into interest expense over the life of the designated fixed-rate
debt. Amortization of amounts deferred in accumulated other comprehensive loss
for the six months ended June 30, 2004 and 2005, was $13 million and $15
million, respectively.
Embedded Derivative. The Company's $575 million of convertible senior
notes, issued May 19, 2003 and $255 million of convertible senior notes, issued
December 17, 2003, contain contingent interest provisions. 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 components was not
material at issuance or at June 30, 2005.
(7) GOODWILL AND INTANGIBLES
Goodwill by reportable business segment is as follows (in millions):
DECEMBER 31, JUNE 30,
2004 2005
------------ --------
Natural Gas Distribution... $1,085 $1,085
Pipelines and Gathering.... 601 604
Other Operations........... 55 55
------ ------
Total................... $1,741 $1,744
====== ======
The Company reviews the carrying value of goodwill annually and at such
times when events or changes in circumstances indicate that it may not be
recoverable. The Company completed its annual evaluation of goodwill for
impairment as of January 1, 2005 and no impairment was indicated.
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2004 JUNE 30, 2005
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Land use rights .... $55 $(12) $55 $(13)
Other .............. 21 (6) 21 (6)
--- ---- --- ----
Total ........... $76 $(18) $76 $(19)
=== ==== === ====
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, 2005. 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.
16
Amortization expense for other intangibles for both the three months ended
June 30, 2004 and 2005 was $0.6 million and for both the six months ended June
30, 2004 and 2005 was $1.2 million. Estimated amortization expense for the
remainder of 2005 and the five succeeding fiscal years is as follows (in
millions):
2005................ $ 1
2006................ 3
2007................ 3
2008................ 3
2009................ 3
2010................ 2
---
Total............ $15
===
(8) COMPREHENSIVE INCOME
The following table summarizes the components of total comprehensive income
(net of tax):
FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- ------------------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Net income .......................................... $57 $54 $131 $121
--- --- ---- ----
Other comprehensive income:
Net deferred gain from cash flow hedges .......... 8 1 16 10
Reclassification of deferred loss (gain) from cash
flow hedges realized in net income ............ (1) 2 1 8
Other comprehensive income from discontinued
operations .................................... -- 4 -- 4
--- --- ---- ----
Other comprehensive income .......................... 7 7 17 22
--- --- ---- ----
Comprehensive income ................................ $64 $61 $148 $143
=== === ==== ====
The following table summarizes the components of accumulated other
comprehensive loss:
DECEMBER 31, JUNE 30,
2004 2005
------------ --------
(IN MILLIONS)
Minimum pension liability adjustment.................... $ (6) $ (6)
Net deferred loss from cash flow hedges................. (52) (34)
Other comprehensive loss from discontinued operations... (3) --
---- ----
Total accumulated other comprehensive loss ............. $(61) $(40)
==== ====
(9) 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, 2004, 308,045,381
shares of CenterPoint Energy common stock were issued and 308,045,215 shares of
CenterPoint Energy common stock were outstanding. At June 30, 2005, 309,396,389
shares of CenterPoint Energy common stock were issued and 309,396,223 shares of
CenterPoint Energy common stock were outstanding. Outstanding common shares
exclude 166 treasury shares at both December 31, 2004 and June 30, 2005.
CenterPoint Energy declared a dividend of $0.10 per share in each of the
first and second quarters of 2004. On January 26, 2005, the Company's board of
directors declared a dividend of $0.10 per share of common stock payable on
March 10, 2005 to shareholders of record as of the close of business on February
16, 2005. On March 3, 2005, the Company's board of directors declared a dividend
of $0.10 per share of common stock payable on March 31, 2005 to shareholders of
record as of the close of business on March 16, 2005. This additional first
quarter dividend was declared in lieu of the regular second quarter dividend to
address technical restrictions that might limit the Company's ability to pay a
regular dividend during the second quarter of this year. Due to the limitations
imposed under the 1935 Act, the Company may declare and pay dividends only from
earnings in the specific quarter in which the dividend is paid, absent specific
authorization from the SEC approving payment of the quarterly
17
dividend from capital or unearned surplus. There can be no assurance, however,
that the SEC would authorize such payments. As a result of the seasonal nature
of the Company's utility businesses, the first quarter is generally the
strongest quarter for the Company's gas distribution business. On June 2, 2005,
the Company's board of directors declared a dividend of $0.07 per share of
common stock payable on June 30, 2005 to shareholders of record as of the close
of business on June 15, 2005. Although dividends are subject to consideration
and approval of the Company's Board of Directors, subject to the Board's
determination, the Company currently intends to pay a 2005 annual dividend of
$0.40 per share in keeping with the Company's historic levels and subject to
remaining in compliance with the dividend payment limitations imposed under the
1935 Act.
(10) LONG-TERM DEBT AND RECEIVABLES FACILITY
(a) Long-term Debt.
In June 2005, CERC Corp. replaced its $250 million three-year revolving
credit facility with a $400 million five-year revolving credit facility. The new
credit facility terminates on June 30, 2010. Borrowings under this facility may
be made at the London interbank offered rate (LIBOR) plus 55 basis points,
including the facility fee, based on current credit ratings. An additional
utilization fee of 10 basis points applies to borrowings whenever more than 50%
of the facility is utilized. Changes in credit ratings could lower or raise the
increment to LIBOR depending on whether ratings improved or were lowered. As of
June 30, 2005, such credit facility was not utilized.
In March 2005, the Company replaced its $750 million revolving credit
facility with a $1 billion five-year revolving credit facility. Borrowings may
be made under the facility at LIBOR plus 100 basis points based on current
credit ratings. An additional utilization fee of 12.5 basis points applies to
borrowings whenever more than 50% of the facility is utilized. Changes in credit
ratings could lower or raise the increment to LIBOR depending on whether ratings
improved or were lowered. As of June 30, 2005, borrowings of $120 million were
outstanding under the revolving credit facility.
In March 2005, CenterPoint Houston established a $200 million five-year
revolving credit facility. Borrowings may be made under the facility at LIBOR
plus 75 basis points based on CenterPoint Houston's current credit rating. An
additional utilization fee of 12.5 basis points applies to borrowings whenever
more than 50% of the facility is utilized. Changes in credit ratings could lower
or raise the increment to LIBOR depending on whether ratings improved or were
lowered. As of June 30, 2005, there were no borrowings outstanding under the
revolving credit facility.
CenterPoint Houston also established a $1.31 billion credit facility in
March 2005. This facility is available to be utilized only to refinance
CenterPoint Houston's $1.31 billion term loan maturing in November 2005 in the
event that proceeds from the issuance of transition bonds are not sufficient to
repay such term loan. Drawings may be made under this credit facility until
November 2005, at which time any outstanding borrowings are converted to term
loans maturing in November 2007. Under this facility, (i) 100% of the net
proceeds from the issuance of transition bonds and (ii) the proceeds, in excess
of $200 million, from certain other new net indebtedness for borrowed money
incurred by CenterPoint Houston must be used to repay borrowings under the
facility. Based on CenterPoint Houston's current credit ratings, borrowings
under the facility may be made at LIBOR plus 75 basis points. The interest rate
under the term loan which this facility would replace is LIBOR plus 975 basis
points. Changes in credit ratings could lower or raise the increment to LIBOR
depending on whether ratings improved or were lowered. Any drawings under this
facility must be secured by CenterPoint Houston's general mortgage bonds in the
same principal amount and bearing the same interest rate as such drawings.
Convertible Debt. In March 2005, the Company filed a registration statement
relating to an offer to exchange its $575 million aggregate principal amount of
3.75% convertible senior notes due 2023 for a new series of 3.75% convertible
senior notes due 2023. This registration statement was declared effective by the
SEC on July 19, 2005 at which time the Company commenced the exchange offer. The
exchange offer expires on August 17, 2005. The Company has commenced the
exchange offer in response to the guidance set forth in Emerging Issues Task
Force (EITF) Issue No. 04-8, "Accounting Issues Related to Certain Features of
Contingently Convertible Debt and the Effect on Diluted Earnings Per Share"
(EITF 04-8). Under that guidance, because settlement of the principal portion of
new notes will be made in cash rather than stock, exchanging new notes for old
notes will allow the Company to exclude the portion of the conversion value of
the new notes attributable to their principal amount from its computation of
diluted earnings per share from continuing operations. See Note 12 for the
impact on diluted earnings per share related to these securities.
18
Junior Subordinated Debentures (Trust Preferred Securities). In February
1997, a Delaware statutory business trust created by CenterPoint Energy (HL&P
Capital Trust II) issued to the public $100 million aggregate amount of capital
securities. The trust used the proceeds of the offering to purchase junior
subordinated debentures issued by CenterPoint Energy having an interest rate and
maturity date that correspond to the distribution rate and the mandatory
redemption date of the capital securities. The amount of outstanding junior
subordinated debentures discussed above was included in long-term debt as of
December 31, 2004 and June 30, 2005.
The junior subordinated debentures are the trust's sole assets and their
entire operations. CenterPoint Energy considers its obligations under the
Amended and Restated Declaration of Trust, Indenture, Guaranty Agreement and,
where applicable, Agreement as to Expenses and Liabilities, relating to the
capital securities, taken together, to constitute a full and unconditional
guarantee by CenterPoint Energy of the trust's obligations with respect to the
capital securities.
The capital securities are mandatorily redeemable upon the repayment of the
related series of junior subordinated debentures at their stated maturity or
earlier redemption. Subject to some limitations, CenterPoint Energy has the
option of deferring payments of interest on the junior subordinated debentures.
During any deferral or event of default, CenterPoint Energy may not pay
dividends on its capital stock. As of June 30, 2005, no interest payments on the
junior subordinated debentures had been deferred.
The outstanding aggregate liquidation amount, distribution rate and
mandatory redemption date of the capital securities of the trust described above
and the identity and similar terms of the related series of junior subordinated
debentures are as follows:
AGGREGATE LIQUIDATION
AMOUNTS AS OF DISTRIBUTION MANDATORY
----------------------- RATE/ REDEMPTION
DECEMBER 31, JUNE 30, INTEREST DATE/
TRUST 2004 2005 RATE MATURITY DATE JUNIOR SUBORDINATED DEBENTURES
----- ------------ -------- ------------ ------------- ------------------------------
(IN MILLIONS)
HL&P Capital Trust II.... $100 $100 8.257% February 2037 8.257% Junior Subordinated
Deferrable Interest
Debentures Series B
In June 1996, a Delaware statutory business trust created by CERC Corp.
(CERC Trust) issued $173 million aggregate amount of convertible preferred
securities to the public. CERC Trust used the proceeds of the offering to
purchase convertible junior subordinated debentures issued by CERC Corp. having
an interest rate and maturity date that correspond to the distribution rate and
mandatory redemption date of the convertible preferred securities. The
convertible junior subordinated debentures represent CERC Trust's sole asset and
its entire operations. CERC Corp. considers its obligation under the Amended and
Restated Declaration of Trust, Indenture and Guaranty Agreement relating to the
convertible preferred securities, taken together, to constitute a full and
unconditional guarantee by CERC Corp. of CERC Trust's obligations with respect
to the convertible preferred securities. The amount of outstanding junior
subordinated debentures was included in long-term debt as of December 31, 2004
and June 30, 2005.
The convertible preferred securities were 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 were 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 both December 31, 2004 and June 30, 2005, the
liquidation amount of convertible preferred securities outstanding was $0.3
million. The securities, and their underlying convertible junior subordinated
debentures, bore interest at 6.25% and had a June 2026 maturity date. Subject to
some limitations, CERC Corp. had the option of deferring payments of interest on
the convertible junior subordinated debentures. During any deferral or event of
default, CERC Corp. could not pay dividends on its common stock to CenterPoint
Energy. As of June 30, 2005, no interest payments on the convertible junior
subordinated debentures had been deferred.
On July 1, 2005, the remaining $0.3 million of convertible preferred
securities and the $6 million of related convertible junior subordinated
debentures were called for redemption on August 1, 2005. Most of the convertible
preferred securities were converted prior to the redemption date and the
remaining securities were redeemed.
19
(b) Receivables Facility.
In January 2005, CERC's $250 million receivables facility was extended to
January 2006 and temporarily increased, for the period from January 2005 to June
2005, to $375 million to provide additional liquidity to CERC during the peak
heating season of 2005. As of June 30, 2005, CERC had $181 million of advances
under its receivables facility.
The average outstanding balance on the receivables facility was $181
million for the six months ended June 30, 2005. Sales of receivables were
approximately $0.6 billion and $0.4 billion for the three months ended June 30,
2004 and 2005, respectively, and $1.3 billion and $0.9 billion for the six
months ended June 30, 2004 and 2005, respectively.
(11) COMMITMENTS AND CONTINGENCIES
(a) Legal Matters.
RRI Indemnified Litigation
The Company, CenterPoint Houston or their predecessor, Reliant Energy, and
certain of their former subsidiaries are named as defendants in several lawsuits
described below. Under a master separation agreement between the Company and
RRI, the Company and its subsidiaries are entitled to be indemnified by RRI for
any losses, including attorneys' fees and other costs, arising out of the
lawsuits described below under Electricity and Gas Market Manipulation Cases and
Other Class Action Lawsuits. Pursuant to the indemnification obligation, RRI is
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.
Electricity and Gas Market Manipulation Cases. A large number of lawsuits
have been filed against numerous market participants and remain pending in both
federal and state courts in California and Nevada in connection with the
operation of the electricity and natural gas markets in California and certain
other western states in 2000-2001, a time of power shortages and significant
increases in prices. These lawsuits, many of which have been filed as class
actions, are based on a number of legal theories, including violation of state
and federal antitrust laws, laws against unfair and unlawful business practices,
the federal Racketeer Influenced Corrupt Organization Act, false claims statutes
and similar theories and breaches of contracts to supply power to governmental
entities. Plaintiffs in these lawsuits, which include state officials and
governmental entities as well as private litigants, are seeking a variety of
forms of relief, including recovery of compensatory damages (in some cases in
excess of $1 billion), a trebling of compensatory damages and punitive damages,
injunctive relief, restitution, interest due, disgorgement, civil penalties and
fines, costs of suit, attorneys' fees and divestiture of assets. To date,
several of the electricity complaints have been dismissed by the trial court and
are on appeal, and several of the dismissals have been affirmed by appellate
courts. Others remain in the early procedural stages. One of the gas complaints
has also been dismissed and is on appeal. The other gas cases remain in the
early procedural stages. The Company's former subsidiary, RRI, was a participant
in the California markets, owning generating plants in the state and
participating in both electricity and natural gas trading in that state and in
western power markets generally. RRI, some of its subsidiaries and, in some
cases, former corporate officers or employees of some of those companies have
been named as defendants in these suits.
The Company or its predecessor, Reliant Energy, has been named in
approximately 30 of these lawsuits, which were instituted between 2001 and 2005
and are pending in California state courts in San Diego County and in federal
district courts in San Francisco, San Diego, Los Angeles, Fresno, Sacramento,
San Jose and Nevada and before the Ninth Circuit Court of Appeals. However, the
Company, CenterPoint Houston and Reliant Energy were not participants in the
electricity or natural gas markets in California. The Company and Reliant Energy
have been dismissed from certain of the lawsuits, either voluntarily by the
plaintiffs or by order of the court and the Company believes it is not a proper
defendant in the remaining cases and will continue to seek dismissal from such
remaining cases. On July 6, 2004 and on October 12, 2004, the Ninth Circuit
affirmed the Company's removal to federal district court of two electric cases
brought by the California Attorney General and affirmed the federal court's
dismissal of these cases based upon the filed rate doctrine and federal
preemption. On April 18, 2005, the Supreme Court of the United States denied the
Attorney General's petition for certiorari in one of these cases. No petition
for certiorari was filed in the other case, and both of these cases are now
finally resolved in favor of the defendants. In one other case filed by the
California Attorney General, a claim for injunctive relief remains pending, with
a trial
20
currently scheduled to begin in federal district court in February 2006. Several
cases that are now pending in state court in San Diego County were originally
filed in several California state courts but were removed by the defendants to
federal district court. When the federal district court remanded those cases,
they were coordinated in front of one San Diego state court. In July 2005, that
San Diego state court refused to dismiss certain of those cases based on
defendants' claims of federal preemption and the filed rate doctrine.
Other Class Action Lawsuits. Fifteen class action lawsuits filed in May,
June and July 2002 on behalf of purchasers of securities of RRI and/or Reliant
Energy have been consolidated in federal district court in Houston. RRI and
certain of its former and current executive officers are named as defendants.
The consolidated complaint also names RRI, Reliant Energy, the underwriters of
the initial public offering of RRI's common stock in May 2001 (RRI Offering),
and RRI's and Reliant Energy's independent auditors as defendants. The
consolidated amended complaint seeks monetary relief purportedly on behalf of
purchasers of common stock of Reliant Energy or RRI during certain time periods
ranging from February 2000 to May 2002, and purchasers of common stock that can
be traced to the RRI 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 January 2004, the trial judge dismissed the plaintiffs'
allegations that the defendants had engaged in fraud, but claims based on
alleged misrepresentations in the registration statement issued in the RRI
Offering remain. In June 2004, the plaintiffs filed a motion for class
certification, which the court granted in February 2005. The defendants appealed
the court's order certifying the class and asked the trial court to reconsider
its ruling certifying the class. In July 2005, the parties announced that they
had reached a settlement in this matter, subject to court approval. The terms of
the settlement do not require payment by the Company.
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 the Company. Two of the lawsuits have been dismissed without
prejudice. The Company and certain current and former members of its benefits
committee are the remaining defendants in the third lawsuit. That lawsuit
alleges that the defendants breached their fiduciary duties to various employee
benefits plans, directly or indirectly sponsored by the Company, in violation of
the Employee Retirement Income Security Act of 1974. The plaintiffs allege that
the defendants permitted the plans to purchase or hold securities issued by the
Company 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 complaint seeks monetary damages for losses
suffered on behalf of the plans and a putative class of plan participants whose
accounts held CenterPoint Energy or RRI securities, as well as restitution. Both
the plaintiffs and the defendants have pending motions for summary judgment
before the court. The court is expected to establish a trial date for this case
later in the fall.
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 set forth claims for breach of fiduciary duty, waste of corporate
assets, abuse of control and gross mismanagement. Specifically, the shareholder
plaintiff alleged that the defendants caused the Company to overstate its
revenues through so-called "round trip" transactions. The plaintiff also alleged
breach of fiduciary duty in connection with the spin-off of RRI and the RRI
Offering. The complaint sought 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. 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 second 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. 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 same party sent another demand
asserting the same claims, but there has been no further activity.
The Company believes that none of the lawsuits described under Other Class
Action Lawsuits has merit because, among other reasons, the alleged
misstatements and omissions were not material and did not result in any damages
to the plaintiffs.
Other Legal Matters
Texas Antitrust Actions. In July 2003, Texas Commercial Energy filed in
federal court in Corpus Christi, Texas a lawsuit against Reliant Energy, the
Company and CenterPoint Houston, as successors to Reliant Energy, Genco
21
LP, RRI, Reliant Energy Solutions, LLC, several other RRI subsidiaries and a
number of other participants in the Electric Reliability Council of Texas
(ERCOT) power market. The plaintiff, a retail electricity provider with the
ERCOT market, alleged 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
sought damages in excess of $500 million, exemplary damages, treble damages,
interest, costs of suit and attorneys' fees. The plaintiff's principal
allegations had previously been investigated by the Texas Utility Commission and
found to be without merit. In June 2004, the federal court dismissed the
plaintiff's claims and in July 2004, the plaintiff filed a notice of appeal. The
Company is vigorously contesting the appeal. The ultimate outcome of this matter
cannot be predicted at this time.
In February 2005, Utility Choice Electric filed in federal court in
Houston, Texas a lawsuit against the Company, CenterPoint Houston, CenterPoint
Energy Gas Services, Inc., CenterPoint Energy Alternative Fuels, Inc., Genco LP
and a number of other participants in the ERCOT power market. The plaintiff, a
retail electricity provider with the ERCOT market, alleged that the defendants
conspired to illegally fix and artificially increase the price of electricity in
violation of state and federal antitrust laws, intentionally interfered with
prospective business relationships and contracts, and committed fraud and
negligent misrepresentation. The plaintiff's principal allegations had
previously been investigated by the Texas Utility Commission and found to be
without merit. The Company intends to vigorously defend the case. The ultimate
outcome of this matter cannot be predicted at this time.
Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton,
Galveston and Pasadena (Three Cities) filed suit in state district court in
Harris County, Texas 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 the Company's predecessor, Reliant Energy) alleging underpayment of municipal
franchise fees. The plaintiffs claimed that they were entitled to 4% of all
receipts of any kind for business conducted within these cities over the
previous four decades. After a jury trial involving the Three Cities' claims
(but not the class of cities), the trial court entered a judgment on the Three
Cities' breach of contract claims for $1.7 million, including interest, plus an
award of $13.7 million in legal fees. It also decertified the class. Following
this ruling, 45 cities filed individual suits against Reliant Energy in the
District Court of Harris County.
On February 27, 2003, a 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 held that
all of the Three Cities' claims were barred by the jury's finding of laches, a
defense similar to the statute of limitations, due to the Three Cities' having
unreasonably delayed bringing their claims during the more than 30 years since
the alleged wrongs began. The court also held that the Three Cities were not
entitled to recover any attorneys' fees. The Three Cities filed a petition for
review to the Texas Supreme Court, which declined to hear the case. Thus, the
Three Cities' claims have been finally resolved in the Company's favor, but the
individual claims of the remaining 45 cities remain pending in the same court.
The Company does not expect the outcome of the remaining claims to have a
material impact on its financial condition, results of operations or cash flows.
Natural Gas Measurement Lawsuits. CERC Corp. and certain of its
subsidiaries are defendants in a suit filed in 1997 under the Federal False
Claims Act alleging mismeasurement of natural gas produced from federal and
Indian lands. The suit seeks undisclosed damages, along with statutory
penalties, interest, costs, and fees. The complaint is part of a larger series
of complaints filed against 77 natural gas pipelines and their subsidiaries and
affiliates. An earlier single action making substantially similar allegations
against the pipelines was dismissed by the federal district court for the
District of Columbia on grounds of improper joinder and lack of jurisdiction. As
a result, the various individual complaints were filed in numerous courts
throughout the country. This case has been consolidated, together with the other
similar False Claims Act cases, in the federal district court in Cheyenne,
Wyoming.
In addition, CERC Corp. and certain of its subsidiaries are defendants in
two mismeasurement lawsuits brought against approximately 245 pipeline companies
and their affiliates pending in state court in Stevens County, Kansas. In one
case (originally filed in May 1999 and amended four times), the plaintiffs
purport to represent a class of royalty owners who allege that the defendants
have engaged in systematic mismeasurement of the volume of natural gas for more
than 25 years. The plaintiffs amended their petition in this suit in July 2003
in response to an order from the judge denying certification of the plaintiffs'
alleged class. In the amendment the plaintiffs dismissed their claims against
certain defendants (including two CERC subsidiaries), limited the scope of the
class of plaintiffs they purport to represent and eliminated previously asserted
claims based on mismeasurement of the Btu content of the gas. The same
plaintiffs then filed a second lawsuit, again as representatives of a class of
royalty owners, in which they assert their claims that the defendants have
engaged in systematic mismeasurement of the Btu content of natural
22
gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory
damages, along with statutory penalties, treble damages, interest, costs and
fees. CERC and its subsidiaries believe that there has been no systematic
mismeasurement of gas and that the suits are without merit. CERC does not expect
the ultimate outcome to have a material impact on the financial condition,
results of operations or cash flows of either the Company or CERC.
Gas Cost Recovery Litigation. In October 2002, a suit was filed in state
district court in Wharton County, Texas against the Company, CERC, Entex Gas
Marketing Company, and certain non-affiliated companies alleging fraud,
violations of the Texas Deceptive Trade Practices Act, violations of the Texas
Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and
Antitrust Act with respect to rates charged to certain consumers of natural gas
in the State of Texas. Subsequently, the plaintiffs added as defendants
CenterPoint Energy Marketing Inc., CenterPoint Energy Gas Transmission Company,
United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy
Pipeline Services, Inc., and CenterPoint Energy Trading and Transportation
Group, Inc., all of which are subsidiaries of the Company. The plaintiffs
alleged that defendants inflated the prices charged to certain consumers of
natural gas. In February 2003, a similar suit was filed in state court in Caddo
Parish, Louisiana against CERC with respect to rates charged to a purported
class of certain consumers of natural gas and gas service in the State of
Louisiana. In February 2004, another suit was filed in state court in Calcasieu
Parish, Louisiana against CERC seeking to recover alleged overcharges for gas or
gas services allegedly provided by Southern Gas Operations to a purported class
of certain consumers of natural gas and gas service without advance approval by
the Louisiana Public Service Commission (LPSC). In October 2004, a similar case
was filed in district court in Miller County, Arkansas against the Company,
CERC, Entex Gas Marketing Company, CenterPoint Energy Gas Transmission Company,
CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc.,
Mississippi River Transmission Corp. and other non-affiliated companies alleging
fraud, unjust enrichment and civil conspiracy with respect to rates charged to
certain consumers of natural gas in at least the states of Arkansas, Louisiana,
Mississippi, Oklahoma and Texas. At the time of the filing of each of the Caddo
and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with
the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu
Parish cases have been stayed pending the resolution of the respective
proceedings by the LPSC. The plaintiffs in the Miller County case seek class
certification, but the proposed class has not been certified. In November 2004,
the Miller County case was removed to federal district court in Texarkana,
Arkansas. In February 2005, the Wharton County case was removed to federal
district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily
moved to dismiss the case and agreed not to refile the claims asserted unless
the Miller County case is not certified as a class action or is later
decertified. In June 2005, the Miller County case was remanded to state district
court in Miller County. The range of relief sought by the plaintiffs in these
cases includes injunctive and declaratory relief, restitution for the alleged
overcharges, exemplary damages or trebling of actual damages, civil penalties
and attorney's fees. In these cases, the Company, CERC and their affiliates deny
that they have overcharged any of their customers for natural gas and believe
that the amounts recovered for purchased gas have been in accordance with what
is permitted by state regulatory authorities. The allegations in these cases are
similar to those asserted in the City of Tyler proceeding described in Note
5(d). The Company and CERC do not expect the outcome of these matters to have a
material impact on the financial condition, results of operations or cash flows
of either the Company or CERC.
Pipeline Safety Compliance. In 2005, CERC received an order from the
Minnesota Office of Pipeline Safety to remove certain components from a portion
of its distribution system by December 2, 2005. Those components were installed
by a predecessor company and are not in compliance with current state and
federal codes. CERC estimates the range of expenditures to locate and replace
such components to be $35 to $45 million. CERC will request return on and of the
capitalized expenditures in future rate cases.
Minnesota Cold Weather Rule. In December 2004, the MPUC opened an
investigation to determine whether CERC's practices regarding restoring natural
gas service during the period between October 15 and April 15 (Cold Weather
Period) are in compliance with the MPUC's Cold Weather Rule (CWR), which governs
disconnection and reconnection of customers during the Cold Weather Period. The
Minnesota Office of the Attorney General issued its report alleging CERC has
violated the CWR and recommended a $5 million penalty. CERC filed its reply
comments in July 2005. In addition, in June 2005, CERC was named in a suit filed
on behalf of a purported class of customers who allege that CERC's conduct under
the CWR was in violation of the Minnesota Consumer Fraud Act and the Minnesota
Deceptive Trade Practices Act and was negligent and fraudulent. CERC believes
that it has not knowingly and intentionally violated the CWR and intends to
vigorously contest the lawsuit. CERC does not expect this matter to have a
material adverse effect on its financial condition, results of operations or
cash flows.
23
(b) Environmental Matters.
Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are
among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish
and Bossier Parish, Louisiana. The suits allege that, at some unspecified date
prior to 1985, the defendants allowed or caused hydrocarbon or chemical
contamination of the Wilcox Aquifer, which lies beneath property owned or leased
by certain of the defendants and which is the sole or primary drinking water
aquifer in the area. The primary source of the contamination is alleged by the
plaintiffs to be a gas processing facility in Haughton, Bossier Parish,
Louisiana known as the "Sligo Facility," which was formerly operated by a
predecessor in interest of CERC Corp. This facility was purportedly used for
gathering natural gas from surrounding wells, separating gasoline and
hydrocarbons from the natural gas for marketing, and transmission of natural gas
for distribution.
Beginning about 1985, the predecessors of certain CERC Corp. defendants
engaged in a voluntary remediation of any subsurface contamination of the
groundwater below the property they owned or leased. This work has been done in
conjunction with and under the direction of the Louisiana Department of
Environmental Quality. The plaintiffs seek monetary damages for alleged damage
to the aquifer underlying their property, unspecified alleged personal injuries,
alleged fear of cancer, alleged property damage or diminution of value of their
property, and, in addition, seek damages for trespass, punitive, and exemplary
damages. The Company does not expect the ultimate cost associated with resolving
this matter to have a material impact on the financial condition, results of
operations or cash flows of either the Company or CERC.
Manufactured Gas Plant Sites. CERC and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed
remediation on two sites, other than ongoing monitoring and water treatment.
There are five remaining sites in CERC's Minnesota service territory. CERC
believes that it has no liability with respect to two of these sites.
At June 30, 2005, CERC had accrued $18 million for remediation of certain
Minnesota sites. At June 30, 2005, the estimated range of possible remediation
costs for these sites was $7 million to $42 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. As of June 30, 2005, CERC has collected or accrued $13
million from insurance companies and ratepayers to be used for future
environmental remediation.
In addition to the Minnesota sites, the United States Environmental
Protection Agency and other regulators have investigated MGP sites that were
owned or operated by CERC or may have been owned by one of its former
affiliates. CERC has been named as a defendant in two lawsuits under which
contribution is sought by private parties for the cost to remediate former MGP
sites based on the previous ownership of such sites by former affiliates of CERC
or its divisions. CERC has also been identified as a PRP by the State of Maine
for a site that is the subject of one of the lawsuits. In March 2005, the court
considering the other suit for contribution granted CERC's motion to dismiss on
the grounds that CERC was not an "operator" of the site as had been alleged. The
plaintiff in that case has filed an appeal of the court's dismissal of CERC. The
Company is investigating details regarding these sites and the range of
environmental expenditures for potential remediation. However, CERC believes it
is not liable as a former owner or operator of those sites under the
Comprehensive Environmental, Response, Compensation and Liability Act of 1980,
as amended, and applicable state statutes, and is vigorously contesting those
suits and its designation as a PRP.
Mercury Contamination. The Company's pipeline and distribution operations
have in the past employed elemental mercury in measuring and regulating
equipment. It is possible that small amounts of mercury may have been spilled in
the course of normal maintenance and replacement operations and that these
spills may have contaminated the immediate area with elemental mercury. 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 does not expect the costs of any remediation of these
sites to be material to the Company's financial condition, results of operations
or cash flows.
24
Asbestos. A number of facilities owned by the Company contain significant
amounts of asbestos insulation and other asbestos-containing materials. The
Company or its subsidiaries have been named, along with numerous others, as a
defendant in lawsuits filed by a large number of individuals who claim injury
due to exposure to asbestos. Most claimants in such litigation have been workers
who participated in construction of various industrial facilities, including
power plants. Some of the claimants have worked at locations owned by the
Company, but most existing claims relate to facilities previously owned by the
Company but currently owned by Texas Genco LLC. The Company anticipates that
additional claims like those received may be asserted in the future. Under the
terms of the separation agreement between the Company and Texas Genco, ultimate
financial responsibility for uninsured losses relating to these claims has been
assumed by Texas Genco, but under the terms of its agreement to sell Texas Genco
to Texas Genco LLC, the Company has agreed to continue to defend such claims to
the extent they are covered by insurance maintained by the Company, subject to
reimbursement of the costs of such defense from Texas Genco LLC. Although their
ultimate outcome cannot be predicted at this time, the Company intends to
continue vigorously contesting claims that it does not consider to have merit
and does not expect, based on its experience to date, these matters, either
individually or in the aggregate, to have a material adverse effect on the
Company's financial condition, results of operations or cash flows.
Other Environmental. From time to time the Company has received notices
from regulatory authorities or others regarding its status as a PRP in
connection with sites found to require remediation due to the presence of
environmental contaminants. In addition, the Company has been named from time to
time as a defendant in litigation related to such sites. Although the ultimate
outcome of such matters cannot be predicted at this time, the Company does not
expect, based on its experience to date, these matters, either individually or
in the aggregate, to have a material adverse effect on the Company's financial
condition, results of operations or cash flows.
(c) Other Proceedings.
The Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company's management
regularly analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters. The Company's
management does not expect the disposition of these matters to have a material
adverse effect on the Company's financial condition, results of operations or
cash flows.
(d) Tax Contingencies.
As discussed in Note 10 to the CenterPoint Energy 10-K/ANotes, in the 1997
through 2000 audit (which now includes 2001), the Internal Revenue Service (IRS)
disallowed all deductions for original issue discount (OID) relating to the
Company's 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) and
7% Automatic Common Exchange Securities (ACES). It is the contention of the IRS
that (1) those instruments, in combination with the Company's long position in
Time Warner common stock (TW Common), constitute a straddle under Section 1092
and 246 of the Internal Revenue Code of 1986, as amended and (2) the
indebtedness underlying those instruments was incurred to carry the TW Common.
If the IRS prevails on both of these positions, all OID (including interest
actually paid) on the ZENS and ACES would not be currently deductible, but would
instead be added to the Company's basis in the TW Common it holds. The
capitalization of OID to the TW Common basis would have the effect of
recharacterizing ordinary interest deductions to capital losses or reduced
capital gains.
The Company's ability to realize the tax benefit of future capital losses,
if any, from the sale of the 21.6 million shares of TW Common currently held
will depend on the timing of those sales, the value of TW Common stock when
sold, and the extent of any other capital gains and losses.
Although the Company is protesting the contention of the IRS, at December
31, 2004, the Company had established a tax reserve for this issue of $79
million, which was increased to $101 million at June 30, 2005. The Company has
also reserved for other significant tax items including issues relating to
acquisitions, capital cost recovery and certain positions taken with respect to
state tax filings. The total amount reserved for the other items is
approximately $40 million.
(e) Nuclear Decommissioning Trusts.
CenterPoint Houston, as collection agent for the nuclear decommissioning
charge assessed on its transmission and distribution customers, deposited $2.9
million in 2004 to trusts established to fund Texas Genco's share of the
25
decommissioning costs for the South Texas Project, and expects to deposit
approximately $2.9 million of collected charges in 2005. There are various
investment restrictions imposed upon Texas Genco by the Texas Utility Commission
and the Nuclear Regulatory Commission relating to Texas Genco's nuclear
decommissioning trusts. Pursuant to the provisions of both a separation
agreement and the Texas Utility Commission's final order, CenterPoint Houston
and Texas Genco are presently jointly administering the decommissioning funds
through the Nuclear Decommissioning Trust Investment Committee. Texas Genco and
CenterPoint Houston 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. As
administrators of the decommissioning funds, CenterPoint Houston and Texas Genco
are jointly responsible for assuring that the funds are prudently invested in a
manner consistent with the rules of the Texas Utility Commission. CenterPoint
Houston and Texas Genco expect to file a request with the Texas Utility
Commission in 2005 to name Texas Genco as the sole fund administrator. Pursuant
to the Texas electric restructuring law, costs associated with nuclear
decommissioning that were not recovered as of January 1, 2002, will continue to
be subject to cost-of-service rate regulation and will be charged to
transmission and distribution customers of CenterPoint Houston or its successor.
26
(12) EARNINGS PER SHARE
The following table reconciles numerators and denominators of the Company's
basic and diluted earnings per share (EPS) calculations:
FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------------- ---------------------------
2004 2005 2004 2005
------------ ------------ ------------ ------------
(IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS)
Basic EPS Calculation:
Income (loss) from continuing operations before
extraordinary item ................................... $ (3) $ 27 $ 26 $ 94
Discontinued operations, net of tax ..................... 60 (3) 105 (3)
Extraordinary item, net of tax .......................... -- 30 -- 30
------------ ------------ ------------ ------------
Net income .............................................. $ 57 $ 54 $ 131 $ 121
============ ============ ============ ============
Weighted average shares outstanding ........................ 307,250,000 309,098,000 306,631,000 308,786,000
============ ============ ============ ============
Basic EPS:
Income (loss) from continuing operations before
extraordinary item ................................... $ (0.01) $ 0.09 $ 0.09 $ 0.30
Discontinued operations, net of tax ..................... 0.20 (0.01) 0.34 (0.01)
Extraordinary item, net of tax .......................... -- 0.10 -- 0.10
------------ ------------ ------------ ------------
Net income .............................................. $ 0.19 $ 0.18 $ 0.43 $ 0.39
============ ============ ============ ============
Diluted EPS Calculation:
Net income .............................................. $ 57 $ 54 $ 131 $ 121
Plus: Income impact of assumed conversions:
Interest on 3 3/4% convertible senior notes .......... -- 4 -- 7
Interest on 6 1/4% convertible trust preferred
securities ........................................ -- -- -- --
------------ ------------ ------------ ------------
Total earnings effect assuming dilution ................. $ 57 $ 58 $ 131 $ 128
============ ============ ============ ============
Weighted average shares outstanding ........................ 307,250,000 309,098,000 306,631,000 308,786,000
Plus: Incremental shares from assumed conversions (1):
Stock options ........................................ 1,301,000 1,302,000 1,259,000 1,254,000
Restricted stock ..................................... 1,070,000 1,365,000 1,070,000 1,365,000
3 3/4% convertible senior notes ...................... -- 49,655,000 -- 49,655,000
6 1/4% convertible trust preferred securities ........ 17,000 16,000 17,000 16,000
------------ ------------ ------------ ------------
Weighted average shares assuming dilution ............... 309,638,000 361,436,000 308,977,000 361,076,000
============ ============ ============ ============
Diluted EPS:
Income (loss) from continuing operations before
extraordinary item ................................... $ (0.01) $ 0.09 $ 0.08 $ 0.28
Discontinued operations, net of tax ..................... 0.20 (0.01) 0.34 (0.01)
Extraordinary item, net of tax .......................... -- 0.08 -- 0.08
------------ ------------ ------------ ------------
Net income .............................................. $ 0.19 $ 0.16 $ 0.42 $ 0.35
============ ============ ============ ============
----------
(1) For the three months ended June 30, 2004 and 2005, the computation of
diluted EPS excludes options to purchase 10,024,219 and 9,356,759 shares of
common stock, respectively, that have exercise prices (ranging from $11.29
to $32.26 per share and $14.01 to $32.26 per share for the second quarter
of 2004 and 2005, respectively) greater than the per share average market
price for the period and would thus be antidilutive if exercised.
For the six months ended June 30, 2004 and 2005, the computation of diluted
EPS excludes options to purchase 12,037,219 and 9,356,759 shares of common
stock, respectively, that have exercise prices (ranging from $10.92 to
$32.26 per share and $14.01 to $32.26 per share for the first six months of
2004 and 2005, respectively) greater than the per share average market
price for the period and would thus be antidilutive if exercised.
27
The Company's $575 million contingently convertible notes are included in
the calculation of diluted earnings per share pursuant to EITF 04-8. The
Company's $255 million contingently convertible notes are not included in the
calculation of diluted earnings per share because the terms of this debt
instrument were modified prior to December 31, 2004 to provide for only cash
settlement of the principal amount upon conversion as required by EITF 04-8.
Additionally, the $255 million contingently convertible notes were excluded from
the calculation of diluted earnings per share because the average market price
of the Company's common stock for the three and six months ended June 30, 2005
did not exceed the conversion price of these notes and would thus be
antidilutive. Diluted earnings per share for the three months and six months
ended June 30, 2004 have not been restated for the adoption of EITF 04-8
effective December 31, 2004 as inclusion of the contingently convertible shares
have an antidilutive effect. The impact on the Company's diluted EPS from
continuing operations for the three and six months ended June 30, 2005 was a
decrease of $-0- and $0.02 per share, respectively.
Subsequent to the modification of the $255 million contingently convertible
notes to provide for only cash settlement of the principal amount upon
conversion, the notes will only be included in the calculation of diluted
earnings per share when the average market price of the Company's common stock
exceeds the conversion price. Any new notes issued in connection with the
exchange offer related to the $575 million contingently convertible notes will
be treated similarly. The conversion prices for the $255 million and the $575
million contingently convertible notes are $12.81 and $11.58, respectively.
(13) 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's Electric
Generation business segment is presented as discontinued operations within these
Interim Financial Statements.
The Company has identified the following reportable business segments:
Electric Transmission & Distribution, Natural Gas Distribution, Pipelines and
Gathering and Other Operations. The Company's generation operations, which were
previously reported in the Electric Generation business segment, are presented
as discontinued operations within these Interim Financial Statements.
Financial data for the Company's reportable business segments are as
follows:
FOR THE THREE MONTHS ENDED JUNE 30, 2004
--------------------------------------------
REVENUES FROM NET
EXTERNAL INTERSEGMENT OPERATING
CUSTOMERS REVENUES INCOME (LOSS)
------------- ------------ -------------
(IN MILLIONS)
Electric Transmission & Distribution .... $ 375(1) $ -- $127
Natural Gas Distribution ................ 1,138(2) -- 23
Pipelines and Gathering ................. 79(3) 34 42
Other Operations ........................ 1 2 (6)
Eliminations ............................ -- (36) --
------ ---- ----
Consolidated ............................ $1,593 $ -- $186
====== ==== ====
FOR THE THREE MONTHS ENDED JUNE 30, 2005
--------------------------------------------
REVENUES FROM NET
EXTERNAL INTERSEGMENT OPERATING
CUSTOMERS REVENUES INCOME (LOSS)
------------- ------------ -------------
(IN MILLIONS)
Electric Transmission & Distribution .... $ 414(1) $ -- $122
Natural Gas Distribution ................ 1,339 1 19
Pipelines and Gathering ................. 87 38 52
Other Operations ........................ 2 2 (7)
Eliminations ............................ -- (41) --
------ ---- ----
Consolidated ............................ $1,842 $ -- $186
====== ==== ====
28
FOR THE SIX MONTHS ENDED JUNE 30, 2004
--------------------------------------------
REVENUES FROM NET TOTAL ASSETS
EXTERNAL INTERSEGMENT OPERATING AS OF
CUSTOMERS REVENUES INCOME (LOSS) DECEMBER 31, 2004
------------- ------------ ------------- -----------------
(IN MILLIONS)
Electric Transmission & Distribution .. $ 705(1) $ -- $212 $ 8,783
Natural Gas Distribution .............. 3,142(2) 1 140 4,732
Pipelines and Gathering ............... 145(3) 71 87 2,637
Other Operations ...................... 3 3 (13) 2,794
Discontinued Operations ............... -- -- -- 1,565
Eliminations .......................... -- (75) -- (2,415)
------ ---- ---- -------
Consolidated .......................... $3,995 $ -- $426 $18,096
====== ==== ==== =======
FOR THE SIX MONTHS ENDED JUNE 30, 2005
--------------------------------------------
REVENUES FROM NET TOTAL ASSETS
EXTERNAL INTERSEGMENT OPERATING AS OF
CUSTOMERS REVENUES INCOME (LOSS) JUNE 30, 2005
------------- ------------ ------------- -------------
(IN MILLIONS)
Electric Transmission & Distribution .. $ 759(1) $ -- $202 $ 8,311
Natural Gas Distribution .............. 3,500 3 158 4,729
Pipelines and Gathering ............... 171 75 116 2,798
Other Operations ...................... 7 4 (14) 2,234
Eliminations .......................... -- (82) -- (2,232)
------ ---- ---- -------
Consolidated .......................... $4,437 $ -- $462 $15,840
====== ==== ==== =======
----------
(1) Sales to subsidiaries of RRI for the three months ended June 30, 2004 and
2005 represented approximately $202 million and $183 million, respectively,
of CenterPoint Houston's transmission and distribution revenues from
external customers. Sales to subsidiaries of RRI for the six months ended
June 30, 2004 and 2005 represented approximately $401 million and $366
million, respectively, of CenterPoint Houston's transmission and
distribution revenues from external customers.
(2) Sales to Texas Genco for the three and six months ended June 30, 2004 of
$10 million and $16 million, respectively, have been reclassified from
intersegment revenues to revenues from external customers due to the sale
of Texas Genco.
(3) Sales to Texas Genco for the three and six months ended June 30, 2004 of $1
million and $2 million, respectively, have been reclassified from
intersegment revenues to revenues from external customers due to the sale
of Texas Genco.
(14) RESTATEMENT
Subsequent to the issuance of its condensed consolidated financial
statements for the three- and six- month periods ended June 30, 2004 and 2005,
the Company determined that, during 2004 and 2005, certain transactions
involving purchases and sales of natural gas among divisions within the
Company's Natural Gas Distribution segment were not properly eliminated in the
Company's consolidated financial statements. Consequently, revenues and natural
gas expenses for the three and six months ended June 30, 2004 were each
overstated by approximately $107 million and $233 million, respectively. For the
three and six months ended June 30, 2005, revenues and natural gas expenses were
each overstated by approximately $90 million and $257 million, respectively, for
the same reason. As a result, the accompanying condensed consolidated financial
statements have been restated from the amounts previously reported to reflect
the elimination of interdivision purchases and sales of natural gas. There was
no effect on the Company's previously reported operating income, net income,
earnings per share or net cash flows for the three and six months ended June 30,
2004 and 2005.
29
A summary of the significant effects of the restatements is as follows:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2004 JUNE 30, 2004
--------------------------- ---------------------------
AS PREVIOUSLY AS PREVIOUSLY
AS RESTATED REPORTED AS RESTATED REPORTED
----------- ------------- ----------- -------------
(IN MILLIONS)
STATEMENTS OF CONSOLIDATED INCOME:
Revenues................................ $1,593 $1,700 $3,995 $4,228
Expenses: Natural gas................... 904 1,011 2,540 2,773
Total Expenses.......................... 1,407 1,514 3,569 3,802
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2005 JUNE 30, 2005
--------------------------- ---------------------------
AS PREVIOUSLY AS PREVIOUSLY
AS RESTATED REPORTED AS RESTATED REPORTED
----------- ------------- ----------- -------------
(IN MILLIONS)
STATEMENTS OF CONSOLIDATED INCOME:
Revenues................................ $1,842 $1,932 $4,437 $4,694
Expenses: Natural gas................... 1,103 1,193 2,884 3,141
Total Expenses.......................... 1,656 1,746 3,975 4,232
AS OF JUNE 30, 2005
---------------------------
AS PREVIOUSLY
AS RESTATED REPORTED
----------- -------------
(IN MILLIONS)
CONSOLIDATED BALANCE SHEETS:
Accounts receivable, net......................... $ 461 $ 512
Total current assets............................. 1,935 1,985
Total assets..................................... 15,840 15,890
Accounts payable................................. 496 546
Total current liabilities........................ 3,588 3,638
Total liabilities and shareholders' equity....... 15,840 15,890
30
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
The following discussion and analysis should be read in combination with
our Interim Financial Statements contained in this Form 10-Q/A.
EXECUTIVE SUMMARY
RESTATEMENT
The following management discussion and analysis gives effect to the
restatement as discussed in Note 14 to our unaudited condensed consolidated
financial statements.
RECENT EVENTS
RECOVERY OF TRUE-UP BALANCE
The Texas Electric Choice Plan (Texas electric restructuring law) provides
for the Public Utility Commission of Texas (Texas Utility Commission) to conduct
a "true-up" proceeding to determine CenterPoint Energy Houston Electric, LLC's
(CenterPoint Houston) stranded costs and certain other costs resulting from the
transition to a competitive retail electric market and to provide for its
recovery of those costs. In March 2004, CenterPoint Houston filed its stranded
cost true-up application with the Texas Utility Commission. CenterPoint Houston
had requested recovery of $3.7 billion, excluding interest. In December 2004,
the Texas Utility Commission issued its final order (True-Up Order) allowing
CenterPoint Houston to recover a true-up balance of approximately $2.3 billion,
which included interest through August 31, 2004, and providing for adjustment of
the amount to be recovered to include interest on the balance until recovery,
the principal portion of additional excess mitigation credits returned to
customers after August 31, 2004 and certain other matters. Both CenterPoint
Houston and other parties filed appeals of the True-Up Order, and those appeals
remain pending before a state district court in Travis County, Texas. The court
held a hearing on the appeal in early August 2005 with a decision currently
expected in the near future.
There are two ways for CenterPoint Houston to recover the true-up balance:
by issuing transition bonds to securitize the amounts due and/or by implementing
a competition transition charge (CTC). In March 2005, the Texas Utility
Commission issued a financing order that authorized the issuance of transition
bonds. Although several parties originally appealed the financing order, only
two have maintained appeals. CenterPoint Houston will not be able to issue
transition bonds while an appeal is pending. Prior to the appeal, it had been
expected that approximately $1.8 billion in transition bonds could be issued by
mid-2005 under the terms of the financing order. On August 4, 2005, the District
Court affirmed the financing order. Texas law provides for any further appeals
to be filed directly with the Texas Supreme Court within 15 days.
On July 14, 2005, CenterPoint Houston received an order from the Texas
Utility Commission allowing it to implement a CTC to collect approximately $570
million over 14 years plus interest at an annual rate of 11.075%. Based on the
accrual of interest provided for in the CTC order, CenterPoint Houston expects
that this amount will increase to approximately $600 million by the end of the
third quarter which is when the CTC is expected to be implemented. The CTC order
also allows CenterPoint Houston to collect approximately $24 million of rate
case expenses over three years. The CTC order authorizes CenterPoint Houston to
impose a charge on retail electric providers to recover the portion of the
true-up balance not covered by the financing order. CenterPoint Houston cannot
implement the CTC until the Texas Utility Commission takes final action on the
motions for rehearing.
CenterPoint Houston is entitled to accrue a return on the true-up balance
until it is fully recovered.
31
CITY OF HOUSTON FRANCHISE
On June 27, 2005, CenterPoint Houston accepted an ordinance granting
CenterPoint Houston a new 30-year franchise to use the public rights-of-way to
conduct its business in the City of Houston (New Franchise Ordinance). The New
Franchise Ordinance took effect on July 1, 2005, and replaced the prior
electricity franchise ordinance, which had been in effect since 1957. The New
Franchise Ordinance clarifies certain operational obligations of CenterPoint
Houston and the City of Houston and provides for streamlined payment and audit
procedures and a two year statute of limitations on claims for underpayment or
overpayment under the ordinance. Under the prior electricity franchise
ordinance, CenterPoint Houston paid annual franchise fees of $76.6 million to
the City of Houston for the year ended December 31, 2004. For the twelve-month
period beginning July 1, 2005, the annual franchise fee (Annual Franchise Fee)
under the New Franchise Ordinance will include a base amount of $88.1 million
(Base Amount) and an additional payment of $8.5 million (Additional Amount). The
Base Amount and the Additional Amount will be adjusted annually based on the
annual increase or decrease in kWh delivered by CenterPoint Houston within the
City of Houston.
The New Franchise Ordinance requires the City of Houston to modify
CenterPoint Houston's tariff to allow CenterPoint Houston to recover the
Additional Amount from retail electric providers serving end-use retail electric
customers within the City of Houston boundaries. CenterPoint Houston filed a
request with the City of Houston to implement a tariff rider to collect the
Additional Amount, but subsequently asked the City of Houston to abate further
consideration of that application pending a review by counsel for the City of
Houston and CenterPoint Houston regarding the implementation of the New
Franchise Ordinance.
CenterPoint Houston began paying the new annual franchise fees on July 1,
2005. Pursuant to the New Franchise Ordinance, CenterPoint Houston retains the
right to recover from the City of Houston any portion of the Additional Amount
paid (or to refuse to pay any portion not yet paid) for which CenterPoint
Houston is denied recovery by any regulatory authority. Additionally, the New
Franchise Ordinance provides that the Annual Franchise Fee will be reduced
prospectively to reflect any portion of the Annual Franchise Fee that is not
included in CenterPoint Houston's base rates in any subsequent rate case.
COMPLETION OF SALE OF TEXAS GENCO
On April 13, 2005, we completed the sale of our nuclear generation assets,
consisting of a 30.8% undivided interest in the South Texas Project Electric
Generating Station, to Texas Genco LLC (formerly known as GC Power Acquisition
LLC) for $700 million in cash. The sale was effected through the merger of our
wholly owned subsidiary, Texas Genco Holdings, Inc. (Texas Genco), with a wholly
owned subsidiary of Texas Genco LLC. As a result of the merger, Texas Genco
became a wholly owned subsidiary of Texas Genco LLC and we received $700 million
in cash. We used the proceeds primarily to repay outstanding indebtedness. The
merger was the second and final step of the transaction announced in July 2004
in which Texas Genco LLC agreed to acquire Texas Genco. In the first step of the
transaction, involving the sale of Texas Genco's fossil generation assets (coal,
lignite and gas-fired plants), we received $2.231 billion in December 2004,
which was used primarily to pay down debt. In 2004, we recorded a loss of $214
million related to the sale of Texas Genco and recorded additional losses to
offset subsequent earnings of Texas Genco. We continued to record additional
losses in 2005 until the April 2005 closing of the final step of the sale
transaction to offset Texas Genco's 2005 earnings.
DEBT FINANCING TRANSACTIONS
In March 2005, we filed a registration statement relating to an offer to
exchange our $575 million aggregate principal amount of 3.75% convertible senior
notes due 2023 for a new series of 3.75% convertible senior notes due 2023. This
registration statement was declared effective by the SEC on July 19, 2005 at
which time we commenced the exchange offer. The exchange offer expires on August
17, 2005. We commenced the exchange offer in response to the guidance set forth
in Emerging Issues Task Force Issue No. 04-8, "The Effect of Contingently
Convertible Instruments on Diluted Earnings Per Share." Under that guidance,
because the terms of the new notes provide for settlement of the principal
amount on conversion in cash rather than our common stock, exchanging new notes
for old notes will allow us to exclude the portion of the conversion value of
the new notes attributable to their principal amount from our computation of
diluted earnings per share from continuing operations.
In June 2005, CERC Corp. replaced its $250 million three-year revolving
credit facility with a $400 million five-year revolving credit facility. The new
credit facility terminates on June 30, 2010. Borrowings under this facility may
be made at the London interbank offered rate (LIBOR) plus 55 basis points,
including the facility fee,
32
based on current credit ratings. An additional utilization fee of 10 basis
points applies to borrowings whenever more than 50% of the facility is utilized.
Changes in credit ratings could lower or raise the increment to LIBOR depending
on whether ratings improved or were lowered.
REPEAL OF THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
On July 29, 2005, Congress passed the Energy Policy Act of 2005 (Energy
Act), which President Bush is expected to sign in early August. Under that
legislation, the Public Utility Holding Company Act of 1935 (1935 Act) is
repealed six months after the enactment of the Energy Act. After the effective
date of repeal, we and our subsidiaries will no longer be subject to
restrictions imposed under the 1935 Act. Until the repeal is effective, we and
our subsidiaries remain subject to the provisions of the 1935 Act and the terms
of orders issued by the Securities and Exchange Commission (SEC) under the 1935
Act. The Energy Act transfers to the Federal Energy Regulatory Commission (FERC)
certain functions performed by the SEC under the 1935 Act, including the
requirement that holding companies and their subsidiaries maintain certain books
and records and make them available for review by FERC and, through FERC, to
state regulatory authorities. The Energy Act requires FERC to issue regulations
to implement its jurisdiction under the Energy Act. It is presently unknown
what, if any, specific obligations under those rules may be imposed on us and
our subsidiaries as result of that rulemaking.
2ND QUARTER 2005 HIGHLIGHTS
Our operating performance for the second quarter of 2005 compared to the
second quarter of 2004 was affected by:
- increased operating income of $10 million in our Pipelines and
Gathering business segment primarily from increased demand for certain
transportation and ancillary services and increased throughput and
demand for services related to our core gas gathering operations;
- continued customer growth, with the addition of 95,000 metered
electric and gas customers;
- an increase in other income of $35 million for the second quarter of
2005 related to the return on our true-up balance; and
- a decrease in interest expense of $10 million.
The above increases in operating performance were partially offset by:
- decreased operating income of $5 million in our Electric Transmission
& Distribution business segment primarily from increased state and
local taxes and higher operation and maintenance expenses including
the absence of a $15 million partial reversal of a reserve related to
the final fuel reconciliation recorded in the second quarter of 2004,
partially offset by increased usage mainly due to weather, continued
customer growth and higher transmission cost recovery; and
- decreased operating income of $4 million in our Natural Gas
Distribution business segment primarily due to increased depreciation
expense.
33
CONSOLIDATED RESULTS OF OPERATIONS
All dollar amounts in the tables that follow are in millions, except for
per share amounts.
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2004 2005 2004 2005
------ ------ ------ ------
Revenues .......................................... $1,593 $1,842 $3,995 $4,437
Expenses .......................................... 1,407 1,656 3,569 3,975
------ ------ ------ ------
Operating Income .................................. 186 186 426 462
Interest and Other Finance Charges ................ (198) (189) (391) (371)
Other Income, net ................................. 10 48 14 84
------ ------ ------ ------
Income (Loss) From Continuing Operations Before
Income Taxes and Extraordinary Item ............ (2) 45 49 175
Income Tax Expense ................................ (1) (18) (23) (81)
------ ------ ------ ------
Income (Loss) From Continuing Operations Before
Extraordinary Item ............................. (3) 27 26 94
Discontinued Operations, net of tax ............... 60 (3) 105 (3)
------ ------ ------ ------
Income Before Extraordinary Item .................. 57 24 131 91
Extraordinary Item, net of tax .................... -- 30 -- 30
------ ------ ------ ------
Net Income ........................................ $ 57 $ 54 $ 131 $ 121
====== ====== ====== ======
BASIC EARNINGS PER SHARE:
Income (Loss) From Continuing Operations Before
Extraordinary Item .......................... $(0.01) $ 0.09 $ 0.09 $ 0.30
Discontinued Operations, net of tax ............ 0.20 (0.01) 0.34 (0.01)
Extraordinary Item, net of tax ................. -- 0.10 -- 0.10
------ ------ ------ ------
Net Income ..................................... $ 0.19 $ 0.18 $ 0.43 $ 0.39
====== ====== ====== ======
DILUTED EARNINGS PER SHARE:
Income (Loss) From Continuing Operations Before
Extraordinary Item .......................... $(0.01) $ 0.09 $ 0.08 $ 0.28
Discontinued Operations, net of tax ............ 0.20 (0.01) 0.34 (0.01)
Extraordinary Item, net of tax ................. -- 0.08 -- 0.08
------ ------ ------ ------
Net Income ..................................... $ 0.19 $ 0.16 $ 0.42 $ 0.35
====== ====== ====== ======
THREE MONTHS ENDED JUNE 30, 2005 COMPARED TO THREE MONTHS ENDED JUNE 30, 2004
Income from Continuing Operations. We reported income from continuing
operations before extraordinary item of $27 million ($0.09 per diluted share)
for the three months ended June 30, 2005 as compared to a $3 million loss ($0.01
per diluted share) for the same period in 2004. The increase in income from
continuing operations of $30 million was primarily due to increased operating
income of $10 million in our Pipelines and Gathering business segment resulting
from increased demand for certain transportation and ancillary services as well
as increased throughput and demand for services related to our core gas
gathering operations, $35 million of other income related to a return on the
true-up balance of our Electric Transmission & Distribution business segment as
a result of the True-Up Order and a $10 million decrease in interest expense due
to lower borrowing levels and lower borrowing costs reflecting the replacement
of certain of our credit facilities. These increases were partially offset by
decreased operating income of $5 million in our Electric Transmission &
Distribution business segment primarily from increased state and local taxes and
higher operation and maintenance expenses including the absence of a $15 million
partial reversal of a reserve related to the final fuel reconciliation recorded
in the second quarter of 2004, partially offset by increased usage mainly due to
weather, continued customer growth and higher transmission cost recovery, as
well as decreased operating income of $4 million in our Natural Gas Distribution
business segment primarily due to increased depreciation expense and increased
income tax expense as discussed below.
Income Tax Expense. During the three months ended June 30, 2005, our
effective tax rate was 39.3%. The most significant items affecting our effective
tax rate in the second quarter of 2005 were an addition to the tax reserve of
approximately $12 million relating to the contention of the Internal Revenue
Service (IRS) that the current deductions for original issue discount (OID) on
our 2.0% Zero-Premium Exchangeable Subordinated Notes due
34
2029 (ZENS) be capitalized, potentially converting what would be ordinary
deductions into capital losses at the time the ZENS are settled, partially
offset by a favorable tax audit adjustment of $10 million. We expect the reserve
to increase by approximately $12 million in each of the remaining two quarters.
SIX MONTHS ENDED JUNE 30, 2005 COMPARED TO SIX MONTHS ENDED JUNE 30, 2004
Income from Continuing Operations. We reported income from continuing
operations before extraordinary item of $94 million ($0.28 per diluted share)
for the six months ended June 30, 2005 as compared to $26 million ($0.08 per
diluted share) for the same period in 2004. The increase in income from
continuing operations of $68 million was primarily due to increased operating
income of $29 million in our Pipelines and Gathering business segment resulting
from increased demand for certain transportation and ancillary services as well
as increased throughput and demand for services related to our core gas
gathering operations, increased operating income of $18 million in our Natural
Gas Distribution business segment primarily due to rate increases, higher
contributions from our competitive natural gas sales business, reduced pension
and benefit costs and the absence of severance costs recorded in the first
quarter of 2004, partially offset by milder weather, decreased throughput and
increased depreciation, $69 million of other income related to a return on the
true-up balance of our Electric Transmission & Distribution business segment as
a result of the True-Up Order, and a $20 million decrease in interest expense
due to lower borrowing levels and lower borrowing costs reflecting the
replacement of certain of our credit facilities. The above increases were
partially offset by decreased operating income of $10 million in our Electric
Transmission & Distribution business segment primarily from increased state and
local taxes and higher operation and maintenance expenses including the absence
of a $15 million partial reversal of a reserve related to the final fuel
reconciliation recorded in the second quarter of 2004, partially offset by
increased usage mainly due to weather, continued customer growth and higher
transmission cost recovery, as well as increased income tax expense as discussed
below.
Income Tax Expense. During the six months ended June 30, 2005, our
effective tax rate was 46.2%. The most significant item affecting our effective
tax rate in the first six months of 2005 is an addition to the tax reserve of
approximately $22 million relating to the ZENS as discussed above.
INTEREST EXPENSE AND OTHER FINANCE CHARGES
In accordance with Emerging Issues Task Force Issue No. 87-24 "Allocation
of Interest to Discontinued Operations," we have reclassified interest to
discontinued operations of Texas Genco based on net proceeds received from the
sale of Texas Genco of $2.5 billion, and have applied the proceeds to the amount
of debt assumed to be paid down in 2004 according to the terms of the respective
credit facilities in effect for that period. In periods where only the term loan
was assumed to be repaid, the actual interest paid on the term loan was
reclassified. In periods where a portion of the revolver was assumed to be
repaid, the percentage of that portion of the revolver to the total outstanding
balance was calculated, and that percentage was applied to the actual interest
paid in those periods to compute the amount of interest reclassified.
Total interest expense incurred was $210 million and $415 million for the
three and six months ended June 30, 2004. We have reclassified $12 million and
$24 million of interest expense for the three and six months ended June 30, 2004
based upon interest expense associated with debt that would have been required
to be repaid as a result of our disposition of Texas Genco.
EXTRAORDINARY ITEM AND LOSS ON DISPOSAL OF TEXAS GENCO
Net income for both the three months and six months ended June 30, 2005
included an after-tax extraordinary gain of $30 million ($0.08 per diluted
share) reflecting an adjustment to the extraordinary loss recorded in the last
half of 2004 to write-down generation-related regulatory assets as a result of
the final orders issued by the Texas Utility Commission.
Net income for the three months ended June 30, 2004 and 2005 included a net
after-tax gain (loss) from discontinued operations of Texas Genco of $60 million
($0.20 per diluted share) and ($3) million ($0.01 per diluted share),
respectively. Net income for the six months ended June 30, 2004 and 2005
included a net after tax gain (loss) from discontinued operations of Texas Genco
of $105 million ($0.34 per diluted share) and ($3) million ($0.01 per diluted
share), respectively.
35
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following table presents operating income for each of our business
segments for the three and six months ended June 30, 2004 and 2005. Some amounts
from the previous year have been reclassified to conform to the 2005
presentation of the financial statements. These reclassifications do not affect
consolidated net income.
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Electric Transmission & Distribution .............. $127 $122 $212 $202
Natural Gas Distribution .......................... 23 19 140 158
Pipelines and Gathering ........................... 42 52 87 116
Other Operations .................................. (6) (7) (13) (14)
---- ---- ---- ----
Total Consolidated Operating Income ............ $186 $186 $426 $462
==== ==== ==== ====
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 -- Risk Factors Affecting Our Electric Transmission &
Distribution Business," " -- Risk Factors Associated with Our Consolidated
Financial Condition" and "-- Other Risks" beginning on Page 51 in Item 5 of Part
II of our Quarterly Report on Form 10-Q for the period ended June 30, 2005 filed
on August 8, 2005.
The following tables provide summary data of our Electric Transmission &
Distribution business segment for the three and six months ended June 30, 2004
and 2005:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2004 2005 2004 2005
---------- ---------- ---------- ----------
(IN MILLIONS, EXCEPT CUSTOMER DATA)
Electric transmission and distribution revenues ............... $ 357 $ 388 $ 672 $ 711
---------- ---------- ---------- ----------
Electric transmission and distribution expenses:
Operation and maintenance .................................. 125 153 258 291
Depreciation and amortization .............................. 63 64 123 128
Taxes other than income taxes .............................. 51 58 98 108
---------- ---------- ---------- ----------
Total electric transmission and distribution expenses.... 239 275 479 527
---------- ---------- ---------- ----------
Operating Income - Electric transmission and
distribution utility ....................................... 118 113 193 184
Operating Income - Transition bond company (1) ................ 9 9 19 18
---------- ---------- ---------- ----------
Total Segment Operating Income ................................ $ 127 $ 122 $ 212 $ 202
========== ========== ========== ==========
Actual gigawatt-hours (GWh) delivered:
Residential ................................................ 5,801 6,594 10,203 10,736
Total ...................................................... 18,545 18,956 34,065 34,783
Average number of metered customers:
Residential ................................................ 1,634,202 1,675,573 1,628,074 1,668,447
Total ...................................................... 1,856,846 1,904,090 1,849,762 1,895,556
----------
(1) Represents the amount necessary to pay interest on the transition bonds.
THREE MONTHS ENDED JUNE 30, 2005 COMPARED TO THREE MONTHS ENDED JUNE 30, 2004
Our Electric Transmission & Distribution business segment reported
operating income of $122 million for the three months ended June 30, 2005,
consisting of $113 million for the regulated electric transmission and
distribution utility and $9 million for the transition bond company. For the
three months ended June 30, 2004, operating income totaled $127 million,
consisting of $118 million for the regulated electric transmission and
distribution utility and $9 million for the transition bond company. Operating
revenues increased primarily from increased usage mainly due to warmer weather
($14 million), continued customer growth ($8 million) with the addition of
48,000 metered customers since June 2004 and higher transmission cost recovery
($4 million). The increase in operating revenues was more than offset by higher
transmission costs ($3 million), higher tree trimming costs for preventive
36
maintenance ($4 million), increased state and local taxes ($7 million) and the
absence of a $15 million partial reversal of a reserve related to the final fuel
reconciliation recorded in 2004.
SIX MONTHS ENDED JUNE 30, 2005 COMPARED TO SIX MONTHS ENDED JUNE 30, 2004
Our Electric Transmission & Distribution business segment reported
operating income of $202 million for the six months ended June 30, 2005,
consisting of $184 million for the regulated electric transmission and
distribution utility and $18 million for the transition bond company. For the
six months ended June 30, 2004, operating income totaled $212 million,
consisting of $193 million for the regulated electric transmission and
distribution utility and $19 million for the transition bond company. Operating
revenues increased primarily from increased usage mainly due to warmer weather
($9 million), continued customer growth ($15 million) with the addition of
48,000 metered customers since June 2004 and higher transmission cost recovery
($8 million). The increase in operating revenues was more than offset by higher
transmission costs ($8 million), higher tree trimming costs for preventive
maintenance ($6 million), the absence of a $15 million partial reversal of a
reserve related to the final fuel reconciliation recorded in 2004, increased
state and local taxes ($10 million) and higher depreciation expense ($5
million), partially offset by reduced benefits expense ($7 million).
NATURAL GAS DISTRIBUTION
For information regarding factors that may affect the future results of
operations of our Natural Gas Distribution business segment, please read "Risk
Factors -- Risk Factors Affecting Our Natural Gas Distribution and Pipelines and
Gathering Businesses," " -- Risk Factors Associated with Our Consolidated
Financial Condition" and "-- Other Risks" beginning on page 51 in Item 5 of Part
II of our Quarterly Report on Form 10-Q for the period ended June 30, 2005 filed
on August 8, 2005.
The following table provides summary data of our Natural Gas Distribution
business segment for the three and six months ended June 30, 2004 and 2005:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2004 2005 2004 2005
---------- ---------- ---------- ----------
(IN MILLIONS, EXCEPT CUSTOMER DATA)
Revenues ................................ $ 1,138 $ 1,340 $ 3,143 $ 3,503
---------- ---------- ---------- ----------
Expenses:
Natural gas .......................... 920 1,123 2,583 2,931
Operation and maintenance ............ 133 133 283 273
Depreciation and amortization ........ 35 39 70 77
Taxes other than income taxes ........ 27 26 67 64
---------- ---------- ---------- ----------
Total expenses .................... 1,115 1,321 3,003 3,345
---------- ---------- ---------- ----------
Operating Income ........................ $ 23 $ 19 $ 140 $ 158
========== ========== ========== ==========
Throughput (in billion cubic feet (Bcf)):
Residential .......................... 21 21 106 98
Commercial and industrial ............ 49 43 132 120
Non-rate regulated ................... 167 148 306 331
Elimination (1) ...................... (63) (29) (73) (78)
---------- ---------- ---------- ----------
Total Throughput .................. 174 183 471 471
========== ========== ========== ==========
Average number of customers:
Residential .......................... 2,793,297 2,833,773 2,802,379 2,842,645
Commercial and industrial ............ 242,111 246,032 244,388 247,429
Non-rate regulated ................... 6,265 6,533 6,228 6,522
---------- ---------- ---------- ----------
Total ............................. 3,041,673 3,086,338 3,052,995 3,096,596
========== ========== ========== ==========
----------
(1) Elimination of intrasegment sales.
THREE MONTHS ENDED JUNE 30, 2005 COMPARED TO THREE MONTHS ENDED JUNE 30, 2004
Our Natural Gas Distribution business segment reported operating income of
$19 million for the three months ended June 30, 2005 as compared to $23 million
for the same period in 2004. Increases in operating income from rate increases
($5 million) and increased contributions from our competitive natural gas sales
business ($1 million)
37
were more than partially offset by the impact of decreased throughput net of
continued customer growth with the addition of approximately 47,000 customers
since June 2004 ($5 million) and increased depreciation expense primarily due to
higher plant balances ($4 million). Decreases in operation and maintenance
expenses primarily from lower employee benefit expenses ($7 million) and the
capitalization of previously incurred restructuring expenses as allowed by a
recent regulatory order from the Railroad Commission of Texas ($4 million)
offset other expense increases ($11 million).
SIX MONTHS ENDED JUNE 30, 2005 COMPARED TO SIX MONTHS ENDED JUNE 30, 2004
Our Natural Gas Distribution business segment reported operating income of
$158 million for the six months ended June 30, 2005 as compared to $140 million
for the same period in 2004. Increases in operating income from rate increases
($16 million) and increased contributions from our competitive natural gas sales
business ($4 million) were partially offset by the impact of milder weather and
decreased throughput net of continued customer growth with the addition of
approximately 47,000 customers since June 2004 ($10 million). Operation and
maintenance expense decreased $10 million. Excluding an $8 million charge
recorded in the first quarter of 2004 for severance costs associated with staff
reductions, which has reduced costs in later periods, operation and maintenance
expenses decreased by $2 million primarily due to lower employee benefit
expenses ($11 million) and the capitalization of previously incurred
restructuring expenses as discussed above ($4 million), which more than offset
other expense increases ($13 million). These net increases to operating income
were partially offset by increased depreciation expense primarily due to higher
plant balances ($7 million).
PIPELINES AND GATHERING
For information regarding factors that may affect the future results of
operations of our Pipelines and Gathering business segment, please read "Risk
Factors -- Risk Factors Affecting Our Natural Gas Distribution and Pipelines and
Gathering Businesses," " -- Risk Factors Associated with Our Consolidated
Financial Condition" and "-- Other Risks" beginning on page 51 in Item 5 of Part
II of our Quarterly Report on Form 10-Q for the period ended June 30, 2005 filed
on August 8, 2005.
The following table provides summary data of our Pipelines and Gathering
business segment for the three and six months ended June 30, 2004 and 2005:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Revenues ........................... $113 $125 $216 $246
---- ---- ---- ----
Expenses:
Natural gas ..................... 18 18 28 25
Operation and maintenance ....... 37 40 70 74
Depreciation and amortization ... 11 11 22 22
Taxes other than income taxes ... 5 4 9 9
---- ---- ---- ----
Total expenses ............... 71 73 129 130
---- ---- ---- ----
Operating Income ................... $ 42 $ 52 $ 87 $116
==== ==== ==== ====
Throughput (in Bcf):
Natural Gas Sales ............... 4 3 7 4
Transportation .................. 207 230 477 501
Gathering ....................... 79 87 154 170
Elimination (1) ................. (3) (2) (5) (3)
---- ---- ---- ----
Total Throughput ............. 287 318 633 672
==== ==== ==== ====
----------
(1) Elimination of volumes both transported and sold.
THREE MONTHS ENDED JUNE 30, 2005 COMPARED TO THREE MONTHS ENDED JUNE 30, 2004
Our Pipelines and Gathering business segment reported operating income of
$52 million for the three months ended June 30, 2005 compared to $42 million for
the same period in 2004. Operating margins (revenues less natural gas costs)
increased by $12 million primarily due to increased demand for certain
transportation and ancillary
38
services ($7 million) and increased throughput and demand for services related
to our core gas gathering operations ($9 million).
SIX MONTHS ENDED JUNE 30, 2005 COMPARED TO SIX MONTHS ENDED JUNE 30, 2004
Our Pipelines and Gathering business segment reported operating income of
$116 million for the six months ended June 30, 2005 compared to $87 million for
the same period in 2004. Operating margins (revenues less natural gas costs)
increased by $33 million primarily due to increased demand for certain
transportation and ancillary services ($18 million) and increased throughput and
demand for services related to our core gas gathering operations ($14 million).
Additionally, operation and maintenance expenses increased by $4 million
primarily due to increased pipeline integrity compliance expenses.
OTHER OPERATIONS
The following table shows the operating loss of our Other Operations
business segment for the three and six months ended June 30, 2004 and 2005:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Revenues ......... $ 3 $ 4 $ 6 $ 11
Expenses ......... 9 11 19 25
--- --- ---- ----
Operating Loss ... $(6) $(7) $(13) $(14)
=== === ==== ====
DISCONTINUED OPERATIONS
In July 2004, we announced our agreement to sell our majority owned
subsidiary, Texas Genco, to Texas Genco LLC. On December 15, 2004, Texas Genco
completed the sale of its fossil generation assets (coal, lignite and gas-fired
plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas
Genco, whose principal remaining asset was its ownership interest in a nuclear
generating facility, distributed $2.231 billion in cash to us. The final step of
the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC
in exchange for an additional cash payment to us of $700 million, was completed
on April 13, 2005.
We recorded after-tax income of $60 million and $105 million for the three
and six months ended June 30, 2004, respectively, related to the operations of
Texas Genco. We recorded an after-tax loss of $3 million for each of the three
and six month periods ended June 30, 2005. General corporate overhead,
previously allocated to Texas Genco from CenterPoint Energy, was $5 million and
$10 million for the three and six months ended June 30, 2004, respectively, and
was less than $1 million for each of the three and six month periods ended June
30, 2005. These amounts will not be eliminated by the sale of Texas Genco and
were excluded from income from discontinued operations and reflected as general
corporate overhead of CenterPoint Energy in income from continuing 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 Interim Financial Statements present these operations as discontinued
operations in accordance with SFAS No. 144. Interest expense of $12 million and
$24 million for the three and six months ended June 30, 2004, respectively, was
reclassified to discontinued operations of Texas Genco related to the applicable
amounts of CenterPoint Energy's term loan and revolving credit facility debt
that would have been assumed to be paid off with any proceeds from the sale of
Texas Genco during those respective periods 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 -- Certain Factors Affecting
Future Earnings" in Item 7 of Part II of the Annual Report on Form 10-K of
CenterPoint Energy for the year ended December 31, 2004 filed on March 16, 2005
(CenterPoint Energy Form 10-K), which is incorporated herein by reference, and
"Risk Factors" beginning on page 51 in Item 5 of Part II of our Quarterly Report
on Form 10-Q for the period ended June 30, 2005 filed on August 8, 2005.
39
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,
2004 and 2005:
SIX MONTHS ENDED JUNE 30,
-------------------------
2004 2005
----- -----
(IN MILLIONS)
Cash provided by (used in):
Operating activities ...... $ 692 $ 17
Investing activities ...... (397) 412
Financing activities ...... (286) (185)
CASH PROVIDED BY OPERATING ACTIVITIES
Net cash provided by operating activities in the first six months of 2005
decreased $675 million compared to the same period in 2004 primarily due to
decreased cash provided by Texas Genco of $243 million and increased tax
payments of $423 million, the majority of which related to the tax payment
associated with the sale of Texas Genco, offset by increased operating income,
higher net accounts receivable/payable due to higher gas prices in 2005 as
compared to 2004 and the termination of excess mitigation credits effective
April 29, 2005.
CASH PROVIDED BY INVESTING ACTIVITIES
Net cash provided by investing activities increased $809 million in the
first six months of 2005 as compared to the same period in 2004 primarily due to
$700 million in proceeds received from the sale of our remaining interest in
Texas Genco and cash of Texas Genco of $163 million, partially offset by
increased capital expenditures of $64 million.
CASH USED IN FINANCING ACTIVITIES
In the first six months of 2005, debt payments exceeded net loan proceeds
by $112 million. During the first six months of 2004, debt payments exceeded net
loan proceeds by $224 million.
FUTURE SOURCES AND USES OF CASH
Our liquidity and capital requirements are affected primarily by our
results of operations, capital expenditures, debt service requirements, tax
payments, working capital needs, various regulatory actions and appeals relating
to such regulatory actions. Our principal cash requirements for the last six
months of 2005 include the following:
- approximately $419 million of capital expenditures;
- dividend payments on CenterPoint Energy common stock and debt service
payments; and
- $1.7 billion of maturing long-term debt, including $31 million of
transition bonds and $325 million of CERC's senior notes which were
repaid in July 2005.
We expect that borrowings under our credit facilities and anticipated cash
flows from operations will be sufficient to meet our cash needs for 2005. Cash
needs may also be met by issuing securities in the capital markets. CenterPoint
Houston's $1.31 billion term loan, maturing in November 2005, requires the
proceeds from the issuance of transition bonds to be used to reduce the term
loan unless refused by the lenders. CenterPoint Houston's $1.31 billion credit
facility may be utilized to refinance the $1.31 billion term loan at maturity.
Under this facility, CenterPoint Houston must repay borrowings under the
facility with (i) 100% of the net proceeds from the issuance of transition bonds
and (ii) the proceeds, in excess of $200 million, from certain other new net
indebtedness for borrowed money incurred by CenterPoint Houston.
The 1935 Act regulates our financing ability, as more fully described in
"-- Certain Contractual and Regulatory Limits on Ability to Issue Securities,
Borrow Money and Pay Dividends on Our Common Stock" below.
40
Off-Balance Sheet Arrangements. Other than operating leases, we have no
off-balance sheet arrangements. However, we do participate in a receivables
factoring arrangement. CERC Corp. has a bankruptcy remote subsidiary, which we
consolidate, which was formed for the sole purpose of buying receivables created
by CERC and selling those receivables to an unrelated third-party. 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 Sheet. In January 2005, the $250 million
facility was extended to January 2006 and temporarily increased, for the period
from January 2005 to June 2005, to $375 million. As of June 30, 2005, CERC had
$181 million of advances under its receivables facility.
Credit Facilities. In June 2005, CERC Corp. replaced its $250 million
three-year revolving credit facility with a $400 million five-year revolving
credit facility. The new credit facility terminates on June 30, 2010. Borrowings
under this facility may be made at the London interbank offered rate (LIBOR)
plus 55 basis points, including the facility fee, based on current credit
ratings. An additional utilization fee of 10 basis points applies to borrowings
whenever more than 50% of the facility is utilized. Changes in credit ratings
could lower or raise the increment to LIBOR depending on whether ratings
improved or were lowered.
In March 2005, we replaced our $750 million revolving credit facility with
a $1 billion five-year revolving credit facility. Borrowings may be made under
the facility at LIBOR plus 100 basis points based on current credit ratings. An
additional utilization fee of 12.5 basis points applies to borrowings whenever
more than 50% of the facility is utilized. Changes in credit ratings could lower
or raise the increment to LIBOR depending on whether ratings improved or were
lowered. The facility contains covenants, including a debt to earnings before
interest, taxes, depreciation and amortization (EBITDA) covenant and an EBITDA
to interest covenant.
Borrowings under our credit facility are available upon customary terms and
conditions for facilities of this type, including a requirement that we
represent, except as described below, that no "material adverse change" has
occurred at the time of a new borrowing under this facility. A "material adverse
change" is defined as the occurrence of a material adverse change in our ability
to perform our obligations under the facility but excludes any litigation
related to the True-Up Order. The base line for any determination of a relative
material adverse change is our most recently audited financial statements. At
any time after the first time our credit ratings reach at least BBB by Standard
& Poor's Ratings Services, a division of The McGraw Hill Companies (S&P), and
Baa2 by Moody's Investors Service, Inc. (Moody's), BBB+ by S&P and Baa3 by
Moody's, or BBB- by S&P and Baa1 by Moody's, or if the drawing is to retire
maturing commercial paper, we are not required to represent as a condition to
such drawing that no material adverse change has occurred or that no litigation
expected to have a material adverse effect has occurred. Due to restrictions
imposed on us under our June 29, 2005 financing order under the 1935 Act, we may
not be able to draw the full amount of our credit agreement without further
authorization from the SEC because such borrowings would reduce our common
equity capitalization ratio below its level as of March 31, 2005. We do not
expect this limitation to constrain our borrowings beyond the end of 2005 based
on current projections. Additionally, these restrictions will no longer be
applicable upon the effective date of the repeal of the 1935 Act. For a
discussion of these restrictions, see "-- Certain Contractual and Regulatory
Limits on Ability to Issue Securities, Borrow Money and Pay Dividends on Our
Common Stock" below.
Also in March 2005, CenterPoint Houston established a $200 million
five-year revolving credit facility. Borrowings may be made under the facility
at LIBOR plus 75 basis points based on CenterPoint Houston's current credit
rating. An additional utilization fee of 12.5 basis points applies to borrowings
whenever more than 50% of the facility is utilized. Changes in credit ratings
could lower or raise the increment to LIBOR depending on whether ratings
improved or were lowered.
CenterPoint Houston also established a $1.31 billion credit facility in
March 2005. This facility is available to be utilized only to refinance
CenterPoint Houston's $1.31 billion term loan maturing in November 2005 in the
event that proceeds from the issuance of transition bonds are not sufficient to
repay such term loan. Due to the pending appeal of the Texas Utility
Commission's financing order, it is unlikely that proceeds from the sale of
transition bonds would be received prior to November 2005. Drawings may be made
under this credit facility until November 2005, at which time any outstanding
borrowings are converted to term loans maturing in November 2007. Under this
facility, (i) 100% of the net proceeds from the issuance of transition bonds and
(ii) the proceeds, in excess of $200 million, from certain other new net
indebtedness for borrowed money incurred by CenterPoint Houston must be used to
repay borrowings under the facility. Based on CenterPoint Houston's current
credit ratings, borrowings under the facility may be made at LIBOR plus 75 basis
points. The interest rate under the term loan which this facility would replace
is LIBOR plus 975 basis points. Changes in credit ratings could lower or raise
the increment
41
to LIBOR depending on whether ratings improved or were lowered. Any drawings
under this facility must be secured by CenterPoint Houston's general mortgage
bonds in the same principal amount and bearing the same interest rate as such
drawings.
CERC Corp.'s $400 million credit facility contains covenants, including a
total debt to capitalization covenant of 65% and an EBITDA to interest covenant.
CenterPoint Houston's $200 million and $1.31 billion credit facilities each
contain covenants, including a debt (excluding transition bonds) to total
capitalization covenant of 68% and an EBITDA to interest covenant. Borrowings
under CERC Corp.'s $400 million credit facility and CenterPoint Houston's $200
million credit facility and its $1.31 billion credit facility are available
notwithstanding that a material adverse change has occurred or litigation that
could be expected to have a material adverse effect has occurred, so long as
other customary terms and conditions are satisfied.
As of August 1, 2005, we had the following credit facilities (in millions):
AMOUNT UTILIZED AT
DATE EXECUTED COMPANY SIZE OF FACILITY AUGUST 1, 2005 TERMINATION DATE
------------- ------------------- ---------------- ------------------ ----------------
March 7, 2005 CenterPoint Energy $1,000 $152 (1) March 7, 2010
March 7, 2005 CenterPoint Houston 200 -- March 7, 2010
March 7, 2005 CenterPoint Houston 1,310 -- (2)
June 30, 2005 CERC Corp. 400 -- June 30, 2010
----------
(1) Includes $27 million of outstanding letters of credit and $125 million of
commercial paper backstopped by the credit facility.
(2) Revolver until November 2005 with two-year term-out of borrowed moneys.
The $1 billion CenterPoint Energy credit facility backstops a $1 billion
commercial paper program under which CenterPoint Energy began issuing commercial
paper in June 2005. No commercial paper was outstanding as of June 30, 2005. The
commercial paper is rated "Not Prime" by Moody's, "A-3" by S&P and "F3" by
Fitch, Inc. (Fitch). We cannot assure you that these ratings, or the credit
ratings set forth below in "-- Impact on Liquidity of a Downgrade in 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 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.
Securities Registered with the SEC. At June 30, 2005, CenterPoint Energy
had a shelf registration statement covering senior debt securities, preferred
stock and common stock aggregating $1 billion and CERC Corp. had a shelf
registration statement covering $50 million principal amount of debt securities.
Temporary Investments. On June 30, 2005, we had temporary investments of
$366 million. CERC Corp.'s temporary external investments were reduced by $325
million in July 2005 when the proceeds from the liquidation of such investments
were used to pay maturing debt of CERC Corp. As of August 1, 2005, CERC Corp.
had temporary investments in a money market fund of $9 million. Such investments
may be utilized to meet the cash flow needs of CERC Corp.
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 net funding requirements of the money pool are expected to be met
with borrowings under CenterPoint Energy's revolving credit facility.
The terms of the money pool are in accordance with requirements applicable
to registered public utility holding companies under the 1935 Act and under an
order from the SEC relating to our financing activities and those of our
subsidiaries on June 29, 2005 (June 2005 Financing Order). This order expires in
June 2008.
Impact on Liquidity of a Downgrade in Credit Ratings. On July 22, 2005,
Moody's upgraded certain of our credit ratings, including our senior unsecured
debt to Ba1 from Ba2. Moody's also upgraded the ratings of CERC
42
Corp., including its senior unsecured debt to Baa3 from Bal. These rating
actions concluded the review for possible upgrade that was initiated on March
24, 2005.
As of August 1, 2005, Moody's, S&P, and 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 Stable BBB- Negative BBB- Stable
CenterPoint Houston Senior Secured Debt (First
Mortgage Bonds)............................ Baa2 Stable BBB Negative BBB+ Stable
CERC Corp. Senior Debt........................ Baa3 Stable BBB Negative BBB Stable
----------
(1) A "stable" outlook from Moody's indicates that Moody's does not expect to
put the rating on review for an upgrade or downgrade within 18 months from
when the outlook was assigned or last affirmed.
(2) An S&P rating outlook assesses the potential direction of a long-term
credit rating over the intermediate to longer term.
(3) A "stable" outlook from Fitch encompasses a one-to-two-year horizon as to
the likely ratings direction.
A decline in credit ratings could increase borrowing costs under our $1
billion credit facility, CenterPoint Houston's $200 million credit facility and
its $1.31 billion credit facility and CERC's $400 million revolving credit
facility. A decline in credit ratings would also increase the interest rate on
long-term debt to be issued in the capital markets and would negatively impact
our ability to complete capital market transactions. If we were unable to
maintain an investment-grade rating from at least one rating agency, as a
registered public utility holding company we would be required to obtain further
approval from the SEC for any additional capital markets transactions as more
fully described in "-- Certain Contractual and Regulatory Limits on Ability to
Issue Securities, Borrow Money and Pay Dividends on Our Common Stock" below.
Additionally, a decline in credit ratings could increase cash collateral
requirements and reduce margins of our Natural Gas Distribution business
segment.
As described above under "-- Credit Facilities," our revolving credit
facility contains a "material adverse change" clause that could impact our
ability to make new borrowings under this facility. CenterPoint Houston's $200
million credit facility, CenterPoint Houston's $1.3 billion facility and CERC
Corp.'s $400 million credit facility do not contain material adverse change
clauses with respect to borrowings.
In September 1999, we issued 2.0% Zero-Premium Exchangeable Subordinated
Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. 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 Time Warner
Inc. (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 note holders
might decide to exchange their ZENS notes for cash. Funds for the payment of
cash upon exchange could be obtained from the sale of the shares of TW Common
that we own or from other sources. We own shares of TW Common equal to 100% of
the reference shares used to calculate our obligation to the holders of the ZENS
notes. ZENS note exchanges result in a cash outflow because deferred tax
liabilities related to the ZENS notes and TW Common shares become current tax
obligations when ZENS notes are exchanged and TW Common shares are sold.
CenterPoint Energy Services, Inc. (formerly CenterPoint Energy Gas
Services, Inc.) (CES), a wholly owned subsidiary of CERC Corp., provides
comprehensive natural gas sales and services to industrial and commercial
customers, electric generators and natural gas utilities throughout the central
United States. In order to hedge its exposure to natural gas prices, CES 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. We estimate
that as of June 30, 2005, unsecured credit limits extended to CES by
counterparties could aggregate $105 million; however, utilized credit capacity
is significantly lower. In addition, CERC and its subsidiaries purchase natural
gas under supply agreements that contain an aggregate credit threshold of $100
million based on CERC's S&P Senior Unsecured Long-Term Debt rating of BBB.
Upgrades and downgrades from this BBB rating will increase and decrease the
aggregate credit threshold accordingly.
43
Cross Defaults. Under our revolving credit 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 the indenture governing our senior notes, 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. As of August 1,
2005, we had issued five series of senior notes aggregating $1.4 billion in
principal amount under this indenture. A default by CenterPoint Energy would not
trigger a default under our subsidiaries' debt instruments or bank credit
facilities.
Other Factors that Could Affect Cash Requirements. In addition to the above
factors, our liquidity and capital resources could be affected by:
- cash collateral requirements that could exist in connection with
certain contracts, including gas purchases, gas price hedging and gas
storage activities of our Natural Gas Distribution 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 and
borrowings under credit facilities;
- various regulatory actions;
- the ability of RRI and its subsidiaries to satisfy their obligations
as the principal customers of CenterPoint Houston and in respect of
RRI's indemnity obligations to us and our subsidiaries; and
- various of the risks identified under "Risk Factors" beginning on page
51 in Item 5 of Part II of our Quarterly Report on Form 10-Q for the
period ended June 30, 2005 filed on August 8, 2005.
Certain Contractual and Regulatory Limits on Our Ability to Issue
Securities, Borrow Money and Pay Dividends on Our Common Stock. The secured term
loan and each of the credit facilities 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 65% and 60%,
respectively, and contain an EBITDA to interest covenant. Our $1 billion credit
facility contains a debt to EBITDA covenant and an EBITDA to interest covenant.
CenterPoint Houston's $1.31 billion and $200 million credit facilities also
contain an EBITDA to interest covenant.
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 and the ability of our regulated subsidiaries to issue debt
and equity securities without prior authorization, restricts the source of
dividend payments to current and retained earnings without prior authorization,
regulates sales and acquisitions of certain assets and businesses and governs
affiliated service, sales and construction contracts. On July 29, 2005 Congress
passed the Energy Act, which President Bush is expected to sign in early August.
Under that legislation, the 1935 Act is repealed six months after the enactment
of the Energy Act. After the effective date of repeal, we and our subsidiaries
will no longer be subject to restrictions imposed under the 1935 Act. Until the
repeal is effective, we and our subsidiaries remain subject to the provisions of
the 1935 Act and the terms of orders issued by the SEC under the 1935 Act. The
Energy Act transfers to the FERC certain functions performed by the SEC under
the 1935 Act, including the requirement that holding companies and their
subsidiaries maintain certain books and records and make them available for
review by FERC and, through FERC, to state regulatory authorities. The Energy
Act requires FERC to issue regulations to implement its jurisdiction under the
Energy Act. It is presently unknown what, if any, specific obligations under
those rules may be imposed on us and our subsidiaries as result of that
rulemaking.
The June 2005 Financing Order is effective until June 30, 2008. This order
establishes limits on the amount of external debt and equity securities that can
be issued by us and our regulated subsidiaries without additional authorization
but generally permits us to refinance our existing obligations and those of our
regulated subsidiaries. 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. The order also generally permits
utilization of undrawn
44
credit facilities at CenterPoint Energy, CenterPoint Houston and CERC. However,
due to the restrictions contained in the order regarding our equity level as
described below, we may be unable to draw the full amount of our credit
agreement for other than refinancing purposes without further authorization from
the SEC. We do not expect this limitation to constrain our borrowings beyond the
end of 2005 based on current projections. Unless we obtain a further order from
the SEC, as of July 31, 2005:
- We are not authorized to issue any additional debt or preferred
securities;
- CenterPoint Houston is authorized to issue an aggregate $16 million of
debt or preferred securities; and
- CERC is authorized to issue an additional $367 million of debt or
preferred securities.
In the June 2005 Financing Order, the SEC "reserved jurisdiction" over a
number of matters, meaning that an order will be required from the SEC before we
may conduct those activities. However, an order regarding the activities over
which the SEC has reserved jurisdiction generally can be issued by the SEC more
quickly than orders on other matters, although there is no assurance that a
release of jurisdiction will be granted on a given matter or the terms under
which such an order may be issued. In the June 2005 Financing Order, the SEC
reserved jurisdiction over all authority otherwise granted if our common equity
ratio falls below its level as of March 31, 2005 (11.4%, net of securitization
debt) or if the common equity ratio of either CERC or CenterPoint Houston (net
of securitization debt) falls below 30%. Among the other transactions over which
the SEC reserved jurisdiction are: (i) issuance of securities by us or any of
our subsidiaries unless our and the issuer's other securities which are rated
have an investment grade rating from at least one nationally recognized
statistical rating organization, (ii) further investment in inactive
subsidiaries and (iii) payment of dividends by us from capital or unearned
surplus. The June 2005 Financing Order also contains certain requirements for
interest rates, maturities, issuance expenses and use of proceeds in connection
with securities issued by us or any of our subsidiaries. So long as our common
equity is less than 30% of our capitalization, the SEC also reserved
jurisdiction over the use of proceeds from authorized financings for the
acquisition of additional energy-related or gas-related companies. Finally, the
SEC reserved jurisdiction over the issuance of $500 million in incremental debt
by each of us, CenterPoint Houston and CERC. The total authorized amount of debt
and preferred securities that could be outstanding during the authorization
period, including the amounts over which the SEC has reserved jurisdiction and
undrawn amounts under revolving credit facilities, are: $4.334 billion for us,
$4.280 billion for CenterPoint Houston and $3.256 billion for CERC. The
foregoing and the following restrictions contained in the June 2005 Financing
Order, along with other restrictions contained in that order, will cease to
apply to us on the effective date of repeal of the 1935 Act.
The 1935 Act limits the payment of dividends to payment from current and
retained earnings unless specific authorization is obtained to pay dividends
from other sources. As discussed above, the SEC has reserved jurisdiction over
payment of $300 million of dividends from CenterPoint Energy's unearned surplus
or capital. Further authorization would be required to make those payments. As
of June 30, 2005, we had an accumulated deficit on our Condensed Consolidated
Balance Sheet. On January 26, 2005, our board of directors declared a dividend
of $0.10 per share of common stock payable on March 10, 2005 to shareholders of
record as of the close of business on February 16, 2005. On March 3, 2005, our
board of directors declared a dividend of $0.10 per share of common stock
payable on March 31, 2005 to shareholders of record as of the close of business
on March 16, 2005. This additional first quarter dividend was declared in lieu
of the regular second quarter dividend to address technical restrictions that
might have limited our ability to pay a regular dividend during the second
quarter of this year. Due to the limitations imposed under the 1935 Act, we may
declare and pay dividends only from earnings in the specific quarter in which
the dividend is paid, absent specific authorization from the SEC approving
payment of the quarterly dividend from capital or unearned surplus. There can be
no assurance, however, that the SEC would authorize such payments. As a result
of the seasonal nature of our utility businesses, the first quarter is generally
the strongest quarter for our gas distribution business. On June 2, 2005, our
board of directors declared a dividend of $0.07 per share of common stock
payable on June 30, 2005 to shareholders of record as of the close of business
on June 15, 2005. Although dividends are subject to consideration and approval
of our Board of Directors, subject to the Board's determination, we currently
intend to pay a 2005 annual dividend of $0.40 per share in keeping with our
historic levels and subject to remaining in compliance with the dividend payment
limitations imposed under the 1935 Act.
In addition, the SEC generally expects registered holding companies to
achieve a ratio of common equity to total capitalization of 30%. At June 30,
2005, our ratio was 13% (excluding transition bonds). Accordingly, we may issue
equity and take other actions to achieve a future equity capitalization of 30%.
The June 2005 Financing Order also requires that CenterPoint Houston and CERC
maintain a ratio of common equity to total capitalization of 30%,
45
although the SEC has permitted the percentage to be below this level for other
companies taking into account non-recourse securitization debt as a component of
capitalization. At June 30, 2005, their ratios were 43% (excluding transition
bonds) and 53%, respectively.
Other Factors Affecting the Upstreaming of Cash from Subsidiaries.
CenterPoint Houston's term loan, subject to certain exceptions, limits the
application of proceeds, in excess of $200 million, from capital markets
transactions and certain other borrowing transactions by CenterPoint Houston to
repayment of debt existing in November 2002.
CenterPoint Houston plans to distribute recovery of the true-up components
not used to repay CenterPoint Houston's indebtedness to us through the payment
of dividends. CenterPoint Houston requires SEC action to approve any dividends
in excess of its current and retained earnings. To maintain CenterPoint
Houston's capital structure at the appropriate levels, we may reinvest funds in
CenterPoint Houston in the form of equity contributions or intercompany loans.
CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one that is both important to the
presentation of our financial condition and results of operations and requires
management to make difficult, subjective or complex accounting estimates. An
accounting estimate is an approximation made by management of a financial
statement element, item or account in the financial statements. Accounting
estimates in our historical consolidated financial statements measure the
effects of past business transactions or events, or the present status of an
asset or liability. The accounting estimates described below require us to make
assumptions about matters that are highly uncertain at the time the estimate is
made. Additionally, different estimates that we could have used or changes in an
accounting estimate that are reasonably likely to occur could have a material
impact on the presentation of our financial condition or results of operations.
The circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be predicted with certainty. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes. Our significant accounting policies are discussed in Note 2 to our
consolidated financial statements in Amendment No. 2 to the CenterPoint Energy
Form 10-K filed on January 10, 2006. We believe the following accounting
policies involve the application of critical accounting estimates. Accordingly,
these accounting estimates have been reviewed and discussed with the audit
committee of the board of directors.
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. Significant accounting estimates embedded within the application of
SFAS No. 71 with respect to our Electric Transmission & Distribution business
segment relate to $2.1 billion of recoverable electric generation-related
regulatory assets as of June 30, 2005. These costs are recoverable under the
provisions of the Texas electric restructuring law. Based on our analysis of the
True-Up Order, we recorded an after-tax charge to earnings in 2004 of
approximately $977 million to write-down our electric generation-related
regulatory assets to their realizable value, which was reflected as an
extraordinary loss. Based on subsequent orders received from the Texas Utility
Commission, we recorded an extraordinary gain of $30 million after-tax in the
second quarter of 2005.
46
IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES
We review the carrying value of our long-lived assets, including goodwill
and identifiable intangibles, whenever events or changes in circumstances
indicate that such carrying values may not be recoverable, and at least annually
for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible
Assets." No impairment of goodwill was indicated based on our analysis as of
January 1, 2005. Unforeseen events and changes in circumstances and market
conditions and material differences in the value of long-lived assets and
intangibles due to changes in estimates of future cash flows, regulatory matters
and operating costs could negatively affect the fair value of our assets and
result in an impairment charge.
Fair value is the amount at which the asset could be bought or sold in a
current transaction between willing parties and may be estimated using a number
of techniques, including quoted market prices or valuations by third parties,
present value techniques based on estimates of cash flows, or multiples of
earnings or revenue performance measures. The fair value of the asset could be
different using different estimates and assumptions in these valuation
techniques.
UNBILLED 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 electricity 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. As additional information
becomes available, or actual amounts are determinable, the recorded estimates
are revised. Consequently, operating results can be affected by revisions to
prior accounting estimates.
PENSION AND OTHER RETIREMENT PLANS
We sponsor pension and other retirement plans in various forms covering all
employees who meet eligibility requirements. We use several statistical and
other factors which attempt to anticipate future events in calculating the
expense and liability related to our plans. These factors include assumptions
about the discount rate, expected return on plan assets and rate of future
compensation increases as estimated by management, within certain guidelines. In
addition, our actuarial consultants use subjective factors such as withdrawal
and mortality rates to estimate these factors. The actuarial assumptions used
may differ materially from actual results due to changing market and economic
conditions, higher or lower withdrawal rates or longer or shorter life spans of
participants. These differences may result in a significant impact to the amount
of pension expense recorded. Please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations-- Other Significant Matters --
Pension Plan" in Item 7 of the CenterPoint Energy Form 10-K, which is
incorporated herein by reference, for further discussion.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 4 to the Interim Financial Statements for a discussion of new
accounting pronouncements that affect us.
ITEM 4. CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we have
re-evaluated, under the supervision and with the participation of management,
including our principal executive officer and principal financial officer, the
effectiveness of our disclosure controls and procedures (as such term is defined
in Rule 13(a)-15(e) under the Securities Exchange Act of 1934, as amended) 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,
solely because of the material weakness described below, our disclosure controls
and procedures were not effective as of June 30, 2005. This conclusion is
different than the conclusion disclosed in the original filing of our Quarterly
Report on Form 10-Q
47
for the period ended June 30, 2005 in which management concluded that our
disclosure controls and procedures were effective. As a result of the material
weakness described below, which was identified subsequent to the original filing
of our Quarterly Report on Form 10-Q for the period ended June 30, 2005,
management has re-evaluated the effectiveness of our disclosure controls and
procedures.
We determined that, during 2004 and 2005, certain transactions involving
purchases and sales of natural gas among divisions within our Natural Gas
Distribution segment were not properly eliminated in the consolidated financial
statements. Consequently, revenues and natural gas expenses during the three and
six months ended June 30, 2004 were each overstated by approximately $107
million and $233 million, respectively. For the three and six months ended June
30, 2005, revenues and natural gas expenses were each overstated by
approximately $90 million and $257 million, respectively, for the same reason
and management concluded that a restatement of the consolidated financial
statements for the three and six months ended June 30, 2004 and 2005 was
necessary to correct this error. Subsequent to the period covered by this
report, in connection with the discovery of the error described above and the
conclusion that we had a material weakness in our internal control over
financial reporting related to ineffective controls over the process of
eliminating certain interdivision purchases and sales of natural gas within our
Natural Gas Distribution segment in the consolidation process, we improved
procedures related to the recording and reporting of purchases and sales of
natural gas, including increased review and approval controls by senior
financial personnel over the personnel that will prepare the accruals and
enhanced analysis of the recorded activity, including ensuring that intercompany
activity is properly eliminated in consolidation.
There has been no change in our internal control over financial reporting
that occurred during the three months ended June 30, 2005 that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting. However, subsequent to the date of filing our original
Quarterly Report on Form 10-Q for the period ended June 30, 2005, we took the
remedial action described above.
48
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
The following exhibits are filed herewith:
Exhibits included with this report are designated by a cross (+); exhibits
previously filed with our Quarterly Report on Form 10-Q for the period ended
June 30, 2005 as filed on August 8, 2005 are designated by two crosses (++); 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
------- ------------------------------- -------------------------------------- ------------ ---------
3.1.1 -- Amended and Restated Articles CenterPoint Energy's Registration 3-69502 3.1
of Incorporation of CenterPoint Statement on Form S-4
Energy
3.1.2 -- Articles of Amendment to CenterPoint Energy's Form 10-K for the 1-31447 3.1.1
Amended and Restated Articles year ended December 31, 2001
of Incorporation of CenterPoint
Energy
3.2 -- Amended and Restated Bylaws of CenterPoint Energy's Form 10-K for the 1-31447 3.2
CenterPoint Energy year ended December 31, 2001
3.3 -- 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 CenterPoint Energy's Registration 3-69502 4.1
Stock Certificate Statement on Form S-4
4.2 -- Rights Agreement dated CenterPoint Energy's Form 10-K for the 1-31447 4.2
January 1, 2002, between year ended December 31, 2001
CenterPoint Energy and JPMorgan
Chase Bank, as Rights Agent
Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy
has not filed as exhibits to this Form 10-Q certain long-term debt instruments,
including indentures, under which the total amount of securities authorized does
not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on
a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any
such instrument to the SEC upon request.
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ------------------------------- -------------------------------------- ------------ ---------
4.3.1 -- $1,310,000,000 Credit Agreement CenterPoint Energy's Form 10-K for the 1-31447 4(g)(1)
dated as of November 12, 2002, year ended December 31, 2002
among CenterPoint Houston and
the banks named therein
4.3.2 -- First Amendment to CenterPoint Energy's Form 10-Q for the 1-31447 10.7
Exhibit 4.1.1, dated as of quarter ended September 30, 2003
September 3, 2003
4.3.3 -- Pledge Agreement, dated as of CenterPoint Energy's Form 10-K for the 1-31447 4(g)(2)
November 12, 2002 executed in year ended December 31, 2002
connection with Exhibit 4.1.1
4.4 -- $1,000,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.1
dated as of March 7, 2005, March 7, 2005
among CenterPoint Energy and
the banks named therein
4.5 -- $400,000,000 Credit Agreement, CenterPoint Energy's Form 8-K dated 1-31447 4.1
dated as of June 30, 2005, June 29, 2005
among CERC Corp., as Borrower,
and the Initial Lenders named
therein, as Initial Lenders
49
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ------------------------------- -------------------------------------- ------------ ---------
4.6 -- $200,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.2
dated as of March 7, 2005 among March 7, 2005
CenterPoint Houston and the
banks named therein
4.7 -- $1,310,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.3
dated as of March 7, 2005 among March 7, 2005
CenterPoint Houston and the
banks named therein
++10.1 -- City of Houston Franchise
Ordinance
+31.1 -- Rule 13a-14(a)/15d-14(a)
Certification of David M.
McClanahan
+31.2 -- Rule 13a-14(a)/15d-14(a)
Certification of Gary L.
Whitlock
+32.1 -- Section 1350 Certification of
David M. McClanahan
+32.2 -- Section 1350 Certification of
Gary L. Whitlock
++99.1 -- Eleventh Amendment to
CenterPoint Energy, Inc.
Retirement Plan, effective as
of May 1, 2005
++99.2 -- Twelfth Amendment to
CenterPoint Energy, Inc.
Retirement Plan, effective as
of June 1, 2005
++99.3 -- Items incorporated by reference
from the CenterPoint Energy
Form 10-K. Item 1
"Business--Regulation,"
"--Environmental Matters,"
Item 3 "Legal Proceedings,"
Item 7 "Management's Discussion
and Analysis of Financial
Condition and Results of
Operations--Certain Factors
Affecting Future Earnings" and
"--Other Significant
Matters--Pension Plan" and
Notes 2(d) (Long-Lived Assets
and Intangibles), 2(e)
(Regulatory Assets and
Liabilities), 4 (Regulatory
Matters), 5 (Derivative
Instruments), 6 (Indexed Debt
Securities (ZENS) and Time
Warner Securities) and 11
(Commitments and Contingencies)
50
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CENTERPOINT ENERGY, INC.
By: /s/ James S. Brian
------------------------------------
James S. Brian
Senior Vice President and Chief
Accounting Officer
Date: January 10, 2006
51
EXHIBIT INDEX
Exhibits included with this report are designated by a cross (+); exhibits
previously filed with our Quarterly Report on Form 10-Q for the period ended
June 30, 2005 as filed on August 8, 2005 are designated by two crosses (++); 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
------- ------------------------------- -------------------------------------- ------------ ---------
3.1.1 -- Amended and Restated Articles CenterPoint Energy's Registration 3-69502 3.1
of Incorporation of CenterPoint Statement on Form S-4
Energy
3.1.2 -- Articles of Amendment to CenterPoint Energy's Form 10-K for the 1-31447 3.1.1
Amended and Restated Articles year ended December 31, 2001
of Incorporation of CenterPoint
Energy
3.2 -- Amended and Restated Bylaws of CenterPoint Energy's Form 10-K for the 1-31447 3.2
CenterPoint Energy year ended December 31, 2001
3.3 -- 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 CenterPoint Energy's Registration 3-69502 4.1
Stock Certificate Statement on Form S-4
4.2 -- Rights Agreement dated CenterPoint Energy's Form 10-K for the 1-31447 4.2
January 1, 2002, between year ended December 31, 2001
CenterPoint Energy and JPMorgan
Chase Bank, as Rights Agent
Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy
has not filed as exhibits to this Form 10-Q certain long-term debt instruments,
including indentures, under which the total amount of securities authorized does
not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on
a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any
such instrument to the SEC upon request.
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ------------------------------- -------------------------------------- ------------ ---------
4.3.1 -- $1,310,000,000 Credit Agreement CenterPoint Energy's Form 10-K for the 1-31447 4(g)(1)
dated as of November 12, 2002, year ended December 31, 2002
among CenterPoint Houston and
the banks named therein
4.3.2 -- First Amendment to CenterPoint Energy's Form 10-Q for the 1-31447 10.7
Exhibit 4.1.1, dated as of quarter ended September 30, 2003
September 3, 2003
4.3.3 -- Pledge Agreement, dated as of CenterPoint Energy's Form 10-K for the 1-31447 4(g)(2)
November 12, 2002 executed in year ended December 31, 2002
connection with Exhibit 4.1.1
4.4 -- $1,000,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.1
dated as of March 7, 2005, March 7, 2005
among CenterPoint Energy and
the banks named therein
4.5 -- $400,000,000 Credit Agreement, CenterPoint Energy's Form 8-K dated 1-31447 4.1
dated as of June 30, 2005, June 29, 2005
among CERC Corp., as Borrower,
and the Initial Lenders named
therein, as Initial Lenders
4.6 -- $200,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.2
dated as of March 7, 2005 among March 7, 2005
CenterPoint Houston and the
banks named therein
4.7 -- $1,310,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.3
dated as of March 7, 2005 among March 7, 2005
CenterPoint Houston and the
banks named therein
++10.1 -- City of Houston Franchise
Ordinance
+31.1 -- Rule 13a-14(a)/15d-14(a)
Certification of David M.
McClanahan
+31.2 -- Rule 13a-14(a)/15d-14(a)
Certification of Gary L.
Whitlock
+32.1 -- Section 1350 Certification of
David M. McClanahan
+32.2 -- Section 1350 Certification of
Gary L. Whitlock
++99.1 -- Eleventh Amendment to
CenterPoint Energy, Inc.
Retirement Plan, effective as
of May 1, 2005
++99.2 -- Twelfth Amendment to
CenterPoint Energy, Inc.
Retirement Plan, effective as
of June 1, 2005
++99.3 -- Items incorporated by reference
from the CenterPoint Energy
Form 10-K. Item 1
"Business--Regulation,"
"--Environmental Matters,"
Item 3 "Legal Proceedings,"
Item 7 "Management's Discussion
and Analysis of Financial
Condition and Results of
Operations--Certain Factors
Affecting Future Earnings" and
"--Other Significant
Matters--Pension Plan" and
Notes 2(d) (Long-Lived Assets
and Intangibles), 2(e)
(Regulatory Assets and
Liabilities), 4 (Regulatory
Matters), 5 (Derivative
Instruments), 6 (Indexed Debt
Securities (ZENS) and Time
Warner Securities) and 11
(Commitments and Contingencies)