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 SEPTEMBER 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 _______________.
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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
incorporation or organization) Identification No.)
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 November 1, 2005, CenterPoint Energy, Inc. had 310,106,178 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 September 30, 2005 as originally filed on
November 3, 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 SEPTEMBER 30, 2005
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements........................................... 1
Condensed Statements of Consolidated Operations
Three Months and Nine Months Ended September 30, 2004 and 2005
(unaudited) (as restated)..................................... 1
Condensed Consolidated Balance Sheets
December 31, 2004 and September 30, 2005 (unaudited)
(as restated)................................................. 2
Condensed Statements of Consolidated Cash Flows
Nine Months Ended September 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................................... 32
Item 4. Controls and Procedures........................................ 49
PART II. OTHER INFORMATION
Item 6. Exhibits....................................................... 51
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 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 September 30, 2005 filed on November 3, 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 OPERATIONS
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------- ----------------
2004 2005 2004 2005
------- ------ ------- ------
(AS RESTATED, SEE NOTE 14)
REVENUES ..................................................... $ 1,567 $2,073 $ 5,562 $6,510
------- ------ ------- ------
EXPENSES:
Natural gas ............................................... 826 1,277 3,366 4,161
Operation and maintenance ................................. 319 336 932 974
Depreciation and amortization ............................. 126 145 362 411
Taxes other than income taxes ............................. 89 90 269 277
------- ------ ------- ------
Total .................................................. 1,360 1,848 4,929 5,823
------- ------ ------- ------
OPERATING INCOME ............................................. 207 225 633 687
------- ------ ------- ------
OTHER INCOME (EXPENSE):
Gain (loss) on Time Warner investment ..................... (31) 30 (40) (29)
Gain (loss) on indexed debt securities .................... 34 (29) 43 34
Interest and other finance charges ........................ (183) (168) (554) (521)
Interest on transition bonds .............................. (9) (9) (29) (27)
Return on true-up balance ................................. -- 35 -- 104
Other, net ................................................ 1 7 15 18
------- ------ ------- ------
Total .................................................. (188) (134) (565) (421)
------- ------ ------- ------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM ........................................ 19 91 68 266
Income Tax Expense ........................................ (2) (41) (25) (122)
------- ------ ------- ------
INCOME FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM .. 17 50 43 144
DISCONTINUED OPERATIONS:
Income from Texas Genco, net of tax ....................... 109 -- 241 11
Minority Interest in Income from Texas Genco ........... (22) -- (49) --
Loss on Disposal of Texas Genco, net of tax ............... (346) -- (346) (14)
------- ------ ------- ------
Total .................................................. (259) -- (154) (3)
------- ------ ------- ------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM ...................... (242) 50 (111) 141
EXTRAORDINARY ITEM, NET OF TAX ............................... (894) -- (894) 30
------- ------ ------- ------
NET INCOME (LOSS) ............................................ $(1,136) $ 50 $(1,005) $ 171
======= ====== ======= ======
BASIC EARNINGS PER SHARE:
Income from Continuing Operations ......................... $ 0.05 $ 0.16 $ 0.14 $ 0.46
Discontinued Operations, net of tax ....................... (0.84) -- (0.50) (0.01)
Extraordinary Item, net of tax ............................ (2.90) -- (2.91) 0.10
------- ------ ------- ------
Net Income (Loss) ......................................... $ (3.69) $ 0.16 $ (3.27) $ 0.55
======= ====== ======= ======
DILUTED EARNINGS PER SHARE:
Income from Continuing Operations ......................... $ 0.05 $ 0.15 $ 0.14 $ 0.43
Discontinued Operations, net of tax ....................... (0.83) -- (0.50) (0.01)
Extraordinary Item, net of tax ............................ (2.88) -- (2.89) 0.09
------- ------ ------- ------
Net Income (Loss) ......................................... $ (3.66) $ 0.15 $ (3.25) $ 0.51
======= ====== ======= ======
See Notes to the Company's Interim Financial Statements
1
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS OF DOLLARS)
(UNAUDITED)
ASSETS
DECEMBER 31, SEPTEMBER 30,
2004 2005
------------ -------------
(AS RESTATED,
SEE NOTE 14)
CURRENT ASSETS:
Cash and cash equivalents ....................... $ 165 $ 162
Investment in Time Warner common stock .......... 421 392
Accounts receivable, net ........................ 674 661
Accrued unbilled revenues ....................... 576 313
Natural gas inventory ........................... 176 317
Materials and supplies .......................... 78 88
Non-trading derivative assets ................... 50 195
Current assets of discontinued operations ....... 514 --
Prepaid expenses ................................ 21 18
Other current assets ............................ 96 240
------- -------
Total current assets ......................... 2,771 2,386
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment ................... 10,963 11,323
Less accumulated depreciation and amortization .. (2,777) (2,962)
------- -------
Property, plant and equipment, net ........... 8,186 8,361
------- -------
OTHER ASSETS:
Goodwill, net ................................... 1,741 1,744
Other intangibles, net .......................... 58 56
Regulatory assets ............................... 3,350 2,943
Non-trading derivative assets ................... 18 108
Non-current assets of discontinued operations ... 1,051 --
Other ........................................... 921 838
------- -------
Total other assets ........................... 7,139 5,689
------- -------
TOTAL ASSETS ................................. $18,096 $16,436
======= =======
See Notes to the Company's Interim Financial Statements
2
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS - (CONTINUED)
(MILLIONS OF DOLLARS)
(UNAUDITED)
LIABILITIES AND SHAREHOLDERS' EQUITY
DECEMBER 31, SEPTEMBER 30,
2004 2005
------------ -------------
(AS RESTATED,
SEE NOTE 14)
CURRENT LIABILITIES:
Current portion of transition bond long-term debt .................... $ 47 $ 54
Current portion of other long-term debt .............................. 1,789 2,004
Indexed debt securities derivative ................................... 342 307
Accounts payable ..................................................... 802 769
Taxes accrued ........................................................ 609 174
Interest accrued ..................................................... 151 143
Non-trading derivative liabilities ................................... 26 89
Regulatory liabilities ............................................... 225 --
Accumulated deferred income taxes, net ............................... 261 366
Current liabilities of discontinued operations ....................... 449 --
Other ................................................................ 420 692
------- -------
Total current liabilities ......................................... 5,121 4,598
------- -------
OTHER LIABILITIES:
Accumulated deferred income taxes, net ............................... 2,415 2,480
Unamortized investment tax credits ................................... 54 48
Non-trading derivative liabilities ................................... 6 14
Benefit obligations .................................................. 440 457
Regulatory liabilities ............................................... 1,082 749
Non-current liabilities of discontinued operations ................... 420 --
Other ................................................................ 259 378
------- -------
Total other liabilities ........................................... 4,676 4,126
------- -------
LONG-TERM DEBT:
Transition bonds ..................................................... 629 575
Other ................................................................ 6,564 5,919
------- -------
Total long-term debt .............................................. 7,193 6,494
------- -------
COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 11)
SHAREHOLDERS' EQUITY:
Common stock (308,045,215 shares and 310,069,770 shares outstanding at
December 31, 2004 and September 30, 2005, respectively) ........... 3 3
Additional paid-in capital ........................................... 2,891 2,917
Accumulated deficit .................................................. (1,727) (1,661)
Accumulated other comprehensive loss ................................. (61) (41)
------- -------
Total shareholders' equity ........................................ 1,106 1,218
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ..................... $18,096 $16,436
======= =======
See Notes to the Company's Interim Financial Statements
3
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(MILLIONS OF DOLLARS)
(UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2004 2005
------- -----
(AS RESTATED, SEE NOTE 14)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ......................................................... $(1,005) $ 171
Discontinued operations, net of tax ....................................... 154 3
Extraordinary item, net of tax ............................................ 894 (30)
------- -----
Income from continuing operations ......................................... 43 144
Adjustments to reconcile income from continuing operations to net cash
provided by operating activities:
Depreciation and amortization .......................................... 362 411
Amortization of deferred financing costs ............................... 63 59
Deferred income taxes .................................................. 105 162
Investment tax credit .................................................. (6) (6)
Unrealized loss on Time Warner investment .............................. 40 29
Unrealized gain on indexed debt securities ............................. (43) (34)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net ...................... 336 316
Inventory ........................................................... (80) (140)
Accounts payable .................................................... (183) (28)
Fuel cost over (under) recovery/surcharge ........................... 43 (69)
Non-trading derivatives, net ........................................ (19) 8
Margin deposits, net ................................................ 15 78
Short-term risk management activities, net .......................... 1 (19)
Interest and taxes accrued .......................................... (28) (440)
Excess tax deduction related to share-based payment arrangements .... -- (3)
Net regulatory assets and liabilities ............................... (253) (166)
Other current assets ................................................ (18) (39)
Other current liabilities ........................................... (2) 8
Other assets ........................................................ (12) (2)
Other liabilities ................................................... (41) 37
Other, net ............................................................. 19 7
------- -----
Net cash provided by operating activities of continuing operations .. 342 313
Net cash provided by (used in) operating activities of
discontinued operations .......................................... 411 (38)
------- -----
Net cash provided by operating activities ........................... 753 275
------- -----
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ...................................................... (405) (506)
Proceeds from sale of Texas Genco ......................................... -- 700
Decrease in restricted cash of Texas Genco ................................ -- 383
Purchase of minority interest in Texas Genco .............................. -- (383)
Decrease (increase) in cash of Texas Genco ................................ (292) 24
Other, net ................................................................ 6 --
------- -----
Net cash provided by (used in) investing activities ................. (691) 218
------- -----
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings, net ......................... (63) 75
Long-term revolving credit facilities, net ................................ 358 (239)
Proceeds from commercial paper, net ....................................... -- 187
Proceeds from long-term debt .............................................. 229 --
Payments of long-term debt ................................................ (545) (424)
Debt issuance costs ....................................................... (14) (7)
Payment of common stock dividends ......................................... (92) (105)
Payment of common stock dividends by subsidiary ........................... (11) --
Proceeds from issuance of common stock, net ............................... 9 14
Excess tax deduction related to share-based payment arrangements .......... -- 3
------- -----
Net cash used in financing activities ............................... (129) (496)
------- -----
NET DECREASE IN CASH AND CASH EQUIVALENTS .................................... (67) (3)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ............................. 87 165
------- -----
CASH AND CASH EQUIVALENTS AT END OF PERIOD ................................... $ 20 $ 162
======= =====
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest .................................................................. $ 572 $ 515
Income taxes (refunds) .................................................... (17) 464
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 August 8, 2005,
President Bush signed into law the Energy Policy Act of 2005 (Energy Act). Under
that legislation, the 1935 Act is repealed effective February 8, 2006. After the
effective date of the 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 grants to the Federal Energy
Regulatory Commission (FERC) authority to require holding companies and their
subsidiaries to maintain certain books and records and make them available for
review by FERC and state regulatory authorities. The Energy Act requires FERC to
issue regulations to implement its jurisdiction under the Energy Act, and on
September 16, 2005, FERC issued proposed rules for public comment. It is
presently unknown what, if any, specific obligations under those rules may be
imposed on the Company and its subsidiaries as a 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
September 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 two unincorporated divisions: Minnesota Gas and
Southern Gas Operations, which includes Houston Gas. 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. Texas Genco owned and operated additional generating
facilities during most of 2004. 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, results of operations and cash flows for the respective
periods. Amounts reported in the Company's Condensed Statements of Consolidated
Operations 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 an after-tax loss of $259 million and $154 million for
the three and nine months ended September 30, 2004, respectively, related to the
operations of Texas Genco. The Company recorded an after-tax loss of $3 million
for the nine months ended September 30, 2005. General corporate overhead,
previously allocated to Texas Genco from the Company, was $5 million and $15
million for the three and nine months ended September 30, 2004, respectively,
and was less than $1 million for the nine months ended September 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 Texas Genco's operations as discontinued operations in
accordance with SFAS No. 144. Interest expense of $14 million and $38 million
for the three and nine months ended September 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 nine months ended September 30, 2004 were $638 million and $1.6
billion, respectively. Revenues for the nine months ended September 30, 2005
were $62 million. Loss from these discontinued operations for the three and nine
months ended September 30, 2004 is reported net of income tax benefit of $164
million and $94 million, respectively. Income from these discontinued operations
for the nine months ended September 30, 2005 is reported net of income tax
expense of $4 million.
(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 is 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 option 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 nine
months ended September 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 adopted 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 $6 million
for the three and nine months ended September 30, 2004, respectively. LICP
compensation expense for the three and nine months ended September 30, 2005 was
$4 million and $10 million, respectively.
The total income tax benefit recognized related to such arrangements was
less than $1 million and $2 million for the three and nine months ended
September 30, 2004, respectively. Income tax benefit for the three and nine
months ended September 30, 2005 was $2 million and $4 million, respectively. No
compensation cost was capitalized as a part of inventory and fixed assets in
either of the three or nine months ended September 30, 2004 and 2005.
Pro forma information for the three and nine months ended September 30,
2004 is provided to show the effect of amortizing 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 ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2004 SEPTEMBER 30, 2004
------------------ ------------------
Net Income (Loss):
As reported ............................................... $(1,136) $(1,005)
Add: stock-based compensation as recorded ................. 1 4
Less: total stock-based employee compensation determined
under the fair value based method ...................... (2) (7)
------- -------
Pro forma ................................................. $(1,137) $(1,008)
======= =======
Basic Earnings Per Share:
As reported ............................................... $ (3.69) $ (3.27)
Pro forma ................................................. (3.70) (3.28)
Diluted Earnings Per Share:
As reported ............................................... (3.66) (3.25)
Pro forma ................................................. (3.67) (3.26)
The following tables summarize the methods used to measure compensation
cost for the various types of awards granted under the LICPs:
7
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 nine months ended September 30, 2005:
STOCK OPTIONS
OUTSTANDING OPTIONS
THREE MONTHS ENDED
SEPTEMBER 30, 2005
------------------------------
SHARES WEIGHTED-AVERAGE
(THOUSANDS) EXERCISE PRICE
----------- ----------------
Outstanding at June 30, 2005 ....... 14,888 $15.78
Canceled ........................ (303) 19.03
Exercised ....................... (503) 7.71
------
Outstanding at September 30, 2005 .. 14,082 16.00
======
NON-VESTED OPTIONS
THREE MONTHS ENDED
SEPTEMBER 30, 2005
------------------------------
WEIGHTED-AVERAGE
SHARES GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------------
Outstanding at June 30, 2005 ....... 4,032 $1.76
Vested .......................... -- --
Canceled ........................ -- --
-----
Outstanding at September 30, 2005 .. 4,032 1.76
=====
OUTSTANDING OPTIONS
NINE MONTHS ENDED SEPTEMBER 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 ........................ (966) 16.78
Exercised ....................... (1,111) 6.97
------
Outstanding at September 30, 2005 .. 14,082 16.00 4.4 $39
======
Exercisable at September 30, 2005 .. 12,127 17.04 3.9 28
======
8
NON-VESTED OPTIONS
NINE MONTHS ENDED SEPTEMBER 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 September 30, 2005 .. 4,032 1.76
======
PERFORMANCE SHARES
OUTSTANDING AND NON-VESTED SHARES
THREE MONTHS ENDED SEPTEMBER 30, 2005
-------------------------------------
SHARES WEIGHTED-AVERAGE GRANT
(THOUSANDS) DATE FAIR VALUE
----------- ----------------------
Outstanding at June 30, 2005 ............ 1,587 $9.27
Granted .............................. -- --
Canceled ............................. (27) 5.64
Vested and released to participants .. -- --
----- -----
Outstanding at September 30, 2005 ....... 1,560 9.33
=====
OUTSTANDING SHARES
NINE MONTHS ENDED SEPTEMBER 30, 2005
--------------------------------------
REMAINING
AVERAGE AGGREGATE
CONTRACTUAL INTRINSIC
SHARES LIFE VALUE
(THOUSANDS) (YEARS) (MILLIONS)
----------- ----------- ----------
Outstanding at December 31, 2004 ........ 1,169
Granted .............................. 945
Canceled ............................. (181)
Vested and released to participants .. (373)
-----
Outstanding at September 30, 2005 ....... 1,560 1.4 $19
=====
NON-VESTED SHARES
NINE MONTHS ENDED SEPTEMBER 30, 2005
------------------------------------
WEIGHTED-AVERAGE
SHARES GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------------
Outstanding at December 31, 2004 ........ 756 $ 5.70
Granted .............................. 945 12.13
Canceled ............................. (121) 9.17
Vested and released to participants .. (20) 5.64
-----
Outstanding at September 30, 2005 ....... 1,560 9.33
=====
The non-vested and outstanding shares displayed in the above tables assume
that shares are issued at the maximum performance level (150%). 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 SEPTEMBER 30, 2005
-------------------------------------
UNITS WEIGHTED-AVERAGE GRANT
(THOUSANDS) DATE FAIR VALUE
----------- ----------------------
Outstanding at June 30, 2005 ............ 35 $100.00
Canceled ............................. (1) --
Vested and released to participants .. -- --
---
Outstanding at September 30, 2005 ....... 34 100.00
===
9
OUTSTANDING AND NON-VESTED UNITS
NINE MONTHS ENDED SEPTEMBER 30, 2005
---------------------------------------------------------
REMAINING
AVERAGE AGGREGATE
WEIGHTED-AVERAGE CONTRACTUAL INTRINSIC
UNITS GRANT DATE LIFE VALUE
(THOUSANDS) FAIR VALUE (YEARS) (MILLIONS)
----------- ---------------- ----------- ----------
Outstanding at December 31, 2004 ........ 37 $100.00
Canceled ............................. (2) 100.00
Vested and released to participants .. (1) 100.00
---
Outstanding at September 30, 2005 ....... 34 100.00 1.3 $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 SEPTEMBER 30, 2005
-------------------------------------
SHARES WEIGHTED-AVERAGE GRANT
(THOUSANDS) DATE FAIR VALUE
----------- ----------------------
Outstanding at June 30, 2005 ............ 974 $ 8.72
Granted .............................. 30 13.34
Canceled ............................. (27) 7.27
Vested and released to participants .. (8) 10.98
---
Outstanding at September 30, 2005 ....... 969 8.89
===
OUTSTANDING AND NON-VESTED SHARES
NINE MONTHS ENDED SEPTEMBER 30, 2005
---------------------------------------------------------
REMAINING
AVERAGE AGGREGATE
WEIGHTED-AVERAGE CONTRACTUAL INTRINSIC
SHARES GRANT DATE LIFE VALUE
(THOUSANDS) FAIR VALUE (YEARS) (MILLIONS)
----------- ---------------- ----------- ----------
Outstanding at December 31, 2004 ........ 769 $ 7.49
Granted .............................. 307 12.25
Canceled ............................. (70) 8.79
Vested and released to participants .. (37) 7.82
---
Outstanding at September 30, 2005 ....... 969 8.89 1.2 $14
===
The weighted-average grant-date fair values of awards granted were as
follows for the three and nine months ended September 30, 2004 and 2005:
THREE MONTHS
ENDED
SEPTEMBER 30,
---------------
2004 2005
------ ------
Options ...................... $ -- $ --
Performance units ............ -- --
Performance shares ........... -- --
Time-based restricted stock .. 11.42 13.34
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------
2004 2005
------- ------
Options ...................... $ 1.86 $ --
Performance units ............ 100.00 --
Performance shares ........... -- 12.13
Time-based restricted stock .. 10.94 12.25
10
The total intrinsic value of awards received by participants were as
follows for the three and nine months ended September 30, 2004 and 2005:
THREE MONTHS ENDED SEPTEMBER 30,
--------------------------------
2004 2005
---- ----
(IN MILLIONS)
Options exercised................. $1 $3
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2004 2005
---- ----
(IN MILLIONS)
Options exercised................. $3 $7
Performance shares................ 7 5
As of September 30, 2005, there was $16 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 1.7 years.
Cash received from LICPs was less than $1 million and $3 million for the
three and nine months ended September 30, 2004, respectively. Cash received from
LICPs was $4 million and $8 million for the three and nine months ended
September 30, 2005, respectively.
The actual tax benefit realized for tax deductions related to LICPs totaled
less than $1 million and $4 million for the three and nine months ended
September 30, 2004, respectively. Tax benefits realized for the three and nine
months ended September 30, 2005 were $1 million and $5 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.
(b) Employee Benefit Plans.
The Company's net periodic cost includes the following components relating
to pension and postretirement benefits:
THREE MONTHS ENDED SEPTEMBER 30,
-----------------------------------------------------
2004 2005
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
Service cost ..................... $ 10 $ 1 $ 9 $ 1
Interest cost .................... 26 8 24 6
Expected return on plan assets ... (26) (4) (34) (3)
Net amortization ................. 9 4 9 2
Curtailment ...................... -- 17 -- 1
---- ---- ---- ---
Net periodic cost ................ $ 19 $ 26 $ 8 $ 7
==== ==== ==== ===
NINE MONTHS ENDED SEPTEMBER 30,
-----------------------------------------------------
2004 2005
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
Service cost ..................... $ 30 $ 3 $ 26 $ 2
Interest cost .................... 77 24 72 20
Expected return on plan assets ... (78) (10) (103) (9)
Net amortization ................. 28 10 28 7
Curtailment ...................... -- 17 -- 1
Other ............................ 3 2 -- --
---- ---- ----- ----
Net periodic cost ................ $ 60 $ 46 $ 23 $ 21
==== ==== ===== ====
Included in the net periodic cost for the three and nine months ended
September 30, 2004 is $20 million and $28 million, respectively, of expense
related to Texas Genco's participants, which is reflected in discontinued
operations in the Statements of Consolidated Operations.
11
Contributions to the pension plan are not required in 2005; however, the
Company may make a contribution in an amount that would insure that plan assets
exceed the accumulated benefit obligation at December 31, 2005. The Company
expects that it will contribute $23 million to its postretirement benefits plan
in 2005. As of September 30, 2005, $17 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 was $2 million for each of the three months ended
September 30, 2004 and 2005, respectively, and $5 million for each of the nine
months ended September 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 is evaluating the effect of adoption of
this new standard on its financial position, results of operations and cash
flows.
(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. CenterPoint Houston and other parties filed appeals of the True-Up
Order to a district court in Travis County, Texas. That court held a hearing on
the appeal in early August 2005, and on August 26, 2005, the court issued its
final judgment on the various appeals. In its judgment, the court affirmed most
aspects of the Texas Utility Commission's order, but reversed two of the Texas
Utility Commission's rulings, which would have the effect of restoring
approximately $620 million, plus interest, of the $1.7 billion the Texas Utility
Commission had disallowed from CenterPoint Houston's initial request. First, the
court reversed the Texas Utility Commission's decision to prohibit CenterPoint
Houston from recovering $180 million in credits through August 2004 that
CenterPoint Houston was ordered to provide to retail electric providers as a
result of a stranded cost estimate made by the Texas Utility Commission in 2000
that subsequently proved to be inaccurate. Second, the court reversed the Texas
Utility Commission's disallowance of $440 million in transition costs which are
recoverable under the Texas Utility Commission's regulations. Additional credits
of approximately $30 million paid after August 2004 and interest would be added
to these amounts. CenterPoint Houston and other parties appealed the district
court decision to the 3rd Court of Appeals in Austin in September 2005. The
parties have agreed to a briefing schedule whereby briefs will be filed by the
parties on a schedule extending into February 2006. No amounts related to the
court's judgment have been recorded in the Company's consolidated financial
statements.
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
approximately $1.8 billion of
12
transition bonds. In August 2005, the same Travis County District Court
considering the appeal of the True-Up Order affirmed the financing order in all
respects. CenterPoint Houston expects to complete the issuance of transition
bonds under that order in the fourth quarter of 2005, subject to, among other
matters, market conditions and the completion of documentation and rating agency
reviews.
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%. 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. The CTC order also allows CenterPoint Houston to collect approximately
$24 million of rate case expenses over three years through a separate tariff
rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE
effective September 13, 2005 and began recovering approximately $600 million and
the rate case expenses. Certain other parties appealed the CTC order to the
Travis County Court on September 27, 2005. Additionally, during the period from
September 13, 2005, the date of implementation of the CTC order, through
September 30, 2005, CenterPoint Houston recognized approximately $7 million in
CTC revenue, which was partially offset by $5 million in related amortization of
the CTC regulatory asset.
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 $62 million
and $189 million for the three months and nine months ended September 30, 2005,
respectively. Effective September 13, 2005, the date of implementation of the
CTC order, the return on the CTC portion of the true-up balance is included in
CenterPoint Houston's tariff-based revenues. The debt return of $35 million and
$104 million for the three months and nine months ended September 30, 2005,
respectively, was accrued and included in other income in the Company's
Statements of Consolidated Operations. The debt return will continue to be
recognized as earned going forward. The equity return of $27 million and $85
million for the three months and nine months ended September 30, 2005,
respectively, will be recognized in income as it is recovered in the future. As
of September 30, 2005, the Company has recorded a regulatory asset of $331
million related to the debt return on its true-up balance and has not recorded
an allowed equity return of $232 million on its true-up balance because such
return will be recognized as it is recovered in the future.
Net income for the nine months ended September 30, 2005 included an
after-tax extraordinary gain of $30 million ($0.09 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 has
applied the remaining unrefunded excess mitigation credits of approximately $522
million to reduce the regulatory asset related to stranded costs.
(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 in June 2005. The parties are briefing the issues before the court.
13
(c) Rate Cases.
In November 2004, Southern Gas Operations filed an application for a $28
million base rate increase, as adjusted, with the Arkansas Public Service
Commission (APSC). In September 2005, the APSC ordered an $11 million rate
reduction, including a $10 million reduction relating to depreciation rates,
which went into effect on September 25, 2005.
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 and August 2005, Southern
Gas Operations filed requests to implement these rates within the incorporated
cities located in its Beaumont/East Texas and South Texas Divisions. If these
rates are approved in all jurisdictions 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. Substantially all of the excess amounts collected in interim rates
over those approved in the final settlement were refunded to customers in the
third quarter.
On November 2, 2005, Minnesota Gas filed a request with the MPUC to
increase annual rates by $41 million. It has requested that an interim rate
increase of $35 million be implemented January 1, 2006. Any difference between
the interim rates collected and the final rates would be subject to refund to
customers. A decision by the MPUC is expected in the third quarter of 2006.
(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. On August 10, 2005, the City
of Tyler appealed this order to the Court of Appeals.
(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
increase, if any, in kWh delivered by CenterPoint Houston within the City of
Houston.
CenterPoint Houston began paying the new annual franchise fees on July 1,
2005. Pursuant to the New Franchise Ordinance, 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. In
accordance with CenterPoint Houston's rights under the New Franchise Ordinance,
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.
14
(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 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.
(g) Texas Utility Commission Staff Report.
The Texas Utility Commission requires each electric utility to file, on
commission-prescribed forms, an annual Earnings Report providing certain
information to enable the Texas Utility Commission to monitor the electric
utilities' earnings and financial condition within the state. On May 16, 2005,
CenterPoint Houston filed its Earnings Report for the calendar year ended
December 31, 2004. CenterPoint Houston's Earnings Report shows that it earned
less than its authorized rate of return on equity in 2004.
On October 21, 2005, the Texas Utility Commission Staff filed a memorandum
summarizing their review of the Earnings Reports filed by electric utilities.
Based on its review, the Texas Utility Commission Staff concluded that
continuation of CenterPoint Houston's existing rates could result in excess
revenues of as much as $105 million annually and recommended that the Texas
Utility Commission initiate a review of the reasonableness of existing rates.
The Texas Utility Commission Staff's analysis is based on an estimated 9.60%
midpoint cost of equity, which is more than 150 basis points lower than the
approved return on equity from CenterPoint Houston's last rate proceeding, the
elimination of interest on debt maturing in November 2005 and certain other
adjustments to CenterPoint Houston's reported information. Additionally, an
assumed hypothetical capital structure of 60% debt and 40% equity was used which
would vary materially from the projected capital structure after the maturity of
CenterPoint Houston's $1.31 billion term loan at the end of 2005.
On October 28, 2005, the Texas Utility Commission considered the Staff
report and agreed to initiate a rate proceeding by December 1, 2005 if
CenterPoint Houston and other parties have not reached a settlement of the
alleged excess earnings.
CenterPoint Houston disagrees with several of the adjustments discussed in
the memorandum and believes the Texas Utility Commission should base any such
analysis on updated expense and revenue amounts and the appropriate capital
structure and cost of capital.
(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 nine months ended September 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
15
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 September 30, 2005, the Company expects $(0.4)
million in accumulated other comprehensive loss 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 and are accounted for on a
mark-to-market basis with changes in fair value reported through earnings. 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 Company does not engage in
proprietary or speculative commodity trading. Unhedged positions are accounted
for by adjusting the carrying amount of the contracts to market and recognizing
any gain or loss in operating income, net. During the nine months ended
September 30, 2004 and 2005, the Company recognized net gains (losses) related
to unhedged positions amounting to $(4) million and $14 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
September 30, 2005, the Company had recorded short-term risk management assets
and liabilities of $55 million and $37 million, respectively, included in other
current assets and other current liabilities, respectively.
A portion of CenterPoint Energy Services, Inc.'s (CES) activities include
entering into transactions for the physical purchase, transportation and sale of
natural gas at different locations (physical contracts). CES attempts to
mitigate basis risk associated with these activities by entering into financial
derivative contracts (financial contracts or financial basis swaps) to address
market price volatility between the purchase and sale delivery points that can
occur over the term of the physical contracts. The underlying physical contracts
are accounted for on an accrual basis with all associated earnings not
recognized until the time of actual physical delivery. The timing of the
earnings impacts for the financial contracts differs from the physical contracts
because the financial contracts meet the definition of a derivative under SFAS
No. 133, "Accounting for Derivative Instruments" (SFAS No. 133), and are
recorded at fair value as of each reporting balance sheet date with changes in
value reported through earnings. Changes in prices between the delivery points
(basis spreads) can and do vary daily resulting in changes to the fair value of
the financial contracts. However, the economic intent of the financial contracts
is to fix the actual net difference in the natural gas pricing at the different
locations for the associated physical purchase and sale contracts throughout the
life of the physical contracts and thus, when combined with the physical
contracts' terms, provide an expected fixed gross margin on the physical
contracts that will ultimately be recognized in earnings at the time of actual
delivery of the natural gas. As of September 30, 2005, the mark-to-market value
of the financial contracts described above reflected an unrealized loss of $3.6
million; however, the underlying expected fixed gross margin associated with
delivery under the physical contracts combined with the price risk management
provided through the financial contracts is $2.3 million. As described above,
over the term of these financial contracts, the quarterly reported
mark-to-market changes in value may vary significantly and the associated
unrealized gains and losses will be reflected in CES' earnings.
CES also sells physical gas and basis to its end-use customers who desire
to lock in a future spread between a specific location and Henry Hub (NYMEX). As
a result, CES incurs exposure to commodity basis risk related to these
transactions, which it attempts to mitigate by buying offsetting financial basis
swaps. Under SFAS No. 133, CES records at fair value and marks-to-market the
financial basis swaps as of each reporting balance sheet date with changes in
value reported through earnings. However, the associated physical sales
contracts are accounted for using the accrual basis, whereby earnings impacts
are not recognized until the time of actual physical delivery. Although the
timing of earnings recognition for the financial basis swaps differs from the
physical contracts, the economic intent of the financial basis swaps is to fix
the basis spread over the life of the physical contracts to an amount
substantially the same as the portion of the basis spread pricing included in
the physical contracts. In so doing, over the period that the financial basis
swaps and related physical contracts are outstanding, actual cumulative earnings
impacts for changes in the basis spread should be minimal, even though from a
timing perspective there could be fluctuations in unrealized gains or losses
associated with the changes in fair value recorded for the financial basis
swaps. The cumulative earnings impact from the financial basis swaps recognized
each reporting period is expected to be offset by the value realized when the
related physical sales occur. As of September 30, 2005, the mark-to-market value
of the financial basis swaps reflected an unrealized loss of $4.8 million.
16
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 nine months ended September 30, 2004 and 2005, was $19 million and $23
million, respectively.
Embedded Derivative. The Company's $575 million and $255 million of
convertible senior notes 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 September 30, 2005.
(7) GOODWILL AND INTANGIBLES
Goodwill by reportable business segment is as follows (in millions):
DECEMBER 31, SEPTEMBER 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 performs its goodwill impairment test at least annually and
evaluates goodwill when events or changes in circumstances indicate that the
carrying value of these assets may not be recoverable. Upon adoption of SFAS No.
142, "Goodwill and Other Intangible Assets," the Company initially selected
January 1 as its annual goodwill impairment testing date. Since the time the
Company selected the January 1 date, the Company's year-end closing and
reporting process has been truncated in order to meet the accelerated reporting
requirements of the SEC, resulting in significant constraints on the Company's
human resources at year-end and during its first fiscal quarter. Accordingly, in
order to meet the accelerated reporting deadlines and to provide adequate time
to complete the analysis each year, beginning in the third quarter of 2005, the
Company changed the date on which it performs its annual goodwill impairment
test from January 1 to July 1. The Company believes the July 1 alternative date
will alleviate the resource constraints that exist during the first quarter and
allow it to utilize additional resources in conducting the annual impairment
evaluation of goodwill. The Company performed the test at July 1, 2005, and
determined that no impairment charge for goodwill was required. The change is
not intended to delay, accelerate or avoid an impairment charge. The Company
believes that this accounting change is an alternative accounting principle that
is preferable under the circumstances.
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2004 SEPTEMBER 30, 2005
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Land use rights ... $55 $(12) $55 $(13)
Other ............. 21 (6) 21 (7)
--- ---- --- ----
Total .......... $76 $(18) $76 $(20)
=== ==== === ====
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
September 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.
Amortization expense for other intangibles for both of the three months
ended September 30, 2004 and 2005 was less than $1 million and for both of the
nine months ended September 30, 2004 and 2005 was $2 million. Estimated
amortization expense for the last three months of 2005 and the five succeeding
fiscal years is as follows (in millions):
17
2005....... $--
2006....... 3
2007....... 3
2008....... 3
2009....... 3
2010....... 2
---
Total... $14
===
(8) COMPREHENSIVE INCOME
The following table summarizes the components of total comprehensive income
(net of tax):
FOR THE THREE FOR THE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------- --------------
2004 2005 2004 2005
------- ---- ------- ----
(IN MILLIONS)
Net income (loss) ...................................... $(1,136) $50 $(1,005) $171
------- --- ------- ----
Other comprehensive income (loss):
Minimum benefit liability ........................... 14 -- 14 --
Net deferred gain from cash flow hedges ............. 17 1 33 11
Reclassification of deferred loss (gain) from cash
flow hedges realized in net income ............... (2) (2) (1) 6
Other comprehensive income (loss) from
discontinued operations .......................... (93) -- (93) 3
------- --- ------- ----
Other comprehensive income (loss) ...................... (64) (1) (47) 20
------- --- ------- ----
Comprehensive income (loss) ............................ $(1,200) $49 $(1,052) $191
======= === ======= ====
The following table summarizes the components of accumulated other
comprehensive loss:
DECEMBER 31, SEPTEMBER 30,
2004 2005
------------ -------------
(IN MILLIONS)
Minimum pension liability adjustment ................... $ (6) $ (6)
Net deferred loss from cash flow hedges ................ (52) (35)
Other comprehensive loss from discontinued operations .. (3) --
---- ----
Total accumulated other comprehensive loss ............. $(61) $(41)
==== ====
(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 September 30, 2005,
310,069,936 shares of CenterPoint Energy common stock were issued and
310,069,770 shares of CenterPoint Energy common stock were outstanding.
Outstanding common shares exclude 166 treasury shares at both December 31, 2004
and September 30, 2005.
CenterPoint Energy's board of directors declared a dividend of $0.10 per
share in each of the first three 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 to address
technical restrictions that might have limited 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 dividend from
capital or unearned surplus. There can be no assurance, however, that the SEC
would authorize such payments. 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. On
August 31, 2005, the Company's board of directors declared a dividend of $0.07
per common share, payable on September 30, 2005, to shareholders of record
18
as of the close of business on September 12, 2005. The dividends declared and
paid for the first three quarters of 2005 totaled $0.34 per share versus $0.30
per share for the first three quarters of 2004.
On October 24, 2005, the Company's board of directors declared a dividend
of $0.06 per common share, payable on December 9, 2005, to shareholders of
record as of the close of business on November 16, 2005.
(10) LONG-TERM DEBT AND RECEIVABLES FACILITY
(a) Long-term Debt.
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 the London interbank offered rate (LIBOR) plus
87.5 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
September 30, 2005, borrowings of $187 million in commercial paper were
backstopped by the revolving credit facility and $27 million in letters of
credit 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 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 September 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. CenterPoint Houston expects to utilize this facility to refinance
CenterPoint Houston's $1.31 billion term loan maturing on November 11, 2005.
Drawings may be made under this credit facility until November 16, 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.
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 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 September 30, 2005, such credit facility
was not utilized.
Convertible Debt. In August 2005, the Company accepted for exchange
approximately $572 million aggregate principal amount of its 3.75% convertible
senior notes due 2023 (Old Notes) for an equal amount of its new 3.75%
convertible senior notes due 2023 (New Notes). Old Notes of approximately $3
million remain outstanding. The Company 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 the New Notes will be made in
cash rather than stock, the exchange of 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.
Additionally, as of September 30, 2005, the 3.75% convertible senior notes
have been included as current portion of long-term debt in the Consolidated
Balance Sheet because the last reported sale price of CenterPoint Energy common
stock for at least 20 trading days during the period of 30 consecutive trading
days ending on the last trading day of the third calendar quarter was greater
than or equal to 120% of the conversion price of the 3.75%
19
convertible senior notes and therefore, during the fourth quarter of 2005, the
3.75% convertible senior notes meet the criteria to be converted by the
noteholders.
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 September 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 September 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, SEPTEMBER 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. 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 convertible junior subordinated debentures represented CERC
Trust's sole asset and its entire operations. The amount of outstanding junior
subordinated debentures was included in long-term debt as of December 31, 2004.
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.
(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 September 30, 2005, CERC had $141 million of
advances under its receivables facility.
Advances under the receivables facility averaged $173 million for the nine
months ended September 30, 2005. Sales of receivables were approximately $447
million and $480 million for the three months ended September 30, 2004 and 2005,
respectively, and $1.7 billion and $1.4 billion for the nine months ended
September 30, 2004 and 2005, respectively.
20
(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, in Kansas state
court in Wyandotte County and in federal district courts in San Francisco, San
Diego, Los Angeles, Fresno, Sacramento, San Jose, Kansas 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. A third case filed by the California Attorney General has been
resolved in the settlement described in the following paragraph. 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.
On August 12, 2005, RRI reached a settlement with the states of California,
Washington and Oregon, California's three largest investor-owned utilities,
classes of consumers from California and other western states, and a number of
California city and county government entities that resolves their claims
against RRI related to the operation of the electricity markets in California
and certain other western states in 2000-2001. The settlement also resolves the
claims of the states and the investor-owned utilities related to the 2000-2001
natural gas markets. The settlement must be approved by FERC, the California
Public Utilities Commission and the courts in which the class action cases are
pending. Approvals are expected by the end of 2005. The Company is not a party
to the settlement,
21
but may rely on the settlement as a defense to any claims brought against it
related to the time when the Company was an affiliate of RRI. The terms of the
settlement do not require payment by the Company.
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 parties
filed a stipulation and agreement of settlement in September 2005, and in
October 2005, filed a corrected and supplemental submission at the court's
request. Notice is being sent to settlement class members, and a settlement
fairness hearing is set for January 2006. 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. Trial is set for January 2006.
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 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
22
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 the plaintiff appealed to the U.S. Fifth Circuit Court of
Appeals, which affirmed the dismissal. The plaintiff has now sought review by
the U.S. Supreme Court in a petition for certiorari. 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.
There has been no activity in the claims of the 45 cities since the Texas
Supreme Court dismissed the claims of the Three Cities. 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
23
they assert their claims that the defendants have engaged in systematic
mismeasurement of the Btu content of natural gas for more than 25 years. In both
lawsuits, the plaintiffs seek compensatory damages, along with statutory
penalties, treble damages, interest, costs and fees. 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 amount of expenditures to locate and replace
such components to be approximately $38 million. CERC is seeking to recover the
capitalized expenditures, together with a return on those amounts through rates.
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 (OAG) issued its report alleging CERC
has violated the CWR and recommended a $5 million penalty. CERC filed its reply
comments in July 2005. CERC and the OAG have reached agreement on procedures to
be followed for the current Cold Weather Period beginning October 15, 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
24
lawsuit. CERC does not expect this matter to have a material adverse effect on
its financial condition, results of operations or cash flows.
(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 September 30, 2005, CERC had accrued $18 million for remediation of
certain Minnesota sites. At September 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 September 30, 2005, CERC has collected a
total of $13 million from insurance companies and its environmental tracker 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
25
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.
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/A Notes, 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 $111 million at September 30, 2005. The
additions to the reserve for the three and nine months ended September 30, 2005
were $10 million and $32 million, respectively. 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 $42
million.
26
(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
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.
27
(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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
2004 2005 2004 2005
------------ ------------ ------------ ------------
(IN MILLIONS, EXCEPT SHARE AND
PER SHARE AMOUNTS)
Basic EPS Calculation:
Income from continuing operations before extraordinary
item ................................................. $ 17 $ 50 $ 43 $ 144
Discontinued operations, net of tax ..................... (259) -- (154) (3)
Extraordinary item, net of tax .......................... (894) -- (894) 30
------------ ------------ ------------ ------------
Net income (loss) ....................................... $ (1,136) $ 50 $ (1,005) $ 171
============ ============ ============ ============
Weighted average shares outstanding ........................ 307,592,000 309,657,000 306,954,000 309,080,000
============ ============ ============ ============
Basic EPS:
Income from continuing operations before extraordinary
item ................................................. $ 0.05 $ 0.16 $ 0.14 $ 0.46
Discontinued operations, net of tax ..................... (0.84) -- (0.50) (0.01)
Extraordinary item, net of tax .......................... (2.90) -- (2.91) 0.10
------------ ------------ ------------ ------------
Net income (loss) ....................................... $ (3.69) $ 0.16 $ (3.27) $ 0.55
============ ============ ============ ============
Diluted EPS Calculation:
Net income (loss) ....................................... $ (1,136) $ 50 $ (1,005) $ 171
Plus: Income impact of assumed conversions:
Interest on 3.75% convertible senior notes ........... -- 2 -- 9
------------ ------------ ------------ ------------
Total earnings effect assuming dilution ................. $ (1,136) $ 52 $ (1,005) $ 180
============ ============ ============ ============
Weighted average shares outstanding ........................ 307,592,000 309,657,000 306,954,000 309,080,000
Plus: Incremental shares from assumed conversions (1):
Stock options ........................................ 1,280,000 1,457,000 1,235,000 1,259,000
Restricted stock ..................................... 1,276,000 1,500,000 1,276,000 1,500,000
2.875% convertible senior notes ...................... -- 1,620,000 -- --
3.75% convertible senior notes ....................... -- 32,269,000 -- 43,183,000
6.25% convertible trust preferred securities ......... 17,000 -- 17,000 --
------------ ------------ ------------ ------------
Weighted average shares assuming dilution ............... 310,165,000 346,503,000 309,482,000 355,022,000
============ ============ ============ ============
Diluted EPS:
Income from continuing operations before extraordinary
item ................................................ $ 0.05 $ 0.15 $ 0.14 $ 0.43
Discontinued operations, net of tax ..................... (0.83) -- (0.50) (0.01)
Extraordinary item, net of tax .......................... (2.88) -- (2.89) 0.09
------------ ------------ ------------ ------------
Net income (loss) ....................................... $ (3.66) $ 0.15 $ (3.25) $ 0.51
============ ============ ============ ============
----------
(1) For the three months ended September 30, 2004 and 2005, the computation of
diluted EPS excludes options to purchase 10,005,605 and 8,940,201 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 third 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 nine months ended September 30, 2004 and 2005, the computation of
diluted EPS excludes options to purchase 12,015,605 and 8,940,201 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 nine
months of 2004 and 2005, respectively) greater than the per share average
market price for the period and would thus be antidilutive if exercised.
28
Diluted earnings per share for the three months and nine months ended
September 30, 2004 have not been restated for the adoption of EITF 04-8,
effective December 31, 2004, as inclusion of the contingently convertible shares
had an antidilutive effect. The impact on the Company's diluted EPS from
continuing operations for the three and nine months ended September 30, 2005 was
a decrease of $0.01 and $0.03 per share, respectively.
In accordance with EITF 04-8, because all of the 2.875% contingently
convertible senior notes and approximately $572 million of the 3.75%
contingently convertible senior notes provide for settlement of the principal
portion in cash rather than stock, the Company excludes the portion of the
conversion value of these notes attributable to their principal amount from its
computation of diluted earnings per share from continuing operations. The
Company includes the conversion spread in the calculation of diluted earnings
per share when the average market price of the Company's common stock in the
respective reporting period exceeds the conversion price. The conversion prices
for the 2.875% and the 3.75% contingently convertible senior 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 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 SEPTEMBER 30, 2004
---------------------------------------------
REVENUES FROM NET
EXTERNAL INTERSEGMENT OPERATING
CUSTOMERS REVENUES INCOME (LOSS)
------------- ------------ -------------
(IN MILLIONS)
Electric Transmission & Distribution .. $ 448(1) $ -- $178
Natural Gas Distribution .............. 1,044 3 (2)
Pipelines and Gathering ............... 73 35 35
Other Operations ...................... 2 -- (4)
Eliminations .......................... -- (38) --
------ ---- ----
Consolidated .......................... $1,567 $ -- $207
====== ==== ====
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005
---------------------------------------------
REVENUES FROM NET
EXTERNAL INTERSEGMENT OPERATING
CUSTOMERS REVENUES INCOME (LOSS)
------------- ------------ -------------
(IN MILLIONS)
Electric Transmission & Distribution .. $ 484(1) $ -- $183
Natural Gas Distribution .............. 1,506 -- (12)
Pipelines and Gathering ............... 81 35 52
Other Operations ...................... 2 2 2
Eliminations .......................... -- (37) --
------ ---- ----
Consolidated .......................... $2,073 $ -- $225
====== ==== ====
29
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004
--------------------------------------------
REVENUES FROM NET TOTAL ASSETS
EXTERNAL INTERSEGMENT OPERATING AS OF
CUSTOMERS REVENUES INCOME (LOSS) DECEMBER 31, 2004
------------- ------------ ------------- -----------------
(IN MILLIONS)
Electric Transmission & Distribution .. $1,153(1) $ -- $390 $ 8,783
Natural Gas Distribution .............. 4,187 3 137 4,732
Pipelines and Gathering ............... 217 107 123 2,637
Other Operations ...................... 5 3 (17) 2,794
Discontinued Operations ............... -- -- -- 1,565
Eliminations .......................... -- (113) -- (2,415)
------ ----- ---- -------
Consolidated .......................... $5,562 $ -- $633 $18,096
====== ===== ==== =======
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005
--------------------------------------------
REVENUES FROM NET TOTAL ASSETS
EXTERNAL INTERSEGMENT OPERATING AS OF
CUSTOMERS REVENUES INCOME (LOSS) SEPTEMBER 30, 2005
------------- ------------ ------------- -----------------
(IN MILLIONS)
Electric Transmission & Distribution .. $1,243(1) $ -- $385 $ 8,355
Natural Gas Distribution .............. 5,006 3 146 5,262
Pipelines and Gathering ............... 252 110 168 2,925
Other Operations ...................... 9 6 (12) 1,853
Eliminations .......................... -- (119) -- (1,959)
------ ----- ---- -------
Consolidated .......................... $6,510 $ -- $687 $16,436
====== ===== ==== =======
----------
(1) Sales to subsidiaries of RRI represented approximately $265 million and
$249 million of CenterPoint Houston's transmission and distribution
revenues from external customers for the three months ended September 30,
2004 and 2005, respectively, and approximately $666 million and $615
million for the nine months ended September 30, 2004 and 2005,
respectively.
(14) RESTATEMENT
Subsequent to the issuance of its condensed consolidated financial
statements for the three- and nine-month periods ended September 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 nine months ended September 30, 2004 were each
overstated by approximately $102 million and $335 million, respectively. For the
three and nine months ended September 30, 2005, revenues and natural gas
expenses were each overstated by approximately $145 million and $402 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 nine
months ended September 30, 2004 and 2005.
30
A summary of the significant effects of the restatements is as follows:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2004 SEPTEMBER 30, 2004
--------------------------- ---------------------------
AS PREVIOUSLY AS PREVIOUSLY
AS RESTATED REPORTED AS RESTATED REPORTED
----------- ------------- ----------- -------------
(IN MILLIONS)
STATEMENTS OF CONSOLIDATED OPERATIONS:
Revenues ................................ $1,567 $1,669 $5,562 $5,897
Expenses: Natural gas ................... 826 928 3,366 3,701
Total Expenses .......................... 1,360 1,462 4,929 5,264
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2005 SEPTEMBER 30, 2005
--------------------------- ---------------------------
AS PREVIOUSLY AS PREVIOUSLY
AS RESTATED REPORTED AS RESTATED REPORTED
----------- ------------- ----------- -------------
(IN MILLIONS)
STATEMENTS OF CONSOLIDATED OPERATIONS:
Revenues ................................ $2,073 $2,218 $6,510 $6,912
Expenses: Natural gas ................... 1,277 1,422 4,161 4,563
Total Expenses .......................... 1,848 1,993 5,823 6,225
AS OF SEPTEMBER 30, 2005
---------------------------
AS PREVIOUSLY
AS RESTATED REPORTED
----------- -------------
CONSOLIDATED BALANCE SHEETS:
Accounts receivable, net .................... $ 661 $ 745
Total current assets ........................ 2,386 2,462
Total assets ................................ 16,436 16,512
Accounts payable ............................ 769 845
Total current liabilities ................... 4,598 4,674
Total liabilities and shareholders' equity .. 16,436 16,512
31
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 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. CenterPoint Houston
and other parties filed appeals of the True-Up Order to a district court in
Travis County, Texas. That court held a hearing on the appeal in early August
2005, and on August 26, 2005, the court issued its final judgment on the various
appeals. In its judgment, the court affirmed most aspects of the Texas Utility
Commission's order, but reversed two of the Texas Utility Commission's rulings,
which would have the effect of restoring approximately $620 million, plus
interest, of the $1.7 billion the Texas Utility Commission had disallowed from
CenterPoint Houston's initial request. First, the court reversed the Texas
Utility Commission's decision to prohibit CenterPoint Houston from recovering
$180 million in credits through August 2004 that CenterPoint Houston was ordered
to provide to retail electric providers as a result of a stranded cost estimate
made by the Texas Utility Commission in 2000 that subsequently proved to be
inaccurate. Second, the court reversed the Texas Utility Commission's
disallowance of $440 million in transition costs which are recoverable under the
Texas Utility Commission's regulations. Additional credits of approximately $30
million paid after August 2004 and interest would be added to these amounts.
CenterPoint Houston and other parties appealed the district court decision to
the 3rd Court of Appeals in Austin in September 2005. The parties have agreed to
a briefing schedule whereby briefs will be filed by the parties on a schedule
extending into February 2006. No amounts related to the court's judgment have
been recorded in our consolidated financial statements.
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
approximately $1.8 billion of transition bonds. In August 2005, the same Travis
County District Court considering the appeal of the True-Up Order affirmed the
financing order in all respects. CenterPoint Houston expects to complete the
issuance of transition bonds under that order in the fourth quarter of 2005,
subject to, among other matters, market conditions and the completion of
documentation and rating agency reviews.
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%. 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. The CTC order also allows CenterPoint Houston to collect approximately
$24 million of rate case expenses over three years through a separate tariff
rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE
effective September 13, 2005 and began recovering approximately $600 million and
the rate case expenses. Certain other parties appealed the CTC order to the
Travis County Court on September 27, 2005. Additionally, during the period from
September 13, 2005, the date of implementation of the CTC order, through
September 30, 2005, CenterPoint Houston recognized approximately $7
32
million in CTC revenue, which was partially offset by $5 million in related
amortization of the CTC regulatory asset.
CenterPoint Houston is entitled to accrue a return on the true-up balance
until it is fully recovered.
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
increase, if any, in kWh delivered by CenterPoint Houston within the City of
Houston.
CenterPoint Houston began paying the new annual franchise fees on July 1,
2005. Pursuant to the New Franchise Ordinance, 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. In
accordance with CenterPoint Houston's rights under the New Franchise Ordinance,
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.
DEBT FINANCING TRANSACTIONS
In August 2005, we accepted for exchange approximately $572 million
aggregate principal amount of our 3.75% convertible senior notes due 2023 (Old
Notes) for an equal amount of our new 3.75% convertible senior notes due 2023
(New Notes). Old Notes of approximately $3 million remain outstanding. We
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 the New Notes will be made in cash rather than stock, the exchange of
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.
REPEAL OF THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
On August 8, 2005, President Bush signed into law the Energy Policy Act of
2005 (Energy Act). Under that legislation, the Public Utility Holding Company
Act of 1935 (1935 Act) is repealed effective February 8, 2006. 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 grants to the Federal Energy Regulatory Commission (FERC)
authority to require holding companies and their subsidiaries to maintain
certain books and records and make them available for review by FERC and state
regulatory authorities. The Energy Act requires FERC to issue regulations to
implement its jurisdiction under the Energy Act, and on September 16, 2005, FERC
issued proposed rules for public comment. It is presently unknown what, if any,
specific obligations under those rules may be imposed on us and our subsidiaries
as a result of that rulemaking.
3RD QUARTER 2005 HIGHLIGHTS
Our operating performance for the third quarter of 2005 compared to the
third quarter of 2004 was affected by:
- increased operating income of $17 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;
33
- continued customer growth, with the addition of 95,000 metered
electric and gas customers;
- an increase in other income of $35 million for the third quarter of
2005 related to the return on our true-up balance; and
- a decrease in interest expense of $15 million.
The above increases in operating performance were partially offset by a net
reduction of operating income of $10 million in our Natural Gas Distribution
business segment primarily due to increased bad debt expense and higher
depreciation expense, partially offset by rate increases and continued customer
growth.
CONSOLIDATED RESULTS OF OPERATIONS
All dollar amounts in the tables that follow are in millions, except for
per share amounts.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2004 2005 2004 2005
------- ------ ------- ------
Revenues .......................................... $ 1,567 $2,073 $ 5,562 $6,510
Expenses .......................................... 1,360 1,848 4,929 5,823
------- ------ ------- ------
Operating Income .................................. 207 225 633 687
Interest and Other Finance Charges ................ (192) (177) (583) (548)
Other Income, net ................................. 4 43 18 127
------- ------ ------- ------
Income From Continuing Operations Before Income
Taxes and Extraordinary Item ................... 19 91 68 266
Income Tax Expense ................................ (2) (41) (25) (122)
------- ------ ------- ------
Income From Continuing Operations Before
Extraordinary Item ............................. 17 50 43 144
Discontinued Operations, net of tax ............... (259) -- (154) (3)
------- ------ ------- ------
Income (Loss) Before Extraordinary Item ........... (242) 50 (111) 141
Extraordinary Item, net of tax .................... (894) -- (894) 30
------- ------ ------- ------
Net Income (Loss) ................................. $(1,136) $ 50 $(1,005) $ 171
======= ====== ======= ======
BASIC EARNINGS PER SHARE:
Income From Continuing Operations Before
Extraordinary Item .......................... $ 0.05 $ 0.16 $ 0.14 $ 0.46
Discontinued Operations, net of tax ............ (0.84) -- (0.50) (0.01)
Extraordinary Item, net of tax ................. (2.90) -- (2.91) 0.10
------- ------ ------- ------
Net Income (Loss) .............................. $ (3.69) $ 0.16 $ (3.27) $ 0.55
======= ====== ======= ======
DILUTED EARNINGS PER SHARE:
Income From Continuing Operations Before
Extraordinary Item .......................... $ 0.05 $ 0.15 $ 0.14 $ 0.43
Discontinued Operations, net of tax ............ (0.83) -- (0.50) (0.01)
Extraordinary Item, net of tax ................. (2.88) -- (2.89) 0.09
------- ------ ------- ------
Net Income (Loss) .............................. $ (3.66) $ 0.15 $ (3.25) $ 0.51
======= ====== ======= ======
THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2004
Income from Continuing Operations. We reported income from continuing
operations of $50 million ($0.15 per diluted share) for the three months ended
September 30, 2005 as compared to $17 million ($0.05 per diluted share) for the
same period in 2004. The increase in income from continuing operations of $33
million was primarily due to increased operating income of $17 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 $15 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 higher bad debt
expense and depreciation
34
expense in our Natural Gas Distribution business segment. Additionally, income
tax expense increased in the third quarter of 2005 as discussed below.
Income Tax Expense. During the three months ended September 30, 2004 and
2005, our effective tax rate was 11.6% and 45.2%, respectively. The most
significant item affecting our effective tax rate in the third quarter of 2005
was an addition to the tax reserve of approximately $10 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 2029 (ZENS) be capitalized, potentially converting what would be
ordinary deductions into capital losses at the time the ZENS are settled. We
expect the reserve to increase by approximately $13 million in the fourth
quarter.
NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2004
Income from Continuing Operations. We reported income from continuing
operations before extraordinary item of $144 million ($0.43 per diluted share)
for the nine months ended September 30, 2005 as compared to $43 million ($0.14
per diluted share) for the same period in 2004. The increase in income from
continuing operations of $101 million was primarily due to increased operating
income of $45 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 $9 million in our Natural
Gas Distribution business segment primarily due to rate increases, 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, $104 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 $35 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 $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 and the absence of an $11
million gain from a land sale recorded in the second quarter of 2004, partially
offset by increased usage mainly due to weather, continued customer growth and
higher transmission cost recovery. Additionally, income tax expense increased in
the nine months ended September 30, 2005 as discussed below.
Income Tax Expense. During the nine months ended September 30, 2004 and
2005, our effective tax rate was 36.7% and 45.9%, respectively. The most
significant item affecting our effective tax rate in the first nine months of
2005 is an addition to the tax reserve of approximately $32 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 $206 million and $621 million for the
three and nine months ended September 30, 2004. We have reclassified $14 million
and $38 million of interest expense for the three and nine months ended
September 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 the nine months ended September 30, 2005 included an
after-tax extraordinary gain of $30 million ($0.09 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.
35
Net income for the three months ended September 30, 2004 included a net
after-tax loss from discontinued operations of Texas Genco of $259 million
($0.83 per diluted share). Net income for the nine months ended September 30,
2004 and 2005 included a net after tax loss from discontinued operations of
Texas Genco of $154 million ($0.50 per diluted share) and $3 million ($0.01 per
diluted share), respectively.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following table presents operating income for each of our business
segments for the three and nine months ended September 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Electric Transmission & Distribution .............. $178 $183 $390 $385
Natural Gas Distribution .......................... (2) (12) 137 146
Pipelines and Gathering ........................... 35 52 123 168
Other Operations .................................. (4) 2 (17) (12)
---- ---- ---- ----
Total Consolidated Operating Income ............ $207 $225 $633 $687
==== ==== ==== ====
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 September 30, 2005
filed on November 3, 2005.
The following tables provide summary data of our Electric Transmission &
Distribution business segment for the three and nine months ended September 30,
2004 and 2005:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2004 2005 2004 2005
---------- ---------- ---------- ----------
(IN MILLIONS, EXCEPT CUSTOMER DATA)
Electric transmission and distribution revenues ............... $ 427 $ 453 $ 1,099 $ 1,164
---------- ---------- ---------- ----------
Electric transmission and distribution expenses:
Operation and maintenance .................................. 136 155 394 446
Depreciation and amortization .............................. 63 69 186 197
Taxes other than income taxes .............................. 59 55 158 163
---------- ---------- ---------- ----------
Total electric transmission and distribution expenses ... 258 279 738 806
---------- ---------- ---------- ----------
Operating Income - Electric transmission and
distribution utility ....................................... 169 174 361 358
Operating Income - Transition bond company (1) ................ 9 9 29 27
---------- ---------- ---------- ----------
Total Segment Operating Income ................................ $ 178 $ 183 $ 390 $ 385
========== ========== ========== ==========
Actual gigawatt-hours (GWh) delivered:
Residential ................................................ 8,512 8,871 18,714 19,607
Total ...................................................... 22,568 22,351 56,634 57,134
Average number of metered customers:
Residential ................................................ 1,645,523 1,690,819 1,633,890 1,675,904
Total ...................................................... 1,870,128 1,921,594 1,856,551 1,904,235
----------
(1) Represents the amount necessary to pay interest on the transition bonds.
THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2004
Our Electric Transmission & Distribution business segment reported
operating income of $183 million for the three months ended September 30, 2005,
consisting of $174 million for the regulated electric transmission and
36
distribution utility and $9 million for the transition bond company. For the
three months ended September 30, 2004, operating income totaled $178 million,
consisting of $169 million for the regulated electric transmission and
distribution utility and $9 million for the transition bond company. Operating
revenues increased primarily due to continued customer growth ($11 million) with
the addition of 53,000 metered customers since September 2004, competition
transition charge (CTC) recovery of our 2004 true-up balance not covered by the
transition bond finance order ($7 million) and higher transmission cost recovery
($5 million). The increase in operating revenues was partially offset by higher
transmission costs ($8 million), the absence of a gain from a land sale recorded
in the third quarter of 2004 ($11 million), increased amortization related to
the CTC regulatory asset resulting from the 2004 true-up balance ($5 million),
partially offset by decreased state and local taxes ($4 million).
NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2004
Our Electric Transmission & Distribution business segment reported
operating income of $385 million for the nine months ended September 30, 2005,
consisting of $358 million for the regulated electric transmission and
distribution utility and $27 million for the transition bond company. For the
nine months ended September 30, 2004, operating income totaled $390 million,
consisting of $361 million for the regulated electric transmission and
distribution utility and $29 million for the transition bond company. Operating
revenues increased primarily due to increased usage resulting from warmer
weather ($10 million), continued customer growth ($26 million) with the addition
of 53,000 metered customers since September 2004, CTC recovery of our 2004
true-up balance not covered by the transition bond finance order ($7 million)
and higher transmission cost recovery ($13 million). The increase in operating
revenues was more than offset by higher transmission costs ($16 million), the
absence of a gain from a land sale recorded in the third quarter of 2004 ($11
million), the absence of a $15 million partial reversal of a reserve related to
the final fuel reconciliation recorded in 2004, higher depreciation and
amortization expense ($11 million, including $5 million of amortization related
to the CTC regulatory asset resulting from the 2004 true-up balance) and
increased state and local taxes ($5 million).
In September 2005, CenterPoint Houston's service area in Texas was
adversely affected by Hurricane Rita. Although damage to CenterPoint Houston's
electric facilities was limited, over 700,000 customers lost power at the height
of the storm. Power was restored to over a half million customers within 36
hours and all power was restored in less than five days. The Electric
Transmission & Distribution business segment's revenues lost as a result of the
storm were more than offset by warmer than normal weather during the quarter.
CenterPoint Houston estimates restoration costs in its service area to be in the
range of $20 to $30 million, which will be deferred for recovery in a future
rate case.
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 September 30, 2005
filed on November 3, 2005.
The following table provides summary data of our Natural Gas Distribution
business segment for the three and nine months ended September 30, 2004 and
2005:
37
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2004 2005 2004 2005
---------- ---------- ---------- ----------
(IN MILLIONS, EXCEPT CUSTOMER DATA)
Revenues ................................... $ 1,047 $ 1,506 $ 4,190 $ 5,009
---------- ---------- ---------- ----------
Expenses:
Natural gas ............................. 857 1,311 3,441 4,242
Operation and maintenance ............... 133 141 416 414
Depreciation and amortization ........... 36 39 106 116
Taxes other than income taxes ........... 23 27 90 91
---------- ---------- ---------- ----------
Total expenses ....................... 1,049 1,518 4,053 4,863
---------- ---------- ---------- ----------
Operating Income (Loss) .................... $ (2) $ (12) $ 137 $ 146
========== ========== ========== ==========
Throughput (in billion cubic feet (Bcf)):
Residential ............................. 15 9 121 107
Commercial and industrial ............... 39 38 171 158
Non-rate regulated ...................... 113 160 419 491
Elimination (1) ......................... (32) (26) (105) (104)
---------- ---------- ---------- ----------
Total Throughput ..................... 135 181 606 652
========== ========== ========== ==========
Average number of customers:
Residential ............................. 2,777,212 2,820,629 2,791,722 2,835,306
Commercial and industrial ............... 242,111 244,249 245,895 246,370
Non-rate regulated ...................... 6,249 6,515 6,234 6,520
---------- ---------- ---------- ----------
Total ................................ 3,025,572 3,071,393 3,043,851 3,088,196
========== ========== ========== ==========
----------
(1) Elimination of intrasegment sales.
THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2004
Our Natural Gas Distribution business segment reported an operating loss of
$12 million for the three months ended September 30, 2005 as compared to an
operating loss of $2 million for the same period in 2004. Increases in operating
income from rate increases ($3 million) and increased margins from our non-rate
regulated natural gas sales business ($11 million) were more than offset by the
impact of certain derivative transactions as discussed below ($8 million),
increases in operation and maintenance expenses ($8 million) primarily related
to higher bad debt expense ($5 million), increased depreciation expense
primarily due to higher plant balances ($3 million) and higher taxes other than
income taxes ($4 million).
A portion of CenterPoint Energy Services, Inc.'s (CES) activities include
entering into transactions for the physical purchase, transportation and sale of
natural gas at different locations (physical contracts). CES attempts to
mitigate basis risk associated with these activities by entering into financial
derivative contracts (financial contracts or financial basis swaps) to address
market price volatility between the purchase and sale delivery points that can
occur over the term of the physical contracts. The underlying physical contracts
are accounted for on an accrual basis with all associated earnings not
recognized until the time of actual physical delivery. The timing of the
earnings impacts for the financial contracts differs from the physical contracts
because the financial contracts meet the definition of a derivative under SFAS
No. 133, "Accounting for Derivative Instruments" (SFAS No. 133), and are
recorded at fair value as of each reporting balance sheet date with changes in
value reported through earnings. Changes in prices between the delivery points
(basis spreads) can and do vary daily resulting in changes to the fair value of
the financial contracts. However, the economic intent of the financial contracts
is to fix the actual net difference in the natural gas pricing at the different
locations for the associated physical purchase and sale contracts throughout the
life of the physical contracts and thus, when combined with the physical
contracts' terms, provide an expected fixed gross margin on the physical
contracts that will ultimately be recognized in earnings at the time of actual
delivery of the natural gas. As of September 30, 2005, the mark-to-market value
of the financial contracts described above reflected an unrealized loss of $3.6
million; however, the underlying expected fixed gross margin associated with
delivery under the physical contracts combined with the price risk management
provided through the financial contracts is $2.3 million. As described above,
over the term of these financial contracts, the quarterly reported
mark-to-market changes in value may vary significantly and the associated
unrealized gains and losses will be reflected in CES' earnings.
CES also sells physical gas and basis to its end-use customers who desire
to lock in a future spread between a specific location and Henry Hub (NYMEX). As
a result, CES incurs exposure to commodity basis risk related to
38
these transactions, which it attempts to mitigate by buying offsetting financial
basis swaps. Under SFAS No. 133, CES records at fair value and marks-to-market
the financial basis swaps as of each reporting balance sheet date with changes
in value reported through earnings. However, the associated physical sales
contracts are accounted for using the accrual basis, whereby earnings impacts
are not recognized until the time of actual physical delivery. Although the
timing of earnings recognition for the financial basis swaps differs from the
physical contracts, the economic intent of the financial basis swaps is to fix
the basis spread over the life of the physical contracts to an amount
substantially the same as the portion of the basis spread pricing included in
the physical contracts. In so doing, over the period that the financial basis
swaps and related physical contracts are outstanding, actual cumulative earnings
impacts for changes in the basis spread should be minimal, even though from a
timing perspective there could be fluctuations in unrealized gains or losses
associated with the changes in fair value recorded for the financial basis
swaps. The cumulative earnings impact from the financial basis swaps recognized
each reporting period is expected to be offset by the value realized when the
related physical sales occur. As of September 30, 2005, the mark-to-market value
of the financial basis swaps reflected an unrealized loss of $4.8 million.
NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2004
Our Natural Gas Distribution business segment reported operating income of
$146 million for the nine months ended September 30, 2005 as compared to $137
million for the same period in 2004. Increases in operating income from rate
increases ($19 million) and increased margins from our non-rate regulated
natural gas sales business ($13 million) were partially offset by the impact of
certain derivative transactions as discussed above ($8 million) and the impact
of milder weather and decreased throughput net of continued customer growth with
the addition of approximately 42,000 customers since September 2004 ($10
million). Operation and maintenance expense decreased $2 million. Excluding an
$8 million charge recorded in the first quarter of 2004 for severance costs
associated with staff reductions, operation and maintenance expenses increased
by $6 million primarily due to increased bad debt expense ($7 million),
partially offset by lower claims expense ($5 million) and the capitalization of
previously incurred restructuring expenses as allowed by a regulatory order from
the Railroad Commission of Texas ($5 million). Additionally, operating income
was unfavorably impacted by increased depreciation expense primarily due to
higher plant balances ($10 million).
During the third quarter of 2005, our east Texas, Louisiana and Mississippi
natural gas service areas were affected by Hurricanes Katrina and Rita. Damage
to our facilities was limited, but approximately 10,000 homes and businesses
were damaged to such an extent that they will not be taking service for the
foreseeable future. The impact on the Natural Gas Distribution business
segment's operating income was not material.
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 September 30, 2005
filed on November 3, 2005.
The following table provides summary data of our Pipelines and Gathering
business segment for the three and nine months ended September 30, 2004 and
2005:
39
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Revenues ................................... $108 $116 $324 $362
---- ---- ---- ----
Expenses:
Natural gas ............................. 6 -- 33 25
Operation and maintenance ............... 52 47 122 121
Depreciation and amortization ........... 11 12 33 34
Taxes other than income taxes ........... 4 5 13 14
---- ---- ---- ----
Total expenses ....................... 73 64 201 194
---- ---- ---- ----
Operating Income ........................... $ 35 $ 52 $123 $168
==== ==== ==== ====
Throughput (in Bcf):
Natural Gas Sales ....................... 1 -- 8 4
Transportation .......................... 181 199 658 700
Gathering ............................... 79 92 233 262
Elimination (1) ......................... -- (1) (5) (4)
---- ---- ---- ----
Total Throughput ..................... 261 290 894 962
==== ==== ==== ====
----------
(1) Elimination of volumes both transported and sold.
THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2004
Our Pipelines and Gathering business segment reported operating income of
$52 million for the three months ended September 30, 2005 compared to $35
million for the same period in 2004. Operating margins (revenues less natural
gas costs) increased by $14 million primarily due to increased demand for
certain transportation and ancillary services ($13 million) and increased
throughput and demand for services related to our core gas gathering operations
($6 million), partially offset by reductions in project-related revenues ($6
million). Additionally, operation and maintenance expenses decreased by $5
million primarily due to a reduction in project-related expenses ($6 million),
offset by increased litigation costs ($4 million) recorded in the third quarter
of 2005.
NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2004
Our Pipelines and Gathering business segment reported operating income of
$168 million for the nine months ended September 30, 2005 compared to $123
million for the same period in 2004. Operating margins (revenues less natural
gas costs) increased by $46 million primarily due to increased demand for
certain transportation and ancillary services ($31 million), increased
throughput and demand for services related to our core gas gathering operations
($20 million), partially offset by reductions in project-related revenues ($10
million). Additionally, operation and maintenance expenses decreased by $1
million primarily due to a reduction in project-related expenses ($9 million),
offset by increased litigation costs ($4 million) recorded in the third quarter
of 2005.
OTHER OPERATIONS
The following table shows the operating loss of our Other Operations
business segment for the three and nine months ended September 30, 2004 and
2005:
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2004 2005 2004 2005
---- ---- ---- ----
(IN MILLIONS)
Revenues.................................... $ 2 $4 $ 8 $ 15
Expenses.................................... 6 2 25 27
--- --- ---- ----
Operating Income (Loss)..................... $(4) $2 $(17) $(12)
=== === ==== ====
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-
40
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 an after-tax loss of $259 million and $154 million for the
three and nine months ended September 30, 2004, respectively, related to the
operations of Texas Genco. We recorded an after-tax loss of $3 million for the
nine months ended September 30, 2005. General corporate overhead, previously
allocated to Texas Genco from CenterPoint Energy, was $5 million and $15 million
for the three and nine months ended September 30, 2004, respectively, and was
less than $1 million for the nine months ended September 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 $14 million and $38 million
for the three and nine months ended September 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 September 30, 2005 filed on November 3, 2005.
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 nine months ended
September 30, 2004 and 2005:
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2004 2005
----- -----
(IN MILLIONS)
Cash provided by (used in):
Operating activities..................... $ 753 $ 275
Investing activities..................... (691) 218
Financing activities..................... (129) (496)
CASH PROVIDED BY OPERATING ACTIVITIES
Net cash provided by operating activities in the first nine months of 2005
decreased $478 million compared to the same period in 2004 primarily due to
increased tax payments of $481 million, the majority of which related to the tax
payment in the second quarter of 2005 associated with the sale of Texas Genco
and decreased cash provided by Texas Genco of $449 million, offset by increased
operating income, higher net accounts receivable/payable primarily 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 $909 million in the
first nine 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 in April 2005 and cash of Texas Genco of $316 million, partially
offset by increased capital expenditures of $101 million.
41
CASH USED IN FINANCING ACTIVITIES
In the first nine months of 2005, debt payments exceeded net loan proceeds
by $408 million. During the first nine months of 2004, debt payments exceeded
net loan proceeds by $35 million. Additionally, dividends paid in the first nine
months of 2005 were $13 million higher than in the same period of 2004.
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 three
months of 2005 include the following:
- approximately $223 million of capital expenditures;
- dividend payments on CenterPoint Energy common stock and debt service
payments;
- contributions to benefit plans; and
- $1.3 billion of maturing long-term debt.
We expect that borrowings under our credit facilities and anticipated cash
flows from operations will be sufficient to meet our cash needs for the next
twelve months. 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 expects
to utilize its $1.31 billion credit facility to refinance the $1.31 billion term
loan at its maturity on November 11, 2005. 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.
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.
On October 25, 2005, CenterPoint Energy Gas Transmission Company (CEGT), a
subsidiary of CERC Corp., executed a definitive Precedent Agreement with XTO
Energy Inc. (XTO) for CEGT to transport approximately 600 million cubic feet per
day of XTO's natural gas production for ten years. To fulfill the requirements
of the agreement, CEGT will construct a new 168-mile pipeline between Carthage,
Texas and its Perryville Hub in northeast Louisiana. The $375 million pipeline
will have an initial design capacity of approximately one Bcf per day. Pending
authorization by FERC, the pipeline could be in service as early as the winter
of 2006-2007. This agreement is expected to cause an increase in our estimated
capital requirements of approximately $5 million, $353 million and $17 million
in 2005, 2006 and 2007, respectively, for our Pipelines and Gathering business
segment from what was previously disclosed in the Center Point Energy Form 10-K.
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 September 30, 2005, CERC
had $141 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
42
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 87.5 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
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.
CenterPoint Houston also established a $1.31 billion credit facility in
March 2005. This facility can be utilized only to refinance CenterPoint
Houston's $1.31 billion term loan maturing on November 11, 2005. Drawings may be
made under this credit facility until November 16, 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.
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.
43
As of November 1, 2005, we had the following credit facilities (in
millions):
AMOUNT UTILIZED AT
DATE EXECUTED COMPANY SIZE OF FACILITY NOVEMBER 1, 2005 TERMINATION DATE
------------- ------- ---------------- ------------------ ----------------
March 7, 2005 CenterPoint Energy $1,000 $271 (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, $40 million
outstanding under the revolving credit facility and $204 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. As of September 30, 2005, $187 million of commercial paper
was outstanding. 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 September 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 $500 million principal amount of debt
securities.
Temporary Investments. On September 30, 2005, we had temporary investments
of $116 million.
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).
Impact on Liquidity of a Downgrade in Credit Ratings. As of November 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- Stable BBB- Stable
CenterPoint Houston Senior Secured Debt (First
Mortgage Bonds).................................. Baa2 Stable BBB Stable BBB+ Stable
CERC Corp. Senior Debt.............................. Baa3 Stable BBB Stable BBB Stable
----------
(1) A "stable" outlook from Moody's indicates that Moody's does not expect to
put the rating on review for an upgrade or downgrade within 18 months from
when the outlook was assigned or last affirmed.
(2) An S&P rating outlook assesses the potential direction of a long-term
credit rating over the intermediate to longer term.
(3) A "stable" outlook from Fitch encompasses a one-to-two-year horizon as to
the likely ratings direction.
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
44
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 under the 1935 Act 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.
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
September 30, 2005, unsecured credit limits extended to CES by counterparties
could aggregate $115 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.
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 November
1, 2005, we had issued six series of senior notes aggregating $1.4 billion in
principal amount under this indenture. A default by CenterPoint Energy would not
trigger a default under our 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;
- increases in interest expense in connection with debt refinancings and
borrowings under credit facilities;
- various regulatory actions;
45
- 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;
- slower customer payments and increased write-offs of receivables due
to higher gas prices;
- cash payments in connection with the exercise of contingent conversion
rights of holders of convertible debt;
- contributions to benefit plans;
- restoration costs and revenue losses resulting from natural disasters
such as hurricanes; 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 September 30, 2005 filed on November 3, 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 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 August 8, 2005,
President Bush signed into law the Energy Act. Under that legislation, the 1935
Act is repealed effective February 8, 2006. 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 grants to FERC authority to require
holding companies and their subsidiaries to maintain certain books and records
and make them available for review by FERC and state regulatory authorities. The
Energy Act requires FERC to issue regulations to implement its jurisdiction
under the Energy Act, and on September 16, 2005, FERC issued proposed rules for
public comment. It is presently unknown what, if any, specific obligations under
those rules may be imposed on us and our subsidiaries as a result of that
rulemaking.
The June 2005 Financing 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
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 October 31, 2005:
- We are not authorized to issue any additional debt or preferred
securities;
- CenterPoint Houston is authorized to issue an aggregate $47 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
46
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 February 8, 2006.
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 September 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 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. 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. On
August 31, 2005, our board of directors declared a dividend of $0.07 per common
share, payable on September 30, 2005, to shareholders of record as of the close
of business on September 12, 2005. The dividends declared and paid for the first
three quarters of 2005 totaled $0.34 per share versus $0.30 per share for the
first three quarters of 2004.
On October 24, 2005, our board of directors declared a dividend of $0.06
per common share, payable on December 9, 2005, to shareholders of record as of
the close of business on November 16, 2005.
In addition, the SEC generally expects registered holding companies to
achieve a ratio of common equity to total capitalization of 30%. At September
30, 2005, our ratio was 14% (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%, 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 September 30, 2005, CenterPoint Houston's and CERC's ratios
were 43% (excluding transition bonds) and 57%, respectively.
Other Factors Affecting the Upstreaming of Cash from Subsidiaries.
CenterPoint Houston's $1.31 billion term loan maturing in November 2005, 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. If the $1.31 billion credit facility established in March 2005 is drawn in
November 2005 to repay the term loan, then (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.
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.
47
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 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 $2.2 billion of recoverable electric generation-related
regulatory assets as of September 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 related to the regulatory asset.
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"
(SFAS No. 142). 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.
We perform our goodwill impairment test at least annually and evaluate
goodwill when events or changes in circumstances indicate that the carrying
value of these assets may not be recoverable. Upon adoption of SFAS No.
48
142, we initially selected January 1 as our annual goodwill impairment testing
date. Since the time we selected the January 1 date, our year-end closing and
reporting process has been truncated in order to meet the accelerated periodic
reporting requirements of the SEC resulting in significant constraints on our
human resources at year-end and during our first fiscal quarter. Accordingly, in
order to meet the accelerated reporting deadlines and to provide adequate time
to complete the analysis each year, beginning in the third quarter of 2005, we
changed the date on which we perform our annual goodwill impairment test from
January 1 to July 1. We believe the July 1 alternative date will alleviate the
resource constraints that exist during the first quarter and allow us to utilize
additional resources in conducting the annual impairment evaluation of goodwill.
We performed the test at July 1, 2005, and determined that no impairment charge
for goodwill was required. The change is not intended to delay, accelerate or
avoid an impairment charge. We believe that this accounting change is an
alternative accounting principle that is preferable under the circumstances.
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 September 30, 2005. This conclusion is
different than the conclusion disclosed in the original filing of our Quarterly
Report on Form 10-Q for the period ended September 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
September 30, 2005, management has re-evaluated the effectiveness of our
disclosure controls and procedures.
49
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
nine months ended September 30, 2004 were each overstated by approximately $102
million and $335 million, respectively. For the three and nine months ended
September 30, 2005, revenues and natural gas expenses were each overstated by
approximately $145 million and $402 million, respectively, for the same reason
and management concluded that a restatement of the consolidated financial
statements for the three and nine months ended September 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 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 September 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 September 30, 2005,
we took the remedial action described above.
50
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
September 30, 2005 as filed on November 3, 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 of CenterPoint Energy's Registration 3-69502 3.1
Incorporation of CenterPoint Energy Statement on Form S-4
3.1.2 -- Articles of Amendment to Amended CenterPoint Energy's Form 10-K for the 1-31447 3.1.1
and Restated Articles of year ended December 31, 2001
Incorporation of CenterPoint Energy
3.2 -- 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 Stock CenterPoint Energy's Registration 3-69502 4.1
Certificate Statement on Form S-4
4.2 -- Rights Agreement dated January 1, CenterPoint Energy's Form 10-K for the 1-31447 4.2
2002, between CenterPoint Energy year ended December 31, 2001
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 Exhibit 4.1.1, CenterPoint Energy's Form 10-Q for the 1-31447 10.7
dated as of September 3, 2003 quarter ended September 30, 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, among March 7, 2005
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, among June 29, 2005
CERC Corp., as Borrower, and the
Initial Lenders named therein, as
Initial Lenders
51
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
++18.1 -- Preferability Letter re: Change in
Accounting Principle
+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 -- Third Amendment to CenterPoint
Energy, Inc. Savings Trust,
effective as of October 27, 2004
++99.2 -- CenterPoint Energy Savings Plan, as
amended and restated effective
January 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)
52
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
53
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
September 30, 2005 as filed on November 3, 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 of CenterPoint Energy's Registration 3-69502 3.1
Incorporation of CenterPoint Energy Statement on Form S-4
3.1.2 -- Articles of Amendment to Amended CenterPoint Energy's Form 10-K for the 1-31447 3.1.1
and Restated Articles of year ended December 31, 2001
Incorporation of CenterPoint Energy
3.2 -- 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 Stock CenterPoint Energy's Registration 3-69502 4.1
Certificate Statement on Form S-4
4.2 -- Rights Agreement dated January 1, CenterPoint Energy's Form 10-K for the 1-31447 4.2
2002, between CenterPoint Energy year ended December 31, 2001
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 Exhibit 4.1.1, CenterPoint Energy's Form 10-Q for the 1-31447 10.7
dated as of September 3, 2003 quarter ended September 30, 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, among March 7, 2005
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, among June 29, 2005
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
++18.1 -- Preferability Letter re: Change in
Accounting Principle
+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 -- Third Amendment to CenterPoint
Energy, Inc. Savings Trust,
effective as of October 27, 2004
++99.2 -- CenterPoint Energy Savings Plan, as
amended and restated effective
January 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)