UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006
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)
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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 a large accelerated filer,
an accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check
one):
Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ]
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 October 31, 2006, CenterPoint Energy, Inc. had 312,839,095 shares
of common stock outstanding, excluding 166 shares held as treasury stock.
CENTERPOINT ENERGY, INC.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2006
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements........................................... 1
Condensed Statements of Consolidated Income
Three Months and Nine Months Ended September 30, 2005 and 2006
(unaudited)...................................................... 1
Condensed Consolidated Balance Sheets
December 31, 2005 and September 30, 2006 (unaudited)............. 2
Condensed Statements of Consolidated Cash Flows
Nine Months Ended September 30, 2005 and 2006 (unaudited)........ 4
Notes to Unaudited Condensed Consolidated Financial
Statements....................................................... 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations......................... 27
Item 3. Quantitative and Qualitative Disclosures about Market Risk..... 42
Item 4. Controls and Procedures........................................ 43
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................. 43
Item 1A. Risk Factors.................................................. 44
Item 5. Other Information............................................. 44
Item 6. Exhibits...................................................... 44
i
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
From time to time we make statements concerning our expectations, beliefs,
plans, objectives, goals, strategies, future events or performance and
underlying assumptions and other statements that are not historical facts. These
statements are "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995. Actual results may differ materially
from those expressed or implied by these statements. You can generally identify
our forward-looking statements by the words "anticipate," "believe," "continue,"
"could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective,"
"plan," "potential," "predict," "projection," "should," "will," or other similar
words.
We have based our forward-looking statements on our management's beliefs
and assumptions based on information available to our management at the time the
statements are made. We caution you that assumptions, beliefs, expectations,
intentions and projections about future events may and often do vary materially
from actual results. Therefore, we cannot assure you that actual results will
not differ materially from those expressed or implied by our forward-looking
statements.
The following are some of the factors that could cause actual results to
differ materially from those expressed or implied in forward-looking statements:
- the timing and amount of our recovery of the true-up components,
including, in particular, the results of appeals to the courts of
determinations on rulings obtained to date;
- state and federal legislative and regulatory actions or developments,
including deregulation, re-regulation, changes in or application of
laws or regulations applicable to other aspects of our business;
- timely and appropriate rate actions and increases, allowing recovery
of costs and a reasonable return on investment;
- 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;
- the timing and extent of changes in natural gas basis differentials;
- commercial bank and financial market conditions, our access to
capital, the cost of such capital, 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);
ii
- the ability of RRI and its subsidiaries to satisfy their obligations
to us, including indemnity obligations, or in connection with the
contractual arrangements pursuant to which we are a guarantor;
- the outcome of litigation brought by or against us;
- 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 we discuss in "Risk Factors" in Item 1A of Part I of our
Annual Report on Form 10-K for the year ended December 31, 2005, which
is incorporated herein by reference and in "Risk Factors' in Item 1A
of Part II of this Quarterly Report on Form 10-Q.
You should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement.
iii
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------- ---------------
2005 2006 2005 2006
------ ------ ------ ------
REVENUES ...................................................... $2,073 $1,935 $6,510 $6,855
------ ------ ------ ------
EXPENSES:
Natural gas ................................................ 1,277 1,058 4,161 4,286
Operation and maintenance .................................. 336 347 974 1,018
Depreciation and amortization .............................. 145 159 411 452
Taxes other than income taxes .............................. 90 87 277 289
------ ------ ------ ------
Total ................................................... 1,848 1,651 5,823 6,045
------ ------ ------ ------
OPERATING INCOME .............................................. 225 284 687 810
------ ------ ------ ------
OTHER INCOME (EXPENSE):
Gain (loss) on Time Warner investment ...................... 30 20 (29) 17
Gain (loss) on indexed debt securities ..................... (29) (12) 34 (13)
Interest and other finance charges ......................... (168) (120) (521) (353)
Interest on transition bonds ............................... (9) (32) (27) (98)
Return on true-up balance .................................. 35 -- 104 --
Other, net ................................................. 7 12 18 27
------ ------ ------ ------
Total ................................................... (134) (132) (421) (420)
------ ------ ------ ------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM ......................................... 91 152 266 390
Income tax expense ......................................... (41) (69) (122) (25)
------ ------ ------ ------
INCOME FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM ... 50 83 144 365
DISCONTINUED OPERATIONS:
Income from Texas Genco, net of tax ........................ -- -- 11 --
Loss on Disposal of Texas Genco, net of tax ............... -- -- (14) --
------ ------ ------ ------
Total ................................................... -- -- (3) --
------ ------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM .............................. 50 83 141 365
EXTRAORDINARY ITEM, NET OF TAX ................................ -- -- 30 --
------ ------ ------ ------
NET INCOME .................................................... $ 50 $ 83 $ 171 $ 365
====== ====== ====== ======
BASIC EARNINGS PER SHARE:
Income from Continuing Operations .......................... $ 0.16 $ 0.27 $ 0.46 $ 1.17
Discontinued Operations, net of tax ........................ -- -- (0.01) --
Extraordinary Item, net of tax ............................. -- -- 0.10 --
------ ------ ------ ------
Net Income ................................................. $ 0.16 $ 0.27 $ 0.55 $ 1.17
====== ====== ====== ======
DILUTED EARNINGS PER SHARE:
Income from Continuing Operations .......................... $ 0.15 $ 0.26 $ 0.43 $ 1.14
Discontinued Operations, net of tax ........................ -- -- (0.01) --
Extraordinary Item, net of tax ............................. -- -- 0.09 --
------ ------ ------ ------
Net Income ................................................. $ 0.15 $ 0.26 $ 0.51 $ 1.14
====== ====== ====== ======
See Notes to the Company's Interim Condensed Financial Statements
1
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS OF DOLLARS)
(UNAUDITED)
ASSETS
DECEMBER 31, SEPTEMBER 30,
2005 2006
------------ -------------
CURRENT ASSETS:
Cash and cash equivalents .................................. $ 74 $ 285
Investment in Time Warner common stock ..................... 377 395
Accounts receivable, net ................................... 1,098 716
Accrued unbilled revenues .................................. 608 226
Natural gas inventory ...................................... 294 286
Materials and supplies ..................................... 88 96
Non-trading derivative assets .............................. 131 141
Taxes receivable ........................................... 53 --
Prepaid expenses and other current assets .................. 168 421
------- -------
Total current assets .................................... 2,891 2,566
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment .............................. 11,558 12,106
Less accumulated depreciation and amortization ............. (3,066) (3,264)
------- -------
Property, plant and equipment, net ...................... 8,492 8,842
------- -------
OTHER ASSETS:
Goodwill ................................................... 1,709 1,709
Other intangibles, net ..................................... 56 45
Regulatory assets .......................................... 2,955 2,838
Non-trading derivative assets .............................. 104 47
Other ...................................................... 909 926
------- -------
Total other assets ...................................... 5,733 5,565
------- -------
TOTAL ASSETS ......................................... $17,116 $16,973
======= =======
See Notes to the Company's Interim Condensed 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,
2005 2006
------------ -------------
CURRENT LIABILITIES:
Current portion of transition bond long-term debt .......... $ 73 $ 147
Current portion of other long-term debt .................... 266 1,093
Indexed debt securities derivative ......................... 292 305
Accounts payable ........................................... 1,161 547
Taxes accrued .............................................. 167 195
Interest accrued ........................................... 122 127
Non-trading derivative liabilities ......................... 43 179
Accumulated deferred income taxes, net ..................... 385 401
Other ...................................................... 505 382
------- -------
Total current liabilities ............................... 3,014 3,376
------- -------
OTHER LIABILITIES:
Accumulated deferred income taxes, net ..................... 2,474 2,403
Unamortized investment tax credits ......................... 46 41
Non-trading derivative liabilities ......................... 35 110
Benefit obligations ........................................ 475 455
Regulatory liabilities ..................................... 728 826
Other ...................................................... 480 290
------- -------
Total other liabilities ................................. 4,238 4,125
------- -------
LONG-TERM DEBT:
Transition bonds ........................................... 2,407 2,260
Other ...................................................... 6,161 5,645
------- -------
Total long-term debt .................................... 8,568 7,905
------- -------
COMMITMENTS AND CONTINGENCIES (NOTE 11)
SHAREHOLDERS' EQUITY:
Common stock (310,324,739 shares and 312,325,790 shares
outstanding at December 31, 2005 and September 30,
2006, respectively) ..................................... 3 3
Additional paid-in capital ................................. 2,931 2,959
Accumulated deficit ........................................ (1,600) (1,375)
Accumulated other comprehensive loss ....................... (38) (20)
------- -------
Total shareholders' equity .............................. 1,296 1,567
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ........... $17,116 $16,973
======= =======
See Notes to the Company's Interim Condensed Financial Statements
3
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(MILLIONS OF DOLLARS)
(UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2005 2006
----- -----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................. $ 171 $ 365
Discontinued operations, net of tax ........................ 3 --
Extraordinary item, net of tax ............................. (30) --
----- -----
Income from continuing operations .......................... 144 365
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation and amortization ........................... 411 452
Amortization of deferred financing costs ................ 59 37
Deferred income taxes ................................... 162 (81)
Tax and interest reserves reductions related to
ZENS and ACES ........................................ -- (119)
Investment tax credit ................................... (6) (6)
Unrealized loss (gain) on Time Warner investment ........ 29 (17)
Unrealized loss (gain) on indexed debt securities ....... (34) 13
Write-down of natural gas inventory ..................... -- 56
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net ....... 316 788
Inventory ............................................ (140) (52)
Taxes receivable ..................................... -- 53
Accounts payable ..................................... (28) (640)
Fuel cost over (under) recovery/surcharge ............ (69) 106
Non-trading derivatives, net ......................... 8 (35)
Margin deposits, net ................................. 78 (176)
Short-term risk management activities, net ........... (19) 3
Interest and taxes accrued ........................... (440) 30
Net regulatory assets ................................ (166) 65
Other current assets ................................. (39) (87)
Other current liabilities ............................ 8 (48)
Other assets ......................................... (2) 30
Other liabilities .................................... 37 (16)
Other, net .............................................. 4 7
----- -----
Net cash provided by operating activities of
continuing operations .......................... 313 728
Net cash used in operating activities of
discontinued operations ........................ (38) --
----- -----
Net cash provided by operating activities ......... 275 728
----- -----
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ....................................... (506) (641)
Proceeds from sale of Texas Genco .......................... 700 --
Decrease in restricted cash of Texas Genco ................. 383 --
Purchase of minority interest in Texas Genco ............... (383) --
Decrease in cash of Texas Genco ............................ 24 --
Increase in restricted cash of transition bond companies ... -- (6)
Other, net ................................................. -- 21
----- -----
Net cash provided by (used in) investing
activities ..................................... 218 (626)
----- -----
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings, net ..................... 75 --
Proceeds from issuance of long-term debt ................... -- 324
Commercial paper, net ...................................... 187 (3)
Long-term revolving credit facilities, net ................. (239) --
Payments of long-term debt ................................. (424) (83)
Debt issuance costs ........................................ (7) (4)
Payment of common stock dividends .......................... (105) (140)
Proceeds from issuance of common stock, net ................ 14 12
Other ...................................................... 3 3
----- -----
Net cash provided by (used in) financing
activities ..................................... (496) 109
----- -----
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS .......... (3) 211
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD .............. 165 74
----- -----
CASH AND CASH EQUIVALENTS AT END OF PERIOD .................... $ 162 $ 285
===== =====
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest, net of capitalized interest ...................... $ 515 $ 423
Income taxes ............................................... 464 150
Non-cash transactions:
Increase in accounts payable related to capital
expenditures ............................................ -- 21
See Notes to the Company's Interim Condensed 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 (Form 10-Q) of
CenterPoint Energy, Inc. are the condensed consolidated interim financial
statements and notes (Interim Condensed Financial Statements) of CenterPoint
Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy, or the
Company). The Interim Condensed 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, 2005
(CenterPoint Energy Form 10-K).
Background. CenterPoint Energy is a public utility holding company, created
on August 31, 2002 as part of a corporate restructuring of Reliant Energy,
Incorporated (Reliant Energy) that implemented certain requirements of the Texas
Electric Choice Plan (Texas electric restructuring law).
CenterPoint Energy was a registered public utility holding company under
the Public Utility Holding Company Act of 1935, as amended (1935 Act). The
Energy Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February
8, 2006, and since that date the Company and its subsidiaries have no longer
been subject to restrictions imposed under the 1935 Act. The Energy Act includes
a new Public Utility Holding Company Act of 2005 (PUHCA 2005) which 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 the FERC and state regulatory authorities in
certain circumstances. On December 8, 2005, the FERC issued rules implementing
PUHCA 2005. Pursuant to those rules, on June 14, 2006, the Company filed with
the FERC the required notification of its status as a public utility holding
company. On October 19, 2006, the FERC adopted additional rules regarding
maintenance of books and records by utility holding companies and additional
reporting and accounting requirements for centralized service companies that
make allocations to public utilities regulated by the FERC under the Federal
Power Act. Although the Company provides services to its subsidiaries through a
service company, its service company is not subject to the service company
rules.
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, 2006, 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. Through wholly owned subsidiaries, CERC Corp. owns two
interstate natural gas pipelines and gas gathering systems and
provides various ancillary services. Through a wholly owned
subsidiary, CERC Corp. also offers variable and fixed-price physical
natural gas supplies primarily to commercial and industrial customers
and electric and gas utilities.
Basis of Presentation. The preparation of financial statements in
conformity with accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimates.
The Company's Interim Condensed 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 Income are not necessarily indicative of amounts expected for a
full-year period due to the effects of, among other things, (a) seasonal
fluctuations in demand for energy and energy services, (b) changes in energy
commodity prices, (c)
5
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 relate to the establishment of the Competitive Natural Gas
Sales and Services business segment as a new reportable business segment during
the fourth quarter of 2005 as discussed in Note 13 and do not affect net income.
(2) DISCONTINUED OPERATIONS
In July 2004, the Company announced its agreement to sell its majority
owned subsidiary, Texas Genco Holdings, Inc. (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, following receipt of approval from the
Nuclear Regulatory Commission (NRC).
The Company recorded an after-tax loss of $3 million for the nine-month
period ended September 30, 2005 related to the operations of Texas Genco.
General corporate overhead, previously allocated to Texas Genco from the
Company, was less than $1 million for the nine-month period ended September 30,
2005. These amounts were not eliminated by the sale of Texas Genco and have been
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 Condensed Financial Statements present these operations as
discontinued operations in accordance with SFAS No. 144.
Revenues related to Texas Genco included in discontinued operations for the
nine months ended September 30, 2005 were $62 million. Income from these
discontinued operations for the nine months ended September 30, 2005 is reported
net of income tax expense of $4 million.
(3) EMPLOYEE BENEFIT PLANS
The Company's net periodic cost includes the following components relating
to pension and postretirement benefits:
THREE MONTHS ENDED SEPTEMBER 30,
-----------------------------------------------------
2005 2006
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
Service cost ............................ $ 9 $ 1 $ 9 $ 1
Interest cost ........................... 24 6 24 6
Expected return on plan assets .......... (34) (3) (36) (3)
Amortization of prior service cost ...... (2) 1 (1) 1
Amortization of net loss ................ 11 -- 12 --
Amortization of transition obligation ... -- 1 -- 1
Other ................................... -- 1 -- --
---- --- ---- ---
Net periodic cost ....................... $ 8 $ 7 $ 8 $ 6
==== === ==== ===
6
NINE MONTHS ENDED SEPTEMBER 30,
-----------------------------------------------------
2005 2006
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
Service cost ............................ $ 26 $ 2 $ 27 $ 2
Interest cost ........................... 72 20 72 19
Expected return on plan assets .......... (103) (9) (107) (9)
Amortization of prior service cost ...... (5) 2 (5) 2
Amortization of net loss ................ 33 -- 36 --
Amortization of transition obligation ... -- 5 -- 5
Benefit enhancement ..................... -- -- 8 1
Other ................................... -- 1 -- --
----- --- ----- ---
Net periodic cost ....................... $ 23 $21 $ 31 $20
===== === ===== ===
The Company expects to contribute approximately $26 million to its
postretirement benefits plan in 2006, of which $20 million had been contributed
as of September 30, 2006.
Contributions to the pension plan are not required in 2006. 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-month periods ended September 30,
2005 and 2006 and $5 million for each of the nine-month periods ended September
30, 2005 and 2006.
On January 5, 2006, the Company offered a Voluntary Early Retirement
Program (VERP) to approximately 200 employees who were age 55 or older with at
least five years of service as of February 28, 2006. The election period was
from January 5, 2006 through February 28, 2006. For those electing to accept the
VERP, three years of age and service was added to their qualified pension plan
benefit and three years of service was added to their postretirement benefit. An
additional pension and postretirement expense of approximately $9 million was
recorded in the first quarter of 2006 and is reflected in the table above as a
benefit enhancement.
(4) NEW ACCOUNTING PRONOUNCEMENTS
In September 2006, the Financial Accounting Standards Board (FASB) issued
SFAS No. 157, "Fair Value Measurements" (SFAS No. 157). SFAS No. 157
establishes a framework for measuring fair value and requires expanded
disclosure about the information used to measure fair value. The statement
applies whenever other statements require, or permit, assets or liabilities to
be measured at fair value. The statement does not expand the use of fair value
accounting in any new circumstances and is effective for the Company for the
year ended December 31, 2008 and for interim periods included in that year, with
early adoption encouraged. The Company does not expect the adoption of this
statement to have a material impact on its financial condition or results of
operations.
In September 2006, the FASB issued SFAS No. 158, "Employers' Accounting for
Defined Benefit Pension and Other Postretirement Plans - An Amendment of FASB
Statements No. 87, 88, 106 and 132(R)" (SFAS No. 158). SFAS No. 158 requires the
Company, as the sponsor of a single employer defined benefit plan, to (a)
recognize on its Balance Sheets as an asset a pension plan's over-funded status
or as a liability such plan's under-funded status, (b) measure a pension plan's
assets and obligations that determine its funded status as of the end of the
Company's fiscal year and (c) recognize changes in the funded status of a
pension plan or postretirement plan in the year in which the changes occur
through adjustments to other comprehensive income. SFAS No. 158 is effective for
the Company for the year ended December 31, 2006.
SFAS No. 158 is expected to require a significant non-cash charge to the
Company's equity to recognize previously unrecognized costs related to its
pension and postretirement plans. The amount of the charge is unknown at this
time due to possible changes in discount rates and investment returns through
year-end. However, if SFAS No. 158 had been adopted as of December 31, 2005, the
charge to comprehensive income would have been approximately $509 million (net
of tax). The adoption of SFAS No. 158 will not impact the Company's compliance
with debt covenants.
In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, "Accounting
for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109"
(FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes
recognized in an enterprise's financial statements in accordance with FASB
Statement No. 109, "Accounting for Income Taxes." FIN 48 prescribes a
recognition threshold and measurement attribute for the financial statement
recognition and measurement of a tax position taken or expected to be taken in a
tax return. FIN 48 also provides guidance on derecognition, classification,
interest and penalties, accounting in interim periods, disclosure, and
transition. The provisions of FIN 48 are effective for fiscal years beginning
after December 15, 2006. The Company expects to adopt FIN 48 in the first
quarter of 2007 and is currently evaluating the impact the adoption will have on
the Company's financial position.
7
(5) REGULATORY MATTERS
(A) RECOVERY OF TRUE-UP BALANCE
In March 2004, CenterPoint Houston filed its true-up application with the
Public Utility Commission of Texas (Texas Utility Commission), requesting
recovery of $3.7 billion, excluding interest, as allowed under the Texas
electric restructuring law. 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. In August
2005, the court issued its final judgment on the various appeals. In its
judgment, the court affirmed most aspects of the True-Up Order, but reversed two
of the Texas Utility Commission's rulings. The judgment would have the effect of
restoring approximately $650 million, plus interest, of the $1.7 billion the
Texas Utility Commission had disallowed from CenterPoint Houston's initial
request. CenterPoint Houston and other parties appealed the district court's
judgment. Oral argument to the 3rd Court of Appeals in Austin is not expected to
occur before late November 2006. No amounts related to the district court's
judgment have been recorded in the consolidated financial statements.
Among the issues raised in CenterPoint Houston's appeal of the True-Up
Order is the Texas Utility Commission's reduction of CenterPoint Houston's
stranded cost recovery by approximately $146 million for the present value of
certain deferred tax benefits associated with its former electric generation
assets. Such reduction was considered in the Company's recording of an after-tax
extraordinary loss of $977 million in the last half of 2004. The Company
believes that the Texas Utility Commission based its order on proposed
regulations issued by the Internal Revenue Service (IRS) in March 2003 related
to those tax benefits. Those proposed regulations would have allowed utilities
owning assets that were deregulated before March 4, 2003 to make a retroactive
election to pass the benefits of Accumulated Deferred Investment Tax Credits
(ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers.
However, in December 2005, the IRS withdrew those proposed normalization
regulations and issued new proposed regulations that do not include the
provision allowing a retroactive election to pass the tax benefits back to
customers. In a recent Private Letter Ruling (PLR) issued to a Texas utility on
facts similar to CenterPoint Houston's, the IRS, without referencing its
proposed regulations, ruled that a normalization violation would occur if ADITC
and EDFIT were required to be returned to customers. The Company intends to seek
a PLR asking the IRS whether the Texas Utility Commission's order reducing the
Company's stranded cost recovery by $146 million for ADITC and EDFIT would cause
a normalization violation. If the Company's PLR determines that such reduction
would cause a normalization violation with respect to the ADITC and the Texas
Utility Commission's order relating to such reduction is not reversed or
otherwise modified, the IRS could require the Company to pay an amount equal to
CenterPoint Houston's unamortized ADITC balance as of the date that the
normalization violation is deemed to have occurred. In addition, if a
normalization violation with respect to EDFIT is deemed to have occurred and the
Texas Utility Commission's order relating to such reduction is not reversed or
otherwise modified, the IRS could deny CenterPoint Houston the ability to elect
accelerated tax depreciation benefits beginning in the taxable year that the
normalization violation is deemed to have occurred. If a normalization violation
should ultimately be found to exist, it could have an adverse impact on the
Company's results of operations, financial condition and cash flows. However,
the Company and CenterPoint Houston are vigorously pursuing the appeal of this
issue and will seek other relief from the Texas Utility Commission to avoid a
normalization violation. The Texas Utility Commission has not previously
required a company subject to its jurisdiction to take action that would result
in a normalization violation.
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). Pursuant to a financing order issued by
the Texas Utility Commission in March 2005 and affirmed in August 2005 by the
Travis County District Court, in December 2005, a subsidiary of CenterPoint
Houston issued $1.85 billion in transition bonds with interest rates ranging
from 4.84 percent to 5.30 percent and final maturity dates ranging from February
2011 to August 2020. Through issuance of the transition bonds, CenterPoint
Houston recovered approximately $1.7 billion of the true-up balance determined
in the True-Up Order plus interest through the date on which the bonds were
issued.
In July 2005, CenterPoint Houston received an order from the Texas Utility
Commission allowing it to implement a CTC designed to collect approximately $596
million over 14 years plus interest at an annual rate of
8
11.075 percent (CTC Order). The CTC Order authorizes CenterPoint Houston to
impose a charge on retail electric providers (REPs) 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 without a return through a separate tariff rider
(Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective
September 13, 2005 and began recovering approximately $620 million. Effective
September 13, 2005, the return on the CTC portion of the true-up balance is
included in CenterPoint Houston's tariff-based revenues. During the three and
nine months ended September 30, 2006, CenterPoint Houston recognized
approximately $14 million and $44 million, respectively, in operating income
from the CTC. Additionally, during the three and nine months ended September 30,
2006, CenterPoint Houston recognized approximately $4 million and $10 million,
respectively, of the allowed equity return not previously recorded. As of
September 30, 2006, the Company had not recorded an allowed equity return of
$237 million on its true-up balance because such return is being recognized as
it is recovered in the future.
Certain parties appealed the CTC Order to the 98th District Court in Travis
County. In May 2006, the district court issued a judgment reversing the CTC
Order in three respects. First, the court ruled that the Texas Utility
Commission had improperly relied on provisions of its rule dealing with the
interest rate applicable to CTC amounts. The district court reached that
conclusion on the grounds that the Texas Supreme Court had previously
invalidated that entire section of the rule. Second, the district court reversed
the Texas Utility Commission's ruling that allows CenterPoint Houston to recover
through the CTC the costs (approximately $5 million) for a panel appointed by
the Texas Utility Commission in connection with the valuation of the Company's
electric generation assets. Finally, the district court accepted the contention
of one party that the CTC should not be allocated to retail customers who have
switched to new on-site generation. The Company and CenterPoint Houston disagree
with the district court's conclusions and in May 2006 appealed the judgment to
the court of appeals and, if required, plan to seek further review from the
Texas Supreme Court. All briefs in the appeal have been filed. CenterPoint
Houston has requested oral argument, but no date has been set. Pending
completion of judicial review and any action required by the Texas Utility
Commission following a remand from the courts, the CTC remains in effect. The
11.075 percent interest rate in question was applicable from the implementation
of the CTC Order on September 13, 2005 until August 1, 2006, the effective date
of the implementation of a new CTC in compliance with the new rule discussed
below. The ultimate outcome of this matter cannot be predicted at this time.
However, the Company does not expect the disposition of this matter to have a
material adverse effect on the Company's or CenterPoint Houston's financial
condition, results of operations or cash flows.
In June 2006, the Texas Utility Commission adopted the revised rule
governing the carrying charges on unrecovered true-up balances, as recommended
by its staff (Staff). The rule, which applies to CenterPoint Houston, reduces
carrying costs on the unrecovered CTC balance prospectively from 11.075 percent
to a weighted average cost of capital of 8.06 percent. The annualized impact on
operating income is approximately $18 million per year for the first year with
lesser impacts in subsequent years. On July 17, 2006, CenterPoint Houston made a
compliance filing necessary to implement the rule changes effective August 1,
2006 per the settlement agreement discussed in Note 5(d) below.
(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 in 2003 plus interest of $10 million. CenterPoint Houston has
fully reserved for the disallowance and related interest accrual. A judgment
was entered by a Travis County court in May 2005 affirming the Texas Utility
Commission's decision. CenterPoint Houston filed an appeal to the 3rd Court of
Appeals in Austin in June 2005, and in April 2006, the 3rd Court of Appeals
issued a judgment affirming the Texas Utility Commission's decision. CenterPoint
Houston filed an appeal with the Texas Supreme Court in August 2006, and in
October 2006, the Texas Supreme Court requested that the Texas Utility
Commission and the City of Houston file written responses to CenterPoint
Houston's petition for review. The Texas Supreme Court may grant or deny the
petition for review. If the petition is denied, the Court of Appeals' judgment
would become final. If the petition is granted, the Texas Supreme Court would
address the merits of CenterPoint Houston's appeal. There is no deadline for the
Texas Supreme Court's decisions.
9
(C) REMAND OF 2001 UNBUNDLED COST OF SERVICE (UCOS) ORDER
The 3rd Court of Appeals in Austin remanded to the Texas Utility Commission
an issue that was decided by the Texas Utility Commission in CenterPoint
Houston's 2001 UCOS proceeding. In its remand order, the court ruled that the
Texas Utility Commission had failed to adequately explain its basis for its
determination of certain projected transmission capital expenditures. The Court
of Appeals ordered the Texas Utility Commission to reconsider that determination
on the basis of the record that existed at the time of the Texas Utility
Commission's original order. In April 2006, the Texas Utility Commission opined
orally that the rate base should be reduced by $57 million and instructed its
Staff to quantify the effect on CenterPoint Houston's rates. In the settlement
of the CenterPoint Houston rate proceeding described in Note 5(d) below, the
parties to the remand proceeding agreed to settle all issues that could be
raised in the remand. Under the terms of that settlement, CenterPoint Houston
implemented riders to its tariff rates under which it will provide rate credits
to retail and wholesale customers for a total of approximately $8 million per
year until a total of $32 million has been credited to customers under those
tariff riders. Those riders became effective October 10, 2006. CenterPoint
Houston reduced revenues and established a corresponding regulatory liability
for $32 million in the second quarter of 2006 to reflect this obligation.
(D) RATE CASES
ELECTRIC TRANSMISSION & DISTRIBUTION
In October 2005, the Texas Utility Commission Staff filed a memorandum
summarizing its review of the Earnings Reports filed by electric utilities for
the calendar year ended December 31, 2004. Based on its review, the Staff
concluded that continuation of CenterPoint Houston's rates could result in
excess retail transmission and distribution revenues and excess wholesale
transmission revenues and recommended that the Texas Utility Commission initiate
a review of the reasonableness of existing rates.
In December 2005, the Texas Utility Commission agreed to order a rate
proceeding concerning the reasonableness of CenterPoint Houston's existing rates
for transmission and distribution service and required CenterPoint Houston to
make a filing by April 15, 2006 to justify or change those rates. In April 2006,
CenterPoint Houston filed cost data and other information that supported the
current rates.
In July, 2006, CenterPoint Houston entered into a settlement agreement with
the parties to the proceeding that resolved the issues raised in this matter.
CenterPoint Houston filed a Stipulation and Agreement (the Agreement) with the
Texas Utility Commission in August 2006 to seek approval of that settlement
agreement. On September 5, 2006, the Texas Utility Commission issued its final
order approving the Agreement. Revised base rates and other revised tariffs
became effective as of October 10, 2006.
Under the terms of the Agreement, CenterPoint Houston's base rate revenues
will be reduced by a net of approximately $58 million per year. Also,
CenterPoint Houston will increase its energy efficiency expenditures by an
additional $10 million per year over the $13 million included in existing rates.
The expenditures will be made to benefit both residential and commercial
customers. CenterPoint Houston also will fund $10 million per year for programs
providing financial assistance to qualified low-income customers in its service
territory.
The Agreement provides for a rate freeze until June 30, 2010 under which
CenterPoint Houston will not seek to increase its base rates and the other
parties will not petition to decrease those rates. The rate freeze is subject to
adjustments for changes related to certain transmission costs, implementation of
the Texas Utility Commission's recently-adopted change to its CTC rule and
certain other changes. The rate freeze does not apply to changes required to
reflect the result of currently pending appeals of the True-Up Order, the
pending appeal of the Texas Utility Commission's order regarding CenterPoint
Houston's final fuel reconciliation, the appeal of the order implementing
CenterPoint Houston's CTC or the implementation of transition charges associated
with current and future securitizations. In addition, CenterPoint Houston is not
required to file annual earnings reports for the calendar years 2006 through
2008, but is required to file an earnings report for 2009 no later than March 1,
2010. CenterPoint Houston must make a new base rate filing not later than June
30, 2010, based on a test year ended December 31, 2009, unless the Texas Utility
Commission staff and certain cities with original jurisdiction notify
CenterPoint Houston that such a filing is unnecessary.
10
The Agreement will permit CenterPoint Houston to amortize its expenditures
of approximately $28 million related to Hurricane Rita over a seven-year period
and to amortize regulatory expenses of approximately $7 million over a four-year
period, both beginning in October 2006. Pursuant to the Agreement, the Texas
Utility Commission determined that franchise fees payable by CenterPoint Houston
under new franchise agreements with the City of Houston and certain other
municipalities in CenterPoint Houston's service area are deemed reasonable and
necessary, along with the revised base rates.
The Agreement also resolves all issues that could be raised in the Texas
Utility Commission's proceeding to review its decision in CenterPoint Houston's
2001 UCOS case. See Note 5(c) above.
NATURAL GAS DISTRIBUTION
SOUTHERN GAS OPERATIONS
South Texas and Beaumont/East Texas. In April 2005, the Railroad Commission
of Texas (Railroad Commission) established new gas tariffs that increased
Southern Gas Operations' base rate and service revenues by a combined $2 million
annually 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 same rates within the incorporated cities located in the two
divisions. During the second quarter of 2006, Southern Gas Operations reached
settlement agreements with the last of the cities that had denied or appealed
the rate change requests.
Settlement rates have now been implemented in all jurisdictions, including
unincorporated areas. Southern Gas Operations' base rates and miscellaneous
service charges are expected to increase by a total of $17 million annually over
the pre-April 2005 levels. Approximately $4 million of this increase was
reflected in the Company's 2005 revenues. The Company expects approximately $16
million will be reflected in revenues in 2006, and the total $17 million will be
reflected in revenues in 2007. Approximately $3 million of expenditures related
to these rate cases was charged to expense during the second quarter of 2006.
The settlements also provide that these new rates will not change over the next
three to five years.
MINNESOTA GAS
At September 30, 2006, Minnesota Gas had recorded approximately $45 million
as a regulatory asset related to prior years' unrecovered purchased gas costs.
Of the total, approximately $24 million relates to the period from July 1, 2004
through June 30, 2006, and approximately $21 million relates to the period from
July 1, 2000 through June 30, 2004. The amounts related to periods prior to July
1, 2004 arose as a result of revisions to the calculation of unrecovered
purchased gas costs previously approved by the Minnesota Public Utilities
Commission (MPUC), and recovery of this regulatory asset is dependent upon
obtaining a waiver from the MPUC rules. Minnesota Gas has requested to recover
the amounts related to costs prior to July 1, 2004 over a three-year period
beginning in 2007. The Minnesota Office of the Attorney General (OAG) and the
Minnesota Department of Commerce have filed comments opposing recovery. Any
amount not approved by the MPUC will be written off. There is no statutory time
frame in which the MPUC must act.
In November 2005, Minnesota Gas filed a request with the MPUC to increase
annual rates by approximately $41 million. In December 2005, the MPUC approved
an interim rate increase of approximately $35 million that was implemented
January 1, 2006. Any excess of amounts collected under the interim rates over
the amounts approved in final rates is subject to refund to customers. On
October 5, 2006, the MPUC considered the request and indicated that it will
grant a rate increase of approximately $21 million, which is still subject to
receipt of a final order. In addition, the MPUC approved a $5 million
affordability program to assist low-income customers, the actual cost of which
will be recovered in rates in addition to the $21 million rate increase.
Issuance of the formal written decision by the MPUC is expected in late 2006.
The proportional share of the excess of the amounts collected in interim rates
over the amount allowed by the final order of approximately $8 million has been
accrued as of September 30, 2006, and will be refunded to customers in late 2006
or early 2007 after receipt of the formal decision.
In December 2004, the MPUC opened an investigation to determine whether
Minnesota Gas' 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. In June 2005, the OAG
issued its report alleging Minnesota Gas had violated the CWR and recommended a
$5 million penalty. In addition, in June 2005, CERC was named in a suit filed in
the United States District Court, District of Minnesota on behalf of
11
a purported class of customers who allege that Minnesota Gas' conduct under the
CWR was in violation of the law. On August 14, 2006 the court gave final
approval to a $13.5 million settlement which resolves all but one small claim
against Minnesota Gas which have or could have been asserted by residential
natural gas customers in the CWR class action. The agreement was also approved
by the MPUC, resolving the claims made by the OAG. During the fourth quarter of
2005, CERC established a litigation reserve to cover the anticipated costs of
this settlement.
(E) 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 May 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. The City of Tyler appealed this order to a
Travis County District Court, but in April 2006, Southern Gas Operations and the
City of Tyler reached a settlement regarding the rates in the City of Tyler and
other aspects of the dispute between them. As contemplated by that settlement,
the City of Tyler's appeal to the district court was dismissed on July 31, 2006,
and the Railroad Commission's final order and findings are no longer subject to
further review or modification.
(6) DERIVATIVE INSTRUMENTS
The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business. The Company utilizes
derivative financial instruments such as physical forward contracts, swaps and
options (energy derivatives) to mitigate the impact of changes in its natural
gas businesses on its operating results and cash flows.
Cash Flow Hedges. During each of the three-month and nine-month periods
ended September 30, 2005 and 2006, hedge ineffectiveness resulted in a gain of
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 previously 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 Condensed Statements of Consolidated
Income under the "Expenses" caption "Natural gas." Cash flows resulting from
these transactions in non-trading energy derivatives are included in the
Condensed Statements of Consolidated Cash Flows in the same category as the item
being hedged. As of September 30, 2006, the Company expects $18 million ($12
million after-tax) in accumulated other comprehensive income to be reclassified
as a decrease in Natural gas expense during the next twelve months.
The maximum length of time the Company is hedging its exposure to the
variability in future cash flows using financial instruments is primarily two
years with a limited amount up to ten years. The Company's policy is not to
exceed ten years in hedging its exposure.
Other Derivative Financial Instruments. The Company enters into certain
derivative financial instruments to manage physical commodity price risks that
do not qualify or are not designated as cash flow or fair value hedges under
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
(SFAS No. 133). While the Company utilizes these financial instruments to manage
physical commodity price risks, it does not engage in proprietary or speculative
commodity trading. During the three months ended September 30, 2005 and 2006,
the Company recognized unrealized net gains of $2 million and $23 million,
respectively, on the derivative financial instruments that had not yet been
settled. During the nine months ended September 30, 2005 and 2006, the Company
recognized unrealized net gains of $3 million and $37 million, respectively.
These derivative gains and losses are included in the Condensed Statements of
Consolidated Income under the "Expenses" caption "Natural gas."
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 five-year life of the designated
fixed-rate debt. Amortization of amounts deferred in accumulated other
comprehensive loss for each of the nine-month periods ended September 30, 2005
and 2006 was $23 million. Hedge ineffectiveness was not material during each of
the nine-month periods ended September 30, 2005 and 2006. As of September 30,
2006, the Company expects $28 million ($19 million after-tax) in accumulated
other comprehensive loss to be amortized during the next twelve months.
12
(7) GOODWILL AND INTANGIBLES
Goodwill as of December 31, 2005 and September 30, 2006 by reportable
business segment is as follows (in millions):
Natural Gas Distribution ..................... $ 746
Pipelines and Field Services ................. 604
Competitive Natural Gas Sales and Services ... 339
Other Operations ............................. 20
------
Total ..................................... $1,709
======
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. The impairment evaluation
for goodwill is performed by using a two-step process. In the first step, the
fair value of each reporting unit is compared with the carrying amount of the
reporting unit, including goodwill. The estimated fair value of the reporting
unit is generally determined on the basis of discounted future cash flows. If
the estimated fair value of the reporting unit is less than the carrying amount
of the reporting unit, then a second step must be completed in order to
determine the amount of the goodwill impairment that should be recorded. In the
second step, the implied fair value of the reporting unit's goodwill is
determined by allocating the reporting unit's fair value to all of its assets
and liabilities other than goodwill (including any unrecognized intangible
assets) in a manner similar to a purchase price allocation. The resulting
implied fair value of the goodwill that results from the application of this
second step is then compared to the carrying amount of the goodwill and an
impairment charge is recorded for the difference.
The Company completed its annual evaluation of goodwill for impairment as
of July 1, 2006 and no impairment was indicated.
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2005 SEPTEMBER 30, 2006
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Land Use Rights.... $55 $(14) $55 $(14)
Other.............. 22 (7) 7 (3)
--- ---- --- ----
Total........... $77 $(21) $62 $(17)
=== ==== === ====
Amortization expense for other intangibles during each of the three-month
periods ended September 30, 2005 and 2006 was less than $1 million. Amortization
expense for other intangibles during each of the nine-month periods ended
September 30, 2005 and 2006 was $2 million. Estimated amortization expense is
less than $1 million for the remainder of 2006 and approximately $1 million in
each of the five succeeding fiscal years.
(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,
------------- -------------
2005 2006 2005 2006
---- ---- ---- ----
(IN MILLIONS)
Net income .............................................. $50 $ 83 $171 $365
--- ---- ---- ----
Other comprehensive income (loss):
Net deferred gain from cash flow hedges .............. 1 10 11 5
Reclassification of deferred loss (gain) from cash
flow hedges realized in net income ................ (2) 7 6 13
Other comprehensive income from discontinued
operations ........................................ -- -- 3 --
--- ---- ---- ----
Other comprehensive income (loss) ....................... (1) 17 20 18
--- ---- ---- ----
Comprehensive income .................................... $49 $100 $191 $383
=== ==== ==== ====
The following table summarizes the components of accumulated other
comprehensive loss:
DECEMBER 31, SEPTEMBER 30,
2005 2006
------------ -------------
(IN MILLIONS)
Minimum pension liability adjustment ......... $(15) $(15)
Net deferred loss from cash flow hedges ...... (23) (5)
---- ----
Total accumulated other comprehensive loss ... $(38) $(20)
==== ====
13
(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, 2005, 310,324,905
shares of CenterPoint Energy common stock were issued and 310,324,739 shares of
CenterPoint Energy common stock were outstanding. At September 30, 2006,
312,325,956 shares of CenterPoint Energy common stock were issued and
312,325,790 shares of CenterPoint Energy common stock were outstanding.
Outstanding common shares exclude 166 treasury shares at both December 31, 2005
and September 30, 2006.
(10) LONG-TERM DEBT AND RECEIVABLES FACILITY
(A) LONG-TERM DEBT
Senior Notes. In May 2006, CERC Corp. issued $325 million aggregate
principal amount of senior notes due in May 2016 with an interest rate of 6.15%.
The proceeds from the sale of the senior notes will be used for general
corporate purposes, including repayment or refinancing of debt (including $145
million of CERC's 8.90% debentures due December 15, 2006), capital expenditures
and working capital.
Revolving Credit Facilities. In March 2006, the Company, CenterPoint
Houston and CERC Corp., entered into amended and restated bank credit
facilities. The Company replaced its $1 billion five-year revolving credit
facility with a $1.2 billion five-year revolving credit facility. The facility
has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 60 basis
points based on the Company's current credit ratings, as compared to LIBOR plus
87.5 basis points for borrowings under the facility it replaced. The facility
contains covenants, including a debt (excluding transition bonds) to earnings
before interest, taxes, depreciation and amortization covenant.
CenterPoint Houston replaced its $200 million five-year revolving credit
facility with a $300 million five-year revolving credit facility. The facility
has a first drawn cost of LIBOR plus 45 basis points based on CenterPoint
Houston's current credit ratings, as compared to LIBOR plus 75 basis points for
borrowings under the facility it replaced. The facility contains covenants,
including a debt (excluding transition bonds) to total capitalization covenant
of 65%.
CERC Corp. replaced its $400 million five-year revolving credit facility
with a $550 million five-year revolving credit facility. The facility has a
first drawn cost of LIBOR plus 45 basis points based on CERC Corp.'s current
credit ratings, as compared to LIBOR plus 55 basis points for borrowings under
the facility it replaced. The facility contains covenants, including a debt to
total capitalization covenant of 65%.
Under each of the credit facilities, an additional utilization fee of 10
basis points applies to borrowings any time more than 50% of the facility is
utilized, and the spread to LIBOR fluctuates based on the borrower's credit
rating. Borrowings under each of the facilities are subject to customary terms
and conditions. However, there is no requirement that the Company, CenterPoint
Houston or CERC Corp. make representations prior to borrowings as to the absence
of material adverse changes or litigation that could be expected to have a
material adverse effect. Borrowings under each of the credit facilities are
subject to acceleration upon the occurrence of events of default that the
Company, CenterPoint Houston or CERC Corp. consider customary.
As of September 30, 2006, the Company had no borrowings and approximately
$28 million of outstanding letters of credit under its $1.2 billion credit
facility, CenterPoint Houston had no borrowings and approximately $4 million of
outstanding letters of credit under its $300 million credit facility and CERC
Corp. had no borrowings under its $550 million credit facility. Additionally,
the Company, CenterPoint Houston and CERC Corp. were in compliance with all
covenants as of September 30, 2006.
Convertible Debt. On May 19, 2003, the Company issued $575 million
aggregate principal amount of convertible senior notes due May 15, 2023 with an
interest rate of 3.75%. Holders may convert each of their notes into shares of
CenterPoint Energy common stock at a conversion rate of 87.4094 shares of common
stock per $1,000 principal amount of notes at any time prior to maturity under
the following circumstances: (1) if the last reported sale price of CenterPoint
Energy common stock for at least 20 trading days during the period of 30
consecutive trading days ending on the last trading day of the previous calendar
quarter is greater than or equal to 120% or, following May 15, 2008, 110% of the
conversion price per share of CenterPoint Energy common stock on such last
trading day, (2) if the notes have been called for redemption, (3) during any
period in which the credit ratings assigned to the notes by both Moody's
Investors Service, Inc. (Moody's) and Standard & Poor's Ratings Services
14
(S&P), a division of The McGraw-Hill Companies, are lower than Ba2 and BB,
respectively, or the notes are no longer rated by at least one of these ratings
services or their successors, or (4) upon the occurrence of specified corporate
transactions, including the distribution to all holders of CenterPoint Energy
common stock of certain rights entitling them to purchase shares of CenterPoint
Energy common stock at less than the last reported sale price of a share of
CenterPoint Energy common stock on the trading day prior to the declaration date
of the distribution or the distribution to all holders of CenterPoint Energy
common stock of the Company's assets, debt securities or certain rights to
purchase the Company's securities, which distribution has a per share value
exceeding 15% of the last reported sale price of a share of CenterPoint Energy
common stock on the trading day immediately preceding the declaration date for
such distribution. The notes originally had a conversion rate of 86.3558 shares
of common stock per $1,000 principal amount of notes. However, effective
February 16, 2006, the conversion rate increased to 87.4094 in accordance with
the terms of the notes due to an increase in the amount of the dividend per
common share paid by the Company in the first quarter of 2006.
Holders have the right to require the Company to purchase all or any
portion of the notes for cash on May 15, 2008, May 15, 2013 and May 15, 2018 for
a purchase price equal to 100% of the principal amount of the notes. The
convertible senior notes also have a contingent interest feature requiring
contingent interest to be paid to holders of notes commencing on or after May
15, 2008, in the event that the average trading price of a note for the
applicable five-trading-day period equals or exceeds 120% of the principal
amount of the note as of the day immediately preceding the first day of the
applicable six-month interest period. For any six-month period, contingent
interest will be equal to 0.25% of the average trading price of the note for the
applicable five-trading-day period.
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.
Under the terms of the New Notes, which are substantially similar to the Old
Notes, settlement of the principal portion will be made in cash rather than
stock.
Additionally, as of September 30, 2006, the 3.75% convertible senior notes
have been included as current portion of long-term debt in the Consolidated
Balance Sheets 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 quarter of 2006 was greater
than or equal to 120% of the conversion price of the 3.75% convertible senior
notes and therefore, during the fourth quarter of 2006, the 3.75% convertible
senior notes meet the criteria that make them eligible for conversion at the
option of the holders of these notes.
On December 17, 2003, the Company issued $255 million aggregate principal
amount of convertible senior notes due January 15, 2024 with an interest rate of
2.875%. Holders may convert each of their notes into shares of CenterPoint
Energy common stock at a conversion rate of 79.0165 shares of common stock per
$1,000 principal amount of notes at any time prior to maturity under the
following circumstances: (1) if the last reported sale price of CenterPoint
Energy common stock for at least 20 trading days during the period of 30
consecutive trading days ending on the last trading day of the previous calendar
quarter is greater than or equal to 120% of the conversion price per share of
CenterPoint Energy common stock on such last trading day, (2) if the notes have
been called for redemption, (3) during any period in which the credit ratings
assigned to the notes by both Moody's and S&P are lower than Ba2 and BB,
respectively, or the notes are no longer rated by at least one of these ratings
services or their successors, or (4) upon the occurrence of specified corporate
transactions, including the distribution to all holders of CenterPoint Energy
common stock of certain rights entitling them to purchase shares of CenterPoint
Energy common stock at less than the last reported sale price of a share of
CenterPoint Energy common stock on the trading day prior to the declaration date
of the distribution or the distribution to all holders of CenterPoint Energy
common stock of the Company's assets, debt securities or certain rights to
purchase the Company's securities, which distribution has a per share value
exceeding 15% of the last reported sale price of a share of CenterPoint Energy
common stock on the trading day immediately preceding the declaration date for
such distribution. The notes originally had a conversion rate of 78.0640 shares
of common stock per $1,000 principal amount of notes. However, effective
February 16, 2006, the conversion rate increased to 79.0165 in accordance with
the terms of the notes due to an increase in the amount of the dividend per
common share paid by the Company in the first quarter of 2006.
Under the original terms of these convertible senior notes, CenterPoint
Energy could elect to satisfy part or all of its conversion obligation by
delivering cash in lieu of shares of CenterPoint Energy. On December 13, 2004,
the
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Company entered into a supplemental indenture with respect to these convertible
senior notes in order to eliminate its right to settle the conversion of the
notes solely in shares of its common stock. Holders have the right to require
the Company to purchase all or any portion of the notes for cash on January 15,
2007, January 15, 2012 and January 15, 2017 for a purchase price equal to 100%
of the principal amount of the notes. As of September 30, 2006, these notes were
classified as current portion of other long-term debt in the Condensed
Consolidated Balance Sheets. The convertible senior notes also have a contingent
interest feature requiring contingent interest to be paid to holders of notes
commencing on or after January 15, 2007, in the event that the average trading
price of a note for the applicable five-trading-day period equals or exceeds
120% of the principal amount of the note as of the day immediately preceding the
first day of the applicable six-month interest period. For any six-month period,
contingent interest will be equal to 0.25% of the average trading price of the
note for the applicable five-trading-day period.
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, 2005 and September 30, 2006.
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, 2006, 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 2005 2006 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
(B) RECEIVABLES FACILITY
In January 2006, CERC's $250 million receivables facility was extended to
January 2007. The facility was temporarily increased to $375 million for the
period from January 2006 to June 2006. As of September 30, 2006, no amounts were
funded under CERC's receivables facility.
Funding under the receivables facility averaged $173 million and $85
million for the nine months ended September 30, 2005 and 2006, respectively.
Sales of receivables were approximately $480 million and $-0- for the three
months ended September 30, 2005 and 2006, respectively, and $1.4 billion and
$555 million for the nine months ended September 30, 2005 and 2006,
respectively. See Note 14(b) for a discussion of changes to the receivables
facility during the fourth quarter of 2006.
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(11) COMMITMENTS AND CONTINGENCIES
(A) NATURAL GAS SUPPLY COMMITMENTS
Natural gas supply commitments include natural gas contracts related to the
Company's natural gas distribution and competitive natural gas sales and
services operations, which have various quantity requirements and durations that
are not classified as non-trading derivative assets and liabilities in the
Company's Consolidated Balance Sheets as of December 31, 2005 and September 30,
2006 as these contracts meet the SFAS No. 133 exception to be classified as
"normal purchases contracts" or do not meet the definition of a derivative.
Natural gas supply commitments also include natural gas transportation contracts
which do not meet the definition of a derivative. As of September 30, 2006,
minimum payment obligations for natural gas supply commitments are approximately
$302 million for the remaining three months in 2006, $724 million in 2007, $230
million in 2008, $131 million in 2009, $130 million in 2010 and $733 million in
2011 and thereafter.
(B) CAPITAL COMMITMENTS
In October 2005, CenterPoint Energy Gas Transmission Company (CEGT), a
wholly owned subsidiary of CERC Corp., signed a 10-year firm transportation
agreement with XTO Energy (XTO) to transport 600 million cubic feet (MMcf) per
day of natural gas from Carthage, Texas to CEGT's Perryville hub in Northeast
Louisiana. To accommodate this transaction, CEGT filed a certificate application
with the FERC in March 2006 to build a 172-mile, 42-inch diameter pipeline and
related compression facilities. The capacity of the pipeline under this filing
will be 1.25 billion cubic feet (Bcf) per day. CEGT has signed firm contracts
for the full capacity of the pipeline.
On October 2, 2006 the FERC issued CEGT's certificate to construct, own and
operate the pipeline and compression facilities. CEGT has begun construction of
the facilities and expects to place the facilities in service in the first
quarter 2007 at a cost of approximately $455 million.
Based on strong interest expressed during an open season held earlier this
year, and subject to FERC approval, CEGT expects to expand capacity of the
pipeline to 1.5 Bcf per day, which would bring the total estimated capital cost
of the project to approximately $510 million. During the four-year period
subsequent to the in-service date of the pipeline, XTO can request, and subject
to mutual negotiations that meet specific financial parameters and to FERC
approval, CEGT would construct a 67-mile extension from CEGT's Perryville hub to
an interconnect with Texas Eastern Gas Transmission at Union Church,
Mississippi.
Earlier this year, CenterPoint Energy Southeast Pipelines Holding, L.L.C.,
a wholly owned subsidiary of CERC Corp., signed a joint venture agreement with a
subsidiary of Duke Energy Gas Transmission (DEGT) to construct, own and operate
a 270-mile pipeline (Southeast Supply Header) that will extend from CEGT's
Perryville hub in northeast Louisiana to Gulfstream Natural Gas System, which is
50 percent owned by an affiliate of DEGT. In August 2006, the joint venture
signed an agreement with Florida Power & Light Company (FPL) for firm
transportation services, which subscribes approximately half of the planned
1 Bcf per day capacity of the pipeline. FPL's commitment is contingent on the
approval of the FPL contract by the Florida Public Service Commission in
December 2006. Subject to the venture receiving a certificate from the FERC to
construct, own and operate the pipeline, subsidiaries of DEGT and CERC Corp.
have committed to build the pipeline, for which total costs are estimated to be
$700 to $800 million. The pre-filing process with the FERC has been initiated,
and an application is expected to be filed in December 2006. Once the project is
approved by the FERC, construction is anticipated to begin in the fourth quarter
of 2007, with an expected in-service date of June 2008.
(C) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS
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
Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (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
17
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
federal court in California, Colorado and Nevada and in state court 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. 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.
The Company and/or Reliant Energy have been named in approximately 30 of
these lawsuits, which were instituted between 2001 and 2006 and are pending in
California state court in San Diego County, in Nevada state court in Clark
County, in federal district court in Colorado, Nevada and the Northern District
of California 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.
To date, several of the electricity complaints have been dismissed, and
several of the dismissals have been affirmed by appellate courts. Others have
been resolved by the settlement described in the following paragraph. Four of
the gas complaints have also been dismissed based on defendants' claims of
federal preemption and the filed rate doctrine, and these dismissals have been
appealed. In June 2005, a San Diego state court refused to dismiss other gas
complaints on the same basis. The other gas cases remain in the early procedural
stages.
On August 12, 2005, RRI reached a settlement with the FERC enforcement
staff, 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 three states and the
investor-owned utilities related to the 2000-2001 natural gas markets. The
settlement has been approved by the FERC, by the California Public Utilities
Commission, and by the courts in which the electricity class action cases are
pending. Two parties have appealed the courts' approval of the settlement to the
California Court of Appeals. A party in the FERC proceedings filed a motion for
rehearing of the FERC's order approving the settlement, which the FERC denied on
May 30, 2006. That party has filed for review of the FERC's orders in the Ninth
Circuit Court of Appeals. The Company is not a party to the settlement, 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. 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 were
dismissed without prejudice. In the remaining lawsuit, the Company and certain
current and former members of its benefits committee are defendants. That
lawsuit alleged 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 by permitting
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 sought 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. In January 2006,
the federal district judge granted a motion for
18
summary judgment filed by the Company and the individual defendants. The
plaintiffs appealed the ruling to the Fifth Circuit Court of Appeals. The
Company believes that this lawsuit is without merit and will continue to
vigorously defend the case. However, the ultimate outcome of this matter cannot
be predicted at this time.
Other Legal Matters
Natural Gas Measurement Lawsuits. CERC Corp. and certain of its
subsidiaries are defendants in a suit filed in 1997 under the Federal False
Claims Act alleging mismeasurement of natural gas produced from federal and
Indian lands. The suit seeks undisclosed damages, along with statutory
penalties, interest, costs, and fees. The complaint is part of a larger series
of complaints filed against 77 natural gas pipelines and their subsidiaries and
affiliates. An earlier single action making substantially similar allegations
against the pipelines was dismissed by the federal district court for the
District of Columbia on grounds of improper joinder and lack of jurisdiction. As
a result, the various individual complaints were filed in numerous courts
throughout the country. This case has been consolidated, together with the other
similar False Claims Act cases, in the federal district court in Cheyenne,
Wyoming. On October 20, 2006, the judge considering this matter granted
defendants' motion to dismiss the suit on the ground that the court lacked
subject matter jurisdiction over the claims asserted.
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 Corp. subsidiaries), limited the scope of
the class of plaintiffs they purport to represent and eliminated previously
asserted claims based on mismeasurement of the Btu content of the gas. The same
plaintiffs then filed a second lawsuit, again as representatives of a class of
royalty owners, in which they assert their claims that the defendants have
engaged in systematic mismeasurement of the Btu content of natural gas for more
than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along
with statutory penalties, treble damages, interest, costs and fees. CERC
believes 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., CEGT, 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, CEGT, CenterPoint Energy Field Services, CenterPoint Energy Pipeline
Services, Inc., CenterPoint Energy - Mississippi River Transmission Corp.
(CEMRT) 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. Subsequently, the plaintiffs dropped as defendants CEGT and CEMRT. 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 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. The range of relief sought by the plaintiffs
19
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 and municipal regulatory authorities.
The allegations in these cases are similar to those asserted in the City of
Tyler proceeding, as described in Note 5(e). 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. Pursuant to an order from the Minnesota Office
of Pipeline Safety, CERC substantially completed removal of certain
non-code-compliant components from a portion of its distribution system by
December 2, 2005. The components were installed by a predecessor company, which
was not affiliated with CERC during the period in which the components were
installed. In November 2005, Minnesota Gas filed a request with the MPUC to
recover the capitalized expenditures (approximately $39 million) and related
expenses, together with a return on the capitalized portion through rates as
part of its existing rate case as further discussed in Note 5(d). Based on the
MPUC deliberations held in October 2006 in the Minnesota Gas rate case, the
capitalized expenditures, plus approximately $2 million previously expensed in
2005, are expected to be allowed in rate base. Return on approximately $4
million of the $41 million is limited to the cost of long-term debt included in
the cost of capital pending the outcome of litigation against the predecessor
companies that installed the original service lines.
Minnesota Cold Weather Rule. For a discussion of this matter, see Note 5(d)
above.
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 liquid 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, including the cost of restoring their
property to its original condition and damages for diminution of value of their
property. In addition, plaintiffs seek damages for trespass, punitive, and
exemplary damages. The parties have reached an agreement on terms of a
settlement in principle of this matter. That settlement would require approvals
from the Louisiana Department of Environmental Quality of an acceptable
remediation plan that could be implemented by CERC. CERC currently is seeking
that approval. If the currently agreed terms for settlement are ultimately
implemented, the Company and CERC do 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, 2006, CERC had accrued $14 million for remediation of
these Minnesota sites. At September 30, 2006, the estimated range of possible
remediation costs for these sites was $4 million to $35 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
20
costs in excess of insurance recovery. As of September 30, 2006, CERC has
collected $13 million from insurance companies and rate payers 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, one filed in
United States District Court, District of Maine and the other filed in Middle
District of Florida, Jacksonville Division, 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 federal district court
considering the suit for contribution in Florida granted CERC's motion to
dismiss on the grounds that CERC was not an "operator" of the site as had been
alleged. In October 2006, the 11th Circuit Court of Appeals affirmed the
district court's dismissal. In June 2006, the federal district court in Maine
that is considering the other suit ruled that the current owner of the site is
responsible for site remediation but that an additional evidentiary hearing is
required to determine if other potentially responsible parties, including CERC,
would have to contribute to that remediation. 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. The
Company has found this type of contamination 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 is not known at this time,
based on the Company's experience and that of others in the natural gas industry
to date and on the current regulations regarding remediation of these sites, the
Company believes that the costs of any remediation of these sites will not be
material to the Company's financial condition, results of operations or cash
flows.
Asbestos. Some facilities owned by the Company contain or have contained
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 number of individuals who claim injury due to exposure to
asbestos. Some of the claimants have worked at locations owned by the Company,
but most existing claims relate to facilities previously owned by the Company or
its subsidiaries. The Company anticipates that additional claims like those
received may be asserted in the future. In 2004, the Company sold its generating
business, to which most of these claims relate, to Texas Genco LLC, which is now
known as NRG Texas LP (NRG). Under the terms of the arrangements regarding
separation of the generating business from the Company and its sale to Texas
Genco LLC, ultimate financial responsibility for uninsured losses from claims
relating to the generating business has been assumed by Texas Genco LLC and its
successor, but 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 the purchaser. 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.
21
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 regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. The Company 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.
TAX CONTINGENCIES
CenterPoint Energy's consolidated federal income tax returns have been
audited and settled through the 1996 tax year.
In the audits of the 1997 through 2003 tax years, the IRS proposed to
disallow all deductions for original issue discount (OID), including interest
paid, relating to the Company's 2.0% Zero Premium Exchangeable Subordinated
Notes (ZENS), and the interest paid on the 7% Automatic Common Exchange
Securities (ACES) redeemed in 1999. The IRS contended that (1) those
instruments, in combination with the Company's long position in shares of Time
Warner Inc. (TW Common), constituted a straddle under Sections 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.
The Company reached agreement with the IRS on terms of a settlement
regarding the tax treatment of the Company's ZENS and its former ACES. On July
17, 2006, the Company signed a Closing Agreement prepared by the IRS and the
Company for the tax years 1999 through 2029 with respect to the ZENS issue. The
agreement reached with the IRS and the Closing Agreement are subject to approval
by the Joint Committee on Taxation of the U.S. Congress. Under the terms of the
agreement reached with the IRS, the Company will pay approximately $64 million
in previously accrued taxes associated with the ACES and the ZENS and will
reduce its future interest deductions associated with the ZENS. As a result of
the agreement reached with the IRS, the Company reduced its previously accrued
tax and related interest reserves by approximately $119 million in the second
quarter of 2006, and will no longer accrue a quarterly reserve related to this
tax contingency.
The Company has also established reserves for other significant tax items
including issues relating to prior acquisitions and dispositions of business
operations, certain positions taken with respect to state tax filings and
certain items related to employee benefits. The total amount reserved for the
other tax items was approximately $60 million and $50 million as of December 31,
2005 and September 30, 2006, respectively.
GUARANTEES
Prior to the Company's distribution of its ownership in RRI to its
shareholders, CERC had guaranteed certain contractual obligations of what became
RRI's trading subsidiary. Under the terms of the separation agreement between
the companies, RRI agreed to extinguish all such guarantee obligations prior to
separation, but when separation occurred in September 2002, RRI had been unable
to extinguish all obligations. To secure the Company and CERC against
obligations under the remaining guarantees, RRI agreed to provide cash or
letters of credit for the benefit of CERC and the Company, and agreed to use
commercially reasonable efforts to extinguish the remaining guarantees. The
Company's current exposure under the remaining guarantees relates to CERC's
guarantee of the payment by RRI of demand charges related to transportation
contracts with one counterparty. The demand charges are approximately $53
million per year in 2006 through 2015, $49 million in 2016, $38 million in 2017
and $13 million in 2018. As a result of changes in market conditions, the
Company's potential exposure under that guarantee currently exceeds the security
provided by RRI. The Company has requested RRI to increase the amount of its
existing letters of credit or, in the alternative, to obtain a release of CERC's
obligations under the guarantee. On June 30, 2006, the RRI trading subsidiary
and CERC jointly filed a complaint at the FERC against the counterparty on the
CERC guarantee. In the complaint, the RRI trading subsidiary seeks a
determination by the FERC that the security held by the counterparty exceeds the
level permitted by the FERC's policies. The complaint asks the FERC to require
the counterparty to release CERC from its guarantee obligation and, in its place
accept (i) a guarantee from RRI of the obligations of the RRI trading
subsidiary, and (ii) letters of credit equal to (A) one year of demand charges
for a transportation agreement related to a 2003 expansion of the counterparty's
pipeline, and (B) three months of demand charges for three other transportation
agreements held by the RRI trading subsidiary. On July 20,
22
2006, the counterparty filed its answer to the complaint, arguing that CERC is
contractually bound to continue the guarantee, that the amount of the guarantee
does not violate the FERC's policies and that the proposed substitution of
credit support is not authorized under the counterparty's financing documents.
The Company and the RRI trading subsidiary have filed a reply to that answer
and, in response to a FERC order, the counterparty has submitted financing
documents for FERC review. It is presently unknown what action the FERC may take
on the complaint. The RRI trading subsidiary continues to meet its obligations
under the transportation contracts.
NUCLEAR DECOMMISSIONING FUND COLLECTIONS
Pursuant to regulatory requirements and its tariff, CenterPoint Houston, as
collection agent, collects from its transmission and distribution customers the
nuclear decommissioning charge assessed with respect to the 30.8% ownership
interest in the South Texas Project which it owned when it was part of an
integrated electric utility. Amounts collected are transferred to nuclear
decommissioning trusts maintained by the current owner of that interest in the
South Texas Project. During 2003 and 2004, $2.9 million was transferred each
year and $3.2 million was transferred in 2005. There are various investment
restrictions imposed on owners of nuclear generating stations by the Texas
Utility Commission and the NRC relating to nuclear decommissioning trusts.
Pursuant to the provisions of both a separation agreement and a final order of
the Texas Utility Commission relating to the 2005 transfer of ownership to Texas
Genco LLC, now NRG, CenterPoint Houston and a subsidiary of NRG were, until July
1, 2006, jointly administering the decommissioning funds through the Nuclear
Decommissioning Trust Investment Committee. On June 9, 2006, the Texas Utility
Commission approved an application by CenterPoint Houston and an NRG subsidiary
to name the NRG subsidiary as the sole fund administrator. As a result,
CenterPoint Houston is no longer responsible for administration of
decommissioning funds it collects as collection agent.
(12) EARNINGS PER SHARE
The following table reconciles numerators and denominators of the Company's
basic and diluted earnings per share calculations:
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
2005 2006 2005 2006
------------ ------------ ------------ ------------
(IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS)
Basic earnings per share calculation:
Income from continuing operations before
extraordinary item .................. $ 50 $ 83 $ 144 $ 365
Discontinued operations, net of tax .... -- -- (3) --
Extraordinary item, net of tax ......... -- -- 30 --
------------ ------------ ------------ ------------
Net income ............................. $ 50 $ 83 $ 171 $ 365
============ ============ ============ ============
Weighted average shares outstanding ....... 309,657,000 311,945,000 309,080,000 311,414,000
============ ============ ============ ============
Basic earnings per share:
Income from continuing operations before
extraordinary item .................. $ 0.16 $ 0.27 $ 0.46 $ 1.17
Discontinued operations, net of tax .... -- -- (0.01) --
Extraordinary item, net of tax ......... -- -- 0.10 --
------------ ------------ ------------ ------------
Net income ............................. $ 0.16 $ 0.27 $ 0.55 $ 1.17
============ ============ ============ ============
23
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
2005 2006 2005 2006
------------ ------------ ------------ ------------
(IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS)
Diluted earnings per share calculation:
Net income ............................. $ 50 $ 83 $ 171 $ 365
Plus: Income impact of assumed
conversions:
Interest on 3.75% convertible senior
notes ............................ 2 -- 9 --
------------ ------------ ------------ ------------
Total earnings effect assuming
dilution ............................ $ 52 $ 83 $ 180 $ 365
============ ============ ============ ============
Weighted average shares outstanding ....... 309,657,000 311,945,000 309,080,000 311,414,000
Plus: Incremental shares from assumed
conversions:
Stock options (1) ................... 1,457,000 1,161,000 1,259,000 1,050,000
Restricted stock .................... 1,500,000 1,292,000 1,500,000 1,292,000
2.875% convertible senior notes ..... 1,620,000 1,613,000 -- 349,000
3.75% convertible senior notes ...... 32,269,000 8,705,000 43,183,000 5,869,000
------------ ------------ ------------ ------------
Weighted average shares assuming
dilution ............................ 346,503,000 324,716,000 355,022,000 319,974,000
============ ============ ============ ============
Diluted earnings per share:
Income from continuing operations before
extraordinary item .................. $ 0.15 $ 0.26 $ 0.43 $ 1.14
Discontinued operations, net of tax .... -- -- (0.01) --
Extraordinary item, net of tax ......... -- -- 0.09 --
------------ ------------ ------------ ------------
Net income ............................. $ 0.15 $ 0.26 $ 0.51 $ 1.14
============ ============ ============ ============
----------
(1) Options to purchase 8,940,201 shares were outstanding for both the three
months and nine months ended September 30, 2005, and options to purchase
6,539,344 shares were outstanding for both the three months and nine months
ended September 30, 2006, but were not included in the computation of
diluted earnings per share because the options' exercise price was greater
than the average market price of the common shares for the respective
periods.
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 (subsequent to the August 2005 exchange
discussed in Note 10) 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 were $12.66 and $11.44,
respectively, at September 30, 2006.
(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 accounting
policies of the business segments are the same as those described in the summary
of significant accounting policies except that some executive benefit costs have
not been allocated to business segments. The Company uses operating income as
the measure of profit or loss for its business segments.
The Company's reportable business segments include the following: Electric
Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas
Sales and Services, Pipelines and Field Services and Other Operations. The
electric transmission and distribution function (CenterPoint Houston) is
reported in the Electric Transmission & Distribution business segment. Natural
Gas Distribution consists of intrastate natural gas sales to, and natural gas
transportation and distribution for, residential, commercial, industrial and
institutional customers. The Company reorganized the oversight of its Natural
Gas Distribution business segment and, as a result, beginning in the fourth
quarter of 2005, the Company established a new reportable business segment,
Competitive Natural Gas Sales and Services. Competitive Natural Gas Sales and
Services represents the Company's non-rate regulated gas
24
sales and services operations, which consist of three operational functions:
wholesale, retail and intrastate pipelines. Pipelines and Field Services
includes the interstate natural gas pipeline operations and the natural gas
gathering and pipeline services businesses. Other Operations consists primarily
of other corporate operations which support all of the Company's business
operations. All prior period segment information has been reclassified to
conform to the 2006 presentation.
Long-lived assets include net property, plant and equipment, net goodwill
and other intangibles and equity investments in unconsolidated subsidiaries.
Intersegment sales are eliminated in consolidation.
Financial data for business segments and products and services are as
follows (in millions):
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005
---------------------------------------------
REVENUES FROM NET
EXTERNAL INTERSEGMENT OPERATING
CUSTOMERS REVENUES INCOME (LOSS)
------------- ------------ -------------
Electric Transmission & Distribution ......... $ 484(1) $ -- $183
Natural Gas Distribution ..................... 532 3 (16)
Competitive Natural Gas Sales and Services ... 974 39 4
Pipelines and Field Services ................. 81 35 52
Other Operations ............................. 2 2 2
Eliminations ................................. -- (79) --
------ ---- ----
Consolidated ................................. $2,073 $ -- $225
====== ==== ====
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2006
---------------------------------------------
REVENUES FROM NET
EXTERNAL INTERSEGMENT OPERATING
CUSTOMERS REVENUES INCOME (LOSS)
------------- ------------ -------------
Electric Transmission & Distribution ......... $ 533(1) $ -- $219
Natural Gas Distribution ..................... 483 2 (11)
Competitive Natural Gas Sales and Services ... 813 17 12
Pipelines and Field Services ................. 104 37 69
Other Operations ............................. 2 1 (5)
Eliminations ................................. -- (57) --
------ ---- ----
Consolidated ................................. $1,935 $ -- $284
====== ==== ====
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005
--------------------------------------------
REVENUES FROM NET TOTAL ASSETS
EXTERNAL INTERSEGMENT OPERATING AS OF DECEMBER
CUSTOMERS REVENUES INCOME (LOSS) 31, 2005
------------- ------------ ------------- --------------
Electric Transmission & Distribution ......... $1,243(1) $ -- $385 $ 8,227
Natural Gas Distribution ..................... 2,399 6 116 4,612
Competitive Natural Gas Sales and Services ... 2,607 176 30 1,849
Pipelines and Field Services ................. 252 110 168 2,968
Other Operations ............................. 9 6 (12) 2,202(2)
Eliminations ................................. -- (298) -- (2,742)
------ ----- ---- -------
Consolidated ................................. $6,510 $ -- $687 $17,116
====== ===== ==== =======
25
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2006
--------------------------------------------
REVENUES FROM NET TOTAL ASSETS
EXTERNAL INTERSEGMENT OPERATING AS OF SEPTEMBER
CUSTOMERS REVENUES INCOME (LOSS) 30, 2006
------------- ------------ ------------- ---------------
Electric Transmission & Distribution ......... $1,374(1) $ -- $480 $ 8,247
Natural Gas Distribution ..................... 2,506 8 90 4,260
Competitive Natural Gas Sales and Services ... 2,681 62 44 1,402
Pipelines and Field Services ................. 287 114 203 3,157
Other Operations ............................. 7 5 (7) 2,023(2)
Eliminations ................................. -- (189) -- (2,116)
------ ----- ---- -------
Consolidated ................................. $6,855 $ -- $810 $16,973
====== ===== ==== =======
----------
(1) Sales to subsidiaries of RRI in the three months ended September 30, 2005
and 2006 represented approximately $249 million and $225 million,
respectively. Sales to subsidiaries of RRI in the nine months ended
September 30, 2005 and 2006 represented approximately $615 million and
$569 million, respectively.
(2) Included in total assets of Other Operations as of December 31, 2005 and
September 30, 2006 is a pension asset of $654 million and $624 million,
respectively.
(14) SUBSEQUENT EVENTS
(A) DIVIDEND DECLARATION
On October 26, 2006, the Company's board of directors declared a regular
quarterly cash dividend of $0.15 per share of common stock payable on December
8, 2006, to shareholders of record as of the close of business on November 16,
2006. The conversion rates related to the Company's 3.75% convertible senior
notes and 2.875% convertible senior notes are expected to increase as a result
of such dividend.
(B) RECEIVABLES FACILITY
In October 2006, CERC extended the termination date of its receivables
facility to October 30, 2007. The facility size is $250 million until December
2006, $375 million from December 2006 to May 2007 and ranges from $150 million
to $325 million during the period from May 2007 to the termination date of the
facility.
26
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 Condensed Financial Statements contained in this Form 10-Q.
EXECUTIVE SUMMARY
RECENT EVENTS
Carthage to Perryville Pipeline. In October 2005, CenterPoint Energy Gas
Transmission Company (CEGT), a wholly owned subsidiary of CenterPoint Energy
Resources Corp. (CERC Corp.), signed a 10-year firm transportation agreement
with XTO Energy (XTO) to transport 600 million cubic feet (MMcf) per day of
natural gas from Carthage, Texas to CEGT's Perryville hub in Northeast
Louisiana. To accommodate this transaction, CEGT filed a certificate application
with the Federal Energy Regulatory Commission (FERC) in March 2006 to build a
172-mile, 42-inch diameter pipeline and related compression facilities. The
capacity of the pipeline under this filing will be 1.25 billion cubic feet (Bcf)
per day. CEGT has signed firm contracts for the full capacity of the pipeline.
On October 2, 2006 the FERC issued CEGT's certificate to construct, own and
operate the pipeline and compression facilities. CEGT has begun construction of
the facilities and expects to place the facilities in service in the first
quarter 2007 at a cost of approximately $455 million.
Based on strong interest expressed during an open season held earlier this
year, and subject to FERC approval, CEGT expects to expand capacity of the
pipeline to 1.5 Bcf per day, which would bring the total estimated capital cost
of the project to approximately $510 million. During the four-year period
subsequent to the in-service date of the pipeline, XTO can request, and subject
to mutual negotiations that meet specific financial parameters and to FERC
approval, CEGT would construct a 67-mile extension from CEGT's Perryville hub to
an interconnect with Texas Eastern Gas Transmission at Union Church,
Mississippi.
Pipeline Joint Venture with Duke Energy Subsidiary. Earlier this year,
CenterPoint Energy Southeast Pipelines Holding, L.L.C., a wholly owned
subsidiary of CERC Corp., signed a joint venture agreement with a subsidiary of
Duke Energy Gas Transmission (DEGT) to construct, own and operate a 270-mile
pipeline (Southeast Supply Header) that will extend from CEGT's Perryville hub
in northeast Louisiana to Gulfstream Natural Gas System, which is 50 percent
owned by an affiliate of DEGT. In August 2006, the joint venture signed an
agreement with Florida Power & Light Company (FPL) for firm transportation
services, which subscribes approximately half of the planned 1 Bcf per day
capacity of the pipeline. FPL's commitment is contingent on the approval of the
FPL contract by the Florida Public Service Commission in December 2006. Subject
to the venture receiving a certificate from the FERC to construct, own and
operate the pipeline, subsidiaries of DEGT and CERC Corp. have committed to
build the pipeline, for which total costs are estimated to be $700 to $800
million. The pre-filing process with the FERC has been initiated, and an
application is expected to be filed in December 2006. Once the project is
approved by the FERC, construction is anticipated to begin in the fourth quarter
of 2007, with an expected in-service date of June 2008.
27
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,
------------------ -----------------
2005 2006 2005 2006
------ ------ ------ ------
Revenues ..................................... $2,073 $1,935 $6,510 $6,855
Expenses ..................................... 1,848 1,651 5,823 6,045
------ ------ ------ ------
Operating Income ............................. 225 284 687 810
Interest and Other Finance Charges ........... (177) (152) (548) (451)
Other Income, net ............................ 43 20 127 31
------ ------ ------ ------
Income From Continuing Operations Before
Income Taxes and Extraordinary Item ....... 91 152 266 390
Income Tax Expense ........................... (41) (69) (122) (25)
------ ------ ------ ------
Income From Continuing Operations Before
Extraordinary Item ........................ 50 83 144 365
Discontinued Operations, net of tax .......... -- -- (3) --
------ ------ ------ ------
Income Before Extraordinary Item ............. 50 83 141 365
Extraordinary Item, net of tax ............... -- -- 30 --
------ ------ ------ ------
Net Income ................................... $ 50 $ 83 $ 171 $ 365
====== ====== ====== ======
BASIC EARNINGS PER SHARE:
Income From Continuing Operations ......... $ 0.16 $ 0.27 $ 0.46 $ 1.17
Discontinued Operations, net of tax ....... -- -- (0.01) --
Extraordinary Item, net of tax ............ -- -- 0.10 --
------ ------ ------ ------
Net Income ................................ $ 0.16 $ 0.27 $ 0.55 $ 1.17
====== ====== ====== ======
DILUTED EARNINGS PER SHARE:
Income From Continuing Operations ......... $ 0.15 $ 0.26 $ 0.43 $ 1.14
Discontinued Operations, net of tax ....... -- -- (0.01) --
Extraordinary Item, net of tax ............ -- -- 0.09 --
------ ------ ------ ------
Net Income ................................ $ 0.15 $ 0.26 $ 0.51 $ 1.14
====== ====== ====== ======
THREE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2005
Income from Continuing Operations. We reported income from continuing
operations before extraordinary item of $83 million ($0.26 per diluted share)
for the three months ended September 30, 2006 as compared to $50 million ($0.15
per diluted share) for the same period in 2005. As discussed below, the increase
in income from continuing operations of $33 million was primarily due to:
- a $48 million decrease in interest expense, excluding transition
bond-related interest expense, due to lower borrowing costs and
borrowing levels;
- a $17 million increase in operating income from our Pipelines and
Field Services business segment;
- a $13 million increase in operating income from the regulated utility
operations of our Electric Transmission & Distribution business
segment, including a $12 million increase for the competitive
transition charge (CTC); and
- an $8 million increase in operating income from our Competitive
Natural Gas Sales and Services business segment.
These increases in income from continuing operations were partially offset
by:
- a $35 million decrease in other income related to a return on the
true-up balance of our Electric Transmission & Distribution business
segment recorded in the third quarter of 2005; and
- a $28 million increase in income taxes resulting from higher income.
28
NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2005
Income from Continuing Operations. We reported income from continuing
operations before extraordinary item of $365 million ($1.14 per diluted share)
for the nine months ended September 30, 2006 as compared to $144 million ($0.43
per diluted share) for the same period in 2005. As discussed below, the increase
in income from continuing operations of $221 million was primarily due to:
- a $168 million decrease in interest expense, excluding transition
bond-related interest expense, due to lower borrowing costs and
borrowing levels;
- a $119 million decrease in income tax expense from the reduction to
previously accrued tax and related interest reserves related to our
ZENS and ACES recorded in the second quarter of 2006;
- a $35 million increase in operating income from our Pipelines and
Field Services business segment;
- a $26 million increase in operating income from the regulated utility
operations of our Electric Transmission & Distribution business
segment, including a $42 million increase for the CTC partially offset
by the $32 million adverse impact of the resolution of the 2001
Unbundled Cost of Service (UCOS) order recorded in the second quarter
of 2006; and
- a $14 million increase in operating income from our Competitive
Natural Gas Sales and Services business segment.
These increases in income from continuing operations were partially offset
by:
- a $104 million decrease in other income related to a return on the
true-up balance of our Electric Transmission & Distribution business
segment recorded in the first nine months of 2005; and
- a $26 million decrease in operating income from our Natural Gas
Distribution business segment.
INCOME TAX EXPENSE
During the three months and nine months ended September 30, 2006, our
effective tax rate was 45% and 6%, respectively. We reached an agreement with
the IRS in July 2006 and have reduced our previously accrued tax and related
interest reserves related to the ZENS and ACES by approximately $119 million in
the second quarter of 2006. The most significant items affecting the tax rate
during the three months ended September 30, 2006, were an increase in deferred
state taxes and an increase in the tax reserve. During the three months and nine
months ended September 30, 2005, our effective tax rate was 45% and 46%,
respectively. During the three months and nine months ended September 30, 2005,
the most significant item affecting our effective tax rates was an addition to
the tax reserve relating to the ZENS and ACES of approximately $10 million and
$32 million, respectively.
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. Net income for the nine months ended
September 30, 2005 included a net after-tax loss from discontinued operations of
Texas Genco of $3 million ($0.01 per diluted share).
29
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following table presents operating income (loss) for each of our
business segments for the three and nine months ended September 30, 2005 and
2006. Some amounts from the previous year have been reclassified to conform to
the 2006 presentation of the financial statements. These reclassifications do
not affect consolidated net income.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2005 2006 2005 2006
---- ---- ---- ----
(IN MILLIONS)
Electric Transmission & Distribution ......... $183 $219 $385 $480
Natural Gas Distribution ..................... (16) (11) 116 90
Competitive Natural Gas Sales and Services ... 4 12 30 44
Pipelines and Field Services ................. 52 69 168 203
Other Operations ............................. 2 (5) (12) (7)
---- ---- ---- ----
Total Consolidated Operating Income ....... $225 $284 $687 $810
==== ==== ==== ====
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 "-- Risks Common to Our Business and Other Risks" in
Item 1A of Part I of our Annual Report on Form 10-K for the year ended December
31, 2005 (2005 Form 10-K).
The following tables provide summary data of our Electric Transmission &
Distribution business segment for the three and nine months ended September 30,
2005 and 2006 (in millions, except throughput and customer data):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2005 2006 2005 2006
---------- ---------- ---------- ----------
Revenues:
Electric transmission and distribution utility ... $ 453 $ 453 $ 1,164 $ 1,170
Transition bond companies ........................ 31 80 79 204
---------- ---------- ---------- ----------
Total revenues ................................ 484 533 1,243 1,374
---------- ---------- ---------- ----------
Expenses:
Operation and maintenance ........................ 155 155 446 436
Depreciation and amortization .................... 69 58 197 182
Taxes other than income taxes .................... 55 53 163 168
Transition bond companies ........................ 22 48 52 108
---------- ---------- ---------- ----------
Total expenses ................................ 301 314 858 894
---------- ---------- ---------- ----------
Operating Income .................................... $ 183 $ 219 $ 385 $ 480
========== ========== ========== ==========
Operating Income - Electric transmission and
distribution utility ............................. $ 174 $ 187 $ 358 $ 384
Operating Income - Transition bond
companies (1) .................................... 9 32 27 96
---------- ---------- ---------- ----------
Total segment operating income ............. $ 183 $ 219 $ 385 $ 480
========== ========== ========== ==========
Throughput (in gigawatt-hours (GWh)):
Residential ...................................... 8,871 8,523 19,607 19,317
Total ............................................ 22,351 22,830 57,134 59,239
Average number of metered customers:
Residential ...................................... 1,690,819 1,740,079 1,675,904 1,729,348
Total ............................................ 1,921,594 1,976,559 1,904,235 1,964,189
----------
(1) Represents the amount necessary to pay interest on the transition bonds.
30
THREE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2005
Our Electric Transmission & Distribution business segment reported
operating income of $219 million for the three months ended September 30, 2006,
consisting of $187 million for the regulated electric transmission and
distribution utility (TDU) (including $14 million for the CTC) and $32 million
related to the transition bonds. For the three months ended September 30, 2005,
operating income totaled $183 million, consisting of $174 million for the TDU
(including $2 million for the CTC) and $9 million related to the transition
bonds. Revenues for the TDU continue to benefit from solid customer growth, with
nearly 49,000 metered customers added since September 2005 ($10 million), higher
transmission cost recovery ($3 million) and recovery of our 2004 true-up balance
($2 million). Houston experienced normal weather during the third quarter of
2006, which created an unfavorable weather variance ($14 million) when compared
to the abnormally warm weather in 2005, that substantially offset the increases
in revenues discussed above. Operation and maintenance expense remained flat
primarily due to higher tree trimming expenses ($3 million) and higher
transmission costs ($3 million) offset by lower employee benefit expenses ($4
million) and decreased corporate support services ($4 million). Depreciation and
amortization expense decreased ($11 million) primarily as a result of
amortization of regulatory liabilities related to the 2004 true-up balance ($13
million), partially offset by an increase in depreciation expense due to higher
plant balances ($3 million).
NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2005
Our Electric Transmission & Distribution business segment reported
operating income of $480 million for the nine months ended September 30, 2006,
consisting of $384 million for the TDU (including $44 million for the CTC) and
$96 million related to the transition bonds. For the nine months ended September
30, 2005, operating income totaled $385 million, consisting of $358 million for
the TDU (including $2 million for the CTC) and $27 million related to the
transition bonds. Revenues for the TDU increased due to continued customer
growth, with nearly 49,000 metered customers added since September 2005 ($28
million), recovery of our 2004 true-up balance ($28 million) and higher
transmission recovery ($8 million), partially offset by the unfavorable weather
discussed above and decreased usage ($28 million) and the impact related to the
resolution of the 2001 UCOS order ($32 million). Operation and maintenance
expense decreased primarily due to a gain on the sale of land in 2006 ($14
million) and lower employee benefit and payroll-related expenses ($6 million),
which was partially offset by higher transmission costs ($8 million) and
severance costs associated with staff reductions ($4 million). Depreciation and
amortization expense decreased ($15 million) primarily as a result of
amortization of regulatory liabilities related to the 2004 true-up balance ($26
million), partially offset by an increase in depreciation expense due to higher
plant balances ($8 million). Additionally, taxes other than income taxes
increased primarily due to higher franchise fees ($13 million) partially offset
by decreased property and state franchise tax ($6 million).
NATURAL GAS DISTRIBUTION
For information regarding factors that may affect the future results of
operations of our Natural Gas Distribution business segment, please read "Risk
Factors -- Risk Factors Affecting Our Natural Gas Distribution, Competitive
Natural Gas Sales and Services and Pipelines and Field Services Businesses," "
-- Risk Factors Associated with Our Consolidated Financial Condition" and "--
Risks Common to Our Business and Other Risks" in Item 1A of Part I of our 2005
Form 10-K.
31
The following table provides summary data of our Natural Gas Distribution
business segment for the three and nine months ended September 30, 2005 and 2006
(in millions, except throughput and customer data):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -----------------------
2005 2006 2005 2006
---------- ---------- ---------- ----------
Revenues................................. $ 535 $ 485 $ 2,405 $ 2,514
---------- ---------- ---------- ----------
Expenses:
Natural gas........................... 355 298 1,693 1,787
Operation and maintenance............. 132 137 393 429
Depreciation and amortization......... 39 38 115 113
Taxes other than income taxes......... 25 23 88 95
---------- ---------- ---------- ----------
Total expenses..................... 551 496 2,289 2,424
---------- ---------- ---------- ----------
Operating Income (Loss).................. $ (16) $ (11) $ 116 $ 90
========== ========== ========== ==========
Throughput (in billion cubic feet (Bcf)):
Residential........................... 9 14 107 98
Commercial and industrial............. 38 44 158 160
---------- ---------- ---------- ----------
Total Throughput................... 47 58 265 258
========== ========== ========== ==========
Average number of customers:
Residential........................... 2,820,629 2,849,040 2,835,306 2,864,999
Commercial and industrial............. 244,249 253,063 246,370 253,357
---------- ---------- ---------- ----------
Total.............................. 3,064,878 3,102,103 3,081,676 3,118,356
========== ========== ========== ==========
THREE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2005
Our Natural Gas Distribution business segment reported an operating loss of
$11 million for the three months ended September 30, 2006 as compared to an
operating loss of $16 million for the three months ended September 30, 2005. Due
to seasonal impacts, the third quarter for this business segment is typically
one of the weakest of the year. Higher operating margins (revenues less natural
gas costs) from rate increases and rate design changes, along with the addition
of nearly 43,000 customers since September 2005 ($7 million) were partially
offset by increased operation and maintenance expenses driven primarily by
higher bad debt expense due to high natural gas prices ($5 million).
NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2005
Our Natural Gas Distribution business segment reported operating income of
$90 million for the nine months ended September 30, 2006 as compared to $116
million for the nine months ended September 30, 2005. Increased operating
margins from rate increases and rate design changes, along with the addition of
nearly 43,000 customers since September 2005 ($26 million) and increased gross
receipts taxes resulting from higher revenues ($6 million), were partially
offset by decreased customer usage and unfavorable weather ($20 million).
Operation and maintenance expenses increased primarily due to costs associated
with staff reductions ($12 million), increased bad debt expense due to high
natural gas prices ($11 million), increased contracts and services expenses and
corporate services ($8 million) and a write-off of certain rate case expenses
($3 million). Additionally, taxes other than income taxes increased ($7 million)
primarily due to higher gross receipts taxes ($6 million), which offset the
corresponding increase in revenues discussed above.
COMPETITIVE NATURAL GAS SALES AND SERVICES
For information regarding factors that may affect the future results of
operations of our Competitive Natural Gas Sales and Services business segment,
please read "Risk Factors -- Risk Factors Affecting Our Natural Gas
Distribution, Competitive Natural Gas Sales and Services and Pipelines and Field
Services Business," " -- Risk Factors Associated with Our Consolidated Financial
Condition" and "-- Risks Common to Our Business and Other Risks" in Item 1A of
Part I of our 2005 Form 10-K.
32
The following table provides summary data of our Competitive Natural Gas
Sales and Services business segment for the three and nine months ended
September 30, 2005 and 2006 (in millions, except throughput and customer data):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2005 2006 2005 2006
------ ------ ------- ------
Revenues ................................ $1,013 $ 830 $ 2,783 $2,743
------ ------ ------- ------
Expenses:
Natural gas .......................... 998 809 2,728 2,673
Operation and maintenance ............ 9 8 21 23
Depreciation and amortization ........ -- -- 1 1
Taxes other than income taxes ........ 2 1 3 2
------ ------ ------- ------
Total expenses .................... 1,009 818 2,753 2,699
------ ------ ------- ------
Operating Income ........................ $ 4 $ 12 $ 30 $ 44
====== ====== ======= ======
Throughput (in Bcf):
Wholesale - third parties ............ 81 90 235 251
Wholesale - affiliates ............... 11 8 46 27
Retail ............................... 31 31 112 110
Pipeline ............................. 10 9 41 28
------ ------ ------- ------
Total Throughput .................. 133 138 434 416
====== ====== ======= ======
Average number of customers:
Wholesale ............................ 144 140 143 140
Retail ............................... 6,225 6,213 6,203 6,416
Pipeline ............................. 147 138 154 138
------ ------ ------- ------
Total ............................. 6,516 6,491 6,500 6,694
====== ====== ======= ======
THREE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2005
Our Competitive Natural Gas Sales and Services business segment reported
operating income of $12 million for the three months ended September 30, 2006 as
compared to $4 million for the three months ended September 30, 2005. The
increase was primarily driven by increased sales of gas from inventory ($9
million), reduced bad debt expenses ($2 million) and a favorable variance
related to mark-to-market accounting for non-trading financial derivatives used
to lock in the economic value associated with basis differentials ($21 million).
These positive variances were partially offset by a write-down of natural gas
inventory to the lower of average cost or market ($26 million). Our Competitive
Natural Gas Sales and Services business segment purchases and stores natural gas
to meet certain future sales requirements and enters into derivative contracts
to hedge the economic value of the future sales. Due to the inventory
write-downs, operating income in the future periods, when these sales of
inventory occur, is expected to be higher.
NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2005
Our Competitive Natural Gas Sales and Services business segment reported
operating income of $44 million for the nine months ended September 30, 2006 as
compared to $30 million for the nine months ended September 30, 2005. The
increase included improved margins ($38 million) and a favorable variance
related to mark-to-market accounting ($34 million), which was partially offset
by a write-down of natural gas inventory ($56 million).
PIPELINES AND FIELD SERVICES
For information regarding factors that may affect the future results of
operations of our Pipelines and Field Services business segment, please read
"Risk Factors -- Risk Factors Affecting Our Natural Gas Distribution,
Competitive Natural Gas Sales and Services and Pipelines and Field Services
Businesses," " -- Risk Factors Associated with Our Consolidated Financial
Condition" and "-- Risks Common to Our Business and Other Risks" in Item 1A of
Part I of our 2005 Form 10-K.
33
The following table provides summary data of our Pipelines and Field
Services business segment for the three and nine months ended September 30, 2005
and 2006 (in millions, except throughput data):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2005 2006 2005 2006
---- ---- ---- ----
Revenues .................................... $116 $141 $362 $401
---- ---- ---- ----
Expenses:
Natural gas .............................. -- 7 25 10
Operation and maintenance ................ 47 47 121 136
Depreciation and amortization ............ 12 12 34 36
Taxes other than income taxes ............ 5 6 14 16
---- ---- ---- ----
Total expenses ........................ 64 72 194 198
---- ---- ---- ----
Operating Income ............................ $ 52 $ 69 $168 $203
==== ==== ==== ====
Operating Income - Pipeline business ........ $ 36 $ 48 $119 $137
Operating Income - Field Services business .. 16 21 49 66
---- ---- ---- ----
Total segment operating income ........ $ 52 $ 69 $168 $203
==== ==== ==== ====
Throughput (in Bcf):
Natural Gas Sales ........................ -- 1 4 3
Transportation ........................... 199 204 700 718
Gathering ................................ 92 97 262 279
Elimination (1) .......................... (1) (1) (4) (2)
---- ---- ---- ----
Total Throughput ...................... 290 301 962 998
==== ==== ==== ====
----------
(1) Elimination of volumes both transported and sold.
THREE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2005
Our Pipelines and Field Services business segment reported operating income
of $69 million for the three months ended September 30, 2006 as compared to $52
million for the three months ended September 30, 2005. This segment's businesses
continue to benefit from favorable dynamics in the markets for natural gas
gathering and transportation services in the Gulf Coast and Mid-Continent
regions. Within this segment, the pipeline business achieved higher operating
income of $48 million for the three months ended September 30, 2006 as compared
to $36 million for the same period in 2005. This $12 million increase was
largely attributable to a pre-tax gain of $13 million associated with the FERC
authorized sale of cushion gas which is no longer required for operational
purposes as the result of certain capital improvements to enhance working gas
capacity and deliverability at one of our storage facilities. The field services
business achieved higher operating income of $21 million for the three months
ended September 30, 2006 as compared to $16 million for the same period in 2005
primarily driven by increased throughput ($7 million).
In addition, this business segment recorded equity income of $1 million and
$2 million for the three months ended September 30, 2005 and 2006, respectively,
from its 50 percent interest in a jointly-owned gas processing plant. These
amounts are included in Other - net under the Other Income (Expense) caption in
our Condensed Statements of Consolidated Income.
NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2005
Our Pipelines and Field Services business segment reported operating income
of $203 million for the nine months ended September 30, 2006 as compared to $168
million for the nine months ended September 30, 2005. The pipeline business
achieved operating income of $137 million for the nine months ended September
30, 2006 as compared to $119 million for the same period in 2005. This $18
million increase is attributable to the gain on the sale of cushion gas ($13
million) discussed above, increased demand for transportation due to favorable
basis differentials across the system ($9 million), higher demand for ancillary
services ($6 million) and increased project-related revenues ($5 million). These
favorable variances were partially offset by increased operating expenses
related to increased project-related expenses ($4 million), increased labor-
related costs ($3 million) and increased
34
costs associated with normal pipeline maintenance, compliance with pipeline
integrity regulations and normal price level increases ($8 million). The field
services business achieved operating income of $66 million for the nine months
ended September 30, 2006 as compared to $49 million for the same period in 2005
driven by increased throughput ($14 million), higher commodity prices ($7
million) and higher demand for ancillary services ($2 million), partially offset
by increased operation and maintenance expenses ($6 million).
Equity income from the jointly-owned gas processing plant discussed above
was $4 million and $7 million for the nine months ended September 30, 2005 and
2006, respectively.
OTHER OPERATIONS
The following table shows the operating loss of our Other Operations
business segment for the three and nine months ended September 30, 2005 and 2006
(in millions):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ -----------------
2005 2006 2005 2006
---- ---- ---- ----
Revenues.................... $4 $ 3 $ 15 $12
Expenses.................... 2 8 27 19
--- --- ---- ---
Operating Income (Loss)..... $2 $(5) $(12) $(7)
=== === ==== ===
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
For information on other developments, factors and trends that may have an
impact on our future earnings, please read Note 5(d) to the Interim Condensed
Financial Statements for a discussion of CenterPoint Houston's rate case
settlement, "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Certain Factors Affecting Future Earnings" in Item 7 of
Part II and "Risk Factors" in Item 1A of Part I of our 2005 Form 10-K and "Risk
Factors" in Item 1A of Part II of this Quarterly Report on Form 10-Q.
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, 2005 and 2006 (in millions):
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------
2005 2006
----- -----
Cash provided by (used in):
Operating activities............ $ 275 $ 728
Investing activities............ 218 (626)
Financing activities............ (496) 109
CASH PROVIDED BY OPERATING ACTIVITIES
Net cash provided by operating activities in the first nine months of 2006
increased $453 million compared to the same period in 2005 primarily due to
decreased tax payments of $314 million, the majority of which related to the tax
payment in the first quarter of 2005 associated with the sale of our former
electric generation business (Texas Genco), increased fuel over-recovery ($175
million) primarily related to declining gas prices during the first nine months
of 2006, decreases in net regulatory assets ($231 million), primarily due to the
termination of excess mitigation credits effective April 29, 2005, decreased gas
storage inventory purchases ($96 million) and decreased cash used in the
operations of Texas Genco ($38 million). These increases in cash provided by
operating activities were partially offset by decreased net accounts
receivable/payable ($140 million) primarily due to decreased gas prices in the
first nine months of 2006 as compared to the same period in 2005 and decreases
in funding of purchases of receivables under CERC Corp.'s receivables facility.
Additionally, customer margin deposit requirements decreased ($203 million)
primarily due to the decline in natural gas prices from December 2005 to
September 2006 and our margin deposits increased ($51 million).
35
CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES
Net cash used in investing activities increased $844 million in the first
nine months of 2006 as compared to the same period in 2005 primarily due to
increased capital expenditures of $135 million primarily related to our Electric
Transmission & Distribution and Pipelines and Field Services business segments
and the absence of $700 million in proceeds received in the second quarter of
2005 from the sale of our remaining interest in Texas Genco and cash of Texas
Genco of $24 million.
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
Net cash provided by financing activities in the first nine months of 2006
increased $605 million compared to the same period in 2005 primarily due to net
proceeds from the issuance of long-term debt of $324 million, decreased
repayments of borrowings under our revolving credit facility ($239 million) and
decreased payments of long-term debt ($341 million), partially offset by the
absence of commercial paper borrowings ($190 million) and borrowings under Texas
Genco's revolving credit facility ($75 million) due to the sale of Texas Genco
and increased dividend payments of $35 million.
FUTURE SOURCES AND USES OF CASH
Our liquidity and capital requirements are affected primarily by our
results of operations, capital expenditures, debt service requirements, tax
payments, working capital needs, various regulatory actions and appeals relating
to such regulatory actions. Our principal cash requirements for the remaining
three months of 2006 include the following:
- approximately $420 million of capital expenditures, including
approximately $200 million related to our Carthage to Perryville
pipeline project discussed above;
- dividend payments on CenterPoint Energy common stock and debt service
payments; and
- long-term debt payments of $145 million.
We expect that borrowings under our credit facilities, liquidation of
temporary investments 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.
Commodity Commitments. We negotiated new natural gas transportation
contracts during 2006 which was the primary reason for a $933 million increase
in the amount of other commodity commitments from the contractual obligations
reported in our 2005 Form 10-K. Minimum payment obligations for natural gas
supply and related transportation commitments are approximately $302 million for
the remaining three months of 2006, $724 million in 2007, $230 million in 2008,
$131 million in 2009, $130 million in 2010 and $733 million in 2011 and
thereafter.
Convertible Debt. As of September 30, 2006, the 3.75% convertible senior
notes discussed in Note 10 to our Interim Condensed Financial Statements have
been included as current portion of long-term debt in the Consolidated Balance
Sheets 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 quarter of 2006 was greater than or
equal to 120% of the conversion price of the 3.75% convertible senior notes and
therefore, during the fourth quarter of 2006, the 3.75% convertible senior notes
meet the criteria that make them eligible for conversion at the option of the
holders of these notes.
Arkansas Public Service Commission, Affiliate Transaction Rulemaking
Proceeding. On August 10, 2006, the Arkansas Public Service Commission (APSC)
instituted a rulemaking proceeding to promulgate rules governing affiliate
transactions involving public utilities operating in Arkansas.
The proposed rules would treat as affiliate transactions all transactions
between CERC Corp.'s Arkansas utility operations and other divisions of CERC
Corp., as well as transactions between the Arkansas utility operations and
affiliates of CERC Corp. All such affiliate transactions would have to be priced
under an asymmetrical pricing formula under which the Arkansas utility
operations would benefit from any difference between the cost of providing goods
and services to or from the Arkansas utility operations and the market value of
those goods or services. The Arkansas utility operations could not participate
in any financing other than to finance retail utility operations in Arkansas,
which would preclude continuation of existing financing arrangements in which
CERC Corp. finances its divisions and subsidiaries, including its Arkansas
utility operations. Currently, CERC Corp. provides financing for all regulated
gas distribution divisions in Arkansas, Louisiana, Minnesota, Mississippi,
Oklahoma and Texas and for CERC's pipeline, field services, gas services and
other unregulated businesses.
Under the proposed rules, utilities operating in Arkansas would be required
to provide annual certifications from the utility's chief executive and chief
financial officers that the rules have been complied with during the previous
year, and the utility would be required to fund, without recovery through rates
or otherwise, the cost of an annual audit of the utility's compliance with the
requirements of the affiliated transactions rules. The utility would be
restricted in the level of its non-utility activities and could be required to
terminate relationships with affiliates (including its parent) if the APSC were
to find that a downgrade of the utility's bond ratings below investment grade
would not have occurred but for its relationship with that affiliate. The
utility or its parent utility holding company would also be required to file an
annual report, signed by its president, certifying that the utility is in
compliance with the rules regarding non-utility ownership and providing
financial information necessary to demonstrate compliance.
No prediction can be made at this time as to whether, or in what form, the
proposed Arkansas affiliate transaction rules will be adopted. However, if the
rules are adopted as proposed, the rules would have significant adverse effects
on CERC's ability to operate its utility operations in Arkansas. At a minimum, a
restructuring of CERC Corp. would be required to create a legal separation of
the Arkansas utility operations from CERC Corp.'s other utility and non-utility
activities. Financing separate from the financing currently provided by CERC for
its utility and non-utility operations would be required for the Arkansas
utility operations.
Further, it is still unclear whether CERC would be able to restructure its
organization and financing arrangements in order to comply with the proposed
rules. It is also unclear whether, even after such a restructuring, the Arkansas
utility operations could provide cost-effective utility service in Arkansas.
Under the procedural schedule established by the APSC, comments on the
proposed rules were filed with the APSC by CERC and other interested persons on
October 6, 2006 and reply comments were filed October 27, 2006. A hearing on the
adoption of the proposed rules is scheduled for November 8, 2006. CERC is
vigorously contesting the adoption of the proposed rules by the APSC in their
current form on the grounds that (i) the proposed rules exceed the statutory
authority granted to APSC on the matters covered by the proposed rules, (ii)
their implementation would violate the Interstate Commerce Clause of the U.S.
Constitution, and (iii) the rules would adversely affect service provided to
Arkansas consumers.
Off-Balance Sheet Arrangements. Other than operating leases and the
guarantees described below, 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, that 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 Statement of Financial Accounting Standards
(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 Condensed Consolidated Balance Sheet. In October 2006, the
termination date of CERC's receivables facility was extended to October 2007. As
of September 30, 2006, no amounts were funded under such facility. The facility
size is $250 million until December 2006, $375 million from December 2006 to May
2007 and ranges from $150 million to $325 million during the period from May
2007 to the termination date of the facility.
Prior to CenterPoint Energy's distribution of its ownership in RRI to its
shareholders, CERC had guaranteed certain contractual obligations of what became
RRI's trading subsidiary. Under the terms of the separation agreement between
the companies, RRI agreed to extinguish all such guarantee obligations prior to
separation, but when separation occurred in September 2002, RRI had been unable
to extinguish all obligations. To secure CenterPoint Energy and CERC against
obligations under the remaining guarantees, RRI agreed to provide cash or
36
letters of credit for the benefit of CERC and CenterPoint Energy, and agreed to
use commercially reasonable efforts to extinguish the remaining guarantees.
CenterPoint Energy's current exposure under the remaining guarantees relates to
CERC's guarantee of the payment by RRI of demand charges related to
transportation contracts with one counterparty. The demand charges are
approximately $53 million per year in 2006 through 2015, $49 million in 2016,
$38 million in 2017 and $13 million in 2018. As a result of changes in market
conditions, the Company's potential exposure under that guarantee currently
exceeds the security provided by RRI. CenterPoint Energy has requested RRI to
increase the amount of its existing letters of credit or, in the alternative, to
obtain a release of CERC's obligations under the guarantee. On June 30, 2006,
the RRI trading subsidiary and CERC jointly filed a complaint at the FERC
against the counterparty on the CERC guarantee. In the complaint, the RRI
trading subsidiary seeks a determination by the FERC that the security held by
the counterparty exceeds the level permitted by the FERC's policies. The
complaint asks the FERC to require the counterparty to release CERC from its
guarantee obligation and, in its place accept (i) a guarantee from RRI of the
obligations of the RRI trading subsidiary, and (ii) letters of credit equal to
(A) one year of demand charges for a transportation agreement related to a 2003
expansion of the counterparty's pipeline, and (B) three months of demand charges
for three other transportation agreements held by the RRI trading subsidiary. On
July 20, 2006, the counterparty filed its answer to the complaint, arguing that
CERC is contractually bound to continue the guarantee, that the amount of the
guarantee does not violate the FERC's policies and that the proposed
substitution of credit support is not authorized under the counterparty's
financing documents. CenterPoint Energy and the RRI trading subsidiary have
filed a reply to that answer and in response to a FERC order, the counterparty
has submitted financing documents for FERC review. It is presently unknown what
action the FERC may take on the complaint. The RRI trading subsidiary continues
to meet its obligations under the transportation contracts.
Senior Notes. In May 2006, CERC Corp. issued $325 million aggregate
principal amount of senior notes due in May 2016 with an interest rate of 6.15%.
The proceeds from the sale of the senior notes will be used for general
corporate purposes, including repayment or refinancing of debt (including $145
million of CERC's 8.90% debentures due December 15, 2006), capital expenditures
and working capital.
Credit Facilities. In March 2006, we, CenterPoint Houston and CERC Corp.,
entered into amended and restated bank credit facilities. We replaced our $1
billion five-year revolving credit facility with a $1.2 billion five-year
revolving credit facility. The facility has a first drawn cost of LIBOR plus 60
basis points based on our current credit ratings, as compared to LIBOR plus 87.5
basis points for borrowings under the facility it replaced. The facility
contains covenants, including a debt (excluding transition bonds) to earnings
before interest, taxes, depreciation and amortization (EBITDA) covenant.
CenterPoint Houston replaced its $200 million five-year revolving credit
facility with a $300 million five-year revolving credit facility. The facility
has a first drawn cost of LIBOR plus 45 basis points based on CenterPoint
Houston's current credit ratings, as compared to LIBOR plus 75 basis points for
borrowings under the facility it replaced. The facility contains covenants,
including a debt (excluding transition bonds) to total capitalization covenant
of 65%.
CERC Corp. replaced its $400 million five-year revolving credit facility
with a $550 million five-year revolving credit facility. The facility has a
first drawn cost of LIBOR plus 45 basis points based on CERC Corp.'s current
credit ratings, as compared to LIBOR plus 55 basis points for borrowings under
the facility it replaced. The facility contains covenants, including a debt to
total capitalization covenant of 65%.
Under each of the credit facilities, an additional utilization fee of 10
basis points applies to borrowings any time more than 50% of the facility is
utilized, and the spread to LIBOR fluctuates based on the borrower's credit
rating. Borrowings under each of the facilities are subject to customary terms
and conditions. However, there is no requirement that we, CenterPoint Houston or
CERC Corp. make representations prior to borrowings as to the absence of
material adverse changes or litigation that could be expected to have a material
adverse effect. Borrowings under each of the credit facilities are subject to
acceleration upon the occurrence of events of default that we, CenterPoint
Houston or CERC Corp. consider customary.
We, CenterPoint Houston and CERC Corp. are currently in compliance with the
various business and financial covenants contained in the respective credit
facilities.
37
As of October 31, 2006, we had the following credit facilities (in
millions):
SIZE OF AMOUNT UTILIZED AT
DATE EXECUTED COMPANY FACILITY OCTOBER 31, 2006 TERMINATION DATE
-------------- ------------------- -------- ------------------ ----------------
March 31, 2006 CenterPoint Energy $1,200 $28(1) March 31, 2011
March 31, 2006 CenterPoint Houston 300 4(1) March 31, 2011
March 31, 2006 CERC Corp. 550 4(1) March 31, 2011
----------
(1) Represents outstanding letters of credit.
The $1.2 billion CenterPoint Energy credit facility backstops a $1.0
billion commercial paper program under which CenterPoint Energy began issuing
commercial paper in June 2005. As of September 30, 2006, there was no commercial
paper outstanding. The commercial paper is rated "Not Prime" by Moody's
Investors Service, Inc. (Moody's), "A-3" by Standard & Poor's Rating Services
(S&P), a division of The McGraw-Hill Companies, and "F3" by Fitch, Inc. (Fitch)
and, as a result, we do not expect to be able to rely on the sale of commercial
paper to fund all of our short-term borrowing requirements. 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, 2006, 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. As of September 30, 2006, we had external temporary
investments of $230 million. As of October 31, 2006, we had external temporary
investments of $279 million.
Money Pool. We have a "money pool" through which the holding company and
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 or the
sale of commercial paper.
Impact on Liquidity of a Downgrade in Credit Ratings. As of October 31,
2006, 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 A- Stable
CERC Corp. Senior Unsecured 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 $1.2
billion credit facility, CenterPoint Houston's $300 million credit facility and
CERC's $550 million revolving credit facility. A decline in credit ratings would
also increase the interest rate on long-term debt to be issued in the capital
markets and could negatively impact our ability to complete capital market
transactions. Additionally, a decline in credit ratings could increase
38
cash collateral requirements and reduce margins of our Natural Gas Distribution
and Competitive Natural Gas Sales and Services business segments.
In September 1999, we issued 2.0% ZENS having an original principal amount
of $1.0 billion of which $840 million remain outstanding. 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 TW Common attributable to
each ZENS note. If our creditworthiness were to drop such that ZENS note holders
thought our liquidity was adversely affected or the market for the ZENS notes
were to become illiquid, some ZENS note holders might decide to exchange their
ZENS notes for cash. Funds for the payment of cash upon exchange could be
obtained from the sale of the shares of TW Common that we own or from other
sources. We own shares of TW Common equal to 100% of the reference shares used
to calculate our obligation to the holders of the ZENS notes. ZENS note
exchanges result in a cash outflow because deferred tax liabilities related to
the ZENS notes and TW Common shares become current tax obligations when ZENS
notes are exchanged and TW Common shares are sold.
CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of CERC
Corp. operating in our Competitive Natural Gas Sales and Services business
segment, provides comprehensive natural gas sales and services primarily to
commercial and industrial customers and electric and gas utilities throughout
the central and eastern United States. In order to hedge its exposure to natural
gas prices, CES uses financial derivatives with provisions standard for the
industry, including those pertaining to credit thresholds. Typically, the credit
threshold negotiated with each counterparty defines the amount of unsecured
credit that such counterparty will extend to CES. To the extent that the
mark-to-market exposure that a counterparty has to CES at a particular time does
not exceed that credit threshold, CES is not obligated to provide collateral.
Mark-to-market exposure in excess of the credit threshold is routinely
collateralized by CES. Should the credit ratings of CERC Corp. (the credit
support provider for CES) fall below certain levels, CES would be required to
provide additional collateral on two business days' notice up to the amount of
its previously unsecured credit limit. We estimate that as of September 30,
2006, unsecured credit limits extended to CES by counterparties aggregate $133
million; however, utilized credit capacity is significantly lower. In addition,
CERC Corp. and its subsidiaries purchase natural gas under supply agreements
that contain an aggregate credit threshold of $100 million based on CERC Corp.'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.
In connection with the development of the Southeast Supply Header, CERC
Corp. has committed that it will advance funds to the joint venture or cause
funds to be advanced, up to $400 million, for its 50 percent share of the cost
to construct the pipeline. CERC Corp. also agreed to provide a letter of credit
in the amount of its share of funds which have not been advanced in the event
S&P reduces CERC Corp.'s bond rating below investment grade after November 30,
2006 and before CERC Corp. has advanced the required construction funds.
However, CERC Corp. is relieved of these commitments (i) to the extent of 50
percent of any borrowing agreements that the joint venture has obtained and
maintains for funding the construction of the pipeline and (ii) to the extent
CERC Corp. or its subsidiary participating in the joint venture obtains
committed borrowing agreements pursuant to which funds may be borrowed and used
for the construction of the pipeline. A similar commitment has been provided by
the other party to the joint venture.
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 October
31, 2006, 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 and Competitive
Natural Gas Sales and Services business segments, 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 natural gas suppliers;
- increased costs related to the acquisition of natural gas;
- increases in interest expense in connection with debt refinancings and
borrowings under credit facilities;
- various regulatory actions;
- the ability of RRI and its subsidiaries to satisfy their obligations
as the principal customers of CenterPoint Houston and in respect of
RRI's indemnity obligations to us and our subsidiaries or in
connection with the contractual arrangement pursuant to which CERC is
a guarantor;
39
- 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;
- the outcome of litigation brought by and against us;
- contributions to benefit plans;
- restoration costs and revenue losses resulting from natural disasters
such as hurricanes; and
- various other risks identified in "Risk Factors" in Item 1A of Part I
of our 2005 Form 10-K and in "Risk Factors" in Item 1A of Part II of
this Quarterly Report on Form 10-Q.
Certain Contractual Limits on Our Ability to Issue Securities, Borrow Money
and Pay Dividends on Our Common Stock. CenterPoint Houston's credit facility
limits CenterPoint Houston's debt (excluding transition bonds) as a percentage
of its total capitalization to 65 percent. CERC Corp.'s bank facility and its
receivables facility limit CERC's debt as a percentage of its total
capitalization to 65 percent. Our $1.2 billion credit facility contains a debt
to EBITDA covenant. Additionally, in connection with the issuance of a certain
series of general mortgage bonds, CenterPoint Houston agreed not to issue,
subject to certain limited exceptions, additional first mortgage bonds.
CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one that is both important to the
presentation of our financial condition and results of operations and requires
management to make difficult, subjective or complex accounting estimates. An
accounting estimate is an approximation made by management of a financial
statement element, item or account in the financial statements. Accounting
estimates in our historical consolidated financial statements measure the
effects of past business transactions or events, or the present status of an
asset or liability. The accounting estimates described below require us to make
assumptions about matters that are highly uncertain at the time the estimate is
made. Additionally, different estimates that we could have used or changes in an
accounting estimate that are reasonably likely to occur could have a material
impact on the presentation of our financial condition or results of operations.
The circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be predicted with certainty. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes. Our significant accounting policies are discussed in Note 2 to the
consolidated financial statements in our 2005 Form 10-K. 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. Our Electric Transmission &
Distribution business applies 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 former 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 $308 million of
recoverable electric generation-related regulatory assets as of September 30,
2006. These costs are recoverable under the provisions of the 1999 Texas
Electric Choice Plan. Based on our analysis of the final order issued by the
Texas Utility Commission, 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.
40
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. Additionally, a district court in Travis
County, Texas issued a judgment that would have the effect of restoring
approximately $650 million, plus interest, of disallowed costs. CenterPoint
Houston and other parties appealed the district court judgment. Oral argument to
the 3rd Court of Appeals in Austin is not expected to occur before late November
2006. No amounts related to the district court's judgment have been recorded in
our consolidated financial statements.
IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES
We review the carrying value of our long-lived assets, including goodwill
and identifiable intangibles, whenever events or changes in circumstances
indicate that such carrying values may not be recoverable, and at least annually
for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible
Assets." No impairment of goodwill was indicated based on our annual analysis as
of July 1, 2006. 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.
ASSET RETIREMENT OBLIGATIONS
We account for our long-lived assets under SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS No. 143), and Financial Accounting Standards
Board Interpretation No. 47, "Accounting for Conditional Asset Retirement
Obligations -- An Interpretation of SFAS No. 143" (FIN 47). SFAS No. 143 and FIN
47 require that an asset retirement obligation be recorded at fair value in the
period in which it is incurred if a reasonable estimate of fair value can be
made. In the same period, the associated asset retirement costs are capitalized
as part of the carrying amount of the related long-lived asset. Rate-regulated
entities may recognize regulatory assets or liabilities as a result of timing
differences between the recognition of costs as recorded in accordance with SFAS
No. 143 and FIN 47, and costs recovered through the ratemaking process.
We estimate the fair value of asset retirement obligations by calculating
the discounted cash flows that are dependent upon the following components:
- Inflation adjustment -- The estimated cash flows are adjusted for
inflation estimates for labor, equipment, materials, and other
disposal costs;
- Discount rate -- The estimated cash flows include contingency factors
that were used as a proxy for the market risk premium; and
- Third party markup adjustments -- Internal labor costs included in the
cash flow calculation were adjusted for costs that a third party would
incur in performing the tasks necessary to retire the asset.
Changes in these factors could materially affect the obligation recorded to
reflect the ultimate cost associated with retiring the assets under SFAS No. 143
and FIN 47. For example, if the inflation adjustment increased 25 basis points,
this would increase the balance for asset retirement obligations by
approximately 3.0%. Similarly, an increase in the discount rate by 25 basis
points would decrease asset retirement obligations by approximately the same
percentage. At September 30, 2006, our estimated cost of retiring these assets
is approximately $79 million.
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,
41
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 that 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. 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 our 2005 Form 10-K.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 4 to the Interim Condensed Financial Statements for a discussion
of new accounting pronouncements that affect us.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK FROM NON-TRADING ACTIVITIES
We measure the commodity risk of our non-trading derivatives (Non-Trading
Energy Derivatives) using a sensitivity analysis.
The sensitivity analysis performed on our Non-Trading Energy Derivatives
measures the potential loss based on a hypothetical 10% movement in energy
prices. At September 30, 2006, the recorded fair value of our Non-Trading Energy
Derivatives was a net liability of $101 million. A decrease of 10% in the market
prices of energy commodities from their September 30, 2006 levels would have
decreased the fair value of our Non-Trading Energy Derivatives from their levels
on that date by $98 million.
The above analysis of the Non-Trading Energy Derivatives utilized for price
risk management purposes does not include the favorable impact that the same
hypothetical price movement would have on our physical purchases and sales of
natural gas to which the hedges relate. Furthermore, the Non-Trading Energy
Derivative portfolio is managed to complement the physical transaction
portfolio, reducing overall risks within limits. Therefore, the adverse impact
to the fair value of the portfolio of Non-Trading Energy Derivatives held for
risk management purposes associated with the hypothetical changes in commodity
prices referenced above is expected to be substantially offset by a favorable
impact on the underlying physical transactions.
INTEREST RATE RISK
We have outstanding long-term debt, bank loans, mandatory redeemable
preferred securities of subsidiary trusts holding solely our junior subordinated
debentures (trust preferred securities), some lease obligations and our
obligations under the ZENS that subject us to the risk of loss associated with
movements in market interest rates.
We had no floating-rate obligations at September 30, 2006.
At September 30, 2006, we had outstanding fixed-rate debt (excluding
indexed debt securities) and trust preferred securities aggregating $9.1 billion
in principal amount and having a fair value of $9.6 billion. These
42
instruments are fixed-rate and, therefore, do not expose us to the risk of loss
in earnings due to changes in market interest rates. However, the fair value of
these instruments would increase by approximately $394 million if interest rates
were to decline by 10% from their levels at September 30, 2006. In general, such
an increase in fair value would impact earnings and cash flows only if we were
to reacquire all or a portion of these instruments in the open market prior to
their maturity.
Upon adoption of SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" (SFAS No. 133), effective January 1, 2001, the ZENS
obligation was bifurcated into a debt component and a derivative component. The
debt component of $111 million at September 30, 2006 is a fixed-rate obligation
and, therefore, does not expose us to the risk of loss in earnings due to
changes in market interest rates. However, the fair value of the debt component
would increase by approximately $17 million if interest rates were to decline by
10% from levels at September 30, 2006. Changes in the fair value of the
derivative component will be recorded in our Condensed Statements of
Consolidated Income and, therefore, we are exposed to changes in the fair value
of the derivative component as a result of changes in the underlying risk-free
interest rate. If the risk-free interest rate were to increase by 10% from
September 30, 2006 levels, the fair value of the derivative component would
increase by approximately $6 million, which would be recorded as a loss in our
Condensed Statements of Consolidated Income.
EQUITY MARKET VALUE RISK
We are exposed to equity market value risk through our ownership of 21.6
million shares of TW Common, which we hold to facilitate our ability to meet our
obligations under the ZENS. A decrease of 10% from the September 30, 2006 market
value of TW Common would result in a net loss of approximately $4 million, which
would be recorded as a loss in our Condensed Statements of Consolidated Income.
ITEM 4. CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our principal executive officer and principal financial officer, of
the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls
and procedures were effective as of September 30, 2006 to provide assurance that
information required to be disclosed in our reports filed or submitted under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange Commission's rules and forms
and such information is accumulated and communicated to our management,
including our principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding disclosure.
There has been no change in our internal controls over financial reporting
that occurred during the three months ended September 30, 2006 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For a description of certain legal and regulatory proceedings affecting
CenterPoint Energy, please read Notes 5 and 11 to our Interim Condensed
Financial Statements, each of which is incorporated herein by reference. See
also "Business -- Regulation" and " -- Environmental Matters" in Item 1 and
"Legal Proceedings" in Item 3 of our 2005 Form 10-K.
43
ITEM 1A. RISK FACTORS
Other than with respect to the risk factor related to our Pipelines and
Field Services business segment set forth below, there have been no material
changes from the risk factors disclosed in our 2005 Form 10-K.
THE ACTUAL CONSTRUCTION COSTS OF OUR PROPOSED PIPELINES AND RELATED COMPRESSION
FACILITIES MAY BE SIGNIFICANTLY HIGHER THAN OUR CURRENT ESTIMATES.
The construction of new pipelines and related compression facilities
requires the expenditure of significant amounts of capital, which may exceed our
estimates. If we undertake these projects, they may not be completed at the
budgeted cost, on schedule or at all. The construction of new pipeline or
compression facilities is subject to construction cost overruns due to labor
costs, costs of equipment and materials, such as steel and nickel, labor
shortages or delays, inflation or other factors, which could be material. In
addition, the construction of these facilities is typically subject to the
receipt of approvals and permits from various regulatory agencies. Those
agencies may not approve the projects in a timely manner or may impose
restrictions or conditions on the projects that could potentially prevent a
project from proceeding, lengthen its expected completion schedule and/or
increase the anticipated cost of the project. As a result, there is the risk
that the new facilities may not be able to achieve our expected investment
return, which could adversely affect our financial condition, results of
operations or cash flows.
ITEM 5. OTHER INFORMATION
The ratio of earnings to fixed charges for the nine months ended September
30, 2005 and 2006 was 1.47 and 1.82, respectively. We do not believe that the
ratios for these nine-month periods are necessarily indicators of the ratios for
the twelve-month periods due to the seasonal nature of our business. The ratios
were calculated pursuant to applicable rules of the Securities and Exchange
Commission.
ITEM 6. EXHIBITS
The following exhibits are filed herewith:
Exhibits not incorporated by reference to a prior filing are designated by
a cross (+); all exhibits not so designated are incorporated by reference to a
prior filing of CenterPoint Energy, Inc.
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
3.1.1 -- 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 1-31447 3.1.1
and Restated Articles of the year ended December 31, 2001
Incorporation of CenterPoint Energy
3.2 -- Amended and Restated Bylaws of CenterPoint Energy's Form 10-K for 1-31447 3.2
CenterPoint Energy the year ended December 31, 2001
3.3 -- Statement of Resolution CenterPoint Energy's Form 10-K for 1-31447 3.3
Establishing Series of Shares the 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 1-31447 4.2
2002, between CenterPoint Energy the year ended December 31, 2001
and JPMorgan Chase Bank, as Rights
Agent
4.3 -- $1,200,000,000 Amended and Restated CenterPoint Energy's Form 8-K dated 1-31447 4.1
Credit Agreement dated as of March March 31, 2006
31, 2006, among CenterPoint Energy,
44
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
as Borrower, and the banks named
therein
4.4 -- $300,000,000 Amended and Restated CenterPoint Energy's Form 8-K dated 1-31447 4.2
Credit Agreement dated as of March March 31, 2006
31, 2006, among CenterPoint
Houston, as Borrower, and the
Initial Lenders named therein, as
Initial Lenders
4.5 -- $550,000,000 Amended and Restated CenterPoint Energy's Form 8-K dated 1-31447 4.3
Credit Agreement dated as of March March 31, 2006
31, 2006 among CERC Corp., as
Borrower, and the banks named
therein
+12 -- Computation of Ratios of Earnings
to Fixed Charges
+31.1 -- Rule 13a-14(a)/15d-14(a)
Certification of David M.
McClanahan
+31.2 -- Rule 13a-14(a)/15d-14(a)
Certification of Gary L. Whitlock
+32.1 -- Section 1350 Certification of David
M. McClanahan
+32.2 -- Section 1350 Certification of Gary
L. Whitlock
+99.1 -- Items incorporated by reference
from the CenterPoint Energy Form
10-K. Item 1A "Risk Factors"
45
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: November 2, 2006
46
Index to Exhibits
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
3.1.1 -- Amended and Restated Articles CenterPoint Energy's Registration 3-69502 3.1
of Incorporation of Statement on Form S-4
CenterPoint Energy
3.1.2 -- Articles of Amendment to CenterPoint Energy's Form 10-K for 1-31447 3.1.1
Amended and Restated Articles the year ended December 31, 2001
of Incorporation of
CenterPoint Energy
3.2 -- Amended and Restated Bylaws of CenterPoint Energy's Form 10-K for 1-31447 3.2
CenterPoint Energy the year ended December 31, 2001
3.3 -- Statement of Resolution CenterPoint Energy's Form 10-K for 1-31447 3.3
Establishing Series of Shares the year ended December 31, 2001
designated Series A Preferred
Stock of CenterPoint Energy
4.1 -- Form of CenterPoint Energy CenterPoint Energy's Registration 3-69502 4.1
Stock Certificate Statement on Form S-4
4.2 -- Rights Agreement dated January CenterPoint Energy's Form 10-K for 1-31447 4.2
1, 2002, between CenterPoint the year ended December 31, 2001
Energy and JPMorgan Chase
Bank, as Rights Agent
4.3 -- $1,200,000,000 Amended and CenterPoint Energy's Form 8-K dated 1-31447 4.1
Restated Credit Agreement March 31, 2006
dated as of March 31, 2006,
among CenterPoint Energy, as
Borrower, and the banks named
therein
4.4 -- $300,000,000 Amended and CenterPoint Energy's Form 8-K dated 1-31447 4.2
Restated Credit Agreement March 31, 2006
dated as of March 31, 2006,
among CenterPoint Houston, as
Borrower, and the Initial
Lenders named therein, as
Initial Lenders
4.5 -- $550,000,000 Amended and CenterPoint Energy's Form 8-K dated 1-31447 4.3
Restated Credit Agreement March 31, 2006
dated as of March 31, 2006
among CERC Corp., as Borrower,
and the banks named therein
+12 -- Computation of Ratios of
Earnings to Fixed Charges
+31.1 -- Rule 13a-14(a)/15d-14(a)
Certification of David M.
McClanahan
+31.2 -- Rule 13a-14(a)/15d-14(a)
Certification of Gary L.
Whitlock
+32.1 -- Section 1350 Certification of
David M. McClanahan
+32.2 -- Section 1350 Certification of
Gary L. Whitlock
+99.1 -- Items incorporated by
reference from the CenterPoint
Energy Form 10-K. Item 1A
"Risk Factors"
47