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 MARCH 31, 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 Identification No.)
incorporation or organization)
1111 LOUISIANA
HOUSTON, TEXAS 77002 (713) 207-1111
(Address and zip code of principal (Registrant's telephone number,
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 May 1, 2006, CenterPoint Energy, Inc. had 311,378,251 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 MARCH 31, 2006
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements...................................... 1
Condensed Statements of Consolidated Income
Three Months Ended March 31, 2005 and 2006 (unaudited)...... 1
Condensed Consolidated Balance Sheets
December 31, 2005 and March 31, 2006 (unaudited)............ 2
Condensed Statements of Consolidated Cash Flows
Three Months Ended March 31, 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.................... 24
Item 3. Quantitative and Qualitative Disclosures about Market
Risk................................................... 36
Item 4. Controls and Procedures................................... 37
PART II. OTHER INFORMATION
Item 1. Legal Proceedings......................................... 38
Item 1A. Risk Factors............................................. 38
Item 5. Other Information......................................... 38
Item 6. Exhibits.................................................. 38
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 and
actions with respect to:
- allowed rates of return;
- rate structures;
- recovery of investments; and
- operation and construction of facilities;
- 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;
- 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);
- the ability of RRI to satisfy its obligations to us, including
indemnity obligations;
ii
- 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.
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
ENDED MARCH 31,
---------------
2005 2006
------ ------
REVENUES ............................................... $2,595 $3,077
------ ------
EXPENSES:
Natural gas ......................................... 1,781 2,193
Operation and maintenance ........................... 313 331
Depreciation and amortization ....................... 130 140
Taxes other than income taxes ....................... 95 107
------ ------
Total ......................................... 2,319 2,771
------ ------
OPERATING INCOME ....................................... 276 306
------ ------
OTHER INCOME (EXPENSE):
Loss on Time Warner investment ...................... (41) (14)
Gain on indexed debt securities ..................... 39 10
Interest and other finance charges .................. (173) (115)
Interest on transition bonds ........................ (9) (33)
Return on true-up balance ........................... 34 --
Other, net .......................................... 4 6
------ ------
Total ......................................... (146) (146)
------ ------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES .. 130 160
Income tax expense .................................. (63) (72)
------ ------
INCOME FROM CONTINUING OPERATIONS ...................... 67 88
------ ------
DISCONTINUED OPERATIONS:
Income from Texas Genco, net of tax .............. 14 --
Loss on disposal of Texas Genco, net of tax ...... (14) --
------ ------
Total ......................................... -- --
------ ------
NET INCOME ............................................. $ 67 $ 88
====== ======
BASIC EARNINGS PER SHARE:
Income from Continuing Operations ................... $ 0.22 $ 0.28
Discontinued Operations, net of tax ................. -- --
------ ------
Net Income .......................................... $ 0.22 $ 0.28
====== ======
DILUTED EARNINGS PER SHARE:
Income from Continuing Operations ................... $ 0.20 $ 0.28
Discontinued Operations, net of tax ................. -- --
------ ------
Net Income .......................................... $ 0.20 $ 0.28
====== ======
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, MARCH 31,
2005 2006
------------ ---------
CURRENT ASSETS:
Cash and cash equivalents ....................... $ 74 $ 113
Investment in Time Warner common stock .......... 377 363
Accounts receivable, net ........................ 1,098 924
Accrued unbilled revenues ....................... 608 329
Natural gas inventory ........................... 294 106
Materials and supplies .......................... 88 88
Non-trading derivative assets ................... 131 88
Taxes receivable ................................ 53 --
Prepaid expenses and other current assets ....... 168 177
------- -------
Total current assets ......................... 2,891 2,188
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment ................... 11,558 11,664
Less accumulated depreciation and amortization .. (3,066) (3,093)
------- -------
Property, plant and equipment, net ........... 8,492 8,571
------- -------
OTHER ASSETS:
Goodwill ........................................ 1,709 1,709
Other intangibles, net .......................... 56 56
Regulatory assets ............................... 2,955 2,934
Non-trading derivative assets ................... 104 70
Other ........................................... 909 888
------- -------
Total other assets ........................... 5,733 5,657
------- -------
TOTAL ASSETS .............................. $17,116 $16,416
======= =======
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, MARCH 31,
2005 2006
------------ ---------
CURRENT LIABILITIES:
Current portion of transition bond long-term debt ..................... $ 73 $ 126
Current portion of other long-term debt ............................... 266 519
Indexed debt securities derivative .................................... 292 283
Accounts payable ...................................................... 1,161 606
Taxes accrued ......................................................... 167 124
Interest accrued ...................................................... 122 138
Non-trading derivative liabilities .................................... 43 66
Accumulated deferred income taxes, net ................................ 385 418
Other ................................................................. 505 385
------- -------
Total current liabilities .......................................... 3,014 2,665
------- -------
OTHER LIABILITIES:
Accumulated deferred income taxes, net ................................ 2,474 2,440
Unamortized investment tax credits .................................... 46 44
Non-trading derivative liabilities .................................... 35 54
Benefit obligations ................................................... 475 460
Regulatory liabilities ................................................ 728 785
Other ................................................................. 480 392
------- -------
Total other liabilities ............................................ 4,238 4,175
------- -------
LONG-TERM DEBT:
Transition bonds ...................................................... 2,407 2,335
Other ................................................................. 6,161 5,896
------- -------
Total long-term debt ............................................... 8,568 8,231
------- -------
COMMITMENTS AND CONTINGENCIES (NOTE 10)
SHAREHOLDERS' EQUITY:
Common stock (310,324,739 shares and 311,343,935 shares outstanding
at December 31, 2005 and March 31, 2006, respectively) ............. 3 3
Additional paid-in capital ............................................ 2,931 2,944
Accumulated deficit ................................................... (1,600) (1,558)
Accumulated other comprehensive loss .................................. (38) (44)
------- -------
Total shareholders' equity ......................................... 1,296 1,345
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ...................... $17,116 $16,416
======= =======
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)
THREE MONTHS ENDED MARCH 31,
----------------------------
2005 2006
----- -----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ...................................................... $ 67 $ 88
Discontinued operations, net of tax ............................. -- --
----- -----
Income from continuing operations ............................... 67 88
Adjustments to reconcile income from continuing operations
to net cash provided by (used in) operating activities:
Depreciation and amortization ................................ 130 140
Amortization of deferred financing costs ..................... 20 14
Deferred income taxes ........................................ 50 6
Investment tax credit ........................................ (2) (2)
Unrealized loss on Time Warner investment .................... 41 14
Unrealized gain on indexed debt securities ................... (40) (10)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net ............ 215 472
Inventory ................................................. 101 129
Taxes receivable .......................................... -- 53
Accounts payable .......................................... (177) (534)
Fuel cost over (under) recovery/surcharge ................. 76 63
Non-trading derivatives, net .............................. (56) 19
Margin deposits, net ...................................... (4) (79)
Interest and taxes accrued ................................ (464) (27)
Net regulatory assets and liabilities ..................... (86) 23
Other current assets ...................................... 43 7
Other current liabilities ................................. (57) (47)
Other assets .............................................. (1) 14
Other liabilities ......................................... (40) (51)
Other, net ................................................... 4 23
----- -----
Net cash provided by (used in) operating activities
of continuing operations ............................ (180) 315
Net cash used in operating activities of discontinued
operations .......................................... (22) --
----- -----
Net cash provided by (used in) operating activities .... (202) 315
----- -----
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ............................................ (131) (186)
Decrease in restricted cash of Texas Genco ...................... 383 --
Purchase of minority interest in Texas Genco .................... (383) --
Decrease in cash of Texas Genco ................................. 11 --
Other, net ...................................................... 2 (15)
----- -----
Net cash used in investing activities .................. (118) (201)
----- -----
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings, net .......................... 75 --
Long-term revolving credit facilities, net ...................... 472 (3)
Payments of long-term debt ...................................... (23) (27)
Debt issuance costs ............................................. (6) (2)
Payment of common stock dividends ............................... (62) (47)
Proceeds from issuance of common stock, net ..................... 4 3
Other, net ...................................................... -- 1
----- -----
Net cash provided by (used in) financing activities .... 460 (75)
----- -----
NET INCREASE IN CASH AND CASH EQUIVALENTS .......................... 140 39
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ................... 165 74
----- -----
CASH AND CASH EQUIVALENTS AT END OF PERIOD ......................... $ 305 $ 113
===== =====
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest, net of capitalized interest ........................... $ 183 $ 125
Income taxes (refunds), net ..................................... 435 (1)
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 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 (the 1935 Act). The
Energy Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February
8, 2006. 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 that will require the Company to
notify the FERC of its status as a holding company and to maintain certain books
and records and make these available to the FERC. On April 24, 2006, the FERC
considered motions for rehearing of these rules and proposed to adopt additional
rules regarding maintenance of books and records by utility holding companies.
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
March 31, 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 owns two
interstate natural gas pipelines and gas gathering systems, provides
various ancillary services, and 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 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)
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 a new reportable business segment discussed in Note
12 and do not affect net income.
5
(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 after-tax income of $13.6 million from Texas Genco's
operations in the first quarter of 2005. The Company recorded a loss of $13.2
million to offset these earnings in the first quarter of 2005. General corporate
overhead of $0.4 million previously allocated to Texas Genco from the Company,
which was not eliminated by the sale of Texas Genco, was excluded from
income from discontinued operations in the first quarter of 2005 and was
reflected as general corporate overhead of the Company in income from continuing
operations in accordance with Statement of Financial Accounting Standards (SFAS)
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS
No. 144). The Interim Financial Statements present these operations as
discontinued operations in accordance with SFAS No. 144.
Revenues related to Texas Genco included in discontinued operations for the
three months ended March 31, 2005 were $57 million. Income from these
discontinued operations for the three months ended March 31, 2005 is reported
net of income tax expense of $6 million.
(3) EMPLOYEE BENEFIT PLANS
The Company's net periodic cost includes the following components relating
to pension and postretirement benefits:
THREE MONTHS ENDED MARCH 31,
-----------------------------------------------------
2005 2006
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
Service cost ........................... $ 9 $ 1 $ 9 $ 1
Interest cost .......................... 23 7 24 6
Expected return on plan assets ......... (34) (3) (35) (3)
Amortization of prior service cost ..... (2) -- (2) --
Amortization of net loss ............... 12 -- 11 --
Amortization of transition obligation .. -- 2 -- 2
Benefit enhancement .................... -- -- 8 1
---- --- ---- ---
Net periodic cost ...................... $ 8 $ 7 $ 15 $ 7
==== === ==== ===
The Company expects to contribute approximately $26 million to its
postretirement benefits plan in 2006, of which $6 million had been contributed
as of March 31, 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 for each of the three-month periods ended March 31, 2005 and 2006 was
$2 million.
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.
6
(4) 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
decisions. Briefs have been filed with the 3rd Court of Appeals in Austin but
oral argument has not yet been scheduled. 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
which 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 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. If the December 2005
proposed regulations become effective and if the Texas Utility Commission's
order on this issue is not reversed on appeal or the amount of the tax benefits
is not otherwise restored by the Texas Utility Commission, the IRS is likely to
consider that a "normalization violation" has occurred. If so, 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 was deemed to have
occurred. In addition, if a normalization violation is deemed to have occurred,
the IRS could also deny CenterPoint Houston the ability to elect accelerated tax
depreciation benefits. 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 all respects in
August 2005 by the same Travis County District Court considering the appeal of
the True-Up Order, 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 which will collect approximately $596
million over 14 years plus interest at an annual rate of 11.075 percent (CTC
Order). The CTC Order authorizes CenterPoint Houston to impose a charge on
retail electric providers to recover the portion of the true-up balance not
covered by the financing order. The CTC Order also allows CenterPoint Houston to
collect approximately $24 million of rate case expenses over three years without
a
7
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 date of
implementation of the CTC Order, the return on the CTC portion of the true-up
balance is included in CenterPoint Houston's tariff-based revenues. During the
three months ended March 31, 2006, CenterPoint Houston recognized approximately
$17 million in CTC operating income. As of March 31, 2006, the Company has not
recorded an allowed equity return of $245 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 Travis County Court in September 2005.
Oral argument was held in April 2006, and a decision is expected in the second
quarter of 2006.
Effective September 13, 2005, the date of implementation of the CTC Order,
the return on the CTC portion of the true-up balance is included in CenterPoint
Houston's tariff-based revenues.
In January 2006, the Texas Utility Commission staff (Staff) proposed that
the Texas Utility Commission adopt new rules governing the carrying charges on
unrecovered true-up balances. If the Texas Utility Commission adopts the rule as
the Staff proposed it and the rule is deemed to apply to CenterPoint Houston,
the rule would reduce carrying costs on the unrecovered CTC balance
prospectively from 11.075 percent to the utility's cost of debt.
(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. 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. Oral arguments were held in April 2006, and a decision is
expected by the end of 2006.
(c) REMAND OF 2001 UNBUNDLED COST OF SERVICE 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 unbundled cost of service 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 indicated its intent to enter an order in the remand
proceeding to reduce CenterPoint Houston's rate base associated with those
expenditures. The Texas Utility Commission instructed its Staff to quantify the
reduction in rate base attributable to the transmission investment and to
develop requirements for compliance filings in order to reduce rates going
forward and to establish a temporary tariff to return the over-collected amount
due to the past inclusion of the full amount for such transmission investment.
The Texas Utility Commission's Staff has not yet announced the result of those
calculations. CenterPoint Houston anticipates that the indicated ruling by the
Texas Utility Commission would reduce its rate base associated with these
capital expenditures by approximately $57 million, though it is not possible for
CenterPoint Houston to quantify the amount of any refund obligation or reduction
to its tariffs until the Staff completes its calculations and the Texas Utility
Commission has entered a formal order. The Company and CenterPoint Houston
continue to believe that the original record before the Texas Utility Commission
supports the rates set by the Texas Utility Commission in its 2001 order. If the
Texas Utility Commission ultimately issues an order based on its indicated
decision, CenterPoint Houston plans to seek a rehearing of that determination
and, if that is unsuccessful, may pursue further judicial review of this matter.
No prediction can be made at this time as to the ultimate outcome of this matter
on remand or the amount of any rate reduction or refund obligation. If the Texas
Utility Commission's indicated ruling on this issue ultimately is entered and
upheld on appeal, it could have a material adverse impact on the Company's and
CenterPoint Houston's financial condition, results of operations or cash flows.
8
(d) RATE CASES
NATURAL GAS DISTRIBUTION
SOUTHERN GAS OPERATIONS
Louisiana
In October 2005, Southern Gas Operations filed for a $2 million Rate
Regulation Adjustment (RRA) increase in its South Louisiana service area and a
$2 million RRA decrease in its North Louisiana service area. Both adjustments
have been implemented, but are subject to review and revision by the Louisiana
Public Service Commission.
Mississippi
In February 2006, the Mississippi Public Service Commission (MPSC) approved
a $1 million increase in miscellaneous service charges for Southern Gas
Operations and in March 2006, it approved an RRA resulting in a $2 million
increase in general service rates. The MPSC is also reviewing a January 2006
application for a one-time recovery of approximately $2 million of costs related
to Hurricane Katrina. A decision on the application is expected in the second
quarter of 2006.
Oklahoma
In March 2006, Oklahoma Gas filed and then revised its filing under its
performance-based rate change tariff. The revised filing reflected a decrease of
approximately $1 million in revenue. The Oklahoma Corporation Commission staff
is currently reviewing this filing and a decision is expected in the second
quarter of 2006.
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 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. The proposed rates were
approved or became effective by operation of law in all but five of these
cities, which cities denied the rate change requests. Southern Gas Operations
appealed the actions of these five cities to the Railroad Commission.
Additionally, 19 cities where new rates had already gone into effect
subsequently challenged the jurisdictional and statutory basis for
implementation of those rates. Southern Gas Operations petitioned the Railroad
Commission for an order declaring that the new rates had been properly
established within these 19 cities.
In April 2006, Southern Gas Operations reached tentative agreements with
the last of the cities that are parties to the Railroad Commission proceedings.
The agreements anticipate the dismissal or settlement of the Railroad Commission
actions and the implementation of the settlement rates.
Once all settlement rates are 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. The settlements also provide that these new rates
will not change over the next three to five years.
MINNESOTA GAS
In April 2006, Minnesota Gas revised its gas cost filing for the twelve
months ended June 30, 2005, which had not yet been approved by the Minnesota
Public Utilities Commission (MPUC). Minnesota Gas refined its unbilled revenue
estimate to more accurately reflect the effect of lost and unaccounted for gas.
As a result, Minnesota Gas determined that its gas costs for the gas cost years
ended June 30, 2001 through June 30, 2005 were understated. Minnesota Gas's
revised gas cost filing requested approximately $9 million in
9
additional recovery for the twelve months ended June 30, 2005. The amended
filing also requested recovery of approximately $13 million related to the
period from July 1, 2000 through June 30, 2004 and a waiver from the MPUC rules
allowing recovery of such costs, since the gas costs for those years had been
previously approved. The filing proposes recovery of the 2001-2004 costs over a
3-year period beginning in 2007.
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. A hearing
was held in April 2006 and a decision is expected by the MPUC in 2006.
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 Minnesota Office of the Attorney General (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 a purported class of
customers who allege that Minnesota Gas' conduct under the CWR was in violation
of the law. On March 28, 2006 the court gave preliminary approval to a $13.5
million settlement which, if ultimately approved by the court following a
hearing, will resolve all claims against Minnesota Gas which have or could have
been asserted by residential natural gas customers in the CWR class action. If
also approved by the MPUC, the settlement will resolve the claims made by the
OAG. During the fourth quarter 2005, CERC established a litigation reserve to
cover the anticipated settlement costs under the terms of this settlement.
ELECTRIC TRANSMISSION & DISTRIBUTION
The Texas Utility Commission requires each electric utility to file an
annual Earnings Report providing certain information to enable the Texas Utility
Commission to monitor the electric utilities' earnings and financial condition
within the state. In May 2005, CenterPoint Houston filed its Earnings Report for
the calendar year ended December 31, 2004. CenterPoint Houston's Earnings Report
shows that it earned less than its authorized rate of return on equity in 2004.
In October 2005, the Staff filed a memorandum summarizing its review of the
Earnings Reports filed by electric utilities. Based on its review, the Staff
concluded that continuation of CenterPoint Houston's rates could result in
excess retail transmission and distribution revenues of as much as $105 million
and excess wholesale transmission revenues of as much as $31 million annually
and recommended that the Texas Utility Commission initiate a review of the
reasonableness of existing rates. The Staff's analysis was based on a 9.60
percent cost of equity, which is 165 basis points lower than the approved return
on equity from CenterPoint Houston's last rate proceeding, the elimination of
interest on debt that matured in November 2005 and certain other adjustments to
CenterPoint Houston's reported information. Additionally, a hypothetical capital
structure of 60 percent debt and 40 percent equity was used which varies
materially from the actual capital structure of CenterPoint Houston's regulated
transmission and distribution utility as of December 31, 2005 of approximately
50 percent debt and 50 percent equity.
In December 2005, the Texas Utility Commission considered the Staff report
and agreed to initiate a rate proceeding concerning the reasonableness of
CenterPoint Houston's existing rates for transmission and distribution service
and to require 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 supports a rate increase of $50 million or 3.7 percent to the retail
electric providers (REPs) that sell electricity to end-use customers in the
Houston area. The filing also supports a $43.1 million increase for CenterPoint
Houston's wholesale transmission customers, which include other utilities
throughout the state.
CenterPoint Houston used a 2005 test year adjusted for updated cost data
where appropriate. The data reflects the $700 million that CenterPoint Houston
has invested during the last few years for new structures, power lines and
related equipment to continue to operate a reliable network as well as certain
transmission interconnect projects that are currently in the planning stages. It
also includes the increase in franchise fees that CenterPoint Houston is
10
paying the City of Houston under the recently adopted franchise ordinance which
allows the company to provide its electric delivery services within the City
during the next thirty years. In addition, recognizing the catastrophic damage
to the facilities of other electric utilities caused by hurricanes in 2004 and
2005, CenterPoint Houston is proposing an increase to its storm reserve as well
as an increase in depreciation rates. Finally, CenterPoint Houston filed
testimony supporting its 11.25% return on equity and a 50% debt/50% equity
capital structure.
A procedural schedule has yet to be set but a final order is expected
around mid-October 2006.
(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 December
2004, the Railroad Commission conducted a hearing on the matter. 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. In August 2005, the City of
Tyler appealed this order to the Travis County District Court. In April 2006,
the Company and the City of Tyler reached a tentative agreement which
anticipates the dismissal of the District Court appeal. Once the appeal is
dismissed, the Railroad Commission's final order and its findings are not
subject to further review or modification.
(5) 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.
(a) NON-TRADING ACTIVITIES
Cash Flow Hedges. During the three months ended March 31, 2006, hedge
ineffectiveness was a gain of $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 "Expense" 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 March 31, 2006, the Company expects $4 million ($3
million after-tax) in accumulated other comprehensive loss to be reclassified as
an increase 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 of exposure up to ten years. The Company's policy is
not to exceed ten years in hedging its exposure.
Other Derivative Financial Instruments. Load following services that the
Company offers its natural gas customers create an inherent tendency for the
Company to be either long or short natural gas supplies relative to customer
purchase commitments. The Company enters into physical and financial forward
natural gas contracts to manage these load following natural gas supply
requirements. These forward natural gas contracts are derivatives which are not
designated as hedges and are accounted for on a mark-to-market basis with
changes in fair value reported through earnings. While the Company also utilizes
derivative instruments to manage physical commodity price risks, it does not
engage in proprietary or speculative commodity trading. During the three months
ended March 31, 2006, the Company recognized net gains related to these
positions amounting to $10 million. As of March 31, 2006, the Company had
recorded short-term assets of $14 million and short-term liabilities of $21
million related to these derivative contracts, included in non-trading
derivative assets and liabilities, respectively, in the Condensed Consolidated
Balance Sheets.
11
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 three-month periods ended March 31, 2005 and 2006 was $8 million. As
of March 31, 2006, the Company expects $31 million ($20 million after-tax) in
accumulated other comprehensive loss to be amortized during the next twelve
months.
Embedded Derivative. The Company's 3.75% and 2.875% convertible senior
notes contain contingent interest provisions. The contingent interest component
is an embedded derivative as defined by SFAS No. 133, and accordingly, must be
split from the host instrument and recorded at fair value on the balance sheet.
The value of the contingent interest components was not material at issuance or
at March 31, 2006.
(6) GOODWILL AND INTANGIBLES
Goodwill by reportable business segment is as follows (in millions):
DECEMBER 31, MARCH 31,
2005 2006
------------ ---------
Natural Gas Distribution .................... $ 746 $ 746
Pipelines and Field Services ................ 604 604
Competitive Natural Gas Sales and Services .. 339 339
Other Operations ............................ 20 20
------ ------
Total .................................... $1,709 $1,709
====== ======
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2005 MARCH 31, 2006
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Land Use Rights .. $55 $(14) $55 $(14)
Other ............ 22 (7) 22 (7)
--- ---- --- ----
Total ......... $77 $(21) $77 $(21)
=== ==== === ====
Amortization expense for other intangibles for each of the three-month
periods ended March 31, 2005 and 2006 was less than $1 million. Estimated
amortization expense for the remainder of 2006 and the five succeeding fiscal
years is as follows (in millions):
2006 ........ $ 2
2007 ........ 3
2008 ........ 3
2009 ........ 2
2010 ........ 2
2011 ........ 2
---
Total .... $14
===
12
(7) COMPREHENSIVE INCOME
The following table summarizes the components of total comprehensive income
(net of tax):
FOR THE THREE MONTHS
ENDED MARCH 31,
--------------------
2005 2006
---- ----
(IN MILLIONS)
Net income .......................................... $67 $88
--- ---
Other comprehensive income:
Net deferred gain (loss) from cash flow hedges ... 9 (3)
Reclassification of deferred loss (gain) from cash
flow hedges realized in net income ............ 6 (3)
--- ---
Other comprehensive income (loss) ................... 15 (6)
--- ---
Comprehensive income ................................ $82 $82
=== ===
The following table summarizes the components of accumulated other
comprehensive loss:
DECEMBER 31, MARCH 31,
2005 2006
------------ ---------
(IN MILLIONS)
Minimum pension liability adjustment ........ $(15) $(15)
Net deferred loss from cash flow hedges ..... (23) (29)
---- ----
Total accumulated other comprehensive loss .. $(38) $(44)
==== ====
(8) CAPITAL STOCK
CenterPoint Energy has 1,020,000,000 authorized shares of capital stock,
comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000
shares of $0.01 par value preferred stock. At December 31, 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 March 31, 2006, 311,344,101
shares of CenterPoint Energy common stock were issued and 311,343,935 shares of
CenterPoint Energy common stock were outstanding. Outstanding common shares
exclude 166 treasury shares at both December 31, 2005 and March 31, 2006.
(9) LONG-TERM DEBT AND RECEIVABLES FACILITY
(a) LONG-TERM DEBT
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 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.
13
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 March 31, 2006, the Company had no borrowings and approximately $29
million of outstanding letters of credit under its $1.2 billion credit facility,
CenterPoint Houston had no borrowings and approximately $3 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 March 31, 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 (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.
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
14
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 78.064 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 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 other 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 March
31, 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 March 31, 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 March 31, 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 DISTRIBUTION MANDATORY
AMOUNTS AS OF RATE/ REDEMPTION
DECEMBER 31, MARCH 31, 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
15
(B) RECEIVABLES FACILITY
In January 2006, CERC's $250 million receivables facility was extended to
January 2007. As of March 31, 2006, CERC had $141 million of advances under its
receivables facility. The facility was temporarily increased to $375 million for
the period from January 2006 to June 2006 to provide additional liquidity to
CERC during the peak heating season of 2006.
Advances under the receivables facility averaged $181 million and $141
million for the three months ended March 31, 2005 and 2006, respectively. Sales
of receivables were approximately $520 million and $346 million for the three
months ended March 31, 2005 and 2006, respectively.
(10) COMMITMENTS AND CONTINGENCIES
(A) 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 at an estimated cost of $425 million. The
capacity of the pipeline under this filing will be 1.275 billion cubic feet
(Bcf) per day. CEGT has signed firm contracts for substantially the full
capacity of the pipeline. CERC will consider an expansion of the pipeline
pending the outcome of an open season announced in late April 2006. 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, CEGT would construct a 67 mile extension from CEGT's Perryville hub
to an interconnect with Texas Eastern Gas Transmission at Union Church,
Mississippi.
(B) 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 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, Nevada and Kansas 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.
16
The Company or its predecessor, Reliant Energy, has been named in
approximately 30 of these lawsuits, which were instituted between 2001 and 2005
and are pending in California state court in San Diego County, in Nevada state
court in Clark County and in federal district courts in San Francisco, San
Diego, Los Angeles, Fresno, Sacramento, San Jose, Kansas and Nevada and before
the Ninth Circuit Court of Appeals. However, the Company, CenterPoint Houston
and Reliant Energy were not participants in the electricity or natural gas
markets in California. The Company and Reliant Energy have been dismissed from
certain of the lawsuits, either voluntarily by the plaintiffs or by order of the
court, and the Company believes it is not a proper defendant in the remaining
cases and will continue to seek dismissal from such remaining cases.
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 states and the investor-owned
utilities related to the 2000-2001 natural gas markets. The settlement has been
approved by the FERC and by the California Public Utilities Commission, and now
must be approved by the courts in which the class action cases are pending. This
approval is expected in the second quarter of 2006. A party in the FERC
proceedings has filed a motion for rehearing of the FERC's order approving the
settlement, upon which the FERC has yet to rule. 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 summary judgment filed by the
Company and the individual defendants. The plaintiffs have filed an appeal of
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.
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
17
royalty owners who allege that the defendants have engaged in systematic
mismeasurement of the volume of natural gas for more than 25 years. The
plaintiffs amended their petition in this suit in July 2003 in response to an
order from the judge denying certification of the plaintiffs' alleged class. In
the amendment the plaintiffs dismissed their claims against certain defendants
(including two CERC subsidiaries), limited the scope of the class of plaintiffs
they purport to represent and eliminated previously asserted claims based on
mismeasurement of the Btu content of the gas. The same plaintiffs then filed a
second lawsuit, again as representatives of a class of royalty owners, in which
they assert their claims that the defendants have engaged in systematic
mismeasurement of the Btu content of natural gas for more than 25 years. In both
lawsuits, the plaintiffs seek compensatory damages, along with statutory
penalties, treble damages, interest, costs and fees. CERC and its subsidiaries
believe that there has been no systematic mismeasurement of gas and that the
suits are without merit. CERC does not expect the ultimate outcome to have a
material impact on the financial condition, results of operations or cash flows
of either the Company or CERC.
Gas Cost Recovery Litigation. In October 2002, a suit was filed in state
district court in Wharton County, Texas against the Company, CERC, Entex Gas
Marketing Company, and certain non-affiliated companies alleging fraud,
violations of the Texas Deceptive Trade Practices Act, violations of the Texas
Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and
Antitrust Act with respect to rates charged to certain consumers of natural gas
in the State of Texas. Subsequently, the plaintiffs added as defendants
CenterPoint Energy Marketing Inc., CenterPoint Energy Gas Transmission Company,
United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy
Pipeline Services, Inc., and CenterPoint Energy Trading and Transportation
Group, Inc., all of which are subsidiaries of the Company. The plaintiffs
alleged that defendants inflated the prices charged to certain consumers of
natural gas. In February 2003, a similar suit was filed in state court in Caddo
Parish, Louisiana against CERC with respect to rates charged to a purported
class of certain consumers of natural gas and gas service in the State of
Louisiana. In February 2004, another suit was filed in state court in Calcasieu
Parish, Louisiana against CERC seeking to recover alleged overcharges for gas or
gas services allegedly provided by Southern Gas Operations to a purported class
of certain consumers of natural gas and gas service without advance approval by
the Louisiana Public Service Commission (LPSC). In October 2004, a similar case
was filed in district court in Miller County, Arkansas against the Company,
CERC, Entex Gas Marketing Company, CenterPoint Energy Gas Transmission Company,
CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc.,
Mississippi River Transmission Corp. and other non-affiliated companies alleging
fraud, unjust enrichment and civil conspiracy with respect to rates charged to
certain consumers of natural gas in at least the states of Arkansas, Louisiana,
Mississippi, Oklahoma and Texas. At the time of the filing of each of the Caddo
and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with
the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu
Parish cases have been stayed pending the resolution of the respective
proceedings by the LPSC. The plaintiffs in the Miller County case seek class
certification, but the proposed class has not been certified. In 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 in these cases includes injunctive and declaratory relief,
restitution for the alleged overcharges, exemplary damages or trebling of actual
damages, civil penalties and attorney's fees. In these cases, the Company, CERC
and their affiliates deny that they have overcharged any of their customers for
natural gas and believe that the amounts recovered for purchased gas have been
in accordance with what is permitted by state regulatory authorities. The
allegations in these cases are similar to those asserted in the City of Tyler
proceeding described in Note 4(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 4(d).
Minnesota Cold Weather Rule. In December 2004, the MPUC opened an
investigation to determine whether Minnesota Gas' practices regarding restoring
natural gas service during the Cold Weather Period are in compliance with the
MPUC's CWR, which governs disconnection and reconnection of customers during the
Cold Weather
18
Period. In June 2005, the Minnesota 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 a purported class of customers who allege
that Minnesota Gas' conduct under the CWR was in violation of the law. In March
2006, the court gave preliminary approval to a $13.5 million settlement which,
if ultimately approved by the court following a hearing, will resolve all claims
against Minnesota Gas which have or could have been asserted by residential
natural gas customers in the CWR class action. If also approved by the MPUC, the
settlement will resolve the claims made by the OAG. During the fourth quarter
2005, CERC established a litigation reserve to cover the anticipated settlement
costs under the terms of this settlement.
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 Company does not expect the ultimate cost associated with
resolving this matter to have a material impact on the financial condition,
results of operations or cash flows of either the Company or CERC.
Manufactured Gas Plant Sites. CERC and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed
remediation on two sites, other than ongoing monitoring and water treatment.
There are five remaining sites in CERC's Minnesota service territory. CERC
believes that it has no liability with respect to two of these sites.
At March 31, 2006, CERC had accrued $14 million for remediation of these
Minnesota sites. At March 31, 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 costs in excess of
insurance recovery. As of March 31, 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 filed in United
States District Court, District of Maine and 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 court considering the other suit for
contribution granted CERC's motion to dismiss on the grounds that CERC was not
an "operator" of the site as had been alleged. The plaintiff in that case has
filed an appeal of the court's dismissal of CERC. The Company is investigating
details regarding these sites and the range of environmental expenditures for
potential remediation. However, CERC believes it is not liable as a former owner
or operator of those sites under the Comprehensive Environmental, Response,
Compensation and Liability Act of 1980, as amended, and applicable state
statutes, and is vigorously contesting those suits and its designation as a PRP.
19
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. 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 large number of individuals who claim injury due to exposure
to asbestos. Most claimants in such litigation have been workers who
participated in construction of various industrial facilities, including power
plants. Some of the claimants have worked at locations owned by the Company, but
most existing claims relate to facilities previously owned by the Company 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. 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.
OTHER PROCEEDINGS
The Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company's management
regularly analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters. The Company's
management does not expect the disposition of these matters to have a material
adverse effect on the Company's financial condition, results of operations or
cash flows.
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 disallowed all
deductions for original issue discount (OID) including interest paid relating to
the Company's 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS),
and the interest paid on the 7% Automatic Common Exchange Securities (ACES),
redeemed in 1999. It is the contention of the IRS that (1) those instruments, in
combination with the Company's long position in Time Warner Inc. common stock
(TW Common), constitute a straddle under Section 1092 and 246 of the Internal
Revenue Code of 1986, as amended and (2) the indebtedness underlying those
instruments was incurred to carry the TW Common. If the IRS prevails on both of
those positions, none of the OID and interest paid on the ZENS and
20
ACES would be currently deductible but would instead be added to the Company's
basis in the TW Common it holds. The capitalization of OID and interest to the
TW Common basis would have the effect of recharacterizing ordinary interest
deductions to capital losses or reduced capital gains.
The Company's ability to realize the tax benefit of future capital losses,
if any, from the sale of the 21.6 million shares of TW Common currently held
will depend on the timing of those sales, the value of TW Common stock when
sold, and the extent of any other capital gains and losses.
Although the Company is protesting the disallowance of the ZENS and ACES
OID and interest paid, reserves have been established for the tax and interest
on this issue totaling $121 million and $135 million as of December 31, 2005 and
March 31, 2006, respectively. The Company has also established reserves for
other significant tax items including issues relating to prior acquisitions and
dispositions of business operations and certain positions taken with respect to
state tax filings. The total amount reserved for the other tax items is
approximately $60 million and $56 million as of December 31, 2005 and March 31,
2006, respectively.
GUARANTEES
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
letters of credit for the benefit of CERC and CenterPoint Energy, and undertook
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,
CenterPoint Energy'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, and CenterPoint Energy and
RRI are pursuing other alternatives. RRI 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, (which is now known as NRG Texas LP, or "NRG"), CenterPoint
Houston and a subsidiary of NRG are presently jointly administering the
decommissioning funds through the Nuclear Decommissioning Trust Investment
Committee. NRG and CenterPoint Houston have each appointed two members to the
Nuclear Decommissioning Trust Investment Committee which establishes the
investment policy of the trusts and oversees the investment of the trusts'
assets. As administrators of the decommissioning funds, CenterPoint Houston and
NRG are jointly responsible for assuring that the funds are prudently invested
in a manner consistent with the rules of the Texas Utility Commission. On
February 2, 2006, CenterPoint Houston and a subsidiary of Texas Genco filed a
request with the Texas Utility Commission to name the Texas Genco subsidiary as
the sole fund administrator. That application is now being pursued in the name
of NRG and is currently pending before an Administrative Law Judge. Pursuant to
the Texas electric restructuring law, costs associated with nuclear
decommissioning that were not recovered as of January 1, 2002, will continue to
be subject to cost-of-service rate regulation and will be charged to
transmission and distribution customers of CenterPoint Houston or its successor.
CenterPoint Houston does not collect a nuclear decommissioning charge with
respect to the additional 12.8% ownership interest in the South Texas Project
that Texas Genco LLC acquired subsequent to its acquisition of the Company's
generation facilities.
21
(11) EARNINGS PER SHARE
The following table reconciles numerators and denominators of the Company's
basic and diluted earnings per share calculations:
THREE MONTHS ENDED
MARCH 31,
---------------------------
2005 2006
------------ ------------
(IN MILLIONS, EXCEPT SHARE
AND PER SHARE AMOUNTS)
Basic earnings per share calculation:
Income from continuing operations ................... $ 67 $ 88
Discontinued operations, net of tax ................. -- --
------------ ------------
Net income .......................................... $ 67 $ 88
============ ============
Weighted average shares outstanding .................... 308,470,000 310,846,000
============ ============
Basic earnings per share:
Income from continuing operations ................... $ 0.22 $ 0.28
Discontinued operations, net of tax ................. -- --
------------ ------------
Net income .......................................... $ 0.22 $ 0.28
============ ============
Diluted earnings per share:
Net income .......................................... $ 67 $ 88
Plus: Income impact of assumed conversions:
Interest on 3.75% convertible senior notes ....... 4 --
------------ ------------
Total earnings effect assuming dilution ............. $ 71 $ 88
============ ============
Weighted average shares outstanding .................... 308,470,000 310,846,000
Plus: Incremental shares from assumed conversions:
Stock options (1) ................................ 1,293,000 1,216,000
Restricted stock ................................. 1,189,000 957,000
2.875% convertible senior notes .................. -- 150,000
3.75% convertible senior notes ................... 49,655,000 5,424,000
6.25% convertible trust preferred securities ..... 16,000 --
------------ ------------
Weighted average shares assuming dilution ........... 360,623,000 318,593,000
============ ============
Diluted earnings per share:
Income from continuing operations ................... $ 0.20 $ 0.28
Discontinued operations, net of tax ................. -- --
------------ ------------
Net income .......................................... $ 0.20 $ 0.28
============ ============
----------
(1) Options to purchase 9,851,111 and 8,425,822 shares were outstanding for the
three months ended March 31, 2005 and 2006, respectively, 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 9) provide for settlement of the principal portion in cash
rather than stock, the Company excludes the portion of the conversion value of
these notes attributable to their principal amount from its computation of
diluted earnings per share from continuing operations. The Company includes the
conversion spread in the calculation of diluted earnings per share when the
average market price of the Company's common stock in the respective reporting
period exceeds the conversion price. The conversion prices for the 2.875% and
the 3.75% contingently convertible senior notes are $12.66 and $11.44,
respectively.
(12) 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
22
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 (formerly Pipelines and
Gathering) 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 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 MARCH 31, 2005
-------------------------------------------------------- TOTAL ASSETS
REVENUES FROM NET INTERSEGMENT OPERATING INCOME AS OF DECEMBER 31,
EXTERNAL CUSTOMERS REVENUES (LOSS) 2005
------------------ ---------------- ---------------- ------------------
Electric Transmission & Distribution ........ $ 345(1) $ -- $ 80 $ 8,227
Natural Gas Distribution .................... 1,329 -- 123 4,612
Competitive Natural Gas Sales and Services .. 832 93 16 1,849
Pipelines and Field Services ................ 84 37 64 2,968
Other Operations ............................ 5 2 (7) 2,202(2)
Eliminations ................................ -- (132) -- (2,742)
------ ----- ---- -------
Consolidated ................................ $2,595 $ -- $276 $17,116
====== ===== ==== =======
FOR THE THREE MONTHS ENDED MARCH 31, 2006
-------------------------------------------------------- TOTAL ASSETS
REVENUES FROM NET INTERSEGMENT OPERATING INCOME AS OF MARCH 31,
EXTERNAL CUSTOMERS REVENUES (LOSS) 2006
------------------ ---------------- ---------------- ---------------
Electric Transmission & Distribution ........ $ 385(1) $ -- $110 $ 8,201
Natural Gas Distribution .................... 1,477 3 103 4,169
Competitive Natural Gas Sales and Services .. 1,126 37 25 1,379
Pipelines and Field Services ................ 87 38 73 2,973
Other Operations ............................ 2 2 (5) 1,970(2)
Eliminations ................................ -- (80) -- (2,276)
------ ---- ---- -------
Consolidated ................................ $3,077 $ -- $306 $16,416
====== ==== ==== =======
----------
(1) Sales to subsidiaries of RRI in the three months ended March 31, 2005 and
2006 represented approximately $183 million and $162 million, respectively.
(2) Included in total assets of Other Operations as of December 31, 2005 and
March 31, 2006 is a pension asset of $654 million and $639 million,
respectively.
(13) SUBSEQUENT EVENT
On April 28, 2006, the Company's board of directors declared a regular
quarterly cash dividend of $0.15 per share of common stock payable on June 9,
2006, to shareholders of record as of the close of business on May 16, 2006.
23
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
The following discussion and analysis should be read in combination with
our Interim Financial Statements contained in this Form 10-Q.
EXECUTIVE SUMMARY
RECENT EVENTS
DEBT FINANCING TRANSACTIONS
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 London Interbank Offered Rate
(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.
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.
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.
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.
CONSOLIDATED RESULTS OF OPERATIONS
All dollar amounts in the tables that follow are in millions, except for
per share amounts.
THREE MONTHS
ENDED MARCH 31,
---------------
2005 2006
------ ------
Revenues ............................................... $2,595 $3,077
Expenses ............................................... 2,319 2,771
------ ------
Operating Income ....................................... 276 306
Interest and Other Finance Charges ..................... (182) (148)
Other Income, net ...................................... 36 2
------ ------
Income From Continuing Operations Before Income Taxes .. 130 160
Income Tax Expense ..................................... (63) (72)
------ ------
Income From Continuing Operations ...................... 67 88
Discontinued Operations, net of tax .................... -- --
------ ------
Net Income ............................................. $ 67 $ 88
====== ======
BASIC EARNINGS PER SHARE:
Income From Continuing Operations ................... $ 0.22 $ 0.28
Discontinued Operations, net of tax ................. -- --
------ ------
Net Income .......................................... $ 0.22 $ 0.28
====== ======
DILUTED EARNINGS PER SHARE:
Income From Continuing Operations ................... $ 0.20 $ 0.28
Discontinued Operations, net of tax ................. -- --
------ ------
Net Income .......................................... $ 0.20 $ 0.28
====== ======
24
THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005
Income from Continuing Operations. We reported income from continuing
operations of $88 million ($0.28 per diluted share) for the three months ended
March 31, 2006 as compared to $67 million ($0.20 per diluted share) for the same
period in 2005. The increase in income from continuing operations of $21 million
was primarily due to:
- increased operating income of $9 million in our Pipelines and Field
Services business segment resulting from increased demand for certain
transportation and ancillary services as well as increased throughput
and demand for services related to our core gas gathering operations;
- increased operating income of $9 million in our Competitive Natural
Gas Sales and Services business segment primarily due to higher sales
to utilities and favorable basis differentials over the pipeline
capacity that we control, partially offset by a write-down of natural
gas inventory to the lower of average cost or market due to the
decline in natural gas prices during the first quarter of 2006;
- a $7 million increase in operating income from the regulated utility
operations of our Electric Transmission & Distribution business
segment primarily due to continued customer growth and recovery of our
2004 true-up balance through the competition transition charge (CTC)
and a gain from the sale of land, partially offset by milder weather
and decreased usage, higher transmission costs, severance associated
with staff reductions in the first quarter of 2006 and increased
franchise fees paid to the City of Houston; and
- a $58 million decrease in interest expense due to lower borrowing
costs and borrowing levels, excluding transition bond-related interest
expense.
These increases in income from continuing operations were partially offset
by:
- decreased operating income of $20 million in our Natural Gas
Distribution business segment primarily due to the impact of milder
weather, increased employee-related expenses in connection with an
early retirement program offered in the first quarter of 2006 and
higher bad debt expense and decreased throughput associated with
higher gas prices, partially offset by rate increases;
- a decrease of $34 million in other income related to a return on the
true-up balance of our Electric Transmission & Distribution business
segment recorded in the first quarter of 2005 as a result of the
True-Up Order, which was partially offset by the operating income
related to the recovery of the true-up balance through the CTC as
discussed above; and
- an increase in income tax expense of $9 million as discussed below.
Income Tax Expense. During the three months ended March 31, 2005 and 2006,
our effective tax rate was 48.6% and 45%, respectively. The most significant
item affecting our effective tax rate in the first quarter of 2005 and 2006 was
an addition to the tax reserve of approximately $11 million and $14 million,
respectively, relating to the contention of the Internal Revenue Service (IRS)
that the current deductions for original issue discount (OID) on our 2.0%
Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) be capitalized,
potentially converting what would be ordinary deductions into capital losses at
the time the ZENS are settled. Future changes to the reserve will depend upon a
number of variables, including the market price of Time Warner Inc. common stock
(TW Common), the amount of ZENS OID, which increases quarterly, our assessment
of available capital gains and the ultimate outcome of the dispute with the IRS.
25
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following table presents operating income for each of our business
segments for the three months ended March 31, 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 MARCH 31,
----------------------------
2005 2006
---- ----
(IN MILLIONS)
Electric Transmission & Distribution ........ $ 80 $110
Natural Gas Distribution .................... 123 103
Competitive Natural Gas Sales and Services .. 16 25
Pipelines and Field Services ................ 64 73
Other Operations ............................ (7) (5)
---- ----
Total Consolidated Operating Income ...... $276 $306
==== ====
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 months ended March 31, 2005 and 2006
(in millions, except throughput and customer data):
THREE
MONTHS ENDED MARCH 31,
-----------------------
2005 2006
---------- ----------
Revenues:
Electric transmission and distribution utility ........... $ 323 $ 331
Transition bond companies ................................ 22 54
---------- ----------
Total revenues ........................................ 345 385
---------- ----------
Expenses:
Operation and maintenance ................................ 138 134
Depreciation and amortization ............................ 64 63
Taxes other than income taxes ............................ 50 56
Transition bond companies ................................ 13 22
---------- ----------
Total expenses ........................................ 265 275
---------- ----------
Operating Income -- Electric transmission and distribution
Utility .................................................. 71 78
Operating Income -- Transition bond companies(1) ............ 9 32
---------- ----------
Total segment operating income ........................ $ 80 $ 110
========== ==========
Throughput (in gigawatt-hours (GWh)):
Residential ........................................... 4,142 3,986
Total ................................................. 15,826 15,987
Average number of metered customers:
Residential ........................................... 1,661,320 1,717,836
Total ................................................. 1,887,020 1,950,829
----------
(1) Represents the amount necessary to pay interest on the transition bonds.
THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005
Our Electric Transmission & Distribution business segment reported
operating income of $110 million for the three months ended March 31, 2006,
consisting of $78 million for the regulated electric transmission and
distribution utility and $32 million for the transition bond company
subsidiaries of CenterPoint Houston that issued
26
$749 million and $1.851 billion principal amount of transition bonds in 2001 and
the fourth quarter of 2005, respectively. For the three months ended March 31,
2005, operating income totaled $80 million, consisting of $71 million for the
regulated electric transmission and distribution utility and $9 million for the
transition bond company. Operating revenues for the regulated electric
transmission and distribution utility increased primarily due to continued
customer growth ($8 million) with the addition of nearly 67,000 metered
customers since March 2005 and recovery of our 2004 true-up balance through the
CTC ($14 million), partially offset by milder weather and decreased usage ($12
million). Operation and maintenance expense decreased ($4 million) primarily due
to a gain on the sale of land ($14 million)for the regulated electric
transmission and distribution utility, which was partially offset by higher
transmission costs ($4 million) and severance costs associated with staff
reductions in the first quarter of 2006 ($4 million). Additionally, taxes other
than income taxes increased ($6 million) primarily due to higher franchise fees
paid to the City of Houston.
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.
The following table provides summary data of our Natural Gas Distribution
business segment for the three months ended March 31, 2005 and 2006 (in
millions, except throughput and customer data):
THREE
MONTHS ENDED MARCH 31,
-----------------------
2005 2006
---------- ----------
Revenues ................................... $ 1,329 $ 1,480
---------- ----------
Expenses:
Natural gas ............................. 997 1,146
Operation and maintenance ............... 135 150
Depreciation and amortization ........... 37 38
Taxes other than income taxes ........... 37 43
---------- ----------
Total expenses ....................... 1,206 1,377
---------- ----------
Operating Income ........................... $ 123 $ 103
========== ==========
Throughput (in billion cubic feet (Bcf)):
Residential ............................. 77 67
Commercial and industrial ............... 77 72
---------- ----------
Total Throughput ..................... 154 139
========== ==========
Average number of customers:
Residential ............................. 2,851,514 2,889,013
Commercial and industrial ............... 248,826 253,519
---------- ----------
Total ................................ 3,100,340 3,142,532
========== ==========
THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005
Our Natural Gas Distribution business segment reported operating income of
$103 million for the three months ended March 31, 2006 as compared to $123
million for the three months ended March 31, 2005. Increases in operating
margins (revenues less natural gas costs) from rate increases ($12 million) and
increased gross receipts taxes resulting from higher revenues ($6 million), were
substantially offset by the impact of milder weather and decreased throughput
net of continued customer growth with the addition of approximately 42,000
customers since March 2005 ($12 million). Operation and maintenance expense
increased $15 million primarily due to increased employee-related expense in
connection with an early retirement program offered in the first quarter of 2006
($6 million), increased bad debt expense associated with higher gas prices ($3
million) and increased contracts and services expenses and corporate services
($4 million). Additionally, taxes other than income taxes increased $6 million
primarily due to higher gross receipts taxes, which offset the corresponding
increase in revenues as discussed above.
27
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.
The following table provides summary data of our Competitive Natural Gas
Sales and Services business segment for the three months ended March 31, 2005
and 2006 (in millions, except throughput and customer data):
THREE MONTHS ENDED
MARCH 31,
------------------
2005 2006
------ ------
Revenues .......................... $ 925 $1,163
------ ------
Expenses:
Natural gas .................... 902 1,129
Operation and maintenance ...... 5 8
Depreciation and amortization .. 1 --
Taxes other than income taxes .. 1 1
------ ------
Total expenses .............. 909 1,138
------ ------
Operating Income .................. $ 16 $ 25
====== ======
Throughput (in Bcf):
Wholesale - third parties ...... 82 89
Wholesale - affiliates ......... 14 11
Retail ......................... 47 48
Pipeline ....................... 19 10
------ ------
Total Throughput ............ 162 158
====== ======
Average number of customers:
Wholesale ...................... 136 145
Retail ......................... 6,224 6,517
Pipeline ....................... 153 147
------ ------
Total ....................... 6,513 6,809
====== ======
THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005
Our Competitive Natural Gas Sales and Services business segment reported
operating income of $25 million for the three months ended March 31, 2006 as
compared to $16 million for the three months ended March 31, 2005. The increase
in operating income of $9 million was primarily due to increased operating
margins (revenues less natural gas costs) related to higher sales to utilities
and favorable basis differentials over the pipeline capacity that we control
($23 million) less the impact of an adjustment in the first quarter of 2006 to
write-down natural gas inventory to the lower of average cost or market ($13
million), partially offset by higher payroll and benefit related expenses ($1
million) and increased bad debt expense ($1 million). Natural gas that is
purchased for inventory is accounted for at the lower of average cost or market
price at each balance sheet date.
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.
28
The following table provides summary data of our Pipelines and Field
Services business segment for the three months ended March 31, 2005 and 2006 (in
millions, except throughput data):
THREE MONTHS
ENDED
MARCH 31,
------------
2005 2006
---- ----
Revenues .......................... $121 $125
---- ----
Expenses:
Natural gas .................... 7 (4)
Operation and maintenance ...... 34 39
Depreciation and amortization .. 11 12
Taxes other than income taxes .. 5 5
---- ----
Total expenses .............. 57 52
---- ----
Operating Income .................. $ 64 $ 73
==== ====
Throughput (in Bcf):
Natural Gas Sales .............. 1 --
Transportation ................. 271 274
Gathering ...................... 83 88
Eliminations (1) ............... (1) --
---- ----
Total Throughput ............ 354 362
==== ====
----------
(1) Elimination of volumes both transported and sold.
THREE MONTHS ENDED MARCH 31, 2006 COMPARED TO THREE MONTHS ENDED MARCH 31, 2005
Our Pipelines and Field Services business segment reported operating income
of $73 million for the three months ended March 31, 2006 as compared to $64
million for the three months ended March 31, 2005. Operating income for the
pipeline business for the three months ended March 31, 2006 was $49 million
compared to $48 million for the three months ended March 31, 2005. The field
services business recorded operating income of $24 million for the three months
ended March 31, 2006 compared to $16 million for the three months ended March
31, 2005. Operating income increased by $9 million primarily due to increased
revenues from higher demand for transportation and higher demand for ancillary
services on the regulated pipelines ($7 million), higher commodity prices and
increased throughput and demand for services related to our core gas gathering
operations ($11 million), partially offset by increased operation and
maintenance expenses ($5 million).
Additionally, this business segment has a 50% interest in a jointly-owned
gas processing plant. Included in other income for the three months ended March
31, 2005 and 2006 was equity income of $1 million and $2 million, respectively,
related to the joint venture.
OTHER OPERATIONS
The following table shows the operating loss of our Other Operations
business segment for the three months ended March 31, 2005 and 2006 (in
millions):
THREE MONTHS
ENDED
MARCH 31,
------------
2005 2006
---- ----
Revenues ........ $ 7 $ 4
Expenses ........ 14 9
--- ---
Operating Loss .. $(7) $(5)
=== ===
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
For information on other developments, factors and trends that may have an
impact on our future earnings, please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Certain Factors Affecting
Future Earnings" in Item 7 of Part II and "Risk Factors" in Item 1A of Part I of
our 2005 Form 10-K.
29
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 three months ended March
31, 2005 and 2006:
THREE MONTHS
ENDED
MARCH 31,
-------------
2005 2006
----- -----
(IN MILLIONS)
Cash provided by (used in):
Operating activities.... $(202) $ 315
Investing activities.... (118) (201)
Financing activities.... 460 (75)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
Net cash provided by operating activities in the first quarter of 2006
increased $517 million compared to the same period in 2005 primarily due to
decreased tax payments of $436 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), decreases in net regulatory
assets/liabilities ($109 million), primarily due to the termination of excess
mitigation credits effective April 29, 2005, and decreased cash used in the
operations of Texas Genco ($22 million). These increases in cash provided by
operating activities were partially offset by decreased net accounts
receivable/payable ($100 million) primarily due to higher gas prices in the
first quarter of 2006 as compared to the same period in 2005 and decreases in
the amount of advances for the purchase of receivables under CERC Corp.'s
receivables facility. Additionally, customer margin deposit requirements
decreased ($75 million) primarily due to the decline in natural gas prices from
December 2005 to March 2006.
CASH USED IN INVESTING ACTIVITIES
Net cash used in investing activities increased $83 million in the first
quarter of 2006 as compared to the same period in 2005 primarily due to
increased capital expenditures of $55 million primarily related to our Electric
Transmission & Distribution and Pipelines and Field Services business segments.
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
Net cash provided by financing activities in the first quarter of 2006
decreased $535 million compared to the same period in 2005 primarily due to
decreased borrowings under our revolving credit facility ($475 million) and the
absence of borrowings under Texas Genco's revolving credit facility ($75
million) due to the sale of Texas Genco, partially offset by decreased dividend
payments of $15 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 remainder of
2006 include the following:
- approximately $859 million of capital expenditures;
- dividend payments on CenterPoint Energy common stock and debt service
payments; and
- long-term debt payments of $199 million, including $54 million of
transition bonds.
We expect that borrowings under our credit facilities and anticipated cash
flows from operations will be sufficient to meet our cash needs for the next
twelve months. Cash needs may also be met by issuing securities in the capital
markets.
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.
30
has a bankruptcy remote subsidiary, which we consolidate, which was formed for
the sole purpose of buying receivables created by CERC and selling those
receivables to an unrelated third-party. This transaction is accounted for as a
sale of receivables under the provisions of 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
January 2006, the $250 million facility, which temporarily increased to $375
million for the period from January 2006 to June 2006, was extended to January
2007. As of March 31, 2006, CERC had $141 million of advances under its
receivables facility.
Prior to CenterPoint Energy's distribution of its ownership in Reliant
Energy, Inc. (formerly named Reliant Resources, Inc.) (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 letters of credit for
the benefit of CERC and CenterPoint Energy, and undertook to use commercially
reasonable efforts to extinguish the remaining guarantees. Our 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, CenterPoint Energy'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,
and CenterPoint Energy and RRI are pursuing other alternatives. RRI continues to
meet its obligations under the transportation contracts.
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 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.
31
As of May 1, 2006, we had the following credit facilities (in millions):
AMOUNT UTILIZED
DATE EXECUTED COMPANY SIZE OF FACILITY AT MAY 1, 2006 TERMINATION DATE
-------------- ------------------- ---------------- --------------- ----------------
March 31, 2006 CenterPoint Energy $1,200 $28(1) March 31, 2011
March 31, 2006 CenterPoint Houston 300 3(1) March 31, 2011
March 31, 2006 CERC Corp. 550 -- 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 March 31, 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 March 31, 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 March 31, 2006, we had external temporary
investments of $65 million. As of May 1, 2006, we had external temporary
investments of $131 million.
Money Pool. We have a "money pool" through which our participating
subsidiaries can borrow or invest on a short-term basis. Funding needs are
aggregated and external borrowing or investing is based on the net cash
position. The net funding requirements of the money pool are expected to be met
with borrowings under CenterPoint Energy's revolving credit facility or the sale
of commercial paper.
Impact on Liquidity of a Downgrade in Credit Ratings. As of May 1, 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.
32
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 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 that establish credit thresholds and require a party to provide
additional collateral on two business days' notice when that party's rating or
the rating of a credit support provider for that party (CERC Corp. in this case)
falls below those levels. We estimate that as of March 31, 2006, unsecured
credit limits extended to CES by counterparties aggregate $131 million; however,
utilized credit capacity is significantly lower. In addition, CERC and its
subsidiaries purchase natural gas under supply agreements that contain an
aggregate credit threshold of $100 million based on CERC's S&P Senior Unsecured
Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will
increase and decrease the aggregate credit threshold accordingly.
Cross Defaults. Under our revolving credit facility, a payment default on,
or a non-payment default that permits acceleration of, any indebtedness
exceeding $50 million by us or any of our significant subsidiaries will cause a
default. Pursuant to the indenture governing our senior notes, a payment default
by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of,
borrowed money and certain other specified types of obligations, in the
aggregate principal amount of $50 million will cause a default. As of May 1,
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 suppliers;
- increased costs related to the acquisition of gas;
- increases in interest expense in connection with debt refinancings and
borrowings under credit facilities;
- various regulatory actions;
33
- 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;
- slower customer payments and increased write-offs of receivables due
to higher gas prices;
- cash payments in connection with the exercise of contingent conversion
rights of holders of convertible debt;
- contributions to benefit plans;
- restoration costs and revenue losses resulting from natural disasters
such as hurricanes; and
- various other risks identified in "Risk Factors" in Item 1A of Part I
of our 2005 Form 10-K.
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. The receivables facility also contains an EBITDA
to interest covenant. 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 exceptions, additional first mortgage bonds.
We were 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 we and our 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 that will require us to notify the FERC of our status as a holding company
and to maintain certain books and records and make these available to the FERC.
On April 24, 2006, the FERC considered motions for rehearing of these rules and
proposed to adopt additional rules regarding maintenance of books and records by
utility holding companies.
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.
34
ACCOUNTING FOR RATE REGULATION
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS No. 71), provides that rate-regulated entities account for and report
assets and liabilities consistent with the recovery of those incurred costs in
rates if the rates established are designed to recover the costs of providing
the regulated service and if the competitive environment makes it probable that
such rates can be charged and collected. Application of SFAS No. 71 to the
electric generation portion of our business was discontinued as of June 30,
1999. Our Electric Transmission & Distribution business continues to apply SFAS
No. 71 which results in our accounting for the regulatory effects of recovery of
stranded costs and other regulatory assets resulting from the unbundling of the
transmission and distribution business from our electric generation operations
in our consolidated financial statements. Certain expenses and revenues subject
to utility regulation or rate determination normally reflected in income are
deferred on the balance sheet and are recognized in income as the related
amounts are included in service rates and recovered from or refunded to
customers. Significant accounting estimates embedded within the application of
SFAS No. 71 with respect to our Electric Transmission & Distribution business
segment relate to $328 million of recoverable electric generation-related
regulatory assets as of March 31, 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 Public Utility Commission of Texas (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. 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.
Appeals of the district court's judgment are still pending. 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." 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;
35
- 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 March 31, 2006, our estimated cost of retiring these assets is
approximately $76 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, amounts of energy delivered to customers since
the date of the last meter reading are estimated and the corresponding unbilled
revenue is estimated. Unbilled electricity delivery revenue is estimated each
month based on daily supply volumes, applicable rates and analyses reflecting
significant historical trends and experience. Unbilled natural gas sales are
estimated based on estimated purchased gas volumes, estimated lost and
unaccounted for gas and tariffed rates in effect. As additional information
becomes available, or actual amounts are determinable, the recorded estimates
are revised. Consequently, operating results can be affected by revisions to
prior accounting estimates.
PENSION AND OTHER RETIREMENT PLANS
We sponsor pension and other retirement plans in various forms covering all
employees who meet eligibility requirements. We use several statistical and
other factors which attempt to anticipate future events in calculating the
expense and liability related to our plans. These factors include assumptions
about the discount rate, expected return on plan assets and rate of future
compensation increases as estimated by management, within certain guidelines. In
addition, our actuarial consultants use subjective factors such as withdrawal
and mortality rates. 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 "-- Other Significant Matters -- Pension Plan" for further
discussion. 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.
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 March 31, 2006, the recorded fair value of our Non-Trading Energy
Derivatives was a net asset of $38 million. A decrease of 10% in the market
prices of energy commodities from their March 31, 2006 levels would have
decreased the fair value of our Non-Trading Energy Derivatives from their levels
on that date by $83 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
hedging purposes
36
associated with the hypothetical changes in commodity prices referenced above
is expected to be substantially offset by a favorable impact on the underlying
hedged physical transactions.
INTEREST RATE RISK
We have outstanding long-term debt, bank loans, mandatory redeemable
preferred securities of subsidiary trusts holding solely our junior subordinated
debentures (trust preferred securities), 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 March 31, 2006.
At March 31, 2006, we had outstanding fixed-rate debt (excluding indexed
debt securities) and trust preferred securities aggregating $8.8 billion in
principal amount and having a fair value of $9.1 billion. These instruments are
fixed-rate and, therefore, do not expose us to the risk of loss in earnings due
to changes in market interest rates. However, the fair value of these
instruments would increase by approximately $386 million if interest rates were
to decline by 10% from their levels at March 31, 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 $110 million at March 31, 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 March 31, 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 March 31, 2006 levels,
the fair value of the derivative component would increase by approximately $5
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 March 31, 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 March 31, 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 March 31, 2006 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
37
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For a description of certain legal and regulatory proceedings affecting
CenterPoint Energy, please read Notes 4 and 10 to our Interim 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.
ITEM 1A. RISK FACTORS
There have been no material changes from the risk factors disclosed in our
2005 Form 10-K.
ITEM 5. OTHER INFORMATION
The ratio of earnings to fixed charges for the three months ended March 31,
2005 and 2006 was 1.69 and 2.04, respectively.
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 and CenterPoint Energy's Form 10-K for the 1-31447 3.1.1
Restated Articles of Incorporation of year ended December 31, 2001
CenterPoint Energy
3.2 -- Amended and Restated Bylaws of CenterPoint CenterPoint Energy's Form 10-K for the 1-31447 3.2
Energy year ended December 31, 2001
3.3 -- Statement of Resolution Establishing Series CenterPoint Energy's Form 10-K for the 1-31447 3.3
of Shares designated Series A Preferred year ended December 31, 2001
Stock of CenterPoint Energy
4.1 -- Form of CenterPoint Energy Stock Certificate CenterPoint Energy's Registration 3-69502 4.1
Statement on Form S-4
4.2 -- Rights Agreement dated January 1, 2002, CenterPoint Energy's Form 10-K for the 1-31447 4.2
between CenterPoint Energy and JPMorgan year ended December 31, 2001
Chase Bank, as Rights Agent
4.3 -- $1,200,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.1
Agreement dated as of March 31, 2006, among March 31, 2006
CenterPoint Energy, as Borrower, and the
banks named therein
4.4 -- $300,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.2
Agreement dated as of March 31, 2006, among March 31, 2006
CenterPoint Houston, as Borrower, and the
Initial Lenders named therein, as Initial
Lenders
38
SEC FILE
OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
-------- ----------- -------------------------------- ------------ ---------
4.5 -- $550,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.3
Agreement dated as of March 31, 2006 among March 31, 2006
CERC Corp., as Borrower, and the banks
named therein
+10 -- Letter Agreement dated March 16, 2006
between CenterPoint Energy and John T. Cater
+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"
39
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: May 4, 2006
40
Exhibit Index
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 and CenterPoint Energy's Form 10-K for the 1-31447 3.1.1
Restated Articles of Incorporation of year ended December 31, 2001
CenterPoint Energy
3.2 -- Amended and Restated Bylaws of CenterPoint CenterPoint Energy's Form 10-K for the 1-31447 3.2
Energy year ended December 31, 2001
3.3 -- Statement of Resolution Establishing Series CenterPoint Energy's Form 10-K for the 1-31447 3.3
of Shares designated Series A Preferred year ended December 31, 2001
Stock of CenterPoint Energy
4.1 -- Form of CenterPoint Energy Stock Certificate CenterPoint Energy's Registration 3-69502 4.1
Statement on Form S-4
4.2 -- Rights Agreement dated January 1, 2002, CenterPoint Energy's Form 10-K for the 1-31447 4.2
between CenterPoint Energy and JPMorgan year ended December 31, 2001
Chase Bank, as Rights Agent
4.3 -- $1,200,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.1
Agreement dated as of March 31, 2006, among March 31, 2006
CenterPoint Energy, as Borrower, and the
banks named therein
4.4 -- $300,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.2
Agreement dated as of March 31, 2006, among March 31, 2006
CenterPoint Houston, as Borrower, and the
Initial Lenders named therein, as Initial
Lenders
4.5 -- $550,000,000 Amended and Restated Credit CenterPoint Energy's Form 8-K dated 1-31447 4.3
Agreement dated as of March 31, 2006 among March 31, 2006
CERC Corp., as Borrower, and the banks
named therein
+10 -- Letter Agreement dated March 16, 2006
between CenterPoint Energy and John T. Cater
+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"