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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
FORM 10-K
(Mark One)
----------
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ________ TO________
COMMISSION FILE NUMBER 1-31447
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CENTERPOINT ENERGY, INC.
(Exact name of registrant as specified in its charter)
TEXAS 74-0694415
(State or other jurisdiction of incorporation or (I.R.S. Employer Identification No.)
organization)
1111 LOUISIANA (713) 207-1111
HOUSTON, TEXAS 77002 (Registrant's telephone number, including area
(Address and zip code of principal executive code)
offices)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common Stock, $0.01 par value and associated New York Stock Exchange
rights to purchase preferred stock Chicago Stock Exchange
HL&P Capital Trust II 8.257% Capital Securities,
Series B New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]
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 if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of each of the registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
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]
The aggregate market value of the voting stock held by non-affiliates of
CenterPoint Energy, Inc. (Company) was $4,069,064,426 as of June 30, 2005, using
the definition of beneficial ownership contained in Rule 13d-3 promulgated
pursuant to the Securities Exchange Act of 1934 and excluding shares held by
directors and executive officers. As of February 28, 2006, the Company had
310,849,323 shares of Common Stock outstanding. Excluded from the number of
shares of Common Stock outstanding are 166 shares held by the Company as
treasury stock.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement relating to the 2006 Annual
Meeting of Shareholders of the Company, which will be filed with the Securities
and Exchange Commission within 120 days of December 31, 2005, are incorporated
by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of
this Form 10-K.
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TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business.................................................... 1
Item 1A. Risk Factors................................................ 21
Item 1B. Unresolved Staff Comments................................... 28
Item 2. Properties.................................................. 28
Item 3. Legal Proceedings........................................... 28
Item 4. Submission of Matters to a Vote of Security Holders......... 28
PART II
Item 5. Market for Registrants' Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities........... 29
Item 6. Selected Financial Data..................................... 30
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 32
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 56
Item 8. Financial Statements and Supplementary Data................. 59
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 117
Item 9A. Controls and Procedures..................................... 117
Item 9B. Other Information........................................... 120
PART III
Item 10. Directors and Executive Officers............................ 121
Item 11. Executive Compensation...................................... 121
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters.................. 121
Item 13. Certain Relationships and Related Transactions.............. 121
Item 14. Principal Accountant Fees and Services...................... 121
PART IV
Item 15. Exhibits and Financial Statement Schedules.................. 122
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.
Some of the factors that could cause actual results to differ from those
expressed or implied by our forward-looking statements are described under "Risk
Factors" in Item 1A of this report.
You should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement.
ii
PART I
ITEM 1. BUSINESS
OUR BUSINESS
OVERVIEW
We are a public utility holding company whose indirect wholly owned
subsidiaries include:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
provides electric transmission and distribution services to retail
electric providers serving approximately 1.9 million metered customers in
a 5,000-square-mile area of the Texas Gulf Coast that has a population of
approximately 4.8 million people and includes Houston; and
- CenterPoint Energy Resources Corp. (CERC Corp. and, together with its
subsidiaries, CERC), which owns gas distribution systems serving
approximately 3.1 million customers in Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma and Texas. Through wholly owned subsidiaries, CERC
also 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.
Our reportable business segments are Electric Transmission & Distribution,
Natural Gas Distribution, Competitive Natural Gas Sales and Services, Pipelines
and Field Services (formerly Pipelines and Gathering), and Other Operations. The
operations of Texas Genco Holdings, Inc. (Texas Genco), formerly our majority
owned generating subsidiary, the sale of which was completed in April 2005, are
presented as discontinued operations.
We were a registered public utility holding company under the Public
Utility Holding Company Act of 1935, as amended (the 1935 Act). The 1935 Act and
related rules and regulations imposed a number of restrictions on our activities
and those of our subsidiaries. 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. The FERC continues to consider
motions for rehearing or clarification of these rules.
Our principal executive offices are located at 1111 Louisiana, Houston,
Texas 77002 (telephone number: 713-207-1111).
We make available free of charge on our Internet website our annual report
on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and
amendments to those reports filed or furnished pursuant to Section 13(a) or
15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable
after we electronically file such reports with, or furnish them to, the
Securities and Exchange Commission (SEC). Additionally, we make available free
of charge on our Internet website:
- our Code of Ethics for our Chief Executive Officer and Senior Financial
Officers;
- our Ethics and Compliance Code;
- our Corporate Governance Guidelines; and
- the charters of our audit, compensation, finance and governance
committees.
Any shareholder who so requests may obtain a printed copy of any of these
documents from us. Changes in or waivers of our Code of Ethics for our Chief
Executive Officer and Senior Financial Officers and waivers of our Ethics and
Compliance Code for directors or executive officers will be posted on our
Internet website
1
within five business days and maintained for at least 12 months or reported on
Item 5.05 of our Forms 8-K. Our website address is www.centerpointenergy.com.
Except to the extent explicitly stated herein, documents and information on our
website are not incorporated by reference herein.
ELECTRIC TRANSMISSION & DISTRIBUTION
Electric Transmission
On behalf of retail electric providers, CenterPoint Houston delivers
electricity from power plants to substations and from one substation to another
and to retail electric customers taking power above 69 kilovolts (kV) in
locations throughout the control area managed by the Electric Reliability
Council of Texas, Inc. (ERCOT). CenterPoint Houston provides transmission
services under tariffs approved by the Public Utility Commission of Texas (Texas
Utility Commission).
Electric Distribution
In ERCOT, end users purchase their electricity directly from certificated
"retail electric providers." CenterPoint Houston delivers electricity for retail
electric providers in its certificated service area by carrying lower-voltage
power from the substation to the retail electric customer. Its distribution
network receives electricity from the transmission grid through power
distribution substations and delivers electricity to end users through
distribution feeders. CenterPoint Houston's operations include construction and
maintenance of electric transmission and distribution facilities, metering
services, outage response services and call center operations. CenterPoint
Houston provides distribution services under tariffs approved by the Texas
Utility Commission. Texas Utility Commission rules and market protocols govern
the commercial operations of distribution companies and other market
participants.
ERCOT Market Framework
CenterPoint Houston is a member of ERCOT. ERCOT serves as the regional
reliability coordinating council for member electric power systems in Texas.
ERCOT membership is open to consumer groups, investor and municipally owned
electric utilities, rural electric cooperatives, independent generators, power
marketers and retail electric providers. The ERCOT market includes much of the
State of Texas, other than a portion of the panhandle, a portion of the eastern
part of the state bordering Louisiana and the area in and around El Paso. The
ERCOT market represents approximately 85% of the demand for power in Texas and
is one of the nation's largest power markets. The ERCOT market includes an
aggregate net generating capacity of approximately 77,000 megawatts. There are
only limited direct current interconnections between the ERCOT market and other
power markets in the United States.
The ERCOT market operates under the reliability standards set by the North
American Electric Reliability Council. The Texas Utility Commission has primary
jurisdiction over the ERCOT market to ensure the adequacy and reliability of
electricity supply across the state's main interconnected power transmission
grid. The ERCOT independent system operator (ERCOT ISO) is responsible for
maintaining reliable operations of the bulk electric power supply system in the
ERCOT market. Its responsibilities include ensuring that electricity production
and delivery are accurately accounted for among the generation resources and
wholesale buyers and sellers. Unlike certain other regional power markets, the
ERCOT market is not a centrally dispatched power pool, and the ERCOT ISO does
not procure energy on behalf of its members other than to maintain the reliable
operations of the transmission system. Members who sell and purchase power are
responsible for contracting sales and purchases of power bilaterally. The ERCOT
ISO also serves as agent for procuring ancillary services for those members who
elect not to provide their own ancillary services.
CenterPoint Houston's electric transmission business, along with those of
other owners of transmission facilities in Texas, supports the operation of the
ERCOT ISO. The transmission business has planning, design, construction,
operation and maintenance responsibility for the portion of the transmission
grid and for the load-serving substations it owns, primarily within its
certificated area. We participate with the ERCOT ISO and other ERCOT utilities
to plan, design, obtain regulatory approval for and construct new transmission
lines
2
necessary to increase bulk power transfer capability and to remove existing
constraints on the ERCOT transmission grid.
True-Up and Securitization
The Texas Electric Choice Plan (Texas electric restructuring law), which
became effective in September 1999, substantially amended the regulatory
structure governing electric utilities in order to allow retail competition for
electric customers beginning in January 2002. The Texas electric restructuring
law requires the Texas Utility Commission to conduct a "true-up" proceeding to
determine CenterPoint Houston's stranded costs and certain other costs resulting
from the transition to a competitive retail electric market and to provide for
its recovery of those costs. In March 2004, CenterPoint Houston filed its
true-up application with the Texas Utility Commission, requesting recovery of
$3.7 billion, excluding interest. In December 2004, the Texas Utility Commission
issued its final order (True-Up Order) allowing CenterPoint Houston to recover a
true-up balance of approximately $2.3 billion, which included interest through
August 31, 2004, and providing for adjustment of the amount to be recovered to
include interest on the balance until recovery, the principal portion of
additional excess mitigation credits returned to customers after August 31, 2004
and certain other matters. CenterPoint Houston and other parties filed appeals
of the True-Up Order to a district court in Travis County, Texas. 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. First, the court reversed the Texas Utility Commission's decision to
prohibit CenterPoint Houston from recovering $180 million in credits through
August 2004 that CenterPoint Houston was ordered to provide to retail electric
providers as a result of an inaccurate stranded cost estimate made by the Texas
Utility Commission in 2000. Additional credits of approximately $30 million were
paid after August 2004. Second, the court reversed the Texas Utility
Commission's disallowance of $440 million in transition costs which are
recoverable under the Texas Utility Commission's regulations. 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.
Among the issues raised in our appeal of the True-Up Order is the Texas
Utility Commission's reduction of our stranded cost recovery by approximately
$146 million for the present value of certain deferred tax benefits associated
with our former Texas Genco assets. Such reduction was considered in our
recording of an after-tax extraordinary loss of $977 million in the last half of
2004. We believe 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 (EDFIT) back to customers. However, in
December 2005, the IRS withdrew those proposed normalization regulations and
issued new proposed regulations that do not include the provision allowing a
retroactive election to pass the tax benefits back to customers. 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 us 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
depreciation benefits. 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
3
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 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. Certain parties appealed the CTC Order to the Travis County Court in
September 2005.
Under the True-Up Order, CenterPoint Houston is allowed to recover carrying
charges at 11.075 percent until the true-up balance is recovered. 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.
CenterPoint Houston Rate Case
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 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.
These and other significant matters currently affecting our financial
condition are further discussed in "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Executive
Summary -- Significant Events in 2005" in Item 7 of this report.
Customers
CenterPoint Houston serves nearly all of the Houston/Galveston metropolitan
area. CenterPoint Houston's customers consist of 66 retail electric providers,
which sell electricity in its certificated service area, and municipalities,
electric cooperatives and other distribution companies located outside
CenterPoint Houston's certificated service area. Each retail electric provider
is licensed by, and must meet creditworthiness
4
criteria established by, the Texas Utility Commission. Two of the retail
electric providers in our service area are subsidiaries of Reliant Energy, Inc
(RRI). Sales to subsidiaries of RRI represented approximately 78%, 71% and 62%
of CenterPoint Houston's transmission and distribution revenues in 2003, 2004
and 2005, respectively. CenterPoint Houston's billed receivables balance from
retail electric providers as of December 31, 2005 was $127 million.
Approximately 56% of this amount was owed by subsidiaries of RRI. CenterPoint
Houston does not have long-term contracts with any of its customers. It operates
on a continuous billing cycle, with meter readings being conducted and invoices
being distributed to retail electric providers each business day.
Distribution Automation
CenterPoint Houston, with assistance from IBM, has developed an Electric
Distribution Grid Automation Strategy that involves the implementation of an
"Intelligent Grid". An Intelligent Grid has the potential to provide us with on
demand data and information that should enable a significant improvement in grid
planning, operations and maintenance. This, in turn, should contribute to fewer
and shorter outages, better customer service, improved operations costs,
improved security and more effective use of the workforce. A limited system
deployment, with an expected capital cost of $11 million in 2006, has been
initiated and allows for a disciplined approach to proving the technology and
validating potential benefits prior to a full-scale implementation. The outcome
of this limited deployment will be a major factor in any decision to expand the
deployment in 2007 and beyond.
Competition
There are no other electric transmission and distribution utilities in
CenterPoint Houston's service area. In order for another provider of
transmission and distribution services to provide such services in CenterPoint
Houston's territory, it would be required to obtain a certificate of convenience
and necessity from the Texas Utility Commission and, depending on the location
of the facilities, may also be required to obtain franchises from one or more
municipalities. We know of no other party intending to enter this business in
CenterPoint Houston's service area at this time.
Seasonality
A significant portion of CenterPoint Houston's revenues is derived from
rates that it collects from each retail electric provider based on the amount of
electricity it distributes on behalf of such retail electric provider. Thus,
CenterPoint Houston's revenues and results of operations are subject to
seasonality, weather conditions and other changes in electricity usage, with
revenues being higher during the warmer months.
Properties
All of CenterPoint Houston's properties are located in Texas. CenterPoint
Houston's transmission system carries electricity from power plants to
substations and from one substation to another. These substations serve to
connect power plants, the high voltage transmission lines and the lower voltage
distribution lines. Unlike the transmission system, which carries high voltage
electricity over long distances, distribution lines carry lower voltage power
from the substation to the retail electric customers. The distribution system
consists primarily of distribution lines, transformers, secondary distribution
lines and service wires and meters. Most of CenterPoint Houston's transmission
and distribution lines have been constructed over lands of others pursuant to
easements or along public highways and streets as permitted by law.
All real and tangible properties of CenterPoint Houston, subject to certain
exclusions, are currently subject to:
- the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1,
1944, as supplemented; and
- the lien of a General Mortgage (the General Mortgage) dated October 10,
2002, as supplemented, which is junior to the lien of the Mortgage.
5
As of December 31, 2005, CenterPoint Houston had outstanding $2.0 billion
aggregate principal amount of general mortgage bonds under the General Mortgage,
including approximately $527 million held in trust to secure pollution control
bonds for which CenterPoint Energy is obligated and approximately $229 million
held in trust to secure pollution control bonds for which CenterPoint Houston is
obligated. Additionally, CenterPoint Houston had outstanding approximately $253
million aggregate principal amount of first mortgage bonds under the Mortgage,
including approximately $151 million held in trust to secure certain pollution
control bonds for which CenterPoint Energy is obligated. CenterPoint Houston may
issue additional general mortgage bonds on the basis of retired bonds, 70% of
property additions or cash deposited with the trustee. Approximately $2.0
billion of additional first mortgage bonds and general mortgage bonds could be
issued on the basis of retired bonds and 70% of property additions as of
December 31, 2005. However, CenterPoint Houston is contractually prohibited,
subject to certain exceptions, from issuing additional first mortgage bonds.
Electric Lines -- Overhead. As of December 31, 2005, CenterPoint Houston
owned 27,026 pole miles of overhead distribution lines and 3,621 circuit miles
of overhead transmission lines, including 451 circuit miles operated at 69,000
volts, 2,093 circuit miles operated at 138,000 volts and 1,077 circuit miles
operated at 345,000 volts.
Electric Lines -- Underground. As of December 31, 2005, CenterPoint
Houston owned 16,662 circuit miles of underground distribution lines and 18.8
circuit miles of underground transmission lines, including 4.5 circuit miles
operated at 69,000 volts and 14.3 circuit miles operated at 138,000 volts.
Substations. As of December 31, 2005, CenterPoint Houston owned 225 major
substation sites having total installed rated transformer capacity of 47,864
megavolt amperes.
Service Centers. CenterPoint Houston operates 16 regional service centers
located on a total of 311 acres of land. These service centers consist of office
buildings, warehouses and repair facilities that are used in the business of
transmitting and distributing electricity.
Franchises
CenterPoint Houston holds non-exclusive franchises from the incorporated
municipalities in its service territory. In exchange for payment of fees, these
franchises give CenterPoint Houston the right to use the streets and public
rights-of way of these municipalities to construct, operate and maintain its
transmission and distribution system and to use that system to conduct its
electric delivery business and for other purposes that the franchises permit.
The terms of the franchises, with various expiration dates, typically range from
5 to 50 years.
In June 2005, CenterPoint Houston accepted an ordinance granting it a new
30-year franchise to use the public rights-of-way to conduct its business in the
City of Houston (New Franchise Ordinance). The New Franchise Ordinance took
effect on July 1, 2005, and replaced the prior electricity franchise ordinance,
which had been in effect since 1957. The New Franchise Ordinance clarifies
certain operational obligations of CenterPoint Houston and the City of Houston
and provides for streamlined payment and audit procedures and a two-year statute
of limitations on claims for underpayment or overpayment under the ordinance.
Under the prior electricity franchise ordinance, CenterPoint Houston paid annual
franchise fees of $76.6 million to the City of Houston for the year ended
December 31, 2004. For the twelve-month period beginning July 1, 2005, the
annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance
will include a base amount of $88.1 million (Base Amount) and an additional
payment of $8.5 million (Additional Amount). The Base Amount and the Additional
Amount will be adjusted annually based on the increase, if any, in kWh delivered
by CenterPoint Houston within the City of Houston.
CenterPoint Houston began paying the new annual franchise fees on July 1,
2005. Pursuant to the New Franchise Ordinance, the Annual Franchise Fee will be
reduced prospectively to reflect any portion of the Annual Franchise Fee that is
not included in CenterPoint Houston's base rates in any subsequent rate case.
6
NATURAL GAS DISTRIBUTION
CERC's natural gas distribution business engages in regulated intrastate
natural gas sales to, and natural gas transportation for, residential,
commercial and industrial customers in Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma and Texas through two unincorporated divisions: Minnesota
Gas and Southern Gas Operations.
Minnesota Gas provides natural gas distribution services to approximately
780,000 customers in over 240 communities. The largest metropolitan area served
by Minnesota Gas is Minneapolis. In 2005, approximately 44% of Minnesota Gas'
total throughput was attributable to residential customers and approximately 56%
was attributable to commercial and industrial customers. Minnesota Gas also
provides unregulated services consisting of heating, ventilating and air
conditioning (HVAC) equipment and appliance repair, sales of HVAC, water heating
and hearth equipment and home security monitoring.
Southern Gas Operations provides natural gas distribution services to
approximately 2.3 million customers in Arkansas, Louisiana, Mississippi,
Oklahoma and Texas. The largest metropolitan areas served by Southern Gas
Operations are Houston, Texas; Little Rock, Arkansas; Shreveport, Louisiana;
Biloxi, Mississippi; and Lawton, Oklahoma. In 2005, approximately 42% of
Southern Gas Operations' total throughput was attributable to residential
customers and approximately 58% was attributable to commercial and industrial
customers.
The demand for intrastate natural gas sales to, and natural gas
transportation for, residential, commercial and industrial customers is
seasonal. In 2005, approximately 70% of the total throughput of CERC's local
distribution companies' business occurred in the first and fourth quarters.
These patterns reflect the higher demand for natural gas for heating purposes
during those periods.
Supply and Transportation. In 2005, Minnesota Gas purchased virtually all
of its natural gas supply pursuant to contracts with remaining terms varying
from a few months to four years. Minnesota Gas' major suppliers in 2005 included
BP Canada Energy Marketing Corp. (54% of supply volumes), Tenaska Marketing
Ventures (11%), ONEOK Energy Services Company, LP (7%) and ConocoPhillips
Company (5%). Numerous other suppliers provided the remaining 23% of Minnesota
Gas' natural gas supply requirements. Minnesota Gas transports its natural gas
supplies through various interstate pipelines under contracts with remaining
terms, including extensions, varying from one to sixteen years. We anticipate
that these gas supply and transportation contracts will be renewed prior to
their expiration.
In 2005, Southern Gas Operations purchased virtually all of its natural gas
supply pursuant to contracts with remaining terms varying from a few months to
five years. Southern Gas Operations' major suppliers in 2005 included Energy
Transfer Company (24% of supply volumes), Kinder Morgan Texas Pipeline
Corporation (18%), BP Energy Company (12%), Merrill Lynch Commodities (9%),
ONEOK Energy Services Company, LP (7%), and Coral Energy LLC (5%). Numerous
other suppliers provided the remaining 25% of Southern Gas Operations' natural
gas supply requirements. Southern Gas Operations transports its natural gas
supplies through various intrastate and interstate pipelines including
CenterPoint Energy's pipeline subsidiaries.
Generally, the regulations of the states in which CERC's natural gas
distribution business operates allow it to pass through changes in the costs of
natural gas to its customers under purchased gas adjustment provisions in its
tariffs. Depending upon the jurisdiction, the purchased gas adjustment factors
are updated periodically, ranging from monthly to semi-annually, using estimated
gas costs. The changes in the cost of gas billed to customers are subject to
review by the applicable regulatory bodies.
Minnesota Gas and Southern Gas Operations use various leased or owned
natural gas storage facilities to meet peak-day requirements and to manage the
daily changes in demand due to changes in weather. Minnesota Gas also
supplements contracted supplies and storage from time to time with stored
liquefied natural gas and propane-air plant production.
Minnesota Gas owns and operates an underground storage facility with a
capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.1 Bcf
available for use during a normal heating season and a maximum
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daily withdrawal rate of 50 million cubic feet (MMcf). It also owns nine
propane-air plants with a total capacity of 204 MMcf per day and on-site storage
facilities for 12 million gallons of propane (1.0 Bcf gas equivalent). Minnesota
Gas owns liquefied natural gas plant facilities with a 12 million-gallon
liquefied natural gas storage tank (1.0 Bcf gas equivalent) and a send-out
capability of 72 MMcf per day.
On an ongoing basis, CERC enters into contracts to provide sufficient
supplies and pipeline capacity to meet its customer requirements. However, it is
possible for limited service disruptions of interruptible customers' load to
occur from time to time due to weather conditions, transportation constraints
and other events. As a result of these factors, supplies of natural gas may
become unavailable from time to time, or prices may increase rapidly in response
to temporary supply constraints or other factors.
Assets
As of December 31, 2005, CERC owned approximately 66,000 linear miles of
gas distribution mains, varying in size from one-half inch to 24 inches in
diameter. Generally, in each of the cities, towns and rural areas served by
CERC, we own the underground gas mains and service lines, metering and
regulating equipment located on customers' premises and the district regulating
equipment necessary for pressure maintenance. With a few exceptions, the
measuring stations at which CERC receives gas are owned, operated and maintained
by others, and its distribution facilities begin at the outlet of the measuring
equipment. These facilities, including odorizing equipment, are usually located
on the land owned by suppliers.
Competition
CERC competes primarily with alternate energy sources such as electricity
and other fuel sources. In some areas, intrastate pipelines, other gas
distributors and marketers also compete directly for gas sales to end-users. In
addition, as a result of federal regulations affecting interstate pipelines,
natural gas marketers operating on these pipelines may be able to bypass CERC's
facilities and market and sell and/or transport natural gas directly to
commercial and industrial customers.
COMPETITIVE NATURAL GAS SALES AND SERVICES
CERC offers variable and fixed-priced physical natural gas supplies
primarily to commercial and industrial customers and electric and gas utilities
through a number of subsidiaries, primarily CenterPoint Energy Services, Inc.
(CES). We have reorganized the oversight of our Natural Gas Distribution
business segment and, as a result, beginning in the fourth quarter of 2005, we
have established a new reportable business segment, Competitive Natural Gas
Sales and Services. These operations were previously reported as part of the
Natural Gas Distribution business segment.
In 2005, CES marketed approximately 538 Bcf (including 27 Bcf to
affiliates) of natural gas, transportation and related energy services to nearly
7,000 customers which vary in size from small commercial to large utility
companies in the central and eastern regions of the United States. The business
has three operational functions: wholesale, retail and intrastate pipelines
further described below.
Wholesale Operations. CES offers a portfolio of physical delivery services
and financial products designed to meet wholesale customers' supply and price
risk management needs. These customers are served directly through interconnects
with various inter- and intra-state pipeline companies, and include gas
utilities, large industrial and electric generation customers.
Retail Operations. CES also offers a variety of natural gas management
services to smaller commercial and industrial customers, whose facilities are
located downstream of natural gas distribution utility city gate stations,
including load forecasting, supply acquisition, daily swing volume management,
invoice consolidation, storage asset management, firm and interruptible
transportation administration and forward price management. CES manages
transportation contracts and energy supply for retail customers in ten states.
Intrastate Pipeline Operations. Another wholly owned subsidiary of CERC
owns and operates approximately 210 miles of intrastate pipeline in Louisiana
and Texas. This subsidiary provides bundled and unbundled merchant and
transportation services to shippers and end-users.
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CES currently transports natural gas on over 30 pipelines throughout the
central and eastern United States. CES maintains a portfolio of natural gas
supply contracts and firm transportation agreements to meet the natural gas
requirements of its customers. CES aggregates supply from various producing
regions and offers contracts to buy natural gas with terms ranging from one
month to over five years. In addition, CES actively participates in the spot
natural gas markets in an effort to balance daily and monthly purchases and
sales obligations. Natural gas supply and transportation capabilities are
leveraged through contracts for ancillary services including physical storage
and other balancing arrangements.
As described above, CES offers its customers a variety of load following
services. In providing these services, CES uses its customers' purchase
commitments to forecast and arrange its own supply purchases and transportation
services to serve customers' natural gas requirements. As a result of the
variance between this forecast activity and the actual monthly activity, CES
will either have too much supply or too little supply relative to its customers'
purchase commitments. These supply imbalances arise each month as customers'
natural gas requirements are scheduled and corresponding natural gas supplies
are nominated by CES for delivery to those customers. CES' processes and risk
control environment are designed to measure and value all supply imbalances on a
real-time basis to ensure that CES' exposure to commodity price and volume risk
is kept to a minimum. The value assigned to these volumetric imbalances is
calculated daily and is known as the aggregate Value at Risk (VaR). In 2005,
CES' VaR averaged $0.5 million with a high of $3 million.
The CenterPoint Energy Risk Control policy, governed by the Risk Oversight
Committee, defines authorized and prohibited trading instruments and volumetric
trading limits. CES is a physical marketer of natural gas and uses a variety of
tools, including pipeline and storage capacity, financial instruments and
physical commodity purchase contracts to support its sales. The CES business
optimizes its use of these various tools to minimize its supply costs and does
not engage in proprietary or speculative commodity trading. The VaR limits
within which CES operates are consistent with its operational objective of
matching its aggregate sales obligations (including the swing associated with
load following services) with its supply portfolio in a manner that minimizes
its total cost of supply.
Competition
CES competes with regional and national wholesale and retail gas marketers
including the marketing divisions of natural gas producers and utilities. In
addition, CES competes with intrastate pipelines for customers and services in
its market areas.
PIPELINES AND FIELD SERVICES
CERC's pipelines and field services business operates two interstate
natural gas pipelines, as well as gas gathering and processing facilities and
also provides operating and technical services and remote data monitoring and
communication services. The rates charged by interstate pipelines for interstate
transportation and storage services are regulated by the FERC.
CERC owns and operates gas transmission lines primarily located in
Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. CERC's pipeline
operations are primarily conducted by two wholly owned interstate pipeline
subsidiaries which provide gas transportation and storage services primarily to
industrial customers and local distribution companies:
- CenterPoint Energy Gas Transmission Company (CEGT) is an interstate
pipeline that provides natural gas transportation, natural gas storage
and pipeline services to customers principally in Arkansas, Louisiana,
Oklahoma and Texas; and
- CenterPoint Energy-Mississippi River Transmission Corporation (MRT) is an
interstate pipeline that provides natural gas transportation, natural gas
storage and pipeline services to customers principally in Arkansas and
Missouri.
CERC's pipeline project management and facility operation services are
provided to affiliates and third parties through a wholly owned pipeline
services subsidiary, CenterPoint Energy Pipeline Services, Inc.
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CERC's field services operations are conducted by a wholly owned
subsidiary, CenterPoint Energy Field Services, Inc. (CEFS). CEFS provides
natural gas gathering and processing services for certain natural gas fields in
the Midcontinent basin of the United States that interconnect with CEGT's and
MRT's pipelines, as well as other interstate and intrastate pipelines. CEFS
operates gathering pipelines, which collect natural gas from approximately 200
separate systems located in major producing fields in Arkansas, Louisiana,
Oklahoma and Texas. CEFS, either directly, or through its 50% interest in the
Waskom Joint Venture, processes in excess of 240 MMcf per day of natural gas
along its gathering system. CEFS, through its ServiceStar operating division,
provides remote data monitoring and communications services to affiliates and
third parties. The ServiceStar operating division currently provides monitoring
activities at 9,100 locations across Alabama, Arkansas, Colorado, Illinois,
Kansas, Louisiana, Mississippi, Missouri, New Mexico, Oklahoma, Texas and
Wyoming.
In 2005, approximately 20% of our total operating revenue from pipelines
and field services was attributable to services provided to Southern Gas
Operations and approximately 7% was attributable to services provided to Laclede
Gas Company (Laclede), an unaffiliated distribution company that provides
natural gas utility service to the greater St. Louis metropolitan area in
Illinois and Missouri. Services to Southern Gas Operations and Laclede are
provided under several long-term firm storage and transportation agreements. The
agreement to provide services to Laclede expires in 2007. We expect that this
agreement will be renewed prior to its expiration. Agreements for firm
transportation, "no notice" transportation service and storage service in
Southern Gas Operations' major service areas (Arkansas, Louisiana and Oklahoma)
expire in 2012.
In October 2005, CEGT signed a firm transportation agreement with XTO
Energy to transport 600 MMcf per day of natural gas from Carthage, Texas to
CEGT's Perryville hub in Northeast Louisiana. To accommodate this transaction,
CEGT is in the process of filing applications for certificates with the FERC to
build a 172 mile, 42-inch diameter pipeline, and related compression facilities
at an estimated cost of $400 million. The final capacity of the pipeline will be
between 960 MMcf per day and 1.24 Bcf per day. CEGT expects to have firm
contracts for the full capacity of the pipeline prior to its expected in service
date in early 2007. 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.
Our pipelines and field services business operations may be affected by
changes in the demand for natural gas, the available supply and relative price
of natural gas in the Midcontinent and Gulf Coast natural gas supply regions and
general economic conditions.
Assets
We own and operate approximately 8,200 miles of gas transmission lines
primarily located in Missouri, Illinois, Arkansas, Louisiana, Oklahoma and
Texas. We also own and operate six natural gas storage fields with a combined
daily deliverability of approximately 1.2 Bcf per day and a combined working gas
capacity of approximately 59.0 Bcf. We also own a 10% interest in Gulf South
Pipeline Company, LP's Bistineau storage facility. This facility has a total
working gas capacity of 85.7 Bcf and approximately 1.1 Bcf per day of
deliverability. Storage capacity in the Bistineau facility is 8 Bcf of working
gas with 100 MMcf per day of deliverability. Most storage operations are in
north Louisiana and Oklahoma. We also own and operate approximately 4,000 miles
of gathering pipelines that collect, treat and process natural gas from
approximately 200 separate systems located in major producing fields in
Arkansas, Louisiana, Oklahoma and Texas.
Competition
Our pipelines and field services business competes with other interstate
and intrastate pipelines and gathering companies in the transportation and
storage of natural gas. The principal elements of competition among pipelines
are rates, terms of service, and flexibility and reliability of service. Our
pipelines and field services business competes indirectly with other forms of
energy available to our customers, including
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electricity, coal and fuel oils. The primary competitive factor is price.
Changes in the availability of energy and pipeline capacity, the level of
business activity, conservation and governmental regulations, the capability to
convert to alternative fuels, and other factors, including weather, affect the
demand for natural gas in areas we serve and the level of competition for
transportation and storage services. In addition, competition for our gathering
operations is impacted by commodity pricing levels because of their influence on
the level of drilling activity. Both pipeline services and ServiceStar compete
with other similar service companies based on market pricing. The principal
elements of competition are rates, terms of service and reliability of services.
OTHER OPERATIONS
Our Other Operations business segment includes office buildings and other
real estate used in our business operations and other corporate operations which
support all of our business operations.
DISCONTINUED OPERATIONS
In July 2004, we announced our agreement to sell our majority owned
subsidiary, Texas Genco, to Texas Genco LLC. On December 15, 2004, Texas Genco
completed the sale of its fossil generation assets (coal, lignite and gas-fired
plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas
Genco, whose principal remaining asset was its ownership interest in a nuclear
generating facility, distributed $2.231 billion in cash to us. The final step of
the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC
in exchange for an additional cash payment to us of $700 million, was completed
on April 13, 2005.
We recorded an after-tax gain (loss) of $91 million, $(133) million and
$(3) million for the years ended December 31, 2003, 2004 and 2005, respectively,
related to the operations of Texas Genco. The consolidated financial statements
report these operations for all periods presented as discontinued operations in
accordance with Statement of Financial Accounting Standards (SFAS) No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets."
FINANCIAL INFORMATION ABOUT SEGMENTS
For financial information about our segments, see Note 14 to our
consolidated financial statements, which note is incorporated herein by
reference.
REGULATION
We are subject to regulation by various federal, state and local
governmental agencies, including the regulations described below.
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
As a registered public utility holding company under the 1935 Act, we and
our subsidiaries were subject to a comprehensive regulatory scheme imposed by
the SEC. Although the SEC did not regulate rates and charges under the 1935 Act,
it did regulate the structure, financing, lines of business and internal
transactions of public utility holding companies and their system companies.
The 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 PUHCA 2005, which grants to
the 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. The FERC continues to consider
motions for rehearing or clarification of these rules.
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FEDERAL ENERGY REGULATORY COMMISSION
The FERC has jurisdiction under the Natural Gas Act and the Natural Gas
Policy Act of 1978, as amended, to regulate the transportation of natural gas in
interstate commerce and natural gas sales for resale in intrastate commerce that
are not first sales. The FERC regulates, among other things, the construction of
pipeline and related facilities used in the transportation and storage of
natural gas in interstate commerce, including the extension, expansion or
abandonment of these facilities. The rates charged by interstate pipelines for
interstate transportation and storage services are also regulated by the FERC.
The Energy Act expanded the FERC's authority to prohibit market manipulation in
connection with FERC-regulated transactions and gave the FERC additional
authority to impose civil penalties for statutory violations and violations of
the FERC's rules or orders and also expanded criminal penalties for such
violations.
Our natural gas pipeline subsidiaries may periodically file applications
with the FERC for changes in their generally available maximum rates and charges
designed to allow them to recover their costs of providing service to customers
(to the extent allowed by prevailing market conditions), including a reasonable
rate of return. These rates are normally allowed to become effective after a
suspension period and, in some cases, are subject to refund under applicable law
until such time as the FERC issues an order on the allowable level of rates.
CenterPoint Houston is not a "public utility" under the Federal Power Act
and therefore is not generally regulated by the FERC, although certain of its
transactions are subject to limited FERC jurisdiction. The Energy Act provides
the FERC the authority to establish mandatory and enforceable service
reliability standards for the electric industry. CenterPoint Energy is subject
to these standards.
STATE AND LOCAL REGULATION
Electric Transmission & Distribution. CenterPoint Houston conducts its
operations pursuant to a certificate of convenience and necessity issued by the
Texas Utility Commission that covers its present service area and facilities. In
addition, CenterPoint Houston holds non-exclusive franchises from the
incorporated municipalities in its service territory. In exchange for payment of
fees, these franchises give CenterPoint Houston the right to use the streets and
public rights-of-way of these municipalities to construct, operate and maintain
its transmission and distribution system and to use that system to conduct its
electric delivery business and for other purposes that the franchises permit.
The terms of the franchises, with various expiration dates, typically range from
5 to 50 years. As discussed above under "Our Business -- Electric Transmission &
Distribution -- Franchises," a new franchise ordinance for the City of Houston
franchise was granted in June 2005 with a term of 30 years. There are a total of
37 cities whose franchises will expire in 2007 and 2008. CenterPoint Houston
expects to be able to renew these expiring franchises.
All retail electric providers in CenterPoint Houston's service area pay the
same rates and other charges for the same transmission and distribution
services.
CenterPoint Houston's distribution rates charged to retail electric
providers for residential customers are based on amounts of energy delivered,
whereas distribution rates for a majority of commercial and industrial customers
are based on peak demand. Transmission rates charged to other distribution
companies are based on amounts of energy transmitted under "postage stamp" rates
that do not vary with the distance the energy is being transmitted. All
distribution companies in ERCOT pay CenterPoint Houston the same rates and other
charges for transmission services. The transmission and distribution rates for
CenterPoint Houston have been in effect since electric competition began. This
regulated delivery charge includes the transmission and distribution rate (which
includes municipal franchise fees), a system benefit fund fee imposed by the
Texas electric restructuring law, a nuclear decommissioning charge associated
with decommissioning the South Texas nuclear generating facility (South Texas
Project), transition charges associated with securitization of regulatory assets
and securitization of stranded costs, a competition transition charge for
collection of the true-up balance not securitized and a rate case expense
charge.
As discussed above under "Electric Transmission & Distribution --
CenterPoint Houston Rate Case," in December 2005, the Texas Utility Commission
agreed to initiate a rate proceeding concerning the reasonable-
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ness 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.
Natural Gas Distribution. In almost all communities in which CERC provides
natural gas distribution services, it operates under franchises, certificates or
licenses obtained from state and local authorities. The original terms of the
franchises, with various expiration dates, typically range from 10 to 30 years,
though franchises in Arkansas are perpetual. None of CERC's material franchises
expire in the near term. CERC expects to be able to renew expiring franchises.
In most cases, franchises to provide natural gas utility services are not
exclusive.
Substantially all of CERC's retail natural gas sales by its local
distribution divisions are subject to traditional cost-of-service regulation at
rates regulated by the relevant state public utility commissions and, in Texas,
by the Railroad Commission of Texas (Railroad Commission) and certain
municipalities CERC serves.
SOUTHERN GAS OPERATIONS
In November 2004, Southern Gas Operations filed an application for a $34
million base rate increase, which was subsequently adjusted downward to $28
million, with the Arkansas Public Service Commission (APSC). In September 2005,
an $11 million rate reduction (which included a $10 million reduction relating
to depreciation rates) ordered by the APSC went into effect. The reduced
depreciation rates were implemented effective October 2005. This base rate
reduction and corresponding reduction in depreciation expense represent an
annualized operating income reduction of $1 million.
In April 2005, the 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 169 incorporated cities located in the two
divisions. The proposed rates were approved or became effective by operation of
law in 164 of these cities. Five municipalities denied the rate change requests
within their respective jurisdictions. Southern Gas Operations has appealed the
actions of these five cities to the Railroad Commission. In February 2006,
Southern Gas Operations notified the Railroad Commission that it had reached a
settlement with four of the five cities. If approved, the settlement will affect
rates in a total of 60 cities in the South Texas Division. In addition, 19
cities where rates have already gone into effect have challenged the
jurisdictional and statutory basis for implementation of the new rates within
their respective jurisdictions. Southern Gas Operations has petitioned the
Railroad Commission for an order declaring that the new rates have been properly
established within these 19 cities. If the settlement is approved and assuming
all other rate change proposals become effective, revenues from Southern Gas
Operations' base rates and miscellaneous service charges would increase by an
additional $17 million annually. Currently, approximately $15 million of this
expected annual increase is in effect in the incorporated areas of Southern Gas
Operations' Beaumont/East Texas and South Texas Divisions.
In October 2005, Southern Gas Operations filed requests with the Louisiana
Public Service Commission (LPSC) for approximately $2 million in base rate
increases for its South Louisiana service territory and approximately $2 million
in base rate reductions for its North Louisiana service territory in accordance
with the Rate Stabilization Plans in its tariffs. These base rate changes became
effective on January 2, 2006 in accordance with the tariffs and are subject to
review and possible adjustment by the staff of the LPSC. Southern Gas Operations
is unable to predict when the LPSC staff may conclude its review or what
adjustments, if any, the staff may recommend.
In December 2005, Southern Gas Operations filed a request with the
Mississippi Public Service Commission (MPSC) for approximately $1 million in
miscellaneous service charges (e.g., charges to connect service, charges for
returned checks, etc.) in its Mississippi service territory. This request was
approved in the first quarter of 2006.
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In addition, in January and February 2006, Southern Gas Operations filed
requests with the MPSC for approximately $3 million in base rate increases in
its Mississippi service territory in accordance with the Automatic Rate
Adjustment Mechanism provisions in its tariffs and an additional $2 million in
surcharges to recover system restoration expenses incurred following hurricane
Katrina. Both requests are being reviewed by the MPSC staff with a decision
expected in the first quarter of 2006.
MINNESOTA GAS
In June 2005, the Minnesota Public Utilities Commission (MPUC) approved a
settlement which increased Minnesota Gas' base rates by approximately $9 million
annually. An interim rate increase of approximately $17 million had been
implemented in October 2004. Substantially all of the excess amounts collected
in interim rates over those approved in the final settlement were refunded to
customers in the third quarter of 2005.
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
decision by the MPUC is expected in the third quarter of 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. The Minnesota Office
of the Attorney General (OAG) issued its report alleging Minnesota Gas has
violated the CWR and recommended a $5 million penalty. Minnesota Gas and the OAG
have reached an agreement on procedures to be followed for the current Cold
Weather Period which began on October 15, 2005. 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. Minnesota Gas is in
settlement discussions regarding both the OAG's action and the action on behalf
of the purported class.
DEPARTMENT OF TRANSPORTATION
In December 2002, Congress enacted the Pipeline Safety Improvement Act of
2002 (the Act). This legislation applies to our interstate pipelines as well as
our intrastate pipelines and local distribution companies. The legislation
imposes several requirements related to ensuring pipeline safety and integrity.
It requires pipeline and distribution companies to assess the integrity of their
pipeline transmission facilities in areas of high population concentration or
High Consequence Areas (HCA). The legislation further requires companies to
perform remediation activities, in accordance with the requirements of the
legislation, over a 10-year period.
Final regulations implementing the Act became effective on February 14,
2004 and provided guidance on, among other things, the areas that should be
classified as HCA.
Our interstate and intrastate pipelines and our natural gas distribution
companies anticipate that compliance with these regulations will require
increases in both capital and operating cost. The level of expenditures required
to comply with these regulations will be dependent on several factors, including
the age of the facility, the pressures at which the facility operates and the
number of facilities deemed to be located in areas designated as HCA. Based on
our interpretation of the rules and preliminary technical reviews, we believe
compliance will require average annual expenditures of approximately $15 to $20
million during the initial 10-year period.
ENVIRONMENTAL MATTERS
Our operations are subject to stringent and complex laws and regulations
pertaining to health, safety and the environment. As an owner or operator of
natural gas pipelines, gas gathering and processing systems, and
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electric transmission and distribution systems we must comply with these laws
and regulations at the federal, state and local levels. These laws and
regulations can restrict or impact our business activities in many ways, such
as:
- restricting the way we can handle or dispose of our wastes;
- limiting or prohibiting construction activities in sensitive areas such
as wetlands, coastal regions, or areas inhabited by endangered species;
- requiring remedial action to mitigate pollution conditions caused by our
operations, or attributable to former operations; and
- enjoining the operations of facilities deemed in non-compliance with
permits issued pursuant to such environmental laws and regulations.
In order to comply with these requirements, we may need to spend
substantial amounts and devote other resources from time to time to:
- construct or acquire new equipment;
- acquire permits for facility operations;
- modify or replace existing and proposed equipment; and
- clean up or decommission waste disposal areas, fuel storage and
management facilities and other locations and facilities.
Failure to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial actions, and the
issuance of orders enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.
The trend in environmental regulation is to place more restrictions and
limitations on activities that may affect the environment, and thus there can be
no assurance as to the amount or timing of future expenditures for environmental
compliance or remediation, and actual future expenditures may be different from
the amounts we currently anticipate. We try to anticipate future regulatory
requirements that might be imposed and plan accordingly to remain in compliance
with changing environmental laws and regulations and to minimize the costs of
such compliance.
Based on current regulatory requirements and interpretations, we do not
believe that compliance with federal, state or local environmental laws and
regulations will have a material adverse effect on our business, financial
position or results of operations. In addition, we believe that the various
environmental remediation activities in which we are presently engaged will not
materially interrupt or diminish our operational ability. We cannot assure you,
however, that future events, such as changes in existing laws, the promulgation
of new laws, or the development or discovery of new facts or conditions will not
cause us to incur significant costs. The following is a discussion of all
material environmental and safety laws and regulations that relate to our
operations. We believe that we are in substantial compliance with all of these
environmental laws and regulations.
AIR EMISSIONS
Our operations are subject to the federal Clean Air Act and comparable
state laws and regulations. These laws and regulations regulate emissions of air
pollutants from various industrial sources, including our processing plants and
compressor stations, and also impose various monitoring and reporting
requirements. Such laws and regulations may require that we obtain pre-approval
for the construction or modification of certain projects or facilities expected
to produce air emissions or result in the increase of existing air emissions,
15
obtain and strictly comply with air permits containing various emissions and
operational limitations, or utilize specific emission control technologies to
limit emissions. Our failure to comply with these requirements could subject us
to monetary penalties, injunctions, conditions or restrictions on operations,
and potentially criminal enforcement actions. We may be required to incur
certain capital expenditures in the future for air pollution control equipment
in connection with obtaining and maintaining operating permits and approvals for
air emissions. We believe, however, that our operations will not be materially
adversely affected by such requirements, and the requirements are not expected
to be any more burdensome to us than to any other similarly situated companies.
WATER DISCHARGES
Our operations are subject to the Federal Water Pollution Control Act of
1972, as amended, also known as the Clean Water Act, and analogous state laws
and regulations. These laws and regulations impose detailed requirements and
strict controls regarding the discharge of pollutants into waters of the United
States. The unpermitted discharge of pollutants, including discharges resulting
from a spill or leak incident, is prohibited. The Clean Water Act and
regulations implemented thereunder also prohibit discharges of dredged and fill
material in wetlands and other waters of the United States unless authorized by
an appropriately issued permit. Any unpermitted release of petroleum or other
pollutants from our pipelines or facilities could result in fines or penalties
as well as significant remedial obligations.
HAZARDOUS WASTE
Our operations generate wastes, including some hazardous wastes, that are
subject to the federal Resource Conservation and Recovery Act (RCRA), and
comparable state laws, which impose detailed requirements for the handling,
storage, treatment and disposal of hazardous and solid waste. RCRA currently
exempts many natural gas gathering and field processing wastes from
classification as hazardous waste. Specifically, RCRA excludes from the
definition of hazardous waste waters produced and other wastes associated with
the exploration, development, or production of crude oil and natural gas.
However, these oil and gas exploration and production wastes are still regulated
under state law and the less stringent non-hazardous waste requirements of RCRA.
Moreover, ordinary industrial wastes such as paint wastes, waste solvents,
laboratory wastes, and waste compressor oils may be regulated as hazardous
waste. The transportation of natural gas in pipelines may also generate some
hazardous wastes that are subject to RCRA or comparable state law requirements.
LIABILITY FOR REMEDIATION
The Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended (CERCLA), also known as "Superfund," and comparable state laws
impose liability, without regard to fault or the legality of the original
conduct, on certain classes of persons responsible for the release of hazardous
substances into the environment. Such classes of persons include the current and
past owners or operators of sites where a hazardous substance was released, and
companies that disposed or arranged for disposal of hazardous substances at
offsite locations such as landfills. Although petroleum, as well as natural gas,
is excluded from CERCLA's definition of a "hazardous substance," in the course
of our ordinary operations we generate wastes that may fall within the
definition of a "hazardous substance." CERCLA authorizes the United States
Environmental Protection Agency (EPA) and, in some cases, third parties to take
actions in response to threats to the public health or the environment and to
seek to recover from the responsible classes of persons the costs they incur.
Under CERCLA, we could be subject to joint and several liability for the costs
of cleaning up and restoring sites where hazardous substances have been
released, for damages to natural resources, and for the costs of certain health
studies.
LIABILITY FOR PREEXISTING CONDITIONS
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
16
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. In the pending litigation, the plaintiffs seek monetary
damages for alleged damage to the aquifer underlying their property, unspecified
alleged personal injuries, alleged fear of cancer, alleged property damage or
diminution of value of their property, and, in addition, seek damages for
trespass, punitive, and exemplary damages. We do not expect the ultimate cost
associated with resolving this matter to have a material impact on our financial
condition, results of operations or cash flows or that of 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 December 31, 2005, CERC had accrued $14 million for remediation of these
Minnesota sites. At December 31, 2005, 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 December 31, 2005, CERC has collected $13
million from insurance companies and ratepayers to be used for future
environmental remediation.
In addition to the Minnesota sites, the EPA and other regulators have
investigated MGP sites that were owned or operated by CERC or may have been
owned or operated by one of its former affiliates. CERC has been named as a
defendant in two lawsuits under which contribution is sought by private parties
for the cost to remediate former MGP sites based on the previous ownership of
such sites by former affiliates of CERC or its divisions. CERC has also been
identified as a PRP by the State of Maine for a site that is the subject of one
of the lawsuits. In March 2005, the court considering the other suit for
contribution granted CERC's motion to dismiss on the grounds that CERC was not
an "operator" of the site as had been alleged. The plaintiff in that case has
filed an appeal of the court's dismissal of CERC. We are 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 CERCLA and applicable state statutes, and is
vigorously contesting those suits and its designation as a PRP.
Mercury Contamination. Our pipeline and natural gas 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. We
have found this type of contamination at some sites in the past, and we have
conducted remediation at these sites. It is possible that other contaminated
sites may exist and that remediation costs may be incurred for these sites.
Although the total amount of these costs cannot be known at this time, based on
our experience and that of others in the natural gas industry to date and on the
current regulations regarding remediation of these sites, we believe that the
costs of any remediation of these sites will not be material to our financial
condition, results of operations or cash flows.
Other Environmental. From time to time, we have received notices from
regulatory authorities or others regarding our status as a PRP in connection
with sites found to require remediation due to the presence of environmental
contaminants. Although their ultimate outcome cannot be predicted at this time,
we do not
17
believe, based on our experience to date, that these matters, either
individually or in the aggregate, will have a material adverse effect on our
financial condition, results of operations or cash flows.
Asbestos. Some of our facilities contain or have contained asbestos
insulation and other asbestos-containing materials. We or our 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 we own, but most existing claims relate to facilities
previously owned by our subsidiaries but currently owned by Texas Genco LLC. We
anticipate that additional claims like those received may be asserted in the
future. Under the terms of the separation agreement between us and Texas Genco,
ultimate financial responsibility for uninsured losses from these claims
relating to facilities transferred to Texas Genco has been assumed by Texas
Genco, but under the terms of our agreement to sell Texas Genco to Texas Genco
LLC, we have agreed to continue to defend such claims to the extent they are
covered by insurance we maintain, subject to reimbursement of the costs of such
defense from Texas Genco LLC. Although their ultimate outcome cannot be
predicted at this time, we intend to continue vigorously contesting claims that
we do not consider to have merit and do not expect, based on our experience to
date, these matters, either individually or in the aggregate, to have a material
adverse effect on our financial condition, results of operations or cash flows.
REGULATORY MATTERS RELATING TO DISCONTINUED OPERATIONS
Texas Genco and the other owners of the South Texas Project are required by
NRC regulations to estimate from time to time the amounts required to
decommission that nuclear generating facility and are required to maintain funds
to satisfy that obligation when the plant ultimately is decommissioned. Although
CenterPoint Houston no longer owns an interest in the South Texas Project,
CenterPoint Houston currently collects through a separate nuclear
decommissioning charge amounts calculated to provide sufficient funds at the
time of decommissioning to discharge these obligations. Funds collected are
deposited into nuclear decommissioning trusts. The beneficial ownership of the
nuclear decommissioning trusts is held by a subsidiary of Texas Genco LLC as a
licensee of the facility. While current funding levels exceed NRC minimum
requirements, no assurance can be given that the amounts held in trust will be
adequate to cover the actual decommissioning costs of the South Texas Project.
Such costs may vary because of changes in the assumed date of decommissioning
and changes in regulatory requirements, technology and costs of labor, materials
and waste burial. In the event that funds from the trust are inadequate to
decommission the facilities, CenterPoint Houston will be required by the
transaction agreement with Texas Genco LLC to collect through rates or other
authorized charges all additional amounts required to fund Texas Genco LLC's
obligations relating to the decommissioning of the South Texas Project.
EMPLOYEES
As of December 31, 2005, we had 9,001 full-time employees. The following
table sets forth the number of our employees by business segment:
NUMBER REPRESENTED
BY UNIONS OR
OTHER COLLECTIVE
BUSINESS SEGMENT NUMBER BARGAINING GROUPS
---------------- ------ ------------------
Electric Transmission & Distribution....................... 2,931 1,225
Natural Gas Distribution................................... 4,387 1,493
Competitive Natural Gas Sales and Services................. 98 --
Pipelines and Field Services............................... 717 --
Other Operations........................................... 868 --
----- -----
Total.................................................... 9,001 2,718
===== =====
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As of December 31, 2005, approximately 30% of the Company's employees are
subject to collective bargaining agreements. Two of these agreements, covering
approximately 19% of the Company's employees will expire in 2006. Minnesota Gas
has 466 bargaining unit employees who are covered by a collective bargaining
unit agreement with the United Association of Journeymen and Apprentices of
Plumbing and Pipe Fitting Industry of the United States and Canada Local 340
that expires in April 2006. CenterPoint Houston has 1,225 bargaining unit
employees who are covered by a collective bargaining unit agreement with the
International Brotherhood of Electrical Workers Local 66, that expires in May
2006. We have a good relationship with these bargaining units and expect to
renegotiate new agreements in 2006.
EXECUTIVE OFFICERS
(AS OF FEBRUARY 28, 2006)
NAME AGE TITLE
---- --- -----
David M. McClanahan....................... 56 President and Chief Executive Officer and Director
Scott E. Rozzell.......................... 56 Executive Vice President, General Counsel and
Corporate Secretary
Gary L. Whitlock.......................... 56 Executive Vice President and Chief Financial
Officer
James S. Brian............................ 58 Senior Vice President and Chief Accounting Officer
Byron R. Kelley........................... 58 Senior Vice President and Group President --
CenterPoint Energy Pipelines and Field Services
Thomas R. Standish........................ 56 Senior Vice President and Group
President -- Regulated Operations
DAVID M. MCCLANAHAN has been President and Chief Executive Officer and a
director of CenterPoint Energy since September 2002. He served as Vice Chairman
of Reliant Energy, Incorporated (Reliant Energy) from October 2000 to September
2002 and as President and Chief Operating Office of Reliant Energy's Delivery
Group from April 1999 to September 2002. He has served in various executive
capacities with CenterPoint Energy since 1986. He previously served as Chairman
of the Board of Directors of ERCOT and Chairman of the Board of the University
of St. Thomas in Houston. He currently serves on the boards of the Edison
Electric Institute and the American Gas Association.
SCOTT E. ROZZELL has served as Executive Vice President, General Counsel
and Corporate Secretary of CenterPoint Energy since September 2002. He served as
Executive Vice President and General Counsel of the Delivery Group of Reliant
Energy from March 2001 to September 2002. Before joining CenterPoint Energy in
2001, Mr. Rozzell was a senior partner in the law firm of Baker Botts L.L.P. He
currently serves as Chair of the Association of Electric Companies of Texas.
GARY L. WHITLOCK has served as Executive Vice President and Chief Financial
Officer of CenterPoint Energy since September 2002. He served as Executive Vice
President and Chief Financial Officer of the Delivery Group of Reliant Energy
from July 2001 to September 2002. Mr. Whitlock served as the Vice President,
Finance and Chief Financial Officer of Dow AgroSciences, a subsidiary of The Dow
Chemical Company, from 1998 to 2001.
JAMES S. BRIAN has served as Senior Vice President and Chief Accounting
Officer of CenterPoint Energy since August 2002. He served as Senior Vice
President, Finance and Administration of the Delivery Group of Reliant Energy
from 1999 to August 2002. Mr. Brian has served in various executive capacities
with CenterPoint Energy since 1983.
BYRON R. KELLEY has served as Senior Vice President and Group
President -- CenterPoint Energy Pipelines and Field Services since June 2004,
having previously served as President and Chief Operating Officer of CenterPoint
Energy Pipelines and Field Services from May 2003 to June 2004. Prior to joining
CenterPoint Energy he served as President of El Paso International, a subsidiary
of El Paso Corporation, from January 2001 to August 2002. He currently serves on
the Board of Directors of the Interstate Natural Gas Association of America.
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THOMAS R. STANDISH has served as Senior Vice President and Group
President-Regulated Operations of CenterPoint Energy since August 2005, having
previously served as Senior Vice President and Group President and Chief
Operating Officer of CenterPoint Houston from June 2004 to August 2005 and as
President and Chief Operating Officer of CenterPoint Houston from August 2002 to
June 2004. He served as President and Chief Operating Officer for both
electricity and natural gas for Reliant Energy's Houston area from 1999 to
August 2002. Mr. Standish has served in various executive capacities with
CenterPoint Energy since 1993. He currently serves on the Board of Directors of
ERCOT.
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ITEM 1A. RISK FACTORS
We are a holding company that conducts all of our business operations
through subsidiaries, primarily CenterPoint Houston and CERC. The following
summarizes the principal risk factors associated with the businesses conducted
by each of these subsidiaries:
RISK FACTORS AFFECTING OUR ELECTRIC TRANSMISSION & DISTRIBUTION BUSINESS
CENTERPOINT HOUSTON MAY NOT BE SUCCESSFUL IN ULTIMATELY RECOVERING THE FULL
VALUE OF ITS TRUE-UP COMPONENTS, WHICH COULD RESULT IN THE ELIMINATION OF
CERTAIN TAX BENEFITS AND COULD HAVE AN ADVERSE IMPACT ON CENTERPOINT HOUSTON'S
RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.
In March 2004, CenterPoint Houston filed its true-up application with the
Texas Utility Commission, requesting recovery of $3.7 billion, excluding
interest. In December 2004, the Texas Utility Commission issued its final order
(True-Up Order) allowing CenterPoint Houston to recover a true-up balance of
approximately $2.3 billion, which included interest through August 31, 2004, and
providing for adjustment of the amount to be recovered to include interest on
the balance until recovery, the principal portion of additional excess
mitigation credits returned to customers after August 31, 2004 and certain other
matters. CenterPoint Houston and other parties filed appeals of the True-Up
Order to a district court in Travis County, Texas. 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. First, the
court reversed the Texas Utility Commission's decision to prohibit CenterPoint
Houston from recovering $180 million in credits through August 2004 that
CenterPoint Houston was ordered to provide to retail electric providers as a
result of an inaccurate stranded cost estimate made by the Texas Utility
Commission in 2000. Additional credits of approximately $30 million were paid
after August 2004. Second, the court reversed the Texas Utility Commission's
disallowance of $440 million in transition costs which are recoverable under the
Texas Utility Commission's regulations. 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 prediction
can be made as to the ultimate outcome or timing of such appeals. Additionally,
if the amount of the true-up balance is reduced on appeal to below the amount
recovered through the issuance of transition bonds and under the CTC, while the
amount of transition bonds outstanding would not be reduced, CenterPoint Houston
would be required to refund the over recovery to its customers.
Among the issues raised in our appeal of the True-Up Order is the Texas
Utility Commission's reduction of our stranded cost recovery by approximately
$146 million for the present value of certain deferred tax benefits associated
with our former Texas Genco assets. Such reduction was considered in our
recording of an after-tax extraordinary loss of $977 million in the last half of
2004. We believe that the Texas Utility Commission based its order on proposed
regulations issued by the 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 ADITC and
EDFIT back to customers. However, in December 2005, the IRS withdrew those
proposed normalization regulations and issued new proposed regulations that do
not include the provision allowing a retroactive election to pass the tax
benefits back to customers. 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 us 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 depreciation benefits. If a
normalization violation should ultimately be found to exist, it could have an
adverse impact on our results of operations, financial condition and cash flows.
The Texas Utility Commission has not previously required a company subject to
its jurisdiction to take action that would result in a normalization violation.
21
CENTERPOINT HOUSTON'S RECEIVABLES ARE CONCENTRATED IN A SMALL NUMBER OF RETAIL
ELECTRIC PROVIDERS, AND ANY DELAY OR DEFAULT IN PAYMENT COULD ADVERSELY AFFECT
CENTERPOINT HOUSTON'S CASH FLOWS, FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
CenterPoint Houston's receivables from the distribution of electricity are
collected from retail electric providers that supply the electricity CenterPoint
Houston distributes to their customers. Currently, CenterPoint Houston does
business with 66 retail electric providers. Adverse economic conditions,
structural problems in the market served by the Electric Reliability Council of
Texas, Inc. (ERCOT) or financial difficulties of one or more retail electric
providers could impair the ability of these retail providers to pay for
CenterPoint Houston's services or could cause them to delay such payments.
CenterPoint Houston depends on these retail electric providers to remit payments
on a timely basis. Applicable regulatory provisions require that customers be
shifted to a provider of last resort if a retail electric provider cannot make
timely payments. RRI, through its subsidiaries, is CenterPoint Houston's largest
customer. Approximately 56% of CenterPoint Houston's $127 million in billed
receivables from retail electric providers at December 31, 2005 was owed by
subsidiaries of RRI. Any delay or default in payment could adversely affect
CenterPoint Houston's cash flows, financial condition and results of operations.
RATE REGULATION OF CENTERPOINT HOUSTON'S BUSINESS MAY DELAY OR DENY
CENTERPOINT HOUSTON'S ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER
ITS COSTS.
CenterPoint Houston's rates are regulated by certain municipalities and the
Texas Utility Commission based on an analysis of its invested capital and its
expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to
charge may not match its expenses at any given time. The regulatory process by
which rates are determined may not always result in rates that will produce full
recovery of CenterPoint Houston's costs and enable CenterPoint Houston to earn a
reasonable return on its invested capital.
DISRUPTIONS AT POWER GENERATION FACILITIES OWNED BY THIRD PARTIES COULD
INTERRUPT CENTERPOINT HOUSTON'S SALES OF TRANSMISSION AND DISTRIBUTION
SERVICES.
CenterPoint Houston transmits and distributes to customers of retail
electric providers electric power that the retail electric providers obtain from
power generation facilities owned by third parties. CenterPoint Houston does not
own or operate any power generation facilities. If power generation is disrupted
or if power generation capacity is inadequate, CenterPoint Houston's sales of
transmission and distribution services may be diminished or interrupted, and its
results of operations, financial condition and cash flows may be adversely
affected.
CENTERPOINT HOUSTON'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.
A significant portion of CenterPoint Houston's revenues is derived from
rates that it collects from each retail electric provider based on the amount of
electricity it distributes on behalf of such retail electric provider. Thus,
CenterPoint Houston's revenues and results of operations are subject to
seasonality, weather conditions and other changes in electricity usage, with
revenues being higher during the warmer months.
RISK FACTORS AFFECTING OUR NATURAL GAS DISTRIBUTION, COMPETITIVE NATURAL GAS
SALES AND SERVICES AND PIPELINES AND FIELD SERVICES BUSINESSES
RATE REGULATION OF CERC'S BUSINESS MAY DELAY OR DENY CERC'S ABILITY TO EARN A
REASONABLE RETURN AND FULLY RECOVER ITS COSTS.
CERC's rates for its local distribution companies are regulated by certain
municipalities and state commissions, and for its interstate pipelines by the
FERC, based on an analysis of its invested capital and its expenses in a test
year. Thus, the rates that CERC is allowed to charge may not match its expenses
at any given time. The regulatory process in which rates are determined may not
always result in rates that will produce full recovery of CERC's costs and
enable CERC to earn a reasonable return on its invested capital.
22
CERC'S BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, WHICH COULD
LEAD TO LESS NATURAL GAS BEING MARKETED, AND ITS PIPELINES AND FIELD SERVICES
BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE TRANSPORTATION, STORAGE,
GATHERING, TREATING AND PROCESSING OF NATURAL GAS, WHICH COULD LEAD TO LOWER
PRICES, EITHER OF WHICH COULD HAVE AN ADVERSE IMPACT ON CERC'S RESULTS OF
OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.
CERC competes primarily with alternate energy sources such as electricity
and other fuel sources. In some areas, intrastate pipelines, other natural gas
distributors and marketers also compete directly with CERC for natural gas sales
to end-users. In addition, as a result of federal regulatory changes affecting
interstate pipelines, natural gas marketers operating on these pipelines may be
able to bypass CERC's facilities and market, sell and/or transport natural gas
directly to commercial and industrial customers. Any reduction in the amount of
natural gas marketed, sold or transported by CERC as a result of competition may
have an adverse impact on CERC's results of operations, financial condition and
cash flows.
CERC's two interstate pipelines and its gathering systems compete with
other interstate and intrastate pipelines and gathering systems in the
transportation and storage of natural gas. The principal elements of competition
are rates, terms of service, and flexibility and reliability of service. They
also compete indirectly with other forms of energy, including electricity, coal
and fuel oils. The primary competitive factor is price. The actions of CERC's
competitors could lead to lower prices, which may have an adverse impact on
CERC's results of operations, financial condition and cash flows.
CERC'S NATURAL GAS DISTRIBUTION AND COMPETITIVE NATURAL GAS SALES AND SERVICES
BUSINESSES ARE SUBJECT TO FLUCTUATIONS IN NATURAL GAS PRICING LEVELS, WHICH
COULD AFFECT THE ABILITY OF CERC'S SUPPLIERS AND CUSTOMERS TO MEET THEIR
OBLIGATIONS OR OTHERWISE ADVERSELY AFFECT CERC'S LIQUIDITY.
CERC is subject to risk associated with increases in the price of natural
gas, which has been the trend in recent years. Increases in natural gas prices
might affect CERC's ability to collect balances due from its customers and, on
the regulated side, could create the potential for uncollectible accounts
expense to exceed the recoverable levels built into CERC's tariff rates. In
addition, a sustained period of high natural gas prices could apply downward
demand pressure on natural gas consumption in the areas in which CERC operates
and increase the risk that CERC's suppliers or customers fail or are unable to
meet their obligations. Additionally, increasing gas prices could create the
need for CERC to provide collateral in order to purchase gas.
IF CERC WERE TO FAIL TO EXTEND A CONTRACT WITH ONE OF ITS SIGNIFICANT PIPELINE
CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON ITS OPERATIONS.
CERC's contract with Laclede Gas Company, one of its pipeline's customers,
is currently scheduled to expire in 2007. To the extent the pipeline is unable
to extend this contract or the contract is renegotiated at rates substantially
less than the rates provided in the current contract, there could be an adverse
effect on CERC's results of operations, financial condition and cash flows.
A DECLINE IN CERC'S CREDIT RATING COULD RESULT IN CERC'S HAVING TO PROVIDE
COLLATERAL IN ORDER TO PURCHASE GAS.
If CERC's credit rating were to decline, it might be required to post cash
collateral in order to purchase natural gas. If a credit rating downgrade and
the resultant cash collateral requirement were to occur at a time when CERC was
experiencing significant working capital requirements or otherwise lacked
liquidity, CERC might be unable to obtain the necessary natural gas to meet its
obligations to customers, and its results of operations, financial condition and
cash flows would be adversely affected.
CERC'S PIPELINES' AND FIELD SERVICES' BUSINESS REVENUES AND RESULTS OF
OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS.
CERC's pipelines and field services business largely relies on gas sourced
in the various supply basins located in the Midcontinent region of the United
States. To the extent the availability of this supply is
23
substantially reduced, it could have an adverse effect on CERC's results of
operations, financial condition and cash flows.
CERC'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.
A substantial portion of CERC's revenues is derived from natural gas sales
and transportation. Thus, CERC's revenues and results of operations are subject
to seasonality, weather conditions and other changes in natural gas usage, with
revenues being higher during the winter months.
RISK FACTORS ASSOCIATED WITH OUR CONSOLIDATED FINANCIAL CONDITION
IF WE ARE UNABLE TO ARRANGE FUTURE FINANCINGS ON ACCEPTABLE TERMS, OUR ABILITY
TO REFINANCE EXISTING INDEBTEDNESS COULD BE LIMITED.
As of December 31, 2005, we had $8.9 billion of outstanding indebtedness on
a consolidated basis, which includes $2.5 billion of non-recourse transition
bonds. As of December 31, 2005, approximately $665 million principal amount of
this debt must be paid through 2008. This amount excludes principal repayments
of approximately $379 million on transition bonds, for which a dedicated revenue
stream exists. In addition, we have $830 million of outstanding convertible
notes on which holders could exercise their "put" rights during this period. Our
future financing activities may depend, at least in part, on:
- 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;
- general economic and capital market conditions;
- credit availability from financial institutions and other lenders;
- investor confidence in us and the market in which we operate;
- maintenance of acceptable credit ratings;
- market expectations regarding our future earnings and probable cash
flows;
- market perceptions of our ability to access capital markets on reasonable
terms;
- our exposure to RRI in connection with its indemnification obligations
arising in connection with its separation from us; and
- provisions of relevant tax and securities laws.
As of December 31, 2005, CenterPoint Houston had outstanding $2.0 billion
aggregate principal amount of general mortgage bonds under the General Mortgage,
including approximately $527 million held in trust to secure pollution control
bonds for which CenterPoint Energy is obligated and approximately $229 million
held in trust to secure pollution control bonds for which CenterPoint Houston is
obligated. Additionally, CenterPoint Houston had outstanding approximately $253
million aggregate principal amount of first mortgage bonds under the Mortgage,
including approximately $151 million held in trust to secure certain pollution
control bonds for which CenterPoint Energy is obligated. CenterPoint Houston may
issue additional general mortgage bonds on the basis of retired bonds, 70% of
property additions or cash deposited with the trustee. Approximately $2.0
billion of additional first mortgage bonds and general mortgage bonds could be
issued on the basis of retired bonds and 70% of property additions as of
December 31, 2005. However, CenterPoint Houston is contractually prohibited,
subject to certain exceptions, from issuing additional first mortgage bonds.
Our current credit ratings are discussed in "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Future Sources and Uses of Cash -- Impact on Liquidity of a
Downgrade in Credit Ratings" in Item 7 of this report. These credit ratings may
not remain in effect for any given period of time and one or more of these
ratings may be lowered or withdrawn entirely by a rating agency. We note that
these credit ratings are not recommendations to buy, sell or hold our
securities. Each rating should be evaluated independently of any other rating.
Any future reduction
24
or withdrawal of one or more of our credit ratings could have a material adverse
impact on our ability to access capital on acceptable terms.
AS A HOLDING COMPANY WITH NO OPERATIONS OF OUR OWN, WE WILL DEPEND ON
DISTRIBUTIONS FROM OUR SUBSIDIARIES TO MEET OUR PAYMENT OBLIGATIONS, AND
PROVISIONS OF APPLICABLE LAW OR CONTRACTUAL RESTRICTIONS COULD LIMIT THE
AMOUNT OF THOSE DISTRIBUTIONS.
We derive all our operating income from, and hold all our assets through,
our subsidiaries. As a result, we will depend on distributions from our
subsidiaries in order to meet our payment obligations. In general, these
subsidiaries are separate and distinct legal entities and have no obligation to
provide us with funds for our payment obligations, whether by dividends,
distributions, loans or otherwise. In addition, provisions of applicable law,
such as those limiting the legal sources of dividends, limit their ability to
make payments or other distributions to us, and they could agree to contractual
restrictions on their ability to make distributions.
Our right to receive any assets of any subsidiary, and therefore the right
of our creditors to participate in those assets, will be effectively
subordinated to the claims of that subsidiary's creditors, including trade
creditors. In addition, even if we were a creditor of any subsidiary, our rights
as a creditor would be subordinated to any security interest in the assets of
that subsidiary and any indebtedness of the subsidiary senior to that held by
us.
THE USE OF DERIVATIVE CONTRACTS BY US AND OUR SUBSIDIARIES IN THE NORMAL
COURSE OF BUSINESS COULD RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT OUR
RESULTS OF OPERATIONS AND THOSE OF OUR SUBSIDIARIES.
We and our subsidiaries use derivative instruments, such as swaps, options,
futures and forwards, to manage our commodity and financial market risks. We and
our subsidiaries could recognize financial losses as a result of volatility in
the market values of these contracts, or should a counterparty fail to perform.
In the absence of actively quoted market prices and pricing information from
external sources, the valuation of these financial instruments can involve
management's judgment or use of estimates. As a result, changes in the
underlying assumptions or use of alternative valuation methods could affect the
reported fair value of these contracts.
RISKS COMMON TO OUR BUSINESSES AND OTHER RISKS
WE ARE SUBJECT TO OPERATIONAL AND FINANCIAL RISKS AND LIABILITIES ARISING FROM
ENVIRONMENTAL LAWS AND REGULATIONS.
Our operations are subject to stringent and complex laws and regulations
pertaining to health, safety and the environment. As an owner or operator of
natural gas pipelines and distribution systems, gas gathering and processing
systems, and electric transmission and distribution systems we must comply with
these laws and regulations at the federal, state and local levels. These laws
and regulations can restrict or impact our business activities in many ways,
such as:
- restricting the way we can handle or dispose of our wastes;
- limiting or prohibiting construction activities in sensitive areas such
as wetlands, coastal regions, or areas inhabited by endangered species;
- requiring remedial action to mitigate pollution conditions caused by our
operations, or attributable to former operations; and
- enjoining the operations of facilities deemed in non-compliance with
permits issued pursuant to such environmental laws and regulations.
In order to comply with these requirements, we may need to spend
substantial amounts and devote other resources from time to time to:
- construct or acquire new equipment;
- acquire permits for facility operations;
25
- modify or replace existing and proposed equipment; and
- clean up or decommission waste disposal areas, fuel storage and
management facilities and other locations and facilities.
Failure to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial actions, and the
issuance of orders enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.
OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT. INSUFFICIENT INSURANCE COVERAGE
AND INCREASED INSURANCE COSTS COULD ADVERSELY IMPACT OUR RESULTS OF
OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.
We currently have general liability and property insurance in place to
cover certain of our facilities in amounts that we consider appropriate. Such
policies are subject to certain limits and deductibles and do not include
business interruption coverage. Insurance coverage may not be available in the
future at current costs or on commercially reasonable terms, and the insurance
proceeds received for any loss of, or any damage to, any of our facilities may
not be sufficient to restore the loss or damage without negative impact on our
results of operations, financial condition and cash flows.
In common with other companies in its line of business that serve coastal
regions, CenterPoint Houston does not have insurance covering its transmission
and distribution system because CenterPoint Houston believes it to be cost
prohibitive. If CenterPoint Houston were to sustain any loss of, or damage to,
its transmission and distribution properties, it may not be able to recover such
loss or damage through a change in its regulated rates, and any such recovery
may not be timely granted. Therefore, CenterPoint Houston may not be able to
restore any loss of, or damage to, any of its transmission and distribution
properties without negative impact on its results of operations, financial
condition and cash flows.
WE, CENTERPOINT HOUSTON AND CERC COULD INCUR LIABILITIES ASSOCIATED WITH
BUSINESSES AND ASSETS THAT WE HAVE TRANSFERRED TO OTHERS.
Under some circumstances, we and CenterPoint Houston could incur
liabilities associated with assets and businesses we and CenterPoint Houston no
longer own. These assets and businesses were previously owned by Reliant Energy,
a predecessor of CenterPoint Houston, directly or through subsidiaries and
include:
- those transferred to RRI or its subsidiaries in connection with the
organization and capitalization of RRI prior to its initial public
offering in 2001; and
- those transferred to Texas Genco in connection with its organization and
capitalization.
In connection with the organization and capitalization of RRI, RRI and its
subsidiaries assumed liabilities associated with various assets and businesses
Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the
applicable transferee subsidiaries to indemnify, us and our subsidiaries,
including CenterPoint Houston and CERC, with respect to liabilities associated
with the transferred assets and businesses. The indemnity provisions were
intended to place sole financial responsibility on RRI and its subsidiaries for
all liabilities associated with the current and historical businesses and
operations of RRI, regardless of the time those liabilities arose. If RRI is
unable to satisfy a liability that has been so assumed in circumstances in which
Reliant Energy has not been released from the liability in connection with the
transfer, we, CenterPoint Houston or CERC could be responsible for satisfying
the liability.
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
26
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 alternatives. RRI continues to meet
its obligations under the transportation contracts.
RRI's unsecured debt ratings are currently below investment grade. If RRI
were unable to meet its obligations, it would need to consider, among various
options, restructuring under the bankruptcy laws, in which event RRI might not
honor its indemnification obligations and claims by RRI's creditors might be
made against us as its former owner.
Reliant Energy and RRI are named as defendants in a number of lawsuits
arising out of power sales in California and other West Coast markets and
financial reporting matters. Although these matters relate to the business and
operations of RRI, claims against Reliant Energy have been made on grounds that
include the effect of RRI's financial results on Reliant Energy's historical
financial statements and liability of Reliant Energy as a controlling
shareholder of RRI. We or CenterPoint Houston could incur liability if claims in
one or more of these lawsuits were successfully asserted against us or
CenterPoint Houston and indemnification from RRI were determined to be
unavailable or if RRI were unable to satisfy indemnification obligations owed
with respect to those claims.
In connection with the organization and capitalization of Texas Genco,
Texas Genco assumed liabilities associated with the electric generation assets
Reliant Energy transferred to it. Texas Genco also agreed to indemnify, and
cause the applicable transferee subsidiaries to indemnify, us and our
subsidiaries, including CenterPoint Houston, with respect to liabilities
associated with the transferred assets and businesses. In many cases the
liabilities assumed were obligations of CenterPoint Houston and CenterPoint
Houston was not released by third parties from these liabilities. The indemnity
provisions were intended generally to place sole financial responsibility on
Texas Genco and its subsidiaries for all liabilities associated with the current
and historical businesses and operations of Texas Genco, regardless of the time
those liabilities arose. In connection with the sale of Texas Genco's fossil
generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC, the
separation agreement we entered into with Texas Genco in connection with the
organization and capitalization of Texas Genco was amended to provide that all
of Texas Genco's rights and obligations under the separation agreement relating
to its fossil generation assets, including Texas Genco's obligation to indemnify
us with respect to liabilities associated with the fossil generation assets and
related business, were assigned to and assumed by Texas Genco LLC. In addition,
under the amended separation agreement, Texas Genco is no longer liable for, and
CenterPoint Energy has assumed and agreed to indemnify Texas Genco LLC against,
liabilities that Texas Genco originally assumed in connection with its
organization to the extent, and only to the extent, that such liabilities are
covered by certain insurance policies or other similar agreements held by
CenterPoint Energy. If Texas Genco or Texas Genco LLC were unable to satisfy a
liability that had been so assumed or indemnified against, and provided Reliant
Energy had not been released from the liability in connection with the transfer,
CenterPoint Houston could be responsible for satisfying the liability.
We or our 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 we own, but most
existing claims relate to facilities previously owned by our subsidiaries but
currently owned by Texas Genco LLC. We anticipate that additional claims like
those received may be asserted in the future. Under the terms of the separation
agreement between us and Texas Genco, ultimate financial responsibility for
uninsured losses from claims relating to facilities transferred
27
to Texas Genco has been assumed by Texas Genco, but under the terms of our
agreement to sell Texas Genco to Texas Genco LLC, we have agreed to continue to
defend such claims to the extent they are covered by insurance we maintain,
subject to reimbursement of the costs of such defense from Texas Genco LLC.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2. PROPERTIES
CHARACTER OF OWNERSHIP
We own or lease our principal properties in fee, including our corporate
office space and various real property. Most of our electric lines and gas mains
are located, pursuant to easements and other rights, on public roads or on land
owned by others.
ELECTRIC TRANSMISSION & DISTRIBUTION
For information regarding the properties of our Electric Transmission &
Distribution business segment, please read "Our Business -- Electric
Transmission & Distribution -- Properties" in Item 1 of this report, which
information is incorporated herein by reference.
NATURAL GAS DISTRIBUTION
For information regarding the properties of our Natural Gas Distribution
business segment, please read "Our Business -- Natural Gas
Distribution -- Assets" in Item 1 of this report, which information is
incorporated herein by reference.
PIPELINES AND FIELD SERVICES
For information regarding the properties of our Pipelines and Field
Services business segment, please read "Our Business -- Pipelines and Field
Services -- Assets" in Item 1 of this report, which information is incorporated
herein by reference.
OTHER OPERATIONS
For information regarding the properties of our Other Operations business
segment, please read "Our Business -- Other Operations" in Item 1 of this
report, which information is incorporated herein by reference.
ITEM 3. LEGAL PROCEEDINGS
For a discussion of material legal and regulatory proceedings affecting us,
please read "Regulation" and "Environmental Matters" in Item 1 of this report
and Notes 4 and 10(d) to our consolidated financial statements, which
information is incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to the vote of our security holders during
the fourth quarter of 2005.
28
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
As of February 28, 2006, our common stock was held of record by
approximately 54,679 shareholders. Our common stock is listed on the New York
and Chicago Stock Exchanges and is traded under the symbol "CNP."
The following table sets forth the high and low closing prices of the
common stock of CenterPoint Energy on the New York Stock Exchange composite tape
during the periods indicated, as reported by Bloomberg, and the cash dividends
declared in these periods. Cash dividends paid aggregated $0.40 per share in
both 2004 and 2005.
MARKET PRICE DIVIDEND
--------------- DECLARED
HIGH LOW PER SHARE
------ ------ ---------
2004
First Quarter............................................. $0.10
January 2............................................... $ 9.72
March 31................................................ $11.43
Second Quarter............................................ $0.10
April 2................................................. $11.88
May 11.................................................. $10.25
Third Quarter............................................. $0.10
July 20................................................. $12.21
September 24............................................ $10.02
Fourth Quarter............................................ $0.10
October 25.............................................. $10.41
December 15............................................. $11.34
2005(1)
First Quarter............................................. $0.20
January 11.............................................. $10.65
March 8................................................. $12.61
Second Quarter............................................ $0.07
April 20................................................ $11.68
June 30................................................. $13.21
Third Quarter............................................. $0.07
August 8................................................ $13.04
September 16............................................ $15.13
Fourth Quarter............................................ $0.06
October 3............................................... $14.82
October 21.............................................. $12.65
---------------
(1) During 2005, we paid irregular quarterly dividends based on earnings in each
specific quarter in order to comply with requirements under the Public
Utility Holding Company Act of 1935, as amended (1935 Act). The 1935 Act,
with its requirements associated with dividends, has been repealed effective
as of February 8, 2006.
The closing market price of our common stock on December 31, 2005 was
$12.85 per share.
29
The amount of future cash dividends will be subject to determination based
upon our results of operations and financial condition, our future business
prospects, any applicable contractual restrictions and other factors that our
board of directors considers relevant and will be declared at the discretion of
the board of directors.
On January 26, 2006, we announced a regular quarterly cash dividend of
$0.15 per share, payable on March 10, 2006 to shareholders of record on February
16, 2006.
Repurchases of Equity Securities
During the quarter ended December 31, 2005, none of our equity securities
registered pursuant to Section 12 of the Securities Exchange Act of 1934 were
purchased by or on behalf of us or any of our "affiliated purchasers," as
defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial data with respect to our
consolidated financial condition and consolidated results of operations and
should be read in conjunction with our consolidated financial statements and the
related notes in Item 8 of this report.
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2001(1) 2002 2003(2) 2004(3) 2005(4)
------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues........................................ $ 7,148 $ 6,438 $ 7,790 $ 7,999 $ 9,722
------- ------- ------- ------- -------
Income from continuing operations before
extraordinary item and cumulative effect of
accounting change............................. 357 482 409 205 225
Discontinued operations, net of tax............. 565 (4,402) 75 (133) (3)
Extraordinary item, net of tax.................. -- -- -- (977) 30
Cumulative effect of accounting change, net of
tax........................................... 58 -- -- -- --
------- ------- ------- ------- -------
Net income (loss)............................... $ 980 $(3,920) $ 484 $ (905) $ 252
======= ======= ======= ======= =======
Basic earnings (loss) per common share:
Income from continuing operations before
extraordinary item and cumulative effect of
accounting change.......................... $ 1.23 $ 1.62 $ 1.35 $ 0.67 $ 0.72
Discontinued operations, net of tax........... 1.95 (14.78) 0.24 (0.43) (0.01)
Extraordinary item, net of tax................ -- -- -- (3.18) 0.10
Cumulative effect of accounting change, net of
tax........................................ 0.20 -- -- -- --
------- ------- ------- ------- -------
Basic earnings (loss) per common share.......... $ 3.38 $(13.16) $ 1.59 $ (2.94) $ 0.81
======= ======= ======= ======= =======
Diluted earnings (loss) per common share:
Income from continuing operations before
extraordinary item and cumulative effect of
accounting change.......................... $ 1.22 $ 1.61 $ 1.24 $ 0.61 $ 0.67
Discontinued operations, net of tax........... 1.93 (14.69) 0.22 (0.37) (0.01)
Extraordinary item, net of tax................ -- -- -- (2.72) 0.09
Cumulative effect of accounting change, net of
tax........................................ 0.20 -- -- -- --
------- ------- ------- ------- -------
Diluted earnings (loss) per common share........ $ 3.35 $(13.08) $ 1.46 $ (2.48) $ 0.75
======= ======= ======= ======= =======
30
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2001(1) 2002 2003(2) 2004(3) 2005(4)
------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Cash dividends paid per common share............ $ 1.50 $ 1.07 $ 0.40 $ 0.40 $ 0.40
Dividend payout ratio from continuing
operations.................................... 122% 66% 30% 60% 56%
Return from continuing operations on average
common equity................................. 5.8% 11.8% 25.7% 14.4% 18.7%
Ratio of earnings from continuing operations to
fixed charges................................. 1.99 2.03 1.81 1.43 1.51
At year-end:
Book value per common share................... $ 22.77 $ 4.74 $ 5.77 $ 3.59 $ 4.18
Market price per common share................. 26.52 8.01 9.69 11.30 12.85
Market price as a percent of book value....... 116% 169% 168% 315% 307%
Assets of discontinued operations............. $16,840 $ 4,594 $ 4,244 $ 1,565 $ --
Total assets.................................. 32,020 20,635 21,461 18,096 17,116
Short-term borrowings......................... 3,469 347 63 -- --
Transition bonds, including current portion... 749 736 717 676 2,480
Other long-term debt, including current
portion.................................... 3,963 9,260 10,222 8,353 6,427
Trust preferred securities(5)................. 706 706 -- -- --
Capitalization:
Common stock equity........................ 55% 12% 14% 11% 13%
Trust preferred securities................. 6% 6% -- -- --
Long-term debt, including current
portion.................................. 39% 82% 86% 89% 87%
Capital expenditures, excluding discontinued
operations................................. $ 802 $ 566 $ 497 $ 530 $ 719
---------------
(1) 2001 net income includes the cumulative effect of an accounting change
resulting from the adoption of SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ($58 million after-tax gain, or $0.20
earnings per basic and diluted share).
(2) 2003 net income includes the cumulative effect of an accounting change
resulting from the adoption of SFAS No. 143, "Accounting for Asset
Retirement Obligations" ($80 million after-tax gain, or $0.26 and $0.24
earnings per basic and diluted share, respectively), which is included in
discontinued operations related to Texas Genco.
(3) 2004 net income includes an after-tax extraordinary loss of $977 million
($3.18 and $2.72 loss per basic and diluted share, respectively) based on
our analysis of the Texas Utility Commission's order in the 2004 True-Up
Proceeding. Additionally, we recorded a net after-tax loss of approximately
$133 million ($0.43 and $0.37 loss per basic and diluted share,
respectively) in 2004 related to our interest in Texas Genco.
(4) 2005 net income includes an after-tax extraordinary gain of $30 million
($0.10 and $0.09 per basic and diluted share, respectively) recorded in the
first quarter reflecting an adjustment to the extraordinary loss recorded in
the last half of 2004 to write down generation-related regulatory assets as
a result of the final orders issued by the Texas Utility Commission.
(5) The subsidiary trusts that issued trust preferred securities have been
deconsolidated as a result of the adoption of FIN 46 "Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research
Bulletin No. 51" (FIN 46) and the subordinated debentures issued to those
trusts were reported as long-term debt effective December 31, 2003.
31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in combination with
our consolidated financial statements included in Item 8 herein.
OVERVIEW
BACKGROUND
We are a public utility holding company whose indirect wholly owned
subsidiaries include:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
provides electric transmission and distribution services to retail
electric providers serving approximately 1.9 million metered customers in
a 5,000-square-mile area of the Texas Gulf Coast that has a population of
approximately 4.8 million people and includes Houston; and
- CenterPoint Energy Resources Corp. (CERC Corp. and, together with its
subsidiaries, CERC), which owns gas distribution systems serving
approximately 3.1 million customers in Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma and Texas. Through wholly owned subsidiaries, CERC
also 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.
We were a registered public utility holding company under the Public
Utility Holding Company Act of 1935, as amended (the 1935 Act). The 1935 Act and
related rules and regulations imposed a number of restrictions on our activities
and those of our subsidiaries. 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. The FERC continues to consider
motions for rehearing or clarification of these rules.
BUSINESS SEGMENTS
In this section, we discuss our results from continuing operations on a
consolidated basis and individually for each of our business segments. We also
discuss our liquidity, capital resources and critical accounting policies.
CenterPoint Energy is first and foremost an energy delivery company and it is
our intention to remain focused on this segment of the energy business. The
results of our business operations are significantly impacted by weather,
customer growth, cost management, rate proceedings before regulatory agencies
and other actions of the various regulatory agencies to which we are subject.
Our transmission and distribution services are subject to rate regulation and
are reported in the Electric Transmission & Distribution business segment, as
are impacts of generation-related stranded costs and other true-up balances
recoverable by the regulated electric utility. Our natural gas distribution
services are also subject to rate regulation and are reported in the Natural Gas
Distribution business segment. Our reportable business segments include:
Electric Transmission & Distribution
Our electric transmission and distribution operations provide electric
transmission and distribution services to retail electric providers serving
approximately 1.9 million metered customers in a 5,000-square-mile area of the
Texas Gulf coast that has a population of approximately 4.8 million people and
includes Houston.
32
On behalf of retail electric providers, CenterPoint Houston delivers
electricity from power plants to substations and from one substation to another
and to retail electric customers in locations throughout the control area
managed by the Electric Reliability Council of Texas, Inc. (ERCOT). ERCOT serves
as the regional reliability coordinating council for member electric power
systems in Texas. ERCOT membership is open to consumer groups, investor and
municipally owned electric utilities, rural electric cooperatives, independent
generators, power marketers and retail electric providers. The ERCOT market
represents approximately 85% of the demand for power in Texas and is one of the
nation's largest power markets. Transmission services are provided under tariffs
approved by the Public Utility Commission of Texas (Texas Utility Commission).
Operations include construction and maintenance of electric transmission
and distribution facilities, metering services, outage response services and
other call center operations. Distribution services are provided under tariffs
approved by the Texas Utility Commission.
Natural Gas Distribution
CERC owns and operates our regulated natural gas distribution business,
which engages in intrastate natural gas sales to, and natural gas transportation
for, approximately 3.1 million residential, commercial and industrial customers
in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.
Competitive Natural Gas Sales and Services
CERC's operations also include non-rate regulated natural gas sales and
services provided primarily to commercial and industrial customers and electric
and gas utilities throughout the central and eastern United States. We have
reorganized the oversight of our Natural Gas Distribution business segment and,
as a result, beginning in the fourth quarter of 2005, we have established a new
reportable business segment, Competitive Natural Gas Sales and Services. These
operations were previously reported as part of the Natural Gas Distribution
business segment. We have reclassified all prior period segment information to
conform to this new presentation.
Pipelines and Field Services
CERC's pipelines and field services business owns and operates
approximately 8,200 miles of gas transmission lines primarily located in
Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. CERC's pipelines
and field services business also owns and operates six natural gas storage
fields with a combined daily deliverability of approximately 1.2 Bcf per day and
a combined working gas capacity of approximately 59.0 Bcf. Most storage
operations are in north Louisiana and Oklahoma. CERC's pipelines and field
services business also owns and operates approximately 4,000 miles of gathering
pipelines that collect, treat and process natural gas from approximately 200
separate systems located in major producing fields in Arkansas, Louisiana,
Oklahoma and Texas.
Other Operations
Our Other Operations business segment includes office buildings and other
real estate used in our business operations and other corporate operations which
support all of our business operations.
33
EXECUTIVE SUMMARY
SIGNIFICANT EVENTS IN 2005
RECOVERY OF TRUE-UP BALANCE/SECURITIZATION FINANCING
The Texas Electric Choice Plan (Texas electric restructuring law), which
became effective in September 1999, substantially amended the regulatory
structure governing electric utilities in order to allow retail competition for
electric customers beginning in January 2002. The Texas electric restructuring
law requires the Texas Utility Commission to conduct a "true-up" proceeding to
determine CenterPoint Houston's stranded costs and certain other costs resulting
from the transition to a competitive retail electric market and to provide for
its recovery of those costs. In March 2004, CenterPoint Houston filed its
true-up application with the Texas Utility Commission, requesting recovery of
$3.7 billion, excluding interest. In December 2004, the Texas Utility Commission
issued its final order (True-Up Order) allowing CenterPoint Houston to recover a
true-up balance of approximately $2.3 billion, which included interest through
August 31, 2004, and providing for adjustment of the amount to be recovered to
include interest on the balance until recovery, the principal portion of
additional excess mitigation credits returned to customers after August 31, 2004
and certain other matters. CenterPoint Houston and other parties filed appeals
of the True-Up Order to a district court in Travis County, Texas. 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. First, the court reversed the Texas Utility Commission's decision to
prohibit CenterPoint Houston from recovering $180 million in credits through
August 2004 that CenterPoint Houston was ordered to provide to retail electric
providers as a result of an inaccurate stranded cost estimate made by the Texas
Utility Commission in 2000. Additional credits of approximately $30 million were
paid after August 2004. Second, the court reversed the Texas Utility
Commission's disallowance of $440 million in transition costs which are
recoverable under the Texas Utility Commission's regulations. 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.
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 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. During the period from September 13, 2005, the date of implementation
of the CTC Order, through December 31, 2005, CenterPoint Houston recognized
approximately $21 million in CTC operating income. Certain parties appealed the
CTC Order to the Travis County Court in September 2005.
Under the True-Up Order, CenterPoint Houston is allowed to recover carrying
charges at 11.075 percent until the true-up balance is recovered. 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
34
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.
CENTERPOINT HOUSTON RATE CASE
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 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.
CITY OF HOUSTON FRANCHISE
In June 2005, CenterPoint Houston accepted an ordinance granting it a new
30-year franchise to use the public rights-of-way to conduct its business in the
City of Houston (New Franchise Ordinance). The New Franchise Ordinance took
effect on July 1, 2005, and replaced the prior electricity franchise ordinance,
which had been in effect since 1957. The New Franchise Ordinance clarifies
certain operational obligations of CenterPoint Houston and the City of Houston
and provides for streamlined payment and audit procedures and a two-year statute
of limitations on claims for underpayment or overpayment under the ordinance.
Under the prior electricity franchise ordinance, CenterPoint Houston paid annual
franchise fees of $76.6 million to the City of Houston for the year ended
December 31, 2004. For the twelve-month period beginning July 1, 2005, the
annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance
will include a base amount of $88.1 million (Base Amount) and an additional
payment of $8.5 million (Additional Amount). The Base Amount and the Additional
Amount will be adjusted annually based on the increase, if any, in kWh delivered
by CenterPoint Houston within the City of Houston.
CenterPoint Houston began paying the new annual franchise fees on July 1,
2005. Pursuant to the New Franchise Ordinance, the Annual Franchise Fee will be
reduced prospectively to reflect any portion of the Annual Franchise Fee that is
not included in CenterPoint Houston's base rates in any subsequent rate case.
DEBT FINANCING TRANSACTIONS
During the fourth quarter of 2005, CenterPoint Houston retired at maturity
its $1.31 billion term loan, which bore interest at the London inter-bank offer
rate (LIBOR) plus 975 basis points, subject to a minimum LIBOR rate of 3
percent. CenterPoint Houston used its $1.31 billion credit facility bearing
interest at LIBOR plus 75 basis points to retire the term loan. Borrowings under
the credit facility were subsequently repaid with a portion of the proceeds of
the $1.85 billion transition bonds referred to above.
35
In August 2005, we accepted for exchange approximately $572 million
aggregate principal amount of our 3.75% convertible senior notes due 2023 (Old
Notes) for an equal amount of our new 3.75% convertible senior notes due 2023
(New Notes). Old Notes of approximately $3 million remain outstanding. We
commenced the exchange offer in response to the guidance set forth in Emerging
Issues Task Force (EITF) Issue No. 04-8, "Accounting Issues Related to Certain
Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per
Share" (EITF 04-8). Under that guidance, because settlement of the principal
portion of the New Notes will be made in cash rather than stock, the exchange of
New Notes for Old Notes will allow us to exclude the portion of the conversion
value of the New Notes attributable to their principal amount from our
computation of diluted earnings per share from continuing operations.
SALE OF TEXAS GENCO
In July 2004, we announced our agreement to sell our majority-owned
generating 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, whose principal
remaining asset was its ownership interest in a nuclear generating facility,
distributed $2.231 billion in cash to us. The final step of the transaction, the
merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an
additional cash payment to us of $700 million, was completed on April 13, 2005.
The operations of Texas Genco, formerly presented as our Electric Generation
business segment, are presented as discontinued operations.
2005 HIGHLIGHTS
Our operating performance for 2005 compared to 2004 was affected by:
- increased operating income of $55 million in our Pipelines and Field
Services business segment primarily from increased demand for
transportation resulting from basis differentials across the system and
higher demand for ancillary services and increased throughput and demand
for services related to our core gas gathering operations;
- increased operating income of $16 million in our Competitive Natural Gas
Sales and Services business segment primarily from higher sales to
utilities and favorable basis differentials over the pipeline capacity
that we control;
- a decreased operating loss of $14 million in our Other Operations
business segment primarily from increased overhead allocated in 2005;
- continued customer growth, with the addition of 105,000 metered electric
and gas customers;
- a decrease in interest expense of $67 million; and
- a decrease in the return on the true-up balance of $105 million in 2005,
partially offset by an increase in operating income of $21 million
related to the return on the true-up balance being recovered through the
CTC. This decrease is primarily due to the recording of the return on the
true-up balance for 2002 through 2004 in the fourth quarter of 2004.
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
Our past earnings and results of operations are not necessarily indicative
of our future earnings and results of operations. The magnitude of our future
earnings and results of our operations will depend on or be affected by numerous
factors including:
- 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;
36
- 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. (RRI);
- the ability of RRI to satisfy its obligations to us, including indemnity
obligations;
- our ability to control costs;
- the investment performance of our employee benefit plans;
- our potential business strategies, including acquisitions or dispositions
of assets or businesses, which we cannot assure will provide the
anticipated benefits to us; and
- other factors we discuss under "Risk Factors" in Item 1A of this report.
37
CONSOLIDATED RESULTS OF OPERATIONS
All dollar amounts in the tables that follow are in millions, except for
per share amounts.
YEAR ENDED DECEMBER 31,
------------------------
2003 2004 2005
------ ------ ------
Revenues.................................................... $7,790 $7,999 $9,722
Expenses.................................................... 6,435 7,135 8,783
------ ------ ------
Operating Income............................................ 1,355 864 939
Gain (Loss) on Time Warner Investment....................... 106 31 (44)
Gain (Loss) on Indexed Debt Securities...................... (96) (20) 49
Interest and Other Finance Charges.......................... (741) (777) (710)
Return on True-Up Balance................................... -- 226 121
Other Income (Expense), net................................. (10) 20 23
------ ------ ------
Income From Continuing Operations Before Income Taxes and
Extraordinary Item........................................ 614 344 378
Income Tax Expense.......................................... 205 139 153
------ ------ ------
Income From Continuing Operations Before Extraordinary
Item...................................................... 409 205 225
Discontinued Operations, net of tax......................... 75 (133) (3)
------ ------ ------
Income Before Extraordinary Item............................ 484 72 222
Extraordinary Item, net of tax.............................. -- (977) 30
------ ------ ------
Net Income (Loss)......................................... $ 484 $ (905) $ 252
====== ====== ======
Basic Earnings (Loss) Per Share:
Income From Continuing Operations Before Extraordinary
Item...................................................... $ 1.35 $ 0.67 $ 0.72
Discontinued Operations, net of tax......................... 0.24 (0.43) (0.01)
Extraordinary Item, net of tax.............................. -- (3.18) 0.10
------ ------ ------
Net Income (Loss)......................................... $ 1.59 $(2.94) $ 0.81
====== ====== ======
Diluted Earnings (Loss) Per Share:
Income From Continuing Operations Before Extraordinary
Item...................................................... $ 1.24 $ 0.61 $ 0.67
Discontinued Operations, net of tax......................... 0.22 (0.37) (0.01)
Extraordinary Item, net of tax.............................. -- (2.72) 0.09
------ ------ ------
Net Income (Loss)......................................... $ 1.46 $(2.48) $ 0.75
====== ====== ======
2005 COMPARED TO 2004
Income from Continuing Operations. We reported income from continuing
operations before extraordinary item of $225 million ($0.67 per diluted share)
for 2005 as compared to $205 million ($0.61 per diluted share) for 2004. The
increase in income from continuing operations of $20 million was primarily due
to increased operating income of $55 million in our Pipelines and Field Services
business segment resulting from increased demand for transportation resulting
from basis differentials across the system and higher demand for ancillary
services as well as increased throughput and demand for services related to our
core gas gathering operations, increased operating income of $16 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, a decrease in the operating loss of $14 million in our
Other Operations business segment resulting from increased overhead allocated in
2005 and a $67 million decrease in interest expense due to lower borrowing
levels and lower borrowing costs reflecting the replacement of certain of our
credit facilities. The above increases were partially offset by a decrease of
$105 million in the return on the true-up
38
balance of our Electric Transmission & Distribution business segment as a result
of the True-Up Order, partially offset by an increase in operating income of $21
million related to the return on the true-up balance being recovered through the
CTC, and decreased operating income of $29 million in our Electric Transmission
& Distribution business segment, excluding the CTC operating income discussed
above, primarily from increased franchise fees paid to the City of Houston,
increased depreciation expense and higher operation and maintenance expenses,
including higher transmission costs, the absence of a $15 million partial
reversal of a reserve related to the final fuel reconciliation recorded in the
second quarter of 2004 and the absence of an $11 million gain from a land sale
recorded in 2004, partially offset by increased usage mainly due to weather,
continued customer growth and higher transmission cost recovery. Additionally,
income tax expense increased $14 million in 2005 as compared to 2004.
Net income for 2005 included an after-tax extraordinary gain of $30 million
($0.09 per diluted share) recorded in the second quarter reflecting an
adjustment to the after-tax extraordinary loss of $977 million recorded in the
last half of 2004 to write down generation-related regulatory assets as a result
of the final orders issued by the Texas Utility Commission.
Income Tax Expense. In 2005, our effective tax rate was 40.6%. The most
significant items affecting our effective tax rate in 2005 were an addition to
the tax reserve of approximately $42 million relating to the contention of the
Internal Revenue Service (IRS) that the current deductions for original issue
discount (OID) on our 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029
(ZENS) be capitalized, potentially converting what would be ordinary deductions
into capital losses at the time the ZENS are settled, partially offset by
favorable tax audit adjustments of $10 million. Future changes to the reserve
will depend upon a number of variables, including the market price of 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.
2004 COMPARED TO 2003
Income from Continuing Operations. We reported income from continuing
operations before extraordinary loss of $205 million ($0.61 per diluted share)
for 2004 as compared to $409 million ($1.24 per diluted share) for 2003. The
decrease in income from continuing operations of $204 million was primarily due
to the termination of revenues in our Electric Transmission & Distribution
business segment related to ECOM as of January 1, 2004, which had contributed
$430 million of income in 2003, higher net transmission costs of $6 million
related to our Electric Transmission & Distribution business segment and
increased interest expense of $36 million related to continuing operations as
discussed below. These items were partially offset by the absence of an $87
million reserve recorded in 2003 by our Electric Transmission & Distribution
business segment related to the final fuel reconciliation, a $15 million
reversal of this reserve in 2004 and $226 million of the return on the true-up
balance of our Electric Transmission & Distribution business segment. These
items were a result of the Texas Utility Commission's final orders in the final
fuel reconciliation and the 2004 True-Up Proceeding. Additionally, income from
continuing operations was favorably impacted by increased operating income of
$31 million related to customer growth in our Electric Transmission &
Distribution business segment, increased operating income of $21 million in our
Natural Gas Distribution business segment primarily due to rate increases,
increased operating income of $22 million in our Pipelines and Field Services
business segment primarily from increased throughput, favorable commodity prices
and increased ancillary services, and a gain of $11 million on the sale of land
by our Electric Transmission & Distribution business segment.
Net loss for 2004 included an after-tax extraordinary loss of $977 million
($2.72 per diluted share) from a write-down of regulatory assets based on our
analysis of the Texas Utility Commission's final order in the 2004 True-Up
Proceeding. Additionally, net loss for 2004 included a net after-tax loss from
discontinued operations of Texas Genco of $133 million ($0.37 per diluted
share).
Net income for 2003 included the cumulative effect of an accounting change
resulting from the adoption of SFAS No. 143, "Accounting for Asset Retirement
Obligations" ($80 million after-tax gain, or $0.24 earnings per diluted share),
which is included in discontinued operations related to Texas Genco.
39
INTEREST EXPENSE AND OTHER FINANCE CHARGES
In 2003, our $3.85 billion credit facility consisted of a revolver and a
term loan. This facility was amended in October 2003 to a $2.35 billion credit
facility, consisting of a revolver and a term loan. According to the terms of
the $3.85 billion credit facility, any net cash proceeds received from the sale
of Texas Genco were required to be applied to repay borrowings under the credit
facility. According to the terms of the $2.35 billion credit facility, until
such time as the facility had been reduced to $750 million, 100% of any net cash
proceeds received from the sale of Texas Genco were required to be applied to
repay borrowings under the credit facility and reduce the amount available under
the credit facility. In the fourth quarter of 2004, we reduced borrowings under
our credit facility by $1.574 billion and retired $375 million of trust
preferred securities. We expensed $15 million of unamortized loan costs in the
fourth quarter of 2004 that were associated with the credit facility. In
accordance with EITF Issue No. 87-24 "Allocation of Interest to Discontinued
Operations", we have reclassified interest to discontinued operations of Texas
Genco based on net proceeds received from the sale of Texas Genco of $2.5
billion, and have applied the proceeds to the amount of debt assumed to be paid
down in each respective period according to the terms of the respective credit
facilities in effect for those periods. In periods where only the term loan was
assumed to be repaid, the actual interest paid on the term loan was
reclassified. In periods where a portion of the revolver was assumed to be
repaid, the percentage of that portion of the revolver to the total outstanding
balance was calculated, and that percentage was applied to the actual interest
paid in those periods to compute the amount of interest reclassified.
Total interest expense incurred was $942 million, $849 million and $711
million in 2003, 2004 and 2005, respectively. We have reclassified $201 million,
$72 million and $1 million of interest expense in 2003, 2004 and 2005,
respectively, based upon actual interest expense incurred within our
discontinued operations and interest expense associated with debt that would
have been required to be repaid as a result of our disposition of Texas Genco.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
Revenues by segment include intersegment sales, which are eliminated in
consolidation.
The following table presents operating income (in millions) for each of our
business segments for 2003, 2004 and 2005. Some amounts from the previous years
have been reclassified to conform to the 2005 presentation of the financial
statements. These reclassifications do not affect consolidated operating income.
OPERATING INCOME (LOSS) BY BUSINESS SEGMENT
YEAR ENDED DECEMBER 31,
-----------------------
2003 2004 2005
------- ----- -----
(IN MILLIONS)
Electric Transmission & Distribution........................ $1,020 $494 $487
Natural Gas Distribution.................................... 157 178 175
Competitive Natural Gas Sales and Services.................. 45 44 60
Pipelines and Field Services................................ 158 180 235
Other Operations............................................ (25) (32) (18)
------ ---- ----
Total Consolidated Operating Income....................... $1,355 $864 $939
====== ==== ====
40
ELECTRIC TRANSMISSION & DISTRIBUTION
The following tables provide summary data of our Electric Transmission &
Distribution business segment, CenterPoint Houston, for 2003, 2004 and 2005 (in
millions, except throughput and customer data):
YEAR ENDED DECEMBER 31,
---------------------------------
2003 2004 2005
--------- --------- ---------
Revenues:
Electric transmission and distribution utility(1)......... $ 2,061 $ 1,446 $ 1,538
Transition bond companies................................. 63 75 106
--------- --------- ---------
Total revenues......................................... 2,124 1,521 1,644
--------- --------- ---------
Expenses:
Operation and maintenance................................. 635 539 618
Depreciation and amortization............................. 246 248 258
Taxes other than income taxes............................. 198 203 214
Transition bond companies................................. 25 37 67
--------- --------- ---------
Total expenses......................................... 1,104 1,027 1,157
--------- --------- ---------
Operating Income -- Electric transmission and distribution
utility................................................... 982 456 448
Operating Income -- Transition bond companies(2)............ 38 38 39
--------- --------- ---------
Total segment operating income......................... $ 1,020 $ 494 $ 487
========= ========= =========
Throughput (in gigawatt-hours (GWh)):
Residential............................................ 23,687 23,748 24,924
Total.................................................. 70,815 73,632 74,189
Average number of metered customers:
Residential............................................ 1,594,177 1,639,488 1,683,100
Total.................................................. 1,815,142 1,862,853 1,912,346
---------------
(1) In 2003, revenues include $661 million of non-cash ECOM revenues in
accordance with the Texas electric restructuring law. In 2004 and 2005,
there were no ECOM revenues.
(2) Represents the amount necessary to pay interest on the transition bonds.
2005 Compared to 2004. Our Electric Transmission & Distribution business
segment reported operating income of $487 million for 2005, consisting of $448
million for the regulated electric transmission and distribution utility and $39
million for the transition bond company subsidiaries of CenterPoint Houston that
issued $749 million and $1.851 billion principal amount of transition bonds in
2001 and 2005, respectively. For 2004, operating income totaled $494 million,
consisting of $456 million for the regulated electric transmission and
distribution utility and $38 million for the transition bond company. Operating
revenues increased primarily due to increased usage resulting from warmer
weather ($13 million), continued customer growth ($33 million) with the addition
of 61,000 metered customers since December 2004, recovery of our 2004 true-up
balance not covered by the transition bond financing order ($21 million) and
higher transmission cost recovery ($13 million). The increase in operating
revenues was more than offset by higher transmission costs ($24 million), the
absence of a gain from a land sale recorded in 2004 ($11 million), the absence
of a $15 million partial reversal of a reserve related to the final fuel
reconciliation recorded in 2004, increased employee-related expenses ($20
million) and higher tree trimming expense ($6 million), partially offset by a
decrease in pension expense ($14 million). Depreciation and amortization expense
increased ($10 million) primarily as a result of higher plant balances. Taxes
other than income taxes increased ($11 million) primarily due to higher
franchise fees paid to the City of Houston.
In September 2005, CenterPoint Houston's service area in Texas was
adversely affected by Hurricane Rita. Although damage to CenterPoint Houston's
electric facilities was limited, over 700,000 customers lost
41
power at the height of the storm. Power was restored to over a half million
customers within 36 hours and all power was restored in less than five days. The
Electric Transmission & Distribution business segment's revenues lost as a
result of the storm were more than offset by warmer than normal weather during
the third quarter. CenterPoint Houston has deferred $28 million of restoration
costs for recovery in a future rate case and has capitalized an additional $8
million of costs as property, plant and equipment.
2004 Compared to 2003. Our Electric Transmission & Distribution business
segment reported operating income of $494 million for 2004, consisting of $456
million for the regulated electric transmission and distribution utility and $38
million for the transition bond company. For 2003, operating income totaled $1.0
billion, consisting of $321 million for the regulated electric transmission and
distribution utility, $38 million for the transition bond company and $661
million of non-cash income associated with ECOM. Operating income increased $31
million from continued customer growth and a $11 million gain on a land sale,
partially offset by milder weather and decreased usage of $18 million and higher
net transmission costs of $6 million. Additionally, operating income in 2004 was
favorably impacted by the absence of $87 million reserve recorded in 2003
related to the final fuel reconciliation and a $15 million partial reversal of
this fuel reserve in 2004 as a result of the Texas Utility Commission's final
orders in the final fuel reconciliation.
NATURAL GAS DISTRIBUTION
The following table provides summary data of our Natural Gas Distribution
business segment for 2003, 2004 and 2005 (in millions, except throughput and
customer data):
YEAR ENDED DECEMBER 31,
---------------------------------
2003 2004 2005
--------- --------- ---------
Revenues............................................ $ 3,389 $ 3,579 $ 3,846
--------- --------- ---------
Expenses:
Natural gas....................................... 2,450 2,596 2,841
Operation and maintenance......................... 540 544 551
Depreciation and amortization..................... 135 141 152
Taxes other than income taxes..................... 107 120 127
--------- --------- ---------
Total expenses................................. 3,232 3,401 3,671
--------- --------- ---------
Operating Income.................................... $ 157 $ 178 $ 175
========= ========= =========
Throughput (in billion cubic feet (Bcf)):
Residential....................................... 183 175 160
Commercial and industrial......................... 238 237 215
--------- --------- ---------
Total Throughput............................... 421 412 375
========= ========= =========
Average number of customers:
Residential.................................... 2,755,200 2,798,210 2,838,357
Commercial and industrial...................... 245,081 246,068 246,372
--------- --------- ---------
Total.......................................... 3,000,281 3,044,278 3,084,729
========= ========= =========
2005 Compared to 2004. Our Natural Gas Distribution business segment
reported operating income of $175 million for 2005 as compared to $178 million
for 2004. Increases in operating margins (revenues less natural gas costs) from
rate increases ($19 million) and margin from gas exchanges ($7 million) were
partially offset by the impact of milder weather and decreased throughput net of
continued customer growth with the addition of approximately 44,000 customers
since December 2004 ($13 million). Operation and maintenance expense increased
$7 million. Excluding an $8 million charge recorded in 2004 for severance costs
associated with staff reductions, operation and maintenance expenses increased
by $15 million primarily due to increased litigation reserves ($11 million) and
increased bad debt expense ($9 million), partially offset by the capitalization
of previously incurred restructuring expenses as allowed by a regulatory order
from the
42
Railroad Commission of Texas ($5 million). Additionally, operating income was
unfavorably impacted by increased depreciation expense primarily due to higher
plant balances ($11 million).
During the third quarter of 2005, our east Texas, Louisiana and Mississippi
natural gas service areas were affected by Hurricanes Katrina and Rita. Damage
to our facilities was limited, but approximately 10,000 homes and businesses
were damaged to such an extent that they will not be taking service for the
foreseeable future. The impact on the Natural Gas Distribution business
segment's operating income was not material.
2004 Compared to 2003. Our Natural Gas Distribution business segment
reported operating income of $178 million for 2004 as compared to $157 million
for 2003. Increases in operating income of $4 million from continued customer
growth with the addition of 45,000 customers since December 31, 2003, $15
million from rate increases, $11 million from the impact of the 2003 change in
estimate of margins earned on unbilled revenues implemented in 2003 and $9
million related to certain regulatory adjustments made to the amount of
recoverable gas costs in 2003 were partially offset by the $8 million impact of
milder weather. Operations and maintenance expense increased $4 million for 2004
as compared to 2003. Excluding an $8 million charge recorded in the first
quarter of 2004 for severance costs associated with staff reductions, which has
reduced costs in later periods, operation and maintenance expenses decreased by
$4 million.
COMPETITIVE NATURAL GAS SALES AND SERVICES
The following table provides summary data of our Competitive Natural Gas
Sales and Services business segment for 2003, 2004 and 2005 (in millions, except
throughput and customer data):
YEAR ENDED DECEMBER 31,
------------------------
2003 2004 2005
------ ------ ------
Revenues................................................... $2,232 $2,848 $4,129
------ ------ ------
Expenses:
Natural gas.............................................. 2,164 2,778 4,033
Operation and maintenance................................ 20 22 30
Depreciation and amortization............................ 1 2 2
Taxes other than income taxes............................ 2 2 4
------ ------ ------
Total expenses........................................ 2,187 2,804 4,069
------ ------ ------
Operating Income........................................... $ 45 $ 44 $ 60
====== ====== ======
Throughput (in Bcf):
Wholesale -- third parties............................... 195 228 304
Wholesale -- affiliates.................................. 21 35 27
Retail................................................... 140 141 156
Pipeline................................................. 80 76 51
------ ------ ------
Total Throughput...................................... 436 480 538
====== ====== ======
Average number of customers:
Wholesale................................................ 73 97 138
Retail................................................... 5,242 5,976 6,328
Pipeline................................................. 188 172 142
------ ------ ------
Total................................................. 5,503 6,245 6,608
====== ====== ======
2005 Compared to 2004. Our Competitive Natural Gas Sales and Services
business segment reported operating income of $60 million for 2005 as compared
to $44 million for 2004. The increase in operating income of $16 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
43
($32 million) less the impact of certain derivative transactions ($6 million),
partially offset by higher payroll and benefit related expenses ($4 million) and
increased bad debt expense ($3 million).
2004 Compared to 2003. Our Competitive Natural Gas Sales and Services
business segment reported operating income of $44 million for 2004 as compared
to $45 million for 2003. The decrease in operating income was primarily due to
increased payroll and benefit-related expenses ($3 million), increased factoring
expenses ($1 million) and increased franchise taxes ($1 million), partially
offset by increased operating margins related to increased volatility and growth
($2 million) and a decrease in bad debt expense ($2 million).
PIPELINES AND FIELD SERVICES
The following table provides summary data of our Pipelines and Field
Services business segment for 2003, 2004 and 2005 (in millions, except
throughput data):
YEAR ENDED DECEMBER 31,
------------------------
2003 2004 2005
------ ------ ------
Revenues................................................... $ 407 $ 451 $ 493
------ ------ ------
Expenses:
Natural gas.............................................. 61 46 30
Operation and maintenance................................ 129 164 164
Depreciation and amortization............................ 40 44 45
Taxes other than income taxes............................ 19 17 19
------ ------ ------
Total expenses........................................ 249 271 258
------ ------ ------
Operating Income........................................... $ 158 $ 180 $ 235
====== ====== ======
Throughput (in Bcf):
Natural gas sales........................................ 9 11 6
Transportation........................................... 794 859 914
Gathering................................................ 292 321 353
Elimination(1)........................................... (4) (7) (4)
------ ------ ------
Total Throughput...................................... 1,091 1,184 1,269
====== ====== ======
---------------
(1) Elimination of volumes both transported and sold.
2005 Compared to 2004. Our Pipelines and Field Services business segment
reported operating income of $235 million for 2005 compared to $180 million for
2004. Operating income for the pipeline business for 2005 was $165 million
compared to $129 million in 2004. The field services business recorded operating
income of $70 million for 2005 compared to $51 million in 2004. Operating
margins (revenues less natural gas costs) increased by $58 million primarily due
to increased demand for transportation resulting from basis differentials across
the system and higher demand for ancillary services ($43 million), increased
throughput and demand for services related to our core gas gathering operations
($29 million), partially offset by reductions in project-related revenues ($11
million). Additionally, operation and maintenance expenses remained flat
primarily due to a reduction in project-related expenses ($9 million), offset by
increases in materials and supplies and contracts and services ($8 million).
2004 Compared to 2003. Our Pipelines and Field Services business segment's
operating income increased by $22 million in 2004 compared to 2003. Operating
margins (revenues less fuel costs) increased by $59 million primarily due to
favorable commodity pricing ($3 million), increased demand for certain
transportation services driven by commodity price volatility ($36 million) and
increased throughput and enhanced services related to our core gas gathering
operations ($11 million). The increase in operating margin was partially offset
by higher operation and maintenance expenses of $35 million primarily due to
compliance
44
with pipeline integrity regulations ($4 million) and costs relating to
environmental matters ($9 million). Project work expenses included in operation
and maintenance expense increased ($11 million) resulting in a corresponding
increase in revenues billed for these services ($15 million).
Additionally, included in other income in 2003, 2004 and 2005 is equity
income of $-0-, $2 million and $6 million, respectively, related to a joint
venture owned by our field services business.
OTHER OPERATIONS
The following table provides summary data for our Other Operations business
segment for 2003, 2004 and 2005 (in millions):
YEAR ENDED DECEMBER 31,
------------------------
2003 2004 2005
------ ------ ------
Revenues.................................................... $ 28 $ 8 $ 19
Expenses.................................................... 53 40 37
---- ---- ----
Operating Loss.............................................. $(25) $(32) $(18)
==== ==== ====
2005 Compared to 2004. Our Other Operations business segment's operating
loss in 2005 compared to 2004 decreased $14 million primarily due to increased
overhead allocated in 2005.
2004 Compared to 2003. Our Other Operations business segment's operating
loss in 2004 compared to 2003 increased $7 million primarily due to a reduction
in rental income from Reliant Energy, Inc. (RRI) in 2004 as compared to 2003,
partially offset by changes in unallocated corporate costs in 2004 as compared
to 2003.
DISCONTINUED OPERATIONS
In February 2003, we sold our interest in Argener, a cogeneration facility
in Argentina, for $23 million. The carrying value of this investment was
approximately $11 million as of December 31, 2002. We recorded an after-tax gain
of $7 million from the sale of Argener in the first quarter of 2003. In April
2003, we sold our final remaining investment in Argentina, a 90 percent interest
in Empresa Distribuidora de Electricidad de Santiago del Estero S.A. We recorded
an after-tax loss of $3 million in the second quarter of 2003 related to our
Latin America operations. We have completed our strategy of exiting all of our
international investments.
In November 2003, we sold CenterPoint Energy Management Services, Inc.
(CEMS), a business that provides district cooling services in the Houston
central business district and related complementary energy services to district
cooling customers and others. We recorded an after-tax loss of $1 million from
the sale of CEMS in the fourth quarter of 2003. We recorded an after-tax loss in
discontinued operations of $16 million ($25 million pre-tax) during the second
quarter of 2003 to record the impairment of the CEMS long-lived assets based on
the impending sale and to record one-time employee termination benefits.
In July 2004, we announced our agreement to sell our majority owned
subsidiary, Texas Genco, to Texas Genco LLC. On December 15, 2004, Texas Genco
completed the sale of its fossil generation assets (coal, lignite and gas-fired
plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas
Genco, whose principal remaining asset was its ownership interest in a nuclear
generating facility, distributed $2.231 billion in cash to us. The final step of
the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC
in exchange for an additional cash payment to us of $700 million, was completed
on April 13, 2005. We recorded an after-tax gain (loss) of $91 million, $(133)
million and $(3) million for the years ended December 31, 2003, 2004 and 2005,
respectively, related to the operations of Texas Genco.
The consolidated financial statements report the businesses described above
as discontinued operations for all periods presented in accordance with
Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).
For further information regarding discontinued operations, please read Note
3 to our consolidated financial statements.
45
LIQUIDITY AND CAPITAL RESOURCES
HISTORICAL CASH FLOW
The net cash provided by/used in operating, investing and financing
activities for 2003, 2004 and 2005 is as follows (in millions):
YEAR ENDED DECEMBER 31,
-----------------------
2003 2004 2005
----- ------- -----
Cash provided by (used in):
Operating activities..................................... $ 894 $ 736 $ 63
Investing activities..................................... (661) 1,466 17
Financing activities..................................... (450) (2,124) (171)
CASH PROVIDED BY OPERATING ACTIVITIES
Net cash provided by operating activities in 2005 decreased $673 million
compared to 2004 primarily due to increased tax payments of $475 million, the
majority of which related to the tax payment in the second quarter of 2005
associated with the sale of Texas Genco, decreased cash provided by Texas Genco
of $393 million, increased net accounts receivable/payable ($151 million),
increased gas storage inventory ($105 million) and increased fuel under-recovery
($154 million), primarily due to higher gas prices in 2005 as compared to 2004.
These decreases were partially offset by decreases in net regulatory
assets/liabilities ($328 million), primarily due to the termination of excess
mitigation credits effective April 29, 2005, and decreased pension contributions
of $401 million in 2005 as compared to 2004.
Net cash provided by operating activities in 2004 decreased $158 million
compared to 2003 primarily due to increased pension contributions of $453
million and decreased income tax refunds of $74 million, partially offset by the
receipt of a $177 million retail clawback payment from RRI in the fourth quarter
of 2004, decreased accounts receivable attributable to a higher level of
accounts receivable being sold under CERC Corp.'s receivables facility ($81
million) and increased cash provided by Texas Genco's operations ($110 million).
Additionally, other changes in working capital items, primarily increased net
accounts receivable and accounts payable due to higher natural gas prices in
December 2004 as compared to December 2003 ($99 million), contributed to the
overall decrease in cash provided by operating activities.
CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES
Net cash provided by investing activities decreased $1.4 billion in 2005 as
compared to 2004 primarily due to proceeds of $700 million received from the
sale of our remaining interest in Texas Genco in April 2005 compared to proceeds
of $2.947 billion received in 2004 from the sale of Texas Genco's fossil
generation assets and increased capital expenditures of $89 million, partially
offset by the purchase of the minority interest in Texas Genco in 2004 of $716
million and cash collateralization of letters of credit by Texas Genco in 2004
related to its anticipated purchase of an additional interest in the South Texas
Project in the first half of 2005 of $191 million.
Net cash provided by investing activities increased $2.1 billion in 2004 as
compared to 2003 primarily due to proceeds of $2.947 billion received from the
sale of Texas Genco's fossil generation assets in December 2004, offset by the
purchase of the minority interest in Texas Genco in December 2004 ($716 million)
and cash collateralization of letters of credit by Texas Genco related to its
anticipated purchase of an additional interest in the South Texas Project in the
first half of 2005 ($191 million).
CASH USED IN FINANCING ACTIVITIES
In 2005, debt payments exceeded net loan proceeds by $66 million. Proceeds
from the December 2005 issuance of $1.85 billion in transition bonds were used
to repay borrowings under our credit facility and CenterPoint Houston's $1.3
billion term loan.
46
In 2004, debt payments exceeded net loan proceeds by $2.0 billion. Proceeds
received from the sale of Texas Genco's fossil generation assets in December
2004 and the retail clawback payment from RRI as discussed above were used to
retire a $915 million term loan, pay down $944 million in borrowings under our
revolving credit facility and retire $375 million of trust preferred securities.
As of December 31, 2004, we had borrowings of $239 million under our revolving
credit facility which were used to fund a portion of the $420 million pension
contribution made in December 2004.
FUTURE SOURCES AND USES OF CASH
Our liquidity and capital requirements are affected primarily by our
results of operations, capital expenditures, debt service requirements, tax
payments, working capital needs, various regulatory actions and appeals relating
to such regulatory actions. Our principal cash requirements for 2006 include the
following:
- approximately $1 billion of capital expenditures, including the
construction of a new pipeline by our Pipelines and Field Services
business segment ($343 million) and transmission project by our Electric
Transmission & Distribution business segment ($60 million);
- dividend payments on CenterPoint Energy common stock and debt service
payments; and
- long-term debt payments of $224 million, including $73 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.
The following table sets forth our capital expenditures for 2005 excluding
capital expenditures of $9 million related to discontinued operations, and
estimates of our capital requirements for 2006 through 2010 (in millions):
2005 2006 2007 2008 2009 2010
---- ------ ---- ---- ---- ----
Electric Transmission & Distribution............. $281 $ 336 $361 $333 $304 $301
Natural Gas Distribution......................... 249 191 253 264 251 218
Competitive Natural Gas Sales and Services....... 12 10 2 1 1 1
Pipelines and Field Services..................... 156 467 257 118 110 65
Other Operations................................. 21 20 28 19 11 9
---- ------ ---- ---- ---- ----
Total.......................................... $719 $1,024 $901 $735 $677 $594
==== ====== ==== ==== ==== ====
The following table sets forth estimates of our contractual obligations,
including payments due by period (in millions):
2011 AND
CONTRACTUAL OBLIGATIONS TOTAL 2006 2007-2008 2009-2010 THEREAFTER
----------------------- ------- ------ --------- --------- ----------
Transition bond debt, including current
portion(1)................................. $ 2,480 $ 73 $ 306 $ 365 $ 1,736
Other long-term debt, including current
portion.................................... 6,423 263 513 216 5,431
Interest payments -- transition bond
debt(1)(2)................................. 960 92 239 207 422
Interest payments -- other long-term
debt(2).................................... 4,861 408 774 724 2,955
Capital leases............................... 4 3 -- -- 1
Operating leases(3).......................... 85 20 32 11 22
Benefit obligations(4)....................... -- -- -- -- --
Purchase obligations(5)...................... 109 109 -- -- --
Non-trading derivative liabilities........... 78 43 20 12 3
Other commodity commitments(6)............... 1,316 858 428 7 23
------- ------ ------ ------ -------
Total contractual cash obligations......... $16,316 $1,869 $2,312 $1,542 $10,593
======= ====== ====== ====== =======
47
---------------
(1) Transition charges are adjusted at least annually to cover debt service on
transition bonds.
(2) We calculated estimated interest payments for long-term debt as follows: for
fixed-rate debt and term debt, we calculated interest based on the
applicable rates and payment dates; for variable-rate debt and/or non-term
debt, we used interest rates in place as of December 31, 2005; we typically
expect to settle such interest payments with cash flows from operations and
short-term borrowings.
(3) For a discussion of operating leases, please read Note 10(b) to our
consolidated financial statements.
(4) Contributions to the pension plan are not required in 2006; however, we
expect to contribute approximately $26 million to our postretirement
benefits plan in 2006 to fund a portion of our obligations in accordance
with rate orders or to fund pay-as-you-go costs associated with the plan.
(5) Represents capital commitments for material in connection with the
construction of a new pipeline by our Pipelines and Field Services business
segment. This project has been included in the table of capital expenditures
presented above.
(6) For a discussion of other commodity commitments, please read Note 10(a) to
our consolidated financial statements.
Off-Balance Sheet Arrangements. Other than operating leases, we have no
off-balance sheet arrangements. However, we do participate in a receivables
factoring arrangement. CERC Corp. has a bankruptcy remote subsidiary, which we
consolidate, which was formed for the sole purpose of buying receivables created
by CERC and selling those receivables to an unrelated third-party. This
transaction is accounted for as a sale of receivables under the provisions of
SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities," and, as a result, the related receivables are
excluded from the Consolidated Balance Sheet. In January 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 December 31,
2005, CERC had $141 million of advances under its receivables facility.
Prior to CenterPoint Energy's distribution of its ownership in RRI to its
shareholders, CERC had guaranteed certain contractual obligations of what became
RRI's trading subsidiary. Under the terms of the separation agreement between
the companies, RRI agreed to extinguish all such guarantee obligations prior to
separation, but when separation occurred in September 2002, RRI had been unable
to extinguish all obligations. To secure CenterPoint Energy and CERC against
obligations under the remaining guarantees, RRI agreed to provide cash or
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
alternatives. RRI continues to meet its obligations under the transportation
contracts.
Credit Facilities. In June 2005, CERC Corp. replaced its $250 million
three-year revolving credit facility with a $400 million five-year revolving
credit facility. Borrowings under this facility may be made at LIBOR plus 55
basis points, including the facility fee, based on current credit ratings. An
additional utilization fee of 10 basis points applies to borrowings whenever
more than 50% of the facility is utilized. Changes in credit ratings could lower
or raise the increment to LIBOR depending on whether ratings improved or were
lowered. CERC Corp.'s $400 million credit facility contains covenants, including
a total debt to capitalization covenant of 65% and an earnings before interest,
taxes, depreciation and amortization (EBITDA) to interest covenant. Borrowings
under CERC Corp.'s $400 million credit facility are available notwithstanding
that a material adverse change has occurred or litigation that could be expected
to have a material adverse effect has occurred, so long as other customary terms
and conditions are satisfied.
48
In March 2005, we replaced our $750 million revolving credit facility with
a $1 billion five-year revolving credit facility. Borrowings may be made under
the facility at LIBOR plus 87.5 basis points based on current credit ratings. An
additional utilization fee of 12.5 basis points applies to borrowings whenever
more than 50% of the facility is utilized. Changes in credit ratings could lower
or raise the increment to LIBOR depending on whether ratings improved or were
lowered. The facility contains covenants, including a debt to EBITDA covenant
and an EBITDA to interest covenant.
Borrowings under our credit facility are available upon customary terms and
conditions for facilities of this type, including a requirement that we
represent, except as described below, that no "material adverse change" has
occurred at the time of a new borrowing under this facility. A "material adverse
change" is defined as the occurrence of a material adverse change in our ability
to perform our obligations under the facility but excludes any litigation
related to the True-Up Order. The base line for any determination of a relative
material adverse change is our most recently audited financial statements. At
any time after the first time our credit ratings reach at least BBB by Standard
& Poor's Ratings Services, a division of The McGraw Hill Companies (S&P), and
Baa2 by Moody's Investors Service, Inc. (Moody's), BBB+ by S&P and Baa3 by
Moody's, or BBB- by S&P and Baa1 by Moody's, or if the drawing is to retire
maturing commercial paper, we are not required to represent as a condition to
such drawing that no material adverse change has occurred or that no litigation
expected to have a material adverse effect has occurred.
Also in March 2005, CenterPoint Houston established a $200 million
five-year revolving credit facility. Borrowings may be made under the facility
at LIBOR plus 75 basis points based on CenterPoint Houston's current credit
ratings. An additional utilization fee of 12.5 basis points applies to
borrowings whenever more than 50% of the facility is utilized. Changes in credit
ratings could lower or raise the increment to LIBOR depending on whether ratings
improved or were lowered. CenterPoint Houston's $200 million credit facility
contains covenants, including a debt (excluding transition bonds) to total
capitalization covenant of 68% and an EBITDA to interest covenant. Borrowings
under CenterPoint Houston's $200 million credit facility are available
notwithstanding that a material adverse change has occurred or litigation that
could be expected to have a material adverse effect has occurred, so long as
other customary terms and conditions are satisfied.
We, CenterPoint Houston and CERC Corp. are currently in compliance with the
various business and financial covenants contained in the respective credit
facilities.
As of February 28, 2006, we had the following credit facilities (in
millions):
AMOUNT UTILIZED AT
DATE EXECUTED COMPANY SIZE OF FACILITY FEBRUARY 28, 2006 TERMINATION DATE
------------- ------- ---------------- ------------------ ----------------
March 7, 2005 CenterPoint Energy $1,000 $96(1) March 7, 2010
March 7, 2005 CenterPoint Houston 200 4(2) March 7, 2010
June 30, 2005 CERC Corp. 400 -- June 30, 2010
---------------
(1) Includes $28 million of outstanding letters of credit and $68 million of
commercial paper backstopped by the credit facility.
(2) Represents $4 million of outstanding letters of credit.
The $1 billion CenterPoint Energy credit facility backstops a $1 billion
commercial paper program under which CenterPoint Energy began issuing commercial
paper in June 2005. As of December 31, 2005, $3 million of commercial paper was
outstanding. The commercial paper is rated "Not Prime" by Moody's, "A-3" by S&P
and "F3" by Fitch, Inc. (Fitch) 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
49
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.
During the fourth quarter of 2005, CenterPoint Houston retired at maturity
its $1.31 billion term loan, which bore interest at LIBOR plus 975 basis points,
subject to a minimum LIBOR rate of 3 percent. It used its $1.31 billion credit
facility bearing interest at LIBOR plus 75 basis points to retire the term loan.
All amounts borrowed under the credit facility were repaid with a portion of the
proceeds of the $1.85 billion transition bonds referred to above.
Securities Registered with the SEC. At December 31, 2005, CenterPoint
Energy had a shelf registration statement covering senior debt securities,
preferred stock and common stock aggregating $1 billion and CERC Corp. had a
shelf registration statement covering $500 million principal amount of debt
securities.
Temporary Investments. On December 31, 2005, we had no temporary
investments.
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 February 28,
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 Debt............. Baa3 Stable BBB Stable BBB Stable
---------------
(1) A "stable" outlook from Moody's indicates that Moody's does not expect to
put the rating on review for an upgrade or downgrade within 18 months from
when the outlook was assigned or last affirmed.
(2) An S&P rating outlook assesses the potential direction of a long-term credit
rating over the intermediate to longer term.
(3) A "stable" outlook from Fitch encompasses a one-to-two-year horizon as to
the likely ratings direction.
A decline in credit ratings could increase borrowing costs under our $1
billion credit facility, CenterPoint Houston's $200 million credit facility and
CERC's $400 million revolving credit facility. A decline in credit ratings would
also increase the interest rate on long-term debt to be issued in the capital
markets and 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.
As described above under "-- Credit Facilities," our revolving credit
facility contains a "material adverse change" clause that could impact our
ability to make new borrowings under this facility. CenterPoint Houston's $200
million credit facility and CERC Corp.'s $400 million credit facility do not
contain material adverse change clauses with respect to borrowings.
In September 1999, we issued 2.0% Zero-Premium Exchangeable Subordinated
Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. Each
ZENS note is exchangeable at the holder's option at any time for an amount of
cash equal to 95% of the market value of the reference shares of Time Warner
Inc. (TW Common) attributable to each ZENS note. If our creditworthiness were to
drop such that ZENS note holders thought our liquidity was adversely affected or
the market for the ZENS notes were to become illiquid, some ZENS note holders
might decide to exchange their ZENS notes for cash. Funds for the payment of
cash upon exchange could be obtained from the sale of the shares of TW Common
that we own or
50
from other sources. We own shares of TW Common equal to 100% of the reference
shares used to calculate our obligation to the holders of the ZENS notes. ZENS
note exchanges result in a cash outflow because deferred tax liabilities related
to the ZENS notes and TW Common shares become current tax obligations when ZENS
notes are exchanged and TW Common shares are sold.
CES, a wholly owned subsidiary of CERC Corp. 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 December 31, 2005, unsecured credit limits extended to CES by
counterparties aggregate $128 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 February
28, 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;
- the ability of RRI and its subsidiaries to satisfy their obligations as
the principal customers of CenterPoint Houston and in respect of RRI's
indemnity obligations to us and our subsidiaries;
- slower customer payments and increased write-offs of receivables due to
higher gas prices;
- cash payments in connection with the exercise of contingent conversion
rights of holders of convertible debt;
- contributions to benefit plans;
- restoration costs and revenue losses resulting from natural disasters
such as hurricanes; and
- various other risks identified in "Risk Factors" in Item 1A of this
report.
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 transi-
51
tion bonds, as a percentage of its total capitalization to 68 percent.
CenterPoint Houston's $200 million credit facility also contains an EBITDA to
interest covenant. CERC Corp.'s bank facility and its receivables facility limit
CERC's debt as a percentage of its total capitalization to 65 percent and
contain an EBITDA to interest covenant. Our $1 billion credit facility contains
a debt to EBITDA covenant and an EBITDA to interest 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 1935 Act. The
1935 Act and related rules and regulations imposed a number of restrictions on
our activities and those of our subsidiaries. The 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 PUHCA 2005 which grants to the 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. The FERC continues to consider motions for rehearing or clarification
of these rules.
CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one that is both important to the
presentation of our financial condition and results of operations and requires
management to make difficult, subjective or complex accounting estimates. An
accounting estimate is an approximation made by management of a financial
statement element, item or account in the financial statements. Accounting
estimates in our historical consolidated financial statements measure the
effects of past business transactions or events, or the present status of an
asset or liability. The accounting estimates described below require us to make
assumptions about matters that are highly uncertain at the time the estimate is
made. Additionally, different estimates that we could have used or changes in an
accounting estimate that are reasonably likely to occur could have a material
impact on the presentation of our financial condition or results of operations.
The circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be predicted with certainty. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes. Our significant accounting policies are discussed in Note 2 to our
consolidated financial statements. We believe the following accounting policies
involve the application of critical accounting estimates. Accordingly, these
accounting estimates have been reviewed and discussed with the audit committee
of the board of directors.
ACCOUNTING FOR RATE REGULATION
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS No. 71), provides that rate-regulated entities account for and report
assets and liabilities consistent with the recovery of those incurred costs in
rates if the rates established are designed to recover the costs of providing
the regulated service and if the competitive environment makes it probable that
such rates can be charged and collected. Application of SFAS No. 71 to the
electric generation portion of our business was discontinued as of June 30,
1999. Our Electric Transmission & Distribution business continues to apply SFAS
No. 71 which results in our accounting for the regulatory effects of recovery of
stranded costs and other regulatory assets resulting from the unbundling of the
transmission and distribution business from our electric generation operations
in our consolidated financial statements. Certain expenses and revenues subject
to utility regulation or rate determination normally reflected in income are
deferred on the balance sheet and are recognized in income as the related
amounts are included in service rates and recovered from or refunded to
customers. Significant accounting estimates embedded within the application of
SFAS No. 71 with respect to our Electric Transmission & Distribution business
segment relate to $332 million of recoverable electric generation-related
52
regulatory assets as of December 31, 2005. These costs are recoverable under the
provisions of the Texas electric restructuring law. Based on our analysis of the
True-Up Order, we recorded an after-tax charge to earnings in 2004 of
approximately $977 million to write-down our electric generation-related
regulatory assets to their realizable value, which was reflected as an
extraordinary loss. Based on subsequent orders received from the Texas Utility
Commission, we recorded an extraordinary gain of $30 million after-tax in the
second quarter of 2005 related to the regulatory asset. 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 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"
(SFAS No. 142). Unforeseen events and changes in circumstances and market
conditions and material differences in the value of long-lived assets and
intangibles due to changes in estimates of future cash flows, regulatory matters
and operating costs could negatively affect the fair value of our assets and
result in an impairment charge.
Fair value is the amount at which the asset could be bought or sold in a
current transaction between willing parties and may be estimated using a number
of techniques, including quoted market prices or valuations by third parties,
present value techniques based on estimates of cash flows, or multiples of
earnings or revenue performance measures. The fair value of the asset could be
different using different estimates and assumptions in these valuation
techniques.
We perform our goodwill impairment test at least annually and evaluate
goodwill when events or changes in circumstances indicate that the carrying
value of these assets may not be recoverable. Upon adoption of SFAS No. 142, we
initially selected January 1 as our annual goodwill impairment testing date.
Since the time we selected the January 1 date, our year-end closing and
reporting process has been truncated in order to meet the accelerated periodic
reporting requirements of the SEC, resulting in significant constraints on our
human resources at year-end and during our first fiscal quarter. Accordingly, in
order to meet the accelerated reporting deadlines and to provide adequate time
to complete the analysis each year, beginning in the third quarter of 2005, we
changed the date on which we perform our annual goodwill impairment test from
January 1 to July 1. We believe the July 1 alternative date will alleviate the
resource constraints that exist during the first quarter and allow us to utilize
additional resources in conducting the annual impairment evaluation of goodwill.
We performed the test at July 1, 2005, and determined that no impairment charge
for goodwill was required. The change is not intended to delay, accelerate or
avoid an impairment charge. We believe that this accounting change is an
alternative accounting principle that is preferable under the circumstances.
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.
53
We estimate the fair value of asset retirement obligations by calculating
the discounted cash flows that are dependent upon the following components:
- Inflation adjustment -- The estimated cash flows are adjusted for
inflation estimates for labor, equipment, materials, and other disposal
costs;
- Discount rate -- The estimated cash flows include contingency factors
that were used as a proxy for the market risk premium; and
- Third party markup adjustments -- Internal labor costs included in the
cash flow calculation were adjusted for costs that a third party would
incur in performing the tasks necessary to retire the asset.
Changes in these factors could materially affect the obligation recorded to
reflect the ultimate cost associated with retiring the assets under SFAS No. 143
and FIN 47. For example, if the inflation adjustment increased 25 basis points,
this would increase the balance for asset retirement obligations by
approximately 3.0%. Similarly, an increase in the discount rate by 25 basis
points would decrease asset retirement obligations by approximately the same
percentage. At December 31, 2005, 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.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 2(n) to the consolidated financial statements for a discussion of
new accounting pronouncements that affect us.
OTHER SIGNIFICANT MATTERS
Pension Plan. As discussed in Note 2(o) to our consolidated financial
statements, we maintain a non-contributory pension plan covering substantially
all employees. Employer contributions are based on actuarial computations that
establish the minimum contribution required under the Employee Retirement Income
Security Act of 1974 (ERISA) and the maximum deductible contribution for income
tax purposes. At December 31, 2005, the projected benefit obligation exceeded
the market value of plan assets by $20 million;
54
however, the market value of the plan assets exceeded the accumulated benefit
obligation by $41 million. Changes in interest rates and the market values of
the securities held by the plan during 2006 could materially, positively or
negatively, change our funded status and affect the level of pension expense and
required contributions in 2007 and beyond.
Although we have not been required to make contributions to our pension
plan in 2004 or 2005, we have made voluntary contributions of $476 million and
$75 million in 2004 and 2005, respectively.
Under the terms of our pension plan, we reserve the right to change, modify
or terminate the plan. Our funding policy is to review amounts annually and
contribute an amount at least equal to the minimum contribution required under
ERISA and the Internal Revenue Code.
In accordance with SFAS No. 87, "Employers' Accounting for Pensions,"
changes in pension obligations and assets may not be immediately recognized as
pension costs in the income statement, but generally are recognized in future
years over the remaining average service period of plan participants. As such,
significant portions of pension costs recorded in any period may not reflect the
actual level of benefit payments provided to plan participants.
Pension costs were $90 million, $80 million and $30 million for 2003, 2004
and 2005, respectively. In addition, included in the costs for 2003, 2004 and
2005 are $17 million, $11 million and less than $1 million, respectively, of
expense related to Texas Genco participants. Pension expense for Texas Genco
participants is reflected in the Statement of Consolidated Operations as
discontinued operations.
Additionally, we maintain a non-qualified benefit restoration plan which
allows participants to retain the benefits to which they would have been
entitled under our non-contributory pension plan except for the federally
mandated limits on qualified plan benefits or on the level of compensation on
which qualified plan benefits may be calculated. The expense associated with
this non-qualified plan was $8 million, $6 million and $6 million in 2003, 2004
and 2005, respectively.
The calculation of pension expense and related liabilities requires the use
of assumptions. Changes in these assumptions can result in different expense and
liability amounts, and future actual experience can differ from the assumptions.
Two of the most critical assumptions are the expected long-term rate of return
on plan assets and the assumed discount rate.
As of December 31, 2005, the expected long-term rate of return on plan
assets was 8.5%, which is unchanged from the rate assumed as of December 31,
2004. We believe that our actual asset allocation, on average, will approximate
the targeted allocation and the estimated return on net assets. We regularly
review our actual asset allocation and periodically rebalance plan assets as
appropriate.
As of December 31, 2005, the projected benefit obligation was calculated
assuming a discount rate of 5.70%, which is a 0.05% decline from the 5.75%
discount rate assumed in 2004. The discount rate was determined by reviewing
yields on high-quality bonds that receive one of the two highest ratings given
by a recognized rating agency and the expected duration of pension obligations
specific to the characteristics of our plan.
Pension expense for 2006, including the benefit restoration plan, is
estimated to be $38 million based on an expected return on plan assets of 8.5%
and a discount rate of 5.70% as of December 31, 2005. If the expected return
assumption were lowered by 0.5% (from 8.5% to 8.0%), 2006 pension expense would
increase by approximately $8 million.
Currently, pension plan assets (excluding the unfunded benefit restoration
plan) exceed the accumulated benefit obligation by $41 million. However, if the
discount rate were lowered by 0.5% (from 5.70% to 5.20%), the assumption change
would increase our projected benefit obligation, accumulated benefit obligation
and 2006 pension expense by approximately $131 million, $120 million and $11
million, respectively. In addition, the assumption change would have significant
impacts on our Consolidated Balance Sheet by changing the pension asset recorded
as of December 31, 2005 of $655 million to a pension liability of $79 million
and would result in a charge to comprehensive income in 2005 of $477 million,
net of tax.
55
For the benefit restoration plan, if the discount rate were lowered by 0.5%
(from 5.70% to 5.20%), the assumption change would increase our projected
benefit obligation, accumulated benefit obligation and 2006 pension expense by
approximately $4 million, $4 million, and less than $1 million, respectively. In
addition, the assumption change would result in a charge to comprehensive income
of approximately $3 million.
Future changes in plan asset returns, assumed discount rates and various
other factors related to the pension plan will impact our future pension expense
and liabilities. We cannot predict with certainty what these factors will be.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
IMPACT OF CHANGES IN INTEREST RATES AND ENERGY COMMODITY PRICES
We are exposed to various market risks. These risks arise from transactions
entered into in the normal course of business and are inherent in our
consolidated financial statements. Most of the revenues and income from our
business activities are impacted by market risks. Categories of market risk
include exposure to commodity prices through non-trading activities, interest
rates and equity prices. A description of each market risk is set forth below:
- Commodity price risk results from exposures to changes in spot prices,
forward prices and price volatilities of commodities, such as natural gas
and other energy commodities risk.
- Interest rate risk primarily results from exposures to changes in the
level of borrowings and changes in interest rates.
- Equity price risk results from exposures to changes in prices of
individual equity securities.
Management has established comprehensive risk management policies to
monitor and manage these market risks. We manage these risk exposures through
the implementation of our risk management policies and framework. We manage our
exposures through the use of derivative financial instruments and derivative
commodity instrument contracts. During the normal course of business, we review
our hedging strategies and determine the hedging approach we deem appropriate
based upon the circumstances of each situation.
Derivative instruments such as futures, forward contracts, swaps and
options derive their value from underlying assets, indices, reference rates or a
combination of these factors. These derivative instruments include negotiated
contracts, which are referred to as over-the-counter derivatives, and
instruments that are listed and traded on an exchange.
Derivative transactions are entered into in our non-trading operations to
manage and hedge certain exposures, such as exposure to changes in natural gas
prices. We believe that the associated market risk of these instruments can best
be understood relative to the underlying assets or risk being hedged.
INTEREST RATE RISK
We have outstanding long-term debt, bank loans, mandatory redeemable
preferred securities of a subsidiary trust holding solely our junior
subordinated debentures (trust preferred securities), some lease obligations and
our obligations under our 2.0% Zero-Premium Exchangeable Subordinated Notes due
2029 (ZENS) that subject us to the risk of loss associated with movements in
market interest rates. In 2003, we had interest rate swaps in place in order to
hedge portions of our floating-rate debt.
Our floating-rate obligations aggregated $1.5 billion and $3 million at
December 31, 2004 and 2005, respectively. If the floating interest rates were to
increase by 10% from December 31, 2005 rates, our combined interest expense
would not materially change.
At December 31, 2004 and 2005, we had outstanding fixed-rate debt
(excluding indexed debt securities) and trust preferred securities aggregating
$7.4 billion and $8.8 billion, respectively, in principal amount and having a
fair value of $8.1 billion and $9.3 billion, respectively. 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 (please read Note 8 to our consolidated
financial statements). However, the fair value of these instruments would
increase
56
by approximately $400 million if interest rates were to decline by 10% from
their levels at December 31, 2005. In general, such an increase in fair value
would impact earnings and cash flows only if we were to reacquire all or a
portion of these instruments in the open market prior to their maturity.
As discussed in Note 6 to our consolidated financial statements, upon
adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was
bifurcated into a debt component and a derivative component. The debt component
of $109 million at December 31, 2005 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 December 31, 2005. Changes in the fair value of the derivative component, a
$292 million recorded liability at December 31, 2005, are recorded in our
Statements of Consolidated Operations 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 December 31, 2005 levels, the fair value of the derivative
component liability would increase by approximately $5 million, which would be
recorded as an unrealized loss in our Statements of Consolidated Operations.
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. Please read Note 6 to our consolidated financial
statements for a discussion of the effect of adoption of SFAS No. 133 on our
ZENS obligation and our historical accounting treatment of our ZENS obligation.
A decrease of 10% from the December 31, 2005 market value of TW Common would
result in a net loss of approximately $4 million, which would be recorded as an
unrealized loss in our Statements of Consolidated Operations.
COMMODITY PRICE RISK FROM NON-TRADING ACTIVITIES
To reduce our commodity price risk from market fluctuations in the revenues
derived from the sale of natural gas and related transportation, we enter into
forward contracts, swaps and options (Non-Trading Energy Derivatives) in order
to hedge some expected purchases of natural gas and sales of natural gas (a
portion of which are firm commitments at the inception of the hedge).
Non-Trading Energy Derivatives are also utilized to fix the price of future
operational gas requirements.
We use derivative instruments as economic hedges to offset the commodity
exposure inherent in our businesses. The stand-alone commodity risk created by
these instruments, without regard to the offsetting effect of the underlying
exposure these instruments are intended to hedge, is described below. We measure
the commodity risk of our Non-Trading Energy Derivatives using a sensitivity
analysis. The sensitivity analysis performed on our Non-Trading Energy
Derivatives measures the potential loss in earnings based on a hypothetical 10%
movement in energy prices. A decrease of 10% in the market prices of energy
commodities from their December 31, 2004 levels would have decreased the fair
value of our Non-Trading Energy Derivatives by $46 million. At December 31,
2005, the recorded fair value of our Non-Trading Energy Derivatives was a net
asset of $157 million. A decrease of 10% in the market prices of energy
commodities from their December 31, 2005 levels would have decreased the fair
value of our Non-Trading Energy Derivatives by $85 million.
The above analysis of the Non-Trading Energy Derivatives utilized for
hedging purposes does not include the favorable impact that the same
hypothetical price movement would have on our physical purchases and sales of
natural gas to which the hedges relate. Furthermore, the 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
57
associated with the hypothetical changes in commodity prices referenced above
would be offset by a favorable impact on the underlying hedged physical
transactions, assuming:
- the Non-Trading Energy Derivatives are not closed out in advance of their
expected term;
- the Non-Trading Energy Derivatives continue to function effectively as
hedges of the underlying risk; and
- as applicable, anticipated underlying transactions settle as expected.
If any of the above-mentioned assumptions ceases to be true, a loss on the
derivative instruments may occur, or the options might be worthless as
determined by the prevailing market value on their termination or maturity date,
whichever comes first. Non-Trading Energy Derivatives designated and effective
as hedges, may still have some percentage which is not effective. The change in
value of the Non-Trading Energy Derivatives that represents the ineffective
component of the hedges is recorded in our results of operations.
We have established a Risk Oversight Committee composed of corporate and
business segment officers, that oversees our commodity price and credit risk
activities, including our trading, marketing, risk management services and
hedging activities. The committee's duties are to establish commodity risk
policies, allocate risk capital within limits established by our board of
directors, approve trading of new products and commodities, monitor risk
positions and ensure compliance with our risk management policies and procedures
and trading limits established by our board of directors.
Our policies prohibit the use of leveraged financial instruments. A
leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.
58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
CenterPoint Energy, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of CenterPoint
Energy, Inc. and subsidiaries (the "Company") as of December 31, 2004 and 2005,
and the related consolidated statements of operations, comprehensive income,
shareholders' equity, and cash flows for each of the three years in the period
ended December 31, 2005. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of CenterPoint Energy, Inc. and
subsidiaries at December 31, 2004 and 2005, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2005 in conformity with accounting principles generally accepted in the
United States of America.
As discussed in Note 2 to the consolidated financial statements, the
Company adopted Financial Accounting Standards Board Interpretation No. 47,
"Accounting for Conditional Asset Retirement Obligations," effective December
31, 2005.
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of the
Company's internal control over financial reporting as of December 31, 2005,
based on the criteria established in Internal Control -- Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated March 15, 2006 expressed an unqualified opinion on
management's assessment of the effectiveness of the Company's internal control
over financial reporting and an unqualified opinion on the effectiveness of the
Company's internal control over financial reporting.
DELOITTE & TOUCHE LLP
Houston, Texas
March 15, 2006
59
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
YEAR ENDED DECEMBER 31,
---------------------------
2003 2004 2005
------- ------- -------
(IN MILLIONS,
EXCEPT PER SHARE AMOUNTS)
REVENUES.................................................... $7,790 $7,999 $9,722
------ ------ ------
EXPENSES:
Natural gas............................................... 4,298 5,013 6,509
Operation and maintenance................................. 1,334 1,277 1,358
Depreciation and amortization............................. 466 490 541
Taxes other than income taxes............................. 337 355 375
------ ------ ------
Total.................................................. 6,435 7,135 8,783
------ ------ ------
OPERATING INCOME............................................ 1,355 864 939
------ ------ ------
OTHER INCOME (EXPENSE):
Gain (loss) on Time Warner investment..................... 106 31 (44)
Gain (loss) on indexed debt securities.................... (96) (20) 49
Interest and other finance charges........................ (741) (777) (710)
Return on true-up balance................................. -- 226 121
Other, net................................................ (10) 20 23
------ ------ ------
Total.................................................. (741) (520) (561)
------ ------ ------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM........................................ 614 344 378
Income Tax Expense.......................................... (205) (139) (153)
------ ------ ------
INCOME FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY
ITEM...................................................... 409 205 225
DISCONTINUED OPERATIONS:
Income from Texas Genco, net of tax....................... 139 294 11
Minority interest on income from Texas Genco.............. (48) (61) --
Loss on disposal of Texas Genco, net of tax............... -- (366) (14)
Loss from Other Operations, net of tax.................... (3) -- --
Loss on disposal of Other Operations, net of tax.......... (13) -- --
------ ------ ------
Total.................................................. 75 (133) (3)
------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM............................ 484 72 222
Extraordinary Item, net of tax.............................. -- (977) 30
------ ------ ------
NET INCOME (LOSS)........................................... $ 484 $ (905) $ 252
====== ====== ======
BASIC EARNINGS (LOSS) PER SHARE:
Income From Continuing Operations Before Extraordinary
Item...................................................... $ 1.35 $ 0.67 $ 0.72
Discontinued Operations, net of tax......................... 0.24 (0.43) (0.01)
Extraordinary Item, net of tax.............................. -- (3.18) 0.10
------ ------ ------
Net Income (Loss)......................................... $ 1.59 $(2.94) $ 0.81
====== ====== ======
DILUTED EARNINGS (LOSS) PER SHARE:
Income From Continuing Operations Before Extraordinary
Item...................................................... $ 1.24 $ 0.61 $ 0.67
Discontinued Operations, net of tax......................... 0.22 (0.37) (0.01)
Extraordinary Item, net of tax.............................. -- (2.72) 0.09
------ ------ ------
Net Income (Loss)......................................... $ 1.46 $(2.48) $ 0.75
====== ====== ======
See Notes to the Company's Consolidated Financial Statements
60
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
YEAR ENDED DECEMBER 31,
-------------------------
2003 2004 2005
------ ------- ------
(IN MILLIONS)
Net income (loss)........................................... $484 $(905) $252
---- ----- ----
Other comprehensive income, net of tax:
Minimum pension liability adjustment (net of tax of $25,
$197 and ($5))......................................... 47 367 (9)
Net deferred gain from cash flow hedges (net of tax of
$15, $31 and $9)....................................... 22 59 17
Reclassification of deferred loss (gain) from cash flow
hedges realized in net income (net of tax of $4, ($3)
and $6)................................................ 9 (7) 11
Reclassification of deferred gain from de-designation of
cash flow hedges to over/under recovery of gas cost
(net of tax of ($37)).................................. -- (68) --
Other comprehensive income (loss) from discontinued
operations (net of tax of $-0-, ($2) and $2)........... 1 (4) 3
---- ----- ----
Other comprehensive income.................................. 79 347 22
---- ----- ----
Comprehensive income (loss)................................. $563 $(558) $274
==== ===== ====
See Notes to the Company's Consolidated Financial Statements
61
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, DECEMBER 31,
2004 2005
------------ ------------
(IN MILLIONS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 165 $ 74
Investment in Time Warner common stock.................... 421 377
Accounts receivable, net.................................. 674 1,098
Accrued unbilled revenues................................. 576 608
Inventory................................................. 254 382
Non-trading derivative assets............................. 50 131
Taxes receivable.......................................... -- 53
Current assets of discontinued operations................. 514 --
Prepaid expense and other current assets.................. 117 168
------- -------
Total current assets................................... 2,771 2,891
------- -------
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 8,186 8,492
------- -------
OTHER ASSETS:
Goodwill.................................................. 1,741 1,709
Other intangibles, net.................................... 58 56
Regulatory assets......................................... 3,350 2,955
Non-trading derivative assets............................. 18 104
Non-current assets of discontinued operations............. 1,051 --
Other..................................................... 921 909
------- -------
Total other assets..................................... 7,139 5,733
------- -------
TOTAL ASSETS......................................... $18,096 $17,116
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt......................... $ 1,836 $ 339
Indexed debt securities derivative........................ 342 292
Accounts payable.......................................... 802 1,161
Taxes accrued............................................. 609 167
Interest accrued.......................................... 151 122
Non-trading derivative liabilities........................ 26 43
Regulatory liabilities.................................... 225 --
Accumulated deferred income taxes, net.................... 261 385
Current liabilities of discontinued operations............ 449 --
Other..................................................... 420 505
------- -------
Total current liabilities.............................. 5,121 3,014
------- -------
OTHER LIABILITIES:
Accumulated deferred income taxes, net.................... 2,415 2,474
Unamortized investment tax credits........................ 54 46
Non-trading derivative liabilities........................ 6 35
Benefit obligations....................................... 440 475
Regulatory liabilities.................................... 1,082 728
Non-current liabilities of discontinued operations........ 420 --
Other..................................................... 259 480
------- -------
Total other liabilities................................ 4,676 4,238
------- -------
LONG-TERM DEBT.............................................. 7,193 8,568
------- -------
COMMITMENTS AND CONTINGENCIES (NOTE 10)
SHAREHOLDERS' EQUITY........................................ 1,106 1,296
------- -------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY............. $18,096 $17,116
======= =======
See Notes to the Company's Consolidated Financial Statements
62
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEAR ENDED DECEMBER 31,
---------------------------
2003 2004 2005
------- ------- -------
(IN MILLIONS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ 484 $ (905) $ 252
Discontinued operations, net of tax....................... (75) 133 3
Extraordinary item, net of tax............................ -- 977 (30)
------- ------- -------
Income from continuing operations......................... 409 205 225
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation and amortization........................... 466 490 541
Deferred income taxes................................... 509 265 232
Amortization of deferred financing costs................ 141 92 77
Investment tax credit................................... (7) (7) (8)
Unrealized loss (gain) on Time Warner investment........ (106) (32) 44
Unrealized loss (gain) on indexed debt securities....... 96 20 (49)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net........ (110) (202) (456)
Inventory............................................. (47) (10) (115)
Taxes receivable...................................... (161) 35 (53)
Accounts payable...................................... 77 218 321
Fuel cost over (under) recovery/surcharge............. 25 25 (129)
Interest and taxes accrued............................ 37 81 (471)
Net regulatory assets and liabilities................. (773) (520) (192)
Clawback payment from RRI............................. -- 177 --
Non-trading derivatives, net.......................... 3 (40) (12)
Pension contribution.................................. (23) (476) (75)
Other current assets.................................. (37) (18) (40)
Other current liabilities............................. (24) (26) 146
Other assets.......................................... 29 80 30
Other liabilities..................................... 107 4 67
Other, net.............................................. 39 20 18
------- ------- -------
Net cash provided by operating activities of
continuing operations............................... 650 381 101
Net cash provided by (used in) operating activities
of discontinued operations.......................... 244 355 (38)
------- ------- -------
Net cash provided by operating activities........... 894 736 63
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures...................................... (659) (604) (693)
Proceeds from sale of Texas Genco, including cash
retained................................................ -- 2,947 700
Purchase of minority interest of Texas Genco.............. -- (326) (383)
Decrease (increase) in restricted cash for purchase of
minority interest of Texas Genco........................ -- (390) 383
Funds held for purchase of additional shares in South
Texas Project........................................... -- (191) --
Increase in cash of Texas Genco........................... -- -- 24
Other, net................................................ (2) 30 (14)
------- ------- -------
Net cash provided by (used in) investing
activities.......................................... (661) 1,466 17
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings, net......... (284) (63) 75
Long-term revolving credit facility, net.................. (2,400) (1,206) (236)
Proceeds from long-term debt.............................. 3,797 229 3,161
Payments of long-term debt................................ (1,211) (943) (3,045)
Debt issuance costs....................................... (241) (15) (21)
Payment of common stock dividends......................... (122) (123) (124)
Payment of common stock dividends by subsidiary........... (15) (15) --
Proceeds from issuance of common stock, net............... 9 12 17
Other, net................................................ 17 -- 2
------- ------- -------
Net cash used in financing activities............... (450) (2,124) (171)
------- ------- -------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ (217) 78 (91)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 304 87 165
------- ------- -------
CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 87 $ 165 $ 74
======= ======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest, net of capitalized interest................... $ 763 $ 759 $ 667
Income taxes (refunds), net............................. (198) (124) 351
Non-cash transactions:
Increase in accounts payable related to capital
expenditures........................................... -- -- 35
See Notes to the Company's Consolidated Financial Statements
63
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY
2003 2004 2005
---------------- ---------------- ----------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------ ------- ------ ------- ------ -------
(IN MILLIONS OF DOLLARS AND SHARES)
PREFERENCE STOCK, NONE OUTSTANDING.............. -- $ -- -- $ -- -- $ --
CUMULATIVE PREFERRED STOCK, $0.01 PAR VALUE;
AUTHORIZED 20,000,000 SHARES, NONE
OUTSTANDING................................... -- -- -- -- -- --
COMMON STOCK, $0.01 PAR VALUE; AUTHORIZED
1,000,000,000 SHARES
Balance, beginning of year.................... 305 3 306 3 308 3
Issuances related to benefit and investment
plans...................................... 1 -- 2 -- 2 --
--- ------- --- ------- --- -------
Balance, end of year.......................... 306 3 308 3 310 3
--- ------- --- ------- --- -------
ADDITIONAL PAID-IN-CAPITAL
Balance, beginning of year.................... -- 3,046 -- 2,868 -- 2,891
Issuances related to benefit and investment
plans...................................... -- (32) -- 23 -- 40
Distribution of Texas Genco................... -- (146) -- -- -- --
--- ------- --- ------- --- -------
Balance, end of year.......................... -- 2,868 -- 2,891 -- 2,931
--- ------- --- ------- --- -------
UNEARNED ESOP STOCK
Balance, beginning of year.................... (5) (78) (1) (3) -- --
Issuances related to benefit plan............. 4 75 1 3 -- --
--- ------- --- ------- --- -------
Balance, end of year.......................... (1) (3) -- -- -- --
--- ------- --- ------- --- -------
ACCUMULATED DEFICIT
Balance, beginning of year.................... (1,062) (700) (1,728)
Net income (loss)............................. 484 (905) 252
Common stock dividends -- $0.40 per share in
2003, 2004 and 2005........................ (122) (123) (124)
------- ------- -------
Balance, end of year.......................... (700) (1,728) (1,600)
------- ------- -------
ACCUMULATED OTHER COMPREHENSIVE LOSS
Balance, end of year:
Minimum pension liability adjustment.......... (373) (6) (15)
Net deferred loss from cash flow hedges....... (35) (51) (23)
Other comprehensive loss from discontinued
operations................................. -- (3) --
------- ------- -------
Total accumulated other comprehensive loss,
end of year................................ (408) (60) (38)
------- ------- -------
Total Shareholders' Equity................. $ 1,760 $ 1,106 $ 1,296
======= ======= =======
See Notes to the Company's Consolidated Financial Statements
64
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) BACKGROUND AND BASIS OF PRESENTATION
(a) BACKGROUND
CenterPoint Energy, Inc. is a public utility holding company, created on
August 31, 2002 as part of a corporate restructuring of Reliant Energy,
Incorporated (Reliant Energy) that implemented certain requirements of the Texas
Electric Choice Plan (Texas electric restructuring law).
CenterPoint Energy was a registered public utility holding company under
the Public Utility Holding Company Act of 1935, as amended (the 1935 Act). The
1935 Act and related rules and regulations imposed a number of restrictions on
the activities of the Company and its subsidiaries. The Energy Policy Act of
2005 (Energy Act) repealed the 1935 Act effective February 8, 2006, and since
that date the Company and its subsidiaries have no longer been subject to
restrictions imposed under the 1935 Act. The Energy Act includes a new Public
Utility Holding Company Act of 2005 (PUHCA 2005), which grants to the Federal
Energy Regulatory Commission (FERC) authority to require holding companies and
their subsidiaries to maintain certain books and records and make them available
for review by the FERC and state regulatory authorities in certain
circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA
2005 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. The FERC continues to consider motions for rehearing or clarification
of these rules.
The Company's operating subsidiaries own and operate electric transmission
and distribution facilities, natural gas distribution facilities, interstate
pipelines and natural gas gathering, processing and treating facilities. As of
December 31, 2005, the Company's indirect wholly owned subsidiaries included:
- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
engages in the electric transmission and distribution business in a
5,000-square mile area of the Texas Gulf Coast that includes Houston; and
- CenterPoint Energy Resources Corp. (CERC Corp., and, together with its
subsidiaries, CERC), which owns gas distribution systems. The operations
of its local distribution companies are conducted through two
unincorporated divisions: Minnesota Gas and Southern Gas Operations.
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.
(b) BASIS OF PRESENTATION
In 2003, the Company sold all of its remaining Latin America operations.
In November 2003, the Company sold its district cooling services business
in the Houston central business district and related complementary energy
services to district cooling customers and others.
The Company sold the fossil generation assets of Texas Genco Holdings, Inc.
(Texas Genco) in December 2004 and completed the sale of Texas Genco, which had
continued to own an interest in a nuclear generating facility, in April 2005.
The consolidated financial statements report the businesses described above
as discontinued operations for all periods presented in accordance with
Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).
For a description of the Company's reportable business segments, see Note
14.
65
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) RECLASSIFICATIONS AND USE OF ESTIMATES
In addition to the items discussed in Note 3, some amounts from the
previous years have been reclassified to conform to the 2005 presentation of
financial statements. These reclassifications relate to a new reportable
business segment discussed in Note 14 and do not affect net income.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
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.
(b) PRINCIPLES OF CONSOLIDATION
The accounts of CenterPoint Energy and its wholly owned and majority owned
subsidiaries are included in the consolidated financial statements. All
significant intercompany transactions and balances are eliminated in
consolidation. The Company uses the equity method of accounting for investments
in entities in which the Company has an ownership interest between 20% and 50%
and exercises significant influence. Such investments were $13 million and $15
million as of December 31, 2004 and 2005, respectively. Other investments,
excluding marketable securities, are carried at cost.
(c) REVENUES
The Company records revenue for electricity delivery and natural gas sales
and services under the accrual method and these revenues are recognized upon
delivery to customers. Electricity deliveries not billed by month-end are
accrued based on daily supply volumes, applicable rates and analyses reflecting
significant historical trends and experience. Natural gas sales not billed by
month-end are accrued based upon estimated purchased gas volumes, estimated lost
and unaccounted for gas and currently effective tariff rates. The Pipelines and
Field Services business segment records revenues as transportation services are
provided.
66
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(d) LONG-LIVED ASSETS AND INTANGIBLES
The Company records property, plant and equipment at historical cost. The
Company expenses repair and maintenance costs as incurred. Property, plant and
equipment includes the following:
WEIGHTED AVERAGE DECEMBER 31,
USEFUL LIVES -----------------
(YEARS) 2004 2005
---------------- ------- -------
(IN MILLIONS)
Electric transmission & distribution.............. 27 $ 6,245 $ 6,463
Natural gas distribution.......................... 30 2,475 2,740
Competitive natural gas sales and services........ 38 19 27
Pipelines and field services...................... 52 1,767 1,887
Other property.................................... 29 457 441
------- -------
Total........................................ 10,963 11,558
------- -------
Accumulated depreciation and amortization:
Electric transmission & distribution............ (2,204) (2,386)
Natural gas distribution........................ (285) (391)
Competitive natural gas sales and services...... (6) (5)
Pipelines and field services.................... (157) (167)
Other property.................................. (125) (117)
------- -------
Total accumulated depreciation and
amortization............................... (2,777) (3,066)
------- -------
Property, plant and equipment, net......... $ 8,186 $ 8,492
======= =======
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2004 DECEMBER 31, 2005
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Land Use Rights............................ $55 $(12) $55 $(14)
Other...................................... 21 (6) 22 (7)
--- ---- --- ----
Total.................................... $76 $(18) $77 $(21)
=== ==== === ====
The Company recognizes specifically identifiable intangibles, including
land use rights and permits, when specific rights and contracts are acquired.
The Company has no intangible assets with indefinite lives recorded as of
December 31, 2005 other than goodwill discussed below. The Company amortizes
other acquired intangibles on a straight-line basis over the lesser of their
contractual or estimated useful lives that range from 27 to 75 years for land
rights and 10 to 56 years for other intangibles.
67
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Amortization expense for other intangibles for 2003, 2004 and 2005 was $2
million in each year. Estimated amortization expense for the five succeeding
fiscal years is as follows (in millions):
2006........................................................ $ 3
2007........................................................ 3
2008........................................................ 3
2009........................................................ 2
2010........................................................ 2
---
Total..................................................... $13
===
Goodwill by reportable business segment is as follows (in millions):
COMPETITIVE
NATURAL GAS PIPELINES
NATURAL GAS SALES AND AND FIELD OTHER
DISTRIBUTION SERVICES SERVICES OPERATIONS TOTAL
------------ ----------- --------- ---------- ------
Balance as of December 31, 2004.......... $746 $339 $601 $ 55 $1,741
Goodwill acquired during year............ -- -- 3 -- 3
Adjustment(1)............................ -- -- -- (35) (35)
---- ---- ---- ---- ------
Balance as of December 31, 2005.......... $746 $339 $604 $ 20 $1,709
==== ==== ==== ==== ======
---------------
(1) In December 2005, the Company determined that $35 million of deferred tax
liabilities originally established in connection with an acquisition were no
longer required. In accordance with Emerging Issues Task Force (EITF) Issue
No. 93-7, "Uncertainties Related to Income Taxes in a Purchase Business
Combination," the adjustment was applied to decrease the remaining goodwill
attributable to that acquisition.
The Company performs its goodwill impairment test at least annually and
evaluates goodwill when events or changes in circumstances indicate that the
carrying value of these assets may not be recoverable. The impairment evaluation
for goodwill is performed by using a two-step process. In the first step, the
fair value of each reporting unit is compared with the carrying amount of the
reporting unit, including goodwill. The estimated fair value of the reporting
unit is generally determined on the basis of discounted future cash flows. If
the estimated fair value of the reporting unit is less than the carrying amount
of the reporting unit, then a second step must be completed in order to
determine the amount of the goodwill impairment that should be recorded. In the
second step, the implied fair value of the reporting unit's goodwill is
determined by allocating the reporting unit's fair value to all of its assets
and liabilities other than goodwill (including any unrecognized intangible
assets) in a manner similar to a purchase price allocation. The resulting
implied fair value of the goodwill that results from the application of this
second step is then compared to the carrying amount of the goodwill and an
impairment charge is recorded for the difference.
Upon adoption of SFAS No. 142, "Goodwill and Other Intangible Assets," the
Company initially selected January 1 as its annual goodwill impairment testing
date. Since the time the Company selected the January 1 date, the Company's
year-end closing and reporting process has been truncated in order to meet the
accelerated reporting requirements of the Securities and Exchange Commission
(SEC), resulting in significant constraints on the Company's human resources at
year-end and during its first fiscal quarter. Accordingly, in order to meet the
accelerated reporting deadlines and to provide adequate time to complete the
analysis each year, beginning in the third quarter of 2005, the Company changed
the date on which it performs its annual goodwill impairment test from January 1
to July 1. The Company believes the July 1 alternative date will alleviate the
resource constraints that exist during the first quarter and allow it to utilize
additional resources in conducting the annual impairment evaluation of goodwill.
The Company performed the
68
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
test at July 1, 2005, and determined that no impairment charge for goodwill was
required. The change is not intended to delay, accelerate or avoid an impairment
charge. The Company believes that this accounting change is an alternative
accounting principle that is preferable under the circumstances.
The Company periodically evaluates long-lived assets, including property,
plant and equipment, and specifically identifiable intangibles, when events or
changes in circumstances indicate that the carrying value of these assets may
not be recoverable. The determination of whether an impairment has occurred is
based on an estimate of undiscounted cash flows attributable to the assets, as
compared to the carrying value of the assets.
(e) REGULATORY ASSETS AND LIABILITIES
The Company applies the accounting policies established in SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), to
the accounts of the Electric Transmission & Distribution business segment and
the Natural Gas Distribution business segment and to some of the accounts of the
Pipelines and Field Services business segment.
The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheets as of December 31, 2004 and 2005:
DECEMBER 31,
---------------
2004 2005
------ ------
(IN MILLIONS)
Recoverable electric generation-related regulatory
assets(1)................................................. $1,946 $ 332
Securitized regulatory asset................................ 647 2,420
Unamortized loss on reacquired debt......................... 80 91
Other long-term regulatory assets/liabilities............... 47 46
------ ------
Subtotal.................................................. 2,720 2,889
Estimated removal costs..................................... (677) (662)
------ ------
Total..................................................... $2,043 $2,227
====== ======
---------------
(1) Excludes $147 million and $248 million of allowed equity return on the
true-up balance as of December 31, 2004 and 2005, respectively. See Note
4(a).
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.
If events were to occur that would make the recovery of these assets and
liabilities no longer probable, the Company would be required to write-off or
write-down these regulatory assets and liabilities. During 2004, the Company
wrote-off net regulatory assets of $1.5 billion ($977 million after-tax) as an
extraordinary loss in response to the Texas Utility Commission's order on
CenterPoint Houston's final true-up application. Based on subsequent orders
received from the Texas Utility Commission, the Company recorded an
extraordinary gain of $47 million ($30 million after-tax) in the second quarter
of 2005 related to these regulatory assets. For further discussion of regulatory
assets, see Note 4.
69
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company's rate-regulated businesses recognize removal costs as a
component of depreciation expense in accordance with regulatory treatment. As of
December 31, 2004 and 2005, these removal costs of $677 million and $662
million, respectively, are classified as regulatory liabilities in the
Consolidated Balance Sheets. A portion of the amount of removal costs that
relate to asset retirement obligations have been reclassified from a regulatory
liability to an asset retirement liability, which is included in other
liabilities in the Consolidated Balance Sheets, in connection with the Company's
adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN)
47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47) as
further discussed in Note 2(n).
(f) DEPRECIATION AND AMORTIZATION EXPENSE
Depreciation is computed using the straight-line method based on economic
lives or a regulatory-mandated recovery period. Amortization expense includes
amortization of regulatory assets and other intangibles. See Notes 2(e) and 4(a)
for additional discussion of these items.
The following table presents depreciation and amortization expense for
2003, 2004 and 2005 (in millions):
2003 2004 2005
---- ---- ----
Depreciation expense........................................ $403 $415 $432
Amortization expense........................................ 63 75 109
---- ---- ----
Total depreciation and amortization expense............... $466 $490 $541
==== ==== ====
(g) CAPITALIZATION OF INTEREST AND ALLOWANCE FOR FUNDS USED DURING
CONSTRUCTION
Allowance for funds used during construction (AFUDC) represents the
approximate net composite interest cost of borrowed funds and a reasonable
return on the equity funds used for construction. Although AFUDC increases both
utility plant and earnings, it is realized in cash through depreciation
provisions included in rates for subsidiaries that apply SFAS No. 71. Interest
and AFUDC for subsidiaries that apply SFAS No. 71 are capitalized as a component
of projects under construction and will be amortized over the assets' estimated
useful lives. During 2003, 2004 and 2005, the Company capitalized interest and
AFUDC of $4 million each year.
(h) INCOME TAXES
The Company files a consolidated federal income tax return and follows a
policy of comprehensive interperiod income tax allocation. The Company uses the
liability method of accounting for deferred income taxes and measures deferred
income taxes for all significant income tax temporary differences in accordance
with SFAS No. 109, "Accounting for Income Taxes." Investment tax credits were
deferred and are being amortized over the estimated lives of the related
property. Management evaluates uncertain tax positions and accrues for those
which management believes are probable of an unfavorable outcome. For additional
information regarding income taxes, see Note 9.
(i) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS
Accounts receivable are net of an allowance for doubtful accounts of $30
million and $43 million at December 31, 2004 and 2005, respectively. The
provision for doubtful accounts in the Company's Statements of Consolidated
Operations for 2003, 2004 and 2005 was $24 million, $27 million and $40 million,
respectively.
70
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 2004 and 2005, CERC had $181 million and $141 million of
advances, respectively, under its receivables facility. CERC Corp. formed a
bankruptcy remote subsidiary for the sole purpose of buying receivables created
by CERC and selling those receivables to an unrelated third-party. These
transactions were accounted for as a sale of receivables under the provisions of
SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities," (SFAS No. 140) and, as a result, the related
receivables are excluded from the Consolidated Balance Sheets. The bankruptcy
remote subsidiary purchases receivables with cash and subordinated notes. The
subordinated notes owned by CERC are pledged to a gas supplier to secure
obligations incurred in connection with the purchase of gas by CERC and totaled
approximately $433 million as of December 31, 2005.
In January 2006, CERC's $250 million receivables facility, which 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, was extended to January 2007.
Advances under the receivables facility averaged $100 million, $190 million
and $166 million in 2003, 2004 and 2005, respectively. Sales of receivables were
approximately $1.2 billion, $2.4 billion and $2.0 billion in 2003, 2004 and
2005, respectively.
(j) INVENTORY
Inventory consists principally of materials and supplies and natural gas.
Materials and supplies are valued at the lower of average cost or market.
Inventories used in the retail natural gas distribution operations are also
primarily valued at the lower of average cost or market.
DECEMBER 31,
-------------
2004 2005
----- -----
(IN MILLIONS)
Materials and supplies...................................... $ 78 $ 88
Natural gas................................................. 176 294
---- ----
Total inventory........................................... $254 $382
==== ====
(k) INVESTMENT IN OTHER DEBT AND EQUITY SECURITIES
In accordance with SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS No. 115), the Company reports
"available-for-sale" securities at estimated fair value within other long-term
assets in the Company's Consolidated Balance Sheets and any unrealized gain or
loss, net of tax, as a separate component of shareholders' equity and
accumulated other comprehensive income. In accordance with SFAS No. 115, the
Company reports "trading" securities at estimated fair value in the Company's
Consolidated Balance Sheets, and any unrealized holding gains and losses are
recorded as other income (expense) in the Company's Statements of Consolidated
Operations.
As of December 31, 2004, Texas Genco held debt and equity securities in its
nuclear decommissioning trust, which was reported at its fair value of $216
million in the Company's Consolidated Balance Sheets in non-current assets of
discontinued operations. Any unrealized losses or gains were accounted for as a
non-current asset/liability of discontinued operations as Texas Genco will not
benefit from any gains, and losses will be recovered through the rate-making
process.
As of December 31, 2004 and 2005, the Company held an investment in Time
Warner Inc. common stock, which was classified as a "trading" security. For
information regarding this investment, see Note 6.
71
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(l) ENVIRONMENTAL COSTS
The Company expenses or capitalizes environmental expenditures, as
appropriate, depending on their future economic benefit. The Company expenses
amounts that relate to an existing condition caused by past operations, and that
do not have future economic benefit. The Company records undiscounted
liabilities related to these future costs when environmental assessments and/or
remediation activities are probable and the costs can be reasonably estimated.
(m) STATEMENTS OF CONSOLIDATED CASH FLOWS
For purposes of reporting cash flows, the Company considers cash
equivalents to be short-term, highly liquid investments with maturities of three
months or less from the date of purchase. In connection with the issuance of
transition bonds in October 2001 and December 2005, the Company was required to
establish restricted cash accounts to collateralize the bonds that were issued
in these financing transactions. These restricted cash accounts are not
available for withdrawal until the maturity of the bonds. Cash and Cash
Equivalents does not include restricted cash. For additional information
regarding the December 2005 securitization financing, see Notes 4(a) and 8(a).
(n) NEW ACCOUNTING PRONOUNCEMENTS
In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error
Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3" (SFAS
No. 154). SFAS No. 154 provides guidance on the accounting for and reporting of
accounting changes and error corrections. It establishes, unless impracticable,
retrospective application as the required method for reporting a change in
accounting principle in the absence of explicit transition requirements specific
to the newly adopted accounting principle. The correction of an error in
previously issued financial statements is not an accounting change and must be
reported as a prior-period adjustment by restating previously issued financial
statements. SFAS No. 154 was effective for accounting changes and corrections of
errors made in fiscal years beginning after December 15, 2005.
In March 2005, the FASB issued FIN 47. FIN 47 clarifies that an entity must
record a liability for a "conditional" asset retirement obligation if the fair
value of the obligation can be reasonably estimated. The Company has identified
conditional asset retirement obligations in the natural gas distribution segment
that exist due to requirements of the U.S. Department of Transportation to cap
and purge certain mains upon retirement. Also, the Company identified
conditional asset retirement obligations for treated utility poles and for
transformers contaminated by polychlorinated biphenyls. The fair value of these
obligations is recorded as a liability on a discounted basis with a
corresponding increase to the related asset. Over time, the liabilities are
accreted for the change in the present value and the initial capitalized costs
are depreciated over the useful lives of the related assets. The adoption of FIN
47, effective December 31, 2005, resulted in the recognition of an asset
retirement obligation liability of $76 million, an increase in net property,
plant and equipment of $37 million and a $39 million increase in net regulatory
assets. The Company's rate-regulated businesses have previously recognized
removal costs as a component of depreciation expense in accordance with
regulatory treatment, and these costs have been classified as a regulatory
liability. Upon adoption of FIN 47, the portion of the removal costs that
relates to this asset retirement obligation has been reclassified from a
regulatory liability to an asset retirement liability, which is included in
other liabilities in the Consolidated Balance Sheets.
The pro forma effect of applying this guidance in the prior periods would
have resulted in an asset retirement obligation of approximately $67 million and
$72 million as of January 1, 2004 and December 31, 2004, respectively.
72
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In February 2006, the FASB issued SFAS No. 155, "Accounting for Certain
Hybrid Financial Instruments" (SFAS No. 155). SFAS No. 155 amends SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," and SFAS No.
140. SFAS No. 155 includes provisions that permit fair value remeasurement for
any hybrid financial instrument that contains an embedded derivative and that
otherwise would require bifurcation. It also establishes a requirement to
evaluate interests in securitized financial assets to identify interests that
are free-standing or that are hybrid financial instruments that contain an
embedded derivative requiring bifurcation. SFAS No. 155 is effective for all
financial instruments acquired or issued after the beginning of the Company's
first fiscal year that begins after September 15, 2006. The fair value election
in SFAS No. 155 may also be applied upon adoption for hybrid instruments that
have been bifurcated under SFAS No. 133 prior to the adoption of this statement.
The Company is evaluating the effect of adoption of this new standard on its
financial position, results of operations and cash flows and does not expect the
standard to have a material impact.
(o) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS
STOCK-BASED INCENTIVE COMPENSATION PLANS
The Company has long-term incentive compensation plans (LICPs) that provide
for the issuance of stock-based incentives, including performance-based shares,
performance-based units, restricted shares and stock options to directors,
officers and key employees. A maximum of approximately 36 million shares of
CenterPoint Energy common stock is authorized to be issued under these plans.
Performance-based shares, performance-based units and restricted shares are
granted to employees without cost to the participants. The performance shares
and units are distributed based upon the performance of the Company over a
three-year cycle. The restricted shares vest at various times ranging from one
year to the end of a three-year period. Upon vesting, the shares are issued to
the participants along with the value of common dividends declared during the
vesting period. The restricted shares granted in 2005 are subject to the
performance condition that common dividends declared during the vesting period
must be at least $1.20 per share.
Option awards are generally granted with an exercise price equal to the
average of the high and low sales price of the Company's stock at the date of
grant. These option awards generally become exercisable in one-third increments
on each of the first through third anniversaries of the grant date and have
10-year contractual terms. No options were granted during 2005.
Effective January 1, 2005, the Company adopted SFAS No. 123 (Revised 2004),
"Share-Based Payment" (SFAS 123(R)), using the modified prospective transition
method. Under this method, the Company records compensation expense at fair
value for all awards it grants after the date it adopted the standard. In
addition, the Company records compensation expense at fair value (as previous
awards continue to vest) for the unvested portion of previously granted stock
option awards that were outstanding as of the date of adoption. Pre-adoption
awards of time-based restricted stock and performance-based restricted stock
will continue to be expensed using the guidance contained in Accounting
Principles Board Opinion No. 25. The adoption of SFAS 123(R) did not have a
material impact on the Company's results of operations, financial condition or
cash flows.
The Company recorded LICP compensation expense of $9 million, $8 million
and $13 million in 2003, 2004 and 2005, respectively.
The total income tax benefit recognized related to such arrangements was $4
million, $3 million and $5 million in 2003, 2004 and 2005, respectively. No
compensation cost related to such arrangements was capitalized as a part of
inventory or fixed assets in 2003, 2004 or 2005.
73
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pro forma information for 2003 and 2004 is provided to show the effect of
amortizing stock-based compensation to expense on a straight-line basis over the
vesting period. Had compensation costs been determined as prescribed by SFAS No.
123, the Company's net income and earnings per share would have been as follows
(in millions, except per share amounts):
YEAR ENDED
DECEMBER 31,
--------------
2003 2004
----- ------
Net income (loss) as reported............................... $ 484 $ (905)
Add: Total stock-based employee compensation expense as
recorded, net of related tax effects...................... 6 5
Less: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects................................ (16) (9)
----- ------
Pro-forma net income (loss)................................. $ 474 $ (909)
===== ======
Basic Earnings (Loss) Per Share:
As reported............................................... $1.59 $(2.94)
Pro-forma................................................. $1.56 $(2.95)
Diluted Earnings (Loss) Per Share:
As reported............................................... $1.46 $(2.48)
Pro-forma................................................. $1.43 $(2.49)
The following tables summarize the methods used to measure compensation
cost for the various types of awards granted under the LICPs:
FOR AWARDS GRANTED BEFORE JANUARY 1, 2005
AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST
---------- ------------------------------------------
Performance shares........................ Initially measured using fair value and expected
achievement levels on the date of grant. Compensation
cost is then periodically adjusted to reflect changes in
market prices and achievement through the settlement
date.
Performance units......................... Initially measured using the award's target unit value
of $100 that reflects expected achievement levels on the
date of grant. Compensation cost is then periodically
adjusted to reflect changes in achievement through the
settlement date.
Time-based restricted stock............... Measured using fair value on the grant date.
Stock options............................. Estimated using the Black-Scholes option valuation
method.
In 2003 and 2004, the fair values of stock options were estimated using the
Black-Scholes option valuation model with the following assumptions:
2003 2004
----- -----
Expected life in years...................................... 5 5
Interest rate............................................... 2.62% 3.02%
Volatility.................................................. 52.60% 27.23%
Expected common stock dividend.............................. $0.40 $0.40
74
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR AWARDS GRANTED AS OF AND AFTER JANUARY 1, 2005
AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST
---------- ------------------------------------------
Performance shares........................ Measured using fair value and expected achievement
levels on the grant date.
Time-based restricted stock............... Measured using fair value on the grant date.
For awards granted before January 1, 2005, forfeitures of awards were
measured upon their occurrence. For awards granted as of and after January 1,
2005, forfeitures are estimated on the date of grant and are adjusted as
required through the remaining vesting period.
The following tables summarize the Company's LICP activity for 2005:
STOCK OPTIONS
OUTSTANDING OPTIONS
YEAR ENDED DECEMBER 31, 2005
------------------------------------------------------------------------
REMAINING AVERAGE
SHARES WEIGHTED-AVERAGE CONTRACTUAL LIFE AGGREGATE INTRINSIC
(THOUSANDS) EXERCISE PRICE (YEARS) VALUE (MILLIONS)
----------- ---------------- ----------------- -------------------
Outstanding at December 31,
2004........................... 16,159 $15.42
Forfeited or expired........... (1,248) 16.96
Exercised...................... (1,244) 7.00
------
Outstanding at December 31,
2005........................... 13,667 16.05 4.2 $25
======
Exercisable at December 31,
2005........................... 11,808 17.13 3.6 18
======
NON-VESTED OPTIONS
YEAR ENDED DECEMBER 31, 2005
------------------------------
WEIGHTED-AVERAGE
SHARES GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------------
Outstanding at December 31, 2004......................... 4,072 $1.70
Vested................................................. (2,166) 1.62
Forfeited or expired................................... (47) 1.95
------
Outstanding at December 31, 2005......................... 1,859 1.79
======
PERFORMANCE SHARES
OUTSTANDING SHARES
YEAR ENDED DECEMBER 31, 2005
-----------------------------------------------------
REMAINING AVERAGE
SHARES CONTRACTUAL LIFE AGGREGATE INTRINSIC
(THOUSANDS) (YEARS) VALUE (MILLIONS)
----------- ----------------- -------------------
Outstanding at December 31, 2004........ 1,169
Granted............................... 945
Forfeited............................. (181)
Vested and released to participants... (373)
-----
Outstanding at December 31, 2005........ 1,560 1.1 $16
=====
75
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NON-VESTED SHARES
YEAR ENDED DECEMBER 31, 2005
------------------------------
WEIGHTED-AVERAGE
SHARES GRANT DATE
(THOUSANDS) FAIR VALUE
----------- ----------------
Outstanding at December 31, 2004......................... 756 $ 5.70
Granted................................................ 945 12.13
Forfeited.............................................. (121) 9.17
Vested and released to participants.................... (20) 5.64
-----
Outstanding at December 31, 2005......................... 1,560 9.33
=====
The non-vested and outstanding shares displayed in the above tables assume
that shares are issued at the maximum performance level (150%). The aggregate
intrinsic value reflects the impacts of current expectations of achievement and
stock price.
PERFORMANCE-BASED UNITS
OUTSTANDING AND NON-VESTED UNITS
YEAR ENDED DECEMBER 31, 2005
------------------------------------------------------------------------
WEIGHTED-AVERAGE REMAINING AVERAGE
UNITS GRANT DATE CONTRACTUAL LIFE AGGREGATE INTRINSIC
(THOUSANDS) FAIR VALUE (YEARS) VALUE (MILLIONS)
----------- ---------------- ----------------- -------------------
Outstanding at December 31,
2004........................... 37 $100.00
Forfeited...................... (2) 100.00
Vested and released to
participants................ (1) 100.00
--
Outstanding at December 31,
2005........................... 34 100.00 1.0 $3
==
The aggregate intrinsic value reflects the value of the performance units
given current expectations of performance through the end of the cycle.
TIME-BASED RESTRICTED STOCK
OUTSTANDING AND NON-VESTED SHARES
YEAR ENDED DECEMBER 31, 2005
------------------------------------------------------------------------
WEIGHTED-AVERAGE REMAINING AVERAGE
SHARES GRANT DATE CONTRACTUAL LIFE AGGREGATE INTRINSIC
(THOUSANDS) FAIR VALUE (YEARS) VALUE (MILLIONS)
----------- ---------------- ----------------- -------------------
Outstanding at December 31,
2004........................... 769 $ 7.49
Granted........................ 307 12.25
Forfeited...................... (70) 8.79
Vested and released to
participants................ (37) 8.11
---
Outstanding at December 31,
2005........................... 969 8.88 1.0 $12
===
The weighted-average grant-date fair values of awards granted were as
follows for 2003, 2004 and 2005:
YEAR ENDED DECEMBER 31,
------------------------
2003 2004 2005
----- ------- ------
Options.................................................... $1.66 $ 1.86 $ --
Performance units.......................................... -- 100.00 --
Performance shares......................................... 5.70 -- 12.13
Time-based restricted stock................................ 5.83 10.95 12.25
76
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The total intrinsic value of awards received by participants were as
follows for 2003, 2004 and 2005:
YEAR ENDED DECEMBER 31,
-----------------------
2003 2004 2005
----- ----- -----
(IN MILLIONS)
Options exercised........................................... $-- $ 3 $ 8
Performance shares.......................................... -- 7 5
Time-based restricted stock................................. 5 -- --
As of December 31, 2005, there was $13 million of total unrecognized
compensation cost related to non-vested LICP arrangements. That cost is expected
to be recognized over a weighted-average period of 1.7 years.
Cash received from LICPs was $1 million, $4 million and $9 million for
2003, 2004 and 2005, respectively.
The actual tax benefit realized for tax deductions related to LICPs totaled
$2 million, $4 million and $5 million, for 2003, 2004 and 2005, respectively.
The Company has a policy of issuing new shares in order to satisfy
share-based payments related to LICPs.
PENSION AND POSTRETIREMENT BENEFITS
The Company maintains a non-contributory qualified defined benefit plan
covering substantially all employees, with benefits determined using a cash
balance formula. Under the cash balance formula, participants accumulate a
retirement benefit based upon 4% of eligible earnings and accrued interest.
Prior to 1999, the pension plan accrued benefits based on years of service,
final average pay and covered compensation. Certain employees participating in
the plan as of December 31, 1998 automatically receive the greater of the
accrued benefit calculated under the prior plan formula through 2008 or the cash
balance formula. Participants are 100% vested in their benefit after completing
five years of service.
The Company provides certain healthcare and life insurance benefits for
retired employees on a contributory and non-contributory basis. Employees become
eligible for these benefits if they have met certain age and service
requirements at retirement, as defined in the plans. Under plan amendments,
effective in early 1999, healthcare benefits for future retirees were changed to
limit employer contributions for medical coverage.
Such benefit costs are accrued over the active service period of employees.
The net unrecognized transition obligation, resulting from the implementation of
accrual accounting, is being amortized over approximately 20 years.
In January 2005, the Department of Health and Human Services' Centers for
Medicare and Medicaid Services released final regulations governing the Medicare
prescription drug benefit and other key elements of the Medicare Modernization
Act. Under the final regulations, a greater portion of benefits offered under
the Company's plans meets the definition of actuarial equivalence and therefore
qualifies for federal subsidies equal to 28% of allowable drug costs. As a
result, the Company has remeasured its obligations and costs to take into
account the new regulations. The Medicare subsidy reduced 2005's net periodic
postretirement benefit costs by approximately $8 million, including $3 million
of amortization of the actuarial loss, $2 million of reduced service cost and $3
million of reduced interest cost on the accumulated postretirement benefit
obligation.
77
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company's net periodic cost includes the following components relating
to pension and postretirement benefits:
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------------
2003 2004 2005
------------------------- ------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- -------------- -------- --------------
(IN MILLIONS)
Service cost....................... $ 37 $ 4 $ 40 $ 4 $ 34 $ 2
Interest cost...................... 102 31 102 31 95 27
Expected return on plan assets..... (92) (11) (103) (13) (137) (12)
Net amortization................... 43 13 37 13 38 9
Curtailment........................ -- -- -- 17 -- --
Benefit enhancement................ -- -- 4 2 -- --
Other.............................. -- -- -- -- -- 1
---- ---- ----- ---- ----- ----
Net periodic cost.................. $ 90 $ 37 $ 80 $ 54 $ 30 $ 27
==== ==== ===== ==== ===== ====
Above amounts include the following
net periodic cost related to
discontinued operations.......... $ 17 $ 4 $ 11 $ 20 $ -- $ --
==== ==== ===== ==== ===== ====
The Company used the following assumptions to determine net periodic cost
relating to pension and postretirement benefits:
DECEMBER 31,
---------------------------------------------------------------------------------
2003 2004 2005
------------------------- ------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- -------------- -------- --------------
Discount rate...................... 6.75% 6.75% 6.25% 6.25% 5.75% 5.75%
Expected return on plan assets..... 9.00 9.00 9.00 8.50 8.50 8.00
Rate of increase in compensation
levels........................... 4.10 -- 4.10 -- 4.60 --
In determining net periodic benefits cost, the Company uses fair value, as
of the beginning of the year, as its basis for determining expected return on
plan assets.
78
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table displays the change in the benefit obligation, the fair
value of plan assets and the amounts included in the Company's Consolidated
Balance Sheets as of December 31, 2004 and 2005 for the Company's pension and
postretirement benefit plans:
DECEMBER 31,
-----------------------------------------------------
2004 2005
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year............ $1,692 $ 518 $1,710 $ 535
Service cost..................................... 40 4 34 2
Interest cost.................................... 102 31 95 27
Participant contributions........................ -- 6 -- 5
Benefits paid.................................... (124) (42) (106) (38)
Plan amendments.................................. -- (20) -- --
Divestitures..................................... (165) -- -- --
Actuarial loss (gain)............................ 161 36 16 (65)
Curtailment, benefit enhancement and
settlement..................................... 4 2 -- 1
------ ----- ------ -----
Benefit obligation, end of year.................. $1,710 $ 535 $1,749 $ 467
====== ===== ====== =====
CHANGE IN PLAN ASSETS
Plan assets, beginning of year................... $1,194 $ 150 $1,657 $ 156
Employer contributions........................... 476 27 75 24
Participant contributions........................ -- 6 -- 5
Benefits paid.................................... (124) (42) (106) (38)
Divestitures..................................... (40) -- -- --
Actual investment return......................... 151 15 103 7
------ ----- ------ -----
Plan assets, end of year......................... $1,657 $ 156 $1,729 $ 154
====== ===== ====== =====
RECONCILIATION OF FUNDED STATUS
Funded status.................................... $ (53) $(379) $ (20) $(313)
Unrecognized actuarial loss...................... 714 96 719 36
Unrecognized prior service cost.................. (51) 14 (44) 12
Unrecognized transition obligation............... -- 65 -- 58
------ ----- ------ -----
Net amount recognized in balance sheets.......... $ 610 $(204) $ 655 $(207)
====== ===== ====== =====
ACTUARIAL ASSUMPTIONS
Discount rate.................................... 5.75% 5.75% 5.70% 5.70%
Expected return on plan assets................... 8.50 8.00 8.50 8.00
Rate of increase in compensation levels.......... 4.60 -- 4.60 --
Healthcare cost trend rate assumed for the next
year........................................... -- 9.75 -- 9.00
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate).............. -- 5.50 -- 5.50
Year that the rate reaches the ultimate trend
rate........................................... -- 2011 -- 2011
79
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31,
-------------------------------------------------------------
2004 2005
----------------------------- -----------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
------------ -------------- ------------ --------------
(IN MILLIONS)
ADDITIONAL INFORMATION
Accumulated benefit obligation........ $1,635 $535 $1,688 $467
Change in minimum liability included
in other comprehensive income....... (559) -- -- --
Measurement date used to determine
plan obligations and assets......... December 31, December 31, December 31, December 31,
2004 2004 2005 2005
Assumed healthcare cost trend rates have a significant effect on the
reported amounts for the Company's postretirement benefit plans. A 1% change in
the assumed healthcare cost trend rate would have the following effects:
1% 1%
INCREASE DECREASE
-------- --------
(IN MILLIONS)
Effect on total of service and interest cost................ $ 1 $ (1)
Effect on the postretirement benefit obligation............. 19 (16)
The following table displays the weighted-average asset allocations as of
December 31, 2004 and 2005 for the Company's pension and postretirement benefit
plans:
DECEMBER 31,
-----------------------------------------------------
2004 2005
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
Domestic equity securities............... 57% 34% 48% 27%
Global equity securities................. -- -- 10 --
International equity securities.......... 15 11 11 9
Debt securities.......................... 26 54 30 64
Real estate.............................. 2 -- 1 --
Cash..................................... -- 1 -- --
--- --- --- ---
Total.................................. 100% 100% 100% 100%
=== === === ===
In managing the investments associated with the benefit plans, the
Company's objective is to preserve and enhance the value of plan assets while
maintaining an acceptable level of volatility. These objectives are expected to
be achieved through an investment strategy that manages liquidity requirements
while maintaining a long-term horizon in making investment decisions and
efficient and effective management of plan assets.
80
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As part of the investment strategy discussed above, the Company has adopted
and maintains the following weighted average allocation targets for its benefit
plans:
PENSION POSTRETIREMENT
BENEFITS BENEFITS
-------- --------------
Domestic equity securities.................................. 45-55% 22-32%
Global equity securities.................................... 7-13% --
International equity securities............................. 7-13% 4-14%
Debt securities............................................. 24-34% 60-70%
Real estate................................................. 0-5% --
Cash........................................................ 0-2% 0-2%
The expected rate of return assumption was developed by reviewing the
targeted asset allocations and historical index performance of the applicable
asset classes over a 15-year period, adjusted for investment fees and
diversification effects.
The pension plan did not include any holdings of CenterPoint Energy common
stock as of December 31, 2004 or 2005.
Although funding for the Company's pension and postretirement plans was not
required during 2005, the Company contributed $75 million and $24 million to its
pension plan and postretirement benefits plan in 2005, respectively.
Contributions to the pension plan are not required in 2006; however, the
Company expects to make a contribution. The Company expects to contribute
approximately $26 million to its postretirement benefits plan in 2006.
The following benefit payments are expected to be paid by the pension and
postretirement benefit plans (in millions):
POSTRETIREMENT BENEFIT PLAN
---------------------------
MEDICARE
PENSION BENEFIT SUBSIDY
BENEFITS PAYMENTS RECEIPTS
-------- ---------- ----------
2006....................................... $104 $31 $ (4)
2007....................................... 108 32 (5)
2008....................................... 113 33 (5)
2009....................................... 118 35 (5)
2010....................................... 122 36 (5)
2011-2015.................................. 646 200 (31)
In addition to the non-contributory pension plans discussed above, the
Company maintains a non-qualified benefit restoration plan which allows
participants to retain the benefits to which they would have been entitled under
the Company's non-contributory pension plan except for the federally mandated
limits on qualified plan benefits or on the level of compensation on which
qualified plan benefits may be calculated. The expense associated with this
non-qualified plan was $8 million, $6 million and $6 million in 2003, 2004 and
2005, respectively. The accrued benefit liability for the non-qualified pension
plan was $69 million and $79 million at December 31, 2004 and 2005,
respectively. In addition, these accrued benefit liabilities include the
recognition of minimum liability adjustments of $10 million as of December 31,
2004 and $14 million as of December 31, 2005, which are reported as a component
of other comprehensive income, net of income tax effects.
81
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table displays the Company's plans that have or have had
accumulated benefit obligations in excess of plan assets:
DECEMBER 31,
---------------------------------------------------------------------------------
2004 2005
--------------------------------------- ---------------------------------------
PENSION RESTORATION POSTRETIREMENT PENSION RESTORATION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS
-------- ----------- -------------- -------- ----------- --------------
(IN MILLIONS)
Accumulated benefit
obligation................ $1,635 $69 $535 $1,688 $79 $467
Projected benefit
obligation................ 1,710 81 535 1,749 81 467
Plan assets................. 1,657 -- 156 1,729 -- 154
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 will be added to their qualified pension
plan benefit and three years of service will be added to their postretirement
benefit. The one-time additional pension and postretirement expense of
approximately $9 million will be reflected in the first quarter of 2006.
SAVINGS PLAN
The Company has a qualified employee savings plan that includes a cash or
deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986,
as amended (the Code), and an employee stock ownership plan (ESOP) under Section
4975(e)(7) of the Code. Under the plan, participating employees may contribute a
portion of their compensation, on a pre-tax or after-tax basis, generally up to
a maximum of 16% of compensation. The Company matches 75% of the first 6% of
each employee's compensation contributed. The Company may contribute an
additional discretionary match of up to 50% of the first 6% of each employee's
compensation contributed. These matching contributions are fully vested at all
times.
Participating employees may elect to invest all or a portion of their
contributions to the plan in CenterPoint Energy common stock, to have dividends
reinvested in additional shares or to receive dividend payments in cash on any
investment in CenterPoint Energy common stock, and to transfer all or part of
their investment in CenterPoint Energy common stock to other investment options
offered by the plan.
The savings plan has significant holdings of CenterPoint Energy common
stock. As of December 31, 2005, an aggregate of 27,720,006 shares of CenterPoint
Energy's common stock were held by the savings plan, which represented 28% of
its investments. Given the concentration of the investments in CenterPoint
Energy's common stock, the savings plan and its participants have market risk
related to this investment.
The Company's savings plan benefit expense was $38 million, $40 million and
$35 million in 2003, 2004 and 2005, respectively. Included in these amounts is
$7 million, $6 million and less than $1 million of savings plan benefit expense
for 2003, 2004 and 2005, respectively, related to Texas Genco participants.
Amounts for Texas Genco's participants are reflected as discontinued operations
in the Statements of Consolidated Operations.
POSTEMPLOYMENT BENEFITS
Net postemployment benefit costs for former or inactive employees, their
beneficiaries and covered dependents, after employment but before retirement
(primarily healthcare and life insurance benefits for participants in the
long-term disability plan) were $10 million, $8 million and $8 million in 2003,
2004 and 2005, respectively.
82
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Included in "Benefit Obligations" in the accompanying consolidated Balance
Sheets at December 31, 2004 and 2005 was $38 million and $42 million,
respectively, relating to postemployment obligations.
OTHER NON-QUALIFIED PLANS
The Company has non-qualified deferred compensation plans that provide
benefits payable to directors, officers and certain key employees or their
designated beneficiaries at specified future dates, upon termination, retirement
or death. Benefit payments are made from the general assets of the Company.
During 2003, 2004 and 2005, the Company recorded benefit expense relating to
these programs of $13 million, $9 million and $8 million, respectively. Included
in "Benefit Obligations" in the accompanying Consolidated Balance Sheets at
December 31, 2004 and 2005 was $121 million and $113 million, respectively,
relating to deferred compensation plans. Included in "Non-Current Liabilities of
Discontinued Operations" in the accompanying Consolidated Balance Sheets at
December 31, 2004 was $3 million relating to deferred compensation plans for
Texas Genco participants.
CHANGE OF CONTROL AGREEMENTS AND OTHER EMPLOYEE MATTERS
In December 2003, the Company entered into agreements with certain of its
executive officers that generally provide, to the extent applicable, in the case
of a change of control of the Company and termination of employment, for
severance benefits of up to three times annual base salary plus bonus and other
benefits. By their terms, these agreements will expire December 31, 2006.
As of December 31, 2005, approximately 30% of the Company's employees are
subject to collective bargaining agreements. Two of these agreements, covering
approximately 19% of the Company's employees, have expired or will expire in
2006. Minnesota Gas, a division of our natural gas distribution business, has
466 bargaining unit employees that are covered by a collective bargaining unit
agreement with the United Association of Journeymen and Apprentices of Plumbing
and Pipe Fitting Industry of US and Canada Local 340 that expires in April 2006.
CenterPoint Houston has 1225 bargaining unit employees that are covered by a
collective bargaining unit agreement with the International Brotherhood of
Electrical Workers Local 66, which expires in May 2006. The Company has a good
relationship with these bargaining units and expects to renegotiate new
agreements in 2006.
(3) DISCONTINUED OPERATIONS
Latin America. In February 2003, the Company sold its interest in Argener,
a cogeneration facility in Argentina, for $23 million. The carrying value of
this investment was approximately $11 million as of December 31, 2002. The
Company recorded an after-tax gain of $7 million from the sale of Argener in the
first quarter of 2003. In April 2003, the Company sold its final remaining
investment in Argentina, a 90 percent interest in Empresa Distribuidora de
Electricidad de Santiago del Estero S.A. The Company recorded an after-tax loss
of $3 million in the second quarter of 2003 related to its Latin America
operations.
Revenues related to the Company's Latin America operations included in
discontinued operations for the year ended December 31, 2003 were $2 million.
Income from these discontinued operations for the year ended December 31, 2003
is reported net of income tax expense of $2 million.
CenterPoint Energy Management Services, Inc. In November 2003, the Company
completed the sale of a component of its Other Operations business segment,
CenterPoint Energy Management Services, Inc. (CEMS), that provides district
cooling services in the Houston central business district and related
complementary energy services to district cooling customers and others. The
Company recorded an after-tax loss of $1 million from the sale of CEMS in the
fourth quarter of 2003. The Company recorded an after-tax loss in discontinued
operations of $16 million ($25 million pre-tax) during the second quarter of
2003 to
83
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
record the impairment of the CEMS long-lived assets based on the impending sale
and to record one-time employee termination benefits.
Revenues related to CEMS included in discontinued operations for the year
ended December 31, 2003 were $10 million. Loss from these discontinued
operations for the year ended December 31, 2003 is reported net of income tax
benefit of $2 million.
Texas Genco. In July 2004, the Company announced its agreement to sell
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's
principal remaining asset was its ownership interest in the South Texas Project
Electric Generating Station, a nuclear generating facility (South Texas
Project). The final step of the transaction, the merger of Texas Genco with a
subsidiary of Texas Genco LLC in exchange for an additional cash payment to the
Company of $700 million, was completed on April 13, 2005.
The following table summarizes the components of the income (loss) from
discontinued operations of Texas Genco for each of the years ended December 31,
2003, 2004 and 2005:
YEAR ENDED DECEMBER 31,
-------------------------
2003 2004 2005
------ ------- ------
(IN MILLIONS)
Texas Genco net income (loss) as reported................... $250 $ (99) $10
Adjustment for Texas Genco loss on sale of fossil assets,
net of tax(1)............................................. -- 426 --
---- ----- ---
Texas Genco net income as adjusted for loss on sale of
fossil assets............................................. 250 327 10
Adjustment for general corporate overhead reclassification,
net of tax(2)............................................. 18 13 1
Adjustment for interest expense reclassification, net of
tax(3).................................................... (129) (46) --
---- ----- ---
Adjusted income from discontinued operations of Texas Genco,
net of tax................................................ 139 294 11
Minority interest in discontinued operations of Texas
Genco..................................................... (48) (61) --
---- ----- ---
Income from discontinued operations of Texas Genco, net of
tax and minority interest................................. 91 233 11
---- ----- ---
Loss on sale of Texas Genco, net of tax..................... -- (214) (4)
Loss offsetting Texas Genco's earnings, net of tax.......... -- (152) (10)
---- ----- ---
Loss on disposal of Texas Genco, net of tax................. -- (366) (14)
---- ----- ---
Total Discontinued Operations of Texas Genco.............. $ 91 $(133) $(3)
==== ===== ===
---------------
(1) In 2004, Texas Genco recorded an after-tax loss of $426 million related to
the sale of its coal, lignite and gas-fired generation plants which occurred
in the first step of the transaction pursuant to which Texas Genco was sold.
This loss was reversed by CenterPoint Energy to reflect its estimated loss
on the sale of Texas Genco.
(2) General corporate overhead previously allocated to Texas Genco from
CenterPoint Energy, which will not be eliminated by the sale of Texas Genco,
was excluded from income from discontinued operations and is reflected as
general corporate overhead of CenterPoint Energy in income from continuing
operations in accordance with SFAS No. 144.
(3) Interest expense was reclassified to discontinued operations of Texas Genco
related to the applicable amounts of CenterPoint Energy's term loan and
revolving credit facility debt that would have been assumed to be paid off
with any proceeds from the sale of Texas Genco during those respective
periods in accordance with SFAS No. 144.
84
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revenues related to Texas Genco included in discontinued operations for the
years ended December 31, 2003, 2004 and 2005 were $2.0 billion, $2.1 billion and
$62 million, respectively. Income from these discontinued operations for the
years ended December 31, 2003, 2004 and 2005 is reported net of income tax
expense of $71 million, $166 million and $4 million, respectively.
Summarized balance sheet information as of December 31, 2004 related to
discontinued operations of Texas Genco is as follows:
DECEMBER 31,
2004
-------------
(IN MILLIONS)
CURRENT ASSETS:
Cash and cash equivalents................................. $ 43
Restricted cash........................................... 390
Accounts receivable, principally trade.................... 28
Other current assets...................................... 53
------
Total current assets................................... 514
------
NON-CURRENT ASSETS:
Funds held for purchase of additional interest in South
Texas Project.......................................... 191
Other non-current assets.................................. 860
------
Total non-current assets............................... 1,051
------
TOTAL ASSETS........................................... 1,565
------
CURRENT LIABILITIES:
Accounts payable, principally trade....................... 17
Payable to minority shareholders.......................... 390
Other current liabilities................................. 42
------
Total current liabilities.............................. 449
OTHER LONG-TERM LIABILITIES(1).............................. 420
------
TOTAL LIABILITIES...................................... 869
MINORITY INTEREST........................................... --
------
NET ASSETS OF DISCONTINUED OPERATIONS....................... $ 696
======
---------------
(1) Taxes payable resulting from the sale were paid by the Company, and were
included in current liabilities as of December 31, 2004.
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. Texas Genco used approximately $716 million of the cash
proceeds from the sale to repay an overnight bridge loan that Texas Genco had
entered into in order to finance the repurchase of Texas Genco's common stock
held by minority shareholders prior to the first step of the Texas Genco sale.
Texas Genco distributed the balance of the cash proceeds from the sale ($2.097
billion) and cash on hand ($134 million), for a total of $2.231 billion, to the
Company. Included in current assets of discontinued operations as of December
31, 2004 was $390 million of restricted cash designated to buy back the
remaining shares of Texas Genco's common stock which had not yet been tendered
by Texas Genco's former minority shareholders.
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 2004, Texas Genco owned a 30.8% interest in the South
Texas Project, which consists of two 1,250 megawatt nuclear generating units and
bore a corresponding 30.8% share of capital and operating costs associated with
the project. As of December 31, 2004, the South Texas Project was owned as a
tenancy in common among Texas Genco and three other co-owners, with each owner
retaining its undivided ownership interest in the two generating units and the
electrical output from those units. Texas Genco was severally liable, but not
jointly liable, for the expenses and liabilities of the South Texas Project.
Texas Genco and the three other co-owners organized the STP Nuclear Operating
Company (STPNOC) to operate and maintain the South Texas Project. STPNOC was
managed by a board of directors comprised of one director appointed by each of
the four co-owners, along with the chief executive officer of STPNOC. Texas
Genco's share of direct expenses of the South Texas Project was included in
discontinued operations in the Statements of Consolidated Operations. As of
December 31, 2004, Texas Genco's total utility plant for the South Texas Project
was $436 million (net of $2.3 billion accumulated depreciation, which includes
an impairment loss recorded in 1999 of $745 million). As of December 31, 2004,
Texas Genco's investment in nuclear fuel was $34 million (net of $334 million
amortization). These assets were included in non-current assets of discontinued
operations in the Consolidated Balance Sheets.
(4) REGULATORY MATTERS
(a) RECOVERY OF TRUE-UP BALANCE
The Texas Electric Choice Plan (Texas electric restructuring law), which
became effective in September 1999, substantially amended the regulatory
structure governing electric utilities in order to allow retail competition for
electric customers beginning in January 2002. The Texas electric restructuring
law requires the Texas Utility Commission to conduct a "true-up" proceeding to
determine CenterPoint Houston's stranded costs and certain other costs resulting
from the transition to a competitive retail electric market and to provide for
its recovery of those costs. In March 2004, CenterPoint Houston filed its
true-up application with the Texas Utility Commission, requesting recovery of
$3.7 billion, excluding interest. In December 2004, the Texas Utility Commission
issued its final order (True-Up Order) allowing CenterPoint Houston to recover a
true-up balance of approximately $2.3 billion, which included interest through
August 31, 2004, and providing for adjustment of the amount to be recovered to
include interest on the balance until recovery, the principal portion of
additional excess mitigation credits returned to customers after August 31, 2004
and certain other matters. CenterPoint Houston and other parties filed appeals
of the True-Up Order to a district court in Travis County, Texas. 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. First, the court reversed the Texas Utility Commission's decision to
prohibit CenterPoint Houston from recovering $180 million in credits through
August 2004 that CenterPoint Houston was ordered to provide to retail electric
providers as a result of an inaccurate stranded cost estimate made by the Texas
Utility Commission in 2000. Additional credits of approximately $30 million were
paid after August 2004. Second, the court reversed the Texas Utility
Commission's disallowance of $440 million in transition costs which are
recoverable under the Texas Utility Commission's regulations. 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 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 Texas Genco 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
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
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 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. During the period from September 13,
2005, the date of implementation of the CTC Order, through December 31, 2005,
CenterPoint Houston recognized approximately $21 million in CTC operating
income. Certain parties appealed the CTC Order to the Travis County Court in
September 2005.
Under the True-Up Order, CenterPoint Houston is allowed to recover carrying
charges at 11.075 percent until the true-up balance is recovered. The rate of
return is based on CenterPoint Houston's cost of capital, established in the
Texas Utility Commission's final order issued in October 2001, which is derived
from CenterPoint Houston's cost to finance assets (debt return) and an allowance
for earnings on shareholders' investment (equity return). Consequently, in
accordance with SFAS No. 92, "Regulated Enterprises -- Accounting for Phase-in
Plans," the rate of return has been bifurcated into a debt return component and
an equity return component. CenterPoint Houston was allowed a return on the
true-up balance of $222 million in 2005. Effective September 13, 2005, the date
of implementation of the CTC Order, the return on the CTC portion of the true-up
balance is included in CenterPoint Houston's tariff-based revenues. The debt
return of $121 million recorded in 2005 was accrued and included in other income
in the Company's Statements of Consolidated Operations. The equity return of
$101 million recorded in 2005 will be recognized in income as it is recovered in
the future. As of December 31, 2005, the Company has recorded a regulatory asset
of
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$347 million related to the debt return on its true-up balance and has not
recorded an allowed equity return of $248 million on its true-up balance because
such return will be recognized as it is recovered in the future.
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.
Net income for 2005 included an after-tax extraordinary gain of $30 million
($0.09 per diluted share) recorded in the second quarter reflecting an
adjustment to the after-tax extraordinary loss of $977 million ($2.72 per
diluted share) recorded in the last half of 2004 to write down
generation-related regulatory assets as a result of the final orders issued by
the Texas Utility Commission.
(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 court of appeals in June
2005. The parties have filed briefs on the issues with the court and are
awaiting a decision from the court of appeals.
(c) REMAND OF 2001 UNBUNDLED COST OF SERVICE ORDER
The 3rd Court of Appeals in Austin has 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 costs
associated with interconnection of a new merchant generating plant. The 3rd
Court of Appeals in Austin ordered the Texas Utility Commission to reconsider
that determination on the basis of the record that existed at the time of the
Commission's original order. The Company and CenterPoint Houston believe that
record is sufficient to support a determination by the Texas Utility Commission
that is consistent with its original determination. However, no prediction can
be made at this time as to the ultimate outcome of this matter on remand.
(d) RATE CASES
NATURAL GAS DISTRIBUTION
SOUTHERN GAS OPERATIONS
In November 2004, Southern Gas Operations filed an application for a $34
million base rate increase, which was subsequently adjusted downward to $28
million, with the Arkansas Public Service Commission (APSC). In September 2005,
an $11 million rate reduction (which included a $10 million reduction relating
to depreciation rates) ordered by the APSC went into effect. The reduced
depreciation rates were implemented effective October 2005. This base rate
reduction and corresponding reduction in depreciation expense represent an
annualized operating income reduction of $1 million.
In April 2005, the 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
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Beaumont/East Texas and South Texas Divisions. In June and August 2005, Southern
Gas Operations filed requests to implement these same rates within 169
incorporated cities located in the two divisions. The proposed rates were
approved or became effective by operation of law in 164 of these cities. Five
municipalities denied the rate change requests within their respective
jurisdictions. Southern Gas Operations has appealed the actions of these five
cities to the Railroad Commission. In February 2006, Southern Gas Operations
notified the Railroad Commission that it had reached a settlement with four of
the five cities. If approved, the settlement will affect rates in a total of 60
cities in the South Texas Division. In addition, 19 cities where rates have
already gone into effect have challenged the jurisdictional and statutory basis
for implementation of the new rates within their respective jurisdictions.
Southern Gas Operations has petitioned the Railroad Commission for an order
declaring that the new rates have been properly established within these 19
cities. If the settlement is approved and assuming all other rate change
proposals become effective, revenues from Southern Gas Operations' base rates
and miscellaneous service charges would increase by an additional $17 million
annually. Currently, approximately $15 million of this expected annual increase
is in effect in the incorporated areas of Southern Gas Operations' Beaumont/East
Texas and South Texas Divisions.
In October 2005, Southern Gas Operations filed requests with the Louisiana
Public Service Commission (LPSC) for approximately $2 million in base rate
increases for its South Louisiana service territory and approximately $2 million
in base rate reductions for its North Louisiana service territory in accordance
with the Rate Stabilization Plans in its tariffs. These base rate changes became
effective on January 2, 2006 in accordance with the tariffs and are subject to
review and possible adjustment by the staff of the LPSC. Southern Gas Operations
is unable to predict when the LPSC staff may conclude its review or what
adjustments, if any, the staff may recommend.
In December 2005, Southern Gas Operations filed a request with the
Mississippi Public Service Commission (MPSC) for approximately $1 million in
miscellaneous service charges (e.g., charges to connect service, charges for
returned checks, etc.) in its Mississippi service territory. This request was
approved in the first quarter of 2006.
In addition, in January and February 2006, Southern Gas Operations filed
requests with the MPSC for approximately $3 million in base rate increases in
its Mississippi service territory in accordance with the Automatic Rate
Adjustment Mechanism provisions in its tariffs and an additional $2 million in
surcharges to recover system restoration expenses incurred following hurricane
Katrina. Both requests are being reviewed by the MPSC staff with a decision
expected in the first quarter of 2006.
MINNESOTA GAS
In June 2005, the Minnesota Public Utilities Commission (MPUC) approved a
settlement which increased Minnesota Gas' base rates by approximately $9 million
annually. An interim rate increase of approximately $17 million had been
implemented in October 2004. Substantially all of the excess amounts collected
in interim rates over those approved in the final settlement were refunded to
customers in the third quarter of 2005.
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
decision by the MPUC is expected in the third quarter of 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
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
reconnection of customers during the Cold Weather Period. The Minnesota Office
of the Attorney General (OAG) issued its report alleging Minnesota Gas has
violated the CWR and recommended a $5 million penalty. Minnesota Gas and the OAG
have reached an agreement on procedures to be followed for the current Cold
Weather Period which began on October 15, 2005. 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. Minnesota Gas is in
settlement discussions regarding both the OAG's action and the action on behalf
of the purported class.
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 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.
(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 Court of Appeals.
(f) CITY OF HOUSTON FRANCHISE
CenterPoint Houston holds non-exclusive franchises from the incorporated
municipalities in its service territory. In exchange for payment of fees, these
franchises give CenterPoint Houston the right to use the streets and public
rights-of-way of these municipalities to construct, operate and maintain its
transmission and distribution system and to use that system to conduct its
electric delivery business and for other purposes that
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the franchises permit. The terms of the franchises, with various expiration
dates, typically range from 5 to 50 years.
In June 2005, CenterPoint Houston accepted an ordinance granting it a new
30-year franchise to use the public rights-of-way to conduct its business in the
City of Houston (New Franchise Ordinance). The New Franchise Ordinance took
effect on July 1, 2005, and replaced the prior electricity franchise ordinance,
which had been in effect since 1957. The New Franchise Ordinance clarifies
certain operational obligations of CenterPoint Houston and the City of Houston
and provides for streamlined payment and audit procedures and a two-year statute
of limitations on claims for underpayment or overpayment under the ordinance.
Under the prior electricity franchise ordinance, CenterPoint Houston paid annual
franchise fees of $76.6 million to the City of Houston for the year ended
December 31, 2004. For the twelve-month period beginning July 1, 2005, the
annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance
will include a base amount of $88.1 million (Base Amount) and an additional
payment of $8.5 million (Additional Amount). The Base Amount and the Additional
Amount will be adjusted annually based on the increase, if any, in kWh delivered
by CenterPoint Houston within the City of Houston.
CenterPoint Houston began paying the new annual franchise fees on July 1,
2005. Pursuant to the New Franchise Ordinance, the Annual Franchise Fee will be
reduced prospectively to reflect any portion of the Annual Franchise Fee that is
not included in CenterPoint Houston's base rates in any subsequent rate case.
(g) SETTLEMENT OF FERC AUDIT
In June 2005, CenterPoint Energy Gas Transmission Company (CEGT), a
subsidiary of CERC Corp., received an Order from the FERC accepting the terms of
a settlement agreed upon by CEGT with the Staff of the FERC's Office of Market
Oversight and Investigations (OMOI). The settlement brought to a conclusion an
investigation of CEGT initiated by OMOI in August 2003. Among other things, the
investigation involved a comprehensive review of CEGT's relationship with its
marketing affiliates and compliance with various FERC record-keeping and
reporting requirements covering the period from January 1, 2001 through
September 22, 2004.
OMOI Staff took the position that some of CEGT's actions resulted in a
limited number of violations of the FERC's affiliate regulations or were in
violation of certain record-keeping and administrative requirements. OMOI did
not find any systematic violations of its rules governing communications or
other relationships among affiliates.
The settlement included two remedies: a payment of a $270,000 civil penalty
and the execution of a compliance plan, applicable to both CEGT and CenterPoint
Energy-Mississippi River Transmission Corporation (MRT). The compliance plan
consists of a detailed set of Implementation Procedures that will facilitate
compliance with the FERC's Order No. 2004, the Standards of Conduct, which
regulate behavior between regulated entities and their affiliates. The Company
does not believe the compliance plan will have any material effect on CEGT's or
MRT's ability to conduct their business.
(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 2005, hedge ineffectiveness was a loss of $2
million from derivatives that qualify for and are designated as cash flow
hedges. No component of the derivative instruments' gain or loss
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
was excluded from the assessment of effectiveness. If it becomes probable that
an anticipated transaction will not occur, the Company realizes in net income
the deferred gains and losses recognized in accumulated other comprehensive
loss. Once the anticipated transaction occurs, the accumulated deferred gain or
loss recognized in accumulated other comprehensive loss is reclassified and
included in the Company's Statements of Consolidated Operations under the
caption "Natural Gas." Cash flows resulting from these transactions in
non-trading energy derivatives are included in the Statements of Consolidated
Cash Flows in the same category as the item being hedged. As of December 31,
2005, the Company expects $10 million in accumulated other comprehensive income
to be reclassified as a decrease in Natural Gas expense during the next twelve
months.
The maximum length of time the Company is hedging its exposure to the
variability in future cash flows on existing 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. The Company also has natural gas
contracts that are derivatives which are not hedged and are accounted for on a
mark-to-market basis with changes in fair value reported through earnings. Load
following services that the Company offers its natural gas customers create an
inherent tendency for the Company to be either long or short natural gas
supplies relative to customer purchase commitments. The Company measures and
values all of its volumetric imbalances on a real-time basis to minimize its
exposure to commodity price and volume risk. The Company does not engage in
proprietary or speculative commodity trading. Unhedged positions are accounted
for by adjusting the carrying amount of the contracts to market and recognizing
any gain or loss in operating income, net. During 2005, the Company recognized
net gains related to unhedged positions amounting to $8 million. As of December
31, 2004 and 2005, the Company had recorded short-term risk management assets of
$4 million and $28 million, respectively, and short-term risk management
liabilities of $5 million and $25 million, respectively, included in other
current assets and other current liabilities, respectively.
A portion of CenterPoint Energy Services, Inc.'s (CES) activities include
entering into transactions for the physical purchase, transportation and sale of
natural gas at different locations (physical contracts). CES attempts to
mitigate basis risk associated with these activities by entering into financial
derivative contracts (financial contracts or financial basis swaps) to address
market price volatility between the purchase and sale delivery points that can
occur over the term of the physical contracts. The underlying physical contracts
are accounted for on an accrual basis with all associated earnings not
recognized until the time of actual physical delivery. The timing of the
earnings impacts for the financial contracts differs from the physical contracts
because the financial contracts meet the definition of a derivative under SFAS
No. 133 and are recorded at fair value as of each reporting balance sheet date
with changes in value reported through earnings. Changes in prices between the
delivery points (basis spreads) can and do vary daily resulting in changes to
the fair value of the financial contracts. However, the economic intent of the
financial contracts is to fix the actual net difference in the natural gas
pricing at the different locations for the associated physical purchase and sale
contracts throughout the life of the physical contracts and thus, when combined
with the physical contracts' terms, provide an expected fixed gross margin on
the physical contracts that will ultimately be recognized in earnings at the
time of actual delivery of the natural gas. As of December 31, 2005, the
mark-to-market value of the financial contracts described above reflected an
unrealized loss of $1 million; however, the underlying expected fixed gross
margin associated with delivery under the physical contracts combined with the
price risk management provided through the financial contracts is expected to
offset the unrealized loss. As described above, over the term of these financial
contracts, the quarterly reported mark-to-market changes in value may vary
significantly and the associated unrealized gains and losses will be reflected
in CES' earnings.
CES also sells physical gas and basis to its end-use customers who desire
to lock in a future spread between a specific location and Henry Hub (NYMEX). As
a result, CES incurs exposure to commodity basis risk related to these
transactions, which it attempts to mitigate by buying offsetting financial basis
swaps.
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Under SFAS No. 133, CES records at fair value and marks-to-market the financial
basis swaps as of each reporting balance sheet date with changes in value
reported through earnings. However, the associated physical sales contracts are
accounted for using the accrual basis, whereby earnings impacts are not
recognized until the time of actual physical delivery. Although the timing of
earnings recognition for the financial basis swaps differs from the physical
contracts, the economic intent of the financial basis swaps is to fix the basis
spread over the life of the physical contracts to an amount substantially the
same as the portion of the basis spread pricing included in the physical
contracts. In so doing, over the period that the financial basis swaps and
related physical contracts are outstanding, actual cumulative earnings impacts
for changes in the basis spread should be minimal, even though from a timing
perspective there could be fluctuations in unrealized gains or losses associated
with the changes in fair value recorded for the financial basis swaps. The
cumulative earnings impact from the financial basis swaps recognized each
reporting period is expected to be offset by the value realized when the related
physical sales occur. As of December 31, 2005, the mark-to-market value of the
financial basis swaps reflected an unrealized loss of $3 million.
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 2003, 2004 and 2005, was $12 million, $25 million and $31
million, respectively.
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 December 31, 2005.
(b) CREDIT RISKS
In addition to the risk associated with price movements, credit risk is
also inherent in the Company's non-trading derivative activities. Credit risk
relates to the risk of loss resulting from non-performance of contractual
obligations by a counterparty. The following table shows the composition of the
non-trading derivative assets of the Company as of December 31, 2004 and 2005
(in millions):
DECEMBER 31, 2004 DECEMBER 31, 2005
------------------- -------------------
INVESTMENT INVESTMENT
GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL
----------- ----- ----------- -----
Energy marketers............................... $10 $17 $ 24 $ 25
Financial institutions......................... 50 50 208 208
Other.......................................... 1 1 -- 2
--- --- ---- ----
Total........................................ $61 $68 $232 $235
=== === ==== ====
---------------
(1) "Investment grade" is primarily determined using publicly available credit
ratings along with the consideration of credit support (such as parent
company guarantees) and collateral, which encompass cash and standby letters
of credit.
(2) For unrated counterparties, the Company performs financial statement
analysis, considering contractual rights and restrictions and collateral, to
create a synthetic credit rating.
(c) GENERAL POLICY
The Company has established a Risk Oversight Committee composed of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including the Company's trading,
93
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
marketing, risk management services and hedging activities. The committee's
duties are to establish the Company's commodity risk policies, allocate risk
capital within limits established by the Company's board of directors, approve
trading of new products and commodities, monitor risk positions and ensure
compliance with the Company's risk management policies and procedures and
trading limits established by the Company's board of directors.
The Company's policies prohibit the use of leveraged financial instruments.
A leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.
(6) INDEXED DEBT SECURITIES (ZENS) AND TIME WARNER SECURITIES
(a) ORIGINAL INVESTMENT IN TIME WARNER SECURITIES
In 1995, the Company sold a cable television subsidiary to Time Warner Inc.
(TW) and received TW convertible preferred stock (TW Preferred) as partial
consideration. On July 6, 1999, the Company converted its 11 million shares of
TW Preferred into 45.8 million shares of TW common stock (TW Common). The
Company currently owns 21.6 million shares of TW Common. Unrealized gains and
losses resulting from changes in the market value of the TW Common are recorded
in the Company's Statements of Consolidated Operations.
(b) ZENS
In September 1999, the Company issued its 2.0% Zero-Premium Exchangeable
Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0
billion. ZENS are exchangeable for cash equal to the market value of a specified
number of shares of TW common. The Company pays interest on the ZENS at an
annual rate of 2% plus the amount of any quarterly cash dividends paid in
respect of the shares of TW Common attributable to the ZENS. The principal
amount of ZENS is subject to being increased or decreased to the extent that the
annual yield from interest and cash dividends on the reference shares of TW
Common is less than or more than 2.309%. At December 31, 2005, ZENS having an
original principal amount of $840 million and a contingent principal amount of
$851 million were outstanding and were exchangeable, at the option of the
holders, for cash equal to 95% of the market value of 21.6 million shares of TW
Common deemed to be attributable to the ZENS. At December 31, 2005, the market
value of such shares was approximately $377 million, which would provide an
exchange amount of $427 for each $1,000 original principal amount of ZENS. At
maturity, the holders of the ZENS will receive in cash the higher of the
original principal amount of the ZENS (subject to adjustment as discussed above)
or an amount based on the then-current market value of TW Common, or other
securities distributed with respect to TW Common.
In 2002, holders of approximately 16% of the 17.2 million ZENS originally
issued exercised their right to exchange their ZENS for cash, resulting in
aggregate cash payments by CenterPoint Energy of approximately $45 million.
Exchanges of ZENS subsequent to 2002 aggregate less than one percent of ZENS
originally issued.
A subsidiary of the Company owns shares of TW Common and elected to
liquidate a portion of such holdings to facilitate the Company's making the cash
payments for the ZENS exchanged in 2002 through 2004. In connection with the
exchanges, the Company received net proceeds of approximately $43 million from
the liquidation of approximately 4.1 million shares of TW Common at an average
price of $10.56 per share. The Company now holds 21.6 million shares of TW
Common which are classified as trading securities under SFAS No. 115 and are
expected to be held to facilitate the Company's ability to meet its obligation
under the ZENS.
Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS
obligation was bifurcated into a debt component and a derivative component (the
holder's option to receive the appreciated value of
94
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
TW Common at maturity). The derivative component was valued at fair value and
determined the initial carrying value assigned to the debt component ($121
million) as the difference between the original principal amount of the ZENS ($1
billion) and the fair value of the derivative component at issuance ($879
million). Effective January 1, 2001 the debt component was recorded at its
accreted amount of $122 million and the derivative component was recorded at its
fair value of $788 million, as a current liability. Subsequently, the debt
component accretes through interest charges at 17.5% annually up to the minimum
amount payable upon maturity of the ZENS in 2029 (approximately $913 million
assuming no dividends are paid on the TW Common subsequent to 2005) which
reflects exchanges and adjustments to maintain a 2.309% annual yield, as
discussed above. Changes in the fair value of the derivative component are
recorded in the Company's Statements of Consolidated Operations. During 2003,
2004 and 2005, the Company recorded a gain (loss) of $106 million, $31 million
and $(44) million, respectively, on the Company's investment in TW Common.
During 2003, 2004 and 2005, the Company recorded a gain (loss) of $(96) million,
$(20) million and $49 million, respectively, associated with the fair value of
the derivative component of the ZENS obligation. Changes in the fair value of
the TW Common held by the Company are expected to substantially offset changes
in the fair value of the derivative component of the ZENS.
The following table sets forth summarized financial information regarding
the Company's investment in TW common and the Company's ZENS obligation (in
millions):
DEBT DERIVATIVE
TW COMPONENT COMPONENT
INVESTMENT OF ZENS OF ZENS
---------- --------- ----------
Balance at December 31, 2002......................... $284 $104 $225
Accretion of debt component of ZENS.................. -- 1 --
Loss on indexed debt securities...................... -- -- 96
Gain on TW Common.................................... 106 -- --
---- ---- ----
Balance at December 31, 2003......................... 390 105 321
Accretion of debt component of ZENS.................. -- 2 --
Loss on indexed debt securities...................... -- -- 20
Gain on TW Common.................................... 31 -- --
---- ---- ----
Balance at December 31, 2004......................... 421 107 341
Accretion of debt component of ZENS.................. -- 2 --
Gain on indexed debt securities...................... -- -- (49)
Loss on TW Common.................................... (44) -- --
---- ---- ----
Balance at December 31, 2005......................... $377 $109 $292
==== ==== ====
(7) EQUITY
(a) 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.
(b) SHAREHOLDER RIGHTS PLAN
The Company has a Shareholder Rights Plan that states that each share of
its common stock includes one associated preference stock purchase right (Right)
which entitles the registered holder to purchase from the Company a unit
consisting of one-thousandth of a share of Series A Preference Stock. The
Rights, which
95
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
expire on December 11, 2011, are exercisable upon some events involving the
acquisition of 20% or more of the Company's outstanding common stock. Upon the
occurrence of such an event, each Right entitles the holder to receive common
stock with a current market price equal to two times the exercise price of the
Right. At anytime prior to becoming exercisable, the Company may repurchase the
Rights at a price of $0.005 per Right. There are 700,000 shares of Series A
Preference Stock reserved for issuance upon exercise of the Rights.
(8) LONG-TERM DEBT AND RECEIVABLES FACILITY
DECEMBER 31, 2004 DECEMBER 31, 2005
---------------------- ----------------------
LONG-TERM CURRENT(1) LONG-TERM CURRENT(1)
--------- ---------- --------- ----------
(IN MILLIONS)
Long-term debt:
CenterPoint Energy:
ZENS(2)......................................... $ -- $ 107 $ -- $109
Senior notes 5.875% to 7.25% due 2008 to 2015... 600 -- 600 --
Convertible senior notes 2.875% to 3.75% due
2023 to 2024................................. 830 -- 830 --
Pollution control bonds 5.60% to 6.70% due 2012
to 2027(3)................................... 151 -- 151 --
Pollution control bonds 4.70% to 8.00% due 2011
to 2030(4)................................... 1,046 -- 1,046 --
Bank loans and commercial paper due 2006 to
2010(5)...................................... 239 -- 3 --
Junior subordinated debentures payable to
affiliate 8.257% due 2037(6)................. 103 -- 103 --
CenterPoint Houston:
First mortgage bonds 9.15% due 2021............. 102 -- 102 --
Term loan, LIBOR plus 9.75%(7).................. -- 1,310 -- --
General mortgage bonds 5.60% to 6.95% due 2013
to 2033...................................... 1,262 -- 1,262 --
Pollution control bonds 3.625% to 5.60% due 2012
to 2027(8)................................... 229 -- 229 --
Series 2001-1 Transition Bonds 3.84% to 5.63%
due 2006 to 2013............................. 629 47 575 54
Series A Transition Bonds 4.84% to 5.30% due
2006 to 2019................................. -- -- 1,832 19
CERC Corp.:
Convertible subordinated debentures 6.00% due
2012......................................... 69 6 63 6
Senior notes 5.95% to 8.90% due 2006 to 2014.... 1,923 325 1,772 148
Junior subordinated debentures payable to
affiliate 6.25% due 2026(6).................. 6 -- -- --
Other............................................. 5 41 2 3
Unamortized discount and premium(9)............... (1) -- (2) --
------ ------ ------ ----
Total long-term debt......................... $7,193 $1,836 $8,568 $339
====== ====== ====== ====
96
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
---------------
(1) Includes amounts due, exchangeable or scheduled to be paid within one year
of the date noted.
(2) Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's ZENS
obligation was bifurcated into a debt component and an embedded derivative
component. For additional information regarding ZENS, see Note 6(b). As ZENS
are exchangeable for cash at any time at the option of the holders, these
notes are classified as a current portion of long-term debt.
(3) These series of debt are secured by first mortgage bonds of CenterPoint
Houston.
(4) $527 million of these series of debt is secured by general mortgage bonds of
CenterPoint Houston.
(5) Classified as long-term debt because the termination dates of the facilities
under which the funds were borrowed are more than one year from the date
noted.
(6) The junior subordinated debentures were issued to subsidiary trusts in
connection with the issuance by those trusts of preferred securities. The
trust preferred securities were deconsolidated effective December 31, 2003
pursuant to the adoption of FIN 46. This resulted in the junior subordinated
debentures held by the trusts being reported as long-term debt.
(7) London inter-bank offered rate (LIBOR) had a minimum rate of 3% under the
terms of this debt. This term loan was secured by general mortgage bonds of
CenterPoint Houston.
(8) These series of debt are secured by general mortgage bonds of CenterPoint
Houston.
(9) Debt acquired in business acquisitions is adjusted to fair market value as
of the acquisition date. Included in long-term debt is additional
unamortized premium related to fair value adjustments of long-term debt of
$5 million at both December 31, 2004 and 2005, which is being amortized over
the respective remaining term of the related long-term debt.
(a) LONG-TERM DEBT
Revolving Credit Facilities. In March 2005, the Company replaced its $750
million revolving credit facility with a $1 billion five-year revolving credit
facility. Borrowings may be made under the facility at LIBOR plus 87.5 basis
points based on current credit ratings. An additional utilization fee of 12.5
basis points applies to borrowings whenever more than 50% of the facility is
utilized. Changes in credit ratings could lower or raise the increment to LIBOR
depending on whether ratings improved or were lowered. As of December 31, 2005,
borrowings of $3 million in commercial paper were backstopped by the revolving
credit facility and $27 million in letters of credit were outstanding under the
revolving credit facility.
Also, in March 2005, CenterPoint Houston established a $200 million
five-year revolving credit facility. Borrowings may be made under the facility
at LIBOR plus 75 basis points based on CenterPoint Houston's current credit
ratings. An additional utilization fee of 12.5 basis points applies to
borrowings whenever more than 50% of the facility is utilized. Changes in credit
ratings could lower or raise the increment to LIBOR depending on whether ratings
improved or were lowered. As of December 31, 2005, there were $4 million in
letters of credit outstanding under the revolving credit facility.
In June 2005, CERC Corp. replaced its $250 million three-year revolving
credit facility with a $400 million five-year revolving credit facility.
Borrowings under this facility may be made at LIBOR plus 55 basis points,
including the facility fee, based on current credit ratings. An additional
utilization fee of 10 basis points applies to borrowings whenever more than 50%
of the facility is utilized. Changes in credit ratings could lower or raise the
increment to LIBOR depending on whether ratings improved or were lowered. As of
December 31, 2005, such credit facility was not utilized.
The bank facilities contain various business and financial covenants with
which the borrowers were in compliance as of December 31, 2005. CenterPoint
Houston's credit facility limits CenterPoint Houston's debt, excluding
transition bonds, as a percentage of its total capitalization to 68 percent.
CERC Corp.'s bank facility and its receivables facility limit CERC's debt as a
percentage of its total capitalization to 65 percent.
97
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Transition Bonds. 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.
Scheduled payment dates range from August 2006 to August 2019. 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. The proceeds received from the
issuance of the transition bonds were used to repay CenterPoint Houston's $1.3
billion credit facility, which was utilized in November 2005 to repay
CenterPoint Houston's $1.3 billion term loan upon its maturity.
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, initially at a conversion rate of 86.3558
shares of common stock per $1,000 principal amount of notes at any time prior to
maturity, under the following circumstances: (1) if the last reported sale price
of CenterPoint Energy common stock for at least 20 trading days during the
period of 30 consecutive trading days ending on the last trading day of the
previous calendar quarter is greater than or equal to 120% or, following May 15,
2008, 110% of the conversion price per share of CenterPoint Energy common stock
on such last trading day, (2) if the notes have been called for redemption, (3)
during any period in which the credit ratings assigned to the notes by both
Moody's Investors Service, Inc. (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. 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.
The Company commenced the exchange offer in response to the guidance set forth
in EITF Issue No. 04-8, "Accounting Issues Related to Certain Features of
Contingently Convertible Debt and the Effect on Diluted Earnings Per Share"
(EITF 04-8). Under that guidance, because settlement of the principal portion of
the New Notes will be made in cash rather than stock, the exchange of New Notes
for Old Notes will allow the Company to exclude the portion of the conversion
value of the New Notes attributable to their principal amount from its
computation of diluted earnings per share from continuing operations. See Note
12 for the impact on diluted earnings per share related to these securities. The
Company determined that the New Notes did not have substantially different terms
than the Old Notes, and thus, in accordance with EITF Issue No. 96-19 "Debtor's
Accounting for a Modification or Exchange of Debt Instruments", the exchange
98
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
transaction was accounted for as a modification of the original instrument and
not as an extinguishment of debt. Accordingly, a new effective interest rate was
determined based on the carrying amount of the original debt instrument and the
revised cash flows, and the recorded discount will be amortized as an adjustment
to interest expense in future periods.
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, initially at a conversion rate of 78.064 shares of common
stock per $1,000 principal amount of notes at any time prior to maturity, under
the following circumstances: (1) if the last reported sale price of CenterPoint
Energy common stock for at least 20 trading days during the period of 30
consecutive trading days ending on the last trading day of the previous calendar
quarter is greater than or equal to 120% of the conversion price per share of
CenterPoint Energy common stock on such last trading day, (2) if the notes have
been called for redemption, (3) during any period in which the credit ratings
assigned to the notes by both Moody's and S&P are lower than Ba2 and BB,
respectively, or the notes are no longer rated by at least one of these ratings
services or their successors, or (4) upon the occurrence of specified corporate
transactions, including the distribution to all holders of CenterPoint Energy
common stock of certain rights entitling them to purchase shares of CenterPoint
Energy common stock at less than the last reported sale price of a share of
CenterPoint Energy common stock on the trading day prior to the declaration date
of the distribution or the distribution to all holders of CenterPoint Energy
common stock of the Company's assets, debt securities or certain rights to
purchase the Company's securities, which distribution has a per share value
exceeding 15% of the last reported sale price of a share of CenterPoint Energy
common stock on the trading day immediately preceding the declaration date for
such distribution. 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 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. 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, 2004 and 2005.
The junior subordinated debentures are the trust's sole assets and their
entire operations. CenterPoint Energy considers its obligations under the
Amended and Restated Declaration of Trust, Indenture, Guaranty Agreement and,
where applicable, Agreement as to Expenses and Liabilities, relating to the
capital securities, taken together, to constitute a full and unconditional
guarantee by CenterPoint Energy of the trust's obligations with respect to the
capital securities.
The capital securities are mandatorily redeemable upon the repayment of the
related series of junior subordinated debentures at their stated maturity or
earlier redemption. Subject to some limitations, CenterPoint Energy has the
option of deferring payments of interest on the junior subordinated debentures.
99
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During any deferral or event of default, CenterPoint Energy may not pay
dividends on its capital stock. As of December 31, 2005, no interest payments on
the junior subordinated debentures had been deferred.
The outstanding aggregate liquidation amount, distribution rate and
mandatory redemption date of the capital securities of the trust described above
and the identity and similar terms of the related series of junior subordinated
debentures are as follows:
AGGREGATE
LIQUIDATION
AMOUNTS AS OF DISTRIBUTION MANDATORY
DECEMBER 31, RATE/ REDEMPTION
------------- INTEREST DATE/
TRUST 2004 2005 RATE MATURITY DATE JUNIOR SUBORDINATED DEBENTURES
----- ----- ----- ------------ ------------- ------------------------------
(IN MILLIONS)
HL&P Capital Trust II.... $100 $100 8.257% February 2037 8.257% Junior Subordinated
Deferrable Interest Debentures
Series B
In June 1996, a Delaware statutory business trust created by CERC Corp.
(CERC Trust) issued $173 million aggregate amount of convertible preferred
securities to the public. CERC Trust used the proceeds of the offering to
purchase convertible junior subordinated debentures issued by CERC Corp. having
an interest rate and maturity date that correspond to the distribution rate and
mandatory redemption date of the convertible preferred securities. The
convertible junior subordinated debentures represented CERC Trust's sole asset
and its entire operations. The $6 million of outstanding junior subordinated
debentures was included in long-term debt as of December 31, 2004. The
convertible preferred securities and the related convertible junior subordinated
debentures were redeemed on August 1, 2005.
Maturities. The Company's maturities of long-term debt (including
scheduled payments on transition bonds), capital leases and sinking fund
requirements, excluding the ZENS obligation, are $230 million in 2006, $153
million in 2007, $666 million in 2008, $181 million in 2009 and $400 million in
2010.
Liens. As of December 31, 2005, CenterPoint Houston's assets were subject
to liens securing approximately $253 million of first mortgage bonds. Sinking or
improvement fund and replacement fund requirements on the first mortgage bonds
may be satisfied by certification of property additions. Sinking fund and
replacement fund requirements for 2003, 2004 and 2005 have been satisfied by
certification of property additions. The replacement fund requirement to be
satisfied in 2006 is approximately $151 million, and the sinking fund
requirement to be satisfied in 2006 is approximately $3 million. The Company
expects CenterPoint Houston to meet these 2006 obligations by certification of
property additions. As of December 31, 2005, CenterPoint Houston's assets were
also subject to liens securing approximately $2.0 billion of general mortgage
bonds which are junior to the liens of the first mortgage bonds.
(b) RECEIVABLES FACILITY
In January 2006, CERC's $250 million receivables facility, which 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, was extended to January 2007. As of December 31, 2005, CERC had $141
million of advances under its receivables facility.
Advances under the receivables facility averaged $100 million, $190 million
and $166 million in 2003, 2004 and 2005, respectively. Sales of receivables were
approximately $1.2 billion, $2.4 billion and $2.0 billion in 2003, 2004 and
2005, respectively.
100
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(9) INCOME TAXES
The Company's current and deferred components of income tax expense
(benefit) were as follows:
YEAR ENDED DECEMBER 31,
-----------------------
2003 2004 2005
------ ------ -----
(IN MILLIONS)
Current:
Federal................................................... $(301) $(130) $(74)
State..................................................... 5 11 2
----- ----- ----
Total current.......................................... (296) (119) (72)
----- ----- ----
Deferred:
Federal................................................... 487 264 208
State..................................................... 14 (6) 17
----- ----- ----
Total deferred......................................... 501 258 225
----- ----- ----
Income tax expense.......................................... $ 205 $ 139 $153
===== ===== ====
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
YEAR ENDED DECEMBER 31,
------------------------
2003 2004 2005
------ ------ ------
(IN MILLIONS)
Income from continuing operations before income taxes and
extraordinary item........................................ $614 $344 $378
Federal statutory rate...................................... 35% 35% 35%
---- ---- ----
Income taxes at statutory rate.............................. 215 120 132
---- ---- ----
Net addition (reduction) in taxes resulting from:
State income taxes, net of valuation allowances and
federal income tax benefit............................. 12 3 13
Amortization of investment tax credit..................... (8) (8) (8)
Excess deferred taxes..................................... (4) (4) (3)
Deferred tax asset write-off.............................. -- 19 --
Increase in tax reserve................................... -- 7 32
Other, net................................................ (10) 2 (13)
---- ---- ----
Total.................................................. (10) 19 21
---- ---- ----
Income tax expense.......................................... $205 $139 $153
==== ==== ====
Effective rate.............................................. 33.4% 40.4% 40.6%
101
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Following are the Company's tax effects of temporary differences between
the carrying amounts of assets and liabilities in the financial statements and
their respective tax bases:
DECEMBER 31,
---------------
2004 2005
------ ------
(IN MILLIONS)
Deferred tax assets:
Current:
Allowance for doubtful accounts........................ $ 13 $ 20
Regulatory liabilities................................. 79 --
Non-trading derivative assets, net..................... 28 16
------ ------
Total current deferred tax assets.................... 120 36
------ ------
Non-current:
Loss carryforwards..................................... 30 26
Deferred gas costs..................................... 69 59
Other.................................................. 98 102
------ ------
Total non-current deferred tax assets before
valuation allowance................................. 197 187
------ ------
Valuation allowance.................................... (20) (21)
------ ------
Total non-current deferred tax assets................ 177 166
------ ------
Total deferred tax assets, net....................... 297 202
------ ------
Deferred tax liabilities:
Current:
Unrealized gain on indexed debt securities............. 287 348
Unrealized gain on Time Warner investments............. 94 73
------ ------
Total current deferred tax liabilities............... 381 421
------ ------
Non-current:
Depreciation........................................... 1,709 1,432
Regulatory assets, net................................. 748 1,076
Employee benefits...................................... 38 52
Other.................................................. 97 80
------ ------
Total non-current deferred tax liabilities........... 2,592 2,640
------ ------
Total deferred tax liabilities....................... 2,973 3,061
------ ------
Accumulated deferred income taxes, net............ $2,676 $2,859
====== ======
Tax Attribute Carryforwards. Based on returns filed the Company has $239
million of state net operating loss carryforwards. The losses are available to
offset future state taxable income through the year 2024. Substantially all of
the state loss carryforwards will expire between 2012 and 2020. A valuation
allowance has been established against approximately 58% of the state net
operating loss carryforwards.
The valuation allowance reflects a net decrease of $53 million in 2004 and
an increase of $1 million in 2005. The net changes resulted from a reassessment
of the Company's ability to use federal capital loss and state net operating
loss carryforwards in 2004 and state net operating loss carryforwards, in 2005.
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Tax Refunds. In 2004, the Company received a refund from the IRS of $163
million, related to the carryback of the federal tax net operating loss
generated in 2003.
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) and interest paid relating to the
Company's 2.0% ZENS, due 2029, and 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 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 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 $79 million and $121 million as of December 31, 2004 and
2005, 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 $74 million and $60 million as of December 31, 2004 and 2005,
respectively.
(10) COMMITMENTS AND CONTINGENCIES
(a) FUEL COMMITMENTS
Fuel commitments include natural gas contracts related to the Company's
natural gas distribution and competitive natural gas sales and services
operations, which have various quantity requirements and durations that are not
classified as non-trading derivatives assets and liabilities in the Company's
Consolidated Balance Sheets as of December 31, 2005 as these contracts meet the
SFAS No. 133 exception to be classified as "normal purchases contracts" or do
not meet the definition of a derivative. Minimum payment obligations for natural
gas supply contracts are approximately $858 million in 2006, $375 million in
2007, $53 million in 2008, $4 million in 2009, $3 million in 2010 and $23
million in 2011 and thereafter.
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(b) LEASE COMMITMENTS
The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases at December 31,
2005, which primarily consist of rental agreements for building space, data
processing equipment and vehicles (in millions):
2006........................................................ $20
2007........................................................ 18
2008........................................................ 14
2009........................................................ 7
2010........................................................ 4
2011 and beyond............................................. 22
---
Total..................................................... $85
===
Total lease expense for all operating leases was $35 million, $32 million
and $37 million during 2003, 2004 and 2005, respectively.
(c) CAPITAL COMMITMENTS
In October 2005, CEGT signed a firm transportation agreement with XTO
Energy 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 is in the process of filing applications for certificates
with the FERC to build a 172 mile, 42-inch diameter pipeline, and related
compression facilities at an estimated cost of $400 million. The final capacity
of the pipeline will be between 960 MMcf per day and 1.24 billion cubic feet per
day. CEGT expects to have firm contracts for the full capacity of the pipeline
prior to its expected in service date in early 2007. 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.
(d) 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
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 California state court 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
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
breaches of contracts to supply power to governmental entities. Plaintiffs in
these lawsuits, which include state officials and governmental entities as well
as private litigants, are seeking a variety of forms of relief, including
recovery of compensatory damages (in some cases in excess of $1 billion), a
trebling of compensatory damages and punitive damages, injunctive relief,
restitution, interest due, disgorgement, civil penalties and fines, costs of
suit, attorneys' fees and divestiture of assets. The Company's former
subsidiary, RRI, was a participant in the California markets, owning generating
plants in the state and participating in both electricity and natural gas
trading in that state and in western power markets generally.
The Company 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 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 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. 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. A number of class action lawsuits filed in
2002 on behalf of purchasers of securities of RRI and/or Reliant Energy were
consolidated in federal district court in Houston. The consolidated complaint
named RRI, certain of its current and former executive officers, Reliant Energy,
the underwriters of the initial public offering of RRI's common stock in May
2001 (RRI Offering), and RRI's and Reliant Energy's independent auditors as
defendants. The complaint sought monetary relief on behalf of purchasers of
common stock of Reliant Energy or RRI during certain time periods ranging from
February 2000 to May 2002, and purchasers of common stock that could be traced
to the RRI Offering. The plaintiffs alleged, among other things, that the
defendants misrepresented revenues and trading volumes by engaging in round-trip
trades and improperly accounted for certain structured transactions as cash-flow
hedges, which resulted in earnings from these transactions being accounted for
as future earnings rather than being accounted for as earnings in fiscal year
2001. In July 2005, the parties announced that they had reached agreement on a
settlement of this matter, and in January 2006, following a hearing, the trial
judge approved that settlement and dismissed this matter. The terms of the
settlement do not require payment by the Company.
In May 2002, three class action lawsuits were filed in federal district
court in Houston on behalf of participants in various employee benefits plans
sponsored by the Company. Two of the lawsuits were dismissed
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
Texas Antitrust Actions. In July 2003, Texas Commercial Energy filed in
federal court in Corpus Christi, Texas a lawsuit against Reliant Energy, the
Company and CenterPoint Houston, as successors to Reliant Energy, Genco LP, RRI,
Reliant Energy Solutions, LLC, several other RRI subsidiaries and a number of
other participants in the Electric Reliability Council of Texas (ERCOT) power
market. The plaintiff, a retail electricity provider with the ERCOT market,
alleged that the defendants conspired to illegally fix and artificially increase
the price of electricity in violation of state and federal antitrust laws and
committed fraud and negligent misrepresentation. The lawsuit sought damages in
excess of $500 million, exemplary damages, treble damages, interest, costs of
suit and attorneys' fees. The plaintiff's principal allegations had previously
been investigated by the Texas Utility Commission and found to be without merit.
In June 2004, the federal court dismissed the plaintiff's claims and the
plaintiff appealed to the U.S. Fifth Circuit Court of Appeals, which affirmed
the dismissal. The plaintiff then sought review by the U.S. Supreme Court in a
petition for certiorari which was denied. Thus, this matter has now been finally
resolved in favor of the defendants.
In February 2005, Utility Choice Electric filed in federal court in
Houston, Texas a lawsuit against the Company, CenterPoint Houston, CenterPoint
Energy Gas Services, Inc., CenterPoint Energy Alternative Fuels, Inc., Genco LP
and a number of other participants in the ERCOT power market. The plaintiff, a
retail electricity provider in the ERCOT market, alleged that the defendants
conspired to illegally fix and artificially increase the price of electricity in
violation of state and federal antitrust laws, intentionally interfered with
prospective business relationships and contracts, and committed fraud and
negligent misrepresentation. The plaintiff's principal allegations had
previously been investigated by the Texas Utility Commission and found to be
without merit. In December 2005, the district court judge granted the
defendants' motion to dismiss the complaint. Subsequently, a settlement was
reached under which the CenterPoint Energy entities have been fully released
from all claims without the payment of any settlement amount by the Company.
Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton,
Galveston and Pasadena (Three Cities) filed suit in state district court in
Harris County, Texas for themselves and a proposed class of all similarly
situated cities in Reliant Energy's electric service area, against Reliant
Energy and Houston Industries Finance, Inc. (formerly a wholly owned subsidiary
of the Company's predecessor, Reliant Energy) alleging underpayment of municipal
franchise fees. After a jury trial involving the Three Cities' claims (but not
the class of cities), and a subsequent appeal, a state court of appeals in
Houston rendered an opinion that the Three Cities should take nothing by their
claims. The Texas Supreme Court declined further review. Thus, the Three Cities'
claims have been finally resolved in the Company's favor. Individual claims of
the remaining 45 cities were filed in the state district court and remain
pending before that same court. Other than the City of Houston nonsuiting its
claim in February 2006, there has been no activity on these claims since the
Texas Supreme Court declined further review of the Three Cities' claims. The
Company does not expect the
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
outcome of the remaining claims to have a material impact on its financial
condition, results of operations or cash flows.
Natural Gas Measurement Lawsuits. CERC Corp. and certain of its
subsidiaries are defendants in a suit filed in 1997 under the Federal False
Claims Act alleging mismeasurement of natural gas produced from federal and
Indian lands. The suit seeks undisclosed damages, along with statutory
penalties, interest, costs, and fees. The complaint is part of a larger series
of complaints filed against 77 natural gas pipelines and their subsidiaries and
affiliates. An earlier single action making substantially similar allegations
against the pipelines was dismissed by the federal district court for the
District of Columbia on grounds of improper joinder and lack of jurisdiction. As
a result, the various individual complaints were filed in numerous courts
throughout the country. This case has been consolidated, together with the other
similar False Claims Act cases, in the federal district court in Cheyenne,
Wyoming.
In addition, CERC Corp. and certain of its subsidiaries are defendants in
two mismeasurement lawsuits brought against approximately 245 pipeline companies
and their affiliates pending in state court in Stevens County, Kansas. In one
case (originally filed in May 1999 and amended four times), the plaintiffs
purport to represent a class of royalty owners who allege that the defendants
have engaged in systematic mismeasurement of the volume of natural gas for more
than 25 years. The plaintiffs amended their petition in this suit in July 2003
in response to an order from the judge denying certification of the plaintiffs'
alleged class. In the amendment the plaintiffs dismissed their claims against
certain defendants (including two CERC subsidiaries), limited the scope of the
class of plaintiffs they purport to represent and eliminated previously asserted
claims based on mismeasurement of the Btu content of the gas. The same
plaintiffs then filed a second lawsuit, again as representatives of a class of
royalty owners, in which they assert their claims that the defendants have
engaged in systematic mismeasurement of the Btu content of natural 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
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 and of the capitalized portion through
rates.
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 period between October 15 and April 15 (Cold
Weather Period) are in compliance with the MPUC's Cold Weather Rule (CWR), which
governs disconnection and reconnection of customers during the Cold Weather
Period. The Minnesota Office of the Attorney General (OAG) issued its report
alleging Minnesota Gas has violated the CWR and recommended a $5 million
penalty. Minnesota Gas and the OAG have reached an agreement on procedures to be
followed for the current Cold Weather Period which began on October 15, 2005. 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. Minnesota Gas is in settlement discussions regarding both the OAG's
action and the action on behalf of the purported class. The Company and CERC do
not expect the outcome of this matter to have a material impact on the financial
condition, results of operations or cash flows of either the Company or CERC.
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, unspecified alleged personal injuries,
alleged fear of cancer, alleged property damage or
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
diminution of value of their property, and, in addition, seek damages for
trespass, punitive, and exemplary damages. The Company does not expect the
ultimate cost associated with resolving this matter to have a material impact on
the financial condition, results of operations or cash flows of either the
Company or CERC.
Manufactured Gas Plant Sites. CERC and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed
remediation on two sites, other than ongoing monitoring and water treatment.
There are five remaining sites in CERC's Minnesota service territory. CERC
believes that it has no liability with respect to two of these sites.
At December 31, 2005, CERC had accrued $14 million for remediation of these
Minnesota sites. At December 31, 2005, 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 December 31, 2005, 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.
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 cannot be 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's
subsidiaries but currently owned by Texas Genco LLC. The Company anticipates
that additional claims like those received may be asserted in
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the future. Under the terms of the separation agreement between the Company and
Texas Genco, ultimate financial responsibility for uninsured losses from claims
relating to facilities transferred to Texas Genco has been assumed by Texas
Genco, but under the terms of its agreement to sell Texas Genco to Texas Genco
LLC, the Company has agreed to continue to defend such claims to the extent they
are covered by insurance maintained by the Company, subject to reimbursement of
the costs of such defense from Texas Genco LLC. Although their ultimate outcome
cannot be predicted at this time, the Company intends to continue vigorously
contesting claims that it does not consider to have merit and does not expect,
based on its experience to date, these matters, either individually or in the
aggregate, to have a material adverse effect on the Company's financial
condition, results of operations or cash flows.
Other Environmental. From time to time the Company has received notices
from regulatory authorities or others regarding its status as a PRP in
connection with sites found to require remediation due to the presence of
environmental contaminants. In addition, the Company has been named from time to
time as a defendant in litigation related to such sites. Although the ultimate
outcome of such matters cannot be predicted at this time, the Company does not
expect, based on its experience to date, these matters, either individually or
in the aggregate, to have a material adverse effect on the Company's financial
condition, results of operations or cash flows.
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.
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 alternatives. RRI continues to meet its obligations under the
transportation contracts.
TEXAS GENCO MATTERS
CenterPoint Houston, as collection agent for the nuclear decommissioning
charge assessed on its transmission and distribution customers, transferred $2.9
million in 2003 and 2004 and $3.2 million in 2005 to trusts established to fund
Texas Genco's share of the decommissioning costs for the South Texas Project.
There are various investment restrictions imposed upon Texas Genco by the Texas
Utility Commission and
110
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Nuclear Regulatory Commission relating to Texas Genco's nuclear
decommissioning trusts. Pursuant to the provisions of both a separation
agreement and the Texas Utility Commission's final order, CenterPoint Houston
and Texas Genco are presently jointly administering the decommissioning funds
through the Nuclear Decommissioning Trust Investment Committee. Texas Genco and
CenterPoint Houston have each appointed two members to the Nuclear
Decommissioning Trust Investment Committee which establishes the investment
policy of the trusts and oversees the investment of the trusts' assets. As
administrators of the decommissioning funds, CenterPoint Houston and Texas Genco
are jointly responsible for assuring that the funds are prudently invested in a
manner consistent with the rules of the Texas Utility Commission. On February 2,
2006, CenterPoint Houston and Texas Genco filed a request with the Texas Utility
Commission to name Texas Genco as the sole fund administrator. Pursuant to the
Texas electric restructuring law, costs associated with nuclear decommissioning
that were not recovered as of January 1, 2002, will continue to be subject to
cost-of-service rate regulation and will be charged to transmission and
distribution customers of CenterPoint Houston or its successor.
(11) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair values of cash and cash equivalents, investments in debt and
equity securities classified as "available-for-sale" and "trading" in accordance
with SFAS No. 115, and short-term borrowings are estimated to be approximately
equivalent to carrying amounts and have been excluded from the table below. The
fair values of non-trading derivative assets and liabilities are equivalent to
their carrying amounts in the Consolidated Balance Sheets at December 31, 2004
and 2005 and have been determined using quoted market prices for the same or
similar instruments when available or other estimation techniques (see Note 5).
Therefore, these financial instruments are stated at fair value and are excluded
from the table below.
DECEMBER 31, 2004 DECEMBER 31, 2005
----------------- -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ------ -------- ------
(IN MILLIONS)
Financial liabilities:
Long-term debt.................................. $8,913 $9,601 $8,794 $9,277
111
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(12) EARNINGS PER SHARE
The following table reconciles numerators and denominators of the Company's
basic and diluted earnings (loss) per share calculations:
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------------
2003 2004 2005
--------------- --------------- ---------------
(IN MILLIONS, EXCEPT PER SHARE AND SHARE AMOUNTS)
Basic earnings (loss) per share calculation:
Income from continuing operations before
extraordinary item............................ $ 409 $ 205 $ 225
Income (loss) from discontinued operations, net
of tax........................................ 75 (133) (3)
Extraordinary item, net of tax................... -- (977) 30
------------ ------------ ------------
Net income (loss)................................ $ 484 $ (905) $ 252
============ ============ ============
Weighted average shares outstanding................ 303,867,000 307,185,000 309,349,000
Basic earnings (loss) per share:
Income from continuing operations before
extraordinary item............................ $ 1.35 $ 0.67 $ 0.72
Income (loss) from discontinued operations, net
of tax........................................ 0.24 (0.43) (0.01)
Extraordinary item, net of tax................... -- (3.18) 0.10
------------ ------------ ------------
Net income (loss)................................ $ 1.59 $ (2.94) $ 0.81
============ ============ ============
Diluted earnings (loss) per share calculation:
Net income (loss)................................ $ 484 $ (905) $ 252
Plus: Income impact of assumed conversions:
Interest on 3.75% contingently convertible
senior notes................................ 9 14 9
Interest on 6.25% convertible trust preferred
securities.................................. -- -- --
------------ ------------ ------------
Total earnings effect assuming dilution.......... $ 493 $ (891) $ 261
============ ============ ============
Weighted average shares outstanding................ 303,867,000 307,185,000 309,349,000
Plus: Incremental shares from assumed
conversions:
Stock options(1).............................. 851,000 1,203,000 1,241,000
Restricted stock.............................. 1,484,000 1,447,000 1,851,000
3.75% contingently convertible senior notes... 30,745,000 49,655,000 33,587,000
6.25% convertible trust preferred
securities.................................. 18,000 16,000 --
------------ ------------ ------------
Weighted average shares assuming dilution........ 336,965,000 359,506,000 346,028,000
============ ============ ============
Diluted earnings (loss) per share:
Income from continuing operations before
extraordinary item............................ $ 1.24 $ 0.61 $ 0.67
Income (loss) from discontinued operations, net
of tax........................................ 0.22 (0.37) (0.01)
Extraordinary item, net of tax................... -- (2.72) 0.09
------------ ------------ ------------
Net income (loss)................................ $ 1.46 $ (2.48) $ 0.75
============ ============ ============
112
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
---------------
(1) Options to purchase 10,106,673, 11,892,508 and 8,677,660 shares were
outstanding for the years ended December 31, 2003, 2004 and 2005,
respectively, but were not included in the computation of diluted earnings
(loss) per share because the options' exercise price was greater than the
average market price of the common shares for the respective years.
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 8) provide for settlement of the principal portion in cash
rather than stock, the Company excludes the portion of the conversion value of
these notes attributable to their principal amount from its computation of
diluted earnings per share from continuing operations. The Company includes the
conversion spread in the calculation of diluted earnings per share when the
average market price of the Company's common stock in the respective reporting
period exceeds the conversion price. The conversion prices for the 2.875% and
the 3.75% contingently convertible senior notes are $12.81 and $11.58,
respectively.
(13) UNAUDITED QUARTERLY INFORMATION
The consolidated financial statements for 2004 and 2005 have been prepared
to reflect the sale of Texas Genco as described in Note 3. Accordingly, the
consolidated financial statements present the Texas Genco business as
discontinued operations, in accordance with SFAS No. 144.
Summarized quarterly financial data is as follows:
YEAR ENDED DECEMBER 31, 2004
-----------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues.......................................... $2,402 $1,593 $ 1,567 $2,437
Operating income.................................. 240 186 207 231
Income (loss) from continuing operations.......... 29 (3) 17 162
Discontinued operations, net of tax............... 45 60 (259) 21
Extraordinary item, net of tax.................... -- -- (894) (83)
------ ------ ------- ------
Net income (loss)................................. $ 74 $ 57 $(1,136) $ 100
====== ====== ======= ======
Basic earnings (loss) per share:(1)
Income (loss) from continuing operations........ $ 0.09 $(0.01) $ 0.05 $ 0.53
Discontinued operations, net of tax............. 0.15 0.20 (0.84) 0.07
Extraordinary item, net of tax.................. -- -- (2.90) (0.27)
------ ------ ------- ------
Net income (loss)............................... $ 0.24 $ 0.19 $ (3.69) $ 0.33
====== ====== ======= ======
Diluted earnings (loss) per share:(1)
Income (loss) from continuing operations........ $ 0.09 $(0.01) $ 0.05 $ 0.46
Discontinued operations, net of tax............. 0.13 0.20 (0.83) 0.06
Extraordinary item, net of tax.................. -- -- (2.88) (0.23)
------ ------ ------- ------
Net income (loss)............................... $ 0.22 $ 0.19 $ (3.66) $ 0.29
====== ====== ======= ======
113
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED DECEMBER 31, 2005
-----------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues........................................... $2,595 $1,842 $2,073 $3,212
Operating income................................... 276 186 225 252
Income from continuing operations.................. 67 27 50 81
Discontinued operations, net of tax................ -- (3) -- --
Extraordinary item, net of tax..................... -- 30 -- --
------ ------ ------ ------
Net income......................................... $ 67 $ 54 $ 50 $ 81
====== ====== ====== ======
Basic earnings (loss) per share:(1)
Income from continuing operations................ $ 0.22 $ 0.09 $ 0.16 $ 0.26
Discontinued operations, net of tax.............. -- (0.01) -- --
Extraordinary item, net of tax................... -- 0.10 -- --
------ ------ ------ ------
Net income....................................... $ 0.22 $ 0.18 $ 0.16 $ 0.26
====== ====== ====== ======
Diluted earnings (loss) per share:(1)
Income from continuing operations................ $ 0.20 $ 0.09 $ 0.15 $ 0.25
Discontinued operations, net of tax.............. -- (0.01) -- --
Extraordinary item, net of tax................... -- 0.08 -- --
------ ------ ------ ------
Net income....................................... $ 0.20 $ 0.16 $ 0.15 $ 0.25
====== ====== ====== ======
---------------
(1) Quarterly earnings per common share are based on the weighted average number
of shares outstanding during the quarter, and the sum of the quarters may
not equal annual earnings per common share. The Company's 3.75% contingently
convertible notes are not included in the calculation of diluted earnings
per share during the first three quarters of 2004 as they were anti-dilutive
due to lower income from continuing operations in these periods. However,
the 3.75% contingently convertible notes are included in the calculation of
diluted earnings per share for the fourth quarter of 2004, and the first and
second quarters of 2005, as they are dilutive. In the third quarter of 2005,
the Company modified approximately $572 million of the 3.75% contingently
convertible senior notes to provide for settlement of the principal portion
in cash rather than stock. Accordingly, the Company excludes the portion of
the conversion value of these notes and the 2.875% contingently convertible
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.
(14) REPORTABLE BUSINESS SEGMENTS
The Company's determination of reportable business segments considers the
strategic operating units under which the Company manages sales, allocates
resources and assesses performance of various products and services to wholesale
or retail customers in differing regulatory environments. The accounting
policies of the business segments are the same as those described in the summary
of significant accounting policies except that some executive benefit costs have
not been allocated to business segments. The Company uses operating income as
the measure of profit or loss for its business segments.
The Company's reportable business segments include the following: Electric
Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas
Sales and Services, Pipelines and Field Services
114
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(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. The Company's Latin America operations and
its energy management services business, which were previously reported in the
Other Operations business segment, are presented as discontinued operations
within these consolidated financial statements. Additionally, the Company's
generation operations, which were previously reported in the Electric Generation
business segment, are presented as discontinued operations within these
consolidated financial statements. All prior period segment information has been
reclassified to conform to the 2005 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):
ELECTRIC COMPETITIVE PIPELINES
TRANSMISSION NATURAL NATURAL GAS AND
& GAS SALES AND FIELD OTHER DISCONTINUED RECONCILING
DISTRIBUTION DISTRIBUTION SERVICES SERVICES OPERATIONS OPERATIONS ELIMINATIONS CONSOLIDATED
------------ ------------ ----------- --------- ---------- ------------ ------------ ------------
AS OF AND FOR THE
YEAR ENDED
DECEMBER 31,
2003:
Revenues from
external
customers(1).... $ 2,124(2) $3,389 $2,017(3) $ 244(4) $ 16 $ -- $ -- $ 7,790
Intersegment
revenues........ -- -- 215 163 12 -- (390) --
Depreciation and
amortization.... 270 135 1 40 20 -- -- 466
Operating income
(loss).......... 1,020 157 45 158 (25) -- -- 1,355
Total assets...... 10,387 4,031 825 2,519 1,746 4,244 (2,291) 21,461
Expenditures for
long-lived
assets.......... 218 198 1 66 14 162 -- 659
AS OF AND FOR THE
YEAR ENDED
DECEMBER 31,
2004:
Revenues from
external
customers....... $ 1,521(2) $3,577 $2,593(3) $ 306(4) $ 2 $ -- $ -- $ 7,999
Intersegment
revenues........ -- 2 255 145 6 -- (408) --
Depreciation and
amortization.... 284 141 2 44 19 -- -- 490
Operating income
(loss).......... 494 178 44 180 (32) -- -- 864
Extraordinary
item, net of
tax............. 977 -- -- -- -- -- -- 977
Total assets...... 8,783 4,083 964 2,637 2,794(5) 1,565 (2,730) 18,096
Expenditures for
long-lived
assets.......... 235 196 1 73 25 74 -- 604
115
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ELECTRIC COMPETITIVE PIPELINES
TRANSMISSION NATURAL NATURAL GAS AND
& GAS SALES AND FIELD OTHER DISCONTINUED RECONCILING
DISTRIBUTION DISTRIBUTION SERVICES SERVICES OPERATIONS OPERATIONS ELIMINATIONS CONSOLIDATED
------------ ------------ ----------- --------- ---------- ------------ ------------ ------------
AS OF AND FOR THE
YEAR ENDED
DECEMBER 31,
2005:
Revenues from
external
customers....... $ 1,644(2) $3,837 $3,884 $ 346 $ 11 $ -- $ -- $ 9,722
Intersegment
revenues........ -- 9 245 147 8 -- (409) --
Depreciation and
amortization.... 322 152 2 45 20 -- -- 541
Operating income
(loss).......... 487 175 60 235 (18) -- -- 939
Extraordinary
item, net of
tax............. (30) -- -- -- -- -- -- (30)
Total assets...... 8,227 4,612 1,849 2,968 2,202(5) -- (2,742) 17,116
Expenditures for
long-lived
assets.......... 281 249 12 156 21 9 -- 728
---------------
(1) Revenues from external customers for the Electric Transmission &
Distribution business segment include ECOM revenues of $661 million for
2003.
(2) Sales to subsidiaries of RRI in 2003, 2004 and 2005 represented
approximately $948 million, $882 million and $812 million, respectively, of
CenterPoint Houston's transmission and distribution revenues.
(3) Sales to Texas Genco in 2003 and 2004 represented approximately $28 million
and $20 million, respectively, of the Competitive Natural Gas Sales and
Services business segment's revenues from external customers. Texas Genco
has been presented as discontinued operations in these consolidated
financial statements.
(4) Sales to Texas Genco in 2003 and 2004 represented approximately $3 million
and $2 million, respectively, of the Pipelines and Field Services business
segment's revenues from external customers. Texas Genco has been presented
as discontinued operations in these consolidated financial statements.
(5) Included in total assets of Other Operations as of December 31, 2004 and
2005 is a pension asset of $610 million and $654 million, respectively. See
Note 2(o) for further discussion.
YEAR ENDED DECEMBER 31,
------------------------
2003 2004 2005
------ ------ ------
(IN MILLIONS)
Revenues by Products and Services:
Electric delivery sales.................................... $1,463 $1,521 $1,644
ECOM revenue............................................... 661 -- --
Retail gas sales........................................... 3,954 4,239 4,871
Wholesale gas sales........................................ 1,064 1,526 2,410
Gas transport.............................................. 537 613 684
Energy products and services............................... 111 100 113
------ ------ ------
Total.................................................... $7,790 $7,999 $9,722
====== ====== ======
(15) SUBSEQUENT EVENT
On January 26, 2006, the Company's board of directors declared a regular
quarterly cash dividend of $0.15 per share of common stock payable on March 10,
2006, to shareholders of record as of the close of business on February 16,
2006.
116
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
DISCLOSURE 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 December 31, 2005 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.
"Management's Annual Report on Internal Control over Financial Reporting"
appears on page 118 of this annual report on Form 10-K. In December 2005, the
Company determined that, during 2004 and 2005, certain transactions involving
purchases and sales of natural gas among divisions within its Natural Gas
Distribution and Competitive Natural Gas Sales and Services segments were not
properly eliminated in the consolidated financial statements. Consequently,
revenues and natural gas expenses during the year ended December 31, 2004 were
each overstated by approximately $511 million and during the nine months ended
September 30, 2005 were each overstated by approximately $402 million.
Management concluded that a restatement of the 2004 consolidated financial
statements and the 2005 interim consolidated financial statements was necessary
to correct this error. In connection with the discovery of the error described
above and the conclusion that the Company had a material weakness in its
internal control over financial reporting related to ineffective controls over
the process of eliminating certain interdivision purchases and sales of natural
gas within its Natural Gas Distribution and Competitive Natural Gas Sales and
Services segments in the consolidation process, the Company improved procedures
related to the recording and reporting of purchases and sales of natural gas
during the three months ended December 31, 2005, including increased review and
approval controls by senior financial personnel over the personnel that prepare
the accruals and enhanced analysis of the recorded activity, including ensuring
that intercompany activity is properly eliminated in consolidation. Management
believes these changes remediated the material weakness in internal control over
financial reporting referenced above as of December 31, 2005.
117
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate
internal control over financial reporting. Internal control over financial
reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the
Securities Exchange Act of 1934 as a process designed by, or under the
supervision of, the company's principal executive and principal financial
officers and effected by the company's board of directors, management and other
personnel, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles and
includes those policies and procedures that:
- Pertain to the maintenance of records that in reasonable detail
accurately and fairly reflect the transactions and dispositions of the
assets of the company;
- Provide reasonable assurance that transactions are recorded as necessary
to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and
- Provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of the company's assets that
could have a material effect on the financial statements.
Management has designed its internal control over financial reporting to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements in accordance with accounting
principles generally accepted in the United States of America. Management's
assessment included review and testing of both the design effectiveness and
operating effectiveness of controls over all relevant assertions related to all
significant accounts and disclosures in the financial statements.
All internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentation. Projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, we
conducted an evaluation of the effectiveness of our internal control over
financial reporting based on the framework in Internal Control -- Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on our evaluation under the framework in Internal
Control -- Integrated Framework, our management has concluded that our internal
control over financial reporting was effective as of December 31, 2005.
Deloitte & Touche LLP, the Company's independent registered public
accounting firm, has issued an attestation report on our management's assessment
of the effectiveness of our internal control over financial reporting as of
December 31, 2005 which is included herein on page 119.
118
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
CenterPoint Energy, Inc.
Houston, Texas
We have audited management's assessment, included in the accompanying
Management's Annual Report on Internal Control Over Financial Reporting, that
CenterPoint Energy, Inc. and subsidiaries (the "Company") maintained effective
internal control over financial reporting as of December 31, 2005, based on the
criteria established in Internal Control -- Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. The Company's
management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the Company's
internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinions.
A company's internal control over financial reporting is a process designed
by, or under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, management's assessment that the Company maintained
effective internal control over financial reporting as of December 31, 2005, is
fairly stated, in all material respects, based on the criteria established in
Internal Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2005, based on the criteria established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
119
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated financial
statements as of and for the year ended December 31, 2005 of the Company and our
report dated March 15, 2006 expressed an unqualified opinion on those financial
statements and included an explanatory paragraph regarding the Company's
adoption of a new accounting standard related to conditional asset retirement
obligations.
DELOITTE & TOUCHE LLP
Houston, Texas
March 15, 2006
ITEM 9B. OTHER INFORMATION
None.
120
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
The information called for by Item 10, to the extent not set forth in
"Executive Officers" in Item 1, is or will be set forth in the definitive proxy
statement relating to CenterPoint Energy's 2006 annual meeting of shareholders
pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a
meeting of shareholders involving the election of directors and the portions
thereof called for by Item 10 are incorporated herein by reference pursuant to
Instruction G to Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by Item 11 is or will be set forth in the
definitive proxy statement relating to CenterPoint Energy's 2006 annual meeting
of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 11 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information called for by Item 12 is or will be set forth in the
definitive proxy statement relating to CenterPoint Energy's 2006 annual meeting
of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 12 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by Item 13 is or will be set forth in the
definitive proxy statement relating to CenterPoint Energy's 2006 annual meeting
of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 13 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information called for by Item 14 is or will be set forth in the
definitive proxy statement relating to CenterPoint Energy's 2006 annual meeting
of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 14 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.
121
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements.
Report of Independent Registered Public Accounting Firm... 59
Statements of Consolidated Operations for the Three Years
Ended December 31, 2005................................ 60
Statements of Consolidated Comprehensive Income for the
Three Years Ended December 31, 2005.................... 61
Consolidated Balance Sheets at December 31, 2004 and
2005................................................... 62
Statements of Consolidated Cash Flows for the Three Years
Ended December 31, 2005................................ 63
Statements of Consolidated Shareholders' Equity for the
Three Years Ended December 31, 2005.................... 64
Notes to Consolidated Financial Statements................ 65
(a)(2) Financial Statement Schedules for the Three Years Ended December
31, 2005.
Report of Independent Registered Public Accounting Firm... 123
I -- Condensed Financial Information of CenterPoint
Energy, Inc. (Parent Company).......................... 124
II -- Qualifying Valuation Accounts....................... 130
The following schedules are omitted because of the absence of the
conditions under which they are required or because the required information is
included in the financial statements:
III, IV and V.
(a)(3) Exhibits.
See Index of Exhibits beginning on page 133, which index also includes the
management contracts or compensatory plans or arrangements required to be filed
as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.
122
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
CenterPoint Energy, Inc.
Houston, Texas
We have audited the consolidated financial statements of CenterPoint
Energy, Inc. and subsidiaries (the "Company") as of December 31, 2005 and 2004,
and for each of the three years in the period ended December 31, 2005, and have
issued our report thereon dated March 15, 2006 (which report expresses an
unqualified opinion and includes an explanatory paragraph relating to the
Company's adoption of a new accounting standard for conditional asset retirement
obligations). We have also audited management's assessment of the effectiveness
of the Company's internal control over financial reporting as of December 31,
2005 and the effectiveness of the Company's internal control over financial
reporting as of December 31, 2005, and have issued our report thereon dated
March 15, 2006; such reports are included elsewhere in this Form 10-K. Our
audits also included the consolidated financial statement schedules the Company
listed in the index at Item 15 (a)(2). These consolidated financial statement
schedules are the responsibility of the Company's management. Our responsibility
is to express an opinion based on our audits. In our opinion, such consolidated
financial statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present fairly, in all
material respects, the information set forth therein.
DELOITTE & TOUCHE LLP
Houston, Texas
March 15, 2006
123
CENTERPOINT ENERGY, INC.
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF
CENTERPOINT ENERGY, INC. (PARENT COMPANY)
STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2003 2004 2005
------ ------- ------
(IN MILLIONS)
Equity Income of Subsidiaries............................... $851 $ 707 $425
Interest Income from Subsidiaries........................... 63 21 15
Loss on Disposal of Subsidiary.............................. -- (366) (14)
Gain (Loss) on Indexed Debt Securities...................... (96) (20) 49
Operation and Maintenance Expenses.......................... (13) (21) (29)
Depreciation and Amortization............................... (14) -- --
Taxes Other than Income..................................... (5) -- --
Interest Expense to Subsidiaries............................ (93) (80) (61)
Interest Expense............................................ (394) (303) (204)
Income Tax Benefit.......................................... 185 134 41
Extraordinary Item, net of tax.............................. -- (977) 30
---- ----- ----
Net Income (Loss)........................................... $484 $(905) $252
==== ===== ====
See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8
124
CENTERPOINT ENERGY, INC.
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF
CENTERPOINT ENERGY, INC. (PARENT COMPANY)
BALANCE SHEETS
DECEMBER 31,
---------------
2004 2005
------ ------
(IN MILLIONS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ -- $ 1
Notes receivable -- subsidiaries.......................... 126 460
Accounts receivable -- subsidiaries....................... 30 22
Other assets.............................................. 2 3
------ ------
Total current assets................................... 158 486
------ ------
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 6 --
------ ------
OTHER ASSETS:
Investment in subsidiaries................................ 6,032 5,225
Notes receivable -- subsidiaries.......................... 321 172
Other assets.............................................. 675 714
------ ------
Total other assets..................................... 7,028 6,111
------ ------
TOTAL ASSETS......................................... $7,192 $6,597
====== ======
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable -- subsidiaries............................. $ 127 $ 5
Current portion of long-term debt......................... 107 109
Indexed debt securities derivative........................ 342 292
Accounts payable:
Subsidiaries........................................... 37 30
Other.................................................. 5 4
Taxes accrued............................................. 811 698
Interest accrued.......................................... 26 26
Other..................................................... 14 22
------ ------
Total current liabilities.............................. 1,469 1,186
------ ------
OTHER LIABILITIES:
Accumulated deferred tax liabilities...................... 433 328
Benefit obligations....................................... 54 78
Notes payable -- subsidiaries............................. 1,167 923
Other..................................................... 98 157
------ ------
Total non-current liabilities.......................... 1,752 1,486
------ ------
LONG-TERM DEBT.............................................. 2,865 2,629
------ ------
SHAREHOLDERS' EQUITY:
Common stock.............................................. 3 3
Additional paid-in capital................................ 2,891 2,931
Accumulated deficit....................................... (1,728) (1,600)
Accumulated other comprehensive loss...................... (60) (38)
------ ------
Total shareholders' equity............................. 1,106 1,296
------ ------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY........... $7,192 $6,597
====== ======
See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8
125
CENTERPOINT ENERGY, INC.
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF
CENTERPOINT ENERGY, INC. (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED
DECEMBER 31,
-------------------------
2003 2004 2005
------- ------- -----
(IN MILLIONS)
OPERATING ACTIVITIES:
Net income (loss)......................................... $ 484 $ (905) $ 252
Loss on disposal of subsidiary............................ -- 366 14
Extraordinary item, net of tax............................ -- 977 (30)
------- ------- -----
Adjusted income........................................... 484 438 236
Non-cash items included in net income (loss):
Equity income of subsidiaries........................... (850) (707) (425)
Deferred income tax expense............................. 66 155 106
Depreciation and amortization........................... 14 -- --
Amortization of debt issuance costs..................... 112 70 37
Loss (gain) on indexed debt securities.................. 96 20 (49)
Changes in working capital:
Accounts receivable/(payable) from subsidiaries, net.... 89 (6) 1
Accounts payable........................................ 4 (1) (1)
Other current assets.................................... (3) (5) (1)
Other current liabilities............................... (43) (290) (73)
Common stock dividends received from subsidiaries......... 122 177 508
Pension contribution...................................... (23) (476) (75)
Other..................................................... 95 54 77
------- ------- -----
Net cash provided by (used in) operating activities......... 163 (571) 341
------- ------- -----
INVESTING ACTIVITIES:
Proceeds from sale of Texas Genco......................... -- 2,231 700
Distributions from (investments in) subsidiaries.......... 33 19 (144)
Short-term notes receivable from subsidiaries............. 290 76 (335)
Long-term notes receivable from subsidiaries.............. 541 192 154
Capital expenditures, net................................. (6) (6) --
------- ------- -----
Net cash provided by investing activities................... 858 2,512 375
------- ------- -----
FINANCING ACTIVITIES:
Long-term revolving credit facility, net.................. (2,400) (1,206) (236)
Payments on long-term debt................................ (159) (888) --
Proceeds from long-term debt.............................. 1,610 -- --
Debt issuance costs....................................... (118) (1) (5)
Common stock dividends paid............................... (122) (123) (124)
Proceeds from issuance of common stock, net............... -- -- 17
Short-term notes payable to subsidiaries.................. (31) 121 (122)
Long-term notes payable to subsidiaries................... (2) 134 (245)
------- ------- -----
Net cash used in financing activities....................... (1,222) (1,963) (715)
------- ------- -----
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ (201) (22) 1
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 223 22 --
------- ------- -----
CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 22 $ -- $ 1
======= ======= =====
See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8
126
CENTERPOINT ENERGY, INC.
SCHEDULE I -- NOTES TO CONDENSED FINANCIAL INFORMATION (PARENT COMPANY)
(1) The condensed parent company financial statements and notes should be
read in conjunction with the consolidated financial statements and notes of
CenterPoint Energy, Inc. (CenterPoint Energy or the Company) appearing in the
Annual Report on Form 10-K. Bank facilities at CenterPoint Energy Houston
Electric, LLC and CenterPoint Energy Resources Corp., indirect wholly owned
subsidiaries of the Company, limit debt, excluding transition bonds, as a
percentage of their total capitalization to 68 percent and 65 percent,
respectively. These covenants could restrict the ability of these subsidiaries
to distribute dividends to the Company.
(2) CenterPoint Energy was a registered public utility holding company
under the Public Utility Holding Company Act of 1935, as amended (the 1935 Act).
The 1935 Act and related rules and regulations imposed a number of restrictions
on the activities of the Company and its subsidiaries. The Energy Policy Act of
2005 (Energy Act) repealed the 1935 Act effective February 8, 2006, and since
that date the Company and its subsidiaries have no longer been subject to
restrictions imposed under the 1935 Act. The Energy Act includes a new Public
Utility Holding Company Act of 2005 (PUHCA 2005), which grants to the Federal
Energy Regulatory Commission (FERC) authority to require holding companies and
their subsidiaries to maintain certain books and records and make them available
for review by the FERC and state regulatory authorities in certain
circumstances. On December 8, 2005, the FERC issued rules implementing PUHCA
2005 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. The FERC continues to consider motions for rehearing or clarification
of these rules.
(3) Effective January 1, 2004, CenterPoint Energy established a service
company in order to comply with the 1935 Act. As a result, certain assets and
liabilities of the parent company were transferred to the service company,
primarily property, plant and equipment and related deferred taxes. These
transfers have been excluded from the Statement of Cash Flows for the year ended
December 31, 2004 as they represent non-cash transactions.
(4) In July 2004, the Company announced its agreement to sell its majority
owned subsidiary, Texas Genco, to Texas Genco LLC (formerly known as GC Power
Acquisition LLC), an entity owned in equal parts by affiliates of The Blackstone
Group, Hellman & Friedman LLC, Kohlberg Kravis Roberts & Co. L.P. and Texas
Pacific Group. 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. Texas Genco's principal remaining asset was its
ownership interest in a nuclear generating facility. The final step of the
transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in
exchange for an additional cash payment to the Company of $700 million, was
completed on April 13, 2005. The Company recorded after tax losses of $366
million and $14 million in 2004 and 2005, respectively, related to the sale of
Texas Genco.
(5) In March 2005, the Company replaced its $750 million revolving credit
facility with a $1 billion five-year revolving credit facility. Borrowings may
be made under the facility at the London interbank offered rate (LIBOR) plus
87.5 basis points based on current credit ratings. An additional utilization fee
of 12.5 basis points applies to borrowings whenever more than 50% of the
facility is utilized. Changes in credit ratings could lower or raise the
increment to LIBOR depending on whether ratings improved or were lowered. As of
December 31, 2005, borrowings of $3 million in commercial paper were backstopped
by the revolving credit facility and $27 million in letters of credit were
outstanding under the revolving credit facility.
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, initially at a conversion rate of 86.3558 shares of common stock per
$1,000 principal amount of notes at any time prior to maturity, under the
following circumstances: (1) if the last reported sale price of CenterPoint
Energy common stock for at least 20 trading days during the period of 30
consecutive trading days ending on the last trading day of the previous calendar
quarter is greater than or
127
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. 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.
The Company commenced the exchange offer in response to the guidance set forth
in Emerging Issues Task Force (EITF) Issue No. 04-8, "Accounting Issues Related
to Certain Features of Contingently Convertible Debt and the Effect on Diluted
Earnings Per Share" (EITF 04-8). Under that guidance, because settlement of the
principal portion of the New Notes will be made in cash rather than stock, the
exchange of New Notes for Old Notes will allow the Company to exclude the
portion of the conversion value of the New Notes attributable to their principal
amount from its computation of diluted earnings per share from continuing
operations. See Note 12 for the impact on diluted earnings per share related to
these securities. The Company determined that the New Notes did not have
substantially different terms than the Old Notes, and thus, in accordance with
EITF Issue No. 96-19 "Debtor's Accounting for a Modification or Exchange of Debt
Instruments", the exchange transaction was accounted for as a modification of
the original instrument and not as an extinguishment of debt. Accordingly, a new
effective interest rate was determined based on the carrying amount of the
original debt instrument and the revised cash flows, and the recorded discount
will be amortized as an adjustment to interest expense in future periods.
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, initially at a conversion rate of 78.064 shares of common
stock per $1,000 principal amount of notes at any time prior to maturity, under
the following circumstances: (1) if the last reported sale price of CenterPoint
Energy common stock for at least 20 trading days during the period of 30
consecutive trading days ending on the last trading day of the previous calendar
quarter is greater than or equal to 120% of the conversion price per share of
CenterPoint Energy common stock on such last trading day, (2) if the notes have
been called for redemption, (3) during any period in which the credit ratings
assigned to the notes by both Moody's and S&P are lower than Ba2 and BB,
respectively, or the notes are no longer rated by at least one of these ratings
services or their successors, or (4) upon the occurrence of specified corporate
transactions, including the distribution to all holders of CenterPoint Energy
common stock of certain rights entitling them to purchase shares of CenterPoint
Energy common stock at less than the last reported sale price of a share of
CenterPoint Energy common stock on the trading day prior to the declaration date
of the distribution or the distribution to all holders of CenterPoint Energy
common stock of the Company's assets, debt securities or certain rights to
purchase the Company's securities, which distribution has a per share value
exceeding 15% of the last reported sale price of a share of CenterPoint Energy
common stock on the trading
128
day immediately preceding the declaration date for such distribution. 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 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. 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.
(6) CenterPoint Energy Intrastate Pipelines, Inc., CenterPoint Energy
Services, Inc. and other wholly owned subsidiaries of CERC Corp. provide
comprehensive natural gas sales and services to industrial and commercial
customers which are primarily located within or near the territories served by
the Company's pipelines and distribution subsidiaries. In order to hedge their
exposure to natural gas prices, these CERC Corp. subsidiaries have entered
standard purchase and sale agreements with various counterparties. CenterPoint
Energy has guaranteed the payment obligations of these subsidiaries under
certain of these agreements, typically for one-year terms. As of December 31,
2005, CenterPoint Energy had guaranteed $182 million under these agreements.
129
CENTERPOINT ENERGY, INC.
SCHEDULE II -- QUALIFYING VALUATION ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2005
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
------------------------------------------- ---------- ----------------------- ----------- ----------
ADDITIONS
-----------------------
BALANCE AT CHARGED TO DEDUCTIONS BALANCE AT
BEGINNING CHARGED OTHER FROM END OF
DESCRIPTION OF PERIOD TO INCOME ACCOUNTS(1) RESERVES(2) PERIOD
----------- ---------- --------- ----------- ----------- ----------
(IN MILLIONS)
Year Ended December 31, 2005:
Accumulated provisions:
Uncollectible accounts receivable..... $30 $ 40 $-- $27 $43
Deferred tax asset valuation
allowance........................... 20 1 -- -- 21
Year Ended December 31, 2004:
Accumulated provisions:
Uncollectible accounts receivable..... $31 $ 27 $-- $28 $30
Deferred tax asset valuation
allowance........................... 73 (67) 14 -- 20
Year Ended December 31, 2003:
Accumulated provisions:
Uncollectible accounts receivable..... $24 $ 24 $-- $17 $31
Deferred tax asset valuation
allowance........................... 83 (10) -- -- 73
---------------
(1) Charges to other accounts represent changes in presentation to reflect state
tax attributes net of federal tax benefit as well as to reflect amounts that
were netted against related attribute balances in prior years.
(2) Deductions from reserves represent losses or expenses for which the
respective reserves were created. In the case of the uncollectible accounts
reserve, such deductions are net of recoveries of amounts previously written
off.
130
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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, in the City of
Houston, the State of Texas, on the 15th day of March, 2006.
CENTERPOINT ENERGY, INC.
(Registrant)
By: /s/ DAVID M. MCCLANAHAN
------------------------------------
David M. McClanahan,
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 15, 2006.
SIGNATURE TITLE
--------- -----
/s/ DAVID M. MCCLANAHAN President, Chief Executive Officer and Director
------------------------------------------------ (Principal Executive Officer and Director)
David M. McClanahan
/s/ GARY L. WHITLOCK Executive Vice President and Chief Financial
------------------------------------------------ Officer (Principal Financial Officer)
Gary L. Whitlock
/s/ JAMES S. BRIAN Senior Vice President and Chief Accounting Officer
------------------------------------------------ (Principal Accounting Officer)
James S. Brian
/s/ MILTON CARROLL Chairman of the Board of Directors
------------------------------------------------
Milton Carroll
/s/ JOHN T. CATER Director
------------------------------------------------
John T. Cater
/s/ DERRILL CODY Director
------------------------------------------------
Derrill Cody
/s/ O. HOLCOMBE CROSSWELL Director
------------------------------------------------
O. Holcombe Crosswell
/s/ JANIECE M. LONGORIA Director
------------------------------------------------
Janiece M. Longoria
/s/ THOMAS F. MADISON Director
------------------------------------------------
Thomas F. Madison
/s/ ROBERT T. O'CONNELL Director
------------------------------------------------
Robert T. O'Connell
131
SIGNATURE TITLE
--------- -----
/s/ MICHAEL E. SHANNON Director
------------------------------------------------
Michael E. Shannon
/s/ PETER WAREING Director
------------------------------------------------
Peter Wareing
/s/ DONALD R. CAMPBELL Director
------------------------------------------------
Donald R. Campbell
132
CENTERPOINT ENERGY, INC.
EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
FOR FISCAL YEAR ENDED DECEMBER 31, 2005
INDEX OF EXHIBITS
Exhibits included with this report are designated by a cross (+); all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated by an asterisk (*) are management
contracts or compensatory plans or arrangements required to be filed as exhibits
to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K. CenterPoint Energy
has not filed the exhibits and schedules to Exhibit 2. CenterPoint Energy hereby
agrees to furnish supplementally a copy of any schedule omitted from Exhibit 2
to the SEC upon request.
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------------ ------------------------ -------------------------------- ------------ ---------
2 -- Transaction Agreement CenterPoint Energy's Form 8-K 1-31447 10.1
dated July 21, 2004 dated July 21, 2004
among CenterPoint
Energy, Utility Holding,
LLC, NN Houston Sub,
Inc., Texas Genco
Holdings, Inc. ("Texas
Genco"), HPC Merger Sub,
Inc. and GC Power
Acquisition LLC
3(a)(1) -- Amended and Restated CenterPoint Energy's 3-69502 3.1
Articles of Registration Statement on Form
Incorporation of S-4
CenterPoint Energy
3(a)(2) -- Articles of Amendment to CenterPoint Energy's Form 10-K 1-31447 3.1.1
Amended and Restated for the year ended December 31,
Articles of 2001
Incorporation of
CenterPoint Energy
3(b) -- Amended and Restated CenterPoint Energy's Form 10-K 1-31447 3.2
Bylaws of CenterPoint for the year ended December 31,
Energy 2001
3(c) -- Statement of Resolution CenterPoint Energy's Form 10-K 1-31447 3.3
Establishing Series of for the year ended December 31,
Shares designated Series 2001
A Preferred Stock of
CenterPoint Energy
4(a) -- Form of CenterPoint CenterPoint Energy's 3-69502 4.1
Energy Stock Certificate Registration Statement on Form
S-4
4(b) -- Rights Agreement dated CenterPoint Energy's Form 10-K 1-31447 4.2
January 1, 2002, between for the year ended December 31,
CenterPoint Energy and 2001
JPMorgan Chase Bank, as
Rights Agent
133
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------------ ------------------------ -------------------------------- ------------ ---------
4(c) -- Contribution and CenterPoint Energy's Form 10-K 1-31447 4.3
Registration Agreement for the year ended December 31,
dated December 18, 2001 2001
among Reliant Energy,
CenterPoint Energy and
the Northern Trust
Company, trustee under
the Reliant Energy,
Incorporated Master
Retirement Trust
4(d)(1) -- Mortgage and Deed of HL&P's Form S-7 filed on August 2-59748 2(b)
Trust, dated November 1, 25, 1977
1944 between Houston
Lighting and Power
Company ("HL&P") and
Chase Bank of Texas,
National Association
(formerly, South Texas
Commercial National Bank
of Houston), as Trustee,
as amended and
supplemented by 20
Supplemental Indentures
thereto
4(d)(2) -- Twenty-First through HL&P's Form 10-K for the year 1-3187 4(a)(2)
Fiftieth Supplemental ended December 31, 1989
Indentures to Exhibit
4(d)(1)
4(d)(3) -- Fifty-First Supplemental HL&P's Form 10-Q for the quarter 1-3187 4(a)
Indenture to Exhibit ended June 30, 1991
4(d)(1) dated as of
March 25, 1991
4(d)(4) -- Fifty-Second through HL&P's Form 10-Q for the quarter 1-3187 4
Fifty-Fifth Supplemental ended March 31, 1992
Indentures to Exhibit
4(d)(1) each dated as of
March 1, 1992
4(d)(5) -- Fifty-Sixth and Fifty- HL&P's Form 10-Q for the quarter 1-3187 4
Seventh Supplemental ended September 30, 1992
Indentures to Exhibit
4(d)(1) each dated as of
October 1, 1992
4(d)(6) -- Fifty-Eighth and Fifty- HL&P's Form 10-Q for the quarter 1-3187 4
Ninth Supplemental ended March 31, 1993
Indentures to Exhibit
4(d)(1) each dated as of
March 1, 1993
4(d)(7) -- Sixtieth Supplemental HL&P's Form 10-Q for the quarter 1-3187 4
Indenture to Exhibit ended June 30, 1993
4(d)(1) dated as of July
1, 1993
134
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------------ ------------------------ -------------------------------- ------------ ---------
4(d)(8) -- Sixty-First through HL&P's Form 10-K for the year 1-3187 4(a)(8)
Sixty-Third Supplemental ended December 31, 1993
Indentures to Exhibit
4(d)(1) each dated as of
December 1, 1993
4(d)(9) -- Sixty-Fourth and Sixty- HL&P's Form 10-K for the year 1-3187 4(a)(9)
Fifth Supplemental ended December 31, 1995
Indentures to Exhibit
4(d)(1) each dated as of
July 1, 1995
4(e)(1) -- General Mortgage CenterPoint Houston's Form 10-Q 1-3187 4(j)(1)
Indenture, dated as of for the quarter ended September
October 10, 2002, 30, 2002
between CenterPoint
Energy Houston Electric,
LLC and JPMorgan Chase
Bank, as Trustee
4(e)(2) -- Second Supplemental CenterPoint Houston's Form 10- Q 1-3187 4(j)(3)
Indenture to Exhibit for the quarter ended September
4(e)(1), dated as of 30, 2002
October 10, 2002
4(e)(3) -- Third Supplemental CenterPoint Houston's Form 10-Q 1-3187 4(j)(4)
Indenture to Exhibit for the quarter ended September
4(e)(1), dated as of 30, 2002
October 10, 2002
4(e)(4) -- Fourth Supplemental CenterPoint Houston's Form 10-Q 1-3187 4(j)(5)
Indenture to Exhibit for the quarter ended September
4(e)(1), dated as of 30, 2002
October 10, 2002
4(e)(5) -- Fifth Supplemental CenterPoint Houston's Form 10-Q 1-3187 4(j)(6)
Indenture to Exhibit for the quarter ended September
4(e)(1), dated as of 30, 2002
October 10, 2002
4(e)(6) -- Sixth Supplemental CenterPoint Houston's Form 10-Q 1-3187 4(j)(7)
Indenture to Exhibit for the quarter ended September
4(e)(1), dated as of 30, 2002
October 10, 2002
4(e)(7) -- Seventh Supplemental CenterPoint Houston's Form 10-Q 1-3187 4(j)(8)
Indenture to Exhibit for the quarter ended September
4(e)(1), dated as of 30, 2002
October 10, 2002
4(e)(8) -- Eighth Supplemental CenterPoint Houston's Form 10-Q 1-3187 4(j)(9)
Indenture to Exhibit for the quarter ended September
4(e)(1), dated as of 30, 2002
October 10, 2002
4(e)(9) -- Officer's Certificates CenterPoint Energy's Form 10-K 1-31447 4(e)(10)
dated October 10, 2002 for the year ended December 31,
setting forth the form, 2003
terms and provisions of
the First through Eighth
Series of General
Mortgage Bonds
135
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------------ ------------------------ -------------------------------- ------------ ---------
4(e)(10) -- Tenth Supplemental CenterPoint Energy's Form 8-K 1-31447 4.1
Indenture to Exhibit dated March 13, 2003
4(e)(1), dated as of
March 18, 2003
4(e)(11) -- Officer's Certificate CenterPoint Energy's Form 8-K 1-31447 4.2
dated March 18, 2003 dated March 13, 2003
setting forth the form,
terms and provisions of
the Tenth Series and
Eleventh Series of
General Mortgage Bonds
4(e)(12) -- Eleventh Supplemental CenterPoint Energy's Form 8-K 1-31447 4.1
Indenture to Exhibit dated May 16, 2003
4(e)(1), dated as of May
23, 2003
4(e)(13) -- Officer's Certificate CenterPoint Energy's Form 8-K 1-31447 4.2
dated May 23, 2003 dated May 16, 2003
setting forth the form,
terms and provisions of
the Twelfth Series of
General Mortgage Bonds
4(e)(14) -- Twelfth Supplemental CenterPoint Energy's Form 8-K 1-31447 4.2
Indenture to Exhibit dated September 9, 2003
4(e)(1), dated as of
September 9, 2003
4(e)(15) -- Officer's Certificate CenterPoint Energy's Form 8-K 1-31447 4.3
dated September 9, 2003 dated September 9, 2003
setting forth the form,
terms and provisions of
the Thirteenth Series of
General Mortgage Bonds
+4(e)(16) Thirteenth Supplemental
Indenture to Exhibit
4(e)(1), dated as of
February 6, 2004
+4(e)(17) Officer's Certificate
dated February 6, 2004
setting forth the form,
terms and provisions of
the Fourteenth Series of
General Mortgage Bonds
+4(e)(18) Fourteenth Supplemental
Indenture to Exhibit
4(e)(1), dated as of
February 11, 2004
+4(e)(19) Officer's Certificate
dated February 11, 2004
setting forth the form,
terms and provisions of
the Fifteenth Series of
General Mortgage Bonds
136
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------------ ------------------------ -------------------------------- ------------ ---------
+4(e)(20) Fifteenth Supplemental
Indenture to Exhibit
4(e)(1), dated as of
March 31, 2004
+4(e)(21) Officer's Certificate
dated March 31, 2004
setting forth the form,
terms and provisions of
the Sixteenth Series of
General Mortgage Bonds
+4(e)(22) Sixteenth Supplemental
Indenture to Exhibit
4(e)(1), dated as of
March 31, 2004
+4(e)(23) Officer's Certificate
dated March 31, 2004
setting forth the form,
terms and provisions of
the Seventeenth Series
of General Mortgage
Bonds
+4(e)(24) Seventeenth Supplemental
Indenture to Exhibit
4(e)(1), dated as of
March 31, 2004
+4(e)(25) Officer's Certificate
dated March 31, 2004
setting forth the form,
terms and provisions of
the Eighteenth Series of
General Mortgage Bonds
4(f)(1) -- Indenture, dated as of CERC Corp.'s Form 8-K dated 1-13265 4.1
February 1, 1998, February 5, 1998
between Reliant Energy
Resources Corp. ("RERC
Corp.") and Chase Bank
of Texas, National
Association, as Trustee
4(f)(2) -- Supplemental Indenture CERC Corp.'s Form 8-K dated 1-13265 4.2
No. 1 to Exhibit November 9, 1998
4(f)(1), dated as of
February 1, 1998,
providing for the
issuance of RERC Corp.'s
6 1/2% Debentures due
February 1, 2008
4(f)(3) -- Supplemental Indenture CERC Corp.'s Form 8-K dated 1-13265 4.1
No. 2 to Exhibit November 9, 1998
4(f)(1), dated as of
November 1, 1998,
providing for the
issuance of RERC Corp.'s
6 3/8% Term Enhanced
ReMarketable Securities
137
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------------ ------------------------ -------------------------------- ------------ ---------
4(f)(4) -- Supplemental Indenture CERC Corp.'s Registration 333-49162 4.2
No. 3 to Exhibit Statement on Form S-4
4(f)(1), dated as of
July 1, 2000, providing
for the issuance of RERC
Corp.'s 8.125% Notes due
2005
4(f)(5) -- Supplemental Indenture CERC Corp.'s Form 8-K dated 1-13265 4.1
No. 4 to Exhibit February 21, 2001
4(f)(1), dated as of
February 15, 2001,
providing for the
issuance of RERC Corp.'s
7.75% Notes due 2011
4(f)(6) -- Supplemental Indenture CenterPoint Energy's Form 8-K 1-31447 4.1
No. 5 to Exhibit dated March 18, 2003
4(f)(1), dated as of
March 25, 2003,
providing for the
issuance of CenterPoint
Energy Resources Corp.'s
("CERC Corp.'s") 7.875%
Senior Notes due 2013
4(f)(7) -- Supplemental Indenture CenterPoint Energy's Form 8-K 1-31447 4.2
No. 6 to Exhibit dated April 7, 2003
4(f)(1), dated as of
April 14, 2003,
providing for the
issuance of CERC Corp.'s
7.875% Senior Notes due
2013
4(f)(8) -- Supplemental Indenture CenterPoint Energy's Form 8-K 1-31447 4.2
No. 7 to Exhibit dated October 29, 2003
4(f)(1), dated as of
November 3, 2003,
providing for the
issuance of CERC Corp.'s
5.95% Senior Notes due
2014
+4(f)(9) -- Supplemental Indenture
No. 8 to Exhibit
4(f)(1), dated as of
December 28, 2005,
providing for a
modification of CERC
Corp.'s 6 1/2%
Debentures due 2008
4(g)(1) -- Indenture, dated as of CenterPoint Energy's Form 8-K 1-31447 4.1
May 19, 2003, between dated May 19, 2003
CenterPoint Energy and
JPMorgan Chase Bank, as
Trustee
4(g)(2) -- Supplemental Indenture CenterPoint Energy's Form 8-K 1-31447 4.2
No. 1 to Exhibit dated May 19, 2003
4(g)(1), dated as of May
19, 2003, providing for
the issuance of
CenterPoint Energy's
3.75% Convertible Senior
Notes due 2023
138
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------------ ------------------------ -------------------------------- ------------ ---------
4(g)(3) -- Supplemental Indenture CenterPoint Energy's Form 8-K 1-31447 4.3
No. 2 to Exhibit dated May 19, 2003
4(g)(1), dated as of May
27, 2003, providing for
the issuance of
CenterPoint Energy's
5.875% Senior Notes due
2008 and 6.85% Senior
Notes due 2015
4(g)(4) -- Supplemental Indenture CenterPoint Energy's Form 8-K 1-31447 4.2
No. 3 to Exhibit dated September 9, 2003
4(g)(1), dated as of
September 9, 2003,
providing for the
issuance of CenterPoint
Energy's 7.25% Senior
Notes due 2010
4(g)(5) -- Supplemental Indenture CenterPoint Energy's Form 8-K 1-31447 4.2
No. 4 to Exhibit dated December 10, 2003
4(g)(1), dated as of
December 17, 2003,
providing for the
issuance of CenterPoint
Energy's 2.875%
Convertible Senior Notes
due 2024
4(g)(6) -- Supplemental Indenture CenterPoint Energy's Form 8-K 1-31447 4.1
No. 5 to Exhibit dated December 9, 2004
4(g)(1), dated as of
December 13, 2004, as
supplemented by Exhibit
4(g)(5), relating to the
issuance of CenterPoint
Energy's 2.875%
Convertible Senior Notes
dues 2024
+4(g)(7) -- Supplemental Indenture
No. 6 to Exhibit
4(g)(1), dated as of
August 23, 2005,
providing for the
issuance of CenterPoint
Energy's 3.75%
Convertible Senior
Notes, Series B Due 2023
4(h)(1) Subordinated Indenture Reliant Energy's Form 8-K dated 1-3187 4.1
dated as of September 1, September 15, 1999
1999
139
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------------ ------------------------ -------------------------------- ------------ ---------
4(h)(2) Supplemental Indenture Reliant Energy's Form 8-K dated 1-3187 4.2
No. 1 dated as of September 15, 1999
September 1, 1999,
between Reliant Energy
and Chase Bank of Texas
(supplementing Exhibit
4(h)(1) and providing
for the issuance Reliant
Energy's 2% Zero-
Premium Exchangeable
Subordinated Notes Due
2029)
4(h)(3) -- Supplemental Indenture CenterPoint Energy's Form 8-K12B 1-31447 4(e)
No. 2 dated as of August dated August 31, 2002
31, 2002, between
CenterPoint Energy,
Reliant Energy and
JPMorgan Chase Bank
(supplementing Exhibit
4(h)(1))
+4(h)(4) -- Supplemental Indenture
No. 3 dated as of
December 28, 2005,
between CenterPoint
Energy, Reliant Energy
and JPMorgan Chase Bank
(supplementing Exhibit
4(h)(1))
4(i) -- Supplemental Indenture CenterPoint Energy's Form 8-K12B 1-31447 4(g)
No. 3 dated as of August dated August 31, 2002
31, 2002 among
CenterPoint Energy, REI
and The Bank of New York
(supplementing the
Junior Subordinated
Indenture dated as of
February 1, 1997 under
which REI's Junior
Subordinated Debentures
related to 8.257%
capital securities
issued by HL&P Capital
Trust II were issued)
140
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------------ ------------------------ -------------------------------- ------------ ---------
4(j) -- Assignment and CenterPoint Energy's Form 8-K12B 1-31447 4(j)
Assumption Agreement for dated August 31, 2002
the Guarantee Agreements
dated as of August 31,
2002 between CenterPoint
Energy and Reliant
Energy (relating to the
Guarantee Agreement
dated as of February 4,
1997 between Reliant
Energy and The Bank of
New York providing for
the guaranty of certain
amounts relating to the
8.257% capital
securities issued by
HL&P Capital Trust II)
4(k) -- Assignment and CenterPoint Energy's Form 8-K12B 1-31447 4(l)
Assumption Agreement for dated August 31, 2002
the Expense and
Liability Agreements and
the Trust Agreements
dated as of August 31,
2002 between CenterPoint
Energy and Reliant
Energy (relating to (i)
the Agreement as to
Expenses and Liabilities
dated as of February 4,
1997 between Reliant
Energy and HL&P Capital
Trust II and (ii) HL&P
Capital Trust II's
Amended and Restated
Trust Agreement dated
February 4, 1997)
4(l) -- $1,000,000,000 Credit CenterPoint Energy's Form 8-K 1-31447 4.1
Agreement dated as of dated March 7, 2005
March 7, 2005 among
CenterPoint Energy and
the banks named therein
4(m) -- $200,000,000 Credit CenterPoint Energy's Form 8-K 1-31447 4.2
Agreement dated as of dated March 7, 2005
March 7, 2005 among
CenterPoint Houston and
the banks named therein
4(n) -- $400,000,000 Credit CenterPoint Energy's Form 8-K 1-31447 4.1
Agreement dated as of dated June 29, 2005
June 30, 2005 among CERC
Corp., as Borrower, and
the Initial Lenders
named therein, as
Initial Lenders
Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy
has not filed as exhibits to this Form 10-K certain long-term debt instruments,
including indentures, under which the total amount of
141
securities authorized does not exceed 10% of the total assets of CenterPoint
Energy and its subsidiaries on a consolidated basis. CenterPoint Energy hereby
agrees to furnish a copy of any such instrument to the SEC upon request.
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(a)(1) -- Executive Benefit Plan of HI's Form 10-Q for the quarter 1-7629 10(a)(1),
Houston Industries ended March 31, 1987 10(a)(2),
Incorporated ("HI") and First and
and Second Amendments thereto 10(a)(3)
effective as of June 1, 1982,
July 1, 1984, and May 7,
1986, respectively
*10(a)(2) -- Third Amendment dated Reliant Energy's Form 10-K for 1-3187 10(a)(2)
September 17, 1999 to Exhibit the year ended December 31, 2000
10(a)(1)
*10(a)(3) -- CenterPoint Energy Executive CenterPoint Energy's Form 10-Q 1-31447 10.4
Benefits Plan, as amended and for the quarter ended September
restated effective June 18, 30, 2003
2003
*10(b)(1) -- Executive Incentive HI's Form 10-K for the year 1-7629 10(b)
Compensation Plan of HI ended December 31, 1991
effective as of January 1,
1982
*10(b)(2) -- First Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(a)
10(b)(1) effective as of ended March 31, 1992
March 30, 1992
*10(b)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(b)
10(b)(1) effective as of ended December 31, 1992
November 4, 1992
*10(b)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(b)(4)
10(b)(1) effective as of ended December 31, 1994
September 7, 1994
*10(b)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(b)(5)
10(b)(1) effective as of ended December 31, 1997
August 6, 1997
*10(c)(1) -- Executive Incentive HI's Form 10-Q for the quarter 1-7629 10(b)(1)
Compensation Plan of HI ended March 31, 1987
effective as of January 1,
1985
*10(c)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(b)(3)
10(c)(1) effective as of ended December 31, 1988
January 1, 1985
*10(c)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(c)(3)
10(c)(1) effective as of ended December 31, 1991
January 1, 1985
*10(c)(4) -- Third Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(b)
10(c)(1) effective as of ended March 31, 1992
March 30, 1992
*10(c)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(c)(5)
10(c)(1) effective as of ended December 31, 1992
November 4, 1992
*10(c)(6) -- Fifth Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(c)(6)
10(c)(1) effective as of ended December 31, 1994
September 7, 1994
*10(c)(7) -- Sixth Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(c)(7)
10(c)(1) effective as of ended December 31, 1997
August 6, 1997
142
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(d) -- Executive Incentive HI's Form 10-Q for the quarter 1-7629 10(b)(2)
Compensation Plan of HL&P ended March 31, 1987
effective as of January 1,
1985
*10(e)(1) -- Executive Incentive HI's Form 10-Q for the quarter 1-7629 10(b)
Compensation Plan of HI as ended June 30, 1989
amended and restated on
January 1, 1989
*10(e)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(e)(2)
10(e)(1) effective as of ended December 31, 1991
January 1, 1989
*10(e)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(c)
10(e)(1) effective as of ended March 31, 1992
March 30, 1992
*10(e)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(c)(4)
10(e)(1) effective as of ended December 31, 1992
November 4, 1992
*10(e)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(e)(5)
10(e)(1) effective as of ended December 31, 1994
September 7, 1994
*10(f)(1) -- Executive Incentive HI's Form 10-K for the year 1-7629 10(b)
Compensation Plan of HI as ended December 31, 1990
amended and restated on
January 1, 1991
*10(f)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(f)(2)
10(f)(1) effective as of ended December 31, 1991
January 1, 1991
*10(f)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(d)
10(f)(1) effective as of ended March 31, 1992
March 30, 1992
*10(f)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(f)(4)
10(f)(1) effective as of ended December 31, 1992
November 4, 1992
*10(f)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(f)(5)
10(f)(1) effective as of ended December 31, 1992
January 1, 1993
*10(f)(6) -- Fifth Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(f)(6)
10(f)(1) effective in part, ended December 31, 1994
January 1, 1995, and in part,
September 7, 1994
*10(f)(7) -- Sixth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(a)
10(f)(1) effective as of ended June 30, 1995
August 1, 1995
*10(f)(8) -- Seventh Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(a)
10(f)(1) effective as of ended June 30, 1996
January 1, 1996
*10(f)(9) -- Eighth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(a)
10(f)(1) effective as of ended June 30, 1997
January 1, 1997
*10(f)(10) -- Ninth Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(f)(10)
10(f)(1) effective in part, ended December 31, 1997
January 1, 1997, and in part,
January 1, 1998
143
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(g) -- Benefit Restoration Plan of HI's Form 10-Q for the quarter 1-7629 10(c)
HI effective as of June 1, ended March 31, 1987
1985
*10(h) -- Benefit Restoration Plan of HI's Form 10-K for the year 1-7629 10(g)(2)
HI as amended and restated ended December 31, 1991
effective as of January 1,
1988
*10(i)(1) -- Benefit Restoration Plan of HI's Form 10-K for the year 1-7629 10(g)(3)
HI, as amended and restated ended December 31, 1991
effective as of July 1, 1991
*10(i)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(i)(2)
10(i)(1) effective in part, ended December 31, 1997
August 6, 1997, in part,
September 3, 1997, and in
part, October 1, 1997
*10(j)(1) -- Deferred Compensation Plan of HI's Form 10-Q for the quarter 1-7629 10(d)
HI effective as of September ended March 31, 1987
1, 1985
*10(j)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(d)(2)
10(j)(1) effective as of ended December 31, 1990
September 1, 1985
*10(j)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(e)
10(j)(1) effective as of ended March 31, 1992
March 30, 1992
*10(j)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(h)(4)
10(j)(1) effective as of June ended December 31, 1993
2, 1993
*10(j)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(h)(5)
10(j)(1) effective as of ended December 31, 1994
September 7, 1994
*10(j)(6) -- Fifth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(d)
10(j)(1) effective as of ended June 30, 1995
August 1, 1995
*10(j)(7) -- Sixth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(b)
10(j)(1) effective as of ended June 30, 1995
December 1, 1995
*10(j)(8) -- Seventh Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(b)
10(j)(1) effective as of ended June 30, 1997
January 1, 1997
*10(j)(9) -- Eighth Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(j)(9)
10(j)(1) effective as of ended December 31, 1997
October 1, 1997
*10(j)(10) -- Ninth Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(j)(10)
10(j)(1) effective as of ended December 31, 1997
September 3, 1997
*10(j)(11) -- Tenth Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(j)(11)
10(j)(1) effective as of for the year ended December 31,
January 1, 2001 2002
*10(j)(12) -- Eleventh Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(j)(12)
10(j)(1) effective as of for the year ended December 31,
August 31, 2002 2002
*10(j)(13) -- CenterPoint Energy 1985 CenterPoint Energy's Form 10-Q 1-31447 10.1
Deferred Compensation Plan, for the quarter ended September
as amended and restated 30, 2003
effective January 1, 2003
144
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(k)(1) -- Deferred Compensation Plan of HI's Form 10-Q for the quarter 1-7629 10(a)
HI effective as of January 1, ended June 30, 1989
1989
*10(k)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(e)(3)
10(k)(1) effective as of ended December 31, 1989
January 1, 1989
*10(k)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(f)
10(k)(1) effective as of ended March 31, 1992
March 30, 1992
*10(k)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(i)(4)
10(k)(1) effective as of June ended December 31, 1993
2, 1993
*10(k)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(i)(5)
10(k)(1) effective as of ended December 31, 1994
September 7, 1994
*10(k)(6) -- Fifth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(c)
10(k)(1) effective as of ended June 30, 1995
August 1, 1995
*10(k)(7) -- Sixth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(c)
10(k)(1) effective December ended June 30, 1995
1, 1995
*10(k)(8) -- Seventh Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(c)
10(k)(1) effective as of ended June 30, 1997
January 1, 1997
*10(k)(9) -- Eighth Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(k)(9)
10(k)(1) effective in part ended December 31, 1997
October 1, 1997 and in part
January 1, 1998
*10(k)(10) -- Ninth Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(k)(10)
10(k)(1) effective as of ended December 31, 1997
September 3, 1997
*10(k)(11) -- Tenth Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(k)(11)
10(k)(1) effective as of for the year ended December 31,
January 1, 2001 2002
*10(k)(12) -- Eleventh Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(k)(12)
10(k)(1) effective as of for the year ended December 31,
August 31, 2002 2002
*10(l)(1) -- Deferred Compensation Plan of HI's Form 10-K for the year 1-7629 10(d)(3)
HI effective as of January 1, ended December 31, 1990
1991
*10(l)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(j)(2)
10(l)(1) effective as of ended December 31, 1991
January 1, 1991
*10(l)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(g)
10(l)(1) effective as of ended March 31, 1992
March 30, 1992
*10(l)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(j)(4)
10(l)(1) effective as of June ended December 31, 1993
2, 1993
*10(l)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(j)(5)
10(l)(1) effective as of ended December 31, 1993
December 1, 1993
145
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(l)(6) -- Fifth Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(j)(6)
10(l)(1) effective as of ended December 31, 1994
September 7, 1994
*10(l)(7) -- Sixth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(b)
10(l)(1) effective as of ended June 30, 1995
August 1, 1995
*10(l)(8) -- Seventh Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(d)
10(l)(1) effective as of ended June 30, 1996
December 1, 1995
*10(l)(9) -- Eighth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(d)
10(l)(1) effective as of ended June 30, 1997
January 1, 1997
*10(l)(10) -- Ninth Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(l)(10)
10(l)(1) effective in part ended December 31, 1997
August 6, 1997, in part
October 1, 1997, and in part
January 1, 1998
*10(l)(11) -- Tenth Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(i)(11)
10(l)(1) effective as of ended December 31, 1997
September 3, 1997
*10(l)(12) -- Eleventh Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(l)(12)
10(l)(1) effective as of for the year ended December 31,
January 1, 2001 2002
*10(l)(13) -- Twelfth Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(l)(13)
10(l)(1) effective as of for the year ended December 31,
August 31, 2002 2002
*10(m)(1) -- Long-Term Incentive HI's Form 10-Q for the quarter 1-7629 10(c)
Compensation Plan of HI ended June 30, 1989
effective as of January 1,
1989
*10(m)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(f)(2)
10(m)(1) effective as of ended December 31, 1989
January 1, 1990
*10(m)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(k)(3)
10(m)(1) effective as of ended December 31, 1992
December 22, 1992
*10(m)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(m)(4)
10(m)(1) effective as of ended December 31, 1997
August 6, 1997
*10(m)(5) -- Fourth Amendment to Exhibit Reliant Energy's Form 10-Q for 1-3187 10.4
10(m)(1) effective as of the quarter ended June 30, 2002
January 1, 2001
*10(n)(1) -- Form of stock option HI's Form 10-Q for the quarter 1-7629 10(h)
agreement for non-qualified ended March 31, 1992
stock options granted under
Exhibit 10(m)(1)
*10(n)(2) -- Forms of restricted stock HI's Form 10-Q for the quarter 1-7629 10(i)
agreement for restricted ended March 31, 1992
stock granted under Exhibit
10(m)(1)
*10(o)(1) -- 1994 Long-Term Incentive HI's Form 10-K for the year 1-7629 10(n)(1)
Compensation Plan of HI ended December 31, 1993
effective as of January 1,
1994
*10(o)(2) -- Form of stock option HI's Form 10-K for the year 1-7629 10(n)(2)
agreement for non-qualified ended December 31, 1993
stock options granted under
Exhibit 10(o)(1)
146
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(o)(3) -- First Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(e)
10(o)(1) effective as of May ended June 30, 1997
9, 1997
*10(o)(4) -- Second Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(p)(4)
10(o)(1) effective as of ended December 31, 1997
August 6, 1997
*10(o)(5) -- Third Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(p)(5)
10(o)(1) effective as of ended December 31, 1998
January 1, 1998
*10(o)(6) -- Reliant Energy 1994 Long-Term Reliant Energy's Form 10-Q for 1-3187 10.6
Incentive Compensation Plan, the quarter ended June 30, 2002
as amended and restated
effective January 1, 2001
*10(o)(7) -- First Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(p)(7)
10(o)(6), effective December for the year ended December 31,
1, 2003 2003
*10(o)(8) -- Form of Non-Qualified Stock CenterPoint Energy's Form 8-K 1-31447 10.6
Option Award Notice under dated January 25, 2005
Exhibit 10(o)(6)
*10(p)(1) -- Savings Restoration Plan of HI's Form 10-K for the year 1-7629 10(f)
HI effective as of January 1, ended December 31, 1990
1991
*10(p)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(l)(2)
10(p)(1) effective as of ended December 31, 1991
January 1, 1992
*10(p)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(q)(3)
10(p)(1) effective in part, ended December 31, 1997
August 6, 1997, and in part,
October 1, 1997
*10(q)(1) -- Director Benefits Plan HI's Form 10-K for the year 1-7629 10(m)
effective as of January 1, ended December 31, 1991
1992
*10(q)(2) -- First Amendment to Exhibit HI's Form 10-K for the year 1-7629 10(m)(1)
10(q)(1) effective as of ended December 31, 1998
August 6, 1997
*10(q)(3) -- CenterPoint Energy Outside CenterPoint Energy's Form 10-Q 1-31447 10.6
Director Benefits Plan, as for the quarter ended September
amended and restated 30, 2003
effective June 18, 2003
*10(q)(4) -- First Amendment to Exhibit CenterPoint Energy's Form 10-Q 1-31447 10.6
10(q)(3) effective as of for the quarter ended June 30,
January 1, 2004 2004
*10(r)(1) -- Executive Life Insurance Plan HI's Form 10-K for the year 1-7629 10(q)
of HI effective as of January ended December 31, 1993
1, 1994
*10(r)(2) -- First Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10
10(r)(1) effective as of ended June 30, 1995
January 1, 1994
*10(r)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year 1-3187 10(s)(3)
10(r)(1) effective as of ended December 31, 1997
August 6, 1997
*10(r)(4) -- CenterPoint Energy Executive CenterPoint Energy's Form 10-Q 1-31447 10.5
Life Insurance Plan, as for the quarter ended September
amended and restated 30, 2003
effective June 18, 2003
147
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(s) -- Employment and Supplemental HI's Form 10-Q for the quarter 1-7629 10(f)
Benefits Agreement between ended March 31, 1987
HL&P and Hugh Rice Kelly
*10(t)(1) -- CenterPoint Energy Savings CenterPoint Energy's Form 10-Q 1-31447 99.2
Plan, as amended and restated for the quarter ended September
effective January 1, 2005 30, 2005
*10(t)(2) -- Reliant Energy Savings Trust CenterPoint Energy's Form 10-K 1-31447 10(u)(7)
between Reliant Energy and for the year ended December 31,
The Northern Trust Company, 2002
as Trustee, as amended and
restated effective April 1,
1999
*10(t)(3) -- First Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(u)(8)
10(t)(2) effective September for the year ended December 31,
30, 2002 2002
*10(t)(4) -- Second Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(u)(9)
10(t)(2) effective January 6, for the year ended December 31,
2003 2003
*10(t)(5) -- Third Amendment to Exhibit CenterPoint Energy's Form 10-Q 1-31447 99.1
10(t)(2) effective October 7, for the quarter ended September
2004, 30, 2005
*10(t)(6) -- Reliant Energy Retirement CenterPoint Energy's Form 10-K 1-31447 10(u)(10)
Plan, as amended and restated for the year ended December 31,
effective January 1, 1999 2002
*10(t)(7) -- First Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(u)(11)
10(t)(6) effective as of for the year ended December 31,
January 1, 1995 2002
*10(t)(8) -- Second Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(u)(12)
10(t)(6) effective as of for the year ended December 31,
January 1, 1995 2002
*10(t)(9) -- Third Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(u)(13)
10(t)(6) effective as of for the year ended December 31,
January 1, 2001 2002
*10(t)(10) -- Fourth Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(u)(14)
10(t)(6) effective as of for the year ended December 31,
January 1, 2001 2002
*10(t)(11) -- Fifth Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(u)(15)
10(t)(6) effective as of for the year ended December 31,
November 15, 2002, and as 2002
renamed effective October 2,
2002
*10(t)(12) -- Sixth Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(u)(16)
10(t)(6) effective as of for the year ended December 31,
January 1, 2002 2002
*10(t)(13) -- Seventh Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(u)(18)
10(t)(6) effective December for the year ended December 31,
1, 2003 2003
*10(t)(14) -- Eighth Amendment to Exhibit CenterPoint Energy's Form 10-Q 1-31447 10.7
10(t)(6) effective as of for the quarter ended June 30,
January 1, 2004 2004
*10(t)(15) -- Ninth Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(t)(20)
10(t)(6) effective as of for the year ended December 31,
October 27, 2004 2004
148
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(t)(16) -- Tenth Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(t)(21)
10(t)(6) effective as of for the year ended December 31,
January 1, 2005 2004
*10(t)(17) -- Eleventh Amendment to Exhibit CenterPoint Energy's Form 10-Q 1-31447 99.1
10(t)(6) effective as of May for the quarter ended June 30,
1, 2005 2005
*10(t)(18) -- Twelfth Amendment to Exhibit CenterPoint Energy's Form 10-Q 1-31447 99.2
10(t)(6) effective as of June for the quarter ended June 30,
1, 2005 2005
+*10(t)(19) -- Thirteenth Amendment to
Exhibit 10(t)(6) effective as
of January 1, 2006
*10(t)(20) -- Reliant Energy, Incorporated Reliant Energy's Form 10-K for 1-3187 10(u)(3)
Master Retirement Trust (as the year ended December 31, 1999
amended and restated
effective January 1, 1999 and
renamed effective May 5,
1999)
10(t)(21) -- Contribution and Registration Reliant Energy's Form 10-K for 1-3187 10(u)(4)
Agreement dated December 18, the year ended December 31, 2001
2001 among Reliant Energy,
CenterPoint Energy and the
Northern Trust Company,
trustee under the Reliant
Energy, Incorporated Master
Retirement Trust
10(u)(1) -- Stockholder's Agreement dated Schedule 13-D dated July 6, 1995 5-19351 2
as of July 6, 1995 between
Houston Industries
Incorporated and Time Warner
Inc.
10(u)(2) -- Amendment to Exhibit 10(u)(1) HI's Form 10-K for the year 1-7629 10(x)(4)
dated November 18, 1996 ended December 31, 1996
*10(v)(1) -- Houston Industries HI's Form 10-K for the year 1-7629 10(7)
Incorporated Executive ended December 31, 1995
Deferred Compensation Trust
effective as of December 19,
1995
*10(v)(2) -- First Amendment to Exhibit HI's Form 10-Q for the quarter 1-3187 10
10(v)(1) effective as of ended June 30, 1998
August 6, 1997
*10(w) -- Letter Agreement dated CenterPoint Energy's Form 8-K 1-31447 10.1
December 9, 2004 between dated December 9, 2004
CenterPoint Energy and Milton
Carroll
*10(x)(1) -- Reliant Energy, Incorporated Reliant Energy's Form 10-K for 1-3187 10(y)
and Subsidiaries Common Stock the year ended December 31, 2000
Participation Plan for
Designated New Employees and
Non-Officer Employees
effective as of March 4, 1998
149
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(x)(2) -- Reliant Energy, Incorporated CenterPoint Energy's Form 10-K 1-31447 10(y)(2)
and Subsidiaries Common Stock for the year ended December 31,
Participation Plan for 2002
Designated New Employees and
Non-Officer Employees, as
amended and restated
effective January 1, 2001
*10(y) -- Reliant Energy, Incorporated Reliant Energy's Definitive 1-3187 Exhibit A
Annual Incentive Compensation Proxy Statement for 2000 Annual
Plan, as amended and restated Meeting of Shareholders
effective January 1, 1999
*10(z)(1) -- Long-Term Incentive Plan of Reliant Energy's Registration 333-60260 4.6
Reliant Energy, Incorporated Statement on Form S-8 dated May
effective as of January 1, 4, 2001
2001
*10(z)(2) -- First Amendment to Exhibit Reliant Energy's Registration 333-60260 4.7
10(z)(1) effective as of Statement on Form S-8 dated May
January 1, 2001 4, 2001
*10(z)(3) -- Second Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(aa)(3)
10(z)(1) effective November for the year ended December 31,
5, 2003 2003
*10(z)(4) -- Long-Term Incentive Plan of CenterPoint Energy's Form 10-Q 1-31447 10.5
CenterPoint Energy, Inc. for the quarter ended June 30,
(amended and restated 2004
effective as of May 1, 2004)
*10(z)(5) -- Form of Performance Share CenterPoint Energy's Form 8-K 1-31447 10.2
Award Agreement for the dated February 22, 2006
20XX-20XX Performance Cycle
under Exhibit 10(z)(4)
*10(z)(6) -- Form of Stock Award Agreement CenterPoint Energy's Form 8-K 1-31447 10.3
(with Performance Goals) dated February 22, 2006
under Exhibit 10(z)(4)
10(aa)(1) -- Master Separation Agreement Reliant Energy's Form 10-Q for 1-3187 10.1
entered into as of December the quarter ended March 31, 2001
31, 2000 between Reliant
Energy, Incorporated and
Reliant Resources, Inc.
10(aa)(2) -- First Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(bb)(5)
10(aa)(1) effective as of for the year ended December 31,
February 1, 2003 2002
10(aa)(3) -- Employee Matters Agreement, Reliant Energy's Form 10-Q for 1-3187 10.5
entered into as of December the quarter ended March 31, 2001
31, 2000, between Reliant
Energy, Incorporated and
Reliant Resources, Inc.
10(aa)(4) -- Retail Agreement, entered Reliant Energy's Form 10-Q for 1-3187 10.6
into as of December 31, 2000, the quarter ended March 31, 2001
between Reliant Energy,
Incorporated and Reliant
Resources, Inc.
10(aa)(5) -- Tax Allocation Agreement, Reliant Energy's Form 10-Q for 1-3187 10.8
entered into as of December the quarter ended March 31, 2001
31, 2000, between Reliant
Energy, Incorporated and
Reliant Resources, Inc.
150
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
10(bb)(1) -- Separation Agreement entered CenterPoint Energy's Form 10-K 1-31447 10(cc)(1)
into as of August 31, 2002 for the year ended December 31,
between CenterPoint Energy 2002
and Texas Genco
10(bb)(2) -- Transition Services CenterPoint Energy's Form 10-K 1-31447 10(cc)(2)
Agreement, dated as of August for the year ended December 31,
31, 2002, between CenterPoint 2002
Energy and Texas Genco
10(bb)(3) -- Tax Allocation Agreement, CenterPoint Energy's Form 10-K 1-31447 10(cc)(3)
dated as of August 31, 2002, for the year ended December 31,
between CenterPoint Energy 2002
and Texas Genco
*10(cc) -- Retention Agreement effective Reliant Energy's Form 10-K for 1-3187 10(jj)
October 15, 2001 between the year ended December 31, 2001
Reliant Energy and David G.
Tees
*10(dd) -- Retention Agreement effective Reliant Energy's Form 10-K for 1-3187 10(kk)
October 15, 2001 between the year ended December 31, 2001
Reliant Energy and Michael A.
Reed
*10(ee)(1) -- Non-Qualified Executive CenterPoint Energy's Form 10-K 1-31447 10(ff)(1)
Disability Income Plan of for the year ended December 31,
Arkla, Inc. effective as of 2002
August 1, 1983
*10(ee)(2) -- Executive Disability Income CenterPoint Energy's Form 10-K 1-31447 10(ff)(2)
Agreement effective July 1, for the year ended December 31,
1984 between Arkla, Inc. and 2002
T. Milton Honea
*10(ff) -- Non-Qualified Unfunded CenterPoint Energy's Form 10-K 1-31447 10(gg)
Executive Supplemental Income for the year ended December 31,
Retirement Plan of Arkla, 2002
Inc. effective as of August
1, 1983
*10(gg)(1) -- Deferred Compensation Plan CenterPoint Energy's Form 10-K 1-31447 10(hh)(1)
for Directors of Arkla, Inc. for the year ended December 31,
effective as of November 10, 2002
1988
*10(gg)(2) -- First Amendment to Exhibit CenterPoint Energy's Form 10-K 1-31447 10(hh)(2)
10(hh)(1) effective as of for the year ended December 31,
August 6, 1997 2002
10(hh) -- Pledge Agreement dated as of CenterPoint Energy's Form 10-Q 1-31447 10.1
May 28, 2003 by Utility for the quarter ended June 30,
Holding, LLC in favor of JP 2003
Morgan Chase Bank, as
administrative agent
*10(ii) -- CenterPoint Energy Deferred CenterPoint Energy's Form 10-Q 1-31447 10.2
Compensation Plan, as amended for the quarter ended June 30,
and restated effective 2003
January 1, 2003
*10(jj)(1) -- CenterPoint Energy Short Term CenterPoint Energy's Form 10-Q 1-31447 10.3
Incentive Plan, as amended for the quarter ended September
and restated effective 30, 2003
January 1, 2003
*10(jj)(2) -- Summary of 2006 Performance CenterPoint Energy's Form 8-K 1-31447 10.1
Goals and Objectives under dated February 22, 2006
Exhibit 10(jj)(1)
151
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE
------- ----------- -------------------------------- ------------ ---------
*10(kk) -- CenterPoint Energy Stock Plan CenterPoint Energy's Form 10-K 1-31447 10(ll)
for Outside Directors, as for the year ended December 31,
amended and restated 2003
effective May 7, 2003
10(ll) -- City of Houston Franchise CenterPoint Energy's Form 10-Q 1-31447 10.1
Ordinance for the quarter ended June 30,
2005
+10(mm) -- Summary of non-employee
director compensation
+10(nn) -- Summary of named executive
officer compensation
+12 -- Computation of Ratios of
Earnings to Fixed Charges
+21 -- Subsidiaries of CenterPoint
Energy
+23 -- Consent of Deloitte & Touche
LLP
+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
152