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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 1-13265

                       CENTERPOINT ENERGY RESOURCES CORP.
             (Exact name of registrant as specified in its charter)

<TABLE>
<S>                                                   <C>
             DELAWARE                                       76-0511406
  (State or other jurisdiction of                        (I.R.S. Employer
   incorporation or organization)                     Identification Number)
</TABLE>

<TABLE>
<S>                                              <C>
          1111 LOUISIANA
       HOUSTON, TEXAS 77002                               (713) 207-1111
(Address and zip code of principal               (Registrant's telephone number,
        executive offices)                             including area code)
</TABLE>

           SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

<TABLE>
<CAPTION>
            TITLE OF EACH CLASS                NAME OF EACH EXCHANGE ON WHICH REGISTERED
            -------------------                -----------------------------------------
<S>                                            <C>
6% Convertible Subordinated Debentures due              New York Stock Exchange
                    2012
</TABLE>

           SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
                                      NONE

     CENTERPOINT ENERGY RESOURCES CORP. MEETS THE CONDITIONS SET FORTH IN
GENERAL INSTRUCTION I(1)(A) AND (B) OF FORM 10-K AND IS THEREFORE FILING THIS
FORM 10-K WITH THE REDUCED DISCLOSURE FORMAT.

     Indicate by check mark if the registrant is a well-known seasoned issuer,
as defined in Rule 405 of the Securities Act. Yes [ ] No [X]

     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 the registrant's 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 [ ] Accelerated filer [ ] Non-accelerated filer [X]

     Indicate by check mark whether the registrant is a shell company (as
defined by Rule 12b-2 of the Act). Yes [ ] No [X]

     The aggregate market value of the common equity held by non-affiliates as
of June 30, 2005: None

================================================================================

<PAGE>

                                TABLE OF CONTENTS

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                                                                                    PAGE
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<S>                                                                                 <C>
                                     PART I

Item 1.  Business................................................................    1
Item 1A. Risk Factors............................................................   12
Item 1B. Unresolved Staff Comments...............................................   16
Item 2.  Properties..............................................................   16
Item 3.  Legal Proceedings.......................................................   16
Item 4.  Submission of Matters to a Vote of Security Holders.....................   16

                                     PART II

Item 5.  Market for Registrant's Common Equity, Related Stockholder
         Matters and Issuer Purchases of Equity Securities.......................   17
Item 6.  Selected Financial Data.................................................   17
Item 7.  Management's Narrative Analysis of Results of Operations................   17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..............   28
Item 8.  Financial Statements and Supplementary Data.............................   30
Item 9.  Changes in and Disagreements with Accountants on
         Accounting and Financial Disclosure.....................................   59
Item 9A. Controls and Procedures.................................................   59
Item 9B. Other Information.......................................................   59

                                    PART III

Item 10. Directors and Executive Officers of the Registrant......................   59
Item 11. Executive Compensation..................................................   59
Item 12. Security Ownership of Certain Beneficial Owners and Management
         and Related Stockholder Matters.........................................   59
Item 13. Certain Relationships and Related Transactions..........................   60
Item 14. Principal Accountant Fees and Services..................................   60

                                     PART IV

Item 15. Exhibits and Financial Statement Schedules..............................   60
</TABLE>


                                        i

<PAGE>

     We meet the conditions specified in General Instruction I(1)(a) and (b) of
Form 10-K and are thereby permitted to use the reduced disclosure format for
wholly owned subsidiaries of reporting companies specified therein. Accordingly,
we have omitted from this report the information called for by Item 4
(Submission of Matters to a Vote of Security Holders), Item 10 (Directors and
Executive Officers of the Registrant), Item 11 (Executive Compensation), Item 12
(Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters) and Item 13 (Certain Relationships and Related
Transactions) of Form 10-K. In lieu of the information called for by Item 6
(Selected Financial Data) and Item 7 (Management's Discussion and Analysis of
Financial Condition and Results of Operations) of Form 10-K, we have included
under Item 7 a Management's Narrative Analysis of the Results of Operations to
explain the reasons for material changes in the amount of revenue and expense
items between 2003, 2004 and 2005.

           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

<PAGE>

                                     PART I

ITEM 1. BUSINESS

                                  OUR BUSINESS

GENERAL

     We own gas distribution systems serving approximately 3.1 million customers
in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Through
wholly owned subsidiaries, we also own two interstate natural gas pipelines and
gas gathering systems, provide various ancillary services, and offer variable
and fixed-price physical natural gas supplies primarily to commercial and
industrial customers and electric and gas utilities. References to "we," "us,"
and "our" mean CenterPoint Energy Resources Corp. (CERC Corp., together with our
subsidiaries, CERC). We are an indirect wholly owned subsidiary of CenterPoint
Energy, Inc. (CenterPoint Energy), a public utility holding company.

     Our reportable business segments are Natural Gas Distribution, Competitive
Natural Gas Sales and Services, Pipelines and Field Services (formerly Pipelines
and Gathering) and Other Operations.

     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 CenterPoint Energy and those of its subsidiaries. The Energy
Policy Act of 2005 (Energy Act) repealed the 1935 Act effective February 8,
2006, and since that date CenterPoint Energy 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 CenterPoint Energy 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.

     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 parent company's 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). Our parent
company's 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.

     NATURAL GAS DISTRIBUTION

     Our 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


                                        1

<PAGE>

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 our 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 our 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 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, we enter 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, we 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 we serve, 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


                                        2

<PAGE>

measuring stations at which we receive gas are owned, operated and maintained by
others, and our 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

     We compete 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 our facilities and
market and sell and/or transport natural gas directly to commercial and
industrial customers.

     COMPETITIVE NATURAL GAS SALES AND SERVICES

     We offer variable and fixed-priced physical natural gas supplies primarily
to commercial and industrial customers and electric and gas utilities through a
number of wholly-owned 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 ours
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.

     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


                                        3

<PAGE>

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

     Our 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.

     We own and operate gas transmission lines primarily located in Arkansas,
Illinois, Louisiana, Missouri, Oklahoma and Texas. Our 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.

     Our 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.

     Our 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


                                        4

<PAGE>

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 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 unallocated corporate costs
and inter-segment eliminations.

FINANCIAL INFORMATION ABOUT SEGMENTS

     For financial information about our segments, see Note 11 to our
consolidated financial statements, which note is incorporated herein by
reference.


                                        5
<PAGE>

                                   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 subsidiary of a registered public utility holding company under the
1935 Act, we 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 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 our parent 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.

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.

STATE AND LOCAL REGULATION

     In almost all communities in which we provide natural gas distribution
services, we operate 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 our material franchises expire in the near term.
We expect to be able to renew expiring franchises. In most cases, franchises to
provide natural gas utility services are not exclusive.

     Substantially all of our retail natural gas sales by our 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 we
serve.


                                       6

<PAGE>

     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.

     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.


                                       7

<PAGE>

     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, we
were 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 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;


                                       8

<PAGE>

     -    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,
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.


                                      9

<PAGE>

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
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 believe the ultimate cost
associated with resolving this matter will not have a material impact on our
financial condition or results of operations.

     Manufactured Gas Plant Sites. We and our predecessors operated manufactured
gas plants (MGP) in the past. In Minnesota, we have completed remediation on two
sites, other than ongoing monitoring and water treatment. There are five
remaining sites in our Minnesota service territory. We believe that we have no
liability with respect to two of these sites.

     At December 31, 2005, we 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


                                       10

<PAGE>

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. We have utilized an environmental
expense tracker mechanism in our rates in Minnesota to recover estimated costs
in excess of insurance recovery. As of December 31, 2005, we have 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 us or may have been owned
or operated by one of our former affiliates. We have 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 ours or our divisions. We have 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 our
motion to dismiss on the grounds that we were 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 us. We are investigating details regarding these sites and the
range of environmental expenditures for potential remediation. However, we
believe we are not liable as a former owner or operator of those sites under
CERCLA and applicable state statutes, and is vigorously contesting those suits
and our 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 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.

                                    EMPLOYEES

     As of December 31, 2005, we had 5,202 full-time employees. The following
table sets forth the number of our employees by business segment as of December
31, 2005:

<TABLE>
<CAPTION>
                                                                NUMBER REPRESENTED BY
                                                                   UNIONS OR OTHER
                                                                COLLECTIVE BARGAINING
                  BUSINESS SEGMENT                     NUMBER           GROUPS
                  ----------------                     ------   ---------------------
<S>                                                    <C>      <C>
Natural Gas Distribution............................    4,387           1,493
Competitive Natural Gas Sales and Services..........       98              --
Pipelines and Field Services........................      717              --
                                                        -----           -----
   Total............................................    5,202           1,493
                                                        =====           =====
</TABLE>

     As of December 31, 2005, approximately 29% of our employees are subject to
collective bargaining agreements. 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.
We have a good relationship with this bargaining unit and expect to
renegotiate a new agreement in 2006.


                                       11

<PAGE>

ITEM 1A. RISK FACTORS

RISK FACTORS AFFECTING OUR BUSINESSES

     RATE REGULATION OF OUR BUSINESS MAY DELAY OR DENY OUR ABILITY TO EARN A
     REASONABLE RETURN AND FULLY RECOVER OUR COSTS.

     Our rates for our local distribution companies are regulated by certain
municipalities and state commissions, and for our interstate pipelines by the
FERC, based on an analysis of our invested capital and our expenses in a test
year. Thus, the rates that we are allowed to charge may not match our 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 our costs and enable
us to earn a reasonable return on our invested capital.

     OUR BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, WHICH COULD
     LEAD TO LESS NATURAL GAS BEING MARKETED, AND OUR 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 OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.

     We compete 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 us 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 our 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 us as a result of competition may
have an adverse impact on our results of operations, financial condition and
cash flows.

     Our two interstate pipelines and our 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 our competitors
could lead to lower prices, which may have an adverse impact on our results of
operations, financial condition and cash flows.

     OUR 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 OUR SUPPLIERS AND CUSTOMERS TO MEET THEIR
     OBLIGATIONS OR OTHERWISE ADVERSELY AFFECT OUR LIQUIDITY.

     We are 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 our ability to collect balances due from our customers and, on the
regulated side, could create the potential for uncollectible accounts expense to
exceed the recoverable levels built into our 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 we operate and increase the
risk that our suppliers or customers fail or are unable to meet their
obligations. Additionally, increasing gas prices could create the need for us to
provide collateral in order to purchase gas.

     IF WE WERE TO FAIL TO EXTEND A CONTRACT WITH ONE OF OUR SIGNIFICANT
     PIPELINE CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON OUR OPERATIONS.

     Our contract with Laclede Gas Company, one of our 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 our results of operations, financial condition and cash flows.


                                       12

<PAGE>

     A DECLINE IN OUR CREDIT RATING COULD RESULT IN US HAVING TO PROVIDE
     COLLATERAL IN ORDER TO PURCHASE GAS.

     If our credit rating were to decline, we 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 we were
experiencing significant working capital requirements or otherwise lacked
liquidity, we might be unable to obtain the necessary natural gas to meet our
obligations to customers, and our results of operations, financial condition and
cash flows would be adversely affected.

     OUR PIPELINES' AND FIELD SERVICES' BUSINESS REVENUES AND RESULTS OF
     OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS.

     Our 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 substantially reduced,
it could have an adverse effect on our results of operations, financial
condition and cash flows.

     OUR REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.

     A substantial portion of our revenues is derived from natural gas sales and
transportation. Thus, our 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 $2 billion of outstanding indebtedness on a
consolidated basis. As of December 31, 2005, approximately $465 million
principal amount of this debt must be paid through 2008. Our future financing
activities may depend, at least in part, on:

     -    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; and

     -    provisions of relevant tax and securities laws.

     Our current credit ratings are discussed in "Management's Narrative
Analysis of Results of Operations -- Liquidity -- 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 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.


                                       13

<PAGE>

     THE FINANCIAL CONDITION AND LIQUIDITY OF OUR PARENT COMPANY COULD AFFECT
     OUR ACCESS TO CAPITAL, OUR CREDIT STANDING AND OUR FINANCIAL CONDITION.

     Our ratings and credit may be impacted by CenterPoint Energy's credit
standing. As of December 31, 2005, CenterPoint Energy and its other subsidiaries
have approximately $200 million principal amount of debt required to be paid
through 2008. This amount excludes amounts related to capital leases,
securitization debt and indexed debt securities obligations. In addition,
CenterPoint Energy has $830 million of outstanding convertible notes on which
holders could exercise their "put" rights during this period. We cannot assure
you that CenterPoint Energy and its other subsidiaries will be able to pay or
refinance these amounts. If CenterPoint Energy were to experience a
deterioration in its credit standing or liquidity difficulties, our access to
credit and our credit ratings could be adversely affected.

     WE ARE AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY.
     CENTERPOINT ENERGY CAN EXERCISE SUBSTANTIAL CONTROL OVER OUR DIVIDEND
     POLICY AND BUSINESS AND OPERATIONS AND COULD DO SO IN A MANNER THAT IS
     ADVERSE TO OUR INTERESTS.

     We are managed by officers and employees of CenterPoint Energy. Our
management will make determinations with respect to the following:

     -    our payment of dividends;

     -    decisions on our financings and our capital raising activities;

     -    mergers or other business combinations; and

     -    our acquisition or disposition of assets.

     There are no contractual restrictions on our ability to pay dividends to
CenterPoint Energy. Our management could decide to increase our dividends to
CenterPoint Energy to support its cash needs. This could adversely affect our
liquidity. However, under our credit facility and our receivables facility, our
ability to pay dividends is restricted by a covenant that debt as a percentage
of total capitalization may not exceed 65%.

     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 use derivative instruments, such as swaps, options, futures and
forwards, to manage our commodity and financial market risks. We 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 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;


                                       14

<PAGE>

     -    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.

     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.

     WE AND CENTERPOINT ENERGY COULD INCUR LIABILITIES ASSOCIATED WITH
     BUSINESSES AND ASSETS THAT WE HAVE TRANSFERRED TO OTHERS.

     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, CenterPoint Energy and its
subsidiaries, including us, 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 or CenterPoint Energy could be responsible for satisfying the liability.

     Prior to CenterPoint Energy's distribution of its ownership in RRI to its
shareholders, we 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 guaranty obligations prior to
separation, but when


                                       15

<PAGE>

separation occurred in September 2002, RRI had been unable to extinguish all
obligations. To secure CenterPoint Energy and us against obligations under the
remaining guarantees, RRI agreed to provide cash or letters of credit for our
benefit and that of CenterPoint Energy, and undertook to use commercially
reasonable efforts to extinguish the remaining guarantees. Our current exposure
under the remaining guarantees relates to our guaranty 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, our potential exposure under that guaranty
currently exceeds the security provided by RRI. We have requested RRI to
increase the amount of its existing letters of credit or, in the alternative, to
obtain a release of our obligations under the guaranty, and we 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

     Not applicable.

ITEM 2. PROPERTIES

CHARACTER OF OWNERSHIP

     We own our principal properties in fee. Most of our gas mains are located,
pursuant to easements and other rights, on public roads or on land owned by
others.

NATURAL GAS DISTRIBUTION

     For information regarding the properties of our Natural Gas Distribution
business segment, please read "Our Business -- Natural Gas Distribution" 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" 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 3, 8(d) and 8(e) to our consolidated financial statements, which
information is incorporated herein by reference.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     The information called for by Item 4 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).


                                       16
<PAGE>

                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES

     All of the 1,000 outstanding shares of CERC Corp.'s common stock are held
by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy.

     In 2004 and 2005, we paid dividends on our common stock of $13 million and
$100 million, respectively, to Utility Holding, LLC.

ITEM 6. SELECTED FINANCIAL DATA

     The information called for by Item 6 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries). The ratio of earnings to fixed charges for the year ended
December 31, 2005 was 2.64.

ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

     The following narrative analysis should be read in combination with our
consolidated financial statements and notes contained in Item 8 of this report.

BACKGROUND

     We are an indirect wholly owned subsidiary of CenterPoint Energy, Inc.
(CenterPoint Energy), a public utility holding company. We own gas distribution
systems serving approximately 3.1 million customers in Arkansas, Louisiana,
Minnesota, Mississippi, Oklahoma and Texas. Through wholly owned subsidiaries,
we also own two interstate natural gas pipelines and gas gathering systems,
provide various ancillary services, and offer variable and fixed-price physical
natural gas supplies primarily to commercial and industrial customers and
electric and gas utilities.

     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
CenterPoint Energy's activities and those of its subsidiaries. The Energy Policy
Act of 2005 (Energy Act) repealed the 1935 Act effective February 8, 2006, and
since that date CenterPoint Energy 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 CenterPoint Energy 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.

BUSINESS SEGMENTS

     Because we are an indirect wholly owned subsidiary of CenterPoint Energy,
our determination of reportable segments considers the strategic operating units
under which CenterPoint Energy manages sales, allocates resources and assesses
performance of various products and services to wholesale or retail customers in
differing regulatory environments. In this section, we discuss our results on a
consolidated basis and individually for each of our business segments. We also
discuss our liquidity, capital resources and critical accounting policies. 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 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:


                                       17

<PAGE>

     Natural Gas Distribution

     We own and operate 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

     Our operations also include non-rate regulated retail 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 (formerly Pipelines and Gathering)

     Our 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. Our 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. Our 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 unallocated corporate costs
and inter-segment eliminations.

                    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:

     -    state and federal legislative and regulatory actions or developments,
          including deregulation, re-regulation, changes in or application of
          laws or regulations applicable to other aspects of our business;

     -    timely and appropriate rate actions and increases, allowing recovery
          of costs and a reasonable return on investment;

     -    industrial, commercial and residential growth in our service territory
          and changes in market demand and demographic patterns;

     -    the timing and extent of changes in commodity prices, particularly
          natural gas;

     -    changes in interest rates or rates of inflation;

     -    weather variations and other natural phenomena;

     -    the timing and extent of changes in the supply of natural gas;

     -    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;


                                       18

<PAGE>

     -    effectiveness of our risk management activities;

     -    inability of various counterparties to meet their obligations to us;

     -    the ability of Reliant Energy, Inc. (RRI) to satisfy its obligations
          to us;

     -    our ability to control costs;

     -    the investment performance of CenterPoint Energy's 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.

                       CONSOLIDATED RESULTS OF OPERATIONS

     Our results of operations are affected by seasonal fluctuations in the
demand for natural gas and price movements of energy commodities. Our results of
operations are also affected by, among other things, the actions of various
federal and state governmental authorities having jurisdiction over rates we
charge, competition in our various business operations, debt service costs and
income tax expense.

     The following table sets forth selected financial data for the years ended
December 31, 2003, 2004 and 2005, followed by a discussion of our consolidated
results of operations based on operating income. We have provided a
reconciliation of consolidated operating income to net income below.

<TABLE>
<CAPTION>
                                         YEAR ENDED DECEMBER 31,
                                        ------------------------
                                         2003     2004     2005
                                        ------   ------   ------
                                              (IN MILLIONS)
<S>                                     <C>      <C>      <C>
Revenues ............................   $5,650   $6,472   $8,070
                                        ------   ------   ------
Expenses:
   Natural gas ......................    4,297    5,013    6,509
   Operation and maintenance ........      688      732      743
   Depreciation and amortization ....      176      187      198
   Taxes other than income taxes ....      130      147      156
                                        ------   ------   ------
      Total .........................    5,291    6,079    7,606
                                        ------   ------   ------
Operating Income ....................      359      393      464
Interest and other finance charges ..     (179)    (178)    (176)
Other income, net ...................        8       16       21
                                        ------   ------   ------
Income Before Income Taxes ..........      188      231      309
Income Tax Expense ..................       59       87      116
                                        ------   ------   ------
      Net Income ....................   $  129   $  144   $  193
                                        ======   ======   ======
</TABLE>

     2005 Compared to 2004. We reported net income of $193 million for 2005 as
compared to $144 million for 2004. The increase in net income of $49 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 and increased operating
income of $16 million in our Competitive Natural Gas Sales and Services business
segment primarily due to higher wholesale sales to utilities and favorable basis
differentials over the pipeline capacity that we control, partially offset by a
$29 million increase in income tax expense in 2005 as compared to 2004.

     Our effective tax rate for 2005 and 2004 was 37.4% and 37.5%, respectively.

     2004 Compared to 2003. We reported net income of $144 million for 2004 as
compared to $129 million for 2003. The increase in net income of $15 million was
primarily due to increased operating income of $21 million in our Natural Gas
Distribution business segment, primarily due to rate increases, and increased
operating income of


                                       19

<PAGE>

$22 million in our Pipelines and Field Services business segment, primarily from
increased throughput, favorable commodity prices and increased ancillary
services.

     Our effective tax rate for 2004 and 2003 was 37.5% and 31.3%, respectively.
The increase in the effective rate for 2004 compared to 2003 was primarily the
result of a non-recurring decreased tax expense in 2003 relating to our
Minnesota operations.

                    RESULTS OF OPERATIONS BY BUSINESS SEGMENT

     Revenues by segment include intersegment sales, which are eliminated in
consolidation.

     The following tables present operating income for our Natural Gas
Distribution, Competitive Natural Gas Sales and Services, and Pipelines and
Field Services 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.

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):

<TABLE>
<CAPTION>
                                                      YEAR ENDED DECEMBER 31,
                                               ------------------------------------
                                                  2003         2004         2005
                                               ----------   ----------   ----------
<S>                                            <C>          <C>          <C>
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
                                               ==========   ==========   ==========
</TABLE>

     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 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.


                                       20
<PAGE>

     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):

<TABLE>
<CAPTION>
                                       YEAR ENDED DECEMBER 31,
                                      ------------------------
                                       2003     2004     2005
                                      ------   ------   ------
<S>                                   <C>      <C>      <C>
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
                                      ======   ======   ======
</TABLE>

     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 ($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).


                                       21

<PAGE>

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):

<TABLE>
<CAPTION>
                                       YEAR ENDED DECEMBER 31,
                                      ------------------------
                                       2003     2004     2005
                                      ------   ------   ------
<S>                                   <C>      <C>      <C>
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
                                      ======   ======   ======
</TABLE>

----------
(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 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.

FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS

     For information regarding our exposure to risk as a result of fluctuations
in commodity prices and derivative instruments, please read "Quantitative and
Qualitative Disclosures About Market Risk" in Item 7A of this report.

                                    LIQUIDITY

     Our liquidity and capital requirements are affected primarily by our
results of operations, capital expenditures, debt service requirements, and
working capital needs. Our principal cash requirements during 2006 are
approximately $668 million of capital expenditures, including $343 million for
the construction of a new pipeline by


                                       22

<PAGE>

our Pipelines and Field Services business segment and $154 million principal
amount of maturing debt. We expect that borrowings under our credit facility,
anticipated cash flows from operations and borrowings from affiliates will be
sufficient to meet our cash needs for 2006.

     Capital Requirements. We anticipate investing up to an aggregate $2 billion
in capital expenditures in the years 2006 through 2010. The following table sets
forth our capital expenditures for 2005 and estimates of our capital
requirements for 2006 through 2010 (in millions):

<TABLE>
<S>                               <C>
2005 ..........................   $417
2006 ..........................    668
2007 ..........................    512
2008 ..........................    383
2009 ..........................    362
2010 ..........................    284
</TABLE>

     The following table sets forth estimates of our contractual obligations,
including payments due by period (in millions):

<TABLE>
<CAPTION>
                                                                                          2011 AND
CONTRACTUAL OBLIGATIONS                         TOTAL    2006    2007-2008   2009-2010   THEREAFTER
-----------------------                        ------   ------   ---------   ---------   ----------
<S>                                            <C>      <C>      <C>         <C>         <C>
Long-term debt, including current portion ..   $1,992   $  154     $  314       $ 12       $1,512
Interest payments (1) ......................      846      149        260        230          207
Operating leases(2) ........................       70       14         23         11           22
Benefit obligations(3) .....................       --       --         --         --           --
Purchase obligations(4) ....................      109      109         --         --           --
Non-trading derivative liabilities .........       78       43         20         12            3
Other commodity commitments(5) .............    1,316      858        428          7           23
                                               ------   ------     ------       ----       ------
   Total contractual cash obligations ......   $4,411   $1,327     $1,045       $272       $1,767
                                               ======   ======     ======       ====       ======
</TABLE>

----------
(1)  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.

(2)  For a discussion of operating leases, please read Note 8(b) to our
     consolidated financial statements.

(3)  We expect to contribute approximately $13 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.

(4)  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.

(5)  For a discussion of other commodity commitments, please read Note 8(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 us 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, we had $141 million of advances under our receivables facility.


                                       23
<PAGE>

     Prior to CenterPoint Energy's distribution of its ownership in RRI to its
shareholders, we 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 guaranty obligations prior to
separation, but when separation occurred in September 2002, RRI had been unable
to extinguish all obligations. To secure CenterPoint Energy and us against
obligations under the remaining guarantees, RRI agreed to provide cash or
letters of credit for our benefit and that of CenterPoint Energy, and undertook
to use commercially reasonable efforts to extinguish the remaining guarantees.
Our current exposure under the remaining guarantees relates to our guaranty 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, our potential exposure under
that guaranty currently exceeds the security provided by RRI. We have requested
RRI to increase the amount of its existing letters of credit or, in the
alternative, to obtain a release of our obligations under the guaranty, and we
and RRI are pursuing alternatives. RRI continues to meet its obligations under
the transportation contracts.

     Credit Facilities. In June 2005, we replaced our $250 million three-year
revolving credit facility with a $400 million five-year revolving credit
facility. Borrowings under this facility may be made at the London inter-bank
offer rate (LIBOR) plus 55 basis points, including the facility fee, based on
current credit ratings. An additional utilization fee of 10 basis points applies
to borrowings whenever more than 50% of the facility is utilized. Changes in
credit ratings could lower or raise the increment to LIBOR depending on whether
ratings improved or were lowered. Our $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 our $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. As of
February 28, 2006, our $400 million credit facility was not utilized.

     We are currently in compliance with the various business and financial
covenants contained in our credit facility.

     Money Pool. We participate in a "money pool" through which we and certain
of our affiliates 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. At December 31, 2005 and February 28, 2006, we had
borrowings of $289 million and $208 million, respectively, from the money pool.
The money pool may not provide sufficient funds to meet our cash needs.

     Securities Registered with the SEC. At December 31, 2005, we had a shelf
registration statement covering $500 million principal amount of debt
securities.

     Impact on Liquidity of a Downgrade in Credit Ratings. As of February 28,
2006, Moody's Investors Service, Inc. (Moody's), Standard & Poor's Ratings
Services, a division of The McGraw Hill Companies (S&P) and Fitch, Inc. (Fitch)
had assigned the following credit ratings to our senior unsecured debt:

<TABLE>
<CAPTION>
      MOODY'S                 S&P                  FITCH
-------------------   -------------------   -------------------
RATING   OUTLOOK(1)   RATING   OUTLOOK(2)   RATING   OUTLOOK(3)
------   ----------   ------   ----------   ------   ----------
<S>      <C>          <C>      <C>          <C>      <C>
 Baa3      Stable       BBB      Stable       BBB      Stable
</TABLE>

----------
(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.

     We cannot assure you that these 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


                                       24

<PAGE>

recommendations to buy, sell or hold our securities and may be revised or
withdrawn at any time by the rating agency. Each rating should be evaluated
independently of any other rating. Any future reduction or withdrawal of one or
more of our credit ratings could have a material adverse impact on our ability
to obtain short- and long-term financing, the cost of such financings, the
willingness of suppliers to extend credit lines to us on an unsecured basis and
the execution of our commercial strategies.

     A decline in credit ratings could increase borrowing costs under our $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.

     Our $400 million credit facility does not contain a material adverse change
clause with respect to borrowings.

     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, we and our subsidiaries purchase natural gas
under supply agreements that contain an aggregate credit threshold of $100
million based on our 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 CenterPoint Energy's revolving credit facility, a
payment default on, or a non-payment default that permits acceleration of, any
indebtedness exceeding $50 million by us will cause a default. Pursuant to the
indenture governing CenterPoint Energy's senior notes, a payment default by us,
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, CenterPoint Energy 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
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 to satisfy its obligations to us;

     -    slower customer payments and increased write-offs of receivables due
          to higher gas prices;

     -    contributions to benefit plans;


                                       25

<PAGE>

     -    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 Ability to Issue Securities and Pay
Dividends. Our bank facility and our receivables facility limit our debt as a
percentage of our total capitalization to 65 percent and contain an EBITDA to
interest covenant.

     Our parent, CenterPoint Energy, was a registered public utility holding
company under the 1935 Act. The 1935 Act and related rules and regulations
imposed a number of restrictions on CenterPoint Energy's activities and those of
its subsidiaries. The Energy Act repealed the 1935 Act effective February 8,
2006, and since that date CenterPoint Energy and its subsidiaries have no longer
been subject to restrictions imposed under the 1935 Act. The Energy Act includes
a new 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 CenterPoint Energy 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.

     Relationship with CenterPoint Energy. We are an indirect wholly owned
subsidiary of CenterPoint Energy. As a result of this relationship, the
financial condition and liquidity of our parent company could affect our access
to capital, our credit standing and our financial condition.

                          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 of CenterPoint Energy.

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 annually for
goodwill as required by SFAS No. 142, "Goodwill and Other Intangible Assets."
Unforeseen events and changes in circumstances and market conditions and
material differences in the value of long-lived assets and intangibles due to
changes in estimates of future cash flows, regulatory matters and operating
costs could negatively affect the fair value of our assets and result in an
impairment charge.

     Fair value is the amount at which the asset could be bought or sold in a
current transaction between willing parties and may be estimated using a number
of techniques, including quoted market prices or valuations by third parties,
present value techniques based on estimates of cash flows, or multiples of
earnings or revenue performance


                                       26

<PAGE>

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.

     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 4%. Similarly, an increase in the discount rate by 25 basis points
would decrease asset retirement obligations by approximately 3%. At December 31,
2005, our estimated cost of retiring these assets is approximately $65 million.

UNBILLED REVENUES

     Revenues related to the sale and/or delivery of natural gas are generally
recorded when natural gas is delivered to customers. However, the determination
of 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 natural gas delivered to customers since the date of the last
meter reading are estimated and the corresponding unbilled revenue is estimated.
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.


                                       27

<PAGE>

                          NEW ACCOUNTING PRONOUNCEMENTS

     See Note 2(n) to the consolidated financial statements, incorporated herein
by reference, 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 participate in CenterPoint Energy's qualified non-contributory
pension plan covering substantially all employees. Pension expense for 2006 is
estimated to be $16 million based on an expected return on plan assets of 8.5%
and a discount rate of 5.7% as of December 31, 2005. Pension expense for the
year ended December 31, 2005 was $15 million. Future changes in plan asset
returns, assumed discount rates and various other factors related to the pension
will impact our future pension expense. We cannot predict with certainty what
these factors will be in the future.

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 and bank loans that subject us to the
risk of loss associated with movements in market interest rates.

     We had no floating-rate obligations at December 31, 2004 and 2005.

     At December 31, 2004 and 2005, we had outstanding fixed-rate debt and trust
preferred securities aggregating $2.4 billion and $2.0 billion, respectively, in
principal amount and having a fair value of $2.7 billion and $2.2


                                       28

<PAGE>

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 6 to our consolidated financial statements). However,
the fair value of these instruments would increase by approximately $53 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.

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 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.

     CenterPoint Energy has 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
CenterPoint Energy's 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 CenterPoint
Energy's 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.


                                       29

<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder of
CenterPoint Energy Resources Corp.
Houston, Texas

We have audited the accompanying consolidated balance sheets of CenterPoint
Energy Resources Corp. and subsidiaries (the Company) as of December 31, 2004
and 2005, and the related consolidated statements of income, comprehensive
income, cash flows and stockholder's equity 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. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, 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 Resources Corp.
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.

DELOITTE & TOUCHE LLP

Houston, Texas
March 24, 2006

                                       30
<PAGE>

               CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
        (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

                        STATEMENTS OF CONSOLIDATED INCOME

<TABLE>
<CAPTION>
                                            YEAR ENDED DECEMBER 31,
                                           ------------------------
                                            2003     2004     2005
                                           ------   ------   ------
                                                 (IN MILLIONS)
<S>                                        <C>      <C>      <C>
REVENUES ...............................   $5,650   $6,472   $8,070
                                           ------   ------   ------
EXPENSES:
   Natural gas .........................    4,297    5,013    6,509
   Operation and maintenance ...........      688      732      743
   Depreciation and amortization .......      176      187      198
   Taxes other than income taxes .......      130      147      156
                                           ------   ------   ------
      Total ............................    5,291    6,079    7,606
                                           ------   ------   ------
OPERATING INCOME .......................      359      393      464
                                           ------   ------   ------
OTHER INCOME (EXPENSE):
   Interest and other finance charges ..     (179)    (178)    (176)
   Other, net ..........................        8       16       21
                                           ------   ------   ------
      Total ............................     (171)    (162)    (155)
                                           ------   ------   ------
INCOME BEFORE INCOME TAXES .............      188      231      309
   Income Tax Expense ..................       59       87      116
                                           ------   ------   ------
NET INCOME .............................   $  129   $  144   $  193
                                           ======   ======   ======
</TABLE>

          See Notes to the Company's Consolidated Financial Statements

                                       31

<PAGE>


               CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
        (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

                 STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31,
                                                                             -----------------------
                                                                               2003   2004   2005
                                                                               ----   ----   ----
                                                                                  (IN MILLIONS)
<S>                                                                          <C>      <C>    <C>
Net income ...............................................................     $129   $144   $193
                                                                               ----   ----   ----
Other comprehensive income (loss), net of tax:
   Net deferred gain from cash flow hedges (net of tax of $15, $31
      and $9) ............................................................       22     59     17
   Reclassification of net deferred loss (gain) from cash flow
      hedges realized in net income (net of tax of $1, ($12) and ($5)) ...        1    (24)    (8)
   Reclassification of deferred gain from de-designation of cash
      flow hedges to over/under recovery of gas costs (net of tax of
      ($37)) .............................................................       --    (68)    --
                                                                               ----   ----   ----
Other comprehensive income (loss) ........................................       23    (33)     9
                                                                               ----   ----   ----
Comprehensive income .....................................................     $152   $111   $202
                                                                               ====   ====   ====
</TABLE>

          See Notes to the Company's Consolidated Financial Statements


                                       32

<PAGE>

               CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
        (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

                           CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                     DECEMBER 31,
                                                                   ---------------
                                                                    2004     2005
                                                                   ------   ------
                                                                    (IN MILLIONS)
<S>                                                                <C>      <C>
                                     ASSETS

CURRENT ASSETS:
   Cash and cash equivalents ...................................   $  141   $   31
   Accounts receivable, net ....................................      545      942
   Accrued unbilled revenue ....................................      502      500
   Accounts and notes receivable -- affiliated companies, net ..       12       --
   Inventory ...................................................      201      323
   Non-trading derivative assets ...............................       50      131
   Taxes receivable ............................................      155      117
   Deferred tax asset ..........................................       12       17
   Prepaid expenses ............................................        9       11
   Other .......................................................       92      119
                                                                   ------   ------
      Total current assets .....................................    1,719    2,191
                                                                   ------   ------
PROPERTY, PLANT AND EQUIPMENT, NET .............................    3,834    4,105
                                                                   ------   ------
OTHER ASSETS:
   Goodwill ....................................................    1,741    1,709
   Other intangibles, net ......................................       20       18
   Non-trading derivative assets ...............................       18      104
   Accounts and notes receivable -- affiliated companies, net ..       18        9
   Other .......................................................      117      165
                                                                   ------   ------
      Total other assets .......................................    1,914    2,005
                                                                   ------   ------
      TOTAL ASSETS .............................................   $7,467   $8,301
                                                                   ======   ======

                      LIABILITIES AND STOCKHOLDER'S EQUITY

CURRENT LIABILITIES:
   Current portion of long-term debt ...........................   $  367   $  154
   Accounts payable ............................................      733    1,077
   Accounts and notes payable -- affiliated companies, net .....       --      319
   Taxes accrued ...............................................       78       67
   Interest accrued ............................................       58       46
   Customer deposits ...........................................       60       62
   Non-trading derivative liabilities ..........................       26       43
   Other .......................................................      273      341
                                                                   ------   ------
      Total current liabilities ................................    1,595    2,109
                                                                   ------   ------
OTHER LIABILITIES:
   Accumulated deferred income taxes, net ......................      641      663
   Non-trading derivative liabilities ..........................        6       35
   Benefit obligations .........................................      128      127
   Other .......................................................      557      716
                                                                   ------   ------
      Total other liabilities ..................................    1,332    1,541
                                                                   ------   ------
LONG-TERM DEBT .................................................    2,001    1,838
                                                                   ------   ------

COMMITMENTS AND CONTINGENCIES (NOTE 8)

STOCKHOLDER'S EQUITY ...........................................    2,539    2,813
                                                                   ------   ------
      TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY ...............   $7,467   $8,301
                                                                   ======   ======
</TABLE>

          See Notes to the Company's Consolidated Financial Statements


                                       33

<PAGE>

               CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
        (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

                      STATEMENTS OF CONSOLIDATED CASH FLOWS

<TABLE>
<CAPTION>
                                                                              YEAR ENDED DECEMBER 31,
                                                                              -----------------------
                                                                                2003    2004    2005
                                                                               -----   -----   -----
                                                                                   (IN MILLIONS)
<S>                                                                           <C>      <C>     <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
   Net income .............................................................    $ 129   $ 144   $ 193
   Adjustments to reconcile net income to net cash provided by operating
      activities:
      Depreciation and amortization .......................................      176     187     198
      Deferred income taxes ...............................................       25      (8)     32
      Amortization of deferred financing costs ............................        8      10       9
      Changes in other assets and liabilities:
         Accounts receivable and unbilled revenues, net ...................     (122)   (163)   (393)
         Accounts receivable/payable, affiliates ..........................       (4)      7      10
         Inventory ........................................................      (51)    (14)   (109)
         Taxes receivable .................................................       29     118      39
         Accounts payable .................................................       58     208     326
         Fuel cost recovery ...............................................       25      25    (129)
         Interest and taxes accrued .......................................       18      11     (23)
         Net non-trading derivative assets and liabilities ................       18     (39)    (12)
         Other current assets .............................................      (37)    (18)    (31)
         Other current liabilities ........................................       (1)    (20)    131
         Other assets .....................................................       20      47       8
         Other liabilities ................................................       40      (6)     30
         Other, net .......................................................      (14)     (3)     (3)
                                                                               -----   -----   -----
            Net cash provided by operating activities .....................      317     486     276
                                                                               -----   -----   -----

CASH FLOWS FROM INVESTING ACTIVITIES:
   Capital expenditures ...................................................     (265)   (269)   (403)
   Decrease (increase) in affiliate notes receivable ......................        5     (30)     42
   Other, net .............................................................       (7)     (3)    (11)
                                                                               -----   -----   -----
            Net cash used in investing activities .........................     (267)   (302)   (372)
                                                                               -----   -----   -----

CASH FLOWS FROM FINANCING ACTIVITIES:
   Payments of long-term debt .............................................     (508)     --    (372)
   Proceeds from long-term debt ...........................................      928      --      --
   Increase (decrease) in short-term borrowings, net ......................     (284)    (63)     --
   Increase (decrease) in notes with affiliates, net ......................      (74)     --     288
   Contribution from parent ...............................................       --      --     171
   Dividends to parent ....................................................       --     (13)   (100)
   Debt issuance costs ....................................................      (87)     (1)     (1)
                                                                               -----   -----   -----
            Net cash used in financing activities .........................      (25)    (77)    (14)
                                                                               -----   -----   -----
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ......................       25     107    (110)
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE YEAR ........................        9      34     141
                                                                               -----   -----   -----
CASH AND CASH EQUIVALENTS AT END OF THE YEAR ..............................    $  34   $ 141   $  31
                                                                               =====   =====   =====
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

   Cash Payments:
      Interest, net of capitalized interest................................    $ 164   $ 176   $ 181
      Income taxes (refunds) ..............................................      (49)     42      87
   Non-cash transactions:
      Increase in accounts payable related to capital expenditures ........    $  --   $  --   $  14
</TABLE>

          See Notes to the Company's Consolidated Financial Statements


                                       34
<PAGE>

               CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
        (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

                 STATEMENTS OF CONSOLIDATED STOCKHOLDER'S EQUITY

<TABLE>
<CAPTION>
                                                      2003               2004               2005
                                                ---------------    ---------------    ---------------
                                                SHARES   AMOUNT    SHARES   AMOUNT    SHARES   AMOUNT
                                                ------   ------    ------   ------    ------   ------
                                                        (IN MILLIONS, EXCEPT SHARE AMOUNTS)
<S>                                             <C>      <C>        <C>      <C>       <C>      <C>
COMMON STOCK
   Balance, beginning of year ...............   1,000        --     1,000    $   --    1,000    $   --
                                                -----    ------     -----    ------    -----    ------
   Balance, end of year .....................   1,000        --     1,000        --    1,000        --
                                                -----    ------     -----    ------    -----    ------
ADDITIONAL PAID-IN-CAPITAL
   Balance, beginning of year ...............             1,986               1,985              2,232
   Contribution from parent .................                --                 247                171
   Other ....................................                (1)                 --                  1
                                                         ------              ------             ------
   Balance, end of year .....................             1,985               2,232              2,404
                                                         ------              ------             ------
RETAINED EARNINGS
   Balance, beginning of year ...............                45                 174                305
   Net income ...............................               129                 144                193
   Dividend to parent .......................                --                 (13)              (100)
                                                         ------              ------             ------
   Balance, end of year .....................               174                 305                398
                                                         ------              ------             ------
ACCUMULATED OTHER COMPREHENSIVE INCOME
   Balance, end of year:
   Net deferred gain from cash flow hedges ..                35                   2                 11
                                                         ------              ------             ------
   Total accumulated other comprehensive
      income, end of year ...................                35                   2                 11
                                                         ------              ------             ------
      Total Stockholder's Equity ............            $2,194              $2,539             $2,813
                                                         ======              ======             ======
</TABLE>

          See Notes to the Company's Consolidated Financial Statements


                                       35

<PAGE>

               CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
        (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BACKGROUND AND BASIS OF PRESENTATION

     CenterPoint Energy Resources Corp. (CERC Corp., and, together with its
subsidiaries, the Company), owns and operates natural gas distribution
facilities, interstate pipelines and natural gas gathering, processing and
treating facilities. CERC Corp. is a Delaware corporation.

     The Company's operations of its local distribution companies are conducted
through two unincorporated divisions: Minnesota Gas and Southern Gas Operations.
Through wholly owned subsidiaries, the Company 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.

     The Company is an indirect wholly owned subsidiary of CenterPoint Energy,
Inc. (CenterPoint Energy), a public utility holding company. 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
CenterPoint Energy and its subsidiaries. The Energy Policy Act of 2005 (Energy
Act) repealed the 1935 Act effective February 8, 2006, and since that date
CenterPoint Energy 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 CenterPoint Energy 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.

BASIS OF PRESENTATION

     For a description of the Company's reportable business segments, see Note
11.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a)  RECLASSIFICATIONS AND USE OF ESTIMATES

     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 11 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 CERC Corp. and its wholly owned and majority owned
subsidiaries are included in the Company's 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


                                       36

<PAGE>

marketable securities, are carried at cost.

(c)  REVENUES

     The Company records revenue for natural gas sales and services under the
accrual method and these revenues are recognized upon delivery to customers.
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.

(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:

<TABLE>
<CAPTION>
                                                             WEIGHTED
                                                              AVERAGE       DECEMBER 31,
                                                           USEFUL LIVES   ---------------
                                                              (YEARS)      2004     2005
                                                           ------------   ------   ------
                                                                           (IN MILLIONS)
<S>                                                        <C>            <C>      <C>
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            35       20
                                                                          ------   ------
      Total ............................................                   4,296    4,674
                                                                          ------   ------
Accumulated depreciation and amortization:
   Natural gas distribution ............................                    (285)    (391)
   Competitive natural gas sales and services ..........                      (6)      (5)
   Pipelines and field services ........................                    (157)    (167)
   Other property ......................................                     (14)      (6)
                                                                          ------   ------
      Total accumulated depreciation and amortization ..                    (462)    (569)
                                                                          ------   ------
         Property, plant and equipment, net ............                  $3,834   $4,105
                                                                          ======   ======
</TABLE>

     The components of the Company's other intangible assets consist of the
following:

<TABLE>
<CAPTION>
                       DECEMBER 31, 2004         DECEMBER 31, 2005
                    -----------------------   -----------------------
                    CARRYING    ACCUMULATED   CARRYING    ACCUMULATED
                     AMOUNT    AMORTIZATION    AMOUNT    AMORTIZATION
                    --------   ------------   --------   ------------
                                      (IN MILLIONS)
<S>                 <C>        <C>            <C>        <C>
Land Use Rights..      $ 7         $(3)          $ 7         $ (3)
Other............       21          (5)           21           (7)
                       ---         ---           ---         ----
   Total.........      $28         $(8)          $28         $(10)
                       ===         ===           ===         ====
</TABLE>

     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.

     Amortization expense for other intangibles for each of the years ended
December 2003, 2004 and 2005 was $2 million. Estimated amortization expense is
approximately $2 million per year for the five succeeding fiscal years.


                                       37

<PAGE>

    Goodwill by reportable business segment is as follows (in millions):

<TABLE>
<CAPTION>
                                                     COMPETITIVE
                                                     NATURAL GAS   PIPELINES
                                       NATURAL GAS    SALES AND    AND FIELD     OTHER
                                      DISTRIBUTION     SERVICES     SERVICES   OPERATIONS    TOTAL
                                      ------------   -----------   ---------   ----------   -------
<S>                                   <C>            <C>           <C>         <C>          <C>
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
                                          ====           ====         ====        ====      ======
</TABLE>

----------
(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 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 utility operations of the Natural Gas Distribution business
segment and to some of the accounts of the Pipelines and Gathering business
segment.


                                       38
<PAGE>

     The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheets as of December 31, 2004 and 2005:

<TABLE>
<CAPTION>
                                                            DECEMBER 31,
                                                           -------------
                                                            2004    2005
                                                           -----   -----
                                                           (IN MILLIONS)
<S>                                                        <C>     <C>
Regulatory assets in other long-term assets.............   $  21   $  53
Regulatory liabilities in other long-term liabilities...    (433)   (434)
                                                           -----   -----
   Total................................................   $(412)  $(381)
                                                           =====   =====
</TABLE>

     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.

     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 $428 million and $406
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.

     The following table presents depreciation and amortization expense
for 2003, 2004 and 2005:

<TABLE>
<CAPTION>
                                                    YEAR ENDED DECEMBER 31,
                                                    -----------------------
                                                       2003   2004   2005
                                                       ----   ----   ----
                                                         (IN MILLIONS)
<S>                                                 <C>       <C>    <C>
Depreciation expense.............................      $161   $171   $180
Amortization expense.............................        15     16     18
                                                       ----   ----   ----
   Total depreciation and amortization expense...      $176   $187   $198
                                                       ====   ====   ====
</TABLE>

(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 $1 million, $2 million and $1 million, respectively.

(h)  INCOME TAXES

     The Company is included in the consolidated income tax returns of
CenterPoint Energy. The Company calculates its income tax provision on a
separate return basis under a tax sharing agreement with CenterPoint Energy.
Pursuant to the tax sharing agreement with CenterPoint Energy, in both 2004 and
2005, the Company received an allocation of CenterPoint Energy's tax benefits
totaling $171 million. 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. Current federal and certain
state income taxes are payable to or receivable from CenterPoint Energy.
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 7.


                                       39

<PAGE>

(i)  ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

     Accounts receivable are net of an allowance for doubtful accounts of $28
million and $38 million at December 31, 2004 and 2005, respectively. The
provision for doubtful accounts in the Company's Statements of Consolidated
Income for 2003, 2004 and 2005 was $24 million, $26 million and $37 million,
respectively.

     As of December 31, 2004 and 2005, the Company 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 the Company 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 the Company are pledged to a
gas supplier to secure obligations incurred in connection with the purchase of
gas by the Company and totaled approximately $433 million as of December 31,
2005.

     In January 2006, the Company'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 the Company 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.
Material and supplies are valued at the lower of average cost or market.
Inventories used in the natural gas distribution operations are also primarily
valued at the lower of average cost or market.

<TABLE>
<CAPTION>
                             DECEMBER 31,
                            -------------
                             2004   2005
                             ----   ----
                            (IN MILLIONS)
<S>                         <C>     <C>
Materials and supplies...    $ 25   $ 29
Natural gas..............     176    294
                             ----   ----
   Total inventory.......    $201   $323
                             ====   ====
</TABLE>

(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 stockholders' 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
Income.

     As of December 31, 2004 and 2005, the Company held no "available-for-sale"
or "trading" securities.

(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


                                       40

<PAGE>

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.

(n)  NEW ACCOUNTING PRONOUNCEMENTS

     In May 2005, the FASB issued Statement of Financial Accounting Standards
(SFAS) No. 154, "Accounting Changes and Error Corrections, a replacement of APB
Opinion No. 20 and FASB Statement No. 3" (SFAS No. 154). SFAS No. 154 provides
guidance on the accounting for and reporting of accounting changes and error
corrections. It establishes, unless impracticable, retrospective application as
the required method for reporting a change in accounting principle in the
absence of explicit transition requirements specific to the newly adopted
accounting principle. The correction of an error in previously issued financial
statements is not an accounting change and must be reported as a prior-period
adjustment by restating previously issued financial statements. SFAS No. 154 is
effective for accounting changes and corrections of errors made in fiscal years
beginning after December 15, 2005.

     In March 2005, the FASB issued 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. 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
$65 million, an increase in net property, plant and equipment of $31 million
and a $34 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 $57 million and
$61 million as of January 1, 2004 and December 31, 2004, respectively.

     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)  EMPLOYEE BENEFIT PLANS

     PENSION PLANS

     Substantially all of the Company's employees participate in CenterPoint
Energy's qualified non-contributory pension plan. Under the cash balance
formula, participants accumulate a retirement benefit based upon 4% of


                                       41

<PAGE>

eligible earnings and accrued interest. Prior to 1999, the pension plan accrued
benefits based on years of service, final average pay and covered compensation.
As a result, certain employees participating in the plan as of December 31, 1998
are eligible to receive the greater of the accrued benefit calculated under the
prior plan through 2008 or the cash balance formula.

     CenterPoint Energy's funding policy is to review amounts annually in
accordance with applicable regulations in order to achieve adequate funding of
projected benefit obligations. Pension expense is allocated to the Company based
on covered employees. This calculation is intended to allocate pension costs in
the same manner as a separate employer plan. Assets of the plan are not
segregated or restricted by CenterPoint Energy's participating subsidiaries. The
Company recognized pension expense of $36 million, $35 million and $15 million
for the years ended December 31, 2003, 2004 and 2005, respectively.

     In addition to the plan, the Company participates in CenterPoint Energy's
non-qualified benefit restoration plan, which allows participants to retain the
benefits to which they would have been entitled under the qualified pension plan
except for federally mandated limits on these benefits or on the level of salary
on which these benefits may be calculated. The expense associated with the
non-qualified pension plan was $3 million for the year ended December 31, 2003
and less than $1 million for each of the years ended December 31, 2004 and 2005.

     SAVINGS PLAN

     The Company participates in CenterPoint Energy's qualified savings plan,
which includes a cash or deferred arrangement under Section 401(k) of the
Internal Revenue Code of 1986, as amended. 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. CenterPoint
Energy matches 75% of the first 6% of each employee's compensation contributed.
CenterPoint Energy 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. CenterPoint Energy allocates to the
Company the savings plan benefit expense related to the Company's employees.

     Savings plan benefit expense was $15 million, $16 million and $17 million
for the years ended December 31, 2003, 2004 and 2005, respectively.

     POSTRETIREMENT BENEFITS

     The Company's employees participate in CenterPoint Energy's plans which
provide 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.

     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
CenterPoint Energy'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 $5 million, including $2 million
of amortization of the actuarial loss, $1 million of reduced service cost and $2
million of reduced interest cost on the accumulated postretirement benefit
obligation.

     The Company is required to fund a portion of its obligations in accordance
with rate orders. All other obligations are funded on a pay-as-you-go basis.


                                       42

<PAGE>

     The net postretirement benefit cost includes the following components:

<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                                       -----------------------
                                                          2003   2004   2005
                                                          ----   ----   ----
                                                             (IN MILLIONS)
<S>                                                    <C>       <C>    <C>
Service cost -- benefits earned during the period...      $ 2    $ 2    $ 1
Interest cost on projected benefit obligation.......       10     10      8
Expected return on plan assets......................       (2)    (2)    (2)
Amortization of prior service cost..................        2      2      2
Other...............................................       --      1      1
                                                          ---    ---    ---
Net postretirement benefit cost.....................      $12    $13    $10
                                                          ===    ===    ===
</TABLE>

     The Company used the following assumptions to determine net postretirement
benefit costs:

<TABLE>
<CAPTION>
                                                  YEAR ENDED
                                                 DECEMBER 31,
                                              ------------------
                                              2003   2004   2005
                                              ----   ----   ----
<S>                                           <C>    <C>    <C>
Discount rate..............................   6.75%  6.25%  5.75%
Expected return on plan assets.............    9.0%   8.5%   8.0%
</TABLE>

     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.

     Following are reconciliations of the Company's beginning and ending
balances of its postretirement benefit plan's benefit obligation, plan assets
and funded status for 2004 and 2005.

<TABLE>
<CAPTION>
                                                              YEAR ENDED
                                                             DECEMBER 31,
                                                         -------------------
                                                           2004       2005
                                                         --------   --------
                                                            (IN MILLIONS)
<S>                                                      <C>        <C>
CHANGE IN BENEFIT OBLIGATION
Accumulated benefit obligation, beginning of year ....    $ 171      $ 174
Service cost .........................................        2          1
Interest cost ........................................       10          8
Benefit enhancement ..................................        1          1
Benefits paid ........................................      (21)       (17)
Participant contributions ............................        4          3
Actuarial loss (gain) ................................        7        (38)
                                                          -----      -----
Accumulated benefit obligation, end of year ..........    $ 174      $ 132
                                                          =====      =====
CHANGE IN PLAN ASSETS
Plan assets, beginning of year .......................    $  21      $  21
Benefits paid ........................................      (21)       (17)
Employer contributions ...............................       14         12
Participant contributions ............................        4          3
Actual investment return .............................        3          1
                                                          -----      -----
Plan assets, end of year .............................    $  21      $  20
                                                          =====      =====
RECONCILIATION OF FUNDED STATUS
Funded status ........................................    $(153)     $(112)
Unrecognized prior service cost ......................       13         11
Unrecognized actuarial loss ..........................       46          9
                                                          -----      -----
Net amount recognized in balance sheets ..............    $ (94)     $ (92)
                                                          =====      =====
ACTUARIAL ASSUMPTIONS
Discount rate ........................................     5.75%       5.7%
Expected long-term return on assets...................      8.0%       4.8%
Healthcare cost trend rate assumed for the next year..     9.75%       9.0%
Rate to which the cost trend rate is assumed to
   decline (ultimate trend rate)......................      5.5%       5.5%
Year that the rate reaches the ultimate trend rate....     2011       2011
Measurement date used to determine plan obligations
   and assets.........................................   December   December
                                                         31, 2004   31, 2005
</TABLE>


                                       43
<PAGE>

     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:

<TABLE>
<CAPTION>
                                                         1%         1%
                                                     INCREASE   DECREASE
                                                     --------   --------
                                                        (IN MILLIONS)
<S>                                                  <C>        <C>
Effect on the postretirement benefit obligation...      $5        ($4)
</TABLE>

     The following table displays the weighted average asset allocations as of
December 31, 2003 and 2004 for the Company's postretirement benefit plan:

<TABLE>
<CAPTION>
                                     DECEMBER 31,
                                     ------------
                                      2004   2005
                                      ----   ----
<S>                                  <C>     <C>
Domestic equity securities........     38%     8%
International equity securities...     11     --
Debt securities...................     50     90
Cash..............................      1      2
                                      ----   ----
   Total.........................     100%   100%
                                      ====   ====
</TABLE>

     In managing the investments associated with the postretirement benefit
plan, 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, which manages liquidity
requirements while maintaining a long-term horizon in making investment
decisions and efficient and effective management of plan assets.

     As part of the investment strategy discussed above, the Company has adopted
and maintains the following asset allocation ranges for its postretirement
benefit plan:

<TABLE>
<S>                             <C>
Domestic equity securities...     4-6%
Debt securities..............   92-94%
Cash.........................     0-2%
</TABLE>

     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 Company expects to contribute $13 million to its postretirement
benefits plan in 2006.

     The following benefit payments are expected to be paid by the
postretirement benefit plan (in millions):

<TABLE>
<CAPTION>
               POSTRETIREMENT BENEFIT PLAN
               ---------------------------
                              MEDICARE
                    BENEFIT    SUBSIDY
                   PAYMENTS   RECEIPTS
                   --------   --------
<S>            <C>            <C>
2006........          $11       $ (1)
2007........           11         (2)
2008........           11         (2)
2009........           11         (2)
2010........           11         (2)
2011-2015...           61        (10)
</TABLE>

     POSTEMPLOYMENT BENEFITS

     The Company participates in CenterPoint Energy's plan which provides
postemployment benefits 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). Postemployment benefits costs were $5 million, $3 million and
$3 million in 2003, 2004 and 2005, respectively.


                                       44

<PAGE>

     Included in "Benefit Obligations" in the accompanying Consolidated Balance
Sheets at December 31,2004 and 2005, was $18 million and $19 million,
respectively, related to postemployment benefits.

     OTHER NON-QUALIFIED PLANS

     The Company participates in CenterPoint Energy's 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 benefits
expense relating to these programs of $1 million each year. Included in "Benefit
Obligations" in the accompanying Consolidated Balance Sheets at December 31,
2004 and 2005, was $9 million and $7 million, respectively, relating to deferred
compensation plans.

3. REGULATORY MATTERS

(a) RATE CASES

     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.


                                       45

<PAGE>

     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, the
Company 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 does not expect the outcome of this
matter to have a material impact on its financial condition, results of
operations or cash flows.

(b) 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.

(c) 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.


                                       46

<PAGE>

     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.

4. RELATED PARTY TRANSACTIONS

     The following table summarizes receivables from, or payables to,
CenterPoint Energy or its subsidiaries:

<TABLE>
<CAPTION>
                                                       DECEMBER 31,
                                                      -------------
                                                      2004   2005
                                                      ----   -----
                                                      (IN MILLIONS)
<S>                                                   <C>    <C>
Accounts receivable from affiliates ...............   $  4   $   4
Accounts payable to affiliates ....................    (34)    (34)
Notes receivable from/(payable to) affiliates(1) ..     42    (289)
                                                      ----   -----
   Accounts and notes receivable/(payable) --
      affiliated companies, net ...................   $ 12   $(319)
                                                      ====   =====
Long-term accounts receivable from affiliates .....   $ 64   $  29
Long-term accounts payable to affiliates ..........    (45)    (20)
Long-term notes payable to affiliates .............     (1)     --
                                                      ----   -----
   Long-term accounts and notes receivable --
      affiliated companies, net ...................   $ 18   $   9
                                                      ====   =====
</TABLE>

----------
(1)  The Company participates in a "money pool" through which it 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. The Company's money pool borrowings of $289 million at December 31,
     2005 had a weighted average interest rate of 4.7%.

     For the years ended December 31, 2003, 2004 and 2005, the Company had net
interest income related to affiliate borrowings of $3 million, $9 million and $3
million, respectively.

     CenterPoint Energy provides some corporate services to the Company. The
costs of services have been charged directly to the Company using methods that
management believes are reasonable. These methods include negotiated usage
rates, dedicated asset assignment, and proportionate corporate formulas based on
assets, operating expenses and employees. These charges are not necessarily
indicative of what would have been incurred had the Company not been an
affiliate. Amounts charged to the Company for these services were $113 million,
$116 million and $129 million for 2003, 2004 and 2005, respectively, and are
included primarily in operation and maintenance expenses.

     Pursuant to the tax sharing agreement with CenterPoint Energy, the Company
received an allocation of CenterPoint Energy's tax benefits of $171 million for
both 2004 and 2005, which was recorded as an increase to additional paid-in
capital.

     In 2004 and 2005, the Company paid dividends of $13 million and $100
million, respectively.

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.


                                       47

<PAGE>

(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 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 Income under the "Expenses" 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. 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.


                                       48

<PAGE>

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.

(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):

<TABLE>
<CAPTION>
                             DECEMBER 31, 2004     DECEMBER 31, 2005
                            -------------------   -------------------
                             INVESTMENT            INVESTMENT
                            GRADE(1)(2)   TOTAL   GRADE(1)(2)   TOTAL
                            -----------   -----   -----------   -----
<S>                         <C>           <C>     <C>           <C>
Energy marketers ........       $10        $17        $ 24       $ 25
Financial institutions ..        50         50         208        208
Other ...................         1          1          --          2
                                ---        ---        ----       ----
   Total ................       $61        $68        $232       $235
                                ===        ===        ====       ====
</TABLE>

----------
(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

     CenterPoint Energy 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, 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 CenterPoint Energy'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 CenterPoint Energy'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.


                                       49
<PAGE>

6. LONG-TERM DEBT AND RECEIVABLES FACILITY

<TABLE>
<CAPTION>
                                                                        DECEMBER 31, 2004        DECEMBER 31, 2005
                                                                     ----------------------   ----------------------
                                                                     LONG-TERM   CURRENT(1)   LONG-TERM   CURRENT(1)
                                                                     ---------   ----------   ---------   ----------
                                                                                      (IN MILLIONS)
<S>                                                                  <C>         <C>          <C>         <C>
Long-term debt:
   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(2).....................................................          6         --            --         --
Other.............................................................         --         36            --         --
Unamortized discount and premium(3)...............................          3         --             3         --
                                                                       ------       ----        ------       ----
   Total long-term debt...........................................     $2,001       $367        $1,838       $154
                                                                       ======       ====        ======       ====
</TABLE>

----------
(1)  Includes amounts due or exchangeable within one year of the date noted.

(2)  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.

(3)  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

     In June 2005, the Company 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 the London inter-bank offer rate
(LIBOR) plus 55 basis points, including the facility fee, based on current
credit ratings. An additional utilization fee of 10 basis points applies to
borrowings whenever more than 50% of the facility is utilized. Changes in credit
ratings could lower or raise the increment to LIBOR depending on whether ratings
improved or were lowered. As of December 31, 2005, such credit facility was not
utilized.

     As of December 31, 2005, the Company was in compliance with various
business and financial covenants contained in the credit facility. The Company's
credit facility and its receivables facility limit the Company's debt as a
percentage of its total capitalization to 65 percent.

     Junior Subordinated Debentures (Trust Preferred Securities) 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 consolidated maturities of long-term debt and
sinking fund requirements are $154 million in 2006, $7 million in 2007, $307
million in 2008, $6 million in 2009 and $6 million in 2010.

(b) RECEIVABLES FACILITY

     In January 2006, the Company'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 the Company during the peak heating
season of 2006, was extended to January 2007. As of December 31, 2005, the
Company had $141 million of advances under its receivables facility.


                                       50

<PAGE>

     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.

7. INCOME TAXES

     The Company's current and deferred components of income tax expense are as
follows:

<TABLE>
<CAPTION>
                          YEAR ENDED DECEMBER 31,
                          -----------------------
                             2003   2004   2005
                             ----   ----   ----
                               (IN MILLIONS)
<S>                       <C>       <C>    <C>
Current
   Federal.............       $30   $86    $ 82
   State...............         4    10       2
                              ---   ---    ----
      Total current....        34    96      84
                              ---   ---    ----
Deferred
   Federal.............        11    (3)      1
   State...............        14    (6)     31
                              ---   ---    ----
      Total deferred...        25    (9)     32
                              ---   ---    ----
Income tax expense.....       $59   $87    $116
                              ===   ===    ====
</TABLE>

     A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

<TABLE>
<CAPTION>
                                                            YEAR ENDED DECEMBER 31,
                                                            -----------------------
                                                              2003    2004    2005
                                                             -----   -----   -----
                                                                 (IN MILLIONS)
<S>                                                         <C>      <C>     <C>
Income before income taxes...............................    $ 188   $ 231   $ 309
   Federal statutory rate................................       35%     35%     35%
                                                             -----   -----   -----
Income tax expense at statutory rate.....................       66      81     108
                                                             -----   -----   -----
Increase (decrease) in tax resulting from:
   State income taxes, net of valuation allowances and
      federal income tax benefit.........................       12       2      22
   Tax reserves..........................................       --      --     (13)
   Changes in estimates for prior year items.............      (19)     --      --
   Deferred tax asset write-off..........................       --       4      --
   Other, net............................................       --      --      (1)
                                                             -----   -----   -----
      Total..............................................       (7)      6       8
                                                             -----   -----   -----
Income tax expense.......................................    $  59   $  87   $ 116
                                                             =====   =====   =====
Effective Rate...........................................     31.3%   37.5%   37.4%
</TABLE>


                                       51

<PAGE>

     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:

<TABLE>
<CAPTION>
                                                                                DECEMBER 31,
                                                                               -------------
                                                                                2004   2005
                                                                                ----   ----
                                                                               (IN MILLIONS)
<S>                                                                            <C>     <C>
Deferred tax assets:
   Current:
      Allowance for doubtful accounts.......................................    $ 13   $ 19
                                                                                ----   ----
         Total current deferred tax assets..................................      13     19
                                                                                ----   ----
   Non-current:
      Employee benefits.....................................................      81     73
      Operating and capital loss carryforwards..............................      30     26
      Deferred gas costs....................................................      68     59
      Other.................................................................      66     80
                                                                                ----   ----
         Total non-current deferred tax assets before valuation allowance...     245    238
                                                                                ----   ----
      Valuation allowance...................................................     (20)   (21)
                                                                                ----   ----
         Total non-current deferred tax assets..............................     225    217
                                                                                ----   ----
         Total deferred tax assets..........................................     238    236
                                                                                ----   ----
Deferred tax liabilities:
   Current:
      Non-trading derivative liabilities, net...............................       1      2
                                                                                ----   ----
         Total current deferred tax liabilities.............................       1      2
                                                                                ----   ----
   Non-current:
      Depreciation..........................................................     827    821
      Regulatory liability..................................................      17     36
      Other.................................................................      22     23
                                                                                ----   ----
         Total non-current deferred tax liabilities.........................     866    880
                                                                                ----   ----
         Total deferred tax liabilities.....................................     867    882
                                                                                ----   ----
         Accumulated deferred income taxes, net.............................    $629   $646
                                                                                ====   ====
</TABLE>

     The Company is included in the consolidated income tax returns of
CenterPoint Energy. CenterPoint Energy's consolidated federal income tax returns
have been audited and settled through the 1996 tax year. The 1997 through 2003
consolidated federal income tax returns are currently under audit.

     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.

     Tax Contingencies. The Company has established reserves for certain
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 these tax items is
approximately $32 million as of December 31, 2005.

8. 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.


                                       52
<PAGE>

(b) LEASE COMMITMENTS

     The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases, principally
consisting of rental agreements for building space, data processing equipment
and vehicles, including major work equipment (in millions):

<TABLE>
<S>                                 <C>
2006.............................   $14
2007.............................    12
2008.............................    11
2009.............................     7
2010.............................     4
2011 and beyond..................    22
                                    ---
   Total.........................   $70
                                    ===
</TABLE>

     Total rental expense for all operating leases was $28 million, $30 million
and $32 million in 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 MATTERS

     Natural Gas Measurement Lawsuits. CERC Corp. and certain of its
subsidiaries are defendants in a suit filed in 1997 under the Federal False
Claims Act alleging mismeasurement of natural gas produced from federal and
Indian lands. The suit seeks undisclosed damages, along with statutory
penalties, interest, costs, and fees. The complaint is part of a larger series
of complaints filed against 77 natural gas pipelines and their subsidiaries and
affiliates. An earlier single action making substantially similar allegations
against the pipelines was dismissed by the federal district court for the
District of Columbia on grounds of improper joinder and lack of jurisdiction. As
a result, the various individual complaints were filed in numerous courts
throughout the country. This case has been consolidated, together with the other
similar False Claims Act cases, in the federal district court in Cheyenne,
Wyoming.

     In addition, CERC Corp. and certain of its subsidiaries are defendants in
two mismeasurement lawsuits brought against approximately 245 pipeline companies
and their affiliates pending in state court in Stevens County, Kansas. In one
case (originally filed in May 1999 and amended four times), the plaintiffs
purport to represent a class of 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 of the Company's 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. The Company believes that there has been no systematic
mismeasurement of gas and that the suits are without merit. The Company does not
expect the ultimate outcome to have a material impact on its financial
condition, results of operations or cash flows.


                                       53

<PAGE>

     Gas Cost Recovery Litigation. In October 2002, a suit was filed in state
district court in Wharton County, Texas against the Company, CenterPoint Energy,
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 the Company 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 the Company 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, CenterPoint Energy, Entex Gas Marketing
Company, CenterPoint Energy Gas Transmission Company, CenterPoint Energy Field
Services, CenterPoint Energy Pipeline Services, Inc., Mississippi River
Transmission Corp. and other non-affiliated companies alleging fraud, unjust
enrichment and civil conspiracy with respect to rates charged to certain
consumers of natural gas in at least the states of Arkansas, Louisiana,
Mississippi, Oklahoma and Texas. At the time of the filing of each of the Caddo
and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with
the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu
Parish cases have been stayed pending the resolution of the respective
proceedings by the LPSC. The plaintiffs in the Miller County case seek class
certification, but the proposed class has not been certified. In February 2005,
the Wharton County case was removed to federal district court in Houston, Texas,
and in March 2005, the plaintiffs voluntarily moved to dismiss the case and
agreed not to refile the claims asserted unless the Miller County case is not
certified as a class action or is later decertified. The range of relief sought
by the plaintiffs in these cases includes injunctive and declaratory relief,
restitution for the alleged overcharges, exemplary damages or trebling of actual
damages, civil penalties and attorney's fees. In these cases, the Company,
CenterPoint Energy 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 3(b). The Company and CenterPoint
Energy 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 CenterPoint Energy.

     Pipeline Safety Compliance. Pursuant to an order from the Minnesota Office
of Pipeline Safety, the Company 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 the Company 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, the Company 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 does not
expect the outcome of this matter to have a material impact on its financial
condition, results of operations or cash flows.


                                       54

<PAGE>

(e) 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 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 its financial condition, results of
operations or cash flows.

     Manufactured Gas Plant Sites. The Company and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, the Company has
completed remediation on two sites, other than ongoing monitoring and water
treatment. There are five remaining sites in the Company's Minnesota service
territory. The Company believes that it has no liability with respect to two of
these sites.

     At December 31, 2005, the Company 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. The Company 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, the
Company 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. The Company 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 the Company or its divisions. The Company 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 the Company's motion to dismiss on the grounds that it 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 the Company. The Company is
investigating details regarding these sites and the range of environmental
expenditures for potential remediation. However, the Company 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


                                       55

<PAGE>

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.

     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, the Company 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 guaranty obligations
prior to separation, but when separation occurred in September 2002, RRI had
been unable to extinguish all obligations. To secure CenterPoint Energy and the
Company against obligations under the remaining guarantees, RRI agreed to
provide cash or letters of credit for our benefit and that of 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 its guaranty of the payment by RRI of demand charges
related to transportation contracts with one counterparty. The demand charges
are approximately $53 million per year in 2006 through 2015, $49 million in
2016, $38 million in 2017 and $13 million in 2018. As a result of changes in
market conditions, the Company's potential exposure under that guaranty
currently exceeds the security provided by RRI. The Company has requested RRI to
increase the amount of its existing letters of credit or, in the alternative, to
obtain a release of the Company's obligations under the guaranty, and the
Company and RRI are pursuing alternatives. RRI continues to meet its obligations
under the transportation contracts.

9. 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.

<TABLE>
<CAPTION>
                                                    DECEMBER 31, 2004   DECEMBER 31, 2005
                                                    -----------------   -----------------
                                                    CARRYING    FAIR    CARRYING    FAIR
                                                     AMOUNT     VALUE    AMOUNT     VALUE
                                                    --------   ------   --------   ------
                                                                (IN MILLIONS)
<S>                                                 <C>        <C>      <C>        <C>
Financial liabilities:
   Long-term debt ..............................    $2,368    $2,659    $1,992    $2,182
</TABLE>


                                       56

<PAGE>

10. UNAUDITED QUARTERLY INFORMATION

     Summarized quarterly financial data is as follows:

<TABLE>
<CAPTION>
                                                 YEAR ENDED DECEMBER 31, 2004
                               ----------------------------------------------------------------
                               FIRST QUARTER   SECOND QUARTER   THIRD QUARTER   FOURTH QUARTER
                               --------------  --------------   -------------   --------------
                                                        (IN MILLIONS)
<S>                            <C>             <C>              <C>             <C>
Revenues....................       $2,070          $1,217          $1,117           $2,068
Operating income............          160              64              32              137
Net income (loss)...........           74              11              (2)              61
</TABLE>

<TABLE>
<CAPTION>
                                                 YEAR ENDED DECEMBER 31, 2005
                               ---------------------------------------------------------------
                               FIRST QUARTER   SECOND QUARTER   THIRD QUARTER   FOURTH QUARTER
                               --------------  --------------   -------------   --------------
                                                        (IN MILLIONS)
<S>                            <C>             <C>              <C>             <C>
Revenues....................       $2,248          $1,426           $1,587          $2,809
Operating income............          202              69               40             153
Net income..................           96              27                4              66
</TABLE>

11. REPORTABLE BUSINESS SEGMENTS

     Because the Company is an indirect wholly owned subsidiary of CenterPoint
Energy, the Company's determination of reportable business segments considers
the strategic operating units under which CenterPoint Energy 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: Natural
Gas Distribution, Competitive Natural Gas Sales and Services, Pipelines and
Field Services (formerly Pipelines and Gathering) and Other Operations. Natural
Gas Distribution consists of intrastate natural gas sales to, and natural gas
transportation and distribution for, residential, commercial, industrial and
institutional customers. The Company reorganized the oversight of its Natural
Gas Distribution business segment and, as a result, beginning in the fourth
quarter of 2005, the Company established a new reportable business segment,
Competitive Natural Gas Sales and Services. Competitive Natural Gas Sales and
Services represents the Company's non-rate regulated gas sales and services
operations, which consist of three operational functions: wholesale, retail and
intrastate pipelines. Pipelines and Field Services includes the interstate
natural gas pipeline operations and the natural gas gathering and pipeline
services businesses. Other Operations consists primarily of other corporate
operations which support all of the Company's business operations. All prior
period segment information has been reclassified to conform to the 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.


                                       57

<PAGE>

Financial data for business segments and products and services are as
follows:

<TABLE>
<CAPTION>
                                                       COMPETITIVE   PIPELINES
                                           NATURAL     NATURAL GAS      AND
                                             GAS        SALES AND      FIELD        OTHER      RECONCILING
                                        DISTRIBUTION     SERVICES     SERVICES   OPERATIONS   ELIMINATIONS   CONSOLIDATED
                                        ------------   -----------   ---------   ----------   ------------   ------------
<S>                                     <C>            <C>           <C>         <C>          <C>            <C>
AS OF AND FOR THE YEAR ENDED
   DECEMBER 31, 2003:
Revenues from external customers ....      $3,389         $2,017       $  244       $ --        $    --         $5,650
Intersegment revenues ...............          --            215          163          9           (387)            --
Depreciation and amortization .......         135              1           40         --             --            176
Operating income (loss) .............         157             45          158         (1)            --            359
Total assets ........................       4,031            825        2,519        388           (910)         6,853
Expenditures for long-lived assets ..         198              1           66         --             --            265
AS OF AND FOR THE YEAR ENDED
   DECEMBER 31, 2004:
Revenues from external customers ....      $3,577         $2,593       $  306       $ (4)       $    --         $6,472
Intersegment revenues ...............           2            255          145          5           (407)            --
Depreciation and amortization .......         141              2           44         --             --            187
Operating income (loss) .............         178             44          180         (9)            --            393
Total assets ........................       4,083            964        2,637        792         (1,009)         7,467
Expenditures for long-lived assets ..         196              1           73         (1)            --            269
AS OF AND FOR THE YEAR ENDED
   DECEMBER 31, 2005:
Revenues from external customers ....      $3,837         $3,884       $  346       $  3        $    --         $8,070
Intersegment revenues ...............           9            245          147          7           (408)            --
Depreciation and amortization .......         152              2           45         (1)            --            198
Operating income (loss) .............         175             60          235         (6)            --            464
Total assets ........................       4,612          1,849        2,968        743         (1,871)         8,301
Expenditures for long-lived assets ..         249             12          156         --             --            417
</TABLE>

<TABLE>
<CAPTION>
                                               YEAR ENDED DECEMBER 31,
                                              ------------------------
                                               2003     2004     2005
                                              ------   ------   ------
                                                    (IN MILLIONS)
<S>                                           <C>      <C>      <C>
Revenues by Products and Services:
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...............       95       94      105
                                              ------   ------   ------
   Total...................................   $5,650   $6,472   $8,070
                                              ======   ======   ======
</TABLE>


                                       58
<PAGE>

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.

     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.

ITEM 9B. OTHER INFORMATION

     None.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The information called for by Item 10 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).

ITEM 11. EXECUTIVE COMPENSATION

     The information called for by Item 11 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

     The information called for by Item 12 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).


                                       59

<PAGE>

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information called for by Item 13 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

     Aggregate fees billed to the Company during the fiscal years ending
December 31, 2004 and 2005 by its principal accounting firm, Deloitte & Touche
LLP, are set forth below. These fees do not include certain fees related to
general corporate matters, financial reporting, tax and other fees which have
not been allocated to the Company by CenterPoint Energy.

<TABLE>
<CAPTION>
                                                            YEAR ENDED DECEMBER 31,
                                                            -----------------------
                                                               2004        2005
                                                             --------   -----------
<S>                                                         <C>         <C>
Audit fees..............................................     $840,408    $  967,192
Audit-related fees......................................       79,075       107,050
                                                             --------    ----------
   Total audit and audit-related fees...................      919,483     1,074,242
Tax fees................................................           --            --
All other fees..........................................           --            --
                                                             --------    ----------
   Total fees...........................................     $919,483    $1,074,242
                                                             ========    ==========
</TABLE>

The Company is not required to have, and does not have, an audit committee.

                                     PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements.

<TABLE>
<S>                                                                          <C>
Report of Independent Registered Public Accounting Firm....................  30
Statements of Consolidated Income for the
   Three Years Ended December 31, 2005.....................................  31
Statements of Consolidated Comprehensive Income for the
   Three Years Ended December 31, 2005.....................................  32
Consolidated Balance Sheets at December 31, 2004 and 2005..................  33
Statements of Consolidated Cash Flows for the
   Three Years Ended December 31, 2005.....................................  34
Statements of Consolidated Stockholder's Equity for the
  Three Years Ended December 31, 2005......................................  35
Notes to Consolidated Financial Statements.................................  36
</TABLE>

(a)(2) Financial Statement Schedules for the Three Years Ended December 31,
2005.

<TABLE>
<S>                                                                          <C>
Report of Independent Registered Public Accounting Firm....................  61
II-- Qualifying Valuation Accounts.........................................  62
</TABLE>

     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:

     I, III, IV and V.

(a)(3) Exhibits.

     See Index of Exhibits beginning on page 64.


                                       60

<PAGE>
             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder of
CenterPoint Energy Resources Corp.
Houston, Texas

We have audited the consolidated financial statements of CenterPoint Energy
Resources Corp. and subsidiaries (the Company) as of December 31, 2004 and 2005,
and for each of the three years in the period ended December 31, 2005, and have
issued our report thereon dated March 24, 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); such report is included elsewhere in this Form 10-K. Our audits
also included the consolidated financial statement schedule of the Company
listed in the index at Item 15 (a)(2). This consolidated financial statement
schedule is 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 schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.

DELOITTE & TOUCHE LLP
Houston, Texas

March 24, 2006

                                       61
<PAGE>

               CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
        (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

                  SCHEDULE II -- QUALIFYING VALUATION ACCOUNTS
                   FOR THE THREE YEARS ENDED DECEMBER 31, 2005

<TABLE>
<CAPTION>
                   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)
<S>                                              <C>          <C>         <C>           <C>           <C>
Year Ended December 31, 2005:
   Accumulated provisions:
      Uncollectible accounts receivable.......       $28         $37          $--           $27           $38
      Deferred tax asset valuation allowance..        20           1           --            --            21
Year Ended December 31, 2004:
   Accumulated provisions:
      Uncollectible accounts receivable.......        28          26           --            26            28
      Deferred tax asset valuation allowance..        73         (67)          14            --            20
Year Ended December 31, 2003:
   Accumulated provisions:
      Uncollectible accounts receivable.......        19          24           --            15            28
      Deferred tax asset valuation allowance..        83         (10)          --            --            73
</TABLE>

----------
(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.


                                       62

<PAGE>

                                   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 24th day of March, 2006.

                                        CENTERPOINT ENERGY RESOURCES CORP.
                                        (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 24, 2006.

<TABLE>
<CAPTION>
              SIGNATURE                                TITLE
              ---------                                -----
<S>                                     <C>


/s/ DAVID M. MCCLANAHAN                 Chairman, President and Chief Executive Officer
-------------------------------------   (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)
</TABLE>


                                       63
<PAGE>

               CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

                   EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
                     FOR FISCAL YEAR ENDED DECEMBER 31, 2005

                                INDEX OF EXHIBITS

     Exhibits not incorporated by reference to a prior filing are designated by
a cross (+); all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.

<TABLE>
<CAPTION>
                                                                                    SEC FILE OR
EXHIBIT                                                                            REGISTRATION    EXHIBIT
 NUMBER                 DESCRIPTION             REPORT OR REGISTRATION STATEMENT      NUMBER      REFERENCE
-------   -----------------------------------   --------------------------------   ------------   ---------
<S>       <C>                                   <C>                                <C>            <C>
2(a)(1)   --   Agreement and Plan of Merger     HI's Form 8-K dated August 11,           1-7629       2
               among the Company, HL&P, HI      1996
               Merger, Inc. and NorAm dated
               August 11, 1996

2(a)(2)   --   Amendment to Agreement and       Registration Statement on Form         33-11329      2(c)
               Plan of Merger among the         S-4
               Company, HL&P, HI Merger, Inc.
               and NorAm dated August 11,
               1996

2(b)      --   Agreement and Plan of Merger     Registration Statement on Form         33-54526       2
               dated December 29, 2000          S-3
               merging Reliant Resources
               Merger Sub, Inc. with and into
               Reliant Energy Services, Inc.

3(a)(1)   --   Certificate of Incorporation     Form 10-K for the year ended             1-3187    3(a)(1)
               of RERC Corp.                    December 31, 1997

3(a)(2)   --   Certificate of Merger merging    Form 10-K for the year ended             1-3187    3(a)(2)
               former NorAm Energy Corp. with   December 31, 1997
               and into HI Merger, Inc. dated
               August 6, 1997

3(a)(3)   --   Certificate of Amendment         Form 10-K for the year ended             1-3187    3(a)(3)
               changing the name to Reliant     December 31, 1998
               Energy Resources Corp.

3(a)(4)   --   Certificate of Amendment         Form 10-Q for the quarter ended         1-13265    3(a)(4)
               changing the name to             June 30, 2003
               CenterPoint Energy Resources
               Corp.

3(b)      --   Bylaws of RERC Corp.             Form 10-K for the year ended             1-3187      3(b)
                                                December 31, 1997

4(a)(1)   --   Indenture, dated as of           NorAm's Form 10-K for the year          1-13265      4.14
               December 1, 1986, between        ended December 31, 1986
               NorAm and Citibank, N.A., as
               Trustee

4(a)(2)   --   First Supplemental Indenture     Form 10-K for the year ended             1-3187    4(a)(2)
               to Exhibit 4(a)(1) dated as of   December 31, 1997
               September 30, 1988

4(a)(3)   --   Second Supplemental Indenture    Form 10-K for the year ended             1-3187    4(a)(3)
               to Exhibit 4(a)(1) dated as of   December 31, 1997
               November 15, 1989

4(a)(4)   --   Third Supplemental Indenture     Form 10-K for the year ended             1-3187    4(a)(4)
               to Exhibit 4(a)(1) dated as of   December 31, 1997
               August 6, 1997

4(b)(1)   --   Indenture, dated as of March     NorAm's Registration Statement         33-14586      4.20
               31, 1987, between NorAm and      on Form S-3
               Chase Manhattan Bank, N.A., as
               Trustee, authorizing 6%
               Convertible Subordinated
               Debentures due 2012

4(b)(2)   --   Supplemental Indenture to        Form 10-K for the year ended             1-3187    4(b)(2)
               Exhibit 4(b)(1) dated as of      December 31, 1997
               August 6, 1997

4(c)(1)   --   Form of Indenture between        NorAm's Registration Statement         33-64001      4.8
               NorAm and The Bank of New York   on Form S-3
               as Trustee
</TABLE>


                                       64

<PAGE>

<TABLE>
<CAPTION>
                                                                                    SEC FILE OR
EXHIBIT                                                                            REGISTRATION    EXHIBIT
 NUMBER                 DESCRIPTION             REPORT OR REGISTRATION STATEMENT      NUMBER      REFERENCE
-------   -----------------------------------   --------------------------------   ------------   ---------
<S>       <C>                                   <C>                                <C>            <C>
4(c)(2)   --   Form of First Supplemental       NorAm's Form 8-K dated June 10,         1-13265      4.01
               Indenture to Exhibit 4(c)(1)     1996

4(c)(3)   --   Second Supplemental Indenture    Form 10-K for the year ended             1-3187    4(d)(3)
               to Exhibit 4(c)(1) dated as of   December 31, 1997
               August 6, 1997

4(d)      --   Indenture, dated as of           Registration Statement on Form        333-41017      4.1
               December 1, 1997, between RERC   S-3
               Corp. and Chase Bank of Texas,
               National Association

4(e)(1)   --   Indenture, dated as of           Form 8-K dated February 5, 1998         1-13265      4.1
               February 1, 1998, between RERC
               Corp. and Chase Bank of Texas,
               National Association, as
               Trustee

4(e)(2)   --   Supplemental Indenture No. 1,    Form 8-K dated February 5, 1998         1-13265      4.2
               dated as of February 1, 1998,
               providing for the issuance of
               RERC Corp.'s 6 1/2% Debentures
               due February 1, 2008


4(e)(3)   --   Supplemental Indenture No. 2,    Form 8-K dated November 9, 1998         1-13265      4.1
               dated as of November 1, 1998,
               providing for the issuance of
               RERC Corp.'s 6 3/8% Term
               Enhanced ReMarketable
               Securities

4(e)(4)   --   Supplemental Indenture No. 3,    Registration Statement on Form        333-49162      4.2
               dated as of July 1, 2000,        S-4
               providing for the issuance of
               RERC Corp.'s 8.125% Notes due
               2005

4(e)(5)   --   Supplemental Indenture No. 4,    Form 8-K dated February 21, 2001        1-13265      4.1
               dated as of February 15, 2001,
               providing for the issuance of
               RERC Corp.'s 7.75% Notes due
               2011

4(e)(6)   --   Supplemental Indenture No. 5,    Form 8-K dated March 18, 2003           1-13265      4.1
               dated as of March 25, 2003,
               providing for the issuance of
               CERC Corp.'s 7.875% Senior
               Notes due 2013

4(e)(7)   --   Supplemental Indenture No. 6,    Form 8-K dated April 7, 2003            1-13265      4.2
               dated as of April 14, 2003,
               providing for the issuance of
               CERC Corp.'s 7.875% Senior
               Notes due 2013

4(e)(8)   --   Supplemental Indenture No. 7,    Form 8-K dated October 29, 2003         1-13265      4.2
               dated as of November 3, 2003,
               providing for the issuance of
               CERC Corp.'s 5.95% Senior
               Notes due 2014

4(e)(9)   --   Supplemental Indenture No. 8,    CNP's Form 10-K for the year            1-31447    4(f)(9)
               dated as of December 28, 2005,   ended December 31, 2005
               providing for the issuance of
               CERC Corp.'s 6 1/2% Debentures
               due 2008

4(f)      --   $400,000,000 Credit Agreement,   CNP's Form 8-K dated June 29,           1-31447      4.1
               dated as of June 30, 2005,       2005
               among CERC Corp., as borrower,
               and the Initial Lenders named
               therein, as Initial Lenders
               named therein, as Initial
               Lenders
</TABLE>


                                       65

<PAGE>

     There have not been filed as exhibits to this Form 10-K certain long-term
debt instruments, including indentures, under which the total amount of
Securities do not exceed 10% of the total assets of CERC. CERC hereby agrees to
furnish a copy of any such instrument to the SEC upon request.

<TABLE>
<CAPTION>
                                                                                    SEC FILE OR
EXHIBIT                                                                            REGISTRATION    EXHIBIT
 NUMBER                 DESCRIPTION             REPORT OR REGISTRATION STATEMENT      NUMBER      REFERENCE
-------   -----------------------------------   --------------------------------   ------------   ---------
<S>       <C>                                   <C>                                <C>            <C>
 10(a)    --   Service Agreement by and         NorAm's Form 10-K for the year          1-13265     10.20
               between Mississippi River        ended December 31, 1989
               Transmission Corporation and
               Laclede Gas Company dated
               August 22, 1989

 +12      --   Computation of Ratios of
               Earnings to Fixed Charges

 +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
</TABLE>


                                       66