UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington, D.C.
20549


________________




Form 10-K





(Mark
      One)R
            ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
      OF 1934FOR
      THE FISCAL YEAR ENDED DECEMBER 31, 2009OR£
            TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
      OF 1934FOR
      THE TRANSITION PERIOD FROM  TO





Commission
File Number 1-13265


______________________________





CenterPoint
Energy Resources Corp.


(Exact
name of registrant as specified in its charter)





Delaware
            76-0511406(State
      or other jurisdiction of incorporation or organization)
            (I.R.S.
      Employer Identification No.)1111
      LouisianaHouston,
      Texas 77002
            (713)
      207-1111(Address
      and zip code of principal executive offices)
            (Registrant’s
      telephone number, including area
code)





Securities
registered pursuant to Section 12(b) of the Act:





Title of Each
      Class
            Name
      of Each Exchange On Which Registered6.625%
      Senior Notes due 2037
            New
      York Stock Exchange





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 R





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 R





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 R  No £





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes £  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. R





Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
definitions of “large accelerated filer”, “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):





Large
      accelerated filer o
            Accelerated
      filer o
            Non-accelerated
      filer þ
            Smaller
      reporting company o(Do
      not check if a smaller reporting company)





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





The
aggregate market value of the common equity held by non-affiliates as of June
30, 2009: None










TABLE OF CONTENTS





PagePART IItem
      1.
            Business
            1Item
      1A.
            Risk Factors
            13Item
      1B.
            Unresolved Staff Comments
            20Item
      2.
            Properties
            20Item
      3.
            Legal Proceedings
            21Item
      4.
            Reserved
            21PART IIItem
      5.
            Market for Registrant’s Common Equity, Related Stockholder
      Matters and Issuer
              Purchases of Equity Securities
            21Item
      6.
            Selected Financial Data
            21Item
      7.
            Management’s Narrative Analysis of Results of
      Operations
            21Item
      7A.
            Quantitative and Qualitative Disclosures About Market
      Risk
            36Item
      8.
            Financial Statements and Supplementary
    Data
            38Item
      9.
            Changes in and Disagreements with Accountants on Accounting
      and Financial Disclosure
            70Item
      9A(T).
            Controls and Procedures
            70Item
      9B.
            Other Information
            70PART IIIItem
      10.
            Directors, Executive Officers and Corporate
      Governance
            70Item
      11.
            Executive Compensation
            70Item
      12.
            Security Ownership of Certain Beneficial Owners and
      Management and
              Related Stockholder Matters
            70Item
      13.
            Certain Relationships and Related Transactions, and
      Director Independence
            70Item
      14.
            Principal Accounting Fees and Services
            71PART IVItem
      15.
            Exhibits and Financial Statement
    Schedules
            71





i
 
 Table of Contents





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 10 (Directors,
Executive Officers, and Corporate Governance), 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, and Director Independence) 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, Management’s Narrative
Analysis of Results of Operations to explain the reasons for material changes in
the amount of revenue and expense items between 2007, 2008 and
2009.





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
 
 Table of Contents


PART I





Item 1.  Business





OUR
BUSINESS





Overview





We own
and operate natural gas distribution systems in six
states.  Subsidiaries of ours own interstate natural gas pipelines and
gas gathering systems and provide various ancillary services.  A
wholly owned subsidiary of ours offers 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, Interstate Pipelines, Field Services and Other
Operations.  From time to time, we consider the acquisition or the
disposition of assets or businesses.





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
parent company’s website are not incorporated by reference herein.





Natural
Gas Distribution





Our
natural gas distribution business (Gas Operations) engages in regulated
intrastate natural gas sales to, and natural gas transportation for,
approximately 3.2 million residential, commercial and industrial customers
in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The largest
metropolitan areas served in each state by Gas Operations are Houston, Texas;
Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi,
Mississippi; and Lawton, Oklahoma. In 2009, approximately 43% of Gas Operations’
total throughput was to residential customers and approximately 57% was to
commercial and industrial customers.





Gas
Operations also provides unregulated services consisting of heating, ventilating
and air conditioning (HVAC) equipment and appliance repair, and sales of HVAC,
hearth and water heating equipment in Minnesota.





The
demand for intrastate natural gas sales to, and natural gas transportation for,
residential, commercial and industrial customers is seasonal. In 2009,
approximately 70% of the total throughput of Gas Operations’ business occurred
in the first and fourth quarters. These patterns reflect the higher demand for
natural gas for heating purposes during those periods.





Gas
Operations suffered some damage to its system in Houston, Texas and in other
portions of its service territory across Texas and Louisiana as a result of
Hurricane Ike, which struck the upper Texas coast in September
2008.  As of December 31, 2009, Gas Operations has deferred
approximately $3 million of costs related to Hurricane Ike for recovery as
part of natural gas distribution rate proceedings.





Supply and
Transportation.  In 2009, Gas Operations purchased virtually
all of its natural gas supply pursuant to contracts with remaining terms varying
from a few months to four years. Major suppliers in 2009 included BP Canada
Energy Marketing Corp. (20.5% of supply volumes), Coral Energy Resources (8.3%),
Tenaska Marketing Ventures (8.2%), Kinder Morgan (8.0%), ConocoPhillips Company
(7.4%), and Cargill, Inc. (5.7%).  Numerous other suppliers provided the
remaining 41.9% of Gas Operations’ natural gas supply requirements. Gas
Operations transports its natural gas supplies through various intrastate and
interstate pipelines, including those owned by our





1
 Table of Contents
 
 other
subsidiaries, under contracts with remaining terms, including extensions,
varying from one to fifteen years. Gas Operations anticipates that these gas
supply and transportation contracts will be renewed or replaced prior to their
expiration.





We
actively engage in commodity price stabilization pursuant to annual gas supply
plans presented to and/or filed with each of our state regulatory authorities.
These price stabilization activities include use of storage gas, contractually
establishing fixed prices with our physical gas suppliers and utilizing
financial derivative instruments to achieve a variety of pricing structures
(e.g., fixed price, costless collars and caps). Our gas supply plans generally
call for 25-50% of winter supplies to be hedged in some fashion.





Generally,
the regulations of the states in which Gas Operations operates allow it to pass
through changes in the cost of natural gas, including gains and losses on
financial derivatives associated with the index-priced physical supply, 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.





Gas
Operations uses various third-party storage services or owned natural gas
storage facilities to meet peak-day requirements and to manage the daily changes
in demand due to changes in weather and may also supplement contracted supplies
and storage from time to time with stored liquefied natural gas and propane-air
plant production.





Gas
Operations owns and operates an underground natural gas storage facility with a
capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of
2.0 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 production rate of 200 Dekatherms (DTH) per
day and on-site storage facilities for 12 million gallons of propane
(1.0 Bcf natural gas equivalent). It owns a liquefied natural gas plant
facility with a 12 million-gallon liquefied natural gas storage tank
(1.0 Bcf natural gas equivalent) and a production rate of 72 DTH per
day.





On an
ongoing basis, Gas Operations enters into contracts to provide sufficient
supplies and pipeline capacity to meet its customer requirements. However, it is
possible for limited service disruptions 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.





Gas
Operations has entered into various asset management agreements associated with
its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma
and Texas.  Generally, these asset management agreements are contracts
between Gas Operations and an asset manager that are intended to transfer the
working capital obligation and maximize the utilization of the assets. In these
agreements, Gas Operations agreed to release transportation and storage capacity
to other parties to manage gas storage, supply and delivery arrangements for Gas
Operations and to use the released capacity for other purposes when it is not
needed for Gas Operations. Gas Operations is compensated by the asset manager
through payments made over the life of the agreements based in part on the
results of the asset optimization.  Gas Operations has received
approval from the state regulatory commissions in Arkansas, Louisiana,
Mississippi and Oklahoma to retain a share of the asset management agreement
proceeds, although the percentage of payments to be retained by Gas Operations
varies based on the jurisdiction, with the majority of the payments to benefit
customers. The agreements have varying terms, the longest of which expires in
2016.





Assets





As of
December 31, 2009, Gas Operations owned approximately 70,700 linear miles
of natural gas distribution mains, varying in size from one-half inch to
24 inches in diameter. Generally, in each of the cities, towns and rural
areas served by Gas Operations, it owns the underground gas mains and service
lines, metering and regulating equipment located on customers’ premises and the
district regulating equipment necessary for pressure maintenance. With a few
exceptions, the measuring stations at which Gas Operations receives gas are
owned, operated and maintained by others, and its distribution facilities begin
at the outlet of the measuring equipment. These facilities, including odorizing
equipment, are usually located on the land owned by suppliers.





2
 Table of Contents





Competition





Gas
Operations competes primarily with alternate energy sources such as electricity
and other fuel sources. In some areas, intrastate pipelines, other gas
distributors and marketers also compete directly for gas sales to end-users. In
addition, as a result of federal regulations affecting interstate pipelines,
natural gas marketers operating on these pipelines may be able to bypass Gas
Operations’ 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 CenterPoint
Energy Services, Inc. (CES) and its subsidiary, CenterPoint Energy Intrastate
Pipelines, LLC (CEIP).





In 2009,
CES marketed approximately 504 Bcf of natural gas, related energy services
and transportation to approximately 11,100 customers (including approximately
3 Bcf to affiliates). CES customers vary in size from small commercial
customers to large utility companies in the central and eastern regions of the
United States. The business has three operational divisions: wholesale, retail
and intrastate pipelines, which are further described below.





Wholesale
Division.  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 interstate and intrastate pipeline companies, and include gas
utilities, large industrial customers and electric generation customers. This
division includes the supply function for the procurement of natural gas and the
management and optimization of transportation and storage assets for
CES.





Retail
Division.  CES offers a variety of natural gas management
services to smaller commercial and industrial customers, municipalities,
educational institutions and hospitals, whose facilities are typically located
downstream of natural gas distribution utility city gate stations. These
services include 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 18
states.





Intrastate Pipeline
Division.  CEIP provides transportation services to shippers
and end-users and contracts out approximately 2.3 Bcf of storage at its
Pierce Junction facility in Texas.





CES
currently transports natural gas on over 41 interstate and intrastate pipelines
within states located throughout the central and eastern United States. CES
maintains a portfolio of natural gas supply contracts and firm transportation
and storage 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, storage 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 imbalances on a real-time
basis to ensure that CES’ exposure to commodity price risk is kept to a minimum.
The value assigned to these imbalances is calculated daily and is known as the
aggregate Value at Risk (VaR). In 2009, CES’ VaR averaged $0.6 million with
a high of $1.6 million.





Our risk
control policy, governed by our Risk Oversight Committee, defines authorized and
prohibited trading instruments and 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.





3
 Table of Contents
 
 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, $4 million maximum, 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.





Assets





CEIP owns
and operates approximately 230 miles of intrastate pipeline in Louisiana
and Texas and holds storage facilities of approximately 2.3 Bcf in Texas
under long-term leases. In addition, CES leases transportation capacity of
approximately 0.8 Bcf per day on various interstate and intrastate
pipelines and approximately 12.5 Bcf of storage to service its customer
base.





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.





Interstate
Pipelines





Our
pipelines business operates interstate natural gas pipelines with gas
transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri,
Oklahoma and Texas. Our interstate pipeline operations are primarily conducted
by two wholly owned subsidiaries that 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.





The rates
charged by CEGT and MRT for interstate transportation and storage services are
regulated by the Federal Energy Regulatory Commission (FERC). Our interstate
pipelines business operations may be affected by changes in the demand for
natural gas, the available supply and relative price of natural gas in the
Mid-continent and Gulf Coast natural gas supply regions and general economic
conditions.





In 2009,
approximately 16% of CEGT and MRT’s total operating revenue was attributable to
services provided to Gas Operations, an affiliate, 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 Gas Operations and Laclede are provided under several long-term firm storage
and transportation agreements.  The primary term of MRT’s firm
transportation and storage contracts with Laclede will expire in
2013.  The primary term of CEGT’s agreements for firm transportation,
“no notice” transportation service and storage services in certain of Gas
Operations’ service areas (Arkansas, Louisiana, Oklahoma and Texas) will expire
in 2012.





Carthage to Perryville. In
February 2010, CEGT completed the expansion of the capacity of its Carthage to
Perryville pipeline to approximately 1.9 Bcf per day.  The expansion
includes new compressor units at two of CEGT’s existing stations.





Southeast Supply Header, LLC.CenterPoint Southeastern Pipelines Holding, LLC, our wholly-owned
subsidiary, owns a 50% interest in Southeast Supply Header, LLC (SESH). SESH
owns a 1.0 Bcf per day, 274-mile interstate pipeline that runs from the
Perryville Hub in Louisiana to Coden, Alabama. The pipeline was placed into
service in September 2008. The rates charged by SESH for interstate
transportation services are regulated by the FERC. A wholly-owned, indirect
subsidiary of Spectra Energy Corp. owns the remaining 50% interest in
SESH.





4
 Table of Contents





Assets





Our
interstate pipelines business currently owns and operates approximately
8,000 miles of natural gas transmission lines primarily located in
Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. Our interstate
pipeline business also owns and operates six natural gas storage fields with a
combined daily deliverability of approximately 1.2 Bcf and a combined
working gas capacity of approximately 59 Bcf. Our interstate pipeline
business also owns a 10% interest in the Bistineau storage facility located in
Bienville Parish, Louisiana, with the remaining interest owned and operated by
Gulf South Pipeline Company, LP. Our interstate pipeline business' 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.





Competition





Our
interstate pipelines business competes with other interstate and intrastate
pipelines 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 interstate pipelines business
competes indirectly with other forms of energy, including electricity, coal and
fuel oils. The primary competitive factor is price, but recently, environmental
considerations have grown in importance when consumers consider other forms of
energy. 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.





Field
Services





Our field
services business operates gas gathering, treating and processing facilities and
also provides operating and technical services and remote data monitoring and
communication services.





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 Mid-continent region
of the United States that interconnect with CEGT’s and MRT’s pipelines, as well
as other interstate and intrastate pipelines. CEFS gathers approximately
1.4 Bcf per day of natural gas and, either directly or through its 50%
interest in a joint venture, processes in excess of 250 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.





Our field
services business operations may be affected by changes in the demand for
natural gas and natural gas liquids (NGLs), the available supply and relative
price of natural gas and NGLs in the Mid-continent and Gulf Coast natural gas
supply regions and general economic conditions.





Long-Term Gas Gathering and Treating
Agreements.In September 2009, CEFS entered into long-term agreements
with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an
indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide
gathering and treating services for their natural gas production from certain
Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired
jointly-owned gathering facilities from EnCana and Shell in De Soto and Red
River parishes in northwest Louisiana.  Each of the agreements
includes acreage dedication and volume commitments for which CEFS has rights to
gather Shell’s and EnCana’s natural gas production from the dedicated
areas.





In
connection with the agreements, CEFS commenced gathering and treating services
utilizing the acquired facilities. CEFS is expanding the acquired facilities in
order to gather and treat up to 700 MMcf per day of natural gas. If EnCana
or Shell elect, CEFS will further expand the facilities in order to gather and
treat additional future volumes.  The construction necessary to reach
the contractual capacity of 700 MMcf per day includes more than 200 miles of
gathering lines, nearly 25,500 horsepower of compression and over 800 MMcf per
day of treating capacity.





CEFS
estimates that the purchase of existing facilities and construction to gather
700 MMcf per day will cost up to $325 million. If EnCana and Shell elect
expansion of the project to gather and process additional future volumes of up
to 1 Bcf per day, CEFS estimates that the expansion would cost as much as
an additional $300 million and EnCana and Shell would provide incremental
volume commitments. Funds for construction are being provided from





5
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 anticipated
cash flows from operations, lines of credit, proceeds from the sale of debt
securities or capital contributions.  As of December 31, 2009,
approximately $176 million has been spent on this project, including the
purchase of existing facilities.





Waskom Gas Processing Company.CenterPoint Energy Gas Processing Company, our wholly-owned, indirect
subsidiary (CEGP), owns a 50% general partnership interest in Waskom Gas
Processing Company (Waskom). Waskom owns a gas processing plant located in East
Texas. The plant is capable of processing approximately 285 MMcf per day of
natural gas.





Assets





Our field
services business owns and operates approximately 3,700 miles of gathering
lines and processing plants that collect, treat and process natural gas from
approximately 140 separate systems located in major producing fields in
Arkansas, Louisiana, Oklahoma and Texas.





Competition





Our field
services business competes with other companies in the natural gas gathering,
treating and processing business. The principal elements of competition are
rates, terms of service and reliability of services. Our field services business
competes indirectly with other forms of energy, including electricity, coal and
fuel oils. The primary competitive factor is price, but recently, environmental
considerations have grown in importance when consumers consider other forms of
energy. 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
gathering, treating, and processing services. In addition, competition among
forms of energy is affected by commodity pricing levels and influences the level
of drilling activity and demand for our gathering operations.





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 12 to our consolidated
financial statements, which note is incorporated herein by
reference.





REGULATION





We are
subject to regulation by various federal, state and local governmental agencies,
including the regulations described below.





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 interstate 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 Policy Act of 2005 (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 significant civil and criminal
penalties for statutory violations and violations of the FERC’s rules or orders
and also expanded criminal penalties for such violations. Our competitive
natural gas sales and services subsidiary markets natural gas in interstate
commerce pursuant to blanket authority granted by the FERC.





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





6
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 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.





Under the
Public Utility Holding Company Act of 2005 (PUHCA 2005), the FERC has 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. In December 2005, the FERC issued rules
implementing PUHCA 2005. Pursuant to those rules, in June 2006, CenterPoint
Energy filed with the FERC the required notification of its status as a public
utility holding company. In October 2006 and December 2009, the FERC adopted
additional rules regarding maintenance of books and records by utility holding
companies and additional reporting and accounting requirements for centralized
service companies that provide non-power goods and services to public utilities,
natural gas companies or both, in the same holding company system.





State
and Local Regulation





In almost
all communities in which Gas Operations provides natural gas distribution
services, it operates under franchises, certificates or licenses obtained from
state and local authorities. The original terms of the franchises, with various
expiration dates, typically range from 10 to 30 years, although franchises
in Arkansas are perpetual. Gas Operations expects to be able to renew expiring
franchises. In most cases, franchises to provide natural gas utility services
are not exclusive.





Substantially
all of Gas Operations is subject to cost-of-service regulation by the relevant
state public utility commissions and, in Texas, by the Railroad Commission of
Texas (Railroad Commission) and those municipalities served by Gas Operations
that have retained original jurisdiction.





Texas. In March 2008, Gas
Operations filed a request to change its rates with the Railroad Commission and
the 47 cities in its Texas Coast service territory, an area consisting of
approximately 230,000 customers in cities and communities on the outskirts of
Houston. In 2008, Gas Operations implemented rates increasing annual revenues by
approximately $3.5 million.  The implemented rates were contested by
nine cities in an appeal to the 353rd District Court in Travis County, Texas. In
January 2010, that court reversed the Railroad Commission’s order in part and
remanded the matter to the Railroad Commission.  The court concluded that
the Railroad Commission did not have statutory authority to impose on the
complaining cities the cost of service adjustment mechanism which the Railroad
Commission had approved in its order.  Certain parties filed a motion to
modify the district court’s judgment and a final decision is not expected until
April 2010.  We do not expect the outcome of this matter to have a material
adverse impact on our financial condition, results of operations or cash
flows.





In July
2009, Gas Operations filed a request to change its rates with the Railroad
Commission and the 29 cities in its Houston service territory, consisting of
approximately 940,000 customers in and around Houston. The request seeks to
establish uniform rates, charges and terms and conditions of service for the
cities and environs of the Houston service territory. As finally submitted to
the Railroad Commission and the cities, the proposed new rates would result in
an overall increase in annual revenue of $20.4 million, excluding carrying
costs on gas inventory of approximately $2 million. In January 2010, Gas
Operations withdrew its request for an annual cost of service adjustment
mechanism due to the uncertainty caused by the court’s ruling in the
above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission
issued its decision authorizing a revenue increase of $5.1 million annually,
reflecting reduced depreciation rates of $1.2 million.  The Railroad
Commission also approved a surcharge of $0.9 million per year to recover
Hurricane Ike costs over three years.





Minnesota. In November 2006,
the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas
Operations for a waiver of MPUC rules in order to allow Gas Operations to
recover approximately $21 million in unrecovered purchased gas costs
related to periods prior to July 1, 2004. Those unrecovered gas costs were
identified as a result of revisions to previously approved calculations of
unrecovered purchased gas costs. Following that denial, Gas Operations recorded
a $21 million adjustment to reduce pre-tax earnings in the fourth quarter
of 2006 and reduced the regulatory asset related to these costs by an equal
amount. In March 2007, following the MPUC’s denial of reconsideration of its
ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of
the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been
arbitrary and capricious in denying Gas Operations a waiver. The MPUC sought
further review of the court of appeals decision from the Minnesota Supreme
Court.  In July 2009, the Minnesota Supreme Court reversed the
decision of the Minnesota





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 Court of
Appeals and upheld the MPUC’s decision to deny the requested variance. The
court’s decision had no negative impact on our financial condition, results of
operations or cash flows, as the costs at issue were written off at the time
they were disallowed.





In
November 2008, Gas Operations filed a request with the MPUC to increase its
rates for utility distribution service by $59.8 million annually. In
addition, Gas Operations sought an adjustment mechanism that would annually
adjust rates to reflect changes in use per customer.  In December 2008, the
MPUC accepted the case and approved an interim rate increase of
$51.2 million, which became effective on January 2, 2009, subject to
refund. In January 2010, the MPUC issued its decision authorizing a revenue
increase of $41 million per year, with an overall rate of return of 8.09%
(10.24% return on equity). The difference between the rates approved by the MPUC
and amounts collected under the interim rates, $10 million as of December 31,
2009, is recorded in other current liabilities and will be refunded to
customers. The MPUC also authorized Gas Operations to implement a pilot program
for residential and small volume commercial customers that is intended to
decouple gas revenues from customers’ natural gas usage. In February 2010, we
filed a request for rehearing of the order by the MPUC.  No other
party to the case filed such a request.  We do not expect a final
order to be issued in this proceeding until spring 2010.





Mississippi.  In
July 2009, Gas Operations filed a request to increase its rates for utility
distribution service with the Mississippi Public Service Commission (MPSC). In
November 2009, as part of a settlement agreement in which the MPSC approved Gas
Operations’ retention of the compensation paid under the terms of an asset
management agreement, Gas Operations withdrew its rate request.





Department
of Transportation





In
December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement
and Safety Act of 2006 (2006 Act), which reauthorized the programs adopted under
the Pipeline Safety Improvement Act of 2002 (2002 Act).  These
programs included several requirements related to ensuring pipeline safety, and
a requirement to assess the integrity of pipeline transmission facilities in
areas of high population concentration. Under the legislation, remediation
activities are to be performed over a 10-year period. Our pipeline subsidiaries
are on schedule to comply with the timeframe mandated for completion of
integrity assessment and remediation.





Pursuant
to the 2002 Act, and then the 2006 Act, the Pipeline and Hazardous Materials
Safety Administration (PHMSA) of the U.S. Department of Transportation (DOT) has
adopted a number of rules concerning, among other things, distinguishing between
gathering lines and transmission facilities, requiring certain design and
construction features in new and replaced lines to reduce corrosion and
requiring pipeline operators to amend existing written operations and
maintenance procedures and operator qualification programs.





We
anticipate that compliance with these regulations and performance of the
remediation activities by our interstate and intrastate pipelines, and natural
gas distribution companies will require increases in both capital expenditures
and operating costs. The level of expenditures will depend upon several factors,
including age, location and operating pressures of the facilities. Based on our
interpretation of the rules written to date and preliminary technical reviews,
we believe compliance will require annual expenditures (capital and operating
costs combined) of approximately $16 million to $18 million during the next
three years.





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 and distribution systems, gas gathering and processing 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
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




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•
            enjoining
      the operations of facilities deemed in non-compliance with permits issued
      pursuant to such environmental laws and
  regulations.





In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:





•
            construct
      or acquire new equipment;





•
            acquire
      permits for facility operations;





•
            modify
      or replace existing and proposed equipment;
and





•
            clean
      up or decommission waste disposal areas, fuel storage and management
      facilities and other locations and
facilities.





Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial actions and the
issuance of orders enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.





The trend
in environmental regulation is to place more restrictions and limitations on
activities that may affect the environment, and thus there can be no assurance
as to the amount or timing of future expenditures for environmental compliance
or remediation, and actual future expenditures may be different from the amounts
we currently anticipate. We try to anticipate future regulatory requirements
that might be imposed and plan accordingly to remain in compliance with changing
environmental laws and regulations and to minimize the costs of such
compliance.





Based on
current regulatory requirements and interpretations, we do not believe that
compliance with federal, state or local environmental laws and regulations will
have a material adverse effect on our business, financial position, results of
operations or cash flows. In addition, we believe that our current environmental
remediation activities 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.





Global
Climate Change





In recent
years, there has been increasing public debate regarding the potential impact on
global climate change by various “greenhouse gases” such as carbon dioxide, a
byproduct of burning fossil fuels, and methane, the principal component of the
natural gas that we transport and deliver to customers. Legislation to regulate
emissions of greenhouse gases has been introduced in Congress, and there has
been a wide-ranging policy debate, both nationally and internationally,
regarding the impact of these gases and possible means for their regulation.
Some of the proposals would require industries such as the utility industry to
meet stringent new standards that would require substantial reductions in carbon
emissions. Those reductions could be costly and difficult to implement. Some
proposals would provide for credits to those who reduce emissions below certain
levels and would allow those credits to be traded and/or sold to
others.  In addition, efforts have been made and continue to be made
in the international community toward the adoption of international treaties or
protocols that would address global climate change issues, such as the United
Nations Climate Change Conference in Copenhagen in 2009.  Also, the
U.S. Environmental Protection Agency (EPA) has undertaken new efforts to collect
information regarding greenhouse gas emissions and their effects. Recently, the
EPA declared that certain greenhouse gases represent an endangerment to human
health and proposed to expand its regulations relating to those
emissions.





9
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It is too
early to determine whether, or in what form, further regulatory action regarding
greenhouse gas emissions will be adopted or what specific impacts a new
regulatory action might have on us and our subsidiaries. However, as a
distributor and transporter of natural gas and consumer of natural gas in our
pipeline and gathering businesses, our revenues, operating costs and capital
requirements could be adversely affected as a result of any regulatory action
that would require installation of new control technologies or a modification of
our operations or would have the effect of reducing the consumption of natural
gas. Likewise, incentives to conserve energy or use energy sources other than
natural gas could result in a decrease in demand for our
services.  Conversely, regulatory actions that effectively promote the
consumption of natural gas because of its lower emission characteristics, would
be expected to beneficially affect us.  At this point in time,
however, it would be speculative to try to quantify the magnitude of the impacts
from possible new regulatory actions related to greenhouse gas emissions, either
positive or negative, on our businesses.





To the
extent climate changes occur, our businesses may be adversely impacted, though
we believe any such impacts are likely to occur very gradually and hence would
be difficult to quantify with specificity.  To the extent global
climate change results in warmer temperatures in our service territories,
financial results from our natural gas distribution businesses could be
adversely affected through lower gas sales, and our gas transmission and field
services businesses could experience lower revenues.  Another possible
climate change that has been widely discussed in recent years is the possibility
of more frequent and more severe weather events, such as hurricanes or
tornadoes.  Since many of our facilities are located along or near the
Gulf Coast, increased or more severe hurricanes or tornadoes can increase our
costs to repair damaged facilities and restore service to our
customers.  When we cannot deliver natural gas to customers or our
customers cannot receive our services, our financial results can be impacted by
lost revenues, and we generally must seek approval from regulators to recover
restoration costs.  To the extent we are unable to recover those
costs, or if higher rates resulting from our recovery of such costs result in
reduced demand for our services, our future financial results may be adversely
impacted.





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.  In recent years the EPA has adopted amendments to its
regulations regarding maximum achievable control technology for stationary
internal combustion engines (sometimes referred to as the RICE MACT rule) and
continues to consider additional amendments.  Compressors used by our
Pipelines and Field Services segments are affected by these
rules.  While the final structure and effective dates of these revised
rules are still uncertain, we currently believe the rules, if adopted in their
current form and on the anticipated schedule, could require expenditures over
the next three years of less than $100 million in order to ensure our compliance
with the revised rules.  We believe, however, that our operations will
not be materially adversely affected by such requirements.





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.




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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 would be 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 the 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 EPA and, in some
cases, third parties to take action 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





Manufactured Gas Plant Sites.
We and our predecessors operated manufactured gas plants (MGPs) 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, 2009, we had accrued $14 million for remediation of these
Minnesota sites and 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 (PRPs), 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, 2009, we had collected
$13 million from insurance companies and rate payers to be used for future
environmental remediation.  In January 2010, as part of our Minnesota
rate case decision, the MPUC eliminated the environmental expense tracker
mechanism and ordered amounts previously collected from ratepayers and related
carrying costs refunded to customers.  As of December 31, 2009, the
balance in the environmental expense tracker account was $8.7
million.  The MPUC provided for the inclusion in rates of
approximately $285,000 annually to fund normal on-going remediation
costs.  We were not required to refund to customers the amount
collected from insurance companies, $4.6 million at December 31, 2009, to be
used to mitigate future environmental costs.  The MPUC further gave
assurance that any reasonable and prudent environmental clean-up costs we incur
in the future will be rate-recoverable under normal regulatory principles and
procedures.  This provision had no effect on earnings.





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 by one of our
former affiliates. We have been named as a defendant in a lawsuit filed in the
United States District Court, District of Maine, 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





11
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 the
lawsuit. In June 2006, the federal district court in Maine ruled that the
current owner of the site is responsible for site remediation but that an
additional evidentiary hearing would be required to determine if other
potentially responsible parties, including us, would have to contribute to that
remediation. In September 2009, the federal district court granted our motion
for summary judgment in the proceeding.  Although it is likely that
the plaintiff will pursue an appeal from that dismissal, further action will not
be taken until the district court disposes of claims against other defendants in
the case. We believe we are not liable as a former owner or operator of the site
under CERCLA and applicable state statutes, and are vigorously contesting the
suit and our designation as a PRP.  We do not expect the ultimate
outcome to have a material adverse impact on our financial condition, results of
operations or cash flows.





Mercury Contamination. Our
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. 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 is not
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.





Asbestos.  Some
facilities formerly owned by our predecessors have contained asbestos insulation
and other asbestos-containing materials. We or our predecessor companies have
been named, along with numerous others, as a defendant in lawsuits filed by
certain individuals who claim injury due to exposure to asbestos during work at
such formerly owned facilities. We anticipate that additional claims like those
received may be asserted in the future.  Although their ultimate
outcome cannot be predicted at this time, we intend to continue vigorously
contesting claims that are not considered to have merit and do not expect, based
on our experience to date, these matters, either individually or in the
aggregate, to have a material adverse effect on our financial condition, results
of operations or cash flows.





Groundwater Contamination
Litigation.Predecessor entities of ours, along with several other
entities, are defendants in litigation, St. Michel Plantation, LLC, et al,
v. White, et al., pending in civil district court in Orleans Parish,
Louisiana.  In the lawsuit, the plaintiffs allege that their property in
Terrebonne Parish, Louisiana suffered salt water contamination as a result of
oil and gas drilling activities conducted by the defendants.  Although a
predecessor of ours held an interest in two oil and gas leases on a portion of
the property at issue, neither we nor any other entities of ours drilled or
conducted other oil and gas operations on those leases.  In January 2009,
we and the plaintiffs reached agreement on the terms of a settlement that, if
ultimately approved by the Louisiana Department of Natural Resources, is
expected to resolve this litigation. We do not expect the outcome of this
litigation to have a material adverse impact on 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. In addition, we
have 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, we do not expect, based on our experience to date, these matters, either
individually or in the aggregate, to have a material adverse effect on our
financial condition, results of operations or cash flows.




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EMPLOYEES





As of
December 31, 2009, we had 4,678 full-time employees. The following
table sets forth the number of our employees by business segment:





Business
      Segment
            
            Number
            
            
            Number
              Represented
              by
      Unions or
              Other
      Collective
              Bargaining
      GroupsNatural
      Gas Distribution
            
            
            3,618
            
            
            
            1,384Competitive
      Natural Gas Sales and Services
            
            
            130
            
            
            
            —Interstate
      Pipelines
            
            
            689
            
            
            
            —Field
      Services
            
            
            241
            
            
            
            —Total
            
            
            4,678
            
            
            
            1,384





As of
December 31, 2009, approximately 30% of our employees are subject to
collective bargaining agreements.





Item 1A. Risk Factors





The
following, along with any additional legal proceedings identified or
incorporated by reference in Item 3 of this report, summarizes the principal
risk factors associated with our business.





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 Gas Operations 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 alternate energy sources, which could result in our
marketing less natural gas, and our interstate 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 and reduced volumes, 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. We also compete indirectly with
other forms of energy, including electricity, coal and fuel oils. The primary
competitive factor is price, but recently, environmental considerations have
grown in importance when consumers consider other forms of energy. 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. Additionally,
any reduction in the volume of natural gas transported or stored may have an
adverse impact on our results of operations, financial condition and cash
flows.





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Our
natural gas distribution and competitive natural gas sales and services
businesses are subject to fluctuations in natural gas prices, which could affect
the ability of our suppliers and customers to meet their obligations or
otherwise adversely affect our liquidity and results of operations.





We are
subject to risk associated with changes in the price of natural gas. Increases
in natural gas prices might affect our ability to collect balances due from our
customers and, for Gas Operations, 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 (i) apply
downward demand pressure on natural gas consumption in the areas in which we
operate thereby resulting in decreased sales volumes and revenues and (ii)
increase the risk that our suppliers or customers fail or are unable to meet
their obligations. An increase in natural gas prices would also increase our
working capital requirements by increasing the investment that must be made in
order to maintain natural gas inventory levels.  Additionally, a
decrease in natural gas prices could increase the amount of collateral that we
must provide under our hedging arrangements.





A
decline in our credit rating could result in our having to provide collateral in
order to purchase natural gas or under our shipping or hedging
arrangements.





If our
credit rating were to decline, we might be required to post cash collateral in
order to purchase natural gas or under our shipping or hedging arrangements. 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, our results of operations, financial
condition and cash flows could be adversely affected.





The
revenues and results of operations of our interstate pipelines and field
services businesses are subject to fluctuations in the supply and price of
natural gas and natural gas liquids.





Our
interstate pipelines and field services businesses largely rely on natural gas
sourced in the various supply basins located in the Mid-continent region of the
United States. The level of drilling and production activity in these regions is
dependent on economic and business factors beyond our control. The primary
factor affecting both the level of drilling activity and production volumes is
natural gas pricing. A sustained decline in natural gas prices could result in a
decrease in exploration and development activities in the regions served by our
gathering and pipeline transportation systems and our natural gas treating and
processing activities. A sustained decline could also lead producers to shut in
production from their existing wells. Other factors that impact production
decisions include the level of production costs relative to other available
production, producers’ access to needed capital and the cost of that capital,
the ability of producers to obtain necessary drilling and other governmental
permits, access to drilling rigs and regulatory changes. Because of these
factors, even if new natural gas reserves are discovered in areas served by our
assets, producers may choose not to develop those reserves or to shut in
production from existing reserves. 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 from these businesses are also affected by the prices of natural gas
and natural gas liquids (NGL). NGL prices generally fluctuate on a basis that
correlates to fluctuations in crude oil prices. In the past, the prices of
natural gas and crude oil have been extremely volatile, and we expect this
volatility to continue. The markets and prices for natural gas, NGLs and crude
oil depend upon factors beyond our control. These factors include supply of and
demand for these commodities, which fluctuate with changes in market and
economic conditions and other factors.





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.




14
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The
actual cost of pipelines under construction, future pipeline, gathering and
treating systems and related compression facilities may be significantly higher
than we had planned.





Our
subsidiaries have been recently involved in significant pipeline construction
projects and, depending on available opportunities, may, from time to time, be
involved in additional significant pipeline construction and gathering and
treating system projects in the future. The construction of new pipelines,
gathering and treating systems and related compression facilities may require
the expenditure of significant amounts of capital, which may exceed our
estimates. These projects may not be completed at the planned cost, on schedule
or at all. The construction of new pipeline, gathering, treating or compression
facilities is subject to construction cost overruns due to labor costs, costs of
equipment and materials such as steel and nickel, labor shortages or delays,
weather delays, inflation or other factors, which could be material. In
addition, the construction of these facilities is typically subject to the
receipt of approvals and permits from various regulatory agencies. Those
agencies may not approve the projects in a timely manner or may impose
restrictions or conditions on the projects that could potentially prevent a
project from proceeding, lengthen its expected completion schedule and/or
increase its anticipated cost. As a result, there is the risk that the new
facilities may not be able to achieve our expected investment return, which
could adversely affect our financial condition, results of operations or cash
flows.





The
states in which we provide regulated local gas distribution may, either through
legislation or rules, adopt restrictions similar to or broader than those under
the Public Utility Holding Company Act of 1935 regarding organization, financing
and affiliate transactions that could have significant adverse impacts on our
ability to operate.





The
Public Utility Holding Company Act of 1935, to which CenterPoint Energy and its
subsidiaries were subject prior to its repeal in the Energy Act, provided a
comprehensive regulatory structure governing the organization, capital
structure, intracompany relationships and lines of business that could be
pursued by registered holding companies and their member companies. Following
repeal of that Act, some states in which we do business have sought to expand
their own regulatory frameworks to give their regulatory authorities increased
jurisdiction and scrutiny over similar aspects of the utilities that operate in
their states. Some of these frameworks attempt to regulate financing activities,
acquisitions and divestitures, and arrangements between the utilities and their
affiliates, and to restrict the level of non-utility business that can be
conducted within the holding company structure. Additionally they may impose
record keeping, record access, employee training and reporting requirements
related to affiliate transactions and reporting in the event of certain
downgrading of the utility’s bond rating.





These
regulatory frameworks could have adverse effects on our ability to conduct our
utility operations, to finance our business and to provide cost-effective
utility service. In addition, if more than one state adopts restrictions on
similar activities, it may be difficult for us to comply with competing
regulatory requirements.





The
revenues and results of operations of our interstate pipelines and field
services businesses could be adversely impacted by new environmental regulations
governing the withdrawal, storage and use of surface water or groundwater
necessary for hydraulic fracturing of wells and the protection of water supplies
in the areas in and around shale fields.





Our
interstate pipelines and field services businesses largely rely on natural gas
sourced in the various supply basins located in the Mid-continent region of the
United States.  To extract natural gas from the shale fields in this
area, producers have historically used a process called hydraulic fracturing.
Recently, new environmental regulations governing the withdrawal, storage and
use of surface water or groundwater necessary for hydraulic fracturing of wells
and the protection of water supplies in the areas in and around the shale fields
have been considered by the federal government.  If enacted, such
regulations could increase operating costs of the producers in these regions or
cause delays, interruptions or termination of drilling operations, all of which
could result in a decrease in demand for the services provided by our interstate
pipelines and field services businesses in the shale fields, which could have an
adverse effect on our results of operations, financial condition and cash
flows.




15
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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, 2009, we had $3.3 billion of outstanding indebtedness on
a consolidated basis. As of December 31, 2009, approximately
$649 million principal amount of this debt is required to be paid through
2012, including $45 million of debentures redeemed in 2010, but excluding
$432 million borrowed from the money pool.   Our future
financing activities may be significantly affected by, among other
things:





•
            general
      economic and capital market
conditions;





•
            credit
      availability from financial institutions and other
  lenders;





•
            investor
      confidence in us and the markets in which we
  operate;





•
            maintenance
      of acceptable credit ratings by us and CenterPoint
  Energy;





•
            market
      expectations regarding our future earnings and cash
  flows;





•
            market
      perceptions of our and CenterPoint Energy's ability to access capital
      markets on reasonable terms;





•
            our
      exposure to RRI in connection with its indemnification obligations arising
      in connection with its separation from CenterPoint Energy;
    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.





The
creditworthiness and liquidity of our parent company and our affiliates could
affect our creditworthiness and liquidity.





Our
credit ratings and liquidity may be impacted by the creditworthiness and
liquidity of our parent company and our affiliates.  As of December
31, 2009, CenterPoint Energy and its subsidiaries other than us have
approximately $562 million principal amount of debt required to be paid
through 2012.  This amount excludes amounts related to capital leases,
principal repayments of approximately $831 million on transition and system
restoration bonds and indexed debt securities obligations, but includes $290
million of pollution control bonds issued on CenterPoint Energy’s behalf which
CenterPoint Energy purchased in January 2010 (and which may be remarketed). If
CenterPoint Energy were to experience a deterioration in its creditworthiness or
liquidity, our creditworthiness and liquidity could be adversely
affected.  In addition, from time to time we and other affiliates
invest or borrow funds in the money pool maintained by CenterPoint
Energy.  If CenterPoint Energy or the affiliates that borrow any funds
that we might invest from time to time in the money pool were to experience a
deterioration in their creditworthiness or liquidity, our creditworthiness,
liquidity and the repayment of notes receivable from CenterPoint Energy and our
affiliates under the money pool could be adversely impacted.




16
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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.





Other
than the financial covenants contained in our credit facility and receivables
facility (described under “Liquidity” in Item 7 of this report), which could
have the practical effect of limiting the payment of dividends under certain
circumstances, 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 could negatively impact our
results of operations and those of our subsidiaries.





We and
our subsidiaries use derivative instruments, such as swaps, options, futures and
forwards, to manage our commodity, weather and financial market risks. We and
our subsidiaries could recognize financial losses as a result of volatility in
the market values of these contracts, or should a counterparty fail to perform.
In the absence of actively quoted market prices and pricing information from
external sources, the valuation of these financial instruments can involve
management’s judgment or use of estimates. As a result, changes in the
underlying assumptions or use of alternative valuation methods could affect the
reported fair value of these contracts.





We
derive a substantial portion of our operating income from subsidiaries through
which we hold a substantial portion of our assets.





We derive
a substantial portion of our operating income from, and hold a substantial
portion of our assets through, our subsidiaries. As a result, we depend on
distributions from our subsidiaries in order to meet our payment obligations. In
general, these subsidiaries are separate and distinct legal entities and have no
obligation to provide us with funds for our payment obligations, whether by
dividends, distributions, loans or otherwise. In addition, provisions of
applicable law, such as those limiting the legal sources of dividends, limit our
subsidiaries’ ability to make payments or other distributions to us, and our
subsidiaries could agree to contractual restrictions on their ability to make
distributions.





Our right
to receive any assets of any subsidiary, and therefore the right of our
creditors to participate in those assets, will be effectively subordinated to
the claims of that subsidiary’s creditors, including trade creditors. In
addition, even if we were a creditor of any subsidiary, our rights as a creditor
would be subordinated to any security interest in the assets of that subsidiary
and any indebtedness of the subsidiary senior to that held by us.





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, and gas gathering and





17
 Table of Contents
 
 processing
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
wastes;





•
            limiting
      or prohibiting construction activities in sensitive areas such as
      wetlands, coastal regions, or areas inhabited by endangered
      species;





•
            requiring
      remedial action to mitigate pollution conditions caused by our operations,
      or attributable to former operations;
and





•
            enjoining
      the operations of facilities deemed in non-compliance with permits issued
      pursuant to such environmental laws and
  regulations.





In order
to comply with these requirements, we may need to spend substantial amounts and
devote other resources from time to time to:





•
            construct
      or acquire new equipment;





•
            acquire
      permits for facility operations;





•
            modify
      or replace existing and proposed equipment;
and





•
            clean
      up or decommission waste disposal areas, fuel storage and management
      facilities and other locations and
facilities.





Failure
to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial actions, and the
issuance of orders enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to clean up and
restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.





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.





Under
some circumstances, we and CenterPoint Energy could incur liabilities associated
with assets and businesses we and CenterPoint Energy no longer own.





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. These 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 were unable to
satisfy a liability that has been so assumed in circumstances in which Reliant
Energy and its subsidiaries were not





18
 Table of Contents
 
 released
from the liability in connection with the transfer, we and 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. When the companies separated, RRI agreed to secure us against
obligations under the guaranties RRI had been unable to extinguish by the time
of separation. Pursuant to such agreement, as amended in December 2007, RRI has
agreed to provide to us cash or letters of credit as security against our
obligations under our remaining guaranties for demand charges under certain gas
transportation agreements if and to the extent changes in market conditions
expose us to a risk of loss on those guaranties.  The present value of the
demand charges under these transportation contracts, which will be effective
until 2018, was approximately $96 million as of December 31, 2009. As of
December 31, 2009, RRI was not required to provide security to us.  If
RRI should fail to perform the contractual obligations, we could have to honor
our guarantee and, in such event, collateral provided as security may be
insufficient to satisfy our obligations.





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
CenterPoint Energy as its former owner.





On May 1,
2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG
Energy, Inc. In connection with the sale, RRI changed its name to RRI Energy,
Inc. The sale does not alter RRI’s contractual obligations to indemnify
CenterPoint Energy and its subsidiaries, including us, for certain liabilities,
including their indemnification regarding certain litigation, nor does it affect
the terms of existing guaranty arrangements for certain RRI gas transportation
contracts discussed above.





Reliant
Energy and RRI are named as defendants in a number of lawsuits arising out of
sales of natural gas in California and other markets. Although these matters
relate to the business and operations of RRI, claims against Reliant Energy have
been made on grounds that include liability of Reliant Energy as a controlling
shareholder of RRI. We and CenterPoint Energy could incur liability if claims in
one or more of these lawsuits were successfully asserted against us and
CenterPoint Energy and indemnification from RRI were determined to be
unavailable or if RRI were unable to satisfy indemnification obligations owed
with respect to those claims.





The
unsettled conditions in the global financial system may have impacts on our
business, liquidity and financial condition that we currently cannot
predict.





The
recent credit crisis and unsettled conditions in the global financial system may
have an impact on our business, liquidity and financial condition. Our ability
to access the capital markets may be severely restricted at a time when we would
like, or need, to access those markets, which could have an impact on our
liquidity and flexibility to react to changing economic and business conditions.
In addition, the cost of debt financing may be materially adversely impacted by
these market conditions. Defaults of lenders in our credit facilities, should
they further occur, could adversely affect our liquidity. Capital market turmoil
was also reflected in significant reductions in equity market valuations in
2008, which significantly reduced the value of assets of CenterPoint Energy’s
pension plan. These reductions increased pension expense in 2009.





In
addition to the credit and financial market issues, a recurrence of national and
local recessionary conditions may impact our business in a variety of ways.
These include, among other things, reduced customer usage, increased customer
default rates and wide swings in commodity prices.





Climate
change legislation and regulatory initiatives could result in increased
operating costs and reduced demand for our services.





Legislation
to regulate emissions of greenhouse gases has been introduced in Congress, and
there has been a wide-ranging policy debate, both nationally and
internationally, regarding the impact of these gases and possible means for
their regulation.  In addition, efforts have been made and continue to
be made in the international community toward the adoption of international
treaties or protocols that would address global climate change issues, such as
the United Nations Climate Change Conference in Copenhagen in 2009. Also, the
EPA has undertaken new efforts to collect information regarding greenhouse gas
emissions and their effects. Recently, the





19
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 EPA
declared that certain greenhouse gases represent an endangerment to human health
and proposed to expand its regulations relating to those
emissions.  It is too early to determine whether, or in what form,
further regulatory action regarding greenhouse gas emissions will be adopted or
what specific impacts a new regulatory action might have on us and our
subsidiaries. However, as a distributor and transporter of natural gas and
consumer of natural gas in our pipeline and gathering businesses, our revenues,
operating costs and capital requirements could be adversely affected as a result
of any regulatory action that would require installation of new control
technologies or a modification of our operations or would have the effect of
reducing the consumption of natural gas.  Likewise, incentives to
conserve energy or use energy sources other than natural gas could result in a
decrease in demand for our services.





Climate
changes could result in more frequent severe weather events and warmer
temperatures which could adversely affect the results of operations of our
businesses.





To the
extent climate changes occur, our businesses may be adversely impacted, though
we believe any such impacts are likely to occur very gradually and hence would
be difficult to quantify with specificity.  To the extent global
climate change results in warmer temperatures in our service territories,
financial results from our natural gas distribution businesses could be
adversely affected through lower gas sales, and our gas transmission and field
services businesses could experience lower revenues. Another possible climate
change that has been widely discussed in recent years is the possibility of more
frequent and more severe weather events, such as hurricanes or
tornadoes.  Since many of our facilities are located along or near the
Gulf Coast, increased or more severe hurricanes or tornadoes can increase our
costs to repair damaged facilities and restore service to our
customers.  When we cannot deliver natural gas to customers or our
customers cannot receive our services, our financial results can be impacted by
lost revenues, and we generally must seek approval from regulators to recover
restoration costs.  To the extent we are unable to recover those
costs, or if higher rates resulting from our recovery of such costs result in
reduced demand for our services, our future financial results may be adversely
impacted.





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 “Business — Our Business — Natural Gas Distribution —
Assets” in Item 1 of this report, which information is incorporated herein by
reference.





Competitive
Natural Gas Sales and Services





For
information regarding the properties of our Competitive Natural Gas Sales and
Services business segment, please read “Business — Our Business — Competitive
Natural Gas Sales and Services — Assets” in Item 1 of this report, which
information is incorporated herein by reference.





Interstate
Pipelines





For
information regarding the properties of our Interstate Pipelines business
segment, please read “Business — Our Business — Interstate Pipelines — Assets”
in Item 1 of this report, which information is incorporated herein by
reference.




20
 Table of Contents





Field
Services





For
information regarding the properties of our Field Services business segment,
please read “Business — Our Business — Field Services — Assets” 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 “Business — Regulation” and “Business — Environmental Matters” in Item 1 of
this report and Notes 3 and 9(e) to our consolidated financial statements, which
information is incorporated herein by reference.





Item 4.  Reserved





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 each
of 2007, 2008 and 2009, we paid dividends on our common stock of
$100 million to Utility Holding, LLC.





Our
revolving credit facility and our receivables facility limit our debt as a
percentage of total capitalization to 65%.  These covenants could
restrict our ability to distribute dividends.





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).





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 own
and operate natural gas distribution systems in six states. Our subsidiaries own
interstate natural gas pipelines and gas gathering systems and provide various
ancillary services. A wholly owned subsidiary of ours offers variable and
fixed-price physical natural gas supplies primarily to commercial and industrial
customers and electric and gas utilities. We are an indirect wholly owned
subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy).





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, economic conditions, 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 and interstate
pipelines business segments are subject to rate regulation. A summary of our
reportable business segments as of December 31, 2009 is set forth
below:





21
 Table of Contents





Natural
Gas Distribution





We own
and operate our regulated natural gas distribution business (Gas Operations),
which engages in intrastate natural gas sales to, and natural gas transportation
for, approximately 3.2 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 and wholesale natural gas
sales to, and transportation services for, commercial and industrial customers
in 18 states in the central and eastern regions of the United
States.





Interstate
Pipelines





Our
interstate pipelines business owns and operates approximately 8,000 miles
of natural gas transmission lines primarily located in Arkansas, Illinois,
Louisiana, Missouri, Oklahoma and Texas. It also owns and operates six natural
gas storage fields with a combined daily deliverability of approximately
1.2 billion cubic feet (Bcf) and a combined working gas capacity of
approximately 59 Bcf. It also owns a 10% interest in an 80 Bcf Bistineau
storage facility located in Bienville Parish, Louisiana, with the remaining
interest owned and operated by Gulf South Pipeline Company, LP. Most storage
operations are in north Louisiana and Oklahoma.





Field
Services





Our field
services business owns and operates approximately 3,700 miles of gathering
pipelines and processing plants that collect, treat and process natural gas from
approximately 140 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.





EXECUTIVE
SUMMARY





Factors
Influencing Our Business




We are an
energy delivery company. The majority of our revenues are generated from the
gathering, processing, transportation and sale of natural gas by our
subsidiaries. To assess our financial performance, our management primarily
monitors operating income and cash flows from our four business segments. Within
these broader financial measures, we monitor margins, operation and maintenance
expense, interest expense, capital spending and working capital requirements. In
addition to these financial measures we also monitor a number of variables that
management considers important to the operation of our business segments,
including the number of customers, throughput, use per customer, commodity
prices and heating degree days. We also monitor system reliability, safety
factors and customer satisfaction to gauge our performance.





To the
extent the adverse economic conditions affect our suppliers and customers,
results from our energy delivery businesses may suffer.  Reduced
demand and lower energy prices could lead to financial pressure on some of our
customers who operate within the energy industry. Also, adverse economic
conditions, coupled with concerns for protecting the environment, may cause
consumers to use less energy or avoid expansions of their facilities, resulting
in less demand for our services.





Performance
of our Natural Gas Distribution business segment is significantly influenced by
the number of customers and energy usage per customer. Weather conditions can
have a significant impact on energy usage, and we compare our results to weather
on an adjusted basis. During 2009, we continued to see evidence that customers
are seeking to conserve in their energy consumption, particularly during periods
of high energy prices or in times of economic distress.  That
conservation can have adverse effects on our results. In many of our service
areas, particularly in the Houston area and in Minnesota, we have benefited from
customer growth that tends to mitigate the effects of reduced
consumption.  We anticipate that this growth will continue despite
recent economic downturns, though that growth may be lower than we have recently
experienced in these areas.  In addition, the





22
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 profitability
of these businesses is influenced significantly by the regulatory treatment we
receive from the various state and local regulators who set our gas distribution
rates. In our recent Gas Operations rate filings, we have sought rate mechanisms
that help to decouple our results from the impacts of weather and conservation,
but such rate mechanisms have not yet been approved in all jurisdictions. We
plan to continue to pursue such decoupling mechanisms in our rate
filings.





Our Field
Services and Interstate Pipelines business segments are currently benefiting
from their proximity to new natural gas producing regions in Texas, Arkansas,
Oklahoma and Louisiana.  Our Interstate Pipelines business segment
benefited from new projects placed into service in 2009 on our Carthage to
Perryville line.  In our Field Services business segment, strong
drilling activity in the new shale producing regions has helped offset declines
in drilling activity in traditional producing regions due to the effects of the
economic downturn and significantly lower commodity prices in 2009. In
monitoring performance of the segments, we focus on throughput of the pipelines
and gathering systems, and in the case of Field Services, on
well-connects.





Our
Competitive Natural Gas Sales and Services business segment contracts with
customers for transportation, storage and sales of natural gas on an unregulated
basis.  Its operations serve customers in the central and eastern
regions of the United States.  The segment benefits from favorable
price differentials, either on a geographic basis or on a seasonal basis. While
it utilizes financial derivatives to hedge its exposure to price movements, it
does not engage in speculative or proprietary trading and maintains a low value
at risk level or VaR to avoid significant financial exposures.  Lower
commodity prices and low price differentials during 2009 adversely affected
results for this business segment.





The
nature of our businesses requires significant amounts of capital investment, and
we rely on internally generated cash, borrowings under our credit facilities,
issuances of debt in the capital markets and capital contributions from our
parent to satisfy these capital needs. We strive to maintain investment grade
ratings for our securities in order to access the capital markets on terms we
consider reasonable. Our goal is to improve our credit ratings over
time.  A reduction in our ratings generally would increase our
borrowing costs for new issuances of debt, as well as borrowing costs under our
existing revolving credit facility. Disruptions in the financial markets, such
as occurred in the last half of 2008 and continued during 2009, can also affect
the availability of new capital on terms we consider attractive. In those
circumstances companies like us may not be able to obtain certain types of
external financing or may be required to accept terms less favorable than they
would otherwise accept. For that reason, we seek to maintain adequate liquidity
for our businesses through our existing credit facility and prudent refinancing
of existing debt. We expect to experience higher borrowing costs and greater
uncertainty in executing capital markets transactions given the current
uncertainties in the financial markets.





As it did
with many businesses, the sharp decline in stock market values during the latter
part of 2008 had a significant adverse impact on the value of CenterPoint
Energy’s pension plan assets.  While that impact did not require us to
make additional contributions to the pension plan, it significantly increased
the pension expense we recognized during 2009 and expect to recognize in 2010
for all our business segments, and we may need to make significant cash
contributions to CenterPoint Energy’s pension plan subsequent to
2010.





Significant
Events





Hurricane
Ike





Gas
Operations suffered some damage to its system in Houston, Texas and in other
portions of its service territory across Texas and Louisiana as a result of
Hurricane Ike, which struck the upper Texas coast in September
2008.  As of December 31, 2009, Gas Operations has deferred
approximately $3 million of costs related to Hurricane Ike for recovery as
part of natural gas distribution rate proceedings.





Long-Term
Gas Gathering and Treatment Agreements





In
September 2009, CenterPoint Energy Field Services, Inc. (CEFS), our wholly-owned
natural gas gathering and treating subsidiary, entered into long-term agreements
with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an
indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide
gathering and treating services for their natural gas production from certain
Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired
jointly-owned gathering facilities from EnCana and Shell in De Soto





23
 Table of Contents
 
 and Red
River parishes in northwest Louisiana.  Each of the agreements
includes acreage dedication and volume commitments for which CEFS has rights to
gather Shell’s and EnCana’s natural gas production from the dedicated
areas.





In
connection with the agreements, CEFS commenced gathering and treating services
utilizing the acquired facilities. CEFS is expanding the acquired facilities in
order to gather and treat up to 700 million cubic feet (MMcf) per day of
natural gas. If EnCana or Shell elect, CEFS will further expand the facilities
in order to gather and treat additional future volumes.  The
construction necessary to reach the contractual capacity of 700 MMcf per day
includes more than 200 miles of gathering lines, nearly 25,500 horsepower of
compression and over 800 MMcf per day of treating capacity.





CEFS
estimates that the purchase of existing facilities and construction to gather
700 MMcf per day will cost up to $325 million. If EnCana and Shell elect
expansion of the project to gather and process additional future volumes of up
to 1 Bcf per day, CEFS estimates that the expansion would cost as much as
an additional $300 million and EnCana and Shell would provide incremental
volume commitments. Funds for construction are being provided from anticipated
cash flows from operations, lines of credit, proceeds from the sale of debt
securities or capital contributions from our parent.  As of December
31, 2009, $176 million had been spent on the project, including the purchase of
existing facilities.





Debt
Financing Transactions





In August
2009, Southeast Supply Header, LLC (SESH) closed on a private debt offering in
the amount of $375 million.  Also during 2009, we made a capital
contribution to SESH in the amount of $137 million.  Using $186
million of its proceeds from the debt offering and the capital contribution,
SESH repaid the note receivable it owed to us, which note had a principal
balance of $323 million at the time of the repayment. We used the proceeds to
repay borrowings under CERC Corp.’s credit facility.





In
October 2009, the size of CERC Corp.’s revolving credit facility was reduced
from $950 million to $915 million through removal of Lehman Brothers
Bank, FSB (Lehman) as a lender.  Prior to its removal, Lehman had a
$35 million commitment to lend.  All credit facility loans to
CERC Corp. that were funded by Lehman were repaid in September
2009.





In
October 2009, we amended our receivables facility to extend the termination date
to October 8, 2010.  Availability under our 364-day receivables
facility ranges from $150 million to $375 million, reflecting seasonal
changes in receivables balances.





In
January 2010, we redeemed $45 million of our outstanding 6% convertible
subordinated debentures due 2012 at 100% of the principal amount plus accrued
and unpaid interest to the redemption date.





Asset
Management Agreements





In 2009,
Gas Operations entered into various asset management agreements associated with
its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma
and Texas.  Generally, these asset management agreements are contracts
between Gas Operations and an asset manager that are intended to transfer the
working capital obligation and maximize the utilization of the assets. In these
agreements, Gas Operations agreed to release transportation and storage capacity
to other parties to manage gas storage, supply and delivery arrangements for Gas
Operations and to use the released capacity for other purposes when it is not
needed for Gas Operations. Gas Operations is compensated by the asset manager
through payments made over the life of the agreements based in part on the
results of the asset optimization.  Gas Operations has received
approval from the state regulatory commissions in Arkansas, Louisiana,
Mississippi and Oklahoma to retain a share of the asset management agreement
proceeds, although the percentage of payments to be retained by Gas Operations
varies based on the jurisdiction, with the majority of the payments to benefit
customers. The agreements have varying terms, the longest of which expires in
2016.




24
 Table of Contents





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, health care reform, and changes in or
      application of laws or regulations applicable to the various aspects of
      our business;





•
            state
      and federal legislative and regulatory actions, developments or
      regulations relating to the environment, including those related to global
      climate change;




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


•
            cost
      overruns on major capital projects that cannot be recouped in
      prices;





•
            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
      and natural gas liquids;





•
            the
      timing and extent of changes in the supply of natural gas, including
      supplies available for gathering by our field services
      business;





•
            the
      timing and extent of changes in natural gas basis
      differentials;





•
            weather
      variations and other natural
phenomena;





•
            changes
      in interest rates or rates of
inflation;





•
            commercial
      bank and financial market conditions, our access to capital, the cost of
      such capital, and the results of our financing and refinancing efforts,
      including availability of funds in the debt capital
    markets;





•
            actions
      by rating agencies;





•
            effectiveness
      of our risk management activities;





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





•
            non-payment
      for our services due to financial distress of our
    customers;





•
            the
      ability of RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc.
      and Reliant Resources, Inc.) and its subsidiaries to satisfy their
      obligations to us, including indemnity obligations, or in connection with
      the contractual arrangements pursuant to which we are their
      guarantor;





•
            the
      outcome of litigation brought by or against
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 be completed or will
      have the anticipated benefits to
us;





•
            acquisition
      and merger activities involving our parent or our competitors;
      and




25
 Table of Contents




•
            other
      factors we discuss under “Risk Factors” in Item 1A of this report and
      in  other reports we file from time to time with the Securities
      and Exchange Commission.





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 as well as natural gas
basis differentials.  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 (in millions) for the years
ended December 31, 2007, 2008 and 2009, 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.





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009Revenues
            
            $
            7,776
            
            
            $
            9,395
            
            
            $
            6,257Expenses:Natural
      gas
            
            
            5,995
            
            
            
            7,466
            
            
            
            4,371Operation
      and maintenance
            
            
            800
            
            
            
            828
            
            
            
            922Depreciation
      and amortization
            
            
            215
            
            
            
            218
            
            
            
            229Taxes
      other than income taxes
            
            
            140
            
            
            
            166
            
            
            
            166Total
            
            
            7,150
            
            
            
            8,678
            
            
            
            5,688Operating
      Income
            
            
            626
            
            
            
            717
            
            
            
            569Interest
      and other finance charges
            
            
            (187
            )
            
            
            (206
            )
            
            
            (213
            )Equity
      in earnings of unconsolidated affiliates
            
            
            16
            
            
            
            51
            
            
            
            15Other
      income, net
            
            
            5
            
            
            
            9
            
            
            
            5Income
      Before Income Taxes
            
            
            460
            
            
            
            571
            
            
            
            376Income
      Tax Expense
            
            
            (173
            )
            
            
            (228
            )
            
            
            (146
            )Net
      Income
            
            $
            287
            
            
            $
            343
            
            
            $
            230





2009 Compared to
2008.We reported net income of $230 million for 2009
compared to $343 million for 2008.  The decrease in net income of
$113 million was primarily due to a $148 million decrease in operating
income from our business segments as discussed below, a $36 million
decrease in equity in earnings of unconsolidated affiliates and a
$7 million increase in interest expense, partially offset by an
$82 million decrease in income tax expense due to lower
earnings.





Income Tax Expense.  Our
2009 effective tax rate of 38.8% differed from the 2008 effective tax rate of
40.0% primarily due to a reduction in state income taxes related to adjustments
in prior years’ state estimates in 2009. For more information, see Note 8 to our
consolidated financial statements.





2008 Compared to
2007.We reported net income of $343 million for 2008
compared to $287 million for 2007.  The increase in net income of
$56 million was primarily due to a $91 million increase in operating
income from our business segments as discussed below and a $35 million
increase in equity in earnings of unconsolidated affiliates related primarily to
SESH, partially offset by a $55 million increase in income tax expense due
to higher earnings and a $19 million increase in interest
expense.





Income Tax Expense.  Our
2008 effective tax rate of 40.0% differed from the 2007 effective tax rate of
37.6% primarily due to the settlement in 2007 of our prior-year state income tax
return examinations.




26
 Table of Contents





RESULTS
OF OPERATIONS BY BUSINESS SEGMENT





The
following table presents operating income (in millions) for each of our business
segments for 2007, 2008 and 2009. Included in revenues are intersegment sales.
We account for intersegment sales as if the sales were to third parties, that
is, at current market prices.





Operating
Income (Loss) by Business Segment





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009Natural
      Gas Distribution
            
            $
            218
            
            
            $
            215
            
            
            $
            204Competitive
      Natural Gas Sales and Services
            
            
            75
            
            
            
            62
            
            
            
            21Interstate
      Pipelines
            
            
            237
            
            
            
            293
            
            
            
            256Field
      Services
            
            
            99
            
            
            
            147
            
            
            
            94Other
      Operations
            
            
            (3
            )
            
            
            —
            
            
            
            (6
            )Total
      Consolidated Operating Income
            
            $
            626
            
            
            $
            717
            
            
            $
            569





Natural
Gas Distribution





The
following table provides summary data of our Natural Gas Distribution business
segment for 2007, 2008 and 2009 (in millions, except throughput and customer
data):





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009Revenues
            
            $
            3,759
            
            
            $
            4,226
            
            
            $
            3,384Expenses:Natural
      gas
            
            
            2,683
            
            
            
            3,124
            
            
            
            2,251Operation
      and maintenance
            
            
            579
            
            
            
            589
            
            
            
            639Depreciation
      and amortization
            
            
            155
            
            
            
            157
            
            
            
            161Taxes
      other than income taxes
            
            
            124
            
            
            
            141
            
            
            
            129Total
      expenses
            
            
            3,541
            
            
            
            4,011
            
            
            
            3,180Operating
      Income
            
            $
            218
            
            
            $
            215
            
            
            $
            204Throughput
      (in Bcf):Residential
            
            
            172
            
            
            
            175
            
            
            
            173Commercial
      and industrial
            
            
            232
            
            
            
            236
            
            
            
            233Total
      Throughput
            
            
            404
            
            
            
            411
            
            
            
            406Number
      of customers at end of period:Residential
            
            
            2,961,110
            
            
            
            2,987,222
            
            
            
            3,002,114Commercial
      and industrial
            
            
            249,877
            
            
            
            248,476
            
            
            
            244,101Total
            
            
            3,210,987
            
            
            
            3,235,698
            
            
            
            3,246,215





2009 Compared to
2008.Our Natural Gas Distribution business segment reported
operating income of $204 million for 2009 compared to $215 million for
2008. Operating income declined ($11 million) primarily as a result of
increased pension expense ($37 million) and higher labor  and
other benefit costs ($16 million), partially offset by increased revenues
from rate increases ($36 million) and lower bad debt expense ($15 million).
Revenues related to both energy-efficiency costs and gross receipts taxes are
substantially offset by the related expenses. Depreciation and amortization
expense increased $4 million primarily due to higher plant
balances.  Taxes other than income taxes, net of the decrease in gross
receipts taxes ($16 million), increased $4 million also primarily due
to higher plant balances.





2008 Compared to
2007.Our Natural Gas Distribution business segment reported
operating income of $215 million for 2008 compared to $218 million for
2007. Operating income declined in 2008 due to a combination of
non-weather-related usage ($13 million), due in part to higher gas prices,
higher customer-related and support services costs ($9 million), higher bad
debts and collection costs ($4 million), increased costs of materials and
supplies ($4 million), and an increase in depreciation and amortization and
taxes other than income taxes ($3 million) resulting from increased
investment in property, plant and equipment. The adverse impacts on operating
income were partially offset by the net impact of rate increases
($11 million), lower labor and benefits costs ($14 million), and
customer growth from the addition of approximately 25,000 customers in 2008
($6 million).




27
 Table of Contents




Competitive
Natural Gas Sales and Services





The
following table provides summary data of our Competitive Natural Gas Sales and
Services business segment for 2007, 2008 and 2009 (in millions, except
throughput and customer data):





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009Revenues
            
            $
            3,579
            
            
            $
            4,528
            
            
            $
            2,230Expenses:Natural
      gas
            
            
            3,467
            
            
            
            4,423
            
            
            
            2,165Operation
      and maintenance
            
            
            31
            
            
            
            39
            
            
            
            39Depreciation
      and amortization
            
            
            5
            
            
            
            3
            
            
            
            4Taxes
      other than income taxes
            
            
            1
            
            
            
            1
            
            
            
            1Total
      expenses
            
            
            3,504
            
            
            
            4,466
            
            
            
            2,209Operating
      Income
            
            $
            75
            
            
            $
            62
            
            
            $
            21Throughput
      (in Bcf)
            
            
            522
            
            
            
            528
            
            
            
            504Number
      of customers at end of period
            
            
            7,139
            
            
            
            9,771
            
            
            
            11,168





2009 Compared to 2008.Our Competitive Natural Gas Sales and Services business
segment reported operating income of $21 million for 2009 compared to
$62 million for 2008.  The decrease in operating income of
$41 million was due to the unfavorable impact of the mark-to-market
valuation for non-trading financial derivatives for 2009 of $23 million
versus a favorable impact of $13 million for the same period in
2008.  A further $28 million decrease in margin is attributable
to reduced basis spreads on pipeline transport opportunities and an absence of
summer storage spreads. These decreases in operating income were partially
offset by a $6 million write-down of natural gas inventory to the lower of
cost or market for 2009 compared to a $30 million write-down in the same
period last year.  Our Competitive Natural Gas Sales and Services
business segment purchases and stores natural gas to meet certain future sales
requirements and enters into derivative contracts to hedge the economic value of
the future sales.





2008 Compared to 2007.Our Competitive Natural Gas Sales and Services business
segment reported operating income of $62 million for the year ended
December 31, 2008 compared to $75 million for the year ended December 31,
2007.  The decrease in operating income in 2008 of $13 million
primarily resulted from lower gains on sales of gas from previously written down
inventory ($24 million) and higher operation and maintenance costs
($6 million), which were partially offset by improved margin as basis and
summer/winter spreads increased ($12 million). In addition, 2008 included a
gain from mark-to-market accounting ($13 million) and a write-down of
natural gas inventory to the lower of average cost or market ($30 million),
compared to a charge to income from mark-to-market accounting for non-trading
derivatives ($10 million) and a write-down of natural gas inventory to the
lower of average cost or market ($11 million) for 2007.






28
 Table of Contents





Interstate
Pipelines





The
following table provides summary data of our Interstate Pipelines business
segment for 2007, 2008 and 2009 (in millions, except throughput
data):





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009Revenues
            
            $
            500
            
            
            $
            650
            
            
            $
            598Expenses:Natural
      gas
            
            
            83
            
            
            
            155
            
            
            
            97Operation
      and maintenance
            
            
            125
            
            
            
            133
            
            
            
            166Depreciation
      and amortization
            
            
            44
            
            
            
            46
            
            
            
            48Taxes
      other than income taxes
            
            
            11
            
            
            
            23
            
            
            
            31Total
      expenses
            
            
            263
            
            
            
            357
            
            
            
            342Operating
      Income
            
            $
            237
            
            
            $
            293
            
            
            $
            256Transportation
      throughput (in Bcf)
            
            
            1,216
            
            
            
            1,538
            
            
            
            1,592





2009 Compared to
2008.  Our Interstate Pipeline business segment reported
operating income of $256 million for 2009 compared to $293 million for
2008. Margins (revenues less natural gas costs) increased $6 million
primarily due to the Carthage to Perryville pipeline ($28 million) and new
contracts with power generation customers ($20 million), partially offset
by reduced other transportation margins and ancillary services
($42 million) primarily due to the decline in commodity prices from the
significantly higher levels in 2008.  Operations and maintenance
expenses increased due to a gain on the sale of two storage development projects
in 2008 ($18 million) and costs associated with incremental facilities
($12 million) and increased pension expenses
($9 million).  These expenses were partially offset by a
write-down associated with pipeline assets removed from service in the third
quarter of 2008 ($7 million).  Depreciation and amortization
expenses increased $2 million and taxes other than income taxes increased
by $8 million, $2 million of which was due to 2008 tax
refunds.





2008 Compared to
2007.  Our Interstate Pipeline business segment reported
operating income of $293 million for 2008 compared to $237 million for
2007. The increase in operating income in 2008 was primarily driven by increased
margins (revenues less natural gas costs) on the Carthage to Perryville pipeline
that went into service in May 2007 ($51 million), increased transportation
and ancillary services ($27 million), and a gain on the sale of two storage
development projects ($18 million). These increases were partially offset
by higher operation and maintenance expenses ($19 million), a write-down
associated with pipeline assets removed from service ($7 million),
increased depreciation expense ($2 million), and higher taxes other than
income taxes ($12 million), largely due to tax refunds in
2007.





Equity Earnings.In addition,
this business segment recorded equity income of $6 million,
$36 million and $7 million in the years ended December 31, 2007, 2008
and 2009, respectively, from its 50% interest in SESH, a jointly-owned pipeline.
The 2007 and 2008 year-end results include $6 million and $33 million
of pre-operating allowance for funds used during construction, respectively. The
2009 results include a non-cash pre-tax charge of $16 million to reflect
SESH’s decision to discontinue the use of guidance for accounting for regulated
operations, which was partially offset by the receipt of a one-time payment
related to the construction of the pipeline and a reduction in estimated
property taxes, of which our 50% share was $5 million. Excluding the effect
of these adjustments, equity earnings from normal operations was $3 million and
$18 million in 2008 and 2009, respectively.  These amounts are
included in Equity in Earnings of Unconsolidated Affiliates under the Other
Income (Expense) caption.






29
 Table of Contents





Field
Services





The
following table provides summary data of our Field Services business segment for
2007, 2008 and 2009 (in millions, except throughput data):





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009Revenues
            
            $
            175
            
            
            $
            252
            
            
            $
            241Expenses:Natural
      gas
            
            
            (4
            )
            
            
            21
            
            
            
            51Operation
      and maintenance
            
            
            66
            
            
            
            69
            
            
            
            77Depreciation
      and amortization
            
            
            11
            
            
            
            12
            
            
            
            15Taxes
      other than income taxes
            
            
            3
            
            
            
            3
            
            
            
            4Total
      expenses
            
            
            76
            
            
            
            105
            
            
            
            147Operating
      Income
            
            $
            99
            
            
            $
            147
            
            
            $
            94Gathering
      throughput (in Bcf)
            
            
            398
            
            
            
            421
            
            
            
            426





2009 Compared to
2008.  Our Field Services business segment reported operating
income of $94 million for 2009 compared to $147 million for 2008.
Operating margin from new projects and core gathering services increased
approximately $24 million for 2009 when compared to the same period in 2008
primarily due to continued development in the shale plays.  This
increase was offset primarily by the effect of a decline in commodity prices of
approximately $54 million from the significantly higher prices experienced
in 2008.  Operating income for 2009 also included higher costs
associated with incremental facilities ($4 million) and increased pension
cost ($2 million).  Operating income for 2008 benefited from a
one-time gain ($11 million) related to a settlement and contract buyout of
one of our customers and a gain on sale of assets
($6 million).





2008 Compared to
2007.  Our Field Services business segment reported operating
income of $147 million for 2008 compared to $99 million for 2007. The
increase in operating income of $48 million resulted from higher margins
(revenue less natural gas costs) from gas gathering, ancillary services and
higher commodity prices ($34 million) and a one-time gain related to a
settlement and contract buyout of one of our customers
($11 million).  Operating expenses increased from 2007 to 2008
due to higher expenses associated with new assets and general cost increases,
partially offset by a gain  related to the sale of assets in 2008
($6 million).





Equity Earnings.In addition,
this business segment recorded equity income of $10 million,
$15 million and $8 million for the years ended December 31, 2007,
2008 and 2009, respectively, from its 50% interest in a jointly-owned gas
processing plant. The decrease is driven by a decrease in natural gas liquid
prices. These amounts are included in Equity in earnings of unconsolidated
affiliates under the Other Income (Expense) caption.





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, tax payments,
working capital needs, various regulatory actions and appeals relating to such
actions. Our principal anticipated cash requirements for 2010 include
approximately $613 million of capital expenditures and $45 million for our
January 2010 redemption of debentures.





We expect
that borrowings under our credit facility, advances under our receivables
facility, anticipated cash flows from operations and intercompany borrowings
will be sufficient to meet our anticipated cash needs in 2010. Cash needs or
discretionary financing or refinancing may result in the issuance of debt
securities in the capital markets or the arrangement of additional credit
facilities. Issuances of debt in the capital markets and additional credit
facilities may not, however, be available to us on acceptable
terms.


30
 Table of Contents


The
following table sets forth our capital expenditures for 2009 and estimates of
our capital requirements for 2010 through 2014 (in millions):





2009
            
            
            2010
            
            
            2011
            
            
            2012
            
            
            2013
            
            
            2014Natural
      Gas Distribution
            
            $
            165
            
            
            $
            210
            
            
            $
            237
            
            
            $
            241
            
            
            $
            259
            
            
            $
            248Competitive
      Natural Gas Sales and Services
            
            
            2
            
            
            
            6
            
            
            
            4
            
            
            
            16
            
            
            
            5
            
            
            
            5Interstate
      Pipelines
            
            
            176
            
            
            
            171
            
            
            
            192
            
            
            
            245
            
            
            
            164
            
            
            
            94Field
      Services
            
            
            348
            
            
            
            226
            
            
            
            163
            
            
            
            126
            
            
            
            95
            
            
            
            85Total
            
            $
            691
            
            
            $
            613
            
            
            $
            596
            
            
            $
            628
            
            
            $
            523
            
            
            $
            432





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





Contractual
      Obligations
            
            Total
            
            
            2010
            
            
            
            2011-2012
            
            
            
            2013-2014
            
            
            2015
      and
              thereafterLong-term
      debt
            
            $
            2,786
            
            
            $
            44
            
            
            $
            550
            
            
            $
            924
            
            
            $
            1,268Interest
      payments — long-term debt(1)
            
            
            1,444
            
            
            
            191
            
            
            
            319
            
            
            
            203
            
            
            
            731Short-term
      borrowings
            
            
            55
            
            
            
            55
            
            
            
            —
            
            
            
            —
            
            
            
            —Operating
      leases(2)
            
            
            51
            
            
            
            12
            
            
            
            22
            
            
            
            10
            
            
            
            7Benefit
      obligations(3)
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —Purchase
      obligations(4)
            
            
            9
            
            
            
            9
            
            
            
            —
            
            
            
            —
            
            
            
            —Non-trading
      derivative liabilities
            
            
            93
            
            
            
            51
            
            
            
            42
            
            
            
            —
            
            
            
            —Other
      commodity commitments(5)
            
            
            2,558
            
            
            
            439
            
            
            
            917
            
            
            
            659
            
            
            
            543Income
      taxes(6)
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —Total
      contractual cash obligations
            
            $
            6,996
            
            
            $
            801
            
            
            $
            1,850
            
            
            $
            1,796
            
            
            $
            2,549





(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, 2009. 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 9(c) to our
      consolidated financial statements.





(3)
            We
      expect to contribute approximately $9 million to our postretirement
      benefits plan in 2010 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 our Interstate
      Pipelines business segment.





(5)
            For
      a discussion of other commodity commitments, please read Note 9(a) to our
      consolidated financial statements.





(6)
            As
      of December 31, 2009, the liability for uncertain income tax positions was
      $6 million.  However, due to the high degree of uncertainty
      regarding the timing of potential future cash flows associated with these
      liabilities, we are unable to make a reasonably reliable estimate of the
      amount and period in which any such liabilities might be
    paid.





Off-Balance Sheet
Arrangements.  Other than operating leases and the guaranties
described below, we have no off-balance sheet arrangements.





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. When the companies separated, RRI agreed to secure us against
obligations under the guaranties RRI had been unable to extinguish by the time
of separation. Pursuant to such agreement, as amended in December 2007, RRI has
agreed to provide to us cash or letters of credit as security against our
obligations under our remaining guaranties for demand charges under certain gas
transportation agreements if and to the extent changes in market conditions
expose us to a risk of loss on those guaranties.  The present value of the
demand charges under these transportation contracts, which will be effective
until 2018, was approximately $96 million as of December 31, 2009. As of
December 31, 2009, RRI was not





31
 Table of Contents
 
 required
to provide security to us.  If RRI should fail to perform the contractual
obligations, we could have to honor our guarantee and, in such event, collateral
provided as security may be insufficient to satisfy our
obligations.





Debt Financing
Transactions.  On August 13, 2009, SESH issued
$375 million of 4.85% senior notes due 2014.  SESH used one-half
of the proceeds of the notes to repay a construction loan to us in the amount of
$186 million.  We used the proceeds from the construction loan
repayment to repay borrowings under CERC Corp.’s credit facility.





In
January 2010, we redeemed $45 million of our outstanding 6% convertible
subordinated debentures due 2012 at 100% of the principal amount plus accrued
and unpaid interest to the redemption date.





Credit and Receivables
Facilities.In October 2009, the size of CERC Corp.’s
revolving credit facility was reduced from $950 million to
$915 million through removal of Lehman as a lender.  Prior to its
removal, Lehman had a $35 million commitment to lend.  All credit
facility loans to CERC Corp. that were funded by Lehman were repaid in September
2009.





In
October 2009, we amended our receivables facility to extend the termination date
to October 8, 2010.  Availability under our 364-day receivables
facility ranges from $150 million to $375 million, reflecting seasonal
changes in receivables balances.





As of
February 15, 2010, we had the following facilities (in millions):





Date
      Executed
            
            Type
      of
              Facility
            
            Size
      of
              Facility
            
            
            Amount
              Utilized
      at
              February 15,
              2010
            
            Termination
      DateJune
      29, 2007
            
            Revolver
            
            $
            915
            
            
            $
            —
            
            June
      29, 2012October
      9, 2009
            
            Receivables
            
            
            375
            
            
            
            —
            
            October
      8, 2010





CERC
Corp.’s $915 million credit facility’s first drawn cost is the London Interbank
Offered Rate (LIBOR) plus 45 basis points based on our current credit
ratings.  The facility contains covenants, including a debt to total
capitalization covenant.





Under the
credit facility, an additional utilization fee of 5 basis points applies to
borrowings any time more than 50% of the facility is utilized. The spread to
LIBOR and the utilization fee fluctuate based on our credit rating. Borrowings
under the facility are subject to customary terms and conditions. However, there
is no requirement that we make representations prior to borrowings as to the
absence of material adverse changes or litigation that could be expected to have
a material adverse effect. Borrowings under the credit facility are subject to
acceleration upon the occurrence of events of default that we consider
customary.





We are
currently in compliance with the various business and financial covenants
contained in the respective receivables and credit facilities.





CERC
Corp.’s $915 million credit facility backstops a $915 million
commercial paper program under which we began issuing commercial paper in
February 2008. Our commercial paper is rated “P-3” by Moody’s Investors Service,
Inc. (Moody’s), “A-3” by Standard & Poor’s Rating Services, a division
of The McGraw Hill Companies (S&P), and “F2” by Fitch, Inc. (Fitch). As a
result of the credit ratings on our commercial paper program, we do not expect
to be able to rely on the sale of commercial paper to fund all of our short-term
borrowing requirements. We cannot assure you that these ratings, or the credit
ratings set forth below in “— Impact on Liquidity of a Downgrade in Credit
Ratings,” will remain in effect for any given period of time or that one or more
of these ratings will not be lowered or withdrawn entirely by a rating agency.
We note that these credit ratings are not recommendations to buy, sell or hold
our securities and may be revised or withdrawn at any time by the rating agency.
Each rating should be evaluated independently of any other rating. Any future
reduction or withdrawal of one or more of our credit ratings could have a
material adverse impact on our ability to obtain short- and long-term financing,
the cost of such financings and the execution of our commercial
strategies.





Securities Registered with the
SEC.  At December 31, 2009, we had a shelf registration
statement covering $500 million principal amount of senior debt
securities.





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Temporary
Investments.As of February 15, 2010, we had no external
temporary investments.





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 by
CenterPoint Energy under its revolving credit facility or the sale by
CenterPoint Energy of its commercial paper. At February 15, 2010, we had
borrowings of $238 million from the money pool.  The money pool
may not provide sufficient funds to meet our cash needs.





Impact on Liquidity of a Downgrade
in Credit Ratings.  As of February 15, 2010, Moody’s,
S&P and Fitch had assigned the following credit ratings to our senior
unsecured debt:





Moody’s
            
            S&P
            
            FitchRating
            
            Outlook(1)
            
            Rating
            
            Outlook(2)
            
            Rating
            
            Outlook(3)Baa3
            
            Stable
            
            BBB
            
            Negative
            
            BBB
            
            Stable


__________


(1)
            A
      Moody’s rating outlook is an opinion regarding the likely direction of a
      rating over the medium term.





(2)
            An
      S&P rating outlook assesses the potential direction of a long-term
      credit rating over the intermediate to longer
  term.





(3)
            A
      “stable” outlook from Fitch encompasses a one-to-two year horizon as to
      the likely ratings direction.





A decline
in these credit ratings could increase borrowing costs under our
$915 million credit facility. If our credit ratings had been downgraded one
notch by each of the three principal credit rating agencies from the ratings
that existed at December 31, 2009, the impact on the borrowing costs under
our credit facility would have been immaterial. 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 earnings of our Natural Gas Distribution
and Competitive Natural Gas Sales and Services business segments.





We and
our subsidiaries purchase natural gas from our largest supplier under supply
agreements that contain an aggregate credit threshold of $120 million based
on CERC Corp.’s S&P senior unsecured long-term debt rating of BBB. Under
these agreements, we may need to provide collateral if the aggregate threshold
is exceeded. Upgrades and downgrades from this BBB rating will increase and
decrease the aggregate credit threshold accordingly.





CenterPoint
Energy Services, Inc. (CES), our wholly owned subsidiary 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 economically hedge its exposure to
natural gas prices, CES uses derivatives with provisions standard for the
industry, including those pertaining to credit thresholds. Typically, the credit
threshold negotiated with each counterparty defines the amount of unsecured
credit that such counterparty will extend to CES. To the extent that the credit
exposure that a counterparty has to CES at a particular time does not exceed
that credit threshold, CES is not obligated to provide collateral.
Mark-to-market exposure in excess of the credit threshold is routinely
collateralized by CES. As of December 31, 2009, the amount posted as
collateral aggregated approximately $114 million ($84 million of which
is associated with price stabilization activities of our Natural Gas
Distribution business segment). Should the credit ratings of CERC Corp. (as the
credit support provider for CES) fall below certain levels, CES would be
required to provide additional collateral up to the amount of its previously
unsecured credit limit. We estimate that as of December 31, 2009, unsecured
credit limits extended to CES by counterparties aggregate $241 million;
however, utilized credit capacity was $67 million.





Pipeline
tariffs and contracts typically provide that if the credit ratings of a shipper
or the shipper’s guarantor drop below a threshold level, which is generally
investment grade ratings from both Moody’s and S&P, cash or other collateral
may be demanded from the shipper in an amount equal to the sum of three months’
charges for pipeline services plus the unrecouped cost of any lateral built for
such shipper. If the credit ratings of CERC Corp. decline below the applicable
threshold levels, we might need to provide cash or other collateral of as much
as $188 million as of December 31, 2009.  The amount of
collateral will depend on seasonal variations in transportation
levels.





33
 Table of Contents





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. In addition, four outstanding
series of CenterPoint Energy’s senior notes, aggregating $950 million in
principal amount as of February 15, 2010, provide that 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. A default by CenterPoint Energy would
not trigger a default under our debt instruments or bank credit
facilities.





Possible Acquisitions, Divestitures
and Joint Ventures.  From time to time, we consider the
acquisition or the disposition of assets or businesses or possible joint
ventures or other joint ownership arrangements with respect to assets or
businesses. Any determination to take any action in this regard will be based on
market conditions and opportunities existing at the time, and accordingly, the
timing, size or success of any efforts and the associated potential capital
commitments are unpredictable. We may seek to fund all or part of any such
efforts with proceeds from debt issuances. Debt financing may not, however, be
available to us at that time due to a variety of events, including, among
others, maintenance of our credit ratings, industry conditions, general economic
conditions, market conditions and market perceptions.





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 and weather hedging and gas
      storage activities of our Natural Gas Distribution and Competitive Natural
      Gas Sales and Services business
segments;





•
            acceleration
      of payment dates on certain gas supply contracts under certain
      circumstances, as a result of increased gas prices and concentration of
      natural gas suppliers;





•
            increased
      costs related to the acquisition of natural
gas;





•
            increases
      in interest expense in connection with debt refinancings and borrowings
      under credit facilities;





•
            various
      regulatory actions;





•
            increased
      capital expenditures required for new gas pipeline or field services
      projects;





•
            the
      ability of our customers to fulfill their payment obligations to
      us;





•
            the
      ability of RRI and its subsidiaries to satisfy their obligations in
      respect of RRI’s indemnity obligations to us and our subsidiaries or in
      connection with the contractual obligations to a third party pursuant to
      which we are their guarantor;





•
            slower
      customer payments and increased write-offs of receivables due to higher
      gas prices or changing economic
conditions;





•
            the
      outcome of litigation brought by and against
us;





•
            restoration
      costs and revenue losses resulting from natural disasters such as
      hurricanes and the timing of recovery of such restoration
      costs; and





•
            various
      other risks identified in “Risk Factors” in Item 1A of this
      report.





Certain Contractual Limits on Our
Ability to Issue Securities and Borrow Money.Our revolving credit
facility and our receivables facility limit our debt as a percentage of our
total capitalization to 65%.





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.





34
 Table of Contents





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.





Accounting
for Rate Regulation




Accounting
guidance for regulated operations provides that rate-regulated entities account
for and report assets and liabilities consistent with the recovery of those
incurred costs in rates if the rates established are designed to recover the
costs of providing the regulated service and if the competitive environment
makes it probable that such rates can be charged and collected. Our Natural Gas
Distribution business segment and portions of our Interstate Pipelines business
segment apply this accounting guidance. Certain expenses and revenues subject to
utility regulation or rate determination normally reflected in income are
deferred on the balance sheet as regulatory assets or liabilities and are
recognized in income as the related amounts are included in service rates and
recovered from or refunded to customers.  Regulatory assets and
liabilities are recorded when it is probable that these items will be recovered
or reflected in future rates.  Determining probability requires
significant judgment on the part of management and includes, but is not limited
to, consideration of testimony presented in regulatory hearings, proposed
regulatory decisions, final regulatory orders and the strength or status of
applications for rehearing or state court appeals.  If events were to
occur that would make the recovery of these assets and liabilities no longer
probable, we would be required to write off or write down these regulatory
assets and liabilities.  At December 31, 2009, we had recorded
regulatory assets of $61 million and regulatory liabilities of $539
million.





Impairment
of Long-Lived Assets and Intangibles





We review
the carrying value of our long-lived assets, including goodwill and identifiable
intangibles, whenever events or changes in circumstances indicate that such
carrying values may not be recoverable, and at least annually for goodwill as
required by accounting guidance for goodwill and other intangible assets. No
impairment of goodwill was indicated based on our annual analysis at
July 1, 2009. 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, interest rates,
regulatory matters and operating costs could negatively affect the fair value of
our assets and result in an impairment charge.





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





Unbilled
Energy Revenues





Revenues
related to natural gas sales and services are generally recognized upon delivery
to customers. However, the determination of deliveries to individual customers
is based on the reading of their meters, which is performed





35
 Table of Contents
 
 on a
systematic basis throughout the month. At the end of each month, deliveries 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.





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 Plans. As discussed
in Note 2(o) to our consolidated financial statements, we participate in
CenterPoint Energy’s qualified and non-qualified pension plans covering
substantially all employees. The expected pension cost for 2010 is
$35 million, of which we expect $28 million to impact pre-tax
earnings, based on an expected return on plan assets of 8.00% and a discount
rate of 5.70% as of December 31, 2009. We recorded pension expense of
$47 million for the year ended December 31, 2009.  Future
changes in plan asset returns, assumed discount rates and various other factors
related to the pension plans 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, natural
      gas liquids and other energy
commodities.





•
            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 commodity price risk
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





As of
December 31, 2009, we had outstanding long-term debt and bank loans from
affiliates that subject us to the risk of loss associated with movements in
market interest rates.




36
 Table of Contents





Our
floating-rate obligations aggregated $1.0 billion and $432 million at
December 31, 2008 and 2009, respectively. If the floating interest rates
were to increase by 10% from December 31, 2009 rates, our combined interest
expense would increase by less than $1 million annually.





At both
December 31, 2008 and 2009, we had outstanding fixed-rate debt aggregating
$2.8 billion in principal amount and having a fair value of
$2.6 billion and $3.0 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 7 to our consolidated
financial statements). However, the fair value of these instruments would
increase by approximately $79 million if interest rates were to decline by
10% from their levels at December 31, 2009. 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





We use
derivative instruments as economic hedges to offset the commodity price 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 fair value based on a hypothetical
10% movement in energy prices. At December 31, 2009, the recorded fair
value of our non-trading energy derivatives was a net liability of
$134 million (before collateral). The net liability consisted of a net
liability of $143 million associated with price stabilization activities of
our Natural Gas Distribution business segment and a net asset of $9 million
related to our Competitive Natural Gas Sales and Services business segment. Net
assets or liabilities related to the price stabilization activities correspond
directly with net over/under recovered gas cost liabilities or assets on the
balance sheet. A decrease of 10% in the market prices of energy commodities from
their December 31, 2009 levels would have increased the fair value of our
non-trading energy derivatives net liability by
$31 million.  However, the consolidated income statement impact
of this same 10% decrease in market prices would be an increase in income of
$3 million.





The above
analysis of the non-trading energy derivatives utilized for commodity price risk
management purposes does not include the favorable impact that the same
hypothetical price movement would have on our physical purchases and sales of
natural gas to which the hedges relate. Furthermore, the non-trading energy
derivative portfolio is managed to complement the physical transaction
portfolio, reducing overall risks within limits. Therefore, the adverse impact
to the fair value of the portfolio of non-trading energy derivatives held for
hedging purposes associated with the hypothetical changes in commodity prices
referenced above is expected to be substantially offset by a favorable impact on
the underlying hedged physical transactions.




37
 Table of Contents


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”, an indirect wholly owned
subsidiary of CenterPoint Energy, Inc.) as of December 31, 2009 and 2008, and
the related statements of consolidated income, comprehensive income, cash flows
and stockholder’s equity for each of the three years in the period ended
December 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2009, in
conformity with accounting principles generally accepted in the United States of
America.








/s/
DELOITTE & TOUCHE LLP








Houston,
Texas


March 11,
2010







38
 Table of Contents


MANAGEMENT’S
ANNUAL REPORT ON INTERNAL CONTROL


OVER
FINANCIAL REPORTING





Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting. Internal control over financial reporting is
defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities
Exchange Act of 1934 as a process designed by, or under the supervision of, the
company’s principal executive and principal financial officers and effected by
the company’s board of directors, management and other personnel, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles and includes those policies and
procedures that:





•
            Pertain
      to the maintenance of records that in reasonable detail accurately and
      fairly reflect the transactions and dispositions of the assets of the
      company;





•
            Provide
      reasonable assurance that transactions are recorded as necessary to permit
      preparation of financial statements in accordance with generally accepted
      accounting principles, and that receipts and expenditures of the company
      are being made only in accordance with authorizations of management and
      directors of the company; and





•
            Provide
      reasonable assurance regarding prevention or timely detection of
      unauthorized acquisition, use or disposition of the company’s assets that
      could have a material effect on the financial
  statements.





Management
has designed its internal control over financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements in accordance with accounting principles generally
accepted in the United States of America. Management’s assessment included
review and testing of both the design effectiveness and operating effectiveness
of controls over all relevant assertions related to all significant accounts and
disclosures in the financial statements.





All
internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentation. Projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.





Under the
supervision and with the participation of our management, including our
principal executive officer and principal financial officer, we conducted an
evaluation of the effectiveness of our internal control over financial reporting
based on the framework in Internal Control — Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission. Based on
our evaluation under the framework in Internal Control — Integrated
Framework, our management has concluded that our internal control over financial
reporting was effective as of December 31, 2009.





This
annual report does not include an attestation report of our registered public
accounting firm regarding internal control over financial
reporting.  Management’s report was not subject to attestation by our
registered public accounting firm pursuant to temporary rules of the Securities
and Exchange Commission that permit us to provide only management’s report in
this annual report.


/s/  DAVID M.
      MCCLANAHANPresident
      and Chief Executive Officer/s/  GARY L.
      WHITLOCKExecutive
      Vice President and ChiefFinancial
      Officer




March 11,
2010




39
 Table of Contents


CENTERPOINT ENERGY RESOURCES CORP. AND
SUBSIDIARIES


(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)





STATEMENTS
OF CONSOLIDATED INCOME





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009(In
      Millions)Revenues
            
            $
            7,776
            
            
            $
            9,395
            
            
            $
            6,257Expenses:Natural
      gas
            
            
            5,995
            
            
            
            7,466
            
            
            
            4,371Operation
      and maintenance
            
            
            800
            
            
            
            828
            
            
            
            922Depreciation
      and amortization
            
            
            215
            
            
            
            218
            
            
            
            229Taxes
      other than income taxes
            
            
            140
            
            
            
            166
            
            
            
            166Total
            
            
            7,150
            
            
            
            8,678
            
            
            
            5,688Operating
      Income
            
            
            626
            
            
            
            717
            
            
            
            569Other
      Income (Expense):Interest
      and other finance charges
            
            
            (187
            )
            
            
            (206
            )
            
            
            (213
            )Equity
      in earnings of unconsolidated affiliates
            
            
            16
            
            
            
            51
            
            
            
            15Other,
      net
            
            
            5
            
            
            
            9
            
            
            
            5Total
            
            
            (166
            )
            
            
            (146
            )
            
            
            (193
            )Income
      Before Income Taxes
            
            
            460
            
            
            
            571
            
            
            
            376Income
      tax expense
            
            
            (173
            )
            
            
            (228
            )
            
            
            (146
            )Net
      Income
            
            $
            287
            
            
            $
            343
            
            
            $
            230











See Notes
to Consolidated Financial Statements


40
 Table of Contents





CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES


(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)





STATEMENTS
OF CONSOLIDATED COMPREHENSIVE INCOME





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009(In
      Millions)Net
      income
            
            $
            287
            
            
            $
            343
            
            
            $
            230Other
      comprehensive income (loss), net of tax:Adjustment
      to pension and other postretirement plans (net of tax of
              $6,
      $3 and $3)
            
            
            13
            
            
            
            (13
            )
            
            
            (2
            )Net
      deferred gain from cash flow hedges (net of tax of $6, $-0-
      and
              $-0-)
            
            
            12
            
            
            
            —
            
            
            
            —Reclassification
      of net deferred gain from cash flow hedges
              realized
      in net income (net of tax of $20, $3 and $-0-)
            
            
            (33
            )
            
            
            (5
            )
            
            
            —Other
      comprehensive loss
            
            
            (8
            )
            
            
            (18
            )
            
            
            (2
            )Comprehensive
      income
            
            $
            279
            
            
            $
            325
            
            
            $
            228











See Notes
to Consolidated Financial Statements


41
 Table of Contents


CENTERPOINT ENERGY RESOURCES CORP. AND
SUBSIDIARIES


(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)





CONSOLIDATED
BALANCE SHEETS





December 31,2008
            
            
            2009(In
      Millions)ASSETSCurrent
      Assets:Cash
      and cash equivalents
            
            $
            1
            
            
            $
            1Accounts
      receivable, net
            
            
            774
            
            
            
            593Accrued
      unbilled revenue
            
            
            480
            
            
            
            421Accounts
      and notes receivable — affiliated companies
            
            
            9
            
            
            
            13Inventory
            
            
            495
            
            
            
            258Non-trading
      derivative assets
            
            
            118
            
            
            
            39Taxes
      receivable
            
            
            —
            
            
            
            47Deferred
      income tax assets
            
            
            25
            
            
            
            16Prepaid
      expenses and other current assets
            
            
            327
            
            
            
            144Total
      current assets
            
            
            2,229
            
            
            
            1,532Property,
      Plant and Equipment, Net
            
            
            5,363
            
            
            
            5,875Other
      Assets:Goodwill
            
            
            1,696
            
            
            
            1,696Non-trading
      derivative assets
            
            
            20
            
            
            
            15Investment
      in unconsolidated affiliates
            
            
            345
            
            
            
            463Notes
      receivable from unconsolidated affiliates
            
            
            323
            
            
            
            —Other
            
            
            235
            
            
            
            203Total
      other assets
            
            
            2,619
            
            
            
            2,377Total
      Assets
            
            $
            10,211
            
            
            $
            9,784LIABILITIES
      AND STOCKHOLDER’S EQUITYCurrent
      Liabilities:Short-term
      borrowings
            
            $
            153
            
            
            $
            55Current
      portion of long-term debt
            
            
            7
            
            
            
            44Accounts
      payable
            
            
            722
            
            
            
            563Accounts
      and notes payable — affiliated companies
            
            
            33
            
            
            
            472Taxes
      accrued
            
            
            99
            
            
            
            67Interest
      accrued
            
            
            54
            
            
            
            52Customer
      deposits
            
            
            59
            
            
            
            70Non-trading
      derivative liabilities
            
            
            87
            
            
            
            51Other
            
            
            302
            
            
            
            282Total
      current liabilities
            
            
            1,516
            
            
            
            1,656Other
      Liabilities:Accumulated
      deferred income taxes, net
            
            
            864
            
            
            
            1,080Non-trading
      derivative liabilities
            
            
            47
            
            
            
            42Benefit
      obligations
            
            
            114
            
            
            
            113Regulatory
      liabilities
            
            
            508
            
            
            
            539Other
            
            
            101
            
            
            
            135Total
      other liabilities
            
            
            1,634
            
            
            
            1,909Long-Term
      Debt
            
            
            3,712
            
            
            
            2,742Commitments
      and Contingencies (Note 9)Stockholder’s
      Equity
            
            
            3,349
            
            
            
            3,477Total
      Liabilities And Stockholder’s Equity
            
            $
            10,211
            
            
            $
            9,784











See Notes
to Consolidated Financial Statements


42
 Table of Contents


CENTERPOINT ENERGY RESOURCES CORP. AND
SUBSIDIARIES


(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)





STATEMENTS
OF CONSOLIDATED CASH FLOWS





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009(In
      Millions)Cash
      Flows from Operating Activities:Net
      income
            
            $
            287
            
            
            $
            343
            
            
            $
            230Adjustments
      to reconcile net income to net cash provided by operating
      activities:
              Depreciation
      and amortization
            
            
            215
            
            
            
            218
            
            
            
            229Deferred
      income taxes
            
            
            64
            
            
            
            92
            
            
            
            247Amortization
      of deferred financing costs
            
            
            8
            
            
            
            9
            
            
            
            9Write-down
      of natural gas inventory
            
            
            11
            
            
            
            30
            
            
            
            6Equity
      in earnings of unconsolidated affiliates, net of
    distributions
            
            
            (13
            )
            
            
            (51
            )
            
            
            (3
            )Changes
      in other assets and liabilities:Accounts
      receivable and unbilled revenues, net
            
            
            14
            
            
            
            (66
            )
            
            
            238Accounts
      receivable/payable, affiliates
            
            
            (8
            )
            
            
            41
            
            
            
            3Inventory
            
            
            (105
            )
            
            
            (95
            )
            
            
            231Taxes
      receivable
            
            
            —
            
            
            
            —
            
            
            
            (47
            )Accounts
      payable
            
            
            (175
            )
            
            
            60
            
            
            
            (160
            )Fuel
      cost recovery
            
            
            (93
            )
            
            
            45
            
            
            
            (5
            )Interest
      and taxes accrued
            
            
            23
            
            
            
            (24
            )
            
            
            (34
            )Net
      non-trading derivative assets and liabilities
            
            
            13
            
            
            
            (19
            )
            
            
            29Margin
      deposits, net
            
            
            65
            
            
            
            (182
            )
            
            
            116Other
      current assets
            
            
            (27
            )
            
            
            (8
            )
            
            
            46Other
      current liabilities
            
            
            (16
            )
            
            
            17
            
            
            
            57Other
      assets
            
            
            (7
            )
            
            
            (3
            )
            
            
            1Other
      liabilities
            
            
            (12
            )
            
            
            (14
            )
            
            
            (14
            )Other,
      net
            
            
            (3
            )
            
            
            (33
            )
            
            
            —Net
      cash provided by operating activities
            
            
            241
            
            
            
            360
            
            
            
            1,179Cash
      Flows from Investing Activities:Capital
      expenditures
            
            
            (676
            )
            
            
            (532
            )
            
            
            (690
            )(Increase)
      decrease in notes receivable from unconsolidated
affiliates
            
            
            (148
            )
            
            
            (175
            )
            
            
            323Investment
      in unconsolidated affiliates
            
            
            (39
            )
            
            
            (206
            )
            
            
            (115
            )Other,
      net
            
            
            (10
            )
            
            
            34
            
            
            
            (3
            )Net
      cash used in investing activities
            
            
            (873
            )
            
            
            (879
            )
            
            
            (485
            )Cash
      Flows from Financing Activities:Increase
      (decrease) in short-term borrowings, net
            
            
            45
            
            
            
            (79
            )
            
            
            (98
            )Revolving
      credit facility, net
            
            
            150
            
            
            
            776
            
            
            
            (926
            )Payments
      of long-term debt
            
            
            (7
            )
            
            
            (307
            )
            
            
            (7
            )Proceeds
      from long-term debt
            
            
            650
            
            
            
            300
            
            
            
            —Increase
      (decrease) in notes with affiliates, net
            
            
            (107
            )
            
            
            (79
            )
            
            
            432Dividends
      to parent
            
            
            (100
            )
            
            
            (100
            )
            
            
            (100
            )Debt
      issuance costs
            
            
            (6
            )
            
            
            (2
            )
            
            
            —Other,
      net
            
            
            3
            
            
            
            10
            
            
            
            5Net
      cash provided by (used in) financing activities
            
            
            628
            
            
            
            519
            
            
            
            (694
            )Net
      Decrease in Cash and Cash Equivalents
            
            
            (4
            )
            
            
            —
            
            
            
            —Cash
      and Cash Equivalents at Beginning of the Year
            
            
            5
            
            
            
            1
            
            
            
            1Cash
      and Cash Equivalents at End of the Year
            
            $
            1
            
            
            $
            1
            
            
            $
            1Supplemental
      Disclosure of Cash Flow Information:Cash
      Payments:Interest,
      net of capitalized interest
            
            $
            167
            
            
            $
            210
            
            
            $
            203Income
      taxes (refunds)
            
            
            106
            
            
            
            145
            
            
            
            (31
            )Non-cash
      transactions:Accounts
      payable related to capital expenditures
            
            $
            51
            
            
            $
            52
            
            
            $
            53











See Notes
to Consolidated Financial Statements


43
 Table of Contents


CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES


(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)





STATEMENTS
OF CONSOLIDATED STOCKHOLDER’S EQUITY





2007
            
            
            2008
            
            
            2009Shares
            
            
            Amount
            
            
            Shares
            
            
            Amount
            
            
            Shares
            
            
            Amount(In
      millions, except share amounts)Common
      StockBalance,
      beginning of year
            
            
            1,000
            
            
            $
            —
            
            
            
            1,000
            
            
            $
            —
            
            
            
            1,000
            
            
            $
            —Balance,
      end of year
            
            
            1,000
            
            
            
            —
            
            
            
            1,000
            
            
            
            —
            
            
            
            1,000
            
            
            
            —Additional
      Paid-in-CapitalBalance,
      beginning of year
            
            
            
            
            
            
            2,403
            
            
            
            
            
            
            
            2,406
            
            
            
            
            
            
            
            2,416Other
            
            
            
            
            
            
            3
            
            
            
            
            
            
            
            10
            
            
            
            
            
            
            
            —Balance,
      end of year
            
            
            
            
            
            
            2,406
            
            
            
            
            
            
            
            2,416
            
            
            
            
            
            
            
            2,416Retained
      EarningsBalance,
      beginning of year
            
            
            
            
            
            
            505
            
            
            
            
            
            
            
            692
            
            
            
            
            
            
            
            935Net
      income
            
            
            
            
            
            
            287
            
            
            
            
            
            
            
            343
            
            
            
            
            
            
            
            230Dividend
      to parent
            
            
            
            
            
            
            (100
            )
            
            
            
            
            
            
            (100
            )
            
            
            
            
            
            
            (100
            )Balance,
      end of year
            
            
            
            
            
            
            692
            
            
            
            
            
            
            
            935
            
            
            
            
            
            
            
            1,065Accumulated
      Other Comprehensive Income (Loss)Balance,
      end of year:Net
      deferred gain from cash flow hedges
            
            
            
            
            
            
            5
            
            
            
            
            
            
            
            —
            
            
            
            
            
            
            
            —Adjustment
      to pension and postretirement plans
            
            
            
            
            
            
            11
            
            
            
            
            
            
            
            (2
            )
            
            
            
            
            
            
            (4
            )Total
      accumulated other comprehensive income (loss),end
      of year
            
            
            
            
            
            
            16
            
            
            
            
            
            
            
            (2
            )
            
            
            
            
            
            
            (4
            )Total
      Stockholder’s Equity
            
            
            
            
            
            $
            3,114
            
            
            
            
            
            
            $
            3,349
            
            
            
            
            
            
            $
            3,477











See Notes
to Consolidated Financial Statements


44
 Table of Contents





CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES


(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)





NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS





(1)
            Background





CenterPoint
Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC),
owns and operates natural gas distribution systems in six states. Subsidiaries
of CERC Corp. own interstate natural gas pipelines and gas gathering systems and
provide various ancillary services. A wholly owned subsidiary of CERC offers
variable and fixed-price physical natural gas supplies primarily to commercial
and industrial customers and electric and gas utilities. CERC Corp. is a
Delaware corporation.





CERC
Corp. is an indirect wholly owned subsidiary of CenterPoint Energy, Inc.
(CenterPoint Energy), a public utility holding company.





For a
description of CERC's reportable business segments, see Note 12.





(2)
            Summary
      of Significant Accounting Policies





(a)
      Use of Estimates





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 CERC's consolidated financial statements. All intercompany
transactions and balances are eliminated in consolidation. CERC uses the equity
method of accounting for investments in entities in which CERC has an ownership
interest between 20% and 50% and exercises significant influence. CERC’s
investments in unconsolidated affiliates include a 50% ownership interest in
Southeast Supply Header, LLC (SESH) which owns and operates a 270-mile
interstate natural gas pipeline and a 50% interest in Waskom Gas Processing
Company, a Texas general partnership, which owns and operates a natural gas
processing plant.  Other investments, excluding marketable securities,
are carried at cost.  During 2009, CERC invested $137 million in
SESH and received a capital distribution of $23 million from
SESH.





(c)
      Revenues





CERC
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
Interstate Pipelines and Field Services business segments record revenues as
transportation and processing services are provided.




45
 Table of Contents


(d)
      Long-Lived Assets and Intangibles





CERC
records property, plant and equipment at historical cost. CERC expenses repair
and maintenance costs as incurred. Property, plant and equipment includes the
following:




Weighted
                Average
      Useful
                Lives
              
              
              December 31,(Years)
              
              
              2008
              
              
              2009(In
      millions)Natural
      Gas Distribution
              
              
              31
              
              
              $
              3,266
              
              
              $
              3,436Competitive
      Natural Gas Sales and Services
              
              
              26
              
              
              
              67
              
              
              
              69Interstate
      Pipelines
              
              
              58
              
              
              
              2,334
              
              
              
              2,524Field
      Services
              
              
              51
              
              
              
              601
              
              
              
              931Other
      property
              
              
              13
              
              
              
              45
              
              
              
              27Total
              
              
              
              
              
              
              6,313
              
              
              
              6,987Accumulated
      depreciation and amortization:Natural
      Gas Distribution
              
              
              
              
              
              
              708
              
              
              
              825Competitive
      Natural Gas Sales and Services
              
              
              
              
              
              
              11
              
              
              
              13Interstate
      Pipelines
              
              
              
              
              
              
              182
              
              
              
              223Field
      Services
              
              
              
              
              
              
              28
              
              
              
              27Other
      property
              
              
              
              
              
              
              21
              
              
              
              24Total
      accumulated depreciation and amortization
              
              
              
              
              
              
              950
              
              
              
              1,112Property,
      plant and equipment, net
              
              
              
              
              
              $
              5,363
              
              
              $
              5,875




Goodwill
by reportable business segment as of December 31, 2008 and 2009 is as
follows (in millions):





Natural
      Gas Distribution
            
            $
            746Interstate
      Pipelines
            
            
            579Competitive
      Natural Gas Sales and Services
            
            
            335Field
      Services
            
            
            25Other
      Operations
            
            
            11Total
            
            $
            1,696





CERC
performs its goodwill impairment tests 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.





CERC
performed the test at July 1, 2009, its annual impairment testing date, and
determined that no impairment charge for goodwill was required.





CERC
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.




46
 Table of Contents





(e)
      Regulatory Assets and Liabilities





CERC
applies the guidance for accounting for regulated operations to the Natural Gas
Distribution business segment and to portions of the Interstate Pipelines
business segment.





The
following is a list of regulatory assets/liabilities reflected on CERC's
Consolidated Balance Sheets as of December 31, 2008 and 2009:





December 31,2008
            
            
            2009(In
      millions)Regulatory
      assets in other long-term assets (1)
            
            $
            53
            
            
            $
            61Regulatory
      liabilities
            
            
            (508
            )
            
            
            (539
            )Net
            
            $
            (455
            )
            
            $
            (478
            )







(1)
            Regulatory
      assets that are not earning a return were not material at December 31,
      2008 and 2009.




CERC’s
rate-regulated businesses recognize removal costs as a component of depreciation
expense in accordance with regulatory treatment. As of December 31, 2008
and 2009, these removal costs of $478 million and $510 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 has been reclassified from a regulatory
liability to an asset retirement liability in accordance with accounting
guidance for conditional asset retirement obligations. At December 31, 2008 and
2009, CERC’s asset retirement obligations were $46 million and
$60 million, respectively.  The increase in asset retirement
obligations in 2009 of $14 million is primarily attributable to the
decrease in the credit-adjusted risk-free rate used to value the asset
retirement obligations as of the end of the period.





(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 2007, 2008
and 2009:





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009(In
      millions)Depreciation
      expense
            
            $
            193
            
            
            $
            200
            
            
            $
            211Amortization
      expense
            
            
            22
            
            
            
            18
            
            
            
            18Total
      depreciation and amortization expense
            
            $
            215
            
            
            $
            218
            
            
            $
            229





(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 when the assets are included in rates for
subsidiaries that apply guidance for accounting for regulated operations.
Interest and AFUDC are capitalized as a component of projects under construction
and will be amortized over the assets’ estimated useful lives. During 2007, 2008
and 2009, CERC capitalized interest and AFUDC of $12 million,
$5 million and $2 million, respectively.





(h)
      Income Taxes





CERC is
included in the consolidated income tax returns of CenterPoint Energy. CERC
calculates its income tax provision on a separate return basis under a tax
sharing agreement with CenterPoint Energy. CERC uses the asset and liability
method of accounting for deferred income taxes in accordance with accounting
guidance for income taxes. Deferred income tax assets and liabilities are
recognized for the future tax consequences attributable to differences between
the financial statement carrying amounts of existing assets and liabilities and
their respective





47
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 tax
bases. A valuation allowance is established against deferred tax assets for
which management believes realization is not considered more likely than not.
Current federal and certain state income taxes are payable to or receivable from
CenterPoint Energy. CERC recognizes interest and penalties as a component of
income tax expense.  For more information, see Note 8 to our
consolidated financial statements.





(i)
      Accounts Receivable and Allowance for Doubtful
  Accounts





Accounts
receivable are net of an allowance for doubtful accounts of $33 million and
$23 million at December 31, 2008 and 2009, respectively. The provision
for doubtful accounts in CERC’s Statements of Consolidated Income for 2007, 2008
and 2009 was $42 million, $53 million and $35 million,
respectively.





On
October 9, 2009, CERC amended its receivables facility to extend the termination
date to October 8, 2010. Availability under CERC’s 364-day receivables facility
ranges from $150 million to $375 million, reflecting seasonal changes
in receivables balances. At December 31, 2008 and 2009, the facility size
was $128 million and $150 million, respectively. As of December 31,
2008 and 2009, advances under the receivables facilities were $78 million
and $-0-, respectively.





(j)
      Inventory





Inventory
consists principally of materials and supplies and natural gas. Materials and
supplies are valued at the lower of average cost or market. Natural gas
inventories of CERC’s Competitive Natural Gas Sales and Services business
segment are also primarily valued at the lower of average cost or market.
Natural gas inventories of CERC’s Natural Gas Distribution business segment are
primarily valued at weighted average cost.  During 2008 and 2009, CERC
recorded $30 million and $6 million, respectively, in write-downs of
natural gas inventory to the lower of average cost or market.





December 31,2008
            
            
            2009(In
      millions)Materials
      and supplies
            
            $
            54
            
            
            $
            69Natural
      gas
            
            
            441
            
            
            
            189Total
      inventory
            
            $
            495
            
            
            $
            258





(k)
      Derivative Instruments





CERC is
exposed to various market risks. These risks arise from transactions entered
into in the normal course of business.  CERC utilizes derivative
instruments such as physical forward contracts, swaps and options to mitigate
the impact of changes in commodity prices and weather on its operating results
and cash flows. Such derivatives are recognized in CERC's Consolidated Balance
Sheets at their fair value unless CERC elects the normal purchase and sales
exemption for qualified physical transactions. A derivative may be designated as
a normal purchase or normal sale if the intent is to physically receive or
deliver the product for use or sale in the normal course of
business.





CenterPoint
Energy has a Risk Oversight Committee composed of corporate and business segment
officers that oversees all commodity price, weather and credit risk activities,
including CERC's marketing, risk management services and hedging activities. The
committee’s duties are to establish CERC's commodity risk policies, allocate
board-approved commercial risk limits, approve use of new products and
commodities, monitor positions and ensure compliance with CERC's risk management
policies and procedures and limits established by CenterPoint Energy’s board of
directors.





CERC'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.





(l)
      Environmental Costs





CERC
expenses or capitalizes environmental expenditures, as appropriate, depending on
their future economic benefit. CERC expenses amounts that relate to an existing
condition caused by past operations that do not have





48
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 future
economic benefit. CERC records undiscounted liabilities related to these future
costs when environmental assessments and/or remediation activities are probable
and the costs can be reasonably estimated.





(m)
      Statements of Consolidated Cash
Flows





For
purposes of reporting cash flows, CERC 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





Effective
January 1, 2009, CERC adopted new accounting guidance which requires enhanced
disclosures of derivative instruments and hedging activities such as the fair
value of derivative instruments and presentation of their gains or losses in
tabular format, as well as disclosures regarding credit risks and strategies and
objectives for using derivative instruments.  These disclosures are
included as part of CERC's Derivatives Instruments footnote (see Note
5).





Effective
January 1, 2009, CERC adopted new accounting guidance on employers’ disclosures
about postretirement benefit plan assets which expands the disclosures about
employers’ plan assets to include more detailed disclosures about the employers’
investment strategies, major categories of plan assets, concentrations of risk
within plan assets and valuation techniques used to measure the fair value of
plan assets. See Note 2(o) below for the required disclosures.





Effective
June 30, 2009, CERC adopted new accounting guidance on interim disclosures about
fair value of financial instruments which expands the fair value disclosures
required for all financial instruments to interim periods. This new guidance
also requires entities to disclose in interim periods the methods and
significant assumptions used to estimate the fair value of financial
instruments. CERC's adoption of this new guidance did not have a material impact
on its financial position, results of operations or cash flows.





Effective
June 30, 2009, CERC adopted new accounting guidance on subsequent events that
establishes general standards of accounting for and disclosure of events that
occur after the balance sheet date but before financial statements are issued or
are available to be issued. CERC’s adoption of this new guidance did not have a
material impact on its financial position, results of operations or cash
flows.





Effective
July 1, 2009, CERC adopted new accounting guidance on the Financial Accounting
Standards Board (FASB) Accounting Standards Codification (Codification) and the
hierarchy of generally accepted accounting principles.  This new
accounting guidance establishes the Codification as the source of authoritative
U.S. generally accepted accounting principles recognized by the FASB to be
applied by nongovernmental entities.  Rules and interpretive releases
of the Securities and Exchange Commission (SEC) under authority of federal
securities laws are also sources of authoritative U.S. generally accepted
accounting principles for SEC registrants. CERC’s adoption of this new
guidance did not have any impact on its financial position, results of
operations or cash flows.





In June
2009, the FASB issued new accounting guidance on consolidation of variable
interest entities (VIEs) that changes how a reporting entity determines a
primary beneficiary that would consolidate the VIE from a quantitative risk and
rewards approach to a qualitative approach based on which variable interest
holder has the power to direct the economic performance related activities of
the VIE as well as the obligation to absorb losses or right to receive benefits
that could potentially be significant to the VIE. This new guidance requires the
primary beneficiary assessment to be performed on an ongoing basis and also
requires enhanced disclosures that will provide more transparency about a
company’s involvement in a VIE. This new guidance is effective for a reporting
entity’s first annual reporting period that begins after November 15,
2009. CERC expects that the adoption of this new guidance will not have a
material impact on its financial position, results of operations or cash
flows.





In
January 2010, the FASB issued new accounting guidance to require additional fair
value related disclosures including transfers into and out of Levels 1 and 2 and
separate disclosures about purchases, sales, issuances, and settlements relating
to Level 3 measurements. It also clarifies existing fair value disclosure
guidance about the level of disaggregation and about inputs and valuation
techniques. This new guidance is effective for the first reporting period
beginning after December 15, 2009. The adoption of this new guidance will not
have a material impact on CERC’s financial position, results of operation or
cash flows.


49
 Table of Contents





Management
believes the impact of other recently issued standards, which are not yet
effective, will not have a material impact on CERC's consolidated financial
position, results of operations or cash flows upon adoption.





(o)
      Employee Benefit Plans





Pension
Plans





Substantially
all of CERC’s employees participate in CenterPoint Energy’s qualified
non-contributory defined benefit pension plan. Under the cash balance formula,
participants accumulate a retirement benefit based upon 5% of eligible earnings,
which increased from 4% effective January 1, 2009, and accrued interest. Prior
to 1999, the pension plan accrued benefits based on years of service, final
average pay and covered compensation. Certain employees participating in the
plan as of December 31, 1998 automatically receive the greater of the
accrued benefit calculated under the prior plan formula through 2008 or the cash
balance formula.





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 CERC 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. CERC recognized pension expense
of $5 million, income of $3 million and expense of $45 million
for the years ended December 31, 2007, 2008 and 2009, respectively.





In
addition to the plan, CERC participates in CenterPoint Energy’s non-qualified
benefit restoration plans, which allow participants to receive the benefits to
which they would have been entitled under CenterPoint Energy’s non-contributory
pension plan except for federally mandated limits on qualified plan benefits or
on the level of compensation on which qualified plan benefits may be calculated.
The expense associated with the non-qualified pension plan was less than
$1 million, less than $1 million and $2 million for the years
ended December 31, 2007, 2008 and 2009, respectively.





Savings
Plan





CERC
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 50%, which increased from 16% in prior years, of compensation.
Effective January 1, 2009, CERC matches 100% of the first 6% of each employee’s
compensation contributed. CERC previously matched 75% of the first 6% of each
employee’s compensation contributed with the potential for an additional
discretionary match of up to 50% of the first 6% of each employee’s compensation
contributed. The matching contributions are fully vested at all times.
CenterPoint Energy allocates to CERC the savings plan benefit expense related to
CERC’s employees.  Savings plan benefit expense was $17 million,
$18 million and $15 million for each of the years ended December 31,
2007, 2008, and 2009, respectively.





Postretirement
Benefits





CERC’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. CERC 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.




50
 Table of Contents





The net
postretirement benefit cost includes the following components:





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009(In
      millions)Service
      cost — benefits earned during the period
            
            $
            1
            
            
            $
            1
            
            
            $
            1Interest
      cost on projected benefit obligation
            
            
            7
            
            
            
            7
            
            
            
            8Expected
      return on plan assets
            
            
            (1
            )
            
            
            (1
            )
            
            
            (1
            )Amortization
      of prior service cost
            
            
            2
            
            
            
            2
            
            
            
            2Net
      postretirement benefit cost
            
            $
            9
            
            
            $
            9
            
            
            $
            10





CERC used
the following assumptions to determine net postretirement benefit
costs:





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009Discount
      rate
            
            
            5.85
            %
            
            
            6.40
            %
            
            
            6.90
            %Expected
      return on plan assets
            
            
            4.50
            %
            
            
            4.50
            %
            
            
            4.50
            %





In
determining net periodic benefits cost, CERC uses fair value, as of the
beginning of the year, as its basis for determining expected return on plan
assets.





Following
are reconciliations of CERC’s beginning and ending balances of its
postretirement benefit plan’s benefit obligation, plan assets and funded status
for 2008 and 2009. The measurement dates for plan assets and obligations were
December 31, 2008 and 2009.




Year
      Ended December 31,2008
              
              
              2009(In
      millions)Change
      in Benefit ObligationAccumulated
      benefit obligation, beginning of year
              
              $
              119
              
              
              $
              120Service
      cost
              
              
              1
              
              
              
              1Interest
      cost
              
              
              7
              
              
              
              8Benefits
      paid
              
              
              (19
              )
              
              
              (22
              )Medicare
      reimbursement
              
              
              1
              
              
              
              —Participant
      contributions
              
              
              4
              
              
              
              5Actuarial
      loss
              
              
              7
              
              
              
              9Accumulated
      benefit obligation, end of year
              
              $
              120
              
              
              $
              121Change
      in Plan AssetsPlan
      assets, beginning of year
              
              $
              20
              
              
              $
              20Benefits
      paid
              
              
              (19
              )
              
              
              (22
              )Employer
      contributions
              
              
              14
              
              
              
              16Participant
      contributions
              
              
              4
              
              
              
              5Medicare
      reimbursement received
              
              
              1
              
              
              
              —Actual
      investment return
              
              
              —
              
              
              
              2Plan
      assets, end of year
              
              $
              20
              
              
              $
              21Amounts
      Recognized in Balance SheetsCurrent
      liabilities-other
              
              $
              (8
              )
              
              $
              (8
              )Other
      liabilities-benefit obligations
              
              
              (92
              )
              
              
              (92
              )Net
      liability, end of year
              
              $
              (100
              )
              
              $
              (100
              )Actuarial
      AssumptionsDiscount
      rate
              
              
              6.90
              %
              
              
              5.70
              %Expected
      long-term return on assets
              
              
              4.50
              %
              
              
              4.50
              %Healthcare
      cost trend rate assumed for the next year
              
              
              6.50
              %
              
              
              7.50
              %Prescription
      cost trend rate assumed for the next year
              
              
              12.00
              %
              
              
              8.00
              %Rate
      to which the cost trend rate is assumed to decline (ultimate trend
      rate)
              
              
              5.50
              %
              
              
              5.50
              %Year
      that the healthcare rate reaches the ultimate trend rate
              
              
              2011
              
              
              
              2014Year
      that the prescription drug rate reaches the ultimate trend
      rate
              
              
              2014
              
              
              
              2015




51
 Table of Contents





The
discount rate assumption was determined by matching the accrued cash flows of
CenterPoint Energy’s plans against a hypothetical yield curve of high-quality
corporate bonds represented by a series of annualized individual discount rates
from one-half to thirty years.





The
expected rate of return assumption was developed by a weighted-average return
analysis of the targeted asset allocation of the CenterPoint Energy’s plans and
the expected real return for each asset class, based on the long-term capital
market assumptions, adjusted for investment fees and diversification effects, in
addition to expected inflation.





For
measurement purposes, healthcare costs are assumed to increase 7.50% during
2010, after which this rate decreases until reaching the ultimate rate of 5.50%
in 2014. Prescription drug costs are assumed to increase 8.00% in 2010, after
which this rate decreases until reaching the ultimate rate of 5.50% in
2015.





Amounts
recognized in accumulated other comprehensive loss consist of the
following:





Year
      Ended December 31,2008
            
            
            2009(In
      millions)Unrecognized
      actuarial loss
            
            $
            14
            
            
            $
            21Unrecognized
      prior service cost
            
            
            10
            
            
            
            824
            
            
            
            29Less
      deferred tax benefit (1)
            
            
            (21
            )
            
            
            (25
            )Net
      amount recognized in accumulated other comprehensive loss
            
            $
            3
            
            
            $
            4







(1)
            CERC’s
      postretirement benefit obligation is reduced by the impact of non-taxable
      government subsidies under the Medicare Prescription Drug
      Act.  Because the subsidies are non-taxable, the temporary
      difference used in measuring the deferred tax impact is determined on the
      unrecognized losses excluding such subsidies.  Accordingly, the
      unrecognized losses used for determining deferred taxes were
      $54 million and $60 million as of December 31, 2008 and
      2009, respectively.





The
changes in plan assets and benefit obligations recognized in other comprehensive
income during 2009 are as follows:





Postretirement
              Benefits(In
      millions)Net
      loss
            
            $
            7Amortization
      of prior service cost
            
            
            (2
            )Total
      recognized in other comprehensive income
            
            $
            5





The total
expense recognized in net periodic costs and other comprehensive income was
$15 million for postretirement benefits for the year ended
December 31, 2009.





The
amounts in accumulated other comprehensive income expected to be recognized as
components of net periodic benefit cost during 2010 are as follows:





Postretirement
              Benefits(In
      millions)Unrecognized
      prior service cost
            
            $
            2Amounts
      in other comprehensive income to be recognized as net periodic cost in
      2010
            
            $
            2





Assumed
healthcare cost trend rates have a significant effect on the reported amounts
for CERC’s postretirement benefit plans. A 1% change in the assumed healthcare
cost trend rate would have the following effects:





1%
              Increase
            
            
            1%
              Decrease(In
      millions)Effect
      on the postretirement benefit obligation
            
            $
            4
            
            
            $
            4Effect
      on the total of service and interest cost
            
            
            —
            
            
            
            —





52
 Table of Contents





In
managing the investments associated with the postretirement benefit plan, CERC’s
objective is to preserve and enhance the value of plan assets while maintaining
an acceptable level of volatility. These objectives are expected to be achieved
through an investment strategy that manages liquidity requirements while
maintaining a long-term horizon in making investment decisions and efficient and
effective management of plan assets.





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





Domestic
      equity securities
            
            
            0-10
            %Debt
      securities
            
            
            90-100
            %Cash
            
            
            0-2
            %





The fair
values of CERC’s postretirement plan assets at December 31, 2009, by asset
category are as follows:





Fair
      Value Measurements at
              December
      31, 2009
              (in
      millions)Total
            
            
            Quoted
      Prices in
              Active
      Markets for
              Identical
      Assets
              (Level
      1)
            
            
            Significant
              Observable
              Inputs
              (Level
      2)
            
            
            Significant
              Unobservable
              Inputs
              (Level
      3)Mutual
      funds (1)
            
            $
            21
            
            
            $
            21
            
            
            $
            —
            
            
            $
            —Total
            
            $
            21
            
            
            $
            21
            
            
            $
            —
            
            
            $
            —







(1)
            95%
      of the amount invested in mutual funds was in fixed income securities and
      5% was in U.S equities.





CERC
expects to contribute $9 million to its postretirement benefits plan in
2010. The following benefit payments are expected to be paid by the
postretirement benefit plan:





Postretirement
      Benefit PlanBenefit
              Payments
            
            
            Medicare
              Subsidy
              Receipts(in
      millions)2010
            
            $
            12
            
            
            $
            (2
            )2011
            
            
            13
            
            
            
            (2
            )2012
            
            
            13
            
            
            
            (3
            )2013
            
            
            13
            
            
            
            (3
            )2014
            
            
            14
            
            
            
            (3
            )2015-2019
            
            
            71
            
            
            
            (19
            )





Postemployment
      Benefits





CERC
participates in CenterPoint Energy’s plan that 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). CERC recorded
postemployment benefit income of $2 million, expense of $1 million,
and $-0- for the years ended December 31, 2007, 2008 and 2009, respectively.
Amounts relating to postemployment benefits included in “Benefit Obligations” in
the accompanying Consolidated Balance Sheets at December 31, 2008 and 2009,
were $16 million and $14 million, respectively.





Other
Non-Qualified Plans





CERC
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 CERC. During
2007, 2008 and 2009, the benefit expense relating to these programs was less
than $1 million each year. Amounts relating to deferred compensation plans
included in “Benefit Obligations” in the accompanying Consolidated Balance
Sheets at December 31, 2008 and 2009 were $1 million and
$2 million, respectively.


53
 Table of Contents





Other
Employee Matters





As of
December 31, 2009, approximately 30% of CERC’s employees are subject to
collective bargaining agreements.





(p)
      Other Current Assets and
Liabilities





Included
in other current assets on the Consolidated Balance Sheets at December 31,
2008 and 2009 was $42 million and $19 million, respectively, of margin
deposits and $128 million and $80 million, respectively of under
recovered gas cost. Included in other current liabilities on the Consolidated
Balance Sheets at December 31, 2008 and 2009 was $79 million and
$70 million, respectively, of over recovered gas cost.





(3)
            Regulatory
      Matters





(a)
      Hurricane Ike





CERC’s
natural gas distribution business (Gas Operations) suffered some damage to its
system in Houston, Texas and in other portions of its service territory across
Texas and Louisiana as a result of Hurricane Ike, which struck the upper Texas
coast in September 2008. As of December 31, 2009, Gas Operations has
deferred approximately $3 million of costs related to Hurricane Ike for
recovery as part of natural gas distribution rate proceedings.





(b)
      Rate Proceedings





Texas. In March 2008, Gas
Operations filed a request to change its rates with the Railroad Commission of
Texas (Railroad Commission) and the 47 cities in its Texas Coast service
territory, an area consisting of approximately 230,000 customers in cities and
communities on the outskirts of Houston. In 2008, Gas Operations implemented
rates increasing annual revenues by approximately $3.5 million.  The
implemented rates were contested by 9 cities in an appeal to the 353rd District
Court in Travis County, Texas. In January 2010, that court reversed the Railroad
Commission’s order in part and remanded the matter to the Railroad
Commission.  The court concluded that the Railroad Commission did not have
statutory authority to impose on the complaining cities the cost of service
adjustment mechanism which the Railroad Commission had approved in its
order.  Certain parties filed a motion to modify the district court’s
judgment and a final decision is not expected until April 2010.  CERC does
not expect the outcome of this matter to have a material adverse impact on its
financial condition, results of operations or cash flows.





In July
2009, Gas Operations filed a request to change its rates with the Railroad
Commission and the 29 cities in its Houston service territory, consisting of
approximately 940,000 customers in and around Houston. The request seeks to
establish uniform rates, charges and terms and conditions of service for the
cities and environs of the Houston service territory. As finally submitted to
the Railroad Commission and the cities, the proposed new rates would result in
an overall increase in annual revenue of $20.4 million, excluding carrying
costs on gas inventory of approximately $2 million. In January 2010, Gas
Operations withdrew its request for an annual cost of service adjustment
mechanism due to the uncertainty caused by the court’s ruling in the
above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission
issued its decision authorizing a revenue increase of $5.1 million
annually, reflecting reduced depreciation rates of $1.2 million. The
Railroad Commission also approved a surcharge of $0.9 million per year to
recover Hurricane Ike costs over three years.





Minnesota. In November 2006,
the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas
Operations for a waiver of MPUC rules in order to allow Gas Operations to
recover approximately $21 million in unrecovered purchased gas costs
related to periods prior to July 1, 2004. Those unrecovered gas costs were
identified as a result of revisions to previously approved calculations of
unrecovered purchased gas costs. Following that denial, Gas Operations recorded
a $21 million adjustment to reduce pre-tax earnings in the fourth quarter
of 2006 and reduced the regulatory asset related to these costs by an equal
amount. In March 2007, following the MPUC’s denial of reconsideration of its
ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of
the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been
arbitrary and capricious in denying Gas Operations a waiver. The MPUC sought
further review of the court of appeals decision from the Minnesota Supreme
Court.  In July 2009, the Minnesota Supreme Court reversed the
decision of the Minnesota Court of Appeals and upheld the MPUC’s decision to
deny the requested variance. The court’s decision had no





54
 Table of Contents
 
 negative
impact on CERC’s financial condition, results of operations or cash flows, as
the costs at issue were written off at the time they were
disallowed.





In
November 2008, Gas Operations filed a request with the MPUC to increase its
rates for utility distribution service by $59.8 million annually.  In
addition, Gas Operations sought an adjustment mechanism that would annually
adjust rates to reflect changes in use per customer.  In December 2008, the
MPUC accepted the case and approved an interim rate increase of
$51.2 million, which became effective on January 2, 2009, subject to
refund. In January 2010, the MPUC issued its decision authorizing a revenue
increase of $41 million per year, with an overall rate of return of 8.09%
(10.24% return on equity).  The difference between the rates approved
by the MPUC and amounts collected under the interim rates, $10 million as
of December 31, 2009, is recorded in other current liabilities and will be
refunded to customers. The MPUC also authorized Gas Operations to implement a
pilot program for residential and small volume commercial customers that is
intended to decouple gas revenues from customers’ natural gas usage. In February
2010, CERC filed a request for rehearing of the order by the MPUC.  No
other party to the case filed such a request.  CERC does not expect a
final order to be issued in this proceeding until spring 2010.





Mississippi.  In
July 2009, Gas Operations filed a request to increase its rates for utility
distribution service with the Mississippi Public Service Commission (MPSC). In
November 2009, as part of a settlement agreement in which the MPSC approved Gas
Operations’ retention of the compensation paid under the terms of an asset
management agreement, Gas Operations withdrew its rate request.





(c)
Regulatory Accounting





CERC has
a 50% ownership interest in SESH which owns and operates a 270-mile interstate
natural gas pipeline.  In 2009, SESH discontinued the use of guidance
for accounting for regulated operations, which resulted in CERC recording its
share of the effects of such write-offs of SESH’s regulatory assets through
non-cash pre-tax charges for the year ended December 31, 2009 of
$16 million.  These non-cash charges are reflected in equity in
earnings of unconsolidated affiliates in the Statements of Consolidated
Income.  The related tax benefits of $6 million are reflected in
the Income Tax Expense line in the Statements of Consolidated
Income.





(4)
            Related
      Party Transactions





CERC
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 CenterPoint Energy’s commercial paper.
CERC had money pool borrowings of $-0-  and $432 million at
December 31, 2008 and 2009, respectively, which are included in accounts
and notes payable—affiliated companies in the Consolidated Balance
Sheets.  At December 31, 2009, CERC’s money pool borrowings had a
weighted-average interest rate of 0.18%.





CERC had
net interest expense related to affiliate borrowings of $3 million, $1
million and less than $1 million for the years ended December 31, 2007,
2008 and 2009, respectively.





CenterPoint
Energy provides some corporate services to CERC. The costs of services have been
charged directly to CERC using methods that management believes are reasonable.
These methods include negotiated usage rates, dedicated asset assignment and
proportionate corporate formulas based on operating expenses, assets, gross
margin, employees and a composite of assets, gross margin and employees. These
charges are not necessarily indicative of what would have been incurred had CERC
not been an affiliate. Amounts charged to CERC for these services were
$133 million, $140 million and $154 million for 2007, 2008 and
2009, respectively, and are included primarily in operation and maintenance
expenses.





In each
of 2007, 2008 and 2009, CERC paid dividends of $100 million to its
parent.




55
 Table of Contents





(5)
            Derivative
      Instruments





CERC is
exposed to various market risks. These risks arise from transactions entered
into in the normal course of business. CERC utilizes derivative instruments such
as physical forward contracts, swaps and options to mitigate the impact of
changes in commodity prices, weather and interest rates on its operating results
and cash flows.





(a)
      Non-Trading Activities





Derivative Instruments. CERC
enters into certain derivative instruments to manage physical commodity price
risks and does not engage in proprietary or speculative commodity
trading.  These financial instruments do not qualify or are not
designated as cash flow or fair value hedges.





During
the year ended December 31, 2007, CERC  recorded increased
natural gas expense from unrealized net losses of
$10 million.  During the year ended December 31, 2008, CERC
recorded increased natural gas revenues from unrealized net gains of
$101 million and increased natural gas expense from unrealized net losses
of $88 million, a net unrealized gain of
$13 million.  During the year ended December 31, 2009, CERC
recorded decreased revenues from unrealized net losses of $80 million and
decreased natural gas expense from unrealized net gains of $57 million, a
net unrealized loss of $23 million.





In prior
years, CERC entered into certain derivative instruments that were designated as
cash flow hedges. The objective of these derivative instruments was to hedge the
price risk associated with natural gas purchases and sales to reduce cash flow
variability related to meeting CERC's wholesale and retail customer
obligations.  In 2007, CERC discontinued designating these instruments as
cash flow hedges.  As of December 31, 2009, there are no remaining
amounts deferred in other comprehensive income related to these instruments that
had previously been designated as cash flow hedges.





Weather Hedges. CERC has
weather normalization or other rate mechanisms that mitigate the impact of
weather on its gas operations in Arkansas, Louisiana, Oklahoma and a portion of
Texas. The remaining Gas Operations jurisdictions do not have such mechanisms.
As a result, fluctuations from normal weather may have a significant positive or
negative effect on the results of the gas operations in the remaining
jurisdictions.





In 2007,
2008 and 2009, CERC entered into heating-degree day swaps to mitigate the effect
of fluctuations from normal weather on its financial position and cash flows for
the respective winter heating seasons.  The swaps were based on
ten-year normal weather. During the years ended December 31, 2007, 2008 and
2009, CERC recognized losses of $-0-, $17 million and $6 million,
respectively, related to these swaps.  The losses were substantially
offset by increased revenues due to colder than normal weather. Weather hedge
losses are included in revenues in the Statements of Consolidated
Income.





(b)
Derivative Fair Values and Income Statement Impacts





The
following tables present information about CERC’s derivative instruments and
hedging activities.  The first table provides a balance sheet overview
of CERC’s Non-trading Derivative Assets and Liabilities as of December 31,
2009, while the latter table provides a breakdown of the related income
statement impact for the year ended December 31, 2009.





Fair
      Value of Derivative InstrumentsDecember 31,
      2009Total
      derivatives not designated as hedging
              instruments
            
            Balance
      Sheet
              Location
            
            Derivative
              Assets
              Fair
      Value (2) (3)
            
            
            Derivative
              Liabilities
              Fair
      Value (2) (3)(in
      millions)Commodity
      contracts (1)
            
            Current
      Assets
            
            $
            46
            
            
            $
            (7
            )Commodity
      contracts(1)
            
            Other
      Assets
            
            
            16
            
            
            
            (1
            )Commodity
      contracts (1)
            
            Current
      Liabilities
            
            
            20
            
            
            
            (123
            )Commodity
      contracts (1)
            
            Other
      Liabilities
            
            
            1
            
            
            
            (86
            )Total
            
            $
            83
            
            
            $
            (217
            )









56
 Table of Contents




(1)
            Commodity
      contracts are subject to master netting arrangements and are presented on
      a net basis in the Consolidated Balance Sheets. This netting causes
      derivative assets (liabilities) to be ultimately presented net in a
      liability (asset) account within the Consolidated Balance
      Sheets.





(2)
            The
      fair value shown for commodity contracts is comprised of derivative gross
      volumes totaling 674 billion cubic feet (Bcf) or a net 152 Bcf long
      position.   Of the net long position, basis swaps constitute 71
      Bcf and volumes associated with price stabilization activities of the
      Natural Gas Distribution business segment comprise 51
  Bcf.





(3)
            The
      net of total non-trading derivative assets and liabilities is a
      $39 million liability as shown on CERC’s Consolidated Balance Sheets,
      and is comprised of the commodity contracts derivative assets and
      liabilities separately shown above offset by collateral netting of
      $95 million.





For
CERC’s price stabilization activities of the Natural Gas Distribution business
segment, the settled costs of derivatives are ultimately recovered through
purchased gas adjustments. Accordingly, the net unrealized gains and losses
associated with interim price movements on contracts that are accounted for as
derivatives and probable of recovery through purchased gas adjustments are
recorded as net regulatory assets. For those derivatives that are not included
in purchased gas adjustments, unrealized gains and losses and settled amounts
are recognized on the Statements of Consolidated Income as revenue for retail
sales derivative contracts and as natural gas expense for natural gas
derivatives and non-retail related physical gas derivatives.





Income
      Statement Impact of Derivative ActivityTotal
      derivatives not designated as hedging
              instruments
            
            Income
      Statement Location
            
            Year
              Ended
              December 31,
      2009(in
      millions)Commodity
      contracts
            
            Gains
      (Losses) in Revenue
            
            $
            102Commodity
      contracts (1)
            
            Gains
      (Losses) in Expense: Natural Gas
            
            
            (255
            )Total
            
            $
            (153
            )







(1)
            The
      Gains (Losses) in Expense: Natural Gas includes $(181) million of
      costs associated with price stabilization activities of the Natural Gas
      Distribution business segment that will be ultimately recovered through
      purchased gas adjustments.





(c)
Credit Risk Contingent Features





CERC
enters into financial derivative contracts containing material adverse change
provisions.  These provisions require CERC to post additional
collateral if the Standard & Poor’s Rating Services or Moody’s Investors
Service, Inc. credit rating of CERC is downgraded.  The total fair
value of the derivative instruments that contain credit risk contingent features
that are in a net liability position at December 31, 2009 is
$140 million.  The aggregate fair value of assets that are
already posted as collateral at December 31, 2009 is
$65 million.  If all derivative contracts (in a net liability
position) containing credit risk contingent features were triggered at
December 31, 2009, $75 million of additional assets would be required
to be posted as collateral.





(d)
Credit Quality of Counterparties





In
addition to the risk associated with price movements, credit risk is also
inherent in CERC’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 counterparties to the
non-trading derivative assets of CERC as of December 31, 2008 and 2009 (in
millions):





December 31,
      2008
            
            
            December 31,
      2009Investment
              Grade(1)
            
            
            Total
            
            
            Investment
              Grade(1)
            
            
            TotalEnergy
      marketers
            
            $
            8
            
            
            $
            9
            
            
            $
            6
            
            
            $
            6Financial
      institutions
            
            
            4
            
            
            
            4
            
            
            
            2
            
            
            
            4Retail
      end users (2)
            
            
            5
            
            
            
            125
            
            
            
            1
            
            
            
            44Total
            
            $
            17
            
            
            $
            138
            
            
            $
            9
            
            
            $
            54







57
 Table of Contents




(1)
            “Investment
      grade” is primarily determined using publicly available credit ratings
      along with the consideration of credit support (such as parent company
      guaranties) and collateral, which encompass cash and standby letters of
      credit. For unrated counterparties, CERC performs financial statement
      analysis, considering contractual rights and restrictions and collateral,
      to create a synthetic credit
rating.





(2)
            Retail
      end users represent commercial and industrial customers who have
      contracted to fix the price of a portion of their physical gas
      requirements for future periods.





(6)
            Fair
      Value Measurements





Effective
January 1, 2008, CERC adopted new accounting guidance on fair value
measurements which requires additional disclosures about CERC’s financial assets
and liabilities that are measured at fair value. Effective January 1,
2009, CERC adopted this new guidance for nonfinancial assets and liabilities,
which adoption had no impact on CERC’s financial position, results of operations
or cash flows.  Beginning in January 2008, assets and liabilities
recorded at fair value in the Consolidated Balance Sheets are categorized based
upon the level of judgment associated with the inputs used to measure their
value. Hierarchical levels, as defined in this guidance and directly related to
the amount of subjectivity associated with the inputs to fair valuations of
these assets and liabilities, are as follows:





Level 1:
Inputs are unadjusted quoted prices in active markets for identical assets or
liabilities at the measurement date. The types of assets carried at Level 1
fair value generally are financial derivatives, investments and equity
securities listed in active markets.





Level 2:
Inputs, other than quoted prices included in Level 1, are observable for the
asset or liability, either directly or indirectly. Level 2 inputs include quoted
prices for similar instruments in active markets, and inputs other than quoted
prices that are observable for the asset or liability. Fair value assets
and liabilities that are generally included in this category are derivatives
with fair values based on inputs from actively quoted markets.





Level 3:
Inputs are unobservable for the asset or liability, and include situations where
there is little, if any, market activity for the asset or liability. In certain
cases, the inputs used to measure fair value may fall into different levels of
the fair value hierarchy. In such cases, the level in the fair value hierarchy
within which the fair value measurement in its entirety falls has been
determined based on the lowest level input that is significant to the fair value
measurement in its entirety. Unobservable inputs reflect CERC’s judgments about
the assumptions market participants would use in pricing the asset or liability
since limited market data exists. CERC develops these inputs based on the best
information available, including CERC’s own data.  CERC’s Level 3
derivative instruments primarily consist of options that are not traded on
recognized exchanges and are valued using option pricing models.





The
following tables present information about CERC’s assets and liabilities
(including derivatives that are presented net) measured at fair value on a
recurring basis as of December 31, 2008 and 2009, and indicate the fair
value hierarchy of the valuation techniques utilized by CERC to determine such
fair value.





Quoted
      Prices in
              Active
      Markets
              for Identical
      Assets
              (Level
      1)
            
            
            Significant
      Other
              Observable
              Inputs
              (Level
      2)
            
            
            Significant
              Unobservable
              Inputs
              (Level
      3)
            
            
            Netting
              Adjustments
      (1)
            
            
            Balance
              as
      of
              December
      31,
              2008(in
      millions)AssetsCorporate
      equities
            
            $
            1
            
            
            $
            —
            
            
            $
            —
            
            
            $
            —
            
            
            $
            1Investments,
      including money
              market
      funds
            
            
            11
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            11Derivative
      assets
            
            
            8
            
            
            
            155
            
            
            
            49
            
            
            
            (74
            )
            
            
            138Total
      assets
            
            $
            20
            
            
            $
            155
            
            
            $
            49
            
            
            $
            (74
            )
            
            $
            150LiabilitiesDerivative
      liabilities
            
            $
            44
            
            
            $
            244
            
            
            $
            107
            
            
            $
            (261
            )
            
            $
            134Total
      liabilities
            
            $
            44
            
            
            $
            244
            
            
            $
            107
            
            
            $
            (261
            )
            
            $
            134






58
 Table of Contents





(1)
            Amounts
      represent the impact of legally enforceable master netting agreements that
      allow CERC to settle positive and negative positions and also include cash
      collateral of $187 million posted with the same
      counterparties.





Quoted
      Prices in
              Active
      Markets
              for Identical
      Assets
              (Level
      1)
            
            
            Significant
      Other
              Observable
              Inputs
              (Level
      2)
            
            
            Significant
              Unobservable
              Inputs
              (Level
      3)
            
            
            Netting
              Adjustments
      (1)
            
            
            Balance
              as
      of
              December 31,
              2009(in
      millions)AssetsCorporate
      equities
            
            $
            1
            
            
            $
            —
            
            
            $
            —
            
            
            $
            —
            
            
            $
            1Investments,
      including money
              market
      funds
            
            
            11
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            11Derivative
      assets
            
            
            1
            
            
            
            77
            
            
            
            5
            
            
            
            (29
            )
            
            
            54Total
      assets
            
            $
            13
            
            
            $
            77
            
            
            $
            5
            
            
            $
            (29
            )
            
            $
            66LiabilitiesDerivative
      liabilities
            
            $
            12
            
            
            $
            194
            
            
            $
            11
            
            
            $
            (124
            )
            
            $
            93Total
      liabilities
            
            $
            12
            
            
            $
            194
            
            
            $
            11
            
            
            $
            (124
            )
            
            $
            93







(1)
            Amounts
      represent the impact of legally enforceable master netting agreements that
      allow CERC to settle positive and negative positions and also include cash
      collateral of $95 million posted with the same
      counterparties.





The
following tables present additional information about assets or liabilities,
including derivatives that are measured at fair value on a recurring basis for
which CERC has utilized Level 3 inputs to determine fair value:





Fair
      Value Measurements Using Significant
              Unobservable
      Inputs (Level 3)Derivative
      assets and liabilities, netYear
      Ended December 31,2008
            
            
            2009(in
      millions)Beginning
      balance
            
            $
            (3
            )
            
            $
            (58
            )Total
      unrealized gains or (losses):Included
      in earnings
            
            
            (11
            )
            
            
            (1
            )Included
      in regulatory assets
            
            
            (10
            )
            
            
            (16
            )Purchases,
      sales, other settlements, net
            
            
            (35
            )
      (1)
            
            
            69
            (1)Net
      transfers into Level 3
            
            
            1
            
            
            
            —Ending
      balance
            
            $
            (58
            )
            
            $
            (6
            )The
      amount of total gains for the period included in earnings
              attributable
      to the change in unrealized gains or losses relating to
              assets
      still held at the reporting date
            
            $
            7
            
            
            $
            1







(1)
            Purchases,
      sales, other settlements, net include a $41 million loss and a
      $66 million gain in 2008 and 2009, respectively, associated with
      price stabilization activities of CERC's Natural Gas Distribution business
      segment.




59
 Table of Contents





(7)
            Short-term
      Borrowings and Long-term Debt





December 31,
      2008
            
            
            December 31,
      2009Long-Term
            
            
            Current(1)
            
            
            Long-Term
            
            
            Current(1)(In
      millions)Short-term
      borrowings:CERC
      Corp. receivables facility
            
            $
            —
            
            
            $
            78
            
            
            $
            —
            
            
            $
            —Inventory
      financing
            
            
            —
            
            
            
            75
            
            
            
            —
            
            
            
            55Total
      short-term borrowings
            
            
            —
            
            
            
            153
            
            
            
            —
            
            
            
            55Long-term
      debt:Convertible
      subordinated debentures 6.00%
              due
      2012(2)
            
            
            44
            
            
            
            7
            
            
            
            —
            
            
            
            44Senior
      notes 5.95% to 7.875% due 2011 to 2037
            
            
            2,747
            
            
            
            —
            
            
            
            2,747
            
            
            
            —Bank
      loans due 2012(3)
            
            
            926
            
            
            
            —
            
            
            
            —
            
            
            
            —Unamortized
      discount and premium(4)
            
            
            (5
            )
            
            
            —
            
            
            
            (5
            )
            
            
            —Total
      long-term debt
            
            
            3,712
            
            
            
            7
            
            
            
            2,742
            
            
            
            44Total
      debt
            
            $
            3,712
            
            
            $
            160
            
            
            $
            2,742
            
            
            $
            99







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





(2)
            In
      January 2010, pursuant to a notice of redemption dated December 11, 2009,
      CERC redeemed all of its outstanding 6% convertible subordinated
      debentures due in 2012.





(3)
            Classified
      as long-term debt because the termination date of the facility under which
      the funds were borrowed is more than one year beyond the dates referenced
      in the table.





(4)
            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
      $3 million and $2 million, respectively, at December 31, 2008
      and 2009, which is being amortized over the respective remaining term of
      the related long-term debt.





(a)
      Short-term Borrowings





Receivables
Facility.On October 9, 2009, CERC amended its receivables
facility to extend the termination date to October 8, 2010. Availability under
CERC’s 364-day receivables facility ranges from $150 million to
$375 million, reflecting seasonal changes in receivables balances. At
December 31, 2008 and 2009, the facility size was $128 million and
$150 million, respectively. As of December 31, 2008 and 2009, advances
under the receivables facilities were $78 million and $-0-,
respectively.





Inventory Financing. In
December 2008, Gas Operations entered into an asset management agreement whereby
it sold $110 million of its natural gas in storage and agreed to repurchase
an equivalent amount of natural gas during the 2008-2009 winter heating season
for payments totaling $114 million.  This transaction was
accounted for as a financing and was paid in full during 2009.





In
October 2009, Gas Operations entered into asset management agreements associated
with its utility distribution service in Arkansas, Louisiana and Oklahoma.
Pursuant to the provisions of the agreements, Gas Operations sold $104 million
of its natural gas in storage and agreed to repurchase an equivalent amount of
natural gas during the 2009-2010 winter heating season at the same cost, plus a
financing charge. This transaction was accounted for as a financing and, as of
December 31, 2009, a principal obligation of $55 million remained.





Also in
October 2009, Gas Operations entered into asset management agreements associated
with its utility distribution service in Louisiana, Mississippi and Texas. In
connection with these asset management agreements, Gas Operations exchanged
natural gas in storage for the right to receive an equivalent amount of natural
gas during the 2009-2010 winter heating season. Although title to the natural
gas in storage was transferred to the third party, the natural gas continues to
be accounted for as inventory due to the right to receive an equivalent amount
of natural gas during the current winter heating season. As of December 31,
2009, CenterPoint Energy’s Consolidated Balance Sheets reflect $10 million in
Inventory related to these agreements.





60
 Table of Contents


(b)
      Long-term Debt





Revolving Credit
Facility.  On October 7, 2009, the size of the CERC Corp.
revolving credit facility was reduced from $950 million to
$915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a
lender.  Prior to its removal, Lehman had a $35 million
commitment to lend.  All credit facility loans to CERC Corp. that were
funded by Lehman were repaid in September 2009.  CERC Corp.’s
$915 million credit facility’s first drawn cost is the London Interbank
Offered Rate (LIBOR) plus 45 basis points based on CERC Corp.’s current credit
ratings. The facility contains a debt to total capitalization
covenant.





Under
CERC Corp.’s $915 million credit facility, an additional utilization fee of
5 basis points applies to borrowings any time more than 50% of the facility is
utilized. The spread to LIBOR and the utilization fee fluctuate based on CERC
Corp.’s credit rating.





As of
December 31, 2008 and 2009, CERC Corp. had $926 million and $-0-,
respectively, of borrowings under its $915 million credit
facility.  There was no outstanding commercial paper backstopped by
CERC Corp.’s credit facility as of December 31, 2008 and 2009.  CERC
Corp. was in compliance with all debt covenants as of December 31,
2009.





Maturities.  CERC’s
consolidated maturities of long-term debt are $44 million in 2010,
$550 million in 2011,     $-0- in 2012,
$764 million in 2013 and $160 million in 2014.


(8)
              Income
      Taxes


The
components of CERC’s income tax expense were as follows:





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009(In
      millions)Current
      income tax expense (benefit):Federal
            
            $
            81
            
            
            $
            118
            
            
            $
            (107
            )State
            
            
            28
            
            
            
            18
            
            
            
            6Total
      current expense (benefit)
            
            
            109
            
            
            
            136
            
            
            
            (101
            )Deferred
      income tax expense:Federal
            
            
            58
            
            
            
            60
            
            
            
            226State
            
            
            6
            
            
            
            32
            
            
            
            21Total
      deferred expense
            
            
            64
            
            
            
            92
            
            
            
            247Total
      income tax expense
            
            $
            173
            
            
            $
            228
            
            
            $
            146





A
reconciliation of the expected federal income tax expense using the federal
statutory income tax rate to the actual income tax expense and resulting
effective income tax rate is as follows:





Year
      Ended December 31,2007
            
            
            2008
            
            
            2009(In
      millions)Income
      before income taxes
            
            $
            460
            
            
            $
            571
            
            
            $
            376Federal
      statutory rate
            
            
            35
            %
            
            
            35
            %
            
            
            35
            %Expected
      federal income tax expense
            
            
            161
            
            
            
            200
            
            
            
            132Increase
      (decrease) in tax expense resulting from:State
      income taxes, net of federal income tax
            
            
            22
            
            
            
            32
            
            
            
            18Decrease
      in settled and uncertain tax positions
            
            
            (8
            )
            
            
            (1
            )
            
            
            (1
            )Other,
      net
            
            
            (2
            )
            
            
            (3
            )
            
            
            (3
            )Total
            
            
            12
            
            
            
            28
            
            
            
            14Total
      income tax expense
            
            $
            173
            
            
            $
            228
            
            
            $
            146Effective
      tax rate
            
            
            37.6
            %
            
            
            40.0
            %
            
            
            38.8
            %





The state
income tax expense of $18 million for 2009 includes a benefit of
approximately $8 million, net of federal income tax effect, related to
adjustments in prior years’ state estimates.





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The tax
effects of temporary differences that give rise to significant portions of
deferred tax assets and liabilities were as follows:





December 31,2008
            
            
            2009(In
      millions)Deferred
      tax assets:Current:Allowance
      for doubtful accounts
            
            $
            13
            
            
            $
            9Deferred
      gas costs
            
            
            12
            
            
            
            7Total
      current deferred tax assets
            
            
            25
            
            
            
            16Non-current:Employee
      benefits
            
            
            80
            
            
            
            83Loss
      and credit carryforwards
            
            
            8
            
            
            
            12Regulatory
      liabilities, net
            
            
            11
            
            
            
            12Other
            
            
            11
            
            
            
            15Total
      non-current deferred tax assets before valuation allowance
            
            
            110
            
            
            
            122Valuation
      allowance
            
            
            (5
            )
            
            
            (5
            )Total
      non-current deferred tax assets, net of valuation allowance
            
            
            105
            
            
            
            117Total
      deferred tax assets, net of valuation allowance
            
            
            130
            
            
            
            133Deferred
      tax liabilities:Non-current:Depreciation
            
            
            927
            
            
            
            1,160Other
            
            
            42
            
            
            
            37Total
      non-current deferred tax liabilities
            
            
            969
            
            
            
            1,197Accumulated
      deferred income taxes, net
            
            $
            839
            
            
            $
            1,064





CERC is
included in the consolidated income tax returns of CenterPoint Energy. CERC
calculates its income tax provision on a separate return basis under a tax
sharing agreement with CenterPoint Energy.





Tax Attribute Carryforwards and
Valuation Allowance.  At December 31, 2009, CERC has
approximately $213 million of state net operating loss carryforwards which
expire in various years between 2010 and 2029. A valuation allowance has been
established for approximately $49 million of the state net operating loss
carryforwards that may not be realized. CERC has approximately $244 million
of state capital loss carryforwards which expire in 2017 for which a valuation
allowance has been established.





Uncertain Income Tax
Positions. The following table reconciles the beginning and ending
balance of CERC’s unrecognized tax benefits:





December 31,2007
            
            
            2008
            
            
            2009(In
      millions)Balance,
      beginning of year
            
            $
            1
            
            
            $
            (11
            )
            
            $
            (12
            )Tax
      Positions related to prior years:Additions
            
            
            —
            
            
            
            —
            
            
            
            18Reductions
            
            
            (10
            )
            
            
            (1
            )
            
            
            —Settlements
            
            
            (2
            )
            
            
            —
            
            
            
            —Tax
      Positions related to current year:Additions
            
            
            —
            
            
            
            —
            
            
            
            2Settlements
            
            
            —
            
            
            
            —
            
            
            
            (2
            )Balance,
      end of year
            
            $
            (11
            )
            
            $
            (12
            )
            
            $
            6





CERC had
approximately $1 million, $1 million and $-0- of unrecognized tax benefits
that, if recognized, would reduce the effective income tax rate for 2007, 2008
and 2009, respectively.  CERC recognizes interest and penalties as a
component of income tax expense. CERC recognized approximately $3 million,
$1 million and $1 million of benefit for interest on uncertain income
tax positions during 2007, 2008 and 2009, respectively. CERC had an accrued
balance of $4 million and $5 million of interest receivables on
uncertain income tax positions at





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 December 31,
2008 and 2009, respectively. CERC does not expect the amount of unrecognized tax
benefits to change significantly over the next 12 months.





Tax Audits and
Settlements.  CenterPoint Energy’s consolidated federal income
tax returns have been audited and settled through the 2005 tax year. CERC is
currently under examination by the IRS for tax years 2006 and 2007 and is at
various stages of the examination process. CERC has considered the effects of
these examinations in its accrual for settled issues and liability for uncertain
income tax positions as of December 31, 2009.





(9)
            Commitments
      and Contingencies





(a)
      Natural Gas Supply Commitments





Natural
gas supply commitments include natural gas contracts related to CERC’s Natural
Gas Distribution and Competitive Natural Gas Sales and Services business
segments, which have various quantity requirements and durations, that are not
classified as non-trading derivative assets and liabilities in CERC’s
Consolidated Balance Sheets as of December 31, 2008 and 2009 as these
contracts meet the exception to be classified as "normal purchases contracts" or
do not meet the definition of a derivative. Natural gas supply commitments also
include natural gas transportation contracts that do not meet the definition of
a derivative. As of December 31, 2009, minimum payment obligations for
natural gas supply commitments are approximately $439 million in 2010,
$490 million in 2011, $427 million in 2012, $390 million in 2013,
$269 million in 2014 and $543 million after 2014.





(b)
      Asset Management Agreements





Gas
Operations has entered into asset management agreements associated with its
utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and
Texas. Generally, these asset management agreements are contracts between Gas
Operations and an asset manager that are intended to transfer the working
capital obligation and maximize the utilization of the assets.  In
these agreements, Gas Operations agreed to release transportation and storage
capacity to other parties to manage gas storage, supply and delivery
arrangements for Gas Operations and to use the released capacity for other
purposes when it is not needed for Gas Operations. Gas Operations is compensated
by the asset manager through payments made over the life of the agreements based
in part on the results of the asset optimization. Under the provisions of these
asset management agreements, Gas Operations has an obligation to purchase its
winter storage requirements from the asset manager. The agreements have varying
terms, the longest of which expires in 2016.





(c)
      Lease Commitments





The
following table sets forth information concerning CERC’s obligations under
non-cancelable long-term operating leases at December 31, 2009, which primarily
consist of rental agreements for building space, data processing equipment and
vehicles, including major work equipment (in millions):





2010
            
            $
            122011
            
            
            132012
            
            
            92013
            
            
            62014
            
            
            42015
      and beyond
            
            
            7Total
            
            $
            51





Total
rental expense for all operating leases was $43 million, $41 million
and $36 million in 2007, 2008 and 2009, respectively.




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(d)
      Capital Commitments





Long-Term Gas Gathering and Treating
Agreements.In September 2009, CenterPoint Energy Field Services, Inc.
(CEFS), a wholly-owned natural gas gathering and treating subsidiary of CERC
Corp., entered into long-term agreements with an indirect wholly-owned
subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned
subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating
services for their natural gas production from certain Haynesville Shale and
Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned
gathering facilities from EnCana and Shell in De Soto and Red River parishes in
northwest Louisiana.  Each of the agreements includes acreage
dedication and volume commitments for which CEFS has rights to gather Shell’s
and EnCana’s natural gas production from the dedicated areas.





In
connection with the agreements, CEFS commenced gathering and treating services
utilizing the acquired facilities. CEFS is expanding the acquired facilities in
order to gather and treat up to 700 million cubic feet (MMcf) per day of
natural gas. If EnCana or Shell elect, CEFS will further expand the facilities
in order to gather and treat additional future volumes.  The
construction necessary to reach the contractual capacity of 700 MMcf per day
includes more than 200 miles of gathering lines, nearly 25,500 horsepower of
compression and over 800 MMcf per day of treating capacity.





CEFS
estimates that the purchase of existing facilities and construction to gather
700 MMcf per day will cost up to $325 million. If EnCana and Shell elect
expansion of the project to gather and process additional future volumes of up
to 1 Bcf per day, CEFS estimates that the expansion would cost as much as
an additional $300 million and EnCana and Shell would provide incremental
volume commitments. Funds for construction are being provided from anticipated
cash flows from operations, lines of credit, proceeds from the sale of debt
securities or capital contributions.  As of December 31, 2009,
approximately $176 million has been spent on this project, including the
purchase of existing facilities.





(e)
      Legal, Environmental and Other
Matters





Legal
Matters





Gas Market Manipulation
Cases.  CenterPoint Energy or its predecessor, Reliant Energy,
Incorporated (Reliant Energy), and certain of their former subsidiaries are
named as defendants in several lawsuits described below. Under a master
separation agreement between CenterPoint Energy and RRI (formerly known as
Reliant Resources, Inc. and Reliant Energy, Inc.), CenterPoint Energy and its
subsidiaries are entitled to be indemnified by RRI for any losses, including
attorneys’ fees and other costs, arising out of these
lawsuits.  Pursuant to the indemnification obligation, RRI is
defending CenterPoint Energy and its subsidiaries to the extent named in these
lawsuits.  A large number of lawsuits were filed against numerous gas
market participants in a number of federal and western state courts in
connection with the operation of the natural gas markets in 2000-2002.
CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in
the California and Western markets. These lawsuits, many of which have been
filed as class actions, allege violations of state and federal antitrust laws.
Plaintiffs in these lawsuits are seeking a variety of forms of relief,
including, among others, recovery of compensatory damages (in some cases in
excess of $1 billion), a trebling of compensatory damages, full
consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant
Energy were named in approximately 30 of these lawsuits, which were instituted
between 2003 and 2009. CenterPoint Energy and its affiliates have been released
or dismissed from all but two of such cases. CenterPoint Energy Services, Inc.
(CES), a subsidiary of CERC Corp., is a defendant in a case now pending in
federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas
prices in 2000-2002.  Additionally, CenterPoint Energy was a defendant
in a lawsuit filed in state court in Nevada that was dismissed in 2007, but the
plaintiffs have indicated that they will appeal the dismissal. CenterPoint
Energy believes that neither it nor CES is a proper defendant in these remaining
cases and will continue to pursue dismissal from those
cases.  CenterPoint Energy does not expect the ultimate outcome of
these remaining matters to have a material impact on its financial condition,
results of operations or cash flows.





On May 1,
2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG
Energy, Inc.  In connection with the sale, RRI changed its name to RRI
Energy, Inc.  The sale does not alter RRI’s contractual obligations to
indemnify CenterPoint Energy and its subsidiaries for certain liabilities,
including their indemnification regarding certain litigation, nor does it affect
the terms of existing guaranty arrangements for certain RRI gas transportation
contracts discussed below.




64
 Table of Contents





Natural Gas Measurement
Lawsuits. CERC Corp. and certain of its subsidiaries, along with 76 other
natural gas pipelines, their subsidiaries and affiliates, were defendants in a
lawsuit filed in 1997 under the Federal False Claims Act alleging mismeasurement
of natural gas produced from federal and Indian lands. The suit sought
undisclosed damages, along with statutory penalties, interest, costs and fees.
This case was consolidated, together with the other similar False Claims Act
cases, in the federal district court in Cheyenne, Wyoming. In October 2006, the
judge considering this matter granted the defendants’ motion to dismiss the suit
on the ground that the court lacked subject matter jurisdiction over the claims
asserted. The plaintiff sought review of that dismissal from the Tenth Circuit
Court of Appeals, which affirmed the district court’s dismissal in March 2009.
Following dismissal of the plaintiff’s motion to the Tenth Circuit for
rehearing, the plaintiff sought review by the United States Supreme Court, but
his petition for certiorari was denied in October 2009.





In
addition, CERC Corp. and certain of its subsidiaries are defendants in two
mismeasurement lawsuits brought against approximately 245 pipeline companies and
their affiliates pending in state court in Stevens County, Kansas.  In
one case (originally filed in May 1999 and amended four times), the plaintiffs
purport to represent a class of royalty owners who allege that the defendants
have engaged in systematic mismeasurement of the volume of natural gas for more
than 25 years. The plaintiffs amended their petition in this suit in July 2003
in response to an order from the judge denying certification of the plaintiffs’
alleged class. In the amendment, the plaintiffs dismissed their claims against
certain defendants (including two CERC Corp. subsidiaries), limited the scope of
the class of plaintiffs they purport to represent and eliminated previously
asserted claims based on mismeasurement of the British thermal unit (Btu)
content of the gas. The same plaintiffs then filed a second lawsuit, again as
representatives of a putative 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.  In September 2009, the district court in
Stevens County, Kansas, denied plaintiffs’ request for class certification of
their case. The plaintiffs are seeking reconsideration of that
denial.





CERC
believes that there has been no systematic mismeasurement of gas and that these
lawsuits are without merit. CERC does not expect the ultimate outcome of the
lawsuits to have a material impact on its financial condition, results of
operations or cash flows.





Gas Cost Recovery Litigation.In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas
and Arkansas in circuit court in Miller County, Arkansas against CenterPoint
Energy, CERC Corp., certain other subsidiaries of CenterPoint Energy and CERC
Corp. and various non-affiliated companies alleging fraud, unjust enrichment and
civil conspiracy with respect to rates charged to certain consumers of natural
gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Although
the plaintiffs in the Miller County case sought class certification, no class
was certified. In June 2007, the Arkansas Supreme Court determined that the
Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas
Public Service Commission (APSC) and in February 2008, the Arkansas Supreme
Court directed the Miller County court to dismiss the entire case for lack of
jurisdiction.





In August
2007, the Arkansas plaintiff in the Miller County litigation initiated a
complaint at the APSC seeking a decision concerning the extent of the APSC’s
jurisdiction over the Miller County case and an investigation into the merits of
the allegations asserted in his complaint with respect to CERC. In February
2009, the Arkansas plaintiff notified the APSC that he would no longer pursue
his claims, and in July 2009 the complaint proceeding was dismissed by the APSC.
All appellate deadlines expired without an appeal of the dismissal
order.





In June
2007, CenterPoint Energy, CERC Corp., and other defendants in the Miller County
case filed a petition in a district court in Travis County, Texas seeking a
determination that the Railroad Commission has exclusive original jurisdiction
over the Texas claims asserted in the Miller County case.  In January
2009, the district court entered a final declaratory judgment ruling that the
Railroad Commission has exclusive jurisdiction over the Texas claims asserted
against CenterPoint Energy, and the other defendants in the Miller County
case.





Environmental
Matters





Manufactured Gas Plant Sites.
CERC and its predecessors operated manufactured gas plants (MGPs) in the past.
In Minnesota, CERC has completed remediation on two sites, other than ongoing
monitoring and water treatment.





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 There are
five remaining sites in CERC’s Minnesota service territory. CERC believes that
it has no liability with respect to two of these sites.





At
December 31, 2009, CERC had accrued $14 million for remediation of
these Minnesota sites and the estimated range of possible remediation costs for
these sites was $4 million to $35 million based on remediation
continuing for 30 to 50 years. The cost estimates are based on studies of a site
or industry average costs for remediation of sites of similar size. The actual
remediation costs will be dependent upon the number of sites to be remediated,
the participation of other potentially responsible parties (PRP), if any, and
the remediation methods used. CERC has utilized an environmental expense tracker
mechanism in its rates in Minnesota to recover estimated costs in excess of
insurance recovery. As of December 31, 2009, CERC had collected
$13 million from insurance companies and rate payers to be used for future
environmental remediation. In January 2010, as part of its Minnesota rate case
decision, the MPUC eliminated the environmental expense tracker mechanism and
ordered amounts previously collected from ratepayers and related carrying costs
refunded to customers.  As of December 31, 2009, the balance in the
environmental expense tracker account was $8.7 million.  The MPUC
provided for the inclusion in rates of approximately $285,000 annually to fund
normal on-going remediation costs.  CERC was not required to refund to
customers the amount collected from insurance companies, $4.6 million at
December 31, 2009, to be used to mitigate future environmental
costs.  The MPUC further gave assurance that any reasonable and
prudent environmental clean-up costs CERC incurs in the future will be
rate-recoverable under normal regulatory principles and
procedures.  This provision had no impact on earnings.





In
addition to the Minnesota sites, the United States Environmental Protection
Agency and other regulators have investigated MGP sites that were owned or
operated by CERC or may have been owned by one of its former affiliates. CERC
has been named as a defendant in a lawsuit filed in the United States District
Court, District of Maine, under which contribution is sought by private parties
for the cost to remediate former MGP sites based on the previous ownership of
such sites by former affiliates of CERC or its divisions. CERC has also been
identified as a PRP by the State of Maine for a site that is the subject of the
lawsuit. In June 2006, the federal district court in Maine ruled that the
current owner of the site is responsible for site remediation but that an
additional evidentiary hearing would be required to determine if other
potentially responsible parties, including CERC, would have to contribute to
that remediation. In September 2009, the federal district court granted CERC’s
motion for summary judgment in the proceeding.  Although it is likely
that the plaintiff will pursue an appeal from that dismissal, further action
will not be taken until the district court disposes of claims against other
defendants in the case. CERC believes it is not liable as a former owner or
operator of the site under the Comprehensive Environmental, Response,
Compensation and Liability Act of 1980, as amended, and applicable state
statutes, and is vigorously contesting the suit and its designation as a PRP.
CERC does not expect the ultimate outcome to have a material adverse impact on
its financial condition, results of operations or cash flows.





Mercury Contamination. CERC'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. CERC has found this type of contamination at some
sites in the past, and CERC has conducted remediation at these sites. It is
possible that other contaminated sites may exist and that remediation costs may
be incurred for these sites. Although the total amount of these costs is not
known at this time, based on CERC's experience and that of others in the natural
gas industry to date and on the current regulations regarding remediation of
these sites, CERC believes that the costs of any remediation of these sites will
not be material to its financial condition, results of operations or cash
flows.





Asbestos.  Some
facilities formerly owned by CERC’s predecessors have contained asbestos
insulation and other asbestos-containing materials. CERC or its predecessor
companies have been named, along with numerous others, as a defendant in
lawsuits filed by certain individuals who claim injury due to exposure to
asbestos during work at such formerly owned facilities. CERC anticipates that
additional claims like those received may be asserted in the
future.  Although their ultimate outcome cannot be predicted at this
time, CERC intends to continue vigorously contesting claims that it does not
consider to have merit and does not expect, based on its experience to date,
these matters, either individually or in the aggregate, to have a material
adverse effect on its financial condition, results of operations or cash
flows.





Groundwater Contamination
Litigation.Predecessor entities of CERC, along with several other
entities, are defendants in litigation, St. Michel Plantation, LLC, et al,
v. White, et al., pending in civil district court in Orleans





66
 Table of Contents
 
 Parish,
Louisiana.  In the lawsuit, the plaintiffs allege that their property in
Terrebonne Parish, Louisiana suffered salt water contamination as a result of
oil and gas drilling activities conducted by the defendants.  Although a
predecessor of CERC held an interest in two oil and gas leases on a portion of
the property at issue, neither it nor any other CERC entities drilled or
conducted other oil and gas operations on those leases.  In January 2009,
CERC and the plaintiffs reached agreement on the terms of a settlement that, if
ultimately approved by the Louisiana Department of Natural Resources, is
expected to resolve this litigation. CERC does not expect the outcome of this
litigation to have a material adverse impact on its financial condition, results
of operations or cash flows.





Other
Environmental.  From time to time CERC 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, CERC 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, CERC does not expect,
based on its experience to date, these matters, either individually or in the
aggregate, to have a material adverse effect on its financial condition, results
of operations or cash flows.





Other
Proceedings





CERC 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. CERC regularly analyzes current information and, as
necessary, provides accruals for probable liabilities on the eventual
disposition of these matters. CERC does not expect the disposition of these
matters to have a material adverse effect on its financial condition, results of
operations or cash flows.





(f)
      Guaranties





Prior to
CenterPoint Energy’s distribution of its ownership in RRI to its shareholders,
CERC had guaranteed certain contractual obligations of what became RRI’s trading
subsidiary.  When the companies separated, RRI agreed to secure CERC
against obligations under the guaranties RRI had been unable to extinguish by
the time of separation.  Pursuant to such agreement, as amended in December
2007, RRI has agreed to provide to CERC cash or letters of credit
as security against CERC’s obligations under its remaining guaranties for
demand charges under certain gas transportation agreements if and to the extent
changes in market conditions expose CERC to a risk of loss on those
guaranties.  The present value of the demand charges under these
transportation contracts, which will be effective until 2018, was approximately
$96 million as of December 31, 2009. As of December 31, 2009, RRI was
not required to provide security to CERC.  If RRI should fail to perform
the contractual obligations, CERC could have to honor its guarantee and, in such
event, collateral provided as security may be insufficient to satisfy CERC’s
obligations.





(10)
            Estimated
      Fair Value of Financial Instruments





The fair
values of cash and cash equivalents and short-term borrowings are estimated to
be approximately equivalent to carrying amounts and have been excluded from the
table below. Non-trading derivative assets and liabilities are stated at fair
value and are excluded from the table below. The fair value of each debt
instrument is determined by multiplying the principal amount of each debt
instrument by the market price.





December 31,
      2008
            
            
            December 31,
      2009Carrying
              Amount
            
            
            Fair
              Value
            
            
            Carrying
              Amount
            
            
            Fair
              Value(In
      millions)Financial
      liabilities:Long-term
      debt
            
            $
            3,719
            
            
            $
            3,568
            
            
            $
            2,786
            
            
            $
            2,969




67
 Table of Contents





(11)
            Unaudited
      Quarterly Information





Summarized
quarterly financial data is as follows:





Year
      Ended December 31, 2008First
              Quarter
            
            
            Second
              Quarter
            
            
            Third
              Quarter
            
            
            Fourth
              Quarter(In
      millions)Revenues
            
            $
            2,952
            
            
            $
            2,157
            
            
            $
            1,960
            
            
            $
            2,326Operating
      income
            
            
            242
            
            
            
            130
            
            
            
            129
            
            
            
            216Net
      income
            
            
            126
            
            
            
            60
            
            
            
            67
            
            
            
            90





Year
      Ended December 31, 2009First
              Quarter
            
            
            Second
              Quarter
            
            
            Third
              Quarter
            
            
            Fourth
              Quarter(In
      millions)Revenues
            
            $
            2,351
            
            
            $
            1,116
            
            
            $
            965
            
            
            $
            1,825Operating
      income
            
            
            214
            
            
            
            89
            
            
            
            64
            
            
            
            202Net
      income
            
            
            95
            
            
            
            34
            
            
            
            5
            
            
            
            96





(12)
            Reportable
      Business Segments





Because
CERC is an indirect wholly owned subsidiary of CenterPoint Energy, CERC’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.  CERC uses operating income as the
measure of profit or loss for its business segments.





CERC’s
reportable business segments include the following: Natural Gas Distribution,
Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services
and Other Operations. Natural Gas Distribution consists of rate-regulated
intrastate natural gas sales to, and natural gas transportation and distribution
for, residential, commercial, industrial and institutional customers.
Competitive Natural Gas Sales and Services represents CERC’s non-rate regulated
gas sales and services operations, which consist of three operational functions:
wholesale, retail and intrastate pipelines.  The Interstate Pipelines
business segment includes the interstate natural gas pipeline operations. The
Field Services business segment includes the natural gas gathering operations.
Our Other Operations business segment includes unallocated corporate costs and
inter-segment eliminations.





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.





68
 Table of Contents





Financial
data for business segments and products and services are as follows (in
millions):





Revenues
              from
              External
              Customers
            
            
            Inter-segment
              Revenues
            
            
            Depreciation
              and
              Amortization
            
            
            Operating
              Income
              (Loss)
            
            
            Total
      Assets
            
            
            Expenditures
              for
      Long-
              Lived
      AssetsAs
      of and for the year ended December 31, 2007:Natural
      Gas Distribution
            
            $
            3,749
            
            
            $
            10
            
            
            $
            155
            
            
            $
            218
            
            
            $
            4,332
            
            
            $
            191Competitive
      Natural Gas Sales and Services
            
            
            3,534
            
            
            
            45
            
            
            
            5
            
            
            
            75
            
            
            
            1,221
            
            
            
            7Interstate
      Pipelines (1)
            
            
            357
            
            
            
            143
            
            
            
            44
            
            
            
            237
            
            
            
            3,007
            
            
            
            308Field
      Services (2)
            
            
            136
            
            
            
            39
            
            
            
            11
            
            
            
            99
            
            
            
            669
            
            
            
            74Other
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            (3
            )
            
            
            670
            
            
            
            —Reconciling
      Eliminations
            
            
            —
            
            
            
            (237
            )
            
            
            —
            
            
            
            —
            
            
            
            (765
            )
            
            
            —Consolidated
            
            $
            7,776
            
            
            $
            —
            
            
            $
            215
            
            
            $
            626
            
            
            $
            9,134
            
            
            $
            580As
      of and for the year ended December 31, 2008:Natural
      Gas Distribution
            
            $
            4,217
            
            
            $
            9
            
            
            $
            157
            
            
            $
            215
            
            
            $
            4,961
            
            
            $
            214Competitive
      Natural Gas Sales and Services
            
            
            4,488
            
            
            
            40
            
            
            
            3
            
            
            
            62
            
            
            
            1,315
            
            
            
            8Interstate
      Pipelines (1)
            
            
            477
            
            
            
            173
            
            
            
            46
            
            
            
            293
            
            
            
            3,578
            
            
            
            189Field
      Services (2)
            
            
            213
            
            
            
            39
            
            
            
            12
            
            
            
            147
            
            
            
            826
            
            
            
            122Other
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            724
            
            
            
            —Reconciling
      Eliminations
            
            
            —
            
            
            
            (261
            )
            
            
            —
            
            
            
            —
            
            
            
            (1,193
            )
            
            
            —Consolidated
            
            $
            9,395
            
            
            $
            —
            
            
            $
            218
            
            
            $
            717
            
            
            $
            10,211
            
            
            $
            533As
      of and for the year ended December 31, 2009:Natural
      Gas Distribution
            
            $
            3,374
            
            
            $
            10
            
            
            $
            161
            
            
            $
            204
            
            
            $
            4,535
            
            
            $
            165Competitive
      Natural Gas Sales and Services
            
            
            2,215
            
            
            
            15
            
            
            
            4
            
            
            
            21
            
            
            
            1,176
            
            
            
            2Interstate
      Pipelines (1)
            
            
            456
            
            
            
            142
            
            
            
            48
            
            
            
            256
            
            
            
            3,484
            
            
            
            176Field
      Services (2)
            
            
            212
            
            
            
            29
            
            
            
            15
            
            
            
            94
            
            
            
            1,045
            
            
            
            348Other
            
            
            —
            
            
            
            —
            
            
            
            1
            
            
            
            (6
            )
            
            
            800
            
            
            
            —Reconciling
      Eliminations
            
            
            —
            
            
            
            (196
            )
            
            
            —
            
            
            
            —
            
            
            
            (1,256
            )
            
            
            —Consolidated
            
            $
            6,257
            
            
            $
            —
            
            
            $
            229
            
            
            $
            569
            
            
            $
            9,784
            
            
            $
            691







(1)
            Interstate
      Pipelines recorded equity income of $6 million, $36 million, and
      $7 million (including $6 million and $33 million related to
      pre-operating allowance for funds used during construction during 2007 and
      2008, respectively) in the years ended December 31, 2007, 2008 and 2009,
      respectively, from its 50% interest in SESH, a jointly-owned pipeline.
      These amounts are included in Equity in earnings of unconsolidated
      affiliates under the Other Income (Expense) caption.  Interstate
      Pipelines’ investment in SESH was $58 million, $307 million and
      $422 million as of December 31, 2007, 2008 and 2009 and is included
      in Investment in unconsolidated
affiliates.





(2)
            Field
      Services recorded equity income of $10 million, $15 million and
      $8 million for the years ended December 31, 2007, 2008 and 2009,
      respectively, from its 50% interest in a jointly-owned gas processing
      plant. These amounts are included in Equity in earnings of unconsolidated
      affiliates under the Other Income (Expense) caption.  Field
      Services’ investment in the jointly-owned gas processing plant was
      $30 million, $38 million and $40 million as of December 31,
      2007, 2008 and 2009, respectively, and is included in Investment in
      unconsolidated affiliates.





Year
      Ended December 31,Revenues
      by Products and Services:
            
            2007
            
            
            2008
            
            
            2009(In
      millions)Retail
      gas sales
            
            $
            4,941
            
            
            $
            6,216
            
            
            $
            4,540Wholesale
      gas sales
            
            
            2,196
            
            
            
            2,295
            
            
            
            902Gas
      transport
            
            
            532
            
            
            
            756
            
            
            
            691Energy
      products and services
            
            
            107
            
            
            
            128
            
            
            
            124Total
            
            $
            7,776
            
            
            $
            9,395
            
            
            $
            6,257




69
 Table of Contents





Item 9. Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure.





None.





Item 9A(T). 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, 2009 to provide assurance
that information required to be disclosed in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission’s rules and
forms and such information is accumulated and communicated to our management,
including our principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding disclosure.





There has
been no change in our internal controls over financial reporting that occurred
during the three months ended December 31, 2009 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.





Management’s
Annual Report on Internal Control over Financial Reporting





See
report set forth above in Item 8, “Financial Statements and Supplementary
Data.”





Item 9B.Other
Information





The ratio
of earnings to fixed charges as calculated pursuant to Securities and Exchange
Commission rules was 2.61, 2.64, 3.04, 3.30, and 2.63 for the years ended
December 31, 2005, 2006, 2007, 2008 and 2009, respectively.





PART III





Item 10. Directors, Executive Officers and
Corporate Governance





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).





Item 13. Certain Relationships and Related
Transactions, and Director Independence





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).




70
 Table of Contents





Item 14. Principal Accounting Fees and
Services





Aggregate
fees billed to CERC during the fiscal years ending December 31, 2008 and
2009 by its principal accounting firm, Deloitte & Touche LLP, are set forth
below.





Year
      Ended December 31,2008
            
            
            2009Audit
      fees
      (1)
            
            $
            1,199,800
            
            
            $
            1,105,310Audit-related
      fees
      (2)
            
            
            86,869
            
            
            
            118,900Total
      audit and audit-related fees
            
            
            1,286,669
            
            
            
            1,224,210Tax
      fees
            
            
            —
            
            
            
            —All
      other
      fees
            
            
            —
            
            
            
            —Total
      fees
            
            $
            1,286,669
            
            
            $
            1,224,210







(1)
            For
      2009 and 2008, amounts include fees for services provided by the principal
      accounting firm relating to the integrated audit of financial statements
      and internal control over financial reporting, statutory audits, attest
      services, and regulatory filings.





(2)
            For
      2009 and 2008, includes fees for consultations concerning financial
      accounting and reporting standards and various agreed-upon or expanded
      procedures related to accounting records to comply with financial
      accounting or regulatory reporting
matters.





CERC 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.Report of Independent Registered Public Accounting Firm
            38Statements of Consolidated Income for the Three Years
      Ended December 31, 2009
            40Statements of Consolidated Comprehensive Income for the Three
      Years Ended December 31, 2009
            41Consolidated Balance Sheets at December 31,
      2008 and 2009
            42Statements of Consolidated Cash Flows for the Three Years
      Ended December 31, 2009
            43Statements of Consolidated Stockholder’s Equity for the
      Three Years Ended December 31, 2009
            44Notes to Consolidated Financial Statements
            45(a)(2)
      Financial Statement Schedules for the Three Years Ended December 31,
      2009.Report
      of Independent Registered Public Accounting Firm
            72II— Valuation and Qualifying Accounts
            73





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 75.





71
 Table of Contents





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”, an indirect wholly owned subsidiary of
CenterPoint Energy, Inc.) as of December 31, 2009 and 2008, and for each of the
three years in the period ended December 31, 2009, and have issued our report
thereon dated March 11, 2010; 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.








/s/
DELOITTE & TOUCHE LLP





Houston,
Texas


March 11,
2010






72
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CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES




(An
Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)





SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS


For
the Three Years Ended December 31, 2009





Column
      A
            
            Column
      B
            
            
            Column
      C
            
            
            Column
      D
            
            
            Column
      EDescription
            
            Balance
      at
              Beginning
              of
      Period
            
            
            Additions
            
            
            Deductions
              From
              Reserves(2)
            
            
            Balance
      at
              End
      of
              PeriodCharged
              to
      Income
            
            
            Charged
      to
              Other
              Accounts
      (1)(In
      millions)Year
      Ended December 31, 2009:Accumulated
      provisions:Uncollectible
      accounts receivable
            
            $
            33
            
            
            $
            35
            
            
            $
            —
            
            
            $
            45
            
            
            $
            23Deferred
      tax asset valuation allowance
            
            
            5
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            5Year
      Ended December 31, 2008:Accumulated
      provisions:Uncollectible
      accounts receivable
            
            $
            37
            
            
            $
            53
            
            
            $
            3
            
            
            $
            60
            
            
            $
            33Deferred
      tax asset valuation allowance
            
            
            18
            
            
            
            (1
            )
            
            
            (12
            )
            
            
            —
            
            
            
            5Year
      Ended December 31, 2007:Accumulated
      provisions:Uncollectible
      accounts receivable
            
            $
            32
            
            
            $
            42
            
            
            $
            —
            
            
            $
            37
            
            
            $
            37Deferred
      tax asset valuation allowance
            
            
            22
            
            
            
            (4
            )
            
            
            —
            
            
            
            —
            
            
            
            18







(1)
            The
      2008 change to the deferred tax asset valuation allowance charged to other
      accounts represents a reduction equal to the related deferred tax asset
      reduction in 2008 for re-measurement of state tax attributes, net of
      federal tax benefit.  A full valuation allowance for this deferred
      tax asset was established in prior
periods.





(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.







73
 Table of Contents





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 11th day of March, 2010.





CENTERPOINT
      ENERGY RESOURCES CORP.(Registrant)By:
            /s/
      DAVID M. MCCLANAHANDavid
      M. McClanahanPresident
      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 11, 2010.





Signature
            
            Title/s/
      DAVID M. MCCLANAHAN
            
            Chairman,
      President and Chief Executive Officer(David
      M. McClanahan)
            
            (Principal
      Executive Officer and Director)/s/
      GARY L. WHITLOCK
            
            Executive
      Vice President and Chief Financial Officer(Gary
      L. Whitlock)
            
            (Principal
      Financial Officer)/s/
      WALTER L. FITZGERALD
            
            Senior
      Vice President and Chief Accounting Officer(Walter
      L. Fitzgerald)
            
            (Principal
      Accounting Officer)










74
 Table of Contents





CENTERPOINT
ENERGY RESOURCES CORP. AND SUBSIDIARIES





EXHIBITS
TO THE ANNUAL REPORT ON FORM 10-K


For
Fiscal Year Ended December 31, 2009





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.





Exhibit
              Number
            
            Description
            
            Report
      or
              Registration
      Statement
            
            SEC
      File or
              Registration
              Number
            
            Exhibit
              Reference2(a)(1)
            
            Agreement
      and Plan of Merger among CERC, Houston Lighting and Power Company
      (“HL&P”), HI Merger, Inc. and NorAm Energy Corp. (“NorAm”) dated
      August 11, 1996
            
            Houston
      Industries’ (“HI’s”) Form 8-K dated August 11, 1996
            
            1-7629
            
            22(a)(2)
            
            Amendment
      to Agreement and Plan of Merger among CERC, HL&P, HI Merger, Inc. and
      NorAm dated August 11, 1996
            
            Registration
      Statement on Form S-4
            
            333-11329
            
            2(c)2(b)
            
            Agreement
      and Plan of Merger dated December 29, 2000 merging Reliant Resources
      Merger Sub, Inc. with and into Reliant Energy Services, Inc.
            
            Registration
      Statement on Form S-3
            
            333-54526
            
            23(a)(1)
            
            Certificate
      of Incorporation of Reliant Energy Resources Corp. (“RERC
      Corp.”)
            
            Form
      10-K for the year ended December 31, 1997
            
            1-3187
            
            3(a)(1)3(a)(2)
            
            Certificate
      of Merger merging former NorAm Energy Corp. with and into HI Merger, Inc.
      dated August 6, 1997
            
            Form
      10-K for the year ended December 31, 1997
            
            1-3187
            
            3(a)(2)3(a)(3)
            
            Certificate
      of Amendment changing the name to Reliant Energy Resources
      Corp.
            
            Form
      10-K for the year ended December 31, 1998
            
            1-3187
            
            3(a)(3)3(a)(4)
            
            Certificate
      of Amendment changing the name to CenterPoint Energy Resources
      Corp.
            
            Form
      10-Q for the quarter ended June 30, 2003
            
            1-13265
            
            3(a)(4)3(b)
            
            Bylaws
      of RERC Corp.
            
            Form
      10-K for the year ended December 31, 1997
            
            1-3187
            
            3(b)4(a)(1)
            
            Indenture,
      dated as of February 1, 1998, between RERC Corp. and Chase Bank
      of Texas, National Association, as Trustee
            
            Form
      8-K dated February 5, 1998
            
            1-13265
            
            4.14(a)(2)
            
            Supplemental
      Indenture No. 1, dated as of February 1, 1998, providing
      for the issuance of RERC Corp.’s 6 1/2%
              Debentures
      due February 1, 2008
            
            Form
      8-K dated February 5, 1998
            
            1-13265
            
            4.2


75
 Table of Contents





Exhibit
              Number
            
            Description
            
            Report
      or
              Registration
      Statement
            
            SEC
      File or
              Registration
              Number
            
            Exhibit
              Reference4(a)(3)
            
            Supplemental
      Indenture No. 2, dated as of November 1, 1998, providing
      for the issuance of RERC Corp.’s 6 3/8% Term Enhanced ReMarketable
      Securities
            
            Form
      8-K dated November 9, 1998
            
            1-13265
            
            4.14(a)(4)
            
            Supplemental
      Indenture No. 3, dated as of July 1, 2000, providing for
      the issuance of RERC Corp.’s 8.125% Notes due 2005
            
            Registration
      Statement on Form S-4
            
            333-49162
            
            4.24(a)(5)
            
            Supplemental
      Indenture No. 4, dated as of February 15, 2001, providing
      for the issuance of RERC Corp.’s 7.75% Notes due 2011
            
            Form
      8-K dated February 21, 2001
            
            1-13265
            
            4.14(a)(6)
            
            Supplemental
      Indenture No. 5, dated as of March 25, 2003, providing for
      the issuance of CERC Corp.’s 7.875% Senior Notes due 2013
            
            Form
      8-K dated March 18, 2003
            
            1-13265
            
            4.14(a)(7)
            
            Supplemental
      Indenture No. 6, dated as of April 14, 2003, providing for
      the issuance of CERC Corp.’s 7.875% Senior Notes due 2013
            
            Form
      8-K dated April 7, 2003
            
            1-13265
            
            4.24(a)(8)
            
            Supplemental
      Indenture No. 7, dated as of November 3, 2003, providing
      for the issuance of CERC Corp.’s 5.95% Senior Notes due 2014
            
            Form
      8-K dated October 29, 2003
            
            1-13265
            
            4.24(a)(9)
            
            Supplemental
      Indenture No. 8, dated as of December 28, 2005, providing
      for the issuance of CERC Corp.’s 6 1/2% Debentures due 2008
            
            CenterPoint
      Energy, Inc.’s (“CNP’s”) Form 10-K for the year ended
      December 31, 2005
            
            1-31447
            
            4(f)(9)4(a)(10)
            
            Supplemental
      Indenture No. 9, dated as of May 18, 2006, providing for
      the issuance of CERC Corp.’s 6.15% Senior Notes due 2016
            
            CNP’s
      Form 10-Q for the quarter ended June 30, 2006
            
            1-31447
            
            4.74(a)(11)
            
            Supplemental
      Indenture No. 10, dated as of February 6, 2007, providing
      for the issuance of CERC Corp.’s 6.25% Senior Notes due 2037
            
            CNP’s
      Form 10-K for the year ended December 31, 2007
            
            1-31447
            
            4(f)(11)4(a)(12)
            
            Supplemental
      Indenture No. 11 dated as of October 23, 2007, providing
      for the issuance of CERC Corp.’s 6.125% Senior Notes due 2017
            
            CNP’s
      Form 10-Q for quarter ended September 30, 2007
            
            1-31447
            
            4.84(a)(13)
            
            Supplemental
      Indenture No. 12  dated as of October 23, 2007,
      providing for the issuance of CERC Corp.’s 6.625% Senior Notes due
      2037
            
            CNP’s
      Form 10-Q for quarter ended September 30, 2007
            
            1-31447
            
            4.94(a)(14)
            
            Supplemental
      Indenture No. 13  dated as of May 15, 2008, providing for
      the issuance of CERC Corp.’s 6.00% Senior Notes due 2018
            
            CNP’s
      Form 10-Q for quarter ended June 30, 2008
            
            1-31447
            
            4.9




76
 Table of Contents





Exhibit
                Number
              
              Description
              
              Report
      or
                Registration
      Statement
              
              SEC
      File or
                Registration
                Number
              
              Exhibit
                Reference4(b)
              
              $950,000,000
      Second Amended and Restated Credit Agreement dated as of
      June 29, 2007, among CERC Corp., as Borrower, and the banks
      named therein
              
              CNP’s
      Form 10-Q for the quarter ended June 30, 2007
              
              1-31447
              
              4.5




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.




Exhibit
                Number
              
              Description
              
              Report
      or
                Registration
      Statement
              
              SEC
      File or
                Registration
                Number
              
              Exhibit
                Reference10(a)
              
              Service
      Agreement by and between Mississippi River Transmission Corporation and
      Laclede Gas Company dated August 22, 1989
              
              NorAm’s
      Form 10-K for the year ended December 31, 1989
              
              1-13265
              
              10.20+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 ofDavid
      M. McClanahan+32.2
              
              Section
      1350 Certification ofGary
      L. Whitlock
  77