10-K 1 cnp_10kx12312012.htm 10-K CNP_10K_12.31.2012


 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________
Form 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
FOR THE TRANSITION PERIOD FROM                TO              

Commission File Number 1-31447
______________________
CenterPoint Energy, Inc.
(Exact name of registrant as specified in its charter)
Texas
74-0694415
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
1111 Louisiana
Houston, Texas 77002
(Address and zip code of principal executive offices)
(713) 207-1111
(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 registered
Common Stock, $0.01 par value
New York Stock Exchange
Chicago Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ No o

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 o No þ

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 þ No o

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 þ No o

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. þ

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 þ
Accelerated filer o
Non-accelerated filer o
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 in Rule 12b-2 of the Exchange Act).  Yes o No þ

The aggregate market value of the voting stock held by non-affiliates of CenterPoint Energy, Inc. (CenterPoint Energy) was $8,760,880,387 as of June 30, 2012, using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers. As of February 14, 2013, CenterPoint Energy had 427,671,739 shares of Common Stock outstanding. Excluded from the number of shares of Common Stock outstanding are 166 shares held by CenterPoint Energy as treasury stock.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2013 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2012, are incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of this Form 10-K.
 




TABLE OF CONTENTS
PART I
 
 
Page
Item 1.
 
Business
 
Item 1A.
 
Risk Factors
 
Item 1B.
 
Unresolved Staff Comments
 
Item 2.
 
Properties
 
Item 3.
 
Legal Proceedings
 
Item 4.
 
Mine Safety Disclosures
 
PART II
Item 5.
 
Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Item 6.
 
Selected Financial Data
 
Item 7.
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Item 7A.
 
Quantitative and Qualitative Disclosures About Market Risk
 
Item 8.
 
Financial Statements and Supplementary Data
 
Item 9.
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
Item 9A.
 
Controls and Procedures
 
Item 9B.
 
Other Information
 
PART III
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
 
Item 13.
 
Certain Relationships and Related Transactions, and Director Independence
 
Item 14.
 
Principal Accounting Fees and Services
 
PART IV
Item 15.
 
Exhibits and Financial Statement Schedules
 
 

i



 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify our forward-looking statements by the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “should,” “will” or other similar words.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

Some of the factors that could cause actual results to differ from those expressed or implied by our forward-looking statements are described under “Risk Factors” in Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Certain Factors Affecting Future Earnings” and “ – Liquidity and Capital Resources – Other Factors That Could Affect Cash Requirements” in Item 7 of this report, which discussions are incorporated herein by reference.

You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to update or revise any forward-looking statements.
 

ii



PART I

Item 1.
Business

OUR BUSINESS

Overview

We are a public utility holding company whose indirect wholly owned subsidiaries include:

CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes the city of Houston; and

CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which 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 Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

Our reportable business segments are Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, 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 Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the Securities and Exchange Commission (SEC). Additionally, we make available free of charge on our Internet website:

our Code of Ethics for our Chief Executive Officer and Senior Financial Officers;

our Ethics and Compliance Code;

our Corporate Governance Guidelines; and

the charters of the audit, compensation, finance and governance committees of our Board of Directors.

Any shareholder who so requests may obtain a printed copy of any of these documents from us. Changes in or waivers of our Code of Ethics for our Chief Executive Officer and Senior Financial Officers and waivers of our Ethics and Compliance Code for directors or executive officers will be posted on our Internet website within five business days of such change or waiver and maintained for at least 12 months or reported on Item 5.05 of Form 8-K. Our website address is www.centerpointenergy.com. Except to the extent explicitly stated herein, documents and information on our website are not incorporated by reference herein.

Electric Transmission & Distribution
 
CenterPoint Houston is a transmission and distribution electric utility that operates wholly within the state of Texas. Neither CenterPoint Houston nor any other subsidiary of CenterPoint Energy makes retail or wholesale sales of electric energy or owns or operates any electric generating facilities.
 
Electric Transmission
 
On behalf of retail electric providers (REPs), CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kilovolts (kV) in locations throughout CenterPoint Houston's certificated service territory. CenterPoint Houston constructs and maintains transmission facilities and provides transmission services under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).
 

1



Electric Distribution
 
In the Electric Reliability Council of Texas, Inc. (ERCOT), end users purchase their electricity directly from certificated REPs. CenterPoint Houston delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer. CenterPoint Houston's distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users through distribution feeders. CenterPoint Houston's operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. CenterPoint Houston provides distribution services under tariffs approved by the Texas Utility Commission. Texas Utility Commission rules and market protocols govern the commercial operations of distribution companies and other market participants. Rates for these existing services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the Texas Utility Commission.
 
ERCOT Market Framework
 
CenterPoint Houston is a member of ERCOT. Within ERCOT, prices for wholesale generation and retail electric sales are unregulated, but services provided by transmission and distribution companies, such as CenterPoint Houston, are regulated by the Texas Utility Commission. ERCOT serves as the regional reliability coordinating council for member electric power systems in most of Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs. The ERCOT market includes most of the State of Texas, other than a portion of the panhandle, portions of the eastern part of the state bordering Arkansas and Louisiana and the area in and around El Paso. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation's largest power markets. The ERCOT market included available generating capacity of approximately 74,000 megawatts (MW) at December 31, 2012. Currently, there are only limited direct current interconnections between the ERCOT market and other power markets in the United States and Mexico.
 
The ERCOT market operates under the reliability standards set by the North American Electric Reliability Corporation (NERC) and approved by the Federal Energy Regulatory Commission (FERC). These reliability standards are administered by the Texas Regional Entity (TRE), a functionally independent division of ERCOT. The Texas Utility Commission has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state's main interconnected power transmission grid. The ERCOT independent system operator (ERCOT ISO) is responsible for operating the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT ISO does not procure energy on behalf of its members other than to maintain the reliable operations of the transmission system. Members who sell and purchase power are responsible for contracting sales and purchases of power bilaterally. The ERCOT ISO also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.
 
CenterPoint Houston's electric transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. The transmission business has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated area. CenterPoint Houston participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.
 
Resolution of True-Up Appeal
 
In 1999, the Texas legislature adopted the Texas Electric Choice Plan (Texas electric restructuring law) that led to the restructuring of certain integrated electric utilities operating within Texas. Pursuant to that legislation, integrated electric utilities operating within ERCOT were required to unbundle their integrated operations into separate retail sales, power generation and transmission and distribution companies. The legislation provided for a transition period to move to the new market structure and provided a true-up mechanism for the formerly integrated electric utilities to recover stranded and certain other costs resulting from the transition to competition. Those costs were recoverable after approval by the Texas Utility Commission either through the issuance of securitization bonds or through the implementation of a competition transition charge (CTC) as a rider to the utility's tariff.

CenterPoint Houston's integrated utility business was restructured in accordance with the Texas electric restructuring law and its generating stations were sold to third parties. In March 2004, CenterPoint Houston filed a true-up application with the Texas Utility Commission, requesting recovery of associated costs of $3.7 billion, excluding interest, as allowed under the Texas electric restructuring law. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint

2



Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other adjustments.  To reflect the impact of the True-Up Order, in 2004 and 2005, CenterPoint Energy recorded a net after-tax extraordinary loss of $947 million.
 
Various parties, including CenterPoint Houston, appealed the True-Up Order.  These appeals were heard first by a district court in Travis County, Texas, then by the Texas Third Court of Appeals and finally by the Texas Supreme Court.  In March 2011, the Texas Supreme Court issued a unanimous ruling on such appeals in which it affirmed in part and reversed in part the decision of the Texas Utility Commission. In June 2011, the Texas Supreme Court issued a final mandate remanding the case to the Texas Utility Commission for further proceedings (the Remand Proceeding).
 
In September 2011, CenterPoint Houston reached an agreement in principle with the staff of the Texas Utility Commission and certain intervenors to settle the issues in the Remand Proceeding (the Settlement). In October 2011, the Texas Utility Commission approved a final order (the Final Order) in the Remand Proceeding consistent with the Settlement. The Final Order provided that (i) CenterPoint Houston was entitled to recover an additional true-up balance of $1.695 billion (the Recoverable True-Up Balance) in the Remand Proceeding, (ii) no further interest would accrue on the Recoverable True-Up Balance, and (iii) CenterPoint Houston would reimburse certain parties for their reasonable rate case expenses.
 
In October 2011, the Texas Utility Commission also issued a financing order (the Financing Order) that authorized the issuance of transition bonds by CenterPoint Houston to securitize the Recoverable True-Up Balance. In January 2012, CenterPoint Energy Transition Bond Company IV, LLC (Bond Company IV), a new special purpose subsidiary of CenterPoint Houston, issued $1.695 billion of transition bonds in three tranches with interest rates ranging from 0.9012% to 3.0282% and final maturity dates ranging from April 15, 2018 to October 15, 2025. Through the issuance of these transition bonds, CenterPoint Houston recovered the Recoverable True-Up Balance, less approximately $10.4 million of offering expenses. The transition bonds will be repaid through a charge imposed on customers in CenterPoint Houston's service territory.
 
As a result of the Final Order, in 2011 CenterPoint Houston recorded a pre-tax extraordinary gain of $921 million ($587 million after-tax) and $352 million ($224 million after-tax) of Other Income related to a portion of interest on the appealed amount.  An additional $405 million ($258 million after-tax) will be recorded as an equity return over the life of the transition bonds.
 
Customers
 
CenterPoint Houston serves nearly all of the Houston/Galveston metropolitan area. At December 31, 2012, CenterPoint Houston's customers consisted of approximately 75 REPs, which sell electricity to over two million metered customers in CenterPoint Houston's certificated service area, and municipalities, electric cooperatives and other distribution companies located outside CenterPoint Houston's certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the Texas Utility Commission.
 
Sales to REPs that are affiliates of NRG Energy, Inc. (NRG) represented approximately 38%, 36% and 39% of CenterPoint Houston's transmission and distribution revenues in 2010, 2011 and 2012, respectively.  Sales to REPs that are affiliates of Energy Future Holdings Corp. (Energy Future Holdings) represented approximately 12%, 11% and 10% of CenterPoint Houston's transmission and distribution revenues in 2010, 2011 and 2012, respectively.  CenterPoint Houston's aggregate billed receivables balance from REPs as of December 31, 2012 was $158 million.  Approximately 42% and 2% of this amount was owed by affiliates of NRG and Energy Future Holdings, respectively. CenterPoint Houston does not have long-term contracts with any of its customers. It operates using a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day.
 
Advanced Metering System and Distribution Grid Automation (Intelligent Grid)
 
In December 2008, CenterPoint Houston received approval from the Texas Utility Commission to deploy an advanced metering system (AMS) across its service territory during the following five years. CenterPoint Houston began installing advanced meters in March 2009. In May 2012, CenterPoint Houston substantially completed the deployment of the advanced metering system having installed approximately 2.2 million smart meters. This technology should encourage greater energy conservation by giving Houston-area electric consumers the ability to better monitor and manage their electric use and its cost in near real time. To recover the cost of the AMS, the Texas Utility Commission approved a monthly surcharge payable by REPs, initially over 12 years. For the first 24 months, which began in February 2009, the surcharge for residential customers was $3.24 per month.  Beginning in February 2011, the surcharge was reduced to $3.05 per month.  In September 2011, the surcharge duration was reduced from 12 years to approximately six years for residential customers and approximately eight years for commercial customers. The surcharge

3



amounts, or duration are subject to adjustment in future proceedings to reflect actual costs incurred and to address required changes in scope. 
 
CenterPoint Houston is also pursuing deployment of an electric distribution grid automation strategy that involves the implementation of an “Intelligent Grid” (IG) which would provide on-demand data and information about the status of facilities on its system. Although this technology is still in the developmental stage, CenterPoint Houston believes it has the potential to provide an improvement in grid planning, operations, maintenance and customer service for the CenterPoint Houston distribution system. These improvements are expected to result in fewer and shorter outages, better customer service, improved operations costs, improved security and more effective use of our workforce. We expect to include the costs of the deployment in future rate proceedings before the Texas Utility Commission.
 
In October 2009, the U.S. Department of Energy (DOE) selected CenterPoint Houston for a $200 million grant to help fund its AMS and IG projects.  As of December 31, 2011, CenterPoint Houston had received substantially all of the $200 million of grant funding from the DOE. CenterPoint Houston used $150 million of the grant funding to accelerate completion of its deployment of advanced meters to 2012, instead of 2014 as originally scheduled.  CenterPoint Houston estimates that capital expenditures of approximately $660 million for the installation of the advanced meters and corresponding communication and data management systems were incurred over the advanced meter deployment period. CenterPoint Houston is using the other $50 million from the grant for an initial deployment of an IG which covers approximately 12% of its service territory. This initial deployment is expected to be completed in 2014.  It is expected that the capital portion of the IG project subject to partial funding by the DOE will cost approximately $140 million.
 
Competition
 
There are no other electric transmission and distribution utilities in CenterPoint Houston's service area. In order for another provider of transmission and distribution services to provide such services in CenterPoint Houston's territory, it would be required to obtain a certificate of convenience and necessity from the Texas Utility Commission and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. We know of no other party intending to enter this business in CenterPoint Houston's service area at this time. Distributed generation could result in a reduction of demand for CenterPoint Houston's electric distribution services but has not been a significant factor to date.
 
Seasonality
 
A significant portion of CenterPoint Houston's revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Thus, CenterPoint Houston's revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months.
 
Properties
 
All of CenterPoint Houston's properties are located in Texas. Its properties consist primarily of high-voltage electric transmission lines and poles, distribution lines, substations, service centers, service wires and meters. Most of CenterPoint Houston's transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets as permitted by law.
 
All real and tangible properties of CenterPoint Houston, subject to certain exclusions, are currently subject to:
 
the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented; and
 
the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, which is junior to the lien of the Mortgage.
 
As of December 31, 2012, CenterPoint Houston had approximately $2.4 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including (a) $290 million held in trust to secure pollution control bonds that are not reflected in our consolidated financial statements because we are both the obligor on the bonds and the current owner of the bonds, (b) approximately $118 million held in trust to secure pollution control bonds for which we are obligated and (c) approximately $183 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, as of December 31, 2012, CenterPoint Houston had approximately $253 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage, including approximately $151 million held in trust to secure certain pollution control bonds for which we are obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70%

4



of property additions or cash deposited with the trustee. Approximately $2.9 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2012. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.
 
Electric Lines - Overhead.  As of December 31, 2012, CenterPoint Houston owned 28,011 pole miles of overhead distribution lines and 3,713 circuit miles of overhead transmission lines, including 373 circuit miles operated at 69,000 volts, 2,124 circuit miles operated at 138,000 volts and 1,216 circuit miles operated at 345,000 volts.
 
Electric Lines - Underground.  As of December 31, 2012, CenterPoint Houston owned 21,151 circuit miles of underground distribution lines and 26 circuit miles of underground transmission lines, including 2 circuit miles operated at 69,000 volts and 24 circuit miles operated at 138,000 volts.

Substations.  As of December 31, 2012, CenterPoint Houston owned 233 major substation sites having a total installed rated transformer capacity of 54,325 megavolt amperes.
 
Service Centers.  CenterPoint Houston operates 14 regional service centers located on a total of 291 acres of land. These service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity.
 
Franchises
 
CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 20 to 40 years.
 
Natural Gas Distribution

CERC Corp.'s natural gas distribution business (Gas Operations) engages in regulated intrastate natural gas sales to, and natural gas transportation for, approximately 3.3 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 2012, approximately 37% of Gas Operations' total throughput was to residential customers and approximately 63% was to commercial and industrial customers.
 
The table below reflects the number of natural gas distribution customers by state as of December 31, 2012:
 
Residential
 
Commercial/
Industrial
 
Total Customers
Arkansas
384,640

 
 
48,405

 
 
433,045

 
Louisiana
231,566

 
 
17,191

 
 
248,757

 
Minnesota
747,266

 
 
68,067

 
 
815,333

 
Mississippi
110,245

 
 
12,587

 
 
122,832

 
Oklahoma
91,795

 
 
10,694

 
 
102,489

 
Texas
1,493,183

 
 
89,469

 
 
1,582,652

 
Total Gas Operations
3,058,695

 
 
246,413

 
 
3,305,108

 
 
Gas Operations also provides unregulated services in Minnesota consisting of heating, ventilating and air conditioning (HVAC) equipment and appliance repair, and sales of HVAC, hearth and water heating equipment.
 
The demand for intrastate natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal. In 2012, approximately 66% 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.
 
Supply and Transportation.  In 2012, 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 2012 included BP Energy Company/BP Canada

5



Energy Marketing (12.2% of supply volumes), Tenaska Marketing Ventures (9.6%), Cargill, Inc. (9.5%), Kinder Morgan Tejas Pipeline/Kinder Morgan Texas Pipeline (8.8%), Shell Energy North America (6.4%), Conoco Inc. (6.2%), Macquarie Energy (5.1%), Sequent Energy Management (4%), JP Morgan (3.8%), and Oneok Energy Services (3.3%). Numerous other suppliers provided the remaining 31.1% 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 other subsidiaries, under contracts with remaining terms, including extensions, varying from one to ten years. Gas Operations anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.
 
Gas Operations actively engages in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of its state regulatory authorities. These price stabilization activities include use of storage gas and contractually establishing structured prices (e.g., fixed price, costless collars and caps) with our physical gas suppliers. Its gas supply plans generally call for 50-75% of winter supplies to be stabilized 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 savings and costs of 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. 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 200,000 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 72,000 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. The agreements have varying terms, the longest of which expires in 2016.

Assets
 
As of December 31, 2012, Gas Operations owned approximately 72,000 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 land owned by suppliers.
 

6



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
 
CERC offers 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 2012, CES marketed approximately 562 Bcf of natural gas, related energy services and transportation to approximately 16,300 customers (including approximately 6 Bcf to affiliates) in 21 states. Not included in the 2012 customer count are approximately 12,700 natural gas customers that are served under residential and small commercial choice programs invoiced by their host utility.  CES customers vary in size from small commercial customers to large utility companies in the central and eastern regions of the United States.
CES offers a variety of natural gas management services to gas utilities, large industrial customers, electric generators, smaller commercial and industrial customers, municipalities, educational institutions and hospitals. 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 also offers a portfolio of physical delivery services and financial products designed to meet customers' supply and price risk management needs. These customers are served directly, through interconnects with various interstate and intrastate pipeline companies, and portably, through our mobile energy solutions business.

In addition to offering natural gas management services, CES procures and optimizes transportation and storage assets. CES currently transports natural gas on 47 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).
 
Our risk control policy, which is overseen 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. 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. However, up to 3 Bcf of storage gas can be sold prior to purchase or purchased prior to sale for a period not to exceed 12 months. These open positions are subject to the existing VaR limits. The VaR limits within which CES operates, a $4 million maximum, are consistent with CES' 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. In 2012, CES' VaR averaged $0.2 million with a high of $1.0 million.

Assets
 
CEIP owns and operates approximately 233 miles of intrastate pipeline in Louisiana and Texas and contracts out approximately 2.3 Bcf of storage at its Pierce Junction facility in Texas under long-term leases. In addition, CES leases transportation capacity of approximately 0.81 Bcf per day on various interstate and intrastate pipelines and approximately 12 Bcf of storage to service its shippers and end-users.

7



 
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

CERC's pipelines business operates interstate natural gas pipelines with gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. CERC's 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, LLC (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 includes the 1.9 Bcf per day pipeline from Carthage, Texas to Perryville, Louisiana, which CEGT operates as a separate line with a fixed fuel rate; and
 
CenterPoint Energy-Mississippi River Transmission, LLC (MRT) is an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas, Illinois and Missouri.
 
The rates charged by CEGT and MRT for interstate transportation and storage services are regulated by the FERC. CERC's 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 2012, approximately 18% of CEGT and MRT's total operating revenue was attributable to services provided to Gas Operations, an affiliate, and approximately 9% 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 terms of CEGT's firm transportation and storage contracts with Gas Operations will expire in 2021. MRT's firm transportation and storage contracts with Laclede are in their evergreen period, subject to termination by either party upon one year notice.
 
Southeast Supply Header, LLC. CenterPoint Southeastern Pipelines Holding, LLC, a wholly owned subsidiary of CERC, 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 the third quarter of 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.
 
Assets
 
CERC's 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. CERC's interstate pipeline business also owns and operates 6 natural gas storage fields with a combined daily deliverability of approximately 1.3 Bcf and a combined working gas capacity of approximately 59 Bcf. CERC's 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. CERC's 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
 
CERC's 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. CERC's interstate pipelines business competes indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but environmental considerations have grown in importance when consumers consider alternative 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.


8



Field Services
 
CERC's field services business operates gas gathering, treating and processing facilities and also provides operating and technical services and remote data monitoring and communication services.
 
CERC's field services operations are conducted by a wholly owned subsidiary, CenterPoint Energy Field Services, LLC (CEFS), and subsidiaries of CEFS. CERC's field services business 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. As of the end of 2012, CERC's field services business gathered an average of approximately 2.4 Bcf per day of natural gas. In addition, CERC's field services business has the capacity available to treat up to 2.5 Bcf per day and process 625 MMcf per day of natural gas. CEFS, through its ServiceStar operating division, provides remote data monitoring and communications services to affiliates and third parties.
 
CERC's 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.
 
CEFS has 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 Texas and Louisiana. Under the long-term agreements, Encana or Shell may elect to require CEFS to expand the capacity of its gathering systems by up to an additional 1.3 Bcf per day. CEFS estimates that the cost to expand the capacity of its gathering systems by an additional 1.3 Bcf per day would be as much as $440 million. Encana and Shell would provide incremental volume commitments in connection with an election to expand system capacity.

In May 2012, CEFS purchased the Amoruso gathering system located in east Texas and related assets from a subsidiary of Encana for approximately $89 million. In connection with this acquisition, CEFS entered into a 15-year gathering agreement with Encana to gather and treat its natural gas production from the Amoruso and Hilltop fields located in Robertson and Leon counties in east Texas. The gathering agreement includes volume commitments and an acreage dedication. As of the end of 2012, the Amoruso gathering system had nearly 200 MMcf per day of natural gas throughput primarily from the Deep Bossier and Cotton Valley Lime formations.
 
Waskom Gas Processing Company. Prior to July 31, 2012, CenterPoint Energy Gas Processing Company, a wholly owned, indirect subsidiary of CERC, owned a 50% general partnership interest in Waskom Gas Processing Company (Waskom), a Texas general partnership, which owns and operates a natural gas processing plant and natural gas gathering assets in east Texas. On July 31, 2012, CenterPoint Energy purchased the 50% interest that it did not already own in Waskom, as well as other gathering and related assets from a third-party for approximately $273 million. The Waskom plant is capable of processing approximately 320 MMcf per day of natural gas. The gathering assets owned by Waskom are capable of gathering approximately 75 MMcf per day of natural gas.
 
Assets
 
CERC's field services business owns and operates approximately 4,600 miles of gathering lines and processing plants that collect, treat and process natural gas primarily from three regions located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.
 
Competition
 
CERC's 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. CERC's field services business competes indirectly with alternative forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but 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.


9



Other Operations

Our Other Operations business segment includes office buildings and other real estate used in our business operations and other corporate operations that support all of our business operations.

Financial Information About Segments

For financial information about our segments, see Note 16 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 FERC has authority to prohibit market manipulation in connection with FERC-regulated transactions and to impose significant civil and criminal penalties for statutory violations and violations of the FERC’s rules or orders. Our competitive natural gas sales and services subsidiary markets natural gas in interstate commerce pursuant to blanket authority granted by the FERC.

CERC's natural gas pipeline subsidiaries may periodically file applications with the FERC for changes in their generally available maximum rates and charges designed to allow them to recover their costs of providing service to customers (to the extent allowed by prevailing market conditions), including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period and, in some cases, are subject to refund under applicable law until such time as the FERC issues an order on the allowable level of rates.

CenterPoint Houston is not a “public utility” under the Federal Power Act and, therefore, is not generally regulated by the FERC, although certain of its transactions are subject to limited FERC jurisdiction. The FERC has certain responsibilities with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by CenterPoint Houston and other utilities within ERCOT. The FERC has designated the NERC as the Electric Reliability Organization (ERO) to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system (Electric Entities). The ERO and the FERC have authority to (a) impose fines and other sanctions on Electric Entities that fail to comply with approved standards and (b) audit compliance with approved standards. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the TRE. CenterPoint Houston does not anticipate that the reliability standards proposed by the NERC and approved by the FERC will have a material adverse impact on its operations. To the extent that CenterPoint Houston is required to make additional expenditures to comply with these standards, it is anticipated that CenterPoint Houston will seek to recover those costs through the transmission charges that are imposed on all distribution service providers within ERCOT for electric transmission provided.

As a public utility holding company, under the Public Utility Holding Company Act of 2005, we and our subsidiaries are subject to reporting and accounting requirements and are required to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances.

State and Local Regulation

Electric Transmission & Distribution

CenterPoint Houston conducts its operations pursuant to a certificate of convenience and necessity issued by the Texas Utility Commission that covers its present service area and facilities. The Texas Utility Commission and municipalities have the authority to set the rates and terms of service provided by CenterPoint Houston under cost-of-service rate regulation. CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and

10



for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 20 to 40 years.

CenterPoint Houston’s distribution rates charged to REPs for residential customers are primarily based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are primarily based on peak demand. All REPs in CenterPoint Houston’s service area pay the same rates and other charges for transmission and distribution services. This regulated delivery charge includes the transmission and distribution rate (which includes municipal franchise fees), a system benefit fund fee imposed by the Texas electric restructuring law, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, an energy efficiency cost recovery charge, a surcharge related to the implementation of AMS and charges associated with securitization of regulatory assets, stranded costs and restoration costs relating to Hurricane Ike. Transmission rates charged to distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay CenterPoint Houston the same rates and other charges for transmission services.

Resolution of True-Up Appeal.  For a discussion of CenterPoint Houston’s true-up proceedings, see “— Our Business — Electric Transmission & Distribution — Resolution of True-Up Appeal” above.
 
Rate Proceedings. For a discussion of CenterPoint Houston's ongoing rate proceedings, see “Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Sources and Uses of Cash — Regulatory Matters — CenterPoint Houston” in Item 7 of this report, which discussion is incorporated herein by reference.

Natural Gas Distribution

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 rate 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. In certain of its jurisdictions, Gas Operations has in effect annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital, earned returns on equity or actual margins realized.
 
Rate Proceedings. For a discussion of Gas Operations' ongoing rate proceedings, see “Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Sources and Uses of Cash — Regulatory Matters — Gas Operations” in Item 7 of this report, which discussion is incorporated herein by reference.

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 2002 Act, remediation activities are to be performed over a 10-year period. Our pipeline subsidiaries met this initial time frame for completion of the base line assessments and are currently performing reassessments as required.

Pursuant to the 2006 Act, the Pipeline and Hazardous Materials Safety Administration (PHMSA) at the Department of Transportation (DOT) issued regulations, effective February 12, 2010, requiring operators of gas distribution pipelines to develop and implement integrity management programs similar to those required for gas transmission pipelines, but tailored to reflect the differences in distribution pipelines.  Operators of natural gas distribution systems were required to write and implement their integrity management programs by August 2, 2011.  Our pipeline subsidiaries met this deadline.
 
Pursuant to the 2002 Act and the 2006 Act, PHMSA 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.  PHMSA also updated its reporting requirements for natural gas pipelines effective January 1, 2011.


11



In December 2011, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act). This act increases the maximum civil penalties for pipeline safety administrative enforcement actions; requires the DOT to study and report on the expansion of integrity management requirements and the sufficiency of existing gathering line regulations to ensure safety; requires pipeline operators to verify their records on maximum allowable operating pressure; and imposes new emergency response and incident notification requirements.

We anticipate that compliance with PHMSA's regulations, performance of the remediation activities by CERC's interstate and intrastate pipelines and natural gas distribution companies and verification of records on maximum allowable operating pressure 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. In particular, the cost of compliance with DOT's integrity management rules will depend on integrity testing and the repairs found to be necessary by such testing. Changes to the amount of pipe subject to integrity management, whether by expansion of the definition of the type of areas subject to integrity management procedures or of the applicability of such procedures outside of those defined areas, may also affect the costs we incur. Implementation of the 2011 Act by PHMSA may result in other regulations or the reinterpretation of existing regulations that could impact our compliance costs. In addition, we may be subject to DOT's enforcement actions and penalties if we fail to comply with pipeline regulations.

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, and electric transmission and distribution systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

restricting the way we can handle or dispose of 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 environmental conditions caused by our operations or attributable to former operations;

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

impacting the demand for our services by directly or indirectly affecting the use or price of natural gas, or the ability to extract natural gas in areas we serve in our interstate pipelines and field services businesses.

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, upgrade 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 recent trend in environmental regulation has been 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

12



future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to ensure the costs of such compliance are reasonable.

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 current 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” (GHGs) 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. The United States Congress has, from time to time, considered adopting legislation to reduce emissions of GHGs, 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 industrial sources to meet stringent new standards that would require substantial reductions in carbon emissions.  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 Doha, Qatar in 2012.  Following a finding by the U.S. Environmental Protection Agency (EPA) that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act. One requires a reduction in emissions of GHGs from motor vehicles beginning January 2, 2011.  The other regulates emissions of GHGs from certain large stationary sources under the Clean Air Act's Prevention of Significant Deterioration and Title V programs, commencing when the motor vehicle standards took effect on January 2, 2011. Also, the EPA adopted its “Mandatory Reporting of Greenhouse Gases Rule” that requires the annual calculation and reporting of GHG emissions from natural gas transmission, gathering, processing and distribution systems and electric distribution systems that emit 25,000 metric tons or more of CO2 equivalent per year.  These additional reporting requirements began in 2012 and we are currently in compliance. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA.

Although the adoption of new legislation is uncertain, action by the EPA to impose new standards and reporting requirements regarding GHG emissions continues.  As a distributor and transporter of natural gas and consumer of natural gas in its pipeline and gathering businesses, CERC’s 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 its operations or would have the effect of reducing the consumption of natural gas. Our electric transmission and distribution business, in contrast to some electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity.  Nevertheless, CenterPoint Houston’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. 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 emissions characteristics would be expected to beneficially affect CERC and its natural gas-related businesses.  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 GHG 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.  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.  On the other hand, warmer temperatures in our electric service territory may increase our revenues from transmission and distribution through increased demand for electricity for cooling.  Another possible effect of climate change is 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 could increase our costs to repair damaged facilities and restore service to our customers. When we cannot deliver electricity or 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.


13



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.

The EPA continues to adopt amendments to its regulations regarding maximum achievable control technology for stationary internal combustion engines (sometimes referred to as the RICE MACT rule), the most recent being January 14, 2013.  Compressors and back up electrical generators used by our Interstate Pipelines, Field Services and Natural Gas Distribution segments are generally compliant. Additional rules are expected to be proposed by the EPA this year for compliance by 2016 which could require an additional $50 million to $75 million in capital expenditure over the next three years.  We believe, however, that our operations will not be materially adversely affected by such requirements.

In addition, on August 16, 2012, the EPA published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (NESHAPS) to address hazardous air pollutants frequently associated with gas production and processing activities. The finalized regulations establish specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. The final rules under NESHAPS include maximum achievable control technology standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. Compliance with such rules is not expected to result in significant costs that would adversely impact our results of operations.

Water Discharges

Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.

Hazardous Waste

Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (RCRA), and comparable state laws, which impose detailed requirements for the handling, storage, treatment, transport 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

14



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. 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. 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.

As of December 31, 2012, CERC had recorded a liability of $14 million for remediation of these Minnesota sites. The estimated range of possible remediation costs for the sites CERC believes it has responsibility for was $6 million to $41 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. The Minnesota Public Utilities Commission includes approximately $285,000 annually in rates to fund normal on-going remediation costs.  As of December 31, 2012, CERC had collected $5.8 million from insurance companies to be used for future environmental remediation.

In addition to the Minnesota sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. We and CERC do not expect the ultimate outcome of these investigations will have a material adverse impact on the financial condition, results of operations or cash flows of either us or CERC.

Asbestos. Some facilities owned by us contain or have contained asbestos insulation and other asbestos-containing materials. We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by our subsidiaries. We anticipate that additional claims like those received may be asserted in the future. In 2004, we sold our generating business, to which most of these claims relate, to a company which is now an affiliate of NRG. Under the terms of the arrangements regarding separation of the generating business from us and our sale of that business, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by the NRG affiliate, but we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense by the NRG affiliate. Although their ultimate outcome cannot be predicted at this time, we intend to continue vigorously contesting claims that we do not consider to have merit and do not expect, based on our experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on our financial condition, results of operations or cash flows.

Other Environmental. From time to time we identify the presence of environmental contaminants on property where we conduct or have conducted operations.  Other such sites involving contaminants may be identified in the future.  We have remediated and expect to continue to remediate identified sites consistent with our legal obligations. 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.

15




EMPLOYEES

As of December 31, 2012, we had 8,720 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 Groups
Electric Transmission & Distribution
 
2,550

 
1,255

Natural Gas Distribution
 
3,610

 
1,333

Competitive Natural Gas Sales and Services
 
148

 

Interstate Pipelines
 
747

 

Field Services
 
337

 

Other Operations
 
1,328

 

Total
 
8,720

 
2,588


As of December 31, 2012, approximately 30% of our employees were covered by collective bargaining agreements. The collective bargaining agreement with the International Brotherhood of Electrical Workers Union Local 66, which covers approximately 14% of our employees, is scheduled to expire in May 2013. We believe we have a good relationship with this bargaining unit and expect to negotiate a new agreement in 2013.

EXECUTIVE OFFICERS
(as of February 14, 2013)
Name
 
Age
 
Title
David M. McClanahan
 
63
 
President and Chief Executive Officer and Director
Scott M. Prochazka
 
46
 
Executive Vice President and Chief Operating Officer
Scott E. Rozzell
 
63
 
Executive Vice President, General Counsel and Corporate Secretary
Thomas R. Standish
 
63
 
Executive Vice President and Group President, Corporate and Energy Services
Gary L. Whitlock
 
63
 
Executive Vice President and Chief Financial Officer
Tracy B. Bridge
 
54
 
Senior Vice President and Division President, Electric Operations
C. Gregory Harper
 
48
 
Senior Vice President and Division Group President, Pipelines and Field Services
Joseph B. McGoldrick
 
59
 
Senior Vice President and Division President, Gas Operations

David M. McClanahan has been President and Chief Executive Officer and a director of CenterPoint Energy since September 2002. He served as Vice Chairman of Reliant Energy, Incorporated (Reliant Energy) from October 2000 to September 2002 and as President and Chief Operating Officer of Reliant Energy’s Delivery Group from April 1999 to September 2002. He previously served as Chairman of the Board of Directors of ERCOT, Chairman of the Board of the University of St. Thomas in Houston and Chairman of the Board of the American Gas Association. He currently serves on the boards of the Edison Electric Institute, the American Gas Association, and as Chairman of the Greater Houston Partnership.

Scott M. Prochazka has served as Executive Vice President and Chief Operating Officer of CenterPoint Energy since July 2012. He previously served as Senior Vice President and Division President, Electric Operations from May 2011 to July 2012; as Division Senior Vice President, Electric Operations of CenterPoint Houston from February 2009 to May 2011; as Division Senior Vice President Regional Operations of CERC from February 2008 to February 2009; and as Division Vice President, Customer Service Operations from October 2006 to February 2008. He also currently serves on the Board of Directors of ERCOT.

Scott E. Rozzell has served as Executive Vice President, General Counsel and Corporate Secretary of CenterPoint Energy since September 2002. He served as Executive Vice President and General Counsel of the Delivery Group of Reliant Energy from March 2001 to September 2002. Before joining Reliant Energy in 2001, Mr. Rozzell was a senior partner in the law firm of Baker Botts L.L.P. He currently serves on the Board of Directors of the Association of Electric Companies of Texas and Powell Industries, Inc.


16



Thomas R. Standish has served as Executive Vice President and Group President, Corporate and Energy Services of CenterPoint Energy since May 2011. He previously served as Senior Vice President and Group President-Regulated Operations of CenterPoint Energy from August 2005 to May 2011; as Senior Vice President and Group President and Chief Operating Officer of CenterPoint Houston from June 2004 to August 2005; and as President and Chief Operating Officer of CenterPoint Houston from August 2002 to June 2004. He served as President and Chief Operating Officer for both electricity and natural gas for Reliant Energy’s Houston area from 1999 to August 2002.

Gary L. Whitlock has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since September 2002. He served as Executive Vice President and Chief Financial Officer of the Delivery Group of Reliant Energy from July 2001 to September 2002. Mr. Whitlock served as the Vice President, Finance and Chief Financial Officer of Dow AgroSciences, a subsidiary of The Dow Chemical Company, from 1998 to 2001. He currently serves on the Board of Directors of KiOR, Inc.

Tracy B. Bridge has served as Senior Vice President and Division President, Electric Operations since September 2012. He previously served as Senior Vice President and Division President, Gas Distribution Operations from May 2011 to September 2012; as Division Senior Vice President - Support Operations from February 2008 to May 2011; and as Division Vice President Regional Operations of CERC from January 2007 to February 2008. He previously served on the Board of Directors of the Southern Gas Association.

C. Gregory Harper has served as Senior Vice President and Group President, Pipelines and Field Services since December 2008. Before joining CenterPoint Energy in 2008, Mr. Harper served as President, Chief Executive Officer and as a Director of Spectra Energy Partners, LP from March 2007 to December 2008.  From January 2007 to March 2007, Mr. Harper was Group Vice President of Spectra Energy Corp., and he was Group Vice President of Duke Energy from January 2004 to December 2006. Mr. Harper served as Senior Vice President of Energy Marketing and Management for Duke Energy North America from January 2003 until January 2004 and Vice President of Business Development for Duke Energy Gas Transmission and Vice President of East Tennessee Natural Gas, LLC from March 2002 until January 2003. He currently serves on the Board of Directors and as Chairman of the Interstate Natural Gas Association of America.

Joseph B. McGoldrick has served as Senior Vice President and Division President, Gas Operations since September 2012. He previously served as Senior Vice President and Division President, Energy Services from May 2011 to September 2012 and as Division President, Gas Operations from February 2007 to May 2011. He previously served on the Board of Directors of the Southern Gas Association.

Item 1A.
Risk Factors

We are a holding company that conducts all of our business operations through subsidiaries, primarily CenterPoint Houston and CERC. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this report, summarizes the principal risk factors associated with the businesses conducted by each of these subsidiaries:
 
Risk Factors Affecting Our Electric Transmission & Distribution Business

A substantial portion of CenterPoint Houston’s receivables is concentrated in a small number of REPs, and any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.

CenterPoint Houston’s receivables from the distribution of electricity are collected from REPs that supply the electricity CenterPoint Houston distributes to their customers. As of December 31, 2012, CenterPoint Houston did business with approximately 75 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for CenterPoint Houston’s services or could cause them to delay such payments. CenterPoint Houston depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a REP cannot make timely payments. Applicable Texas Utility Commission regulations significantly limit the extent to which CenterPoint Houston can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and thus remains at risk for payments not made prior to the shift to the provider of last resort. The Texas Utility Commission revised its regulations in 2009 to (i) increase the financial qualifications required of REPs that began selling power after January 1, 2009, and (ii) authorize utilities to defer bad debts resulting from defaults by REPs for recovery in a future rate case. A significant portion of CenterPoint Houston's billed receivables from REPs are from affiliates of NRG and affiliates of Energy Future Holdings. CenterPoint Houston's aggregate billed receivables balance from REPs as of December 31, 2012 was $158 million.  Approximately 42% of this amount was owed by affiliates of NRG . Any delay or default in payment by REPs could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various

17



options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments CenterPoint Houston had received from such REP.

Rate regulation of CenterPoint Houston’s business may delay or deny CenterPoint Houston’s ability to earn a reasonable return and fully recover its costs.

CenterPoint Houston’s rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. The regulatory process by which rates are determined may not always result in rates that will produce full recovery of CenterPoint Houston’s costs and enable CenterPoint Houston to earn a reasonable return on its invested capital.

Disruptions at power generation facilities owned by third parties could interrupt CenterPoint Houston’s sales of transmission and distribution services.

CenterPoint Houston transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. CenterPoint Houston does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, CenterPoint Houston’s sales of transmission and distribution services may be diminished or interrupted, and its results of operations, financial condition and cash flows could be adversely affected.

CenterPoint Houston’s revenues and results of operations are seasonal.

A significant portion of CenterPoint Houston’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Thus, CenterPoint Houston’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months.

CenterPoint Houston could be subject to higher costs and fines or other sanctions as a result of mandatory reliability standards.
The FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by CenterPoint Houston and other utilities within ERCOT. The FERC has designated the NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the TRE, a functionally independent division of ERCOT. Compliance with the mandatory reliability standards may subject CenterPoint Houston to higher operating costs and may result in increased capital expenditures. In addition, if CenterPoint Houston were to be found to be in noncompliance with applicable mandatory reliability standards, it could be subject to sanctions, including substantial monetary penalties.
The AMS deployed throughout CenterPoint Houston's service territory may experience unexpected problems with respect to the timely receipt of accurate metering data.
CenterPoint Houston has deployed an AMS throughout its service territory. The deployment consisted, among other elements, of replacing existing meters with new electronic meters that record metering data at 15-minute intervals and wirelessly communicate that information to CenterPoint Houston over a bi-directional communications system installed for that purpose. The AMS integrates equipment and computer software from various vendors in order to eliminate the need for physical meter readings to be taken at consumers' premises, such as monthly readings for billing purposes and special readings associated with a customer's change in REPs or the connection or disconnection of electric service. Unanticipated difficulties could be encountered during the operation of the AMS, including failures or inadequacy of equipment or software, difficulties in integrating the various components of the AMS, changes in technology, cyber-security issues and factors outside the control of CenterPoint Houston, which could result in delayed or inaccurate metering data that might lead to delays or inaccuracies in the calculation and imposition of delivery or other charges, which could have a material adverse affect on CenterPoint Houston's results of operations, financial condition and cash flows.

18



Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses

Rate regulation of CERC’s business may delay or deny CERC’s ability to earn a reasonable return and fully recover its costs.

CERC’s rates for Gas Operations are regulated by certain municipalities and state commissions, and for its interstate pipelines by the FERC, based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CERC is allowed to charge may not match its expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of CERC’s costs and enable CERC to earn a reasonable return on its invested capital.
 
CERC’s businesses must compete with alternate energy sources, which could result in CERC marketing less natural gas, and its 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 CERC’s results of operations, financial condition and cash flows.

CERC competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with CERC for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CERC’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC’s two interstate pipelines and its gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. They also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but recently, environmental considerations have grown in importance when consumers consider alternative forms of energy. Excess pipeline capacity in the regions served by CERC's interstate pipelines could also increase competition and adversely impact CERC's ability to re-contract its available capacity when contracts expire. The actions of CERC’s competitors could lead to lower prices, which may have an adverse impact on CERC’s results of operations, financial condition and cash flows. Additionally, any reduction in the volume of natural gas transported or stored may have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC’s natural gas distribution and competitive natural gas sales and services businesses are subject to fluctuations in notional natural gas prices as well as geographic and seasonal natural gas price differentials, which could affect the ability of CERC’s suppliers and customers to meet their obligations or otherwise adversely affect CERC’s liquidity and results of operations and financial condition.

CERC is subject to risk associated with changes in the notional price of natural gas as well as geographic and seasonal natural gas price differentials. Increases in natural gas prices might affect CERC’s ability to collect balances due from its customers and, for Gas Operations, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC’s tariff rates. In addition, a sustained period of high natural gas prices could (i) apply downward demand pressure on natural gas consumption in the areas in which CERC operates, thereby resulting in decreased sales and transportation volumes and revenues and (ii) increase the risk that CERC’s suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase CERC’s 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 CERC must provide under its hedging arrangements. Changes in geographic and seasonal natural gas price differentials affect the value of CERC's transportation and storage services and its ability to re-contract its available capacity when contracts expire.

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

If CERC’s credit rating were to decline, it might be required to post cash collateral under its shipping or hedging arrangements or in order to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC’s results of operations, financial condition and cash flows could be adversely affected.


19



The revenues and results of operations of CERC’s interstate pipelines and field services businesses are subject to fluctuations in the supply and price of natural gas and natural gas liquids and regulatory and other issues impacting our customers’ production decisions.

CERC’s 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, access to drilling rigs, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes. Regulatory changes include the potential for more restrictive rules governing the use of hydraulic fracturing, a process used in the extraction of natural gas from shale reservoir formations, and the use of water in that process. 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 CERC’s results of operations, financial condition and cash flows.

CERC’s revenues from these businesses are also affected by the prices of natural gas and natural gas liquids (NGLs). Although the gathering revenues from our field services operations are primarily fee-based, a small portion of these revenues is related to sales of natural gas that we retain from either a usage component of our contracts or from compressor efficiencies, and a reduction in natural gas prices could adversely impact these revenues. 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.

CERC’s revenues and results of operations are seasonal.

A substantial portion of CERC’s revenues is derived from natural gas sales and transportation. Thus, CERC’s revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months.

The actual cost of pipelines and gathering systems under construction, future pipeline, gathering and treating systems and related compression facilities may be significantly higher than CERC anticipates.

Subsidiaries of CERC Corp. have been recently involved in significant pipeline and gathering 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 CERC’s 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 CERC’s expected investment return, which could adversely affect CERC’s financial condition, results of operations or cash flows.

The states in which CERC provides regulated local gas distribution may, either through legislation or rules, adopt restrictions regarding organization, financing and affiliate transactions that could have significant adverse impacts on CERC’s ability to operate.

The Public Utility Holding Company Act of 1935, to which CERC Corp. and its subsidiaries were subject prior to its repeal in 2005, 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, proposals have been put forth in some of the states in which CERC does business that have sought to expand the state regulatory frameworks to give state regulatory authorities increased jurisdiction and scrutiny over similar aspects of the utilities that operate in those states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and

20



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 credit rating.
 
These regulatory frameworks could have adverse effects on CERC’s ability to conduct its utility operations, to finance its 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 CERC and us to comply with competing regulatory requirements.

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, 2012, we had $9.8 billion of outstanding indebtedness on a consolidated basis, which includes $3.8 billion of non-recourse transition and system restoration bonds. As of December 31, 2012, approximately $1.4 billion principal amount of this debt is required to be paid through 2015. This amount excludes principal repayments of approximately $1.2 billion on transition and system restoration bonds, for which dedicated revenue streams exist. 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;

market expectations regarding our future earnings and cash flows;

market perceptions of our ability to access capital markets on reasonable terms;

our exposure to GenOn Energy, Inc. (GenOn) (formerly known as RRI Energy, Inc., Reliant Energy, Inc. and Reliant Resources, Inc. (RRI)), a wholly owned subsidiary of NRG, in connection with certain indemnification obligations;

incremental collateral that may be required due to regulation of derivatives; and

provisions of relevant tax and securities laws.

As of December 31, 2012, CenterPoint Houston had approximately $2.4 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, (a) including $290 million held in trust to secure pollution control bonds that are not reflected in our consolidated financial statements because we are both the obligor on the bonds and the current owner of the bonds, (b) approximately $118 million held in trust to secure pollution control bonds for which we are obligated and (c) approximately $183 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, as of December 31, 2012, CenterPoint Houston had approximately $253 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage, including approximately $151 million held in trust to secure certain pollution control bonds for which we are obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.9 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2012. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.
 
Our current credit ratings are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Sources and Uses of Cash — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of Part II 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.


21



As a holding company with no operations of our own, we will depend on distributions from our subsidiaries to meet our payment obligations, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.

We derive all of our operating income from, and hold all 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.

Poor investment performance of the pension plan and factors adversely affecting the calculation of pension liabilities could unfavorably impact our liquidity and results of operations.

We maintain a qualified defined benefit pension plan covering all employees. Our costs of providing this plan are dependent upon a number of factors including the investment returns on plan assets, the level of interest rates used to calculate the funded status of the plan, our contributions to the plan and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase as a result of a decline in the market value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations or government regulations that increase minimum funding requirements or the pension liability. In addition to affecting our funding requirements, each of these factors could adversely affect our results of operations and financial position.

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.

Risks Common to Our Businesses and Other Risks

We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines and distribution systems, gas gathering and processing systems, and electric transmission and distribution systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
 
restricting the way we can handle or dispose of 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 environmental conditions caused by our operations, or attributable to former operations;

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

impacting the demand for our services by directly or indirectly affecting the use or price of natural gas, or the ability to extract natural gas in areas we serve in our interstate pipelines and field services businesses.


22



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 recent trend in environmental regulation has been 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 greater than the amounts we currently anticipate.

Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations, financial condition and cash flows.

We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system, other than substations, because CenterPoint Houston believes it to be cost prohibitive. In the future, CenterPoint Houston may not be able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other natural disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise, or any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

We, CenterPoint Houston and CERC could incur liabilities associated with businesses and assets that we have transferred to others.

Under some circumstances, we, CenterPoint Houston and CERC could incur liabilities associated with assets and businesses we, CenterPoint Houston and CERC no longer own. These assets and businesses were previously owned by Reliant Energy, Incorporated (Reliant Energy), a predecessor of CenterPoint Houston, directly or through subsidiaries and include:

merchant energy, energy trading and REP businesses transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001 and now owned by affiliates of NRG; and

Texas electric generating facilities transferred to a subsidiary of Texas Genco Holdings, Inc. (Texas Genco) in 2002, later sold to a third party and now owned by an affiliate of NRG.

In connection with the organization and capitalization of RRI (now GenOn), that company and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston and CERC, with respect to liabilities associated with the transferred assets and businesses. 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 (now GenOn) were unable to satisfy a liability that has

23



been so assumed in circumstances in which Reliant Energy and its subsidiaries were not released from the liability in connection with the transfer, we, CenterPoint Houston or CERC could be responsible for satisfying the liability.

Prior to the distribution of our ownership in RRI to our 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 (now GenOn) 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 based on an annual calculation, with any required collateral to be posted each December.  The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $73 million as of December 31, 2012.  Based on market conditions in the fourth quarter of 2012 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. As a result, CenterPoint Energy returned to GenOn in the fourth quarter of 2012 the approximately $28 million of aggregate collateral previously posted by GenOn under the agreement. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC’s obligations.

GenOn's unsecured debt ratings are currently below investment grade. If GenOn were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event GenOn might not honor its indemnification obligations and claims by GenOn’s creditors might be made against us as its former owner.

Reliant Energy and RRI (GenOn’s predecessor) 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 GenOn, claims against Reliant Energy have been made on grounds that include liability of Reliant Energy as a controlling shareholder of GenOn’s predecessor. We, CenterPoint Houston or CERC could incur liability if claims in one or more of these lawsuits were successfully asserted against us, CenterPoint Houston or CERC and indemnification from GenOn were determined to be unavailable or if GenOn were unable to satisfy indemnification obligations owed with respect to those claims.

In connection with the organization and capitalization of Texas Genco (now an affiliate of NRG), Reliant Energy and Texas Genco entered into a separation agreement in which Texas Genco assumed liabilities associated with the electric generation assets Reliant Energy transferred to it. Texas Genco also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston, with respect to liabilities associated with the transferred assets and businesses. In many cases the liabilities assumed were obligations of CenterPoint Houston, and CenterPoint Houston was not released by third parties from these liabilities. The indemnity provisions were intended generally to place sole financial responsibility on Texas Genco and its subsidiaries for all liabilities associated with the current and historical businesses and operations of Texas Genco, regardless of the time those liabilities arose. If Texas Genco (now an affiliate of NRG) were unable to satisfy a liability that had been so assumed or indemnified against, and provided we or Reliant Energy had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability.

In connection with our sale of Texas Genco, the separation agreement was amended to provide that Texas Genco would no longer be liable for, and we would assume and agree to indemnify Texas Genco against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies held by us. Texas Genco and its related businesses now operate as subsidiaries of NRG.

We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by our subsidiaries. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the arrangements regarding separation of the generating business from us and our sale of that business to an affiliate of NRG, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by the NRG affiliate, but we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense by the NRG affiliate.

Cyber-attacks, acts of terrorism or other disruptions could adversely impact our results of operations, financial condition and cash flows.
We are subject to cyber-security risks related to breaches in the systems and technology that we use (i) to manage our operations and other business processes and (ii) to protect sensitive information maintained in the normal course of our businesses. The operation of our electric transmission and distribution system is dependent on not only physical interconnection of our facilities, but also on communications among the various components of our system.  As we deploy smart meters and the intelligent grid,

24



reliance on communication between and among those components increases.  Similarly, the distribution of natural gas to our customers and the gathering, processing and transportation of natural gas from our gathering, processing and pipeline facilities, are dependent on communications among our facilities and with third-party systems that may be delivering natural gas into or receiving natural gas and other products from our facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural phenomena, by failure of equipment or technology, or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt our ability to deliver electricity and gas and control these assets. Cyber-attacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt our operations and critical business functions, adversely affect our reputation, and subject us to possible legal claims and liability, any of which could have a material adverse affect on our results of operations, financial condition and cash flows. In addition, our electrical distribution and transmission facilities and gas distribution and pipeline systems may be targets of terrorist activities that could disrupt our ability to conduct our business and have a material adverse affect on our results of operations, financial condition and cash flows.
Our results of operations, financial condition and cash flows may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions.

Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks, including:

operator error or failure of equipment or processes;

operating limitations that may be imposed by environmental or other regulatory requirements;

labor disputes;

information technology system failures; and

catastrophic events such as fires, earthquakes, explosions, floods, droughts, hurricanes, pandemic health events or other similar occurrences.

Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have a material adverse effect on our results of operations, financial condition and/or cash flows.

Our merger and acquisition activities may not be successful or may result in completed acquisitions that do not perform as anticipated.

From time to time, we have made and may continue to make acquisitions of businesses and assets. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable. In addition, any completed or future acquisitions involve substantial risks, including the following:
 
acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;

acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;

we may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;

we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and

acquisitions, or the pursuit of acquisitions, could disrupt our ongoing businesses, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.    

Failure to attract and retain an appropriately qualified workforce could adversely impact our results of operations.

Our business is dependent on our ability to recruit, retain, and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to future needs, or the unavailability of contract

25



resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

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

The continued 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 and the proceeds of equity financing may be materially adversely impacted by these market conditions. Defaults of lenders in our credit facilities, should they occur, could adversely affect our liquidity.

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.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, 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 Doha, Qatar in 2012. Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. In addition, the EPA expanded its existing GHG emissions reporting requirements to include upstream petroleum and natural gas systems that emit 25,000 metric tons of CO2 equivalent per year. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA.  As a distributor and transporter of natural gas and consumer of natural gas in its pipeline and gathering businesses, CERC’s 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 its operations or would have the effect of reducing the consumption of natural gas.  Our electric transmission and distribution business, in contrast to some electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity.  Nevertheless, CenterPoint Houston’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. 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 and more severe weather events 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 is 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 could increase our costs to repair damaged facilities and restore service to our customers.  When we cannot deliver electricity or 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

None.

26




Item 2.
Properties

Character of Ownership

We lease or own our principal properties in fee, including our corporate office space and various real property. Most of our electric lines and gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others.

Electric Transmission & Distribution

For information regarding the properties of our Electric Transmission & Distribution business segment, please read “Business — Our Business — Electric Transmission & Distribution — Properties” in Item 1 of this report, which information is incorporated herein by reference.

Natural Gas Distribution

For information regarding the properties of our Natural Gas Distribution business segment, please read “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.

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.

Other Operations

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

Item 3.
Legal Proceedings

For a discussion of material legal and regulatory proceedings affecting us, please read “Business — Regulation” and “Business — Environmental Matters” in Item 1 of this report, “Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Sources and Uses of Cash — Regulatory Matters” in Item 7 of this report and Note 13(f) to our consolidated financial statements, which information is incorporated herein by reference.

Item 4.
Mine Safety Disclosures

Not applicable.


27



PART II

Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

As of February 14, 2013, our common stock was held by approximately 39,060 shareholders of record. Our common stock is listed on the New York and Chicago Stock Exchanges and is traded under the symbol “CNP.”

The following table sets forth the high and low closing prices of the common stock of CenterPoint Energy on the New York Stock Exchange composite tape during the periods indicated, as reported by Bloomberg, and the cash dividends declared in these periods.

 
 Market Price
 
Dividend
Declared
 
High
 
Low
 
Per Share
2011
 

 
 

 
 

First Quarter
 

 
 

 
$
0.1975

March 17
 
 
$
15.20

 
 

March 30
$
17.68

 
 
 
 

Second Quarter
 
 
 
 
$
0.1975

April 12
 
 
$
17.23

 
 

June 30
$
19.35

 
 
 
 

Third Quarter
 
 
 
 
$
0.1975

July 21
$
20.28

 
 
 
 

August 8
 
 
$
17.24

 
 

Fourth Quarter
 
 
 
 
$
0.1975

October 28
$
21.29

 
 
 
 

November 25
 
 
$
18.59

 
 

 
 
 
 
 
 
2012
 

 
 

 
 

First Quarter
 

 
 

 
$
0.2025

January 3
$
19.89

 
 
 
 

January 27
 
 
$
18.23

 
 

Second Quarter
 
 
 
 
$
0.2025

April 10
 
 
$
19.06

 
 

June 18
$
20.71

 
 
 
 

Third Quarter
 
 
 
 
$
0.2025

August 23
 
 
$
20.24

 
 

September 26
$
21.45

 
 
 
 

Fourth Quarter
 
 
 
 
$
0.2025

October 17
$
21.75

 
 
 
 

December 28
 
 
$
19.00

 
 


The closing market price of our common stock on December 31, 2012 was $19.25 per share.

The amount of future cash dividends will be subject to determination based upon our results of operations and financial condition, our future business prospects, any applicable contractual restrictions and other factors that our board of directors considers relevant and will be declared at the discretion of the board of directors.

On January 25, 2013, we announced a regular quarterly cash dividend of $0.2075 per share, payable on March 8, 2013 to shareholders of record on February 15, 2013.


28



Repurchases of Equity Securities

During the quarter ended December 31, 2012, none of our equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.

Item 6.        Selected Financial Data

The following table presents selected financial data with respect to our consolidated financial condition and consolidated results of operations and should be read in conjunction with our consolidated financial statements and the related notes in Item 8 of this report.

 
Year Ended December 31,
 
2008(1)
 
2009
 
2010
 
2011 (2)
 
2012
 
(in millions, except per share amounts)
Revenues
$
11,322

 
$
8,281

 
$
8,785

 
$
8,450

 
$
7,452

Income before Extraordinary Item
446

 
372

 
442

 
770

 
417

Extraordinary Item, net of tax

 

 

 
587

 

Net income
$
446

 
$
372

 
$
442

 
$
1,357

 
$
417

Basic earnings per common share:
 
 
 
 
 
 
 
 
 
Income before Extraordinary Item
$
1.32

 
$
1.02

 
$
1.08

 
$
1.81

 
$
0.98

Extraordinary Item, net of tax

 

 

 
1.38

 

Basic earnings per common share
$
1.32

 
$
1.02

 
$
1.08

 
$
3.19

 
$
0.98

Diluted earnings per common share:
 
 
 
 
 
 
 
 
 
Income before Extraordinary Item
$
1.30

 
$
1.01

 
$
1.07

 
$
1.80

 
$
0.97

Extraordinary Item, net of tax

 

 

 
1.37

 

Diluted earnings per common share
$
1.30

 
$
1.01

 
$
1.07

 
$
3.17

 
$
0.97

 
 
 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
0.73

 
$
0.76

 
$
0.78

 
$
0.79

 
$
0.81

Dividend payout ratio
55
%
 
75
%
 
72
%
 
44
%
(3
)
83
%
Return on average common equity
23
%
 
16
%
 
15
%
 
21
%
(3
)
10
%
Ratio of earnings to fixed charges
2.05

 
1.82

 
2.08

 
2.96

(3
)
2.29

At year-end:
 

 
 

 
 

 
 

 
 

Book value per common share
$
5.84

 
$
6.74

 
$
7.53

 
$
9.91

 
$
10.09

Market price per common share
12.62

 
14.51

 
15.72

 
20.09

 
19.25

Market price as a percent of book value
216
%
 
215
%
 
209
%
 
203
%
 
191
%
Total assets
$
19,676

 
$
19,773

 
$
20,111

 
$
21,703

 
$
22,871

Short-term borrowings
153

 
55

 
53

 
62

 
38

Transition and system restoration bonds, including current maturities
2,589

 
3,046

 
2,805

 
2,522

 
3,847

Other long-term debt, including current maturities
7,925

 
6,976

 
6,624

 
6,603

 
5,910

Capitalization:
 

 
 

 
 

 
 

 
 

Common stock equity
16
%
 
21
%
 
25
%
 
32
%
 
31
%
Long-term debt, including current maturities
84
%
 
79
%
 
75
%
 
68
%
 
69
%
Capitalization, excluding transition and system restoration bonds:
 

 
 

 
 

 
 

 
 

Common stock equity
20
%
 
27
%
 
33
%
 
39
%
 
42
%
Long-term debt, excluding transition and system restoration bonds, and including current maturities
80
%
 
73
%
 
67
%
 
61
%
 
58
%
Capital expenditures
$
1,053

 
$
1,148

 
$
1,462

 
$
1,191

 
$
1,188

___________________
(1)
Net income has been retrospectively adjusted by $1 million for the year ended 2008 to reflect the adoption of new accounting guidance as of January 1, 2009 for convertible debt instruments that may be settled in cash upon conversion.

(2)
2011 Income before Extraordinary Item includes a $224 million after-tax ($0.53 and $0.52 per basic and diluted share, respectively) return on true-up balance related to a portion of interest on the appealed true-up amount.

(3)
Calculated using Income before Extraordinary Item.

29




Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in combination with our consolidated financial statements included in Item 8 herein.

OVERVIEW

Background

We are a public utility holding company whose indirect wholly owned subsidiaries include:

CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes the city of Houston; and

CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which 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 Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

Business Segments

In this Management’s Discussion and Analysis, we discuss our results from continuing operations on a consolidated basis and individually for each of our business segments. We also discuss our liquidity, capital resources and certain critical accounting policies. We are first and foremost an energy delivery company and it is our intention to remain focused on this segment of the energy business. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are subject. Our electric transmission and distribution services are subject to rate regulation and are reported in the Electric Transmission & Distribution business segment, as are impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. Our natural gas distribution services are also subject to rate regulation and are reported in the Natural Gas Distribution business segment. A summary of our reportable business segments as of December 31, 2012 is set forth below:

Electric Transmission & Distribution

Our electric transmission and distribution operations provide electric transmission and distribution services to retail electric providers (REPs) serving over two million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately six million people and includes the city of Houston.

On behalf of REPs, CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers in locations throughout CenterPoint Houston’s certificated service territory. The Electric Reliability Council of Texas, Inc. (ERCOT) serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation’s largest power markets. Transmission and distribution services are provided under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).

Natural Gas Distribution

CERC owns and operates our regulated natural gas distribution business (Gas Operations), which engages in intrastate natural gas sales to, and natural gas transportation for, approximately 3.3 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.

Competitive Natural Gas Sales and Services

CERC’s operations also include non-rate regulated natural gas sales to, and transportation services for, commercial and industrial customers in 21 states in the central and eastern regions of the United States.


30



Interstate Pipelines

CERC’s 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 1.3 billion cubic feet (Bcf) and a combined working gas capacity of approximately 59 Bcf. It 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. Most storage operations are in north Louisiana and Oklahoma.

Field Services

CERC’s field services business owns and operates approximately 4,600 miles of gathering pipelines and processing plants that collect, treat and process natural gas primarily from three regions located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.  

Other Operations

Our other operations business segment includes office buildings and other real estate used in our business operations and other corporate operations which support all of our business operations.

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 and the transmission and delivery of electricity by our subsidiaries. We do not own or operate electric generating facilities or make retail sales to end-use electric customers. To assess our financial performance, our management primarily monitors operating income and cash flows from our 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 and cooling degree days. We also monitor system reliability, safety factors and customer satisfaction to gauge our performance.

To the extent 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 Electric Transmission & Distribution and Natural Gas Distribution business segments 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 on a weather adjusted basis. The Houston area experienced extremely hot and dry weather during 2011, and each month from April through September was one of the ten warmest months on record.  In 2012, we experienced a return to more normal weather in the summer months. However, every state in which we distribute natural gas had the warmest winter on record. In recent years, customers have typically reduced their energy consumption, and reduced consumption can adversely affect our results. However, due to more affordable energy prices and continued economic recovery in the areas we serve, the trend toward lower usage has slowed in some of the areas we serve. In addition, in many of our service areas, particularly in the Houston area and in Minnesota, we have benefited from growth in the number of customers that also tends to mitigate the effects of reduced consumption.  We anticipate that this growth will continue as the regions experience a continued economic recovery.  The profitability of our businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set our electric and gas distribution rates. In recent rate filings, we have sought rate mechanisms that help to decouple our results from the impacts of weather and variations in usage from levels reflected in rates, but such rate mechanisms have not yet been approved in all jurisdictions. We plan to continue to pursue such decoupling mechanisms in our future rate filings.

Our Field Services and Interstate Pipelines business segments are currently benefiting from their proximity to significant natural gas producing regions in Texas, Arkansas, Oklahoma and Louisiana.  In our Field Services business segment, the development of shale formations has helped offset declines in production from more traditional basins. The recent decline in natural gas prices has contributed to reductions in drilling activity in dry gas shale formations as well, including those served by our Field Services business segment. Many producers have shifted their focus to liquids-rich natural gas or crude oil basins. A

31



reduction in drilling activity may result in lower throughput volumes on our systems as the wells decline over time. However, a significant amount of the volumes gathered by systems we recently developed in shale basins such as the Haynesville and Fayetteville shales are supported by contracts with annual volume commitments, or price adjustment mechanisms that provide for minimum returns on capital deployed. In monitoring performance of the segments, we focus on throughput of the pipelines and gathering systems, and in the case of Field Services, on the number of 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 this business 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 geographic and seasonal price differentials during 2010, 2011 and 2012 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, proceeds from commercial paper and issuances of debt and equity in the capital markets 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 continue 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 facilities, and may prevent us from accessing the commercial paper markets. Disruptions in the financial markets 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 existing credit facilities and prudent refinancing of existing debt.

We expect to make contributions to our pension plan aggregating approximately $83 million in 2013 and may need to make larger contributions in subsequent years. Consistent with the regulatory treatment of such costs, we can defer the amount of pension expense that differs from the level of pension expense included in our base rates for our Electric Transmission & Distribution business segment and our Gas Operations in Texas.

Significant Events

Acquisition

On July 31, 2012, we purchased the 50% interest that we did not already own in Waskom Gas Processing Company (Waskom), a Texas general partnership, which owns and operates a natural gas processing plant and natural gas gathering assets, as well as other gathering and related assets from a third-party for approximately $273 million. The amount of the purchase price allocated to the acquisition of the 50% interest in Waskom was approximately $201 million, with the remaining purchase price allocated to the other gathering assets, based on a discounted cash flow methodology. The purchase of the 50% interest in Waskom was determined to be a business combination achieved in stages, and as such we recorded a pre-tax gain of approximately $136 million on July 31, 2012, which is the result of remeasuring our original 50% interest in Waskom to fair value. As a result of the purchase, we recorded goodwill of $24 million, which includes $17 million related to Waskom (including the re-measurement of our existing 50% interest) and $7 million related to the other gathering and related assets.

Goodwill Impairment

We performed our annual impairment test in the third quarter of 2012 and determined that a non-cash goodwill impairment charge in the amount of $252 million was required for the Competitive Natural Gas Sales and Services reportable segment. We also determined that no impairment charge was required for any other reportable segment. The adverse wholesale market conditions facing our energy services business, specifically the prospects for continued low geographic and seasonal price differentials for natural gas, led to a reduction in the estimate of the fair value of goodwill associated with this reporting unit.

Debt Financing Transactions

In January 2012, CenterPoint Energy Transition Bond Company IV, LLC (Bond Company IV) issued $1.695 billion of transition bonds in three tranches with interest rates ranging from 0.9012% to 3.0282% and final maturity dates ranging from April 15, 2018 to October 15, 2025. Through the issuance of these transition bonds, CenterPoint Houston recovered the additional true-up balance of $1.695 billion, less approximately $10.4 million of offering expenses. The transition bonds will be repaid through a charge imposed on customers in CenterPoint Houston’s service territory.


32



In February 2012, we purchased $275 million aggregate principal amount of pollution control bonds issued on our behalf at 100% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds. The purchased pollution control bonds will remain outstanding and may be remarketed. Prior to the purchase, the pollution control bonds had fixed interest rates ranging from 5.15% to 5.95%. Additionally, in March 2012, we redeemed $100 million aggregate principal amount of pollution control bonds issued on our behalf at 100% of their principal amount plus accrued interest pursuant to the optional redemption provisions of the bonds. The redeemed pollution control bonds had a fixed interest rate of 5.25%.

In August 2012, CenterPoint Houston issued $300 million of 2.25% general mortgage bonds due 2022 and $500 million of 3.55% general mortgage bonds due 2042. The net proceeds from the sale of the bonds were used to fund a portion of the redemption of the general mortgage bonds discussed below.

In August 2012, CenterPoint Houston redeemed $300 million principal amount of its 5.75% general mortgage bonds due 2014 at a price of 107.332% of their principal amount and $500 million principal amount of its 7.00% general mortgage bonds due 2014 at a price of 109.397% of their principal amount.  Redemption premiums for the two series aggregated approximately $69 million.  

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 affecting various aspects of our businesses, including, among others, energy deregulation or re-regulation, pipeline integrity and safety, health care reform, financial reform, tax legislation and actions regarding the rates charged by our regulated businesses;

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

timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment;

the timing and outcome of any audits, disputes and other proceedings related to taxes;

problems with construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or in cost overruns that cannot be recouped in rates;

industrial, commercial and residential growth in our service territory and changes in market demand, including the effects of energy efficiency measures and demographic patterns;

the timing and extent of changes in commodity prices, particularly natural gas and natural gas liquids, the competitive effects of excess pipeline capacity in the regions we serve, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on our interstate pipelines;

the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering by our field services business and transporting by our interstate pipelines, including the impact of natural gas and natural gas liquids prices on the level of drilling and production activities in the regions we serve;

competition in our mid-continent region footprint for access to natural gas supplies and markets;

weather variations and other natural phenomena, including the impact on operations and capital of severe weather events;

any direct or indirect effects on our facilities, operations and financial condition resulting from terrorism, cyber-attacks, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events;

the impact of unplanned facility outages;

timely and appropriate regulatory actions allowing securitization or other recovery of costs associated with any future hurricanes or natural disasters;

33




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

the ability of REPs, including REP affiliates of NRG and Energy Future Holdings Corp. (Energy Future Holdings), which are CenterPoint Houston’s two largest customers, to satisfy their obligations to us and our subsidiaries;

the outcome of litigation brought by or against us;

our ability to control costs;

the investment performance of our pension and postretirement benefit plans;

our potential business strategies, including restructurings, joint ventures, and acquisitions or dispositions of assets or businesses, which we cannot assure you will be completed or will have the anticipated benefits to us;

acquisition and merger activities involving us or our competitors;

future economic conditions in regional and national markets and their effect on sales, prices and costs; and

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 SEC.

34




CONSOLIDATED RESULTS OF OPERATIONS

All dollar amounts in the tables that follow are in millions, except for per share amounts.

 
Year Ended December 31,
 
2010
 
2011
 
2012
Revenues
$
8,785

 
$
8,450

 
$
7,452

Expenses
7,536

 
7,152

 
6,414

Operating Income
1,249

 
1,298

 
1,038

Gain on Marketable Securities
67

 
19

 
154

Gain (Loss) on Indexed Debt Securities
(31
)
 
35

 
(71
)
Interest and Other Finance Charges
(481
)
 
(456
)
 
(422
)
Interest on Transition and System Restoration Bonds
(140
)
 
(127
)
 
(147
)
Equity in Earnings of Unconsolidated Affiliates
29

 
30

 
31

Return on True-Up Balance

 
352

 

Step acquisition gain

 

 
136

Other Income, net
12

 
23

 
38

Income Before Income Taxes and Extraordinary Item
705

 
1,174

 
757

Income Tax Expense
263

 
404

 
340

Income Before Extraordinary Item
442

 
770

 
417

Extraordinary Item, net of tax

 
587

 

Net Income
$
442

 
$
1,357

 
$
417

 
 
 
 
 
 
Basic Earnings Per Share:
 
 
 
 
 
Income Before Extraordinary Item
$
1.08

 
$
1.81

 
$
0.98

Extraordinary Item, net of tax

 
1.38

 

Net Income
$
1.08

 
$
3.19

 
$
0.98

 
 
 
 
 
 
Diluted Earnings Per Share:
 
 
 
 
 
Income Before Extraordinary Item
$
1.07

 
$
1.80

 
$
0.97

Extraordinary Item, net of tax

 
1.37

 

Net Income
$
1.07

 
$
3.17

 
$
0.97


2012 Compared to 2011

Net Income.  We reported net income of $417 million ($0.97 per diluted share) for 2012 compared to $1.357 billion ($3.17 per diluted share) for the same period in 2011. The decrease in net income of $940 million was primarily due to the resolution in 2011 of the true-up appeal resulting in an after-tax extraordinary gain of $587 million and a $352 million return on the true-up balance, a $260 million decrease in operating income (discussed by segment below), including a $252 million non-cash goodwill impairment charge, and a $106 million increase in the loss on our indexed debt securities, which were partially offset by a $136 million step acquisition gain related to the acquisition of an additional 50% interest in Waskom, a $135 million increase in the gain on our marketable securities, a $64 million decrease in income tax expense and a $14 million decrease in interest expense due to lower levels of debt.

Income Tax Expense.   We reported an effective tax rate of 44.9% for 2012 compared to 34.4% for the same period in 2011. The increase in the effective tax rate of 10.5% is due to goodwill impairment of $252 million which is non-deductible for tax purposes. It is partially offset by favorable tax adjustments, including the re-measurement of certain unrecognized tax benefits of $28 million related to the Internal Revenue Service (IRS) settlement of tax years 2006 through 2009.


35



2011 Compared to 2010

Net Income.  We reported net income of $1.357 billion ($3.17 per diluted share) for 2011 compared to $442 million ($1.07 per diluted share) for the same period in 2010. The increase in net income of $915 million was primarily due to the resolution of the true-up appeal resulting in an after-tax extraordinary gain of $587 million and a $352 million return on the true-up balance, a $66 million increase in the gain on our indexed debt securities, a $49 million increase in operating income and a $38 million decrease in interest expense due to lower levels of debt, which were partially offset by a $141 million increase in income tax expense and a $48 million decrease in the gain on our marketable securities.

Income Tax Expense.  We reported an effective tax rate of 34.4% for 2011 compared to 37.3% for the same period in 2010. The decrease in the effective tax rate of 2.9% is due to an $18 million reduction to the uncertain tax liability primarily related to the resolution of the tax normalization issue, a $21 million reduction to the deferred tax asset due to the enactment of the Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act recognized in 2010, a $24 million decrease to state tax expense due to the restructuring of certain subsidiaries in December 2010, and a $17 million state tax benefit primarily attributable to lower blended state tax rates and a reduction to the state deferred tax liability recorded in December 2011.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) (in millions) for each of our business segments for 2010, 2011 and 2012. 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,
 
2010
 
2011
 
2012
Electric Transmission & Distribution
$
567

 
$
623

 
$
639

Natural Gas Distribution
231

 
226

 
226

Competitive Natural Gas Sales and Services
16

 
6

 
(250
)
Interstate Pipelines
270

 
248

 
207

Field Services
151

 
189

 
214

Other Operations
14

 
6

 
2

Total Consolidated Operating Income
$
1,249

 
$
1,298

 
$
1,038



36



Electric Transmission & Distribution

The following tables provide summary data of our Electric Transmission & Distribution business segment, CenterPoint Houston, for 2010, 2011 and 2012 (in millions, except throughput and customer data):

 
Year Ended December 31,
 
2010
 
2011
 
2012
Revenues:
 
 
 
 
 
Electric transmission and distribution utility
$
1,768

 
$
1,893

 
$
1,949

Transition and system restoration bond companies
437

 
444

 
591

Total revenues
2,205

 
2,337

 
2,540

Expenses:
 

 
 

 
 

Operation and maintenance, excluding transition and system restoration bond companies
841

 
908

 
942

Depreciation and amortization, excluding transition and system restoration bond companies
293

 
279

 
301

Taxes other than income taxes
207

 
210

 
214

Transition and system restoration bond companies
297

 
317

 
444

Total expenses
1,638

 
1,714

 
1,901

Operating Income
$
567

 
$
623

 
$
639

 
 
 
 
 
 
Operating Income:
 

 
 

 
 

Electric transmission and distribution operations
$
427

 
$
496

 
$
492

Transition and system restoration bond companies (1) 
140

 
127

 
147

Total segment operating income
$
567

 
$
623

 
$
639

Throughput (in gigawatt-hours (GWh)):
 

 
 

 
 

Residential
26,554

 
28,511

 
27,315

Total
76,973

 
80,013

 
78,593

Number of metered customers at end of period:
 

 
 

 
 

Residential
1,867,251

 
1,904,818

 
1,943,423

Total
2,110,608

 
2,155,710

 
2,199,764

___________________
(1)
Represents the amount necessary to pay interest on the transition and system restoration bonds.

2012 Compared to 2011.  Our Electric Transmission & Distribution business segment reported operating income of $639 million for 2012, consisting of $492 million from our regulated electric transmission and distribution utility operations (TDU) and $147 million related to transition and system restoration bond companies. For 2011, operating income totaled $623 million, consisting of $496 million from the TDU and $127 million related to transition and system restoration bond companies. TDU operating income decreased $4 million due to decreased usage ($54 million), primarily due to a return to more normal summer weather when compared to the previous year, and the impact of the 2010 rate case implemented in September 2011 ($34 million), partially offset by higher equity returns ($28 million) primarily related to true-up proceeds, increased miscellaneous revenues ($24 million), primarily from right-of-way easement grants, customer growth ($24 million) from the addition of over 44,000 new customers and decreased labor and benefits costs ($6 million).
 
2011 Compared to 2010.  Our Electric Transmission & Distribution business segment reported operating income of $623 million for 2011, consisting of $496 million from our TDU and $127 million related to transition and system restoration bond companies. For 2010, operating income totaled $567 million, consisting of $427 million from the TDU and $140 million related to transition and system restoration bond companies. TDU operating income increased $69 million due to increased usage ($51 million), primarily due to favorable weather, customer growth ($22 million) from the addition of over 45,000 new customers, lower depreciation expense ($16 million) and higher transmission-related revenues net of the costs billed by transmission providers ($13 million), partially offset by the impact of the 2010 rate case implemented in September 2011 ($12 million) and other operating expense increases ($12 million).


37



Natural Gas Distribution

The following table provides summary data of our Natural Gas Distribution business segment for 2010, 2011 and 2012 (in millions, except throughput and customer data):
 
 
Year Ended December 31,
 
2010
 
2011
 
2012
Revenues
$
3,213

 
$
2,841

 
$
2,342

Expenses:
 

 
 

 
 

Natural gas
2,049

 
1,675

 
1,196

Operation and maintenance
639

 
655

 
637

Depreciation and amortization
166

 
166

 
173

Taxes other than income taxes
128

 
119

 
110

Total expenses
2,982

 
2,615

 
2,116

Operating Income
$
231

 
$
226

 
$
226

Throughput (in Bcf):
 

 
 

 
 

Residential
177

 
172

 
140

Commercial and industrial
249

 
251

 
243

Total Throughput
426

 
423

 
383

Number of customers at end of period:
 

 
 

 
 

Residential
3,016,333

 
3,036,267

 
3,058,695

Commercial and industrial
246,891

 
246,220

 
246,413

Total
3,263,224

 
3,282,487

 
3,305,108

 
2012 Compared to 2011.  Our Natural Gas Distribution business segment reported operating income of $226 million for each of 2012 and 2011. Operating income was unchanged despite substantially reduced revenues from near record mild temperatures in the first quarter of 2012 that were partially mitigated by weather hedges and weather normalization adjustments ($21 million), increased depreciation and amortization expense ($7 million) and increased property taxes ($4 million). These adverse impacts were offset by certain reduced operation and maintenance expenses ($5 million), lower bad debt expense ($7 million), the addition of over 22,000 customers ($6 million) and rate increases ($12 million). Decreased expense related to energy efficiency programs ($4 million) and decreased expense related to lower gross receipts taxes ($12 million) were offset by a corresponding reduction in the related revenues.

2011 Compared to 2010.  Our Natural Gas Distribution business segment reported operating income of $226 million for 2011 compared to $231 million for 2010. Operating income decreased $5 million primarily as a result of higher benefit costs ($8 million), lower miscellaneous revenues ($7 million) and higher other expenses ($9 million). These were partially offset by the addition of 19,000 customers ($5 million), lower bad debt expense ($8 million) and rate increases ($7 million).  Increased expense related to energy efficiency programs ($19 million) and decreased expense related to lower gross receipt taxes ($10 million) were offset by the related revenues.


38



Competitive Natural Gas Sales and Services

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for 2010, 2011 and 2012 (in millions, except throughput and customer data):

 
Year Ended December 31,
 
2010
 
2011
 
2012
Revenues
$
2,651

 
$
2,511

 
$
1,784

Expenses:
 

 
 

 
 

Natural gas
2,591

 
2,458

 
1,730

Operation and maintenance
38

 
41

 
45

Depreciation and amortization
4

 
5

 
6

Taxes other than income taxes
2

 
1

 
1

Goodwill impairment

 

 
252

Total expenses
2,635

 
2,505

 
2,034

Operating Income (Loss)
$
16

 
$
6

 
$
(250
)
 
 
 
 
 
 
Throughput (in Bcf)
548

 
558

 
562

 
 
 
 
 
 
Number of customers at end of period (1)
12,193

 
14,267

 
16,330

___________________
(1)
These numbers do not include approximately 12,700 natural gas customers as of December 31, 2012 that are under residential and small commercial choice programs invoiced by their host utility.

2012 Compared to 2011. Our Competitive Natural Gas Sales and Services business segment reported operating income, excluding the goodwill impairment discussed below, of $2 million for 2012 compared to $6 million for 2011.  The decrease in operating income of $4 million was primarily due to a $24 million negative impact of mark-to-market accounting for derivatives associated with certain forward natural gas purchases and sales used to lock in economic margins. 2012 included mark-to-market charges of $16 million compared to a $8 million benefit for the same period of 2011.  Substantially offsetting this decrease was a $20 million improvement in operating margins primarily as a result of the termination of uneconomic transportation contracts and an increase in retail sales customers and volumes.

2011 Compared to 2010. Our Competitive Natural Gas Sales and Services business segment reported operating income of $6 million for 2011 compared to $16 million for 2010.  The decrease in operating income of $10 million was primarily due to reduced basis spreads on pipeline transport opportunities and decreased seasonal storage spreads of $9 million in 2011, which included a $5 million charge related to an early capacity release on pipeline transportation, as compared to 2010.  Additionally, an $11 million write-down of natural gas inventory to the lower of cost or market occurred in 2011 as compared to a $6 million write-down in 2010. Offsetting these decreases to operating income is an increase in operating income of $4 million related to the favorable impact of the mark-to-market valuation for non-trading financial derivatives for 2011 of $8 million versus the favorable impact of $4 million for 2010.

Goodwill Impairment

A non-cash goodwill impairment charge of $252 million for our Competitive Natural Gas Sales and Services business segment was recorded in 2012. The adverse wholesale market conditions facing our energy services business, specifically the prospects for continued low geographic and seasonal price differentials for natural gas, led to a reduction in our estimate of the fair value of goodwill associated with this reporting unit. See Note 4 to our consolidated financial statements for further discussion of the goodwill impairment charge.


39



Interstate Pipelines

The following table provides summary data of our Interstate Pipelines business segment for 2010, 2011 and 2012 (in millions, except throughput data):

 
Year Ended December 31,
 
2010
 
2011
 
2012
Revenues
$
601

 
$
553

 
$
502

Expenses:
 

 
 

 
 

Natural gas
93

 
67

 
57

Operation and maintenance
153

 
152

 
153

Depreciation and amortization
52

 
54

 
56

Taxes other than income taxes
33

 
32

 
29

Total expenses
331

 
305

 
295

Operating Income
$
270

 
$
248

 
$
207

 
 
 
 
 
 
Equity in earnings of unconsolidated affiliates
$
19

 
$
21

 
$
26

 
 
 
 
 
 
Transportation throughput (in Bcf)
1,693

 
1,579

 
1,367


2012 Compared to 2011.  Our Interstate Pipeline business segment reported operating income of $207 million for 2012 compared to $248 million for 2011. Operating income decreased $41 million primarily due to lower margins resulting from a backhaul contract that expired in 2011 ($16 million), as well as the associated reduction in compressor efficiency ($8 million) on the Carthage to Perryville pipeline due to lower volumes, lower off-system transportation revenues ($8 million), lower seasonal and market-sensitive transportation contracts ($7 million) and ancillary services ($7 million). These margin decreases were partially offset by the effects of the 10-year agreement with our natural gas distribution affiliate ($5 million) which we restructured in 2010. Operating income decreases due to higher operations and maintenance expenses ($1 million) and higher depreciation and amortization expenses ($2 million) due to asset additions were offset by lower taxes other than income taxes ($3 million).

2011 Compared to 2010.  Our Interstate Pipeline business segment reported operating income of $248 million for 2011 compared to $270 million for 2010. Operating income decreased $22 million primarily due to a backhaul contract that expired in 2011 ($22 million), as well as the effects of the restructured 10-year agreement with our natural gas distribution affiliate ($11 million) and lower off-system revenues ($11 million). These margin decreases were partially offset by new firm transportation contracts and higher ancillary revenues ($22 million). Operating income increases due to lower operation and maintenance expenses ($1 million) and lower taxes other than income ($1 million) were offset by increased depreciation and amortization expenses ($2 million) related to new assets.

Equity Earnings. In addition, this business segment recorded equity income of $19 million, $21 million and $26 million for the years ended December 31, 2010, 2011 and 2012, respectively, from its 50% interest in Southeast Supply Header, LLC (SESH), a jointly-owned pipeline. The 2012 increase in equity earnings primarily resulted from restructuring and extending a long-term agreement with an anchor shipper at the end of 2011. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption in the Statements of Consolidated Income.


40



Field Services

The following table provides summary data of our Field Services business segment for 2010, 2011 and 2012 (in millions, except throughput data):

 
Year Ended December 31,
 
2010
 
2011
 
2012
Revenues
$
338

 
$
412

 
$
506

Expenses:
 

 
 

 
 

Natural gas
72

 
68

 
122

Operation and maintenance
85

 
112

 
115

Depreciation and amortization
25

 
37

 
50

Taxes other than income taxes
5

 
6

 
5

Total expenses
187

 
223

 
292

Operating Income
$
151

 
$
189

 
$
214

 
 
 
 
 
 
Equity in earnings of unconsolidated affiliates
$
10

 
$
9

 
$
5

 
 
 
 
 
 
Gathering throughput (in Bcf)
650

 
823

 
896


2012 Compared to 2011.  Our Field Services business segment reported operating income of $214 million for 2012 compared to $189 million for 2011. Operating income increased $25 million primarily from increased margins ($36 million) due to gathering projects in the Haynesville shale, including revenues from throughput guarantees, growth in gathering services and retained natural gas volumes, and acquisitions completed during 2012 ($13 million), partially offset by lower commodity prices ($28 million) on sales of retained natural gas. Operating income also increased ($3 million) due to the classification of earnings from the 50% partnership interest in Waskom which we already owned as operating income beginning in August 2012 instead of equity earnings as reported for prior periods, due to our July 31, 2012 purchase of the 50% interest in Waskom that we did not already own. Lower operation and maintenance expenses ($7 million) were partially offset by higher depreciation expense ($6 million).

2011 Compared to 2010.  Our Field Services business segment reported operating income of $189 million for 2011 compared to $151 million for 2010. Operating income increased $38 million primarily from increased margins due to gathering projects in the Haynesville and Fayetteville shales and growth in core gathering services, including revenues from throughput guarantees ($88 million), partially offset by lower commodity prices ($10 million) from sales of retained natural gas and reduced processing margins. Increases in operation and maintenance expenses ($6 million), depreciation expense ($12 million) and taxes other than income ($1 million) resulted primarily from the expansion of the Magnolia and Olympia gathering systems in North Louisiana. In addition, operating expenses in 2010 benefited from a gain on the sale of non-strategic gathering assets ($21 million).

Equity Earnings. In addition, this business segment recorded equity income of $10 million, $9 million and $5 million for the years ended December 31, 2010, 2011 and 2012, respectively, from its 50% interest in Waskom. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption in the Statements of Consolidated Income. As discussed above, beginning on August 1, 2012, financial results for Waskom are included in operating income.

Other Operations

The following table provides summary data for our Other Operations business segment for 2010, 2011 and 2012 (in millions):

 
Year Ended December 31,
 
2010
 
2011
 
2012
Revenues
$
11

 
$
11

 
$
11

Expenses (Income)
(3
)
 
5

 
9

Operating Income
$
14

 
$
6

 
$
2


41




LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The net cash provided by (used in) operating, investing and financing activities for 2010, 2011 and 2012 is as follows (in millions):

 
Year Ended December 31,
 
2010
 
2011
 
2012
Cash provided by (used in):
 
 
 
 
 
Operating activities
$
1,386

 
$
1,888

 
$
1,860

Investing activities
(1,420
)
 
(1,206
)
 
(1,603
)
Financing activities
(507
)
 
(661
)
 
169


Cash Provided by Operating Activities

Net cash provided by operating activities decreased $28 million in 2012 compared to 2011 primarily due to increased net tax payments ($251 million) , which was partially offset by increased cash provided by net accounts receivable/payable ($45 million), increased cash provided by net regulatory assets and liabilities ($35 million), increased cash from non-trading derivatives ($33 million), increased cash related to gas storage inventory ($25 million), decreased net margin deposits ($19 million) and increased cash provided by fuel cost recovery ($18 million).

Net cash provided by operating activities increased $502 million in 2011 compared to 2010 primarily due to increased tax refunds ($412 million), increased cash related to gas storage inventory ($41 million), decreased net margin deposits ($27 million) and increased cash provided by net regulatory assets and liabilities ($17 million), which were partially offset by decreased cash provided by net accounts receivable/payable ($108 million) and decreased cash provided by fuel cost recovery ($61 million).

Cash Used in Investing Activities

Net cash used in investing activities increased $397 million in 2012 compared to 2011 due to increased cash paid for acquisitions ($360 million) and decreased cash received from the DOE grant ($110 million), which were partially offset by decreased capital expenditures ($91 million).

Net cash used in investing activities decreased $214 million in 2011 compared to 2010 due to decreased capital expenditures ($206 million) and increased cash received from the DOE grant ($20 million).

Cash Provided by (Used in) Financing Activities

Net cash provided by financing activities increased $830 million in 2012 compared to 2011 primarily due to increased proceeds from long-term debt ($1,945 million) and decreased debt issuance costs ($8 million), which were partially offset by increased payments of long-term debt ($681 million), increased payments of commercial paper ($387 million), decreased short-term borrowings ($33 million), increased cash paid for debt retirement ($11 million) and increased payments of common stock dividends ($9 million).

Net cash used in financing activities increased $154 million in 2011 compared to 2010 primarily due to decreased proceeds from the issuance of common stock ($410 million), increased payments of long-term debt ($126 million), decreased proceeds from commercial paper ($81 million), increased cash paid for debt exchange ($58 million), increased debt issuance costs ($22 million) and increased common stock dividend payments ($18 million), which were partially offset by increased proceeds from long-term debt ($550 million) and increased short-term debt borrowings ($11 million).


42



Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Our principal anticipated cash requirements for 2013 include the following:

capital expenditures of approximately $1.7 billion;

the retirement of CenterPoint Houston and CERC long-term debt aggregating $815 million;

scheduled principal payments on transition and system restoration bonds of $447 million;

pension contributions aggregating approximately $83 million; and

dividend payments on CenterPoint Energy common stock and interest payments on debt.

We expect that cash on hand, borrowings under our credit facilities, proceeds from commercial paper and anticipated cash flows from operations will be sufficient to meet our anticipated cash needs in 2013. Cash needs or discretionary financing or refinancing may result in the issuance of equity or debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available to us on acceptable terms.

The following table sets forth our capital expenditures for 2012 and estimates of our capital expenditures for currently identified or planned projects for 2013 through 2017 (in millions): 
 
2012
 
2013
 
2014
 
2015
 
2016
 
2017
Electric Transmission & Distribution
$
599

 
$
720

 
$
677

 
$
557

 
$
534

 
$
512

Natural Gas Distribution
359

 
422

 
420

 
400

 
387

 
393

Competitive Natural Gas Sales and Services
6

 
9

 
25

 
37

 
36

 
11

Interstate Pipelines
132

 
201

 
212

 
128

 
136

 
126

Field Services
52

 
271

 
114

 
88

 
70

 
71

Other Operations
40

 
43

 
30

 
45

 
56

 
52

Total                                                             
$
1,188

 
$
1,666

 
$
1,478

 
$
1,255

 
$
1,219

 
$
1,165


Our capital expenditures are expected to be used for investment in infrastructure for our electric transmission and distribution operations, and our natural gas transmission, distribution and gathering operations. These capital expenditures are anticipated to maintain reliability and safety as well as expand our systems through value-added projects.


43



The following table sets forth estimates of our contractual obligations, including payments due by period (in millions):
Contractual Obligations
 
Total
 
2013
 
2014-2015
 
2016-2017
 
2018 and
thereafter
Transition and system restoration bond debt
 
$
3,847

 
$
447

 
$
726

 
$
802

 
$
1,872

Other long-term debt (1)
 
6,555

 
815

 
579

 
953

 
4,208

Interest payments — transition and system restoration bond debt (2)
 
730

 
135

 
228

 
176

 
191

Interest payments — other long-term debt (2)
 
3,759

 
327

 
579

 
497

 
2,356

Short-term borrowings
 
38

 
38

 

 

 

Capital leases
 
1

 

 

 

 
1

Operating leases (3)
 
48

 
12

 
15

 
8

 
13

Benefit obligations (4)
 

 

 

 

 

Purchase obligations (5)
 
4

 
4

 

 

 

Non-trading derivative liabilities
 
16

 
14

 
2

 

 

Other commodity commitments (6)
 
1,389

 
430

 
558

 
245

 
156

Other
 
6

 
6

 

 

 

Total contractual cash obligations
 
$
16,393

 
$
2,228

 
$
2,687

 
$
2,681

 
$
8,797

___________________

(1)
2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) obligations are included in the 2018 and thereafter column at their contingent principal amount as of December 31, 2012 of $784 million.  These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($540 million at December 31, 2012), as discussed in Note 9 to our consolidated financial statements.  

(2)
We calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, we calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, we used interest rates in place as of December 31, 2012. We typically expect to settle such interest payments with cash flows from operations and short-term borrowings.

(3)
For a discussion of operating leases, please read Note 13(c) to our consolidated financial statements.

(4)
In 2013, we expect to make contributions to our qualified pension plan aggregating approximately $83 million. We expect to contribute approximately $9 million and $18 million, respectively, to our non-qualified pension and postretirement benefits plans in 2013.

(5)
Represents capital commitments for material in connection with our Interstate Pipelines business segment.

(6)
For a discussion of other commodity commitments, please read Note 13(a) to our consolidated financial statements.

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

Prior to the distribution of our ownership in RRI to our 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 (now GenOn) 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 based on an annual calculation, with any required collateral to be posted each December.  The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $73 million as of December 31, 2012.  Based on market conditions in the fourth quarter of 2012 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. As a result, CenterPoint Energy returned to GenOn in the fourth quarter of 2012 the approximately $28 million of aggregate collateral previously posted by GenOn under the agreement. If GenOn should fail to perform the contractual

44



obligations, CERC could have to honor its guarantee and, in such event, any collateral then provided as security may be insufficient to satisfy CERC’s obligations.

Regulatory Matters. Regulatory developments that have occurred since our 2011 Form 10-K was filed with the Securities and Exchange Commission (SEC) are discussed below.

CenterPoint Houston
 
June 2010 Rate Case. The order on rehearing issued by the Public Utility Commission of Texas (Texas Utility Commission) in connection with CenterPoint Houston's 2010 rate case was appealed to the Texas courts by various parties and a trial was scheduled for December 2012. In December 2012, the parties entered into a settlement agreement prior to the trial dismissing all material provisions of the appeals.

Other.  In May 2012, CenterPoint Houston filed an application, subsequently modified consistent with the Texas Utility Commission's preliminary order, requesting approval to recover a total of approximately $47.5 million in 2013 consisting of: (1) estimated 2013 energy efficiency program costs of $42.9 million; (2) a credit of $1.8 million related to the over-recovery of 2011 program costs; (3) a performance incentive for 2011 program achievements of $6.3 million and (4) certain rate case expenses.  In October 2012, the Texas Utility Commission approved a settlement agreement filed by the parties to recover a total of $46.2 million.  The $1.3 million reduction was attributable to settlement spending from CenterPoint Houston's 2006 rate settlement included in the 2011 performance incentive calculation.  The settlement preserves the right for CenterPoint Houston to appeal the reduction in its requested performance bonus amount.  The rates took effect with the commencement of CenterPoint Houston's January 2013 billing month.

Gas Operations

Beaumont/East Texas Rate Case. In July 2012, the natural gas distribution business of CERC (Gas Operations) filed a general rate case with the Railroad Commission of Texas (Railroad Commission) and certain municipalities requesting an increase of approximately $8.6 million based on a proposed rate of return of 9.09%, a return on equity (ROE) of 11.00%, and a capital structure with 42% debt and 58% equity. Rates went into effect in August 2012 for 24 cities.  All other cities suspended the rates for up to 90 days or denied any increase outright. The Railroad Commission suspended the rates for the environs and for the cities that have given up original jurisdiction for up to 150 days. On November 5, 2012, rates went into effect for another 13 cities. On November 15, 2012, a Unanimous Settlement Agreement was signed by all parties and resolved all issues resulting in a net revenue requirement increase of $6.2 million. On December 4, 2012, the Railroad Commission approved the Unanimous Settlement Agreement of $6.2 million and rates went into effect on December 7, 2012. Beginning January 2, 2013, a rate case expense surcharge of $0.16 was implemented and will only affect customers in the cities that gave up original jurisdictions and cities and environs of all parties involved in the Unanimous Settlement Agreement. The rate case expense surcharge will continue over the next 36 months or until all approved expenses are collected.
 
Mississippi Regulatory Rate Adjustment (RRA). In May 2012, Gas Operations and the Mississippi Public Utility Staff filed a joint stipulation for the revised RRA and initial Weather Normalization Adjustment which the Mississippi Public Service Commission (MPSC) approved in May 2012.   In June 2012, Gas Operations requested an annual increase of approximately $2.2 million under the newly revised RRA based on calendar year 2011. New rates reflecting an increase of approximately $1.7 million, as approved by the MPSC, took effect on September 20, 2012.

Minnesota Conservation Improvement Program (CIP). In May 2012, Gas Operations filed a request with the Minnesota Public Utilities Commission (MPUC) for a $4.6 million CIP incentive. The MPUC approved the incentive in December 2012.

Oklahoma Performance Based Rate Change (PBRC). In March 2012, Gas Operations filed a PBRC with the Oklahoma Corporation Commission (OCC) showing that it had earnings for 2011 above the prescribed threshold and would refund approximately $1.9 million to customers beginning in July 2012.  The OCC issued a final order approving the refund on June 6, 2012.   

Houston and South Texas Gas Reliability Infrastructure Programs (GRIP). Gas Operations' Houston and South Texas Divisions each submitted annual GRIP filings on March 30, 2012.  For the Houston division, the filing was to recover costs related to $51.2 million in incremental capital expenditures that were incurred in 2011.  The increase in revenue requirements for this filing period was $9.4 million annually based on an authorized rate of return of 8.65%.  For the South Texas division, the filing was to recover costs related to $14.5 million in incremental capital expenditures that were incurred since the last rate case.  The increase in revenue requirements for this filing period was $2.4 million annually based on an authorized rate of return of 8.75%.  In June 2012, the

45



Railroad Commission approved both GRIP applications as filed, and the new rates were implemented in July 2012 in the applicable cities, with the exception of Houston and Pasadena. Lower GRIP rates were implemented in July 2012 for these two cities, subject to final action by the Railroad Commission. In September 2012, the Railroad Commission approved the GRIP rates as originally filed and the rates were then implemented in the two remaining cities.

City of Houston Gas Utility Rate Inquiry.  In July 2012, the City Council of Houston adopted an ordinance to initiate a formal inquiry regarding the reasonableness of the rates charged by Gas Operations in its Houston service territory.  On January 16, 2013, the City Council of Houston voted to require a rate filing by Gas Operations by March 22, 2013. Gas Operations and the City of Houston have agreed to postpone filing of a response to the rate inquiry until at least September 2013.

Interstate Pipelines

CenterPoint Energy-Mississippi River Transmission, LLC Rate Filing. In August 2012, our subsidiary, CenterPoint Energy-Mississippi River Transmission, LLC (MRT), an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas, Illinois and Missouri, made a rate filing with the Federal Energy Regulatory Commission (FERC) pursuant to Section 4 of the Natural Gas Act. In its filing, MRT requested an annual cost of service of $103.8 million (an increase of approximately $47.3 million above the annual cost of service underlying the current FERC approved maximum rates for MRT's pipeline), new depreciation rates, an overall rate of return of 10.813% (based on a return on equity of 13.62%), a regulatory compliance cost (RCC) surcharge with a true-up mechanism to recover safety, environmental, and security costs associated with mandated requirements and billing determinants reflecting no adjustments for MRT's conversion of a portion of CenterPoint Energy Gas Transmission Company, LLC’s (CEGT) firm capacity to a lease. In August 2012, a number of parties filed protests in response to MRT's rate filing. In September 2012, the FERC issued an order accepting MRT's filing, suspending the filed tariff rates for the full statutorily permitted five month suspension period and setting certain issues for hearing. In particular, the FERC limited the scope of the RCC surcharge set for hearing to the recovery of only security costs. In October 2012, MRT requested rehearing as to the proper scope of the RCC surcharge. The procedural schedule for the rate filing contemplates a hearing at the FERC in the third quarter of 2013.

CEGT Rate Settlement Proceeding. In an effort to avoid the expense of a rate case, in October 2012 CEGT initiated a settlement process with its customers. Should these discussions fail, CEGT will consider filing with the FERC for a general rate increase in 2013. CEGT will attempt to reach a mutually agreeable rate solution with its customers to recover the increased costs to maintain a safe and reliable system, but there can be no assurance that it will be successful or will avoid the initiation of a general rate case filing.

Debt Financing Transactions. In January 2012, Bond Company IV issued $1.695 billion of transition bonds in three tranches with interest rates ranging from 0.9012% to 3.0282% and final maturity dates ranging from April 15, 2018 to October 15, 2025. Through the issuance of these transition bonds, CenterPoint Houston recovered the additional true-up balance of $1.695 billion, less approximately $10.4 million of offering expenses. The transition bonds will be repaid through a charge imposed on customers in CenterPoint Houston’s service territory.
 
In February 2012, we purchased $275 million aggregate principal amount of pollution control bonds issued on our behalf at 100% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds. The purchased pollution control bonds will remain outstanding and may be remarketed. Prior to the purchase, the pollution control bonds had fixed interest rates ranging from 5.15% to 5.95%. The purchases reduced temporary investments and leverage while providing us with the flexibility to finance future capital needs in the tax-exempt market through the remarketing of these bonds. Additionally, in March 2012, we redeemed $100 million aggregate principal amount of pollution control bonds issued on our behalf at 100% of their principal amount plus accrued interest pursuant to the optional redemption provisions of the bonds. The redeemed pollution control bonds had a fixed interest rate of 5.25%.

In August 2012, CenterPoint Houston issued $300 million of 2.25% general mortgage bonds due 2022 and $500 million of 3.55% general mortgage bonds due 2042. The net proceeds from the sale of the bonds were used to fund a portion of the redemption of the general mortgage bonds discussed below.

In August 2012, CenterPoint Houston redeemed $300 million principal amount of its 5.75% general mortgage bonds due 2014 at a price of 107.332% of their principal amount and $500 million principal amount of its 7.00% general mortgage bonds due 2014 at a price of 109.397% of their principal amount.  Redemption premiums for the two series aggregated approximately $69 million.  


46



Credit Facilities.  As of February 14, 2013, we had the following facilities (in millions): 
Date Executed
 
Company
 
Size of
Facility
 
Amount
Utilized at
February 14, 2013 (1)
 
Termination Date
September 9, 2011
 
CenterPoint Energy
 
$
1,200

 
$
7

(2) 
September 9, 2016
September 9, 2011
 
CenterPoint Houston
 
300

 
4

(2) 
September 9, 2016
September 9, 2011
 
CERC Corp.
 
950

 

 
September 9, 2016
___________________
(1)
Based on the debt (excluding transition and system restoration bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant contained in our $1.2 billion credit facility, we would have been permitted to utilize the full capacity of our credit facilities of $2.5 billion at December 31, 2012.

(2)
Represents outstanding letters of credit.

Our $1.2 billion credit facility can be drawn at the London Interbank Offered Rate (LIBOR) plus 150 basis points based on our current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to EBITDA covenant (as those terms are defined in the facility).   The facility allows for a temporary increase of the permitted ratio in the financial covenant from 5 times to 5.5 times if CenterPoint Houston experiences damage from a natural disaster in its service territory and we certify to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-month period, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date we deliver our certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of our certification or (iii) the revocation of such certification.
 
CenterPoint Houston’s $300 million credit facility can be drawn at LIBOR plus 125 basis points based on CenterPoint Houston’s current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to total capitalization covenant which limits debt to 65% of CenterPoint Houston’s total capitalization.
 
CERC Corp.’s $950 million credit facility can be drawn at LIBOR plus 150 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant which limits debt to 65% of CERC’s total capitalization.

Borrowings under each of the facilities are subject to customary terms and conditions. However, there is no requirement that the borrower make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the three revolving credit facilities, the spread to LIBOR and the commitment fees fluctuate based on the borrower's credit rating. The borrowers are currently in compliance with the various business and financial covenants in the three revolving credit facilities.
 
Our $1.2 billion credit facility backstops our $1.0 billion commercial paper program. The $950 million CERC Corp. credit facility backstops a $915 million commercial paper program. As of December 31, 2012, we and CERC Corp. had no commercial paper outstanding.

Securities Registered with the SEC. CenterPoint Energy, CenterPoint Houston and CERC Corp. have filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of CenterPoint Houston’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of CenterPoint Energy’s shares of common stock, shares of preferred stock, as well as stock purchase contracts and equity units.

Temporary Investments.  As of February 14, 2013, CenterPoint Houston had external temporary investments aggregating $502 million.

Money Pool.  We have a money pool through which the holding company and participating subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under our revolving credit facility or the sale of our commercial paper.<