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EX-12 - COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES - CENTERPOINT ENERGY RESOURCES CORPex12.htm
EX-32.1 - SECTION 1350 CERTIFICATION OF DAVID M. MCCLANAHAN - CENTERPOINT ENERGY RESOURCES CORPex32-1.htm
EX-31.2 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF GARY L. WHITLOCK - CENTERPOINT ENERGY RESOURCES CORPex31-2.htm
EX-32.2 - SECTION 1350 CERTIFICATION OF GARY L. WHITLOCK - CENTERPOINT ENERGY RESOURCES CORPex32-2.htm
EX-31.1 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF DAVID M. MCCLANAHAN - CENTERPOINT ENERGY RESOURCES CORPex31-1.htm


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549

FORM 10-Q

(Mark One)
R
QUARTERLY  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009
OR
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
FOR THE TRANSITION PERIOD FROM              TO             



Commission file number 1-13265

CENTERPOINT ENERGY RESOURCES CORP.

(Exact name of registrant as specified in its charter)

Delaware
76-0511406
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
   
1111 Louisiana
 
Houston, Texas 77002
(713) 207-1111
(Address and zip code of principal executive offices)
(Registrant’s telephone number, including area code)
 
 
CenterPoint Energy Resources Corp. meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

Indicate by check mark whether the registrant:  (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes R  No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £  No £

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

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

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

As of October 19, 2009, all 1,000 shares of CenterPoint Energy Resources Corp. common stock were held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy, Inc.
 




CENTERPOINT ENERGY RESOURCES CORP.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2009


 
PART I.
 
FINANCIAL INFORMATION
   
         
Item 1.
   
1
         
       
   
Three and Nine months Ended September 30, 2008 and 2009 (unaudited)
 
1
         
       
   
December 31, 2008 and September 30, 2009 (unaudited)
 
2
         
       
   
Nine months Ended September 30, 2008 and 2009 (unaudited)
 
4
         
     
5
         
Item 2.
   
21
         
  Item 4T.
   
31
         
PART II.
 
OTHER INFORMATION
   
         
Item 1.
   
31
         
   Item 1A.
   
32
         
Item 5.
   
38
         
Item 6.
   
38



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

The following are some of the factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements:

 
state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, environmental regulations, including regulations related to global climate change and health care reform, and changes in or application of laws or regulations applicable to the various aspects of our business;
 
 
timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;
 
 
cost overruns on major capital projects that cannot be recouped in prices;
 
 
industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns;
 
 
the timing and extent of changes in commodity prices, particularly natural gas and natural gas liquids;
 
 
the timing and extent of changes in the supply of natural gas, including supplies available for gathering by our field services business;
 
 
the timing and extent of changes in natural gas basis differentials;
 
 
weather variations and other natural phenomena;
 
 
changes in interest rates or rates of inflation;
 
 
commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;
 
 
actions by rating agencies;
 
 
effectiveness of our risk management activities;
 
 
inability of various counterparties to meet their obligations to us;
 
 
non-payment for our services due to financial distress of our customers;
 
 
the ability of RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;
 
 
the outcome of litigation brought by or against us;
 
 
our ability to control costs;
 
 
 
the investment performance of CenterPoint Energy, Inc.’s employee benefit plans;
 
 
our potential business strategies, including acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us;
 
 
acquisition and merger activities involving our parent or our competitors; and
 
 
other factors we discuss in “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q and other reports we file from time to time with the Securities and Exchange Commission.
 
You should not place undue reliance on forward-looking statements.  Each forward-looking statement speaks only as of the date of the particular statement.
 


PART I.  FINANCIAL INFORMATION



(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(Millions of Dollars)
(Unaudited)

   
Three Months Ended
September 30,
   
Nine months Ended
September 30,
 
   
2008
   
2009
   
2008
   
2009
 
                         
Revenues
  $ 1,960     $ 965     $ 7,069     $ 4,432  
                                 
Expenses:
                               
Natural gas
    1,532       582       5,675       3,081  
Operation and maintenance
    212       230       601       686  
Depreciation and amortization
    54       58       163       172  
Taxes other than income taxes
    33       31       129       126  
Total
    1,831       901       6,568       4,065  
                                 
Operating Income
    129       64       501       367  
                                 
Other Income (Expense):
Interest and other finance charges
    (51 )     (52 )     (148 )     (159 )
Equity in earnings of unconsolidated affiliates
    23       (3 )     46       8  
Other, net
    3       1       7       4  
Total
    (25 )     (54 )     (95 )     (147 )
                                 
Income Before Income Taxes
    104       10       406       220  
Income tax expense
    (37 )     (5 )     (153 )     (86 )
Net Income
  $ 67     $ 5     $ 253     $ 134  


See Notes to the Interim Condensed Consolidated Financial Statements



(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
(Unaudited)

ASSETS

   
December 31,
2008
   
September 30,
2009
 
Current Assets:
           
Cash and cash equivalents
  $ 1     $ 1  
Accounts and notes receivable, net
    774       331  
Accrued unbilled revenue
    480       99  
Accounts and notes receivable – affiliated companies
    9       15  
Materials and supplies
    54       78  
Natural gas inventory
    441       225  
Non-trading derivative assets
    118       50  
Taxes receivable
          144  
Deferred tax asset, net
    25        
Prepaid expenses and other current assets
    327       264  
Total current assets
    2,229       1,207  
                 
Property, Plant and Equipment:
               
Property, plant and equipment
    6,313       6,743  
Less accumulated depreciation and amortization
    950       1,081  
Property, plant and equipment, net
    5,363       5,662  
                 
Other Assets:
               
Goodwill
    1,696       1,696  
Non-trading derivative assets
    20       15  
Investment in unconsolidated affiliates
    345       471  
Notes receivable from unconsolidated affiliates
    323        
Other
    235       202  
Total other assets
    2,619       2,384  
                 
Total Assets
  $ 10,211     $ 9,253  


See Notes to the Interim Condensed Consolidated Financial Statements



CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED CONSOLIDATED BALANCE SHEETS — (Continued)
(Millions of Dollars)
(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY

   
December 31,
2008
   
September 30,
2009
 
Current Liabilities:
           
Short-term borrowings
  $ 153     $ 40  
Current portion of long-term debt
    7       7  
Accounts payable
    722       282  
Accounts and notes payable — affiliated companies
    33       270  
Taxes accrued
    99       74  
Interest accrued
    54       69  
Customer deposits
    59       65  
Non-trading derivative liabilities
    87       45  
Other
    302       235  
Total current liabilities
    1,516       1,087  
                 
Other Liabilities:
               
Accumulated deferred income taxes, net
    864       1,052  
Non-trading derivative liabilities
    47       42  
Benefit obligations
    114       108  
Regulatory liabilities
    508       533  
Other
    101       142  
Total other liabilities
    1,634       1,877  
                 
Long-term Debt
    3,712       2,805  
                 
Commitments and Contingencies (Note 11)
               
                 
Stockholder’s Equity:
               
Common stock
           
Paid-in capital
    2,416       2,416  
Retained earnings
    935       1,069  
Accumulated other comprehensive loss
    (2 )     (1 )
Total stockholder’s equity
    3,349       3,484  
                 
Total Liabilities and Stockholder’s Equity
  $ 10,211     $ 9,253  


See Notes to the Interim Condensed Consolidated Financial Statements


(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
(Unaudited)

   
Nine months Ended September 30,
 
   
2008
   
2009
 
Cash Flows from Operating Activities:
           
Net income
  $ 253     $ 134  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    163       172  
Amortization of deferred financing costs
    7       7  
Deferred income taxes
    62       235  
Write-down of natural gas inventory
    24       6  
Equity in earnings of unconsolidated affiliates, net of distributions
    (45 )     (4 )
Changes in other assets and liabilities:
               
Accounts receivable and unbilled revenues, net
    469       819  
Accounts receivable/payable, affiliates
    40       (8 )
Inventory
    (241 )     186  
Taxes receivable
    (26 )     (144 )
Accounts payable
    (118 )     (440 )
Fuel cost over (under) recovery
    (11 )     (53 )
Interest and taxes accrued
    (23 )     (10 )
Non-trading derivatives, net
    (22 )     26  
Margin deposits, net
    (96 )     89  
Other current assets
    20       23  
Other current liabilities
    (16 )     (2 )
Other assets
    (1 )     4  
Other liabilities
    (37 )     (10 )
Other, net
    (33 )      
Net cash provided by operating activities
    369       1,030  
                 
Cash Flows from Investing Activities:
               
Capital expenditures
    (358 )     (458 )
Decrease (increase) in notes receivable from unconsolidated affiliates
    (175 )     323  
Investment in unconsolidated affiliates
    (207 )     (111 )
Other, net
    34       (3 )
Net cash used in investing activities
    (706 )     (249 )
                 
Cash Flows from Financing Activities:
               
Decrease in short-term borrowings, net
    (82 )     (113 )
Long-term revolving credit facility, net
    595       (916 )
Proceeds from commercial paper, net
          15  
Proceeds from long-term debt
    300        
Payments of long-term debt
    (307 )     (6 )
Increase (decrease) in notes payable to affiliates
    (67 )     239  
Debt issuance costs
    (2 )      
Dividend to parent
    (100 )      
Net cash provided by (used in) financing activities
    337       (781 )
                 
Net Increase in Cash and Cash Equivalents
           
Cash and Cash Equivalents at Beginning of Period
    1       1  
Cash and Cash Equivalents at End of Period
  $ 1     $ 1  
                 
Supplemental Disclosure of Cash Flow Information:
               
Cash Payments:
               
Interest, net of capitalized interest
  $ 137     $ 136  
Income taxes
    148       18  
Non-cash transactions:
               
Accounts payable related to capital expenditures
    54       51  

See Notes to the Interim Condensed Consolidated Financial Statements



NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1)
Background and Basis of Presentation

General.  Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy Resources Corp. (CERC Corp.) are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy Resources Corp. and its subsidiaries (collectively, CERC). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2008 (CERC Corp. Form 10-K).

Background.  CERC owns and operates natural gas distribution systems in six states. Subsidiaries of CERC Corp. own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

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

Basis of Presentation. The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

CERC’s Interim Condensed Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods.  Amounts reported in CERC’s Condensed Statements of Consolidated Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests.

For a description of CERC’s reportable business segments, see Note 14.

(2)
New Accounting Pronouncements

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

In December 2008, the FASB issued new accounting guidance on employers' disclosures about postretirement benefit plan assets which expands the disclosures about employers’ plan assets to include more detailed disclosures about the employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets and valuation techniques used to measure the fair value of plan assets. This new accounting guidance is effective for fiscal years ending after December 15, 2009. CERC expects that the adoption of this new guidance will not have a material impact on its financial position, results of operations or cash flows.

In April 2009, the FASB issued new accounting guidance on interim disclosures about fair value of financial instruments which expands the fair value disclosures required for all financial instruments to interim periods. This new guidance also requires entities to disclose in interim periods the methods and significant assumptions used to estimate the fair value of financial instruments. This new accounting guidance is effective for interim reporting periods ending after June 15, 2009. CERC’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows.  See Note 13 for the required disclosures.

 
In May 2009, the FASB issued new accounting guidance on subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This new accounting guidance is effective for interim or annual periods ending after June 15, 2009. CERC’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. See Note 16 for the subsequent event related disclosures.

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

In June 2009, the FASB issued new accounting guidance on the FASB Accounting Standards Codification (Codification) and the hierarchy of generally accepted accounting principles.  This new accounting guidance establishes the Codification as the source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This new accounting guidance is effective for financial statements issued for interim and annual periods ending after September 15, 2009. CERC’s adoption of this new guidance did not have any impact on its financial position, results of operations or cash flows.

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

(3)
Employee Benefit Plans

CERC’s employees participate in CenterPoint Energy’s postretirement benefit plan. CERC’s net periodic cost includes the following components relating to postretirement benefits:

   
Three Months Ended
September 30,
   
Nine months Ended
September 30,
 
   
2008
   
2009
   
2008
   
2009
 
   
(in millions)
 
Interest cost
  $ 2     $ 2     $ 6     $ 6  
Expected return on plan assets
    (1 )     (1 )     (1 )     (1 )
Amortization of prior service cost
    1       1       2       2  
Net periodic cost
  $ 2     $ 2     $ 7     $ 7  

CERC expects to contribute approximately $16 million to CenterPoint Energy’s postretirement benefit plan in 2009, of which $4 million and $12 million, respectively, have been contributed during the three and nine months ended September 30, 2009.

(4)
Regulatory Matters

(a) Rate Proceedings

Texas. In March 2008, the natural gas distribution businesses of CERC (Gas Operations) filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. In 2008, Gas Operations implemented rates that are expected to increase annual revenues by approximately $3.5 million.  The implemented rates have been contested by 9 cities. CERC does not expect the outcome of this matter to have a material adverse impact on its financial condition, results of operations or cash flows.

 
In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request seeks to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. If approved by the Railroad Commission and the cities, the proposed new rates would result in an overall increase in annual revenue of $25.4 million.  The proposed increase would allow Gas Operations to recover increased operating costs, which include higher pension expense.  It would also provide a return on the additional capital invested to serve its customers.  In addition, Gas Operations is seeking an adjustment mechanism similar to that obtained in the Texas Coast rate proceeding discussed above that would annually adjust rates to reflect changes in capital, expenses and usage. CERC does not expect an order from the Railroad Commission and the cities until the first quarter of 2010.

Minnesota. In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been arbitrary and capricious in denying Gas Operations a waiver. The court ordered the case remanded to the MPUC for reconsideration under the same principles the MPUC had applied in previously granted waiver requests. The MPUC sought further review of the court of appeals decision from the Minnesota Supreme Court, and in July 2008, the Minnesota Supreme Court agreed to review the decision.  In July 2009, the Minnesota Supreme Court issued its decision in which it reversed the decision of the Minnesota Court of Appeals and upheld the MPUC’s decision to deny the requested variance. The court’s decision had no negative impact on CERC’s financial condition, results of operations or cash flows, as the costs at issue were written off at the time they were disallowed.

In November 2008, Gas Operations filed a request with the MPUC to increase its rates for utility distribution service.  If approved by the MPUC, the proposed new rates would result in an overall increase in annual revenue of $59.8 million.  The proposed increase would allow Gas Operations to recover increased operating costs, including higher bad debt and collection expenses, higher pension expenses, the cost of improved customer service and inflationary increases in other expenses.  It also would allow recovery of increased costs related to conservation improvement programs and provide a return on the additional capital invested to serve its customers.  In addition, Gas Operations is seeking an adjustment mechanism that would annually adjust rates to reflect changes in use per customer.  In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. CERC does not expect an order from the MPUC until early 2010.

Mississippi. In July 2009, Gas Operations filed a request with the Mississippi Public Service Commission (MPSC) to increase its rates by $6.2 million annually.  In October 2009, the MPSC issued an order whereby Gas Operations would retain 100% of the benefits of an asset management agreement covering Mississippi pipeline and gas storage capacity, withdraw its request to increase base rates and not file another general rate increase, with certain exceptions, prior to July 1, 2011.

(b) Regulatory Accounting

CERC has a 50% ownership interest in Southeast Supply Header, LLC (SESH) which owns and operates a 270-mile interstate natural gas pipeline.  In 2009, SESH discontinued the use of guidance for accounting for regulated operations, which resulted in CERC recording its share of the effects of such write-offs of SESH’s regulatory assets through non-cash pre-tax charges for the quarters ended March 31, 2009 and September 30, 2009 of $5 million and $11 million, respectively.  These non-cash charges are reflected in equity in earnings of unconsolidated affiliates in the Condensed Statements of Consolidated Income.  The related tax benefits of $2 million and $4 million, respectively, are reflected in the income tax expense line of the Condensed Statements of Consolidated Income.
 

(5)
Derivative Instruments

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

In prior years, CERC entered into certain derivative instruments that were designated as cash flow hedges. The objective of these derivative instruments was to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting CERC’s wholesale and retail customer obligations.  If derivatives are designated as a cash flow hedge, the effective portions of the changes in their fair values are reflected initially as a separate component of stockholder’s equity and subsequently recognized in income at the same time the hedged items impact earnings. The ineffective portions of changes in fair values of derivatives designated as hedges are immediately recognized in income. Changes in derivatives not designated as normal or as cash flow hedges are recognized in income as they occur. CERC does not enter into or hold derivative instruments for trading purposes.

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

CERC’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

(a) Non-Trading Activities

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

During the three months ended September 30, 2008, CERC recorded increased natural gas revenues from unrealized net gains of $80 million and increased natural gas expense from unrealized net losses of $34 million, resulting in a net unrealized gain of $46 million. During the three months ended September 30, 2009, CERC recorded decreased natural gas revenues from unrealized net losses of $37 million and decreased natural gas expense from unrealized net gains of $31 million, resulting in a net unrealized loss of $6 million.

During the nine months ended September 30, 2008, CERC recorded increased natural gas revenues from unrealized net gains of $51 million and increased natural gas expense from unrealized net losses of $37 million, resulting in a net unrealized gain of $14 million. During the nine months ended September 30, 2009, CERC recorded decreased natural gas revenues from unrealized net losses of $71 million and decreased natural gas expense from unrealized net gains of $49 million, resulting in a net unrealized loss of $22 million.

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

In 2007, 2008 and 2009, CERC entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the respective winter heating seasons.  The swaps were based on ten-year normal weather.  During the three and nine months ended September 30, 2008, CERC recognized losses of $-0- and $13 million, respectively, related to these swaps.  During the three and nine months ended September 30, 2009, CERC recognized
 
8

 
losses of $-0- and $3 million, respectively, related to these swaps.  The losses were substantially offset by increased revenues due to colder than normal weather. Weather hedge losses are included in revenues in the Condensed Statements of Consolidated Income.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CERC’s derivative instruments and hedging activities.  The first table provides a balance sheet overview of CERC’s Derivative Assets and Liabilities as of September 30, 2009, while the latter tables provide a breakdown of the related income statement impact for the three and nine months ended September 30, 2009.

Fair Value of Derivative Instruments
 
   
September 30, 2009
 
Total derivatives not designated as hedging
instruments
 
Balance Sheet
Location
 
Derivative
Assets
Fair Value (2) (3)
 
Derivative
Liabilities
Fair Value (2) (3)
 
       
(in millions)
 
Commodity contracts (1)
 
Current Assets
  $ 59   $ (9 )
Commodity contracts (1) 
 
Other Assets
    16     (1 )
Commodity contracts (1)
 
Current Liabilities
    26     (137 )
Commodity contracts (1)
 
Other Liabilities
    2     (94 )
Total                                                                       
  $ 103   $ (241 )
_______
 
(1)
Commodity contracts are subject to master netting arrangements and are presented on a net basis in the Condensed Consolidated Balance Sheets. This netting causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets.

 
(2)
The fair value shown for commodity contracts is comprised of derivative gross volumes totaling 668 billion cubic feet (Bcf) or a net 138 Bcf long position.   Of the net long position, basis swaps constitute 61 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 56 Bcf.

 
(3)
The net of total non-trading derivative assets and liabilities is a $22 million liability as shown on CERC’s Condensed Consolidated Balance Sheets, and is comprised of the commodity contracts derivative assets and liabilities separately shown above offset by collateral netting of $116 million.

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


Income Statement Impact of Derivative Activity
 
Total derivatives not designated as hedging
instruments
 
Income Statement Location
 
Three Months
Ended
September 30, 2009
 
       
(in millions)
 
Commodity contracts
 
Gains (Losses) in Revenue
  $ (4 )
Commodity contracts (1)
 
Gains (Losses) in Expense: Natural Gas
    (27 )
Total
  $ (31 )
_________
 
(1)
The Gains (Losses) in Expense: Natural Gas includes $(31) million of costs associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.


Income Statement Impact of Derivative Activity
 
Total derivatives not designated as hedging
instruments
 
Income Statement Location
 
Nine Months
Ended
September 30, 2009
 
       
(in millions)
 
Commodity contracts
 
Gains (Losses) in Revenue
  $ 80  
Commodity contracts (1)
 
Gains (Losses) in Expense: Natural Gas
    (218 )
Total
  $ (138 )
_________
 
(1)
The Gains (Losses) in Expense: Natural Gas includes $(148) million of costs associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered through purchased gas adjustments.

(c) Credit Risk Contingent Features

CERC enters into financial derivative contracts containing material adverse change provisions.  These provisions require CERC to post additional collateral if the Standard & Poor’s Rating Services or Moody’s Investors Service, Inc. credit rating of CERC is downgraded.  The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at September 30, 2009 is $151 million.  The aggregate fair value of assets that are already posted as collateral at September 30, 2009 is $82 million.  If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at September 30, 2009, $69 million of additional assets would be required to be posted as collateral.

(6)
Fair Value Measurements

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

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

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

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

The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2008 and September 30, 2009, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.

   
Quoted Prices in
Active Markets
for Identical Assets
(Level 1)
   
Significant Other
Observable
Inputs
(Level 2)
   
Significant
Unobservable
Inputs
(Level 3)
   
Netting
Adjustments (1)
   
Balance
as of
December 31,
2008
 
   
(in millions)
 
Assets
                             
Corporate equities
  $ 1     $     $     $     $ 1  
Investments, including money
market funds
    11                         11  
Derivative assets
    8       155       49       (74 )     138  
Total assets
  $ 20     $ 155     $ 49     $ (74 )   $ 150  
Liabilities
                                       
Derivative liabilities
  $ 44     $ 244     $ 107     $ (261 )   $ 134  
Total liabilities
  $ 44     $ 244     $ 107     $ (261 )   $ 134  
__________
 
(1)
Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral held or placed with the same counterparties.

   
Quoted Prices in
Active Markets
for Identical Assets
(Level 1)
   
Significant Other
Observable
Inputs
(Level 2)
   
Significant
Unobservable
Inputs
(Level 3)
   
Netting
Adjustments (1)
   
Balance
as of
September 30,
2009
 
   
(in millions)
 
Assets
                             
Corporate equities
  $ 1     $     $     $     $ 1  
Investments, including money
market funds
    11                         11  
Derivative assets
    2       94       7       (38 )     65  
Total assets
  $ 14     $ 94     $ 7     $ (38 )   $ 77  
Liabilities
                                       
Derivative liabilities
  $ 16     $ 207     $ 18     $ (154 )   $ 87  
Total liabilities
  $ 16     $ 207     $ 18     $ (154 )   $ 87  
__________
 
(1)
Amounts represent the impact of legally enforceable master netting agreements that allow CERC to settle positive and negative positions and also include cash collateral of $116 million posted with the same counterparties.
 

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

   
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
 
   
Derivative assets and liabilities, net
 
   
Three Months Ended September 30,
 
   
2008
   
2009
 
   
(in millions)
 
Beginning balance
  $ 6     $ (17 )
Total unrealized gains or (losses):
               
Included in earnings
    (61 )     2  
Included in regulatory assets
          3  
Purchases, sales, other settlements, net
    (4 )     1 (1)
Ending balance
  $ (59 )   $ (11 )
The amount of total gains for the period included in earnings
attributable to the change in unrealized gains or losses relating to
assets still held at the reporting date
  $ 4     $ 3  
__________
(1)  
Purchases, sales, other settlements, net include a less than $1 million gain associated with price stabilization activities of CERC’s Natural Gas Distribution business segment.

   
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
 
   
Derivative assets and liabilities, net
 
   
Nine Months Ended September 30,
 
   
2008
   
2009
 
   
(in millions)
 
Beginning balance
  $ (3 )   $ (58 )
Total unrealized gains or (losses):
               
Included in earnings
    (52 )      
Included in regulatory assets
          (13 )
Purchases, sales, other settlements, net
    (4 )     60 (1)
Ending balance
  $ (59 )   $ (11 )
The amount of total gains for the period included in earnings
attributable to the change in unrealized gains or losses relating to
assets still held at the reporting date
  $ 9     $ 2  
_________
 
(1)
Purchases, sales, other settlements, net include a $57 million gain associated with price stabilization activities of CERC’s Natural Gas Distribution business segment.

 (7)
Goodwill

Goodwill by reportable business segment as of both December 31, 2008 and September 30, 2009 is as follows (in millions):

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

CERC performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is
 
12

 
generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

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

(8)
Comprehensive Income

The following table summarizes the components of total comprehensive income (net of tax):

   
For the Three Months Ended
September 30,
 
For the Nine Months Ended
September 30,
 
   
2008
   
2009
 
2008
   
2009
 
   
(in millions)
 
Net income
  $ 67     $ 5   $ 253     $ 134  
Other comprehensive income (loss):
                             
Adjustment to pension and other postretirement
plans (net of tax of $1, $-0-, $1 and $1)
    (1 )         (1 )     1  
Reclassification of deferred gain from cash flow
hedges realized in net income (net of tax of $-0-,
$-0-,$2, $-0-)
    (1 )         (5 )      
Other comprehensive income (loss)
    (2 )         (6 )     1  
Comprehensive income
  $ 65     $ 5   $ 247     $ 135  

The following table summarizes the components of accumulated other comprehensive loss:

   
December 31,
2008
   
September 30,
2009
 
   
(in millions)
 
Adjustment to pension and other postretirement plans
    (2 )     (1 )
Total accumulated other comprehensive income
  $ (2 )   $ (1 )

(9)
Related Party Transactions

CERC participates in a “money pool” through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings by CenterPoint Energy under its revolving credit facility or the sale by CenterPoint Energy of its commercial paper. As of December 31, 2008 and September 30, 2009, CERC had borrowings from the money pool of $-0- and $239 million, respectively.

For both the three months ended September 30, 2008 and 2009, CERC had net interest expense related to affiliate borrowings of less than $1 million. For the nine months ended September 30, 2008 and 2009, CERC had net interest expense related to affiliate borrowings of approximately $1 million and less than $1 million, respectively.

CenterPoint Energy provides some corporate services to CERC. The costs of services have been charged directly to CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate. Amounts charged to CERC for these services were $35 million and $39 million for the three months ended September 30, 2008 and 2009, respectively, and $105 million and $115 million for the nine months ended September 30, 2008 and 2009, respectively, and are included primarily in operation and maintenance expenses.

(10)
Short-term Borrowings and Long-term Debt

(a) Short-term Borrowings

Receivables Facility.  On October 9, 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010.  Availability under CERC’s 364-day receivables facility now ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances.  As of December 31, 2008 and September 30, 2009, the facility size was $128 million and $150 million, respectively. As of December 31, 2008 and September 30, 2009, advances under the receivables facilities were $78 million and $40 million, respectively.

Inventory Financing. In December 2008, CERC entered into an asset management agreement whereby it sold $110 million of its natural gas in storage and agreed to repurchase an equivalent amount of natural gas during the 2008-2009 winter heating season for payments totaling $114 million.  This transaction was accounted for as a financing and, as of December 31, 2008 and September 30, 2009, CERC’s financial statements reflect natural gas inventory of $75 million and $-0-, respectively, and a financing obligation of $75 million and $-0-, respectively, related to this transaction.

(b) Long-term Debt

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

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

As of December 31, 2008 and September 30, 2009, CERC Corp. had $926 million and $10 million, respectively, of borrowings under its $915 million credit facility.  There was $-0- and $15 million of outstanding commercial paper backstopped by CERC Corp.’s credit facility as of December 31, 2008 and September 30, 2009, respectively.  CERC Corp. was in compliance with all debt covenants as of September 30, 2009.

(11)
Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Condensed Consolidated Balance Sheets as of December 31, 2008 and September 30, 2009 as these contracts meet the exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of September 30, 2009, minimum payment obligations for natural gas supply commitments are approximately $151 million for the remaining three months in 2009, $449 million in 2010, $466 million in 2011, $383 million in 2012, $371 million in 2013 and $738 million after 2013.

(b) Capital Commitments

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

 
Under the terms of the agreements, CEFS commenced gathering and treating services immediately utilizing the acquired facilities. CEFS will also expand the acquired facilities to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas from their current throughput of over 100 MMcf per day. If EnCana or Shell elect, CEFS will further expand the facilities in order to gather and treat additional future volumes.

New construction to reach capacity of 700 MMcf per day includes more than 200 miles of pipelines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.

Each of the agreements includes volume commitments for which CEFS has exclusive rights to gather Shell’s and EnCana’s natural gas production.

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

(c) Legal, Environmental and Other Regulatory Matters

Legal Matters

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

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

Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in a lawsuit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. In October 2006, the judge considering this matter granted the defendants’ motion to dismiss the suit on
 
 
the ground that the court lacked subject matter jurisdiction over the claims asserted. The plaintiff sought review of that dismissal from the Tenth Circuit Court of Appeals, which affirmed the district court’s dismissal in March 2009. Following dismissal of the plaintiff's motion to the Tenth Circuit for rehearing, the plaintiff sought review by the United States Supreme Court, but his petition for certiorari was denied in October 2009.

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

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

Gas Cost Recovery Litigation. In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas and Arkansas in circuit court in Miller County, Arkansas against CERC Corp., CenterPoint Energy, Entex Gas Marketing Company (EGMC), CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CenterPoint Energy Pipeline Services, Inc. (CEPS), Mississippi River Transmission Corp. (MRT) and various non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT and MRT as defendants. Although the plaintiffs in the Miller County case sought class certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service Commission (APSC). In response to that ruling, in August 2007 the Miller County court stayed but refused to dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court directed the Miller County court to dismiss the entire case for lack of jurisdiction. The Miller County court subsequently dismissed the case in accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines have expired.

In June 2007, CenterPoint Energy, CERC Corp., EGMC and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has exclusive original jurisdiction over the Texas claims asserted in the Miller County case. In October 2007, CEFS and CEPS joined the petition in the Travis County case.  In October 2008, the district court ruled that the Railroad Commission had exclusive original jurisdiction over the Texas claims asserted against CenterPoint Energy, CERC Corp., EGMC and the other defendants in the Miller County case.  In January 2009, the court entered a final declaratory judgment ruling that the Railroad Commission has exclusive jurisdiction over Texas claims.  All appellate deadlines expired without an appeal of the final declaratory judgment.

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

Environmental Matters

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

At September 30, 2009, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of September 30, 2009, CERC had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.

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

Mercury Contamination. CERC’s pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. CERC has found this type of contamination at some sites in the past, and CERC has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs is not known at this time, based on CERC’s experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, CERC believes that the costs of any remediation of these sites will not be material to its financial condition, results of operations or cash flows.

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

Groundwater Contamination Litigation. Predecessor entities of CERC, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al., pending in civil district court in Orleans Parish, Louisiana.  In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants.  Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases.  In January 2009, CERC
 
17

 
and the plaintiffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources, is expected to resolve this litigation. CERC does not expect the outcome of this litigation to have a material adverse impact on its financial condition, results of operations or cash flows.

Other Environmental.  From time to time CERC has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, CERC has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, CERC does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows.

Other Proceedings

CERC is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. CERC regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. CERC does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

(d) Guaranties

Prior to CenterPoint Energy’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary.  When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation.  Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas purchase and transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties.  As of September 30, 2009, RRI was not required to provide security to CERC.  If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

(12)
Income Taxes

During the three months and nine months ended September 30, 2008, the effective tax rate was 36% and 38%, respectively.  During the three months and nine months ended September 30, 2009, the effective tax rate was 49% and 39%, respectively.  Lower pre-tax income in 2009 primarily affected the comparability of the effective tax rate for the three months ended September 30, 2008 and 2009.

The following table summarizes CERC’s uncertain tax positions at December 31, 2008 and September 30, 2009:

   
December 31,
2008
   
September 30,
2009
 
   
(in millions)
 
Liability (receivable) for uncertain tax positions
  $ (12 )   $ 8  
Portion of receivable for uncertain tax positions that, if
recognized, would reduce the effective income tax rate
    1       -  
Interest accrued on uncertain tax positions
    (4 )     (5 )
 
 
(13)
Estimated Fair Value of Financial Instruments
 
The fair values of cash and cash equivalents, investments in debt and equity securities classified as "available-for-sale" and "trading" and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The fair values of non-trading derivative assets and liabilities are equivalent to their carrying amounts in the Condensed Consolidated Balance Sheets at December 31, 2008 and September 30, 2009 and have been determined using quoted market prices for the same or similar instruments when available or other estimation techniques (see Notes 5 and 6). Therefore, these financial instruments are stated at fair value and are excluded from the table below.  The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by the market price.

   
December 31, 2008
 
September 30, 2009
 
   
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
   
(In millions)
 
Financial liabilities:
                 
Long-term debt
  $ 3,719   $ 3,568   $ 2,812   $ 2,939  

(14)
Reportable Business Segments

Because CERC is an indirect wholly owned subsidiary of CenterPoint Energy, CERC’s determination of reportable business segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to business segments. CERC uses operating income as the measure of profit or loss for its business segments.

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

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

   
For the Three Months Ended September 30, 2008
 
   
Revenues from
External
Customers
 
Net
Intersegment
Revenues
 
Operating
Income (Loss)
 
Natural Gas Distribution
  $ 548   $ 2   $ (6 )
Competitive Natural Gas Sales and Services
    1,256     13     35  
Interstate Pipelines
    96     47     55 (1)
Field Services
    60     11     44  
Other Operations
            1  
Eliminations
        (73 )    
Consolidated
  $ 1,960   $   $ 129  
 
   
For the Three Months Ended September 30, 2009
 
   
Revenues from
External
Customers
   
Net
Intersegment
Revenues
 
Operating
Income (Loss)
 
Natural Gas Distribution
  $ 400     $ 2   $ (15 )
Competitive Natural Gas Sales and Services
    395       4     (8 )
Interstate Pipelines
    119       34     64  
Field Services
    51       12     23  
Other Operations
               
Eliminations
          (52    
Consolidated
  $ 965     $   $ 64  

   
For the Nine Months Ended September 30, 2008
       
   
Revenues from
External
Customers
   
Net
Intersegment
Revenues
   
Operating
Income (Loss)
   
Total Assets
as of December 31,
2008
 
Natural Gas Distribution
  $ 2,969     $ 7     $ 119     $ 4,961  
Competitive Natural Gas Sales and Services
    3,599       33       36       1,315  
Interstate Pipelines
    337       131       227 (1)     3,578  
Field Services
    164       27       121 (2)     826  
Other Operations
                (2 )     724  
Eliminations
          (198 )           (1,193 )
Consolidated
  $ 7,069     $     $ 501     $ 10,211  

   
For the Nine Months Ended September 30, 2009
       
   
Revenues from
External
Customers
   
Net
Intersegment
Revenues
   
Operating
Income (Loss)
   
Total Assets
as of September 30,
2009
 
Natural Gas Distribution
  $ 2,334     $ 7     $ 105     $ 4,281  
Competitive Natural Gas Sales and Services
    1,585       11             1,065  
Interstate Pipelines
    355       106       194       3,478  
Field Services
    158       18       72       934  
Other Operations
                (4 )     404  
Eliminations
          (142 )           (909 )
Consolidated
  $ 4,432     $     $ 367     $ 9,253  

 
(1)
Included in operating income of Interstate Pipelines for the three and nine months ended September 30, 2008 is a $7 million loss on pipeline assets removed from service.  Also included in operating income of Interstate Pipelines for the nine months ended September 30, 2008 is an $18 million gain on the sale of two storage development projects.

 
(2)
Included in operating income of Field Services for the nine months ended September 30, 2008 is an $11 million gain related to a settlement and contract buyout of one of its customers and a $6 million gain on the sale of assets.

(15)
Other Currents Assets and Liabilities

Included in other current assets on the Condensed Consolidated Balance Sheets at December 31, 2008 and September 30, 2009 was $128 million and $81 million, respectively of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at December 31, 2008 and September 30, 2009 was $79 million and $21 million, respectively, of over recovered gas cost.

(16)
Subsequent Events

CERC has evaluated all subsequent events through the date these Interim Condensed Financial Statements were issued, which was November 10, 2009.



Item 2.              MANAGEMENT’S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS

The following narrative analysis should be read in combination with our Interim Condensed Financial Statements contained in Item 1 of this report and our Annual Report on Form 10-K for the year ended December 31, 2008 (2008 Form 10-K).

We meet the conditions specified in General Instruction H(1)(a) and (b) to Form 10-Q and are therefore permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies. Accordingly, we have omitted from this report the information called for by Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity Securities and Use of Proceeds), Item 3 (Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of Security Holders). The following discussion explains material changes in our revenue and expense items between the three and nine months ended September 30, 2008 and the three and nine months ended September 30, 2009. Reference is made to “Management’s Narrative Analysis of Results of Operations” in Item 7 of our 2008 Form 10-K.

EXECUTIVE SUMMARY
Recent Events

Long-Term Gas Gathering and Treatment Agreements

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

Under the terms of the agreements, CEFS commenced gathering and treating services immediately utilizing the acquired facilities. CEFS will also expand the acquired facilities to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas from their current throughput of over 100 MMcf per day. If EnCana or Shell elect, CEFS will further expand the facilities in order to gather and treat additional future volumes.

New construction to reach capacity of 700 MMcf per day includes more than 200 miles of pipelines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.

Each of the agreements includes volume commitments for which CEFS has exclusive rights to gather Shell’s and EnCana’s natural gas production.

CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 billion cubic feet per day (Bcf), CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments. Funds for construction will be provided from anticipated cash flows from operations, lines of credit or proceeds from the sale of debt or equity securities.

Debt Transactions

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

On October 7, 2009, the size of CERC Corp.’s revolving credit facility was reduced from $950 million to $915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a lender.  Prior to its removal, Lehman had a $35 million commitment to lend.  All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009.
 
 
On October 9, 2009, we amended our receivables facility to extend the termination date to October 8, 2010.  Availability under our 364-day receivables facility ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances.

Asset Management Agreements

Our natural gas distribution businesses (Gas Operations) entered into various asset management agreements associated with its utility distribution service in Arkansas, Oklahoma, Louisiana, Mississippi and Texas.  Generally, an asset management agreement is a contract between an asset holder and an asset manager that strives to maximize the revenue-earning potential of the asset. In these agreements, Gas Operations agreed to release transportation and storage capacity to another party to manage gas storage, supply and delivery arrangements for Gas Operations when the released capacity is not needed and thereby maximize the value of the assets. Gas Operations will be compensated by the asset manager, in part based on the results of the asset optimization, and entering into the asset management agreements will reduce working capital requirements.   The agreements are expected, subject to regulatory approval, to commence in the fourth quarter of 2009 and to continue for various terms extending up to 2016.

Gas Operations has filed applications with state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma for approval of the applicable asset management agreements and to retain a share of the proceeds, with the remainder to benefit customers.  Commission approval has been obtained in Louisiana, Oklahoma, Mississippi and for one of two agreements in Arkansas.  A filing is expected to be made in Texas in the fourth quarter of 2009.

CONSOLIDATED RESULTS OF OPERATIONS

Our results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities as well as natural gas basis differentials. Our results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates we charge, competition in our various business operations, debt service costs and income tax expense. For more information regarding factors that may affect the future results of operations of our business, please read “Risk Factors” in Item 1A of Part II of this Form 10-Q.

The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2008 and 2009, followed by a discussion of our consolidated results of operations.

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2008
   
2009
   
2008
   
2009
 
   
(in millions)
 
Revenues                                                    
  $ 1,960     $ 965     $ 7,069     $ 4,432  
Expenses:
                               
Natural gas
    1,532       582       5,675       3,081  
Operation and maintenance
    212       230       601       686  
Depreciation and amortization
    54       58       163       172  
Taxes other than income taxes
    33       31       129       126  
Total Expenses
    1,831       901       6,568       4,065  
Operating Income
    129       64       501       367  
Interest and Other Finance Charges
    (51 )     (52 )     (148 )     (159 )
Equity in earnings of unconsolidated affiliates
    23       (3 )     46       8  
Other Income, net
    3       1       7       4  
Income Before Income Taxes
    104       10       406       220  
Income Tax Expense
    (37 )     (5 )     (153 )     (86 )
Net Income
  $ 67     $ 5     $ 253     $ 134  

Three months ended September 30, 2009 compared to three months ended September 30, 2008

We reported net income of $5 million for the three months ended September 30, 2009 compared to $67 million for the same period in 2008.  The decrease in net income of $62 million was primarily due to a $65 million decrease
 
22

 
in operating income from our business segments as discussed below and a $26 million decrease in equity in earnings of unconsolidated affiliates, partially offset by a $32 million decrease in income tax expense.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

We reported net income of $134 million for the nine months ended September 30, 2009 compared to $253 million for the same period in 2008.  The decrease in net income of $119 million was primarily due to a $134 million decrease in operating income from our business segments as discussed below, a $38 million decrease in equity in earnings of unconsolidated affiliates and an $11 million increase in interest and other finance charges, partially offset by a $67 million decrease in income tax expense.

Income Tax Expense. During the three months and nine months ended September 30, 2008, the effective tax rate was 36% and 38%, respectively.  During the three months and nine months ended September 30, 2009, the effective tax rate was 49% and 39%, respectively.  Lower pre-tax income in 2009 primarily affected the comparability of the effective tax rate for the three months ended September 30, 2008 and 2009.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for the three and nine months ended September 30, 2008 and 2009 (in millions), followed by a discussion of the results of operations by business segment based on operating income. 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.

   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
   
2008
   
2009
 
2008
   
2009
 
Natural Gas Distribution
  $ (6 )   $ (15 )   $ 119     $ 105  
Competitive Natural Gas Sales and Services
    35       (8 )     36        
Interstate Pipelines
    55       64       227       194  
Field Services
    44       23       121       72  
Other Operations
    1             (2 )     (4 )
Total Consolidated Operating Income
  $ 129     $ 64     $ 501     $ 367  
 
 
 
 

Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read "Risk Factors Risk Factors Affecting Our Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A of Part II of this Form 10-Q.

The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput and customer data):

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2008
   
2009
   
2008
   
2009
 
Revenues
  $ 550     $ 402     $ 2,976     $ 2,341  
Expenses:
                               
Natural gas
    351       198       2,196       1,538  
Operation and maintenance
    139       157       436       478  
Depreciation and amortization
    40       40       118       121  
Taxes other than income taxes
    26       22       107       99  
Total expenses
    556       417       2,857       2,236  
Operating Income (Loss)
  $ (6 )   $ (15 )   $ 119     $ 105  
                                 
Throughput (in   Bcf):
                               
Residential
    13       13       117       111  
Commercial and industrial
    41       38       171       154  
Total Throughput
    54       51       288       265  
                                 
Number of customers at period end:
                               
Residential
    2,936,777       2,954,095       2,936,777       2,954,095  
Commercial and industrial
    244,959       241,036       244,959       241,036  
Total
    3,181,736       3,195,131       3,181,736       3,195,131  

Three months ended September 30, 2009 compared to three months ended September 30, 2008

Our Natural Gas Distribution business segment reported an operating loss of $15 million for the three months ended September 30, 2009 compared to an operating loss of $6 million for the three months ended September 30, 2008. Operating margin (revenues less cost of gas) increased $5 million primarily due to increased rates ($4 million). Operation and maintenance expenses increased $18 million primarily due to increased pension expense ($8 million), higher labor and non-pension related benefits expense ($4 million), customer related expenses and support services costs ($5 million) and increases in other expenses ($4 million), partially offset by lower bad debt expense ($4 million).  Taxes other than income taxes decreased primarily due to lower gross receipts taxes.

Nine months ended September 30, 2009 compared to nine months ended September 30, 2008

Our Natural Gas Distribution business segment reported operating income of $105 million for the nine months ended September 30, 2009 compared to operating income of $119 million for the nine months ended September 30, 2008.  Operating margin improved $23 million primarily as a result of rate increases ($18 million), recovery of higher energy-efficiency costs ($4 million), increased non-utility revenues ($5 million), residential customer growth ($2 million), with the addition of approximately 17,000 customers, and increased margin from commercial and industrial customers ($2 million), partially offset by decreased gross receipts taxes ($10 million).  Operation and maintenance expenses increased $42 million primarily due to increased pension expense ($26 million), higher labor and non-pension related benefits expense ($11 million) and increased customer-related expenses and support services costs ($11 million), partially offset by lower bad debt expense ($8 million) and other expense reductions ($3 million).  Depreciation expense increased due to higher plant balances.  Taxes other than income taxes decreased due to the gross receipts taxes above, partially offset by an increase in property taxes ($2 million).
 

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read "Risk Factors Risk Factors Affecting Our Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Other Risks" in Item 1A of Part II of this Form 10-Q.

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three and nine months ended September 30, 2008 and 2009 (in millions, except throughput and customer data):

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2008
   
2009
   
2008
   
2009
 
Revenues
  $ 1,269     $ 399     $ 3,632     $ 1,596  
Expenses:
                               
Natural gas
    1,225       396       3,567       1,562  
Operation and maintenance
    8       10       26       30  
Depreciation and amortization
    1       1       2       3  
Taxes other than income taxes
    -       -       1       1  
Total expenses
    1,234       407       3,596       1,596  
Operating Income (Loss)
  $ 35     $ (8 )   $ 36     $ -