CenterPoint Energy, Inc.
CENTERPOINT ENERGY INC (Form: 10-Q, Received: 05/05/2010 08:01:46)


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 MARCH 31, 2010
OR
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
FOR THE TRANSITION PERIOD FROM                    TO                   

Commission file number 1-31447
____________________________
 
CENTERPOINT ENERGY, INC.
(Exact name of registrant as specified in its charter)

Texas
74-0694415
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
   
1111 Louisiana
 
Houston, Texas 77002
(713) 207-1111
(Address and zip code of principal executive offices)
(Registrant’s telephone number, including area code )
____________________________

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

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

As of April 27, 2010, CenterPoint Energy, Inc. had 394,410,559 shares of common stock outstanding, excluding 166 shares held as treasury stock.




 
 
 
 


CENTERPOINT ENERGY, INC.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2010

TABLE OF CONTENTS

 
PART I.
 
FINANCIAL INFORMATION
   
         
Item 1.
 
Financial Statements
 
1
         
       
   
Three Months Ended March 31, 2009 and 2010 (unaudited)
 
1
         
       
   
December 31, 2009 and March 31, 2010 (unaudited)
 
2
         
       
   
Three Months Ended March 31, 2009 and 2010 (unaudited)
 
4
         
     
5
         
Item 2.
   
25
         
Item 3.
   
38
         
Item 4.
   
39
         
PART II.
 
OTHER INFORMATION
   
         
Item 1.
   
39
         
   Item 1A.
   
39
         
Item 5.
   
39
         
Item 6.
   
40



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:

 
the resolution of the true-up proceedings, including, in particular, the results of appeals to the Texas Supreme Court regarding rulings obtained to date;
 
 
state and federal legislative and regulatory actions or developments relating to the environment, including those related to global climate change;
 
 
other state and federal legislative and regulatory actions or developments, including, among others, deregulation, re-regulation and health care reform;
 
 
timely and appropriate regulatory actions allowing securitization or other recovery of costs associated with any future hurricanes or natural disasters;
 
 
timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;
 
 
problems with construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or in cost overruns that cannot be recouped in rates;
 
 
industrial, commercial and residential growth in our service territory and changes in market demand, including the effects of energy efficiency measures, and demographic patterns;
 
 
the timing and extent of changes in commodity prices, particularly natural gas and natural gas liquids;
 
 
the timing and extent of changes in the supply of natural gas, including supplies available for gathering by our field services business and transporting by our interstate pipelines;
 
 
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 ability of retail electric providers, and particularly the two largest customers of CenterPoint Houston Electric LLC, which are subsidiaries of NRG Retail LLC and TXU Energy Retail Company LLC, to satisfy their obligations to us and our subsidiaries;
 
 
the outcome of litigation brought by or against us;
 
 
our ability to control costs;
 
 
the investment performance of our pension and postretirement benefit plans;
 
 
our potential business strategies, including restructurings, 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 us or our competitors; and
 
 
other factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2009, which is incorporated herein by reference, 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

Item 1.      FINANCIAL STATEMENTS
 
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(In Millions, Except Per Share Amounts)
(Unaudited)

   
Three Months Ended
March 31,
 
   
2009
   
2010
 
             
Revenues
  $ 2,766     $ 3,023  
                 
Expenses:
               
Natural gas
    1,789       1,935  
Operation and maintenance
    413       414  
Depreciation and amortization
    166       200  
Taxes other than income taxes
    113       117  
Total
    2,481       2,666  
Operating Income
    285       357  
                 
Other Income (Expense):
               
Gain (loss) on marketable securities
    (34 )     38  
Gain (loss) on indexed debt securities
    22       (27 )
Interest and other finance charges
    (129 )     (122 )
Interest on transition and system restoration bonds
    (33 )     (36 )
Equity in earnings of unconsolidated affiliates
          5  
Other, net
    4       1  
Total
    (170 )     (141 )
                 
Income Before Income Taxes
    115       216  
Income tax expense
    (48 )     (102 )
Net Income
  $ 67     $ 114  
                 
Basic Earnings Per Share
  $ 0.19     $ 0.29  
                 
Diluted Earnings Per Share
  $ 0.19     $ 0.29  
                 
Dividends Declared Per Share
  $ 0.190     $ 0.195  
                 
Weighted Average Shares Outstanding, Basic
    347       393  
                 
Weighted Average Shares Outstanding, Diluted
    349       395  

See Notes to Interim Condensed Consolidated Financial Statements



CONDENSED CONSOLIDATED BALANCE SHEETS
(In Millions)
(Unaudited)

ASSETS

   
December 31,
2009
   
March 31,
2010
 
Current Assets:
           
Cash and cash equivalents
  $ 740     $ 329  
Investment in marketable securities
    300       338  
Accounts receivable, net
    790       933  
Accrued unbilled revenues
    485       296  
Natural gas inventory
    189       32  
Materials and supplies
    138       134  
Non-trading derivative assets
    39       60  
Prepaid expenses and other current assets
    223       262  
Total current assets
    2,904       2,384  
                 
Property, Plant and Equipment:
               
Property, plant and equipment
    14,770       15,001  
Less accumulated depreciation and amortization
    3,982       4,073  
Property, plant and equipment, net
    10,788       10,928  
                 
Other Assets:
               
Goodwill
    1,696       1,696  
Regulatory assets
    3,677       3,619  
Non-trading derivative assets
    15       18  
Investment in unconsolidated affiliates
    463       478  
Other
    230       228  
Total other assets
    6,081       6,039  
                 
Total Assets
  $ 19,773     $ 19,351  



See Notes to Interim Condensed Consolidated Financial Statements



CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)
(In Millions)
(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY

   
December 31,
2009
   
March 31,
2010
 
Current Liabilities:
           
Short-term borrowings
  $ 55     $ 2  
Current portion of transition and system restoration bonds long-term debt
    241       274  
Current portion of indexed debt
    121       122  
Current portion of other long-term debt
    541       776  
Indexed debt securities derivative
    201       228  
Accounts payable
    648       522  
Taxes accrued
    148       226  
Interest accrued
    181       148  
Non-trading derivative liabilities
    51       53  
Accumulated deferred income taxes, net
    406       354  
Other
    445       497  
Total current liabilities
    3,038       3,202  
                 
Other Liabilities:
               
Accumulated deferred income taxes, net
    2,776       2,799  
Unamortized investment tax credits
    16       15  
Non-trading derivative liabilities
    42       32  
Benefit obligations
    861       863  
Regulatory liabilities
    921       946  
Other
    361       375  
Total other liabilities
    4,977       5,030  
                 
Long-term Debt:
               
Transition and system restoration bonds
    2,805       2,665  
Other
    6,314       5,745  
Total long-term debt
    9,119       8,410  
                 
Commitments and Contingencies (Note 11)
               
                 
Shareholders’ Equity:
               
Common stock (391,746,779 shares and 394,186,137 shares outstanding
   at December 31, 2009 and March 31, 2010, respectively)
    4       4  
Additional paid-in capital
    3,671       3,701  
Accumulated deficit
    (912 )     (875 )
Accumulated other comprehensive loss
    (124 )     (121 )
Total shareholders’ equity
    2,639       2,709  
                 
Total Liabilities and Shareholders’ Equity
  $ 19,773     $ 19,351  



See Notes to Interim Condensed Consolidated Financial Statements


CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(In Millions)
(Unaudited)

   
Three Months Ended March 31,
 
   
2009
   
2010
 
Cash Flows from Operating Activities:
           
Net income
  $ 67     $ 114  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    166       200  
Amortization of deferred financing costs
    10       7  
Deferred income taxes
    30       (34 )
Unrealized loss (gain) on marketable securities
    34       (38 )
Unrealized loss (gain) on indexed debt securities
    (22 )     27  
Write-down of natural gas inventory
    6        
Equity in earnings of unconsolidated affiliates, net of distributions
          5  
Changes in other assets and liabilities:
               
Accounts receivable and unbilled revenues, net
    308       (2 )
Inventory
    416       161  
Accounts payable
    (425 )     (125 )
Fuel cost over (under) recovery
    (30 )     126  
Non-trading derivatives, net
    8       (6 )
Margin deposits, net
    (62 )     (67 )
Interest and taxes accrued
    (94 )     44  
Net regulatory assets and liabilities
    21       19  
Other current assets
    43       10  
Other current liabilities
    (64 )     (16 )
Other assets
    (4 )     (5 )
Other liabilities
    24       13  
Other, net
    1       2  
Net cash provided by operating activities
    433       435  
                 
Cash Flows from Investing Activities:
               
Capital expenditures
    (260 )     (258 )
Decrease in restricted cash of transition and system restoration bonds companies
    1       1  
Investment in unconsolidated affiliates
    2       (20 )
Other, net
    (4 )     (26 )
Net cash used in investing activities
    (261 )     (303 )
                 
Cash Flows from Financing Activities:
               
Increase (decrease) in short-term borrowings, net
    62       (53 )
Revolving credit facilities, net
    (706 )      
Proceeds from commercial paper, net
    19        
Proceeds from long-term debt
    500        
Payments of long-term debt
    (110 )     (441 )
Debt issuance costs
    (4 )     (2 )
Payment of common stock dividends
    (66 )     (77 )
Proceeds from issuance of common stock, net
    30       29  
Other, net
    1       1  
Net cash used in financing activities
    (274 )     (543 )
                 
Net Decrease in Cash and Cash Equivalents
    (102 )     (411 )
Cash and Cash Equivalents at Beginning of Period
    167       740  
Cash and Cash Equivalents at End of Period
  $ 65     $ 329  
                 
Supplemental Disclosure of Cash Flow Information:
               
Cash Payments:
               
Interest, net of capitalized interest
  $ 182     $ 191  
Income taxes (refunds), net
    26       (8 )
Non-cash transactions:
               
Accounts payable related to capital expenditures
    67       83  
 
See Notes to 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, Inc. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy). 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 CenterPoint Energy for the year ended December 31, 2009 (CenterPoint Energy Form 10-K).

Background. CenterPoint Energy, Inc. is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of March 31, 2010, CenterPoint Energy’s indirect wholly owned subsidiaries included:

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

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

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

CenterPoint Energy’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 CenterPoint Energy’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 CenterPoint Energy’s reportable business segments, reference is made to Note 15.

(2)
New Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (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. CenterPoint Energy’s adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows.

In January 2010, the FASB issued new accounting guidance to require additional fair value related disclosures including transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and
 
 
5

 
settlements relating to Level 3 measurements. It also clarifies existing fair value disclosure guidance about the level of disaggregation and about inputs and valuation techniques. This new guidance is effective for the first reporting period beginning after December 15, 2009 except for the requirement to separately disclose purchases, sales, issuances and settlements relating to Level 3 measurements, which is effective for the first reporting period beginning after December 15, 2010. CenterPoint Energy's adoption of this new guidance did not have a material impact on its financial position, results of operations or cash flows. CenterPoint Energy expects that the adoption of the Level 3 related gross disclosure requirement, which is effective in 2011, will not have a material impact on the 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 CenterPoint Energy’s consolidated financial position, results of operations or cash flows upon adoption.

(3)
Employee Benefit Plans

CenterPoint Energy’s net periodic cost includes the following components relating to pension and postretirement benefits:

   
Three Months Ended March 31,
 
   
2009
   
2010
 
   
Pension
Benefits
   
Postretirement
Benefits
   
Pension
Benefits (1)
   
Postretirement
Benefits
 
   
(in millions)
 
Service cost
  $ 6     $     $ 8     $  
Interest cost
    28       7       25       6  
Expected return on plan assets
    (24 )     (2 )     (27 )     (2 )
Amortization of prior service credit
    1       1       1       1  
Amortization of net loss
    17             15        
Amortization of transition obligation
          2             2  
Net periodic cost
  $ 28     $ 8     $ 22     $ 7  

 
(1)
Net periodic cost in these tables is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.  CenterPoint Houston’s actuarially determined pension expense for 2010 in excess of the 2007 base year amount is being deferred for rate making purposes until its next general rate case pursuant to Texas law.  CenterPoint Houston deferred as a regulatory asset $4 million and $6 million, respectively, in pension expense during the three months ended March 31, 2009 and 2010.

CenterPoint Energy expects to contribute approximately $9 million to its pension plans in 2010, of which $2 million was contributed during the three months ended March 31, 2010.

CenterPoint Energy expects to contribute approximately $19 million to its postretirement benefits plan in 2010, of which $6 million was contributed during the three months ended March 31, 2010.

(4)
Regulatory Matters

(a) Recovery of True-Up Balance

In March 2004, CenterPoint Houston filed its true-up application with the Public Utility Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan (Texas electric restructuring law). In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits (EMCs) returned to customers after August 31, 2004 and certain other adjustments.
 

CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In its judgment, the district court:

 
reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;

 
reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to retail electric providers (REPs); and

 
affirmed the True-Up Order in all other respects.

The district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request.

CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:

 
reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;

 
reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.);

 
ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and

 
affirmed the district court’s judgment in all other respects.

In April 2008, the court of appeals denied all motions for rehearing and reissued substantially the same opinion as it had rendered in December 2007.

In June 2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the court of appeals decision. In its petition, CenterPoint Houston seeks reversal of the parts of the court of appeals decision that (i) denied recovery of EMCs paid to RRI, (ii) denied recovery of the capacity auction true-up amounts allowed by the district court, (iii) affirmed the Texas Utility Commission’s rulings that denied recovery of approximately $378 million related to depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit CenterPoint Houston to utilize the partial stock valuation methodology for determining the market value of its former generation assets. Two other petitions for review were filed with the Texas Supreme Court by other parties to the appeal. In those petitions parties contend that (i) the Texas Utility Commission was without authority to fashion the methodology it used for valuing the former generation assets after it had determined that CenterPoint Houston could not use the partial stock valuation method, (ii) in fashioning the method it used for valuing the former generating assets, the Texas Utility Commission deprived parties of their due process rights and an opportunity to be heard, (iii) the net book value of the generating assets should have been adjusted downward due to the impact of a purchase option that had been granted to RRI, (iv) CenterPoint Houston should not have been permitted to recover construction work in progress balances without proving those amounts in the manner required by law and (v) the Texas Utility Commission was without authority to award interest on the capacity auction true-up award.

In June 2009, the Texas Supreme Court granted the petitions for review of the court of appeals decision.  Oral argument before the court was held in October 2009, and the parties have filed post-submission briefs to the court.  Although CenterPoint Energy and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that it will be successful in its appeal to the Texas Supreme Court, CenterPoint Energy can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005, CenterPoint Energy recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of
 
 
7

 
appeals have been recorded in CenterPoint Energy’s consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of further review by the Texas Supreme Court, CenterPoint Energy anticipates that it would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-Up Order, but could range from $180 million to $410 million (pre-tax) plus interest subsequent to December 31, 2009.

In the True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, for the present value of certain deferred tax benefits associated with its former electric generation assets. CenterPoint Energy believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 that would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew those proposed normalization regulations and, in March 2008, adopted final regulations that would not permit utilities like CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, CenterPoint Energy received a Private Letter Ruling (PLR) from the IRS in August 2007, prior to adoption of the final regulations, that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require CenterPoint Energy to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on CenterPoint Energy’s results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party has challenged that order by the court of appeals although the Texas Supreme Court has the authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. CenterPoint Energy and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate and administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the Texas Utility Commission’s True-Up Order to be recovered either through securitization or through implementation of a competition transition charge (CTC) or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005, a new special purpose subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84% to 5.30% and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.

In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC designed to collect the remaining $596 million from the True-Up Order over 14 years plus interest at an annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston to impose a charge on REPs to recover the portion of the true-up balance not recovered through a financing order. The CTC Order also allowed CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. The return on the CTC portion of the true-up balance was included in CenterPoint Houston’s tariff-based revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to 8.06%
 
 
8

 
pursuant to a revised rule adopted by the Texas Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE was completed in September 2008.

Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the revised rule discussed above. Second, the district court reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston to recover through Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. The Texas Utility Commission and CenterPoint Houston appealed the district court’s judgment to the Texas Third Court of Appeals, and in July 2008, the court of appeals reversed the district court’s judgment in all respects and affirmed the Texas Utility Commission’s order. Two parties appealed the court of appeals decision to the Texas Supreme Court which heard oral argument in October 2009. The ultimate outcome of this matter cannot be predicted at this time. However, CenterPoint Energy does not expect the disposition of this matter to have a material adverse effect on CenterPoint Energy’s or CenterPoint Houston’s financial condition, results of operations or cash flows.

During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a request with the Texas Utility Commission for a financing order that would allow the securitization of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. In February 2008, pursuant to the financing order, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million of transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

As of March 31, 2010, CenterPoint Energy has not recognized an allowed equity return of $190 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates. During the three months ended March 31, 2009 and 2010, CenterPoint Houston recognized approximately $2 million and $3 million, respectively, of the allowed equity return not previously recognized.

(b) Rate Proceedings

Texas. The final order in its 2006 rate proceeding requires CenterPoint Houston to file a general rate case with the Texas Utility Commission by June 30, 2010 unless the Texas Utility Commission Staff and certain other parties determined by March 31, 2010 that no such filing would be necessary.  Those parties have advised CenterPoint Houston that a rate case filing is necessary, and, accordingly, CenterPoint Houston plans to file its application to change rates no later than the June 30, 2010 deadline.  The amount and other terms of the rate filing have not been established at this time.  Based on the prescribed timeline for processing such an application, CenterPoint Houston anticipates that a final order on that application would be entered in early 2011.

In May 2009, CenterPoint Houston filed an application at the Texas Utility Commission seeking approval of certain estimated 2010 energy efficiency program costs, an energy efficiency performance bonus for 2008 programs, and carrying costs, totaling approximately $10 million. The application sought to begin recovery of these costs through a surcharge effective July 1, 2010. In October 2009, the Texas Utility Commission issued its order approving recovery of the 2010 energy efficiency program costs and a partial performance bonus, plus carrying costs, but refused to permit CenterPoint Houston to recover a performance bonus of $2 million on approximately $10 million in 2008 energy efficiency costs expended pursuant to the terms of a settlement agreement reached in CenterPoint Houston’s 2006 rate proceeding.  CenterPoint Houston has appealed the denial of the full 2008 performance bonus to the 98th district court in Travis County, Texas, where the case remains pending.
 
 
In April 2010, CenterPoint Houston filed an application with the Texas Utility Commission to recover a total of approximately $14.4 million in costs related to its energy efficiency programs.  The filing seeks authorization to recover certain projected costs for its 2011 energy efficiency programs, an energy efficiency performance bonus for 2009 programs, and revenue losses related to the implementation of the 2009 energy efficiency program. The application seeks to begin recovery of these costs through a surcharge beginning in January 2011.  A final order is not expected until later this year.

In March 2008, the natural gas distribution business 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, the Railroad Commission approved the implementation of rates increasing annual revenues by approximately $3.5 million.  The implemented rates were contested by nine cities in an appeal to the 353rd District Court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission’s order in part and remanded the matter to the Railroad Commission.  In its final judgment the court ruled that the Railroad Commission lacked authority to impose the approved cost of service adjustment mechanism in both those nine cities and in those areas in which the Railroad Commission has original jurisdiction.  The Railroad Commission and Gas Operations have appealed the court’s ruling on the cost of service adjustment mechanism to the court of appeals, but CenterPoint Energy and CERC do not expect the outcome of this matter to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

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 sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would have resulted in an overall increase in annual revenue of $20.4 million, excluding carrying costs on gas inventory of approximately $2 million. In January 2010, Gas Operations withdrew its request for an annual cost of service adjustment mechanism due to the uncertainty caused by the court’s ruling in the above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission issued its decision authorizing a revenue increase of $5.1 million annually, reflecting reduced depreciation rates as well as adjustments to pension and benefits, accumulated deferred income taxes and other items. The Railroad Commission also approved a surcharge of $0.9 million per year to recover Hurricane Ike costs over three years. Gas Operations and other parties filed motions for rehearing, which, except for minor corrections to the order, were denied  by the Railroad Commission in May 2010.  The parties are entitled to petition for judicial review by a district court in Travis County, Texas, within thirty days of the Railroad Commission’s order on rehearing.

Minnesota. In November 2008, Gas Operations filed a request with the Minnesota Public Utilities Commission (MPUC) to increase its rates for utility distribution service by $59.8 million annually.  In addition, Gas Operations sought an adjustment mechanism that would annually adjust rates to reflect changes in use per customer.  In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. In January 2010, the MPUC issued its decision authorizing a revenue increase of $41 million per year, with an overall rate of return of 8.09% (10.24% return on equity).  The MPUC also authorized Gas Operations to implement a pilot program for residential and small volume commercial customers that is intended to decouple gas revenues from customers’ natural gas usage. In February 2010, CERC filed a request for rehearing of the order by the MPUC.  No other party to the case filed such a request. In March 2010, the MPUC declined to act on CERC’s request for rehearing and a final order was issued.  The difference between the amounts approved by the MPUC and amounts collected, $15 million as of March 31, 2010, is recorded in other current liabilities and will be refunded to customers when final tariffs are approved this summer.

(5)
Derivative Instruments

CenterPoint Energy is exposed to various market risks. These risks arise from transactions entered into in the normal course of business.  CenterPoint Energy 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 CenterPoint Energy’s Condensed Consolidated Balance Sheets at their fair value unless CenterPoint Energy 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.

 
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 CenterPoint Energy’s marketing, risk management services and hedging activities. The committee’s duties are to establish CenterPoint Energy’s commodity risk policies, allocate board-approved commercial risk limits, approve use of new products and commodities, monitor positions and ensure compliance with CenterPoint Energy’s risk management policies and procedures and limits established by CenterPoint Energy’s board of directors.

CenterPoint Energy’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. CenterPoint Energy enters into certain derivative instruments to manage physical commodity price risks but does not engage in proprietary or speculative commodity trading.  CenterPoint Energy has not elected to designate these instruments as cash flow or fair value hedges.

During the three months ended March 31, 2009, CenterPoint Energy recorded increased natural gas revenues from unrealized net gains of $3 million and increased natural gas expense from unrealized net losses of $22 million, resulting in a net unrealized loss of $19 million.  During the three months ended March 31, 2010, CenterPoint Energy recorded increased natural gas revenues from unrealized net gains of $30 million and increased natural gas expense from unrealized net losses of $27 million, resulting in a net unrealized gain of $3 million .

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

In 2008 and 2009, CenterPoint Energy 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 months ended March 31, 2009 and 2010, CenterPoint Energy recognized losses of $3 million and $7 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 CenterPoint Energy’s derivative instruments and hedging activities. The first tables provide a balance sheet overview of CenterPoint Energy’s Derivative Assets and Liabilities as of December 31, 2009 and March 31, 2010, while the latter tables provide a breakdown of the related income statement impact for the three months ended March 31, 2009 and March 31, 2010.

Fair Value of Derivative Instruments
 
   
December 31, 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)
 
Natural gas contracts (1)
 
Current Assets
  $ 46     $ (7 )
Natural gas contracts   (1)  
 
Other Assets
    16       (1 )
Natural gas contracts (1)
 
Current Liabilities
    20       (123 )
Natural gas contracts (1)
 
Other Liabilities
    1       (86 )
Indexed debt securities derivative
 
Current Liabilities
          (201 )
Total                                                                           
  $ 83     $ (418 )
_________

 
 
(1)
Natural gas 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 natural gas contracts is comprised of derivative gross volumes totaling 674 billion cubic feet (Bcf) or a net 152 Bcf long position.  Of the net long position, basis swaps constitute 71 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 51 Bcf.

 
(3)
The net of total non-trading derivative assets and liabilities is a $39 million liability as shown on CenterPoint Energy’s Condensed Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $95 million.
 
Fair Value of Derivative Instruments
 
   
March 31, 2010
 
Total derivatives not designated as hedging
instruments
 
Balance Sheet
Location
 
Derivative
Assets
Fair Value (2) (3)
   
Derivative
Liabilities
Fair Value (2) (3)
 
       
(in millions)
 
Natural gas contracts (1)
 
Current Assets
  $ 61     $ (1 )
Natural gas contracts   (1)  
 
Other Assets
    18        
Natural gas contracts (1)
 
Current Liabilities
    20       (179 )
Natural gas contracts (1)
 
Other Liabilities
    1       (81 )
Indexed debt securities derivative
 
Current Liabilities
          (228 )
Total                                                                           
  $ 100     $ (489 )
_________
 
(1)
Natural gas 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 natural gas contracts is comprised of derivative gross volumes totaling 717 billion cubic feet (Bcf) or a net 181 Bcf long position.  Of the net long position, basis swaps constitute 73 Bcf and volumes associated with price stabilization activities of the Natural Gas Distribution business segment comprise 46 Bcf.

 
(3)
The net of total non-trading derivative assets and liabilities is a $7 million liability as shown on CenterPoint Energy’s Condensed Consolidated Balance Sheets, and is comprised of the natural gas contracts derivative assets and liabilities separately shown above offset by collateral netting of $154 million.
 
For CenterPoint Energy’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 these contracts are recorded as net regulatory assets. Realized and unrealized gains and losses on other derivatives are recognized in 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. Unrealized gains and losses on indexed debt securities are recorded as Other Income (Expense) on the Condensed Statements of Consolidated Income.
 
Income Statement Impact of Derivative Activity
 
       
Three Months Ended March 31,
 
Total derivatives not designated as hedging instruments
 
Income Statement Location
 
2009
   
2010
 
       
(in millions)
   
(in millions)
 
Natural gas contracts
 
Gains (Losses) in Revenue
  $ 77     $ 44  
Natural gas contracts (1)
 
Gains (Losses) in Expense: Natural Gas
    (149 )     (61 )
Indexed debt securities derivative
 
Gains (Losses) in Other Income (Expense)
    22       (27 )
Total
  $ (50 )   $ (44 )
_________
 
 
 
(1)
The Gains (Losses) in Expense: Natural Gas includes $(78) and $(25) million of costs in 2009 and 2010, respectively, associated with price stabilization activities of the Natural Gas Distribution business segment that will be ultimately recovered/refunded through purchased gas adjustments.
 
(c) Credit Risk Contingent Features

CenterPoint Energy enters into financial derivative contracts containing material adverse change provisions.  These provisions require CenterPoint Energy to post additional collateral if the Standard & Poor’s Rating Services or Moody’s Investors Service, Inc. credit rating of CenterPoint Energy is downgraded.  The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position at March 31, 2010 is $173 million compared to $140 million at December 31, 2009.  The aggregate fair value of assets that are already posted as collateral at March 31, 2010 is $92 million compared to $65 million at December 31, 2009.  If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at March 31, 2010, $79 million of additional assets would be required to be posted as collateral compared to $75 million at December 31, 2009.

(6)
Fair Value Measurements

Assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and 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.  A market approach is utilized to value CenterPoint Energy’s Level 2 assets or liabilities.

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 CenterPoint Energy’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CenterPoint Energy develops these inputs based on the best information available, including CenterPoint Energy’s own data. A market approach is utilized to value CenterPoint Energy’s Level 3 assets or liabilities.  CenterPoint Energy’s Level 3 derivative instruments primarily consist of options that are not traded on recognized exchanges and are valued using option pricing models.

CenterPoint Energy determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period.  For the quarter ended March 31, 2010, there were no significant transfers between levels.

 
The following tables present information about CenterPoint Energy’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of December 31, 2009 and March 31, 2010, and indicate the fair value hierarchy of the valuation techniques utilized by CenterPoint Energy 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,
2009
 
   
(in millions)
 
Assets
                             
Corporate equities
  $ 301     $     $     $     $ 301  
Investments in money
market funds
    41                         41  
Natural gas derivatives
    1       77       5       (29 )     54  
Total assets
  $ 343     $ 77     $ 5     $ (29 )   $ 396  
Liabilities
                                       
Indexed debt securities
derivative
  $     $ 201     $     $     $ 201  
Natural gas derivatives
    12       194       11       (124 )     93  
Total liabilities
  $ 12     $ 395     $ 11     $ (124 )   $ 294  
_________
 
(1)
Amounts represent the impact of legally enforceable master netting agreements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $95 million posted with the same counterparties.
 
   
Quoted Prices in
Active Markets
for Identical Assets
(Level 1)
   
Significant Other
Observable
Inputs
(Level 2)
   
Significant
Unobservable
Inputs
(Level 3)
   
Netting
Adjustments (1)
   
Balance
as of
March 31,
2010
 
   
(in millions)
 
Assets
                             
Corporate equities
  $ 340     $     $     $     $ 340  
Investments in money
market funds
    40                         40  
Natural gas derivatives
          94       6       (22 )     78  
Total assets
  $ 380     $ 94     $ 6     $ (22 )   $ 458  
Liabilities
                                       
Indexed debt securities
derivative
  $     $ 228     $     $     $ 228  
Natural gas derivatives
    15       244       2       (176 )     85  
Total liabilities
  $ 15     $ 472     $ 2     $ (176 )   $ 313  
_________
 
(1)
Amounts represent the impact of legally enforceable master netting agreements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $154 million posted with the same counterparties.

 
The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CenterPoint Energy 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 March 31,
 
   
2009
   
2010
 
   
(in millions)
 
Beginning balance
  $ (58 )   $ (6 )
Total unrealized gains or (losses):
               
Included in earnings
    (3 )     2  
Included in regulatory assets
    (17 )     (1 )
Total purchases, sales, other settlements, net:
               
Included in earnings
    2        
Included in regulatory assets
    50       9  
Ending balance
  $ (26 )   $ 4  
The amount of total gains(losses) for the period included in earnings
attributable to the change in unrealized gains or losses relating to
assets still held at the reporting date
  $ (2 )   $ 2  

(7)
Goodwill

Goodwill by reportable business segment as of both December 31, 2009 and March 31, 2010 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  

(8)
Comprehensive Income

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

   
For the Three Months Ended
March 31,
 
   
2009
   
2010
 
   
(in millions)
 
Net income
  $ 67     $ 114  
Other comprehensive income:
               
Adjustment related to pension and other postretirement
plans (net of tax of $1 and $1)
    2       3  
Total
    2       3  
Comprehensive income
  $ 69     $ 117  

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

   
December 31,
2009
   
March 31,
2010
 
   
(in millions)
 
Adjustment related to pension and postretirement plans
  $ (120 )   $ (117 )
Net deferred loss from cash flow hedges
    (4 )     (4 )
Total accumulated other comprehensive loss
  $ (124 )   $ (121 )

(9)
Capital Stock

CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock. At December 31, 2009, 391,746,945 shares of CenterPoint Energy common stock were issued and 391,746,779 shares were outstanding. At March 31, 2010, 394,186,303 shares of CenterPoint Energy common stock were issued and 394,186,137 shares were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2009 and March 31, 2010.

(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, 2009 and March 31, 2010, the facility size was $150 million and $375 million, respectively. As of both December 31, 2009 and March 31, 2010, there were no advances under the receivables facility.

Inventory Financing .  In October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma. Pursuant to the provisions of the agreements, Gas Operations sold $104 million of its natural gas in storage and agreed to repurchase an equivalent amount of natural gas during the 2009-2010 winter heating season at the same cost, plus a financing charge. This transaction was accounted for as a financing and a principal obligation of $55 million and $2 million remained as of December 31, 2009 and March 31, 2010, respectively.
 
Also in October 2009, Gas Operations entered into asset management agreements associated with its utility distribution service in south Louisiana, Mississippi and Texas. In connection with these asset management agreements, Gas Operations exchanged natural gas in storage for the right to receive an equivalent amount of natural gas during the 2009-2010 winter heating season. Although title to the natural gas in storage was transferred to the third party, the natural gas continues to be accounted for as inventory due to the right to receive an equivalent amount of natural gas during the current winter heating season. As of December 31, 2009 and March 31, 2010, CenterPoint Energy’s Consolidated Balance Sheets reflect $10 million and $-0-, respectively, in inventory related to these agreements.
 
(b) Long-term Debt
 
Pollution Control Bonds. In January 2010, CenterPoint Energy purchased $290 million principal amount of pollution control bonds issued on its behalf at 101% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds.  Prior to the purchase, the pollution control bonds had a fixed rate of interest of 5.125%.

Convertible Subordinated Debentures. In January 2010, CERC Corp. redeemed $45 million of its outstanding 6% convertible subordinated debentures due 2012 at 100% of the principal amount plus accrued and unpaid interest to the redemption date.

Revolving Credit Facilities. As of both December 31, 2009 and March 31, 2010, there were no outstanding borrowings under CenterPoint Energy’s, CenterPoint Houston’s or CERC Corp.’s long-term revolving credit facilities.

 
In addition, as of December 31, 2009 and March 31, 2010, CenterPoint Energy had approximately $25 million and $20 million, respectively, of outstanding letters of credit under its $1.2 billion credit facility. As of both December 31, 2009 and March 31, 2010 CenterPoint Houston had approximately $4 million of outstanding letters of credit under its $289 million credit facility. There was no commercial paper outstanding that would have been backstopped by CenterPoint Energy’s $1.2 billion credit facility or by CERC Corp.'s credit facility as of December 31, 2009 and March 31, 2010.  CenterPoint Energy, CenterPoint Houston and CERC Corp. were in compliance with all debt covenants as of March 31, 2010.

CenterPoint Energy’s $1.2 billion credit facility has a first drawn cost of the London Interbank Offered Rate (LIBOR) plus 55 basis points based on CenterPoint Energy’s current credit ratings. The facility contains a debt (excluding transition and system restoration bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant (as those terms are defined in the facility).  In February 2010, CenterPoint Energy amended its credit facility to modify the covenant to allow for a temporary increase of the permitted ratio from 5 times to 5.5 times if CenterPoint Houston experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a calendar year, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temporary increase in the financial ratio covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

CenterPoint Houston’s $289 million credit facility contains a debt (excluding transition and system restoration bonds) to total capitalization covenant. The facility’s first drawn cost is LIBOR plus 45 basis points based on CenterPoint Houston’s current credit ratings.

CERC Corp.’s $915 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.

Under CenterPoint Energy’s $1.2 billion credit facility, CenterPoint Houston’s $289 million credit facility and 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 the borrower’s credit rating.

(11)
Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CenterPoint Energy’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 CenterPoint Energy’s Consolidated Balance Sheets as of December 31, 2009 and March 31, 2010 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 March 31, 2010, minimum payment obligations for natural gas supply commitments are approximately $308 million for the remaining nine months in 2010, $484 million in 2011, $405 million in 2012, $346 million in 2013, $254 million in 2014 and $527 million after 2014.

(b) Capital Commitments

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

 
In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas and expects to place those facilities in service by the end of 2010.  CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. As of March 31, 2010, approximately $260 million has been spent on this project, including the purchase of existing facilities.

Under the agreements, Encana or Shell can elect to require CEFS to further expand the facilities in order to gather and treat an additional volume of up to 1 billion cubic feet (Bcf) per day, and in March 2010, Encana and Shell exercised initial expansion elections to increase gathering capacity by 200 MMcf per day to 900 MMcf. Total capital expenditures for this expansion are estimated to be $50 million to $70 million, and the increased capacity is expected to be in service by the first quarter of 2011.  In connection with the expansion, Encana and Shell each made incremental volume commitments for the capacity expansion.

If Encana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 Bcf per day (including the 200 MMcf per day already elected), CEFS estimates that the expansion would cost as much as $300 million, and Encana and Shell would provide incremental volume commitments.

In April 2010, CEFS entered into additional long-term agreements with Encana and Shell to provide gathering and treating services for their natural gas production from the Haynesville Shale and Bossier Shale formations in Texas and Louisiana. Pursuant to the agreements, CEFS has also acquired existing jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in De Soto and Red River parishes in northwest Louisiana.

CEFS has integrated the acquired facilities with CEFS’s Magnolia Gathering System, allowing CEFS to commence gathering and treating services immediately for up to 150 MMcf per day of natural gas. Under the terms of the agreements, CEFS will expand the acquired facilities to gather and treat up to 580 MMcf per day of natural gas. Each of the agreements includes volume commitments and dedicated acreage for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production.

New construction to reach capacity of 580 MMcf per day includes more than 180 miles of pipelines, over 8,000 horsepower of compression and over 680 MMcf per day of treating capacity.

CEFS estimates that the capital cost to purchase the existing facilities and construct new facilities for the Olympia Gathering System to gather 580 MMcf per day will be as much as $400 million. If Encana and Shell elect, CEFS will expand the project to gather and process additional future volumes of up to 520 MMcf per day, for a total Olympia Gathering System capacity of up to 1.1 Bcf per day.  CEFS estimates that an expansion to process 1.1 Bcf would cost as much as an additional $200 million.  Encana and Shell would provide incremental volume commitments in connection with expansions of the Olympia Gathering System.

(c) Legal, Environmental and Other Regulatory Matters

Legal Matters

Gas Market Manipulation Cases .  CenterPoint Energy, CenterPoint Houston or their predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between CenterPoint Energy and RRI (formerly known as Reliant Resources, Inc. and Reliant Energy, Inc.), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of these lawsuits.  Pursuant to the indemnification obligation, RRI is defending CenterPoint Energy and its subsidiaries to the extent named in these lawsuits.  A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2002. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately
 
 
18

 
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 appealed the dismissal in March 2010 to the Nevada Supreme Court. CenterPoint Energy believes that neither it nor CES is a proper defendant in these remaining cases and will continue to pursue dismissal from those cases.  CenterPoint Energy does not expect the ultimate outcome of these remaining matters to have a material impact on its financial condition, results of operations or cash flows.

In May 2009, RRI sold its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc.  In connection with the sale, RRI changed its name to RRI Energy, Inc. and no longer provides service as a REP in CenterPoint Houston’s service territory.  In April 2010, RRI announced its plan to merge with Mirant Corporation in an all-stock transaction.  Neither the sale of the retail business nor the merger with Mirant Corporation, if ultimately finalized, alters RRI’s contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including CenterPoint Houston, for certain liabilities, including their indemnification regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain RRI gas transportation contracts discussed below under Guaranties.

Natural Gas Measurement Lawsuits. 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 and, in March 2010, denied the plaintiffs’ request for reconsideration of that order.

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

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 March 31, 2010, 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. In January 2010, as part of its Minnesota rate case decision, the MPUC eliminated the environmental expense tracker mechanism and ordered amounts previously collected from ratepayers and related carrying costs refunded to customers.  As of March 31, 2010, the balance in the environmental expense tracker account was $8.3 million.  The MPUC provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs.  CERC was not required to refund to customers the amount collected from insurance companies, $5.0 million at March 31, 2010, to be used to mitigate future environmental costs.  The MPUC
 
 
19

 
further gave assurance that any reasonable and prudent environmental clean-up costs CERC incurs in the future will be rate-recoverable under normal regulatory principles and procedures.  This provision had no impact on earnings.

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

Mercury Contamination. CenterPoint Energy’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. CenterPoint Energy has found this type of contamination at some sites in the past, and CenterPoint Energy 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 CenterPoint Energy’s experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, CenterPoint Energy believes that the costs of any remediation of these sites will not be material to CenterPoint Energy’s financial condition, results of operations or cash flows.

Asbestos. Some facilities owned by CenterPoint Energy contain or have contained asbestos insulation and other asbestos-containing materials. CenterPoint Energy or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by CenterPoint Energy, but most existing claims relate to facilities previously owned by CenterPoint Energy’s subsidiaries. CenterPoint Energy anticipates that additional claims like those received may be asserted in the future. In 2004, CenterPoint Energy sold its generating business, to which most of these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP. Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale to NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by NRG Texas LP, but CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from NRG Texas LP. Although their ultimate outcome cannot be predicted at this time, CenterPoint Energy 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 CenterPoint Energy’s 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 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. CenterPoint Energy and CERC do not expect the outcome of this litigation to have a material adverse impact on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.

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

Other Proceedings

CenterPoint Energy 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. CenterPoint Energy regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. CenterPoint Energy does not expect the disposition of these matters to have a material adverse effect on CenterPoint Energy’s 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 transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties.  The present value of the demand charges under these transportation contracts, which will be effective until 2018, was approximately $91 million as of March 31, 2010. As of March 31, 2010, 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 ended March 31, 2009 and 2010, the effective tax rate was 42% and 47%, respectively. The most significant item affecting the comparability of the effective tax rate is a non-cash, $21 million increase in the 2010 income tax expense as a result of a change in tax law upon the enactment in March 2010 of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010. Additionally, the comparability of the effective tax rate is affected by a $4 million increase in the 2009 income tax expense related to a state tax examination.

The change in tax law, which becomes effective for tax years beginning after December 31, 2012, eliminates the tax deductibility of the portion of retiree health care costs which are reimbursed by Medicare Part D subsidies. Based upon the actuarially determined net present value of lost future retiree health care deductions related to the subsidies, CenterPoint Energy reduced its deferred tax asset related to future retiree health care deductions by approximately $32 million as of March 31, 2010.  The portion of the reduction that CenterPoint Energy believes will be recovered through the regulatory process, or approximately $11 million, has been recorded as a regulatory asset.  The remaining $21 million of the reduction in CenterPoint Energy’s deferred tax asset has been reflected as a charge to income tax expense.

 
The following table summarizes CenterPoint Energy’s unrecognized tax benefits at December 31, 2009 and March 31, 2010:

   
December 31,
2009
   
March 31,
2010
 
   
(in millions)
 
Unrecognized tax benefits                                                                          
  $ 187     $ 199  
Portion of unrecognized tax benefits that, if recognized,
would reduce the effective income tax rate
    10       11  
Interest accrued on unrecognized tax benefits                                                                          
    3       6  

During the three months ended March 31, 2010, the IRS notified CenterPoint Energy that it would perform an examination of CenterPoint Energy’s 2008 consolidated federal income tax return.

(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 and the ZENS indexed debt securities derivative 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, 2009
   
March 31, 2010
 
   
Carrying
Amount
   
Fair
Value
   
Carrying
Amount
   
Fair
Value
 
   
(in millions)
 
Financial liabilities:
                       
Long-term debt
  $ 9,900     $ 10,413     $ 9,459     $ 10,087  
 
(14)
Earnings Per Share

The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings per share calculations:

   
Three Months Ended March 31,
 
   
2009
   
2010
 
   
(in millions, except share and per share amounts)
 
Basic earnings per share calculation:
           
Net income
  $ 67     $ 114  
                 
Weighted average shares outstanding
    347,496,000       392,855,000  
                 
Basic earnings per share:
               
Net income
  $ 0.19     $ 0.29  
                 
Diluted earnings per share calculation:
               
Net income
  $ 67     $ 114  
                 
Weighted average shares outstanding
    347,496,000       392,855,000  
Plus: Incremental shares from assumed conversions:
               
Stock options (1)
    511,000       582,000  
Restricted stock
    1,150,000       1,641,000  
Weighted average shares assuming dilution
    349,157,000       395,078,000  
                 
Diluted earnings per share:
               
Net income
  $ 0.19     $ 0.29  
_________
 
 
 
(1)
Options to purchase 2,662,903 and 1,753,239 shares were outstanding for the three months ended March 31, 2009 and 2010, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares for the respective periods.

(15)
Reportable Business Segments

CenterPoint Energy’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. CenterPoint Energy uses operating income as the measure of profit or loss for its business segments.

CenterPoint Energy’s reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. The electric transmission and distribution function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents CenterPoint Energy’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, processing and treating operations. Other Operations consists primarily of other corporate operations which support all of CenterPoint Energy’s business operations.

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

   
For the Three Months Ended March 31, 2009
       
   
Revenues from
External
Customers
   
Net
Intersegment
Revenues
   
Operating
Income
   
Total Assets
as of December 31,
2009
 
Electric Transmission & Distribution
  $ 412 (1)   $     $ 70     $ 9,755  
Natural Gas Distribution
    1,418       3       118       4,535  
Competitive Natural Gas Sales and Services
    760       5       2       1,176  
Interstate Pipelines
    117       36       69       3,484  
Field Services
    56       1       26       1,045  
Other Operations
    3                   2,261 (2)
Eliminations
          (45 )           (2,483 )
Consolidated
  $ 2,766     $     $ 285     $ 19,773  

   
For the Three Months Ended March 31, 2010
       
   
Revenues from
External
Customers
   
Net
Intersegment
Revenues
   
Operating
Income
   
Total Assets
as of March 31,
2010
 
Electric Transmission & Distribution
  $ 482 (1)   $     $ 107     $ 9,597  
Natural Gas Distribution
    1,533       4       139       4,597  
Competitive Natural Gas Sales and Services
    844       8       15       1,215  
Interstate Pipelines
    103       35       72       3,526  
Field Services
    58       10       23       1,199  
Other Operations
    3             1       2,378 (2)
Eliminations
          (57 )           (3,161 )
Consolidated
  $ 3,023     $     $ 357     $ 19,351  
_________
 
(1)
Sales to subsidiaries of NRG Retail LLC, the successor to RRI's Texas retail business, in the three months ended March 31, 2009 and 2010 represented approximately $142 million and $135 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to subsidiaries of TXU Energy Retail Company LLC in the three months ended March 31, 2009 and 2010 represented approximately $37 million and $42 million, respectively, of CenterPoint Houston’s transmission and distribution revenues.
 
 
 
(2)
Included in total assets of Other Operations as of December 31, 2009 and March 31, 2010 are pension and other postemployment related regulatory assets of $731 million and $721 million, respectively.
 
(16)
Subsequent Events

On April 22, 2010, CenterPoint Energy’s board of directors declared a regular quarterly cash dividend of $0.195 per share of common stock payable on June 10, 2010, to shareholders of record as of the close of business on May 14, 2010.
 

 


Item 2.      MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

The following discussion and analysis should be read in combination with our Interim Condensed Financial Statements contained in this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2009 (2009 Form 10-K).

EXECUTIVE SUMMARY
Recent Events

Long-Term Gas Gathering and Treating Agreements

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

In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas and expects to place those facilities in service by the end of 2010.  CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million.  As of March 31, 2010, approximately $260 million has been spent on this project, including the purchase of existing facilities.

Under the agreements, Encana or Shell can elect to require CEFS to further expand the facilities in order to gather and treat an additional volume of up to 1 billion cubic feet (Bcf) per day, and in March 2010, Encana and Shell exercised initial expansion elections to increase gathering capacity by 200 MMcf per day to 900 MMcf. Total capital expenditures for this expansion are estimated to be $50 million to $70 million, and the increased capacity is expected to be in service by the first quarter of 2011.  In connection with the expansion, Encana and Shell each made incremental volume commitments for the capacity expansion.

If Encana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 Bcf per day (including the 200 MMcf per day already elected), CEFS estimates that the expansion would cost as much as $300 million, and Encana and Shell would provide incremental volume commitments.

In April 2010, CEFS entered into additional long-term agreements with Encana and Shell to provide gathering and treating services for their natural gas production from the Haynesville Shale and Bossier Shale formations in Texas and Louisiana. Pursuant to the agreements, CEFS has also acquired existing jointly-owned gathering facilities (the Olympia Gathering System) from Encana and Shell in De Soto and Red River parishes in northwest Louisiana.

CEFS has integrated the acquired facilities with CEFS’s Magnolia Gathering System, allowing CEFS to commence gathering and treating services immediately for up to 150 MMcf per day of natural gas. Under the terms of the agreements, CEFS will expand the acquired facilities to gather and treat up to 580 MMcf per day of natural gas. Each of the agreements includes volume commitments and dedicated acreage for which CEFS has exclusive rights to gather Shell’s and Encana’s natural gas production.

New construction to reach capacity of 580 MMcf per day includes more than 180 miles of pipelines, over 8,000 horsepower of compression and over 680 MMcf per day of treating capacity.

CEFS estimates that the capital cost to purchase the existing facilities and construct new facilities for the Olympia Gathering System to gather 580 MMcf per day will be as much as $400 million. If Encana and Shell elect, CEFS will expand the project to gather and process additional future volumes of up to 520 MMcf per day, for a total Olympia Gathering System capacity of up to 1.1 Bcf per day.  CEFS estimates that an expansion to process 1.1 Bcf would cost as much as an additional $200 million.  Encana and Shell would provide incremental volume commitments in connection with expansions of the Olympia Gathering System.
 
 
Debt Transactions

In January 2010, we purchased $290 million principal amount of pollution control bonds issued on our behalf at 101% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds.  Prior to the purchase, the pollution control bonds had a fixed rate of interest of 5.125%. The purchase reduces temporary investments and leverage while providing us with the flexibility to finance future capital needs in the tax-exempt market through a remarketing of these bonds.

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

Advanced Metering System and Distribution Automation (Intelligent Grid)

In October 2009, the U.S. Department of Energy (DOE) notified CenterPoint Energy Houston Electric, LLC (CenterPoint Houston) that it had been selected for a $200 million grant for its advanced metering system (AMS) and intelligent grid (IG) projects.  In March 2010, CenterPoint Houston and the DOE completed negotiations and finalized the agreement. The DOE will reimburse CenterPoint Houston 50% of its eligible costs until the total amount of the grant has been paid.  CenterPoint Houston will use $150 million of the grant funding to accelerate completion of its current deployment of advanced meters by 2012, instead of 2014 as originally scheduled.  CenterPoint Houston will use the other $50 million from the grant to begin deployment of an electric distribution grid automation strategy in a portion of its service territory over the next three years.  It is expected that the portion of the IG project subject to funding by DOE will cost approximately $115 million.  CenterPoint Houston believes the IG has the potential to provide a significant improvement in grid planning, operations, maintenance and customer service for its distribution system.

In March 2010, the Internal Revenue Service (IRS) announced through the issuance of Revenue Procedure 2010-20 that it was providing a safe harbor to corporations who receive a Smart Grid Investment Grant. The IRS stated that it would not challenge a corporation’s treatment of the grant as a non-taxable non-shareholder contribution to capital as long as the corporation properly reduced the tax basis of the property acquired with grant funds.

CenterPoint Houston Rate Case

The final order in its 2006 rate proceeding requires CenterPoint Houston to file a general rate case with the Public Utility Commission of Texas (Texas Utility Commission) by June 30, 2010 unless the Texas Utility Commission Staff and certain other parties determined by March 31, 2010 that no such filing would be necessary.  Those parties have advised CenterPoint Houston that a rate case filing is necessary, and, accordingly, CenterPoint Houston plans to file its application to change rates no later than the June 30, 2010 deadline.  The amount and other terms of the rate filing have not been established at this time.  Based on the prescribed timeline for processing such an application, CenterPoint Houston anticipates that a final order on that application would be entered in early 2011.



CONSOLIDATED RESULTS OF OPERATIONS

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

   
Three Months Ended March 31,
 
   
2009
   
2010
 
Revenues
  $ 2,766     $ 3,023  
Expenses
    2,481       2,666  
Operating Income
    285       357  
Gain (Loss) on Marketable Securities
    (34 )     38  
Gain (Loss) on Indexed Debt Securities
    22       (27 )
Interest and Other Finance Charges
    (129 )     (122 )
Interest on Transition and System Restoration Bonds
    (33 )     (36 )
Equity in Earnings of Unconsolidated Affiliates
          5  
Other Income, net
    4       1  
Income Before Income Taxes
    115       216  
Income Tax Expense
    (48 )     (102 )
Net Income
  $ 67     $ 114  
                 
Basic Earnings Per Share
  $ 0.19     $ 0.29  
                 
Diluted Earnings Per Share
  $ 0.19     $ 0.29  

Three months ended March 31, 2010 compared to three months ended March 31, 2009

We reported consolidated net income of $114 million ($0.29 per diluted share) for the three months ended March 31, 2010 compared to $67 million ($0.19 per diluted share) for the same period in 2009. The increase in net income of $47 million was primarily due to a $72 million increase in operating income (discussed by segment below), a change in net gain (loss) on our indexed debt and marketable securities of $23 million, a $7 million decrease in interest expense, excluding transition and system restoration bond-related interest expense and a $5 million increase in the equity in earnings of unconsolidated affiliates.  These increases in net income were partially offset by a $54 million increase in income tax expense.

Income Tax Expense

During the three months ended March 31, 2009 and 2010, the effective tax rate was 42% and 47%, respectively. The most significant item affecting the comparability of the effective tax rate is a non-cash, $21 million increase in the 2010 income tax expense as a result of a change in tax law upon the enactment in March 2010 of the Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act of 2010. Additionally, the comparability of the effective tax rate is affected by a $4 million increase in the 2009 income tax expense related to a state tax examination.

The change in tax law, which becomes effective for tax years beginning after December 31, 2012, eliminates the tax deductibility of the portion of retiree health care costs which are reimbursed by Medicare Part D subsidies. Based upon the actuarially determined net present value of lost future retiree health care deductions related to the subsidies, we reduced our deferred tax asset related to future retiree health care deductions by approximately $32 million as of March 31, 2010.  The portion of the reduction that we believe will be recovered through the regulatory process, or approximately $11 million, has been recorded as a regulatory asset.  The remaining $21 million of the reduction in our deferred tax asset has been reflected as a charge to income tax expense.
 

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (in millions) for each of our business segments for the three months ended March 31, 2009 and 2010.  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 March 31,
 
   
2009
   
2010
 
Electric Transmission & Distribution
  $ 70     $ 107  
Natural Gas Distribution
    118       139  
Competitive Natural Gas Sales and Services
    2       15  
Interstate Pipelines
    69       72  
Field Services
    26       23  
Other Operations
          1  
Total Consolidated Operating Income
  $ 285     $ 357  

Electric Transmission & Distribution

For information regarding factors that may affect the future results of operations of our Electric Transmission & Distribution business segment, please read "Risk Factors Risk Factors Affecting Our Electric Transmission & Distribution Business," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Risks Common to Our Business and Other Risks" in Item 1A of Part I of our 2009 Form 10-K.

The following tables provide summary data of our Electric Transmission & Distribution business segment for the three months ended March 31, 2009 and 2010 (in millions, except throughput and customer data):

   
Three Months Ended March 31,
 
   
2009
   
2010
 
Revenues:
           
Electric transmission and distribution utility
  $ 346     $ 386  
Transition and system  restoration bond companies
    66       96  
Total revenues
    412       482  
Expenses:
               
Operation and maintenance, excluding transition and system
restoration bond companies
    188       190  
Depreciation and amortization, excluding transition and system
restoration bond companies
    68       73  
Taxes other than income taxes
    53       52  
Transition and system restoration bond companies
    33       60  
Total expenses
    342       375  
Operating Income
  $ 70     $ 107  
                 
Operating Income:
               
Electric transmission and distribution utility
    37       71  
Transition and system restoration bond companies (1)
    33       36  
Total segment operating income
  $ 70     $ 107  
                 
Throughput (in gigawatt-hours (GWh)):
               
Residential
    3,967       5,173  
Total
    15,142       16,436  
                 
Number of metered customers at period end:
               
Residential
    1,838,766       1,858,403  
Total
    2,082,930       2,104,786  
___________
 
(1)
Represents the amount necessary to pay interest on the transition and system restoration bonds.
 

Three months ended March 31, 2010 compared to three months ended March 31, 2009

Our Electric Transmission & Distribution business segment reported operating income of $107 million for the three months ended March 31, 2010, consisting of $71 million from the regulated electric transmission and distribution utility (TDU) and $36 million related to transition and system restoration bonds companies. For the three months ended March 31, 2009, operating income totaled $70 million, consisting of $37 million from the TDU and $33 million related to transition and system restoration bond companies. TDU revenues increased $40 million primarily due to increased usage ($26 million) in part due to colder weather, revenues from implementation of the AMS ($9 million), higher transmission-related revenues ($5 million) and higher revenues due to customer growth ($4 million) from the addition of nearly 22,000 new customers, partially offset by a credit to customers related to deferred income taxes associated with Hurricane Ike storm restoration costs ($6 million).  Operation and maintenance expenses increased due to higher transmission costs billed by transmission providers ($3 million) and increased AMS project expenses ($4 million), partially offset by lower pension costs ($4 million).  Increased depreciation expense is related to increased investment in AMS ($4 million) and other capital additions ($1 million).

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 Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Risks Common to Our Business and Other Risks" in Item 1A of Part I of our 2009 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, 2009 and 2010 (in millions, except throughput and customer data):

   
Three Months Ended March 31,
 
   
2009
   
2010
 
Revenues
  $ 1,421     $ 1,537  
Expenses:
               
Natural gas
    1,045       1,139  
Operation and maintenance
    169       167  
Depreciation and amortization
    40       40  
Taxes other than income taxes
    49       52  
Total expenses
    1,303       1,398  
Operating Income
  $ 118     $ 139  
                 
Throughput (in billion cubic feet (Bcf)):
               
Residential
    78       96  
Commercial and industrial
    77       87  
Total Throughput
    155       183  
                 
Number of customers at period end:
               
Residential
    2,996,455       3,012,856  
Commercial and industrial
    246,405       246,676  
Total
    3,242,860       3,259,532  

Three months ended March 31, 2010 compared to three months ended March 31, 2009

Our Natural Gas Distribution business segment reported operating income of $139 million for the three months ended March 31, 2010 compared to $118 million for the three months ended March 31, 2009.  Operating income increased $21 million primarily as a result of increased margin (revenue less cost of natural gas) and lower bad debt expense.  The increase in margin ($22 million) is due to increased use ($9 million), primarily caused by colder weather, and higher transportation ($4 million), non-utility ($3 million) and other miscellaneous revenues ($4 million).  Revenues related to both energy efficiency programs and gross receipts taxes are substantially offset by the related expenses.  Operation and maintenance expense declined $2 million due to lower bad debt expense ($5
 
 
29

 
 million) related to improved collection efforts and lower pension expense ($2 million), partially offset by higher labor costs ($2 million) and other expense increases ($3 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 Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses," "─ Risk Factors Associated with Our Consolidated Financial Condition" and "─ Risks Common to Our Business and Other Risks" in Item 1A of Part I of our 2009 Form 10-K.

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three months ended March 31, 2009 and 2010 (in millions, except throughput and customer data):

   
Three Months Ended March 31,
 
   
2009
   
2010
 
Revenues
  $ 765     $ 852  
Expenses:
               
Natural gas
    752       826  
Operation and maintenance
    10       9  
Depreciation and amortization
    1       1  
Taxes other than income taxes
          1  
Total expenses
    763       837  
Operating Income
  $ 2     $ 15  
                 
Throughput (in Bcf):
    141       141  
                 
Number of customers at period end
    10,862       11,369  

Three months ended March 31, 2010 compared to three months ended March 31, 2009

Our Competitive Natural Gas Sales and Services business segment reported operating income of $15 million for the three months ended March 31, 2010 compared to $2 million for the three months ended March 31, 2009.  The increase in operating income of $13 million is primarily due to the favorable impact of the mark-to-market valuation for non-trading financial derivatives for 2010 of $3 million versus an unfavorable impact of $19 million for the same period in 2009.  A further favorable impact of $5 million is attributable to the $6 million write down of gas in the first quarter of 2009 to the lower of cost or market as compared to a write down of less than $1 million in the first quarter of 2010.  Offsetting these favorable impacts is a $14 million decrease in margin attributable to reduced basis spreads on pipeline transport opportunities and decreased winter storage spreads.

Interstate Pipelines

For information regarding factors that may affect the future results of operations of our Interstate Pipelines business segment, please read "Risk Factors