Quarterly Report

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 )

____________________________

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

PART I. FINANCIAL INFORMATION

Item 1.      FINANCIAL STATEMENTS

 

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

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

 

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

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

 

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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

 

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

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

 

 

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

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

 

 

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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.

 

 

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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

 

 

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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%

 

 

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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.

 

 

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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.

 

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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	)

_________

 

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(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.

 

		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

_________

		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

_________

		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

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

		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

		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	)

		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

		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

		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

_________

		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

_________

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.

 

 

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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.

 

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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.

 

 

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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.

 

 

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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

 

 

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 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 ─ 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.

 

 

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