QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

100 CONSTELLATION WAY, BALTIMORE, MARYLAND 21202
(Address of principal executive offices) (Zip Code)

410-470-2800
(~~Registrants'~~Registrant's telephone number, including area code)

2 CENTER PLAZA, 110 WEST FAYETTE STREET, BALTIMORE, MARYLAND 21202
(Address of principal executive offices) (Zip Code)

410-234-5000
(~~Registrants'~~Registrant's telephone number, including area code)

NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrants (1) have 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, and (2) have been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether Constellation Energy Group, Inc. 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether Baltimore Gas and Electric Company 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether Constellation Energy Group, Inc. 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~~

Indicate by check mark whether Baltimore Gas and Electric Company 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~~

Indicate by check mark whether Constellation Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o No ý

Indicate by check mark whether Baltimore Gas and Electric Company is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o No ý

Common Stock, without par value ~~200,630,389~~201,681,394 shares outstanding
of Constellation Energy Group, Inc. on ~~July 31, 2009.~~April 30, 2010.

Baltimore Gas and Electric Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form in the reduced disclosure format.

See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.

* Unaudited
See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.

See Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements.
Certain prior-period amounts have been reclassified to conform with the current period's presentation.

~~Table of Contents~~

~~CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)~~

~~Baltimore Gas and Electric Company and Subsidiaries~~

Three Months Ended
June 30,
Six Months Ended
June 30,

2009
2008
2009
2008

(In millions)

Revenues

Electric revenues
$ 655.7 $ 448.7 $ 1,462.5 $ 1,158.1

Gas revenues
111.7 188.1 498.6 584.5

Total revenues
767.4 636.8 1,961.1 1,742.6
Expenses

Operating expenses

Electricity purchased for resale
402.5 404.3 927.7 859.6

Gas purchased for resale
51.6 127.7 309.7 397.7

Operations and maintenance
148.9 136.8 275.9 270.4

Depreciation and amortization
65.7 59.0 132.6 121.7

Taxes other than income taxes
44.4 40.1 92.2 86.6

Total expenses
713.1 767.9 1,738.1 1,736.0

Income (Loss) from Operations
54.3 (131.1 ) 223.0 6.6
Other Income
7.2 6.3 14.7 14.2
Fixed Charges

Interest expense
36.0 32.0 72.7 67.0

Allowance for borrowed funds used during construction
(1.1 ) (1.1 ) (2.1 ) (2.1 )

Total fixed charges
34.9 30.9 70.6 64.9

Income (Loss) Before Income Taxes
26.6 (155.7 ) 167.1 (44.1 )
Income Taxes
10.6 (51.5 ) 66.1 (16.1 )

Net Income (Loss)
16.0 (104.2 ) 101.0 (28.0 )
Preference Stock Dividends
3.3 3.3 6.6 6.6

Net Income (Loss) Attributable to Common Stock before Noncontrolling Interests
12.7 (107.5 ) 94.4 (34.6 )
Net Loss Attributable to Noncontrolling Interests
— 0.1 — 0.2

Net Income (Loss) Attributable to Common Stock
$ 12.7 $ (107.4 ) $ 94.4 $ (34.4 )

~~See Notes to Consolidated Financial Statements.~~
~~Certain prior-period amounts have been reclassified to conform with the current period's presentation.~~

Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

June 30,
2009*
December 31,
2008

(In millions)

Assets

Current Assets

Cash and cash equivalents
$ 4.6 $ 10.7

Accounts receivable (net of allowance for uncollectibles of$51.2 and $33.3, respectively)
304.6 327.0

Accounts receivable, unbilled (net of allowance for uncollectibles of$0.9 and $0.9, respectively)
171.9 232.3

Investment in cash pool, affiliated company
154.0 148.8

Accounts receivable, affiliated companies
2.1 4.3

Fuel stocks
59.1 143.7

Materials and supplies
35.2 38.4

Prepaid taxes other than income taxes
0.5 51.0

Regulatory assets (net)
63.5 79.7

Restricted cash
23.0 23.7

Other
3.4 10.8

Total current assets
821.9 1,070.4

Investments and Other Assets

Regulatory assets (net)
454.5 494.7

Receivable, affiliated company
316.4 161.1

Other
122.0 131.6

Total investments and other assets
892.9 787.4

Utility Plant

Plant in service

Electric
4,604.4 4,493.7

Gas
1,231.0 1,221.1

Common
495.5 476.3

Total plant in service
6,330.9 6,191.1

Accumulated depreciation
(2,255.5 ) (2,191.0 )

Net plant in service
4,075.4 4,000.1

Construction work in progress
232.3 225.7

Plant held for future use
2.3 2.6

Net utility plant
4,310.0 4,228.4

Total Assets

$
6,024.8
$
6,086.2

				*March 31,* 2010*			December 31, 2009


				(In millions)
Assets
	Current Assets
		Cash and cash equivalents		$	310.5		$	13.6
		Accounts receivable (net of allowance for uncollectibles of$35.9 and $46.2, respectively)			367.8			311.7
		Accounts receivable, unbilled (net of allowance for uncollectibles of$1.0 and $1.0, respectively)			194.7			252.7
		Investment in cash pool, affiliated company			—			314.7
		Accounts receivable, affiliated companies			1.7			15.4
		Fuel stocks			28.7			73.8
		Materials and supplies			36.4			31.9
		Prepaid taxes other than income taxes			24.5			49.5
		Regulatory assets (net)			45.3			72.5
		Restricted cash—consolidated variable interest entity			48.1			24.3
		Deferred income taxes			—			11.2
		Other			10.0			11.3

		Total current assets			1,067.7			1,182.6

	Investments and Other Assets
		Regulatory assets (net)			399.8			414.4
		Receivable, affiliated company			319.9			326.2
		Other			59.0			98.2

		Total investments and other assets			778.7			838.8

	Utility Plant
		Plant in service
			Electric		4,816.3			4,772.4
			Gas		1,267.9			1,260.6
			Common		496.8			499.0

			Total plant in service		6,581.0			6,532.0
		Accumulated depreciation			(2,343.5	)		(2,318.2	)

		Net plant in service			4,237.5			4,213.8
		Construction work in progress			232.7			215.5
		Plant held for future use			3.7			2.4

		Net utility plant			4,473.9			4,431.7

	Total Assets			$	6,320.3		$	6,453.1

* Unaudited
See Notes to Consolidated Financial Statements.
~~Certain prior-period amounts have been reclassified to conform with the current period's presentation.~~

Table of Contents

CONSOLIDATED BALANCE SHEETS

Baltimore Gas and Electric Company and Subsidiaries

June 30,
2009*
December 31,
2008

(In millions)

Liabilities and Equity

Current Liabilities

Short-term borrowings
$ 339.9 $ 370.0

Current portion of long-term debt
66.5 90.0

Accounts payable and accrued liabilities
119.4 231.0

Accounts payable and accrued liabilities, affiliated companies
58.7 97.0

Customer deposits
74.0 72.3

Current portion of deferred income taxes
27.8 40.2

Accrued taxes
51.1 18.8

Accrued expenses and other
86.5 98.4

Total current liabilities
823.9 1,017.7

Deferred Credits and Other Liabilities

Deferred income taxes
904.6 843.3

Payable, affiliated company
244.1 243.2

Deferred investment tax credits
10.1 10.6

Other
24.8 28.6

Total deferred credits and other liabilities
1,183.6 1,125.7

Long-term Debt

Rate stabilization bonds
537.8 564.4

Other long-term debt
1,443.0 1,443.0

6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities
257.7 257.7

Long-term debt of nonregulated businesses
— 25.0

Unamortized discount and premium
(2.3 ) (2.4 )

Current portion of long-term debt
(66.5 ) (90.0 )

Total long-term debt
2,169.7 2,197.7

Equity

Common shareholder's equity:

Common stock
912.2 912.2

Retained earnings
719.8 625.4

Accumulated other comprehensive income
0.6 0.6

Total common shareholder's equity
1,632.6 1,538.2

Preference stock not subject to mandatory redemption
190.0 190.0

Noncontrolling interest
25.0 16.9

Total equity
1,847.6 1,745.1

Commitments, Guarantees, and Contingencies (see Notes)

Total Liabilities and Equity

$
6,024.8
$
6,086.2

			*March 31,* 2010*			December 31, 2009


			(In millions)
Liabilities and Equity
	Current Liabilities
		Short-term borrowings	$	—		$	46.0
		Current portion of long-term debt—consolidated variable interest entity		56.5			56.5
		Accounts payable and accrued liabilities		130.9			166.0
		Accounts payable and accrued liabilities, affiliated companies		80.3			98.3
		Customer deposits		76.9			76.0
		Deferred income taxes		25.6			—
		Accrued taxes		79.6			80.2
		Residential customer rate credit		—			112.4
		Accrued expenses and other		97.7			96.1

		Total current liabilities		547.5			731.5

	Deferred Credits and Other Liabilities
		Deferred income taxes		1,099.5			1,087.6
		Payable, affiliated company		244.1			243.4
		Deferred investment tax credits		9.2			9.5
		Liability for uncertain tax positions		71.4			73.3
		Other		17.2			20.0

		Total deferred credits and other liabilities		1,441.4			1,433.8

	Long-term Debt
		Rate stabilization bonds—consolidated variable interest entity		510.9			510.9
		Other long-term debt		1,431.5			1,431.5
		6.20% deferrable interest subordinated debentures due October 15, 2043 to wholly owned BGE Capital Trust II relating to trust preferred securities		257.7			257.7
		Unamortized discount and premium		(2.1	)		(2.2	)
		Current portion of long-term debt—consolidated variable interest entity		(56.5	)		(56.5	)

		Total long-term debt		2,141.5			2,141.4

	Equity
		Common shareholder's equity		1,999.9			1,938.8
		Preference stock not subject to mandatory redemption		190.0			190.0
		Noncontrolling interest		—			17.6

		Total equity		2,189.9			2,146.4

	Commitments, Guarantees, and Contingencies (see Notes)
	Total Liabilities and Equity		$	6,320.3		$	6,453.1

* Unaudited
See Notes to Consolidated Financial Statements.
~~Certain prior-period amounts have been reclassified to conform with the current period's presentation.~~

Table of Contents

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Baltimore Gas and Electric Company and Subsidiaries

Six Months Ended June 30,
2009
2008

(In millions)

Cash Flows From Operating Activities

Net income (loss)
$ 101.0 $ (28.0 )

Adjustments to reconcile to net cash provided by operating activities

Depreciation and amortization
132.6 121.7

Other amortization
3.7 6.9

Deferred income taxes
46.7 11.3

Investment tax credit adjustments
(0.5 ) (0.7 )

Deferred fuel costs
32.4 19.7

Defined benefit plan expenses
17.5 18.7

Allowance for equity funds used during construction
(4.2 ) (4.0 )

Accrual of Maryland settlement agreement credit
— 188.2

Changes in:

Accounts receivable
82.8 36.7

Accounts receivable, affiliated companies
2.2 (3.6 )

Materials, supplies, and fuel stocks
87.8 5.0

Other current assets
57.9 (54.4 )

Accounts payable and accrued liabilities
(111.6 ) 68.7

Accounts payable and accrued liabilities, affiliated companies
(38.3 ) 50.7

Other current liabilities
10.6 88.9

Long-term receivables and payables, affiliated companies
(171.8 ) (42.0 )

Other
(3.1 ) (14.9 )

Net cash provided by operating activities
245.7 468.9

Cash Flows From Investing Activities

Utility construction expenditures (excluding equity portion of allowance for funds used during construction)
(166.7 ) (219.6 )

Change in cash pool at parent
(5.2 ) (102.7 )

Sales of investments and other assets
— 12.9

Decrease (increase) in restricted funds
0.7 (207.7 )

Net cash used in investing activities
(171.2 ) (517.1 )

Cash Flows From Financing Activities

Proceeds from issuance of long-term debt
— 400.0

Repayment of long-term debt
(51.6 ) (259.5 )

Net repayment of short-term borrowings
(30.1 ) —

Debt issuance costs
(0.3 ) (2.4 )

Contribution from noncontrolling interest
8.0 —

Preference stock dividends paid
(6.6 ) (6.6 )

Distribution to parent
— (86.0 )

Net cash (used in) provided by financing activities
(80.6 ) 45.5

Net Decrease in Cash and Cash Equivalents
(6.1 ) (2.7 )
Cash and Cash Equivalents at Beginning of Period
10.7 17.6

Cash and Cash Equivalents at End of Period
$ 4.6 $ 14.9

Three Months Ended March 31,				2010			2009


				(In millions)
Cash Flows From Operating Activities
	Net income			$	64.4		$	85.0
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation and amortization			67.7			66.9
		Other amortization			(0.3	)		0.9
		Deferred income taxes			45.6			9.0
		Investment tax credit adjustments			(0.3	)		(0.3	)
		Deferred fuel costs			23.9			16.6
		Defined benefit plan expenses			8.2			9.2
		Allowance for equity funds used during construction			(2.5	)		(2.0	)
		Changes in
			Accounts receivable		0.1			(45.7	)
			Accounts receivable, affiliated companies		13.7			1.3
			Materials, supplies, and fuel stocks		40.6			113.2
			Other current assets		25.8			29.3
			Accounts payable and accrued liabilities		(34.5	)		(66.7	)
			Accounts payable and accrued liabilities, affiliated companies		(18.0	)		14.8
			Other current liabilities		(73.0	)		102.2
			Long-term receivables and payables, affiliated companies		(1.2	)		(1.9	)
			Other		(38.6	)		16.5

	Net cash provided by operating activities				121.6			348.3

Cash Flows From Investing Activities
	Utility construction expenditures (excluding equity portion of allowance for funds used during construction)				(87.2	)		(79.3	)
	Change in cash pool at parent				314.7			(238.9	)
	Proceeds from sales of investments and other assets				20.9			—
	Increase in restricted funds				(23.8	)		(24.5	)

	Net cash provided by (used in) investing activities				224.6			(342.7	)

Cash Flows From Financing Activities
	Repayment of short-term borrowings				(46.0	)		—
	Preference stock dividends paid				(3.3	)		(3.3	)

	Net cash used in financing activities				(49.3	)		(3.3	)

Net Increase in Cash and Cash Equivalents					296.9			2.3
Cash and Cash Equivalents at Beginning of Period					13.6			10.7

Cash and Cash Equivalents at End of Period				$	310.5		$	13.0

See Notes to Consolidated Financial Statements.
~~Certain prior-period amounts have been reclassified to conform with the current period's presentation.~~

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Basis of Presentation

This Quarterly Report on Form 10-Q is a combined report of Constellation Energy Group, Inc. (Constellation Energy) and Baltimore Gas and Electric Company (BGE). References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE.

Various factors can have a significant impact on our results for interim periods. This means that the results for this quarter are not necessarily indicative of future quarters or full year results given the seasonality of our business.

Our interim financial statements on the previous pages reflect all adjustments that management believes are necessary for the fair statement of the results of operations for the interim periods presented. These adjustments are of a normal recurring nature.

Reclassifications

In accordance with the presentation requirements for consolidated variable interest entities (VIEs), which we adopted on January 1, 2010, we have separately presented the following material assets and liabilities of these VIEs on our, and/or BGE's, Consolidated Balance Sheets:

•: "Accounts receivable—consolidated variable interest entities,"
•: "Restricted cash—consolidated variable interest entities,"
•: "Current portion of long-term debt—consolidated variable interest entities,"
•: "Accounts payable and accrued liabilities—consolidated variable interest entities," and
•: "Long-term Debt, Net of Current Portion—consolidated variable interest entities."

We discuss our adoption of the reporting requirements for consolidated variable interest entities below in theVariable Interest Entities section.

We have ~~evaluated events or transactions that occurred after June 30, 2009 for inclusion in these financial statements through August 7, 2009, the date these financial statements were issued.~~

~~Basis of Presentation~~

~~Reclassifications~~

~~We have~~also reclassified certain prior-period amounts:

•

~~In accordance with Statement of Financial Accounting Standards (SFAS) No. 160,~~~~Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51~~~~, which we adopted on January 1, 2009, we~~We have separately ~~presented:~~

•: ~~"Net income (loss) attributable to noncontrolling interests" on our, and BGE's, Consolidated Statements of Income (Loss),~~
•: ~~"Noncontrolling interests" and "BGE Preference Stock Not Subject to Mandatory Redemption" as noncontrolling interests on our Consolidated Balance Sheets,~~
•: ~~"Comprehensive income attributable to noncontrolling interests,~~presented "Other comprehensive income—other equity method investees, net of taxes" inthat was previously reported within "Reclassification of net loss on hedging instruments from OCI to net income (loss), net of taxes" and "Net unrealized gain (loss) on hedging instruments, net of taxes" on our Consolidated Statements of Comprehensive Income (Loss)~~, and~~
•: ~~"BGE preference stock dividends paid" in the financing section of our Consolidated Statements of Cash Flows.~~

~~We discuss our adoption of SFAS No. 160 in more detail on page 41.~~

~~We also made the following reclassifications:~~

•: We have separately presented "Amortization of nuclear fuel," "Amortization of energy contracts," and "All other amortization" that were previously reported within "Depreciation, depletion, and amortization" on our Consolidated Statements of Cash Flows..
•: We have separately presented ~~"Net collateral and margin"~~"Electricity purchased for resale from affiliate" that was previously reported within ~~other working capital accounts~~"Electricity purchased for resale" on ~~our~~BGE's Consolidated Statements of ~~Cash Flows.~~Income.
•: We have separately presented ~~"Other amortization"~~"Operations and maintenance from affiliate" that was previously reported within ~~"Depreciation~~"Operations and ~~amortization"~~maintenance" on BGE's Consolidated Statements of ~~Cash Flows.~~Income.

~~Investment Agreement with EDF Group~~

On December 17, 2008, we entered into an Investment Agreement with EDF Group and related entities (EDF) under which EDF will purchase from us a 49.99% membership interest in our nuclear generation and operation business for $4.5 billion (subject to certain adjustments). We discuss the Investment Agreement with EDF in more detail in~~Note 15~~ ~~of our 2008 Annual Report on Form 10-K.~~

~~Merger Termination and Strategic Alternatives Costs~~

We incurred costs during the quarter and six months ended June 30, 2009 related to the terminated merger agreement with MidAmerican Energy Holdings Company (MidAmerican), the conversion of our Series A Preferred Stock, the transactions related to EDF, and other strategic alternatives costs. These costs totaled $4.0 million pre-tax and $46.3 million pre-tax for the quarter and six months ended June 30, 2009, respectively, and primarily relate to the first quarter of 2009 write-off of the unamortized debt discount associated with the 14% Senior Notes (Senior Notes) that were repaid in full to MidAmerican in January 2009.

Variable Interest Entities

Effective January 1, 2010, we adopted new accounting, presentation, and disclosure requirements related to VIEs. As a result of ~~June 30, 2009, we~~our assessment and implementation of the new requirements, our accounting and disclosures related to VIEs were impacted as follows:

•: We have presented separately on our Consolidated Balance Sheets, to the extent material, the assets of our consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit.
•: The new requirements emphasize a qualitative assessment of whether the equity holders of the entity have the power to direct matters that most significantly impact the entity. We have evaluated all existing entities under the new VIE accounting requirements, both those previously considered VIEs and those considered potential VIEs. Our accounting for and disclosure about VIEs did not change materially as a result of these assessments.

We consolidate three ~~variable interest entities (VIE) in~~VIEs for which we ~~were~~are the primary beneficiary, and we ~~had~~have significant interests in ~~seven~~six VIEs for which we ~~did~~do not have controlling financial interests and, accordingly, ~~were~~are not the primary beneficiary. ~~We discuss our VIEs in more detail in~~~~Note 4~~ ~~of our 2008 Annual Report on Form 10-K.~~

Consolidated Variable Interest Entities

In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy-remote limited liability company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to

~~Table of Contents~~

assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Maryland Senate Bill 1. ~~We discuss Senate Bill 1 in more detail in~~~~Management's Discussion and Analysis~~ ~~section of our 2008 Annual Report on Form 10-K.~~

BGE determined that BondCo is a VIE for which it is the primary beneficiary. As a result, BGE, and we, consolidated BondCo.

The BondCo assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from customers for rate stabilization charges to BondCo. During the quarter ~~and six months~~ ended ~~June 30, 2009,~~March 31, 2010, BGE remitted ~~$17.6~~$23.8 million ~~and $42.1 million, respectively,~~ to BondCo.

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BGE did not provide any additional financial support to BondCo during the quarter ~~and six months~~ ended ~~June 30, 2009.~~March 31, 2010. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo.

During ~~the second quarter of~~ 2009, our retail gas ~~customer supply~~ operation formed two new entities and combined them with our existing retail gas ~~customer supply~~ operation into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement ~~(GSA)~~ with a third party gas supplier. While we own 100% of these entities, we determined that the retail gas entity group is a VIE because ~~we provide~~there is not sufficient equity to fund the group's activities without the additional credit support ~~to the gas supplier~~we provide in the form of a letter of credit and a parental guarantee. We are the primary beneficiary of the retail gas entity group; accordingly, we consolidate the retail gas entity group as a VIE, including the existing retail gas customer supply operation, which we formerly consolidated as a voting interest entity.

The gas supply arrangement is collateralized as follows:

•: The assets of the retail gas entity group must be used to settle obligations under the third party gas supply agreement before it can make any distributions to us,
•: The third party gas supplier has a collateral interest in all of the assets and equity of the retail gas entity group, and
•: WeAs of March 31, 2010, we provided a $100 million parental guarantee and a ~~$160~~$49 million letter of credit to the third party gas supplier in support of the retail gas entity group. ~~The letter of credit has been decreased to $100 million as of June 30, 2009.~~

Other than credit support provided by the parental guarantee and the letter of credit, we do not have any contractual or other obligations to provide additional financial support to the retail gas entity group. The retail gas entity group creditors do not have any recourse to our general credit. Finally, we did not provide any financial support to the retail gas entity group during the first quarter ~~ended June 30, 2009,~~of 2010, other than the ~~initial equity contribution,~~ parental guarantee and the letter of credit.

~~The carrying amounts and classification of the above consolidated VIEs' assets and liabilities included in our consolidated financial statements at June 30, 2009 are as follows:~~

(In millions)

Current assets
$ 542.0
Noncurrent assets
63.0

Total Assets
$ 605.0

Current liabilities
$ 467.6
Noncurrent liabilities
479.8

Total Liabilities
$ 947.4

~~All of the assets in the table above are restricted for settlement of the VIE obligations and all of the liabilities in the table above can only be settled using VIE resources.~~

We also consolidate a retail power supply VIE for which we became the primary beneficiary in 2008 as a result of a modification to its contractual arrangements that changed the allocation of the economic risks and rewards of the VIE among the variable interest holders. The consolidation of this VIE did not have a material impact on our financial results or financial condition.

The carrying amounts and classification of the above three consolidated VIEs' assets and liabilities included in our consolidated financial statements at March 31, 2010 are as follows:

	(In millions)


Current assets	$	662.2
Noncurrent assets		43.9

Total Assets	$	706.1

Current liabilities	$	414.2
Noncurrent liabilities		431.6

Total Liabilities	$	845.8

All of the assets in the table above are restricted for settlement of the VIE obligations and all of the liabilities in the table above can only be settled using VIE resources.

Unconsolidated Variable Interest Entities

As of ~~June 30, 2009,~~March 31, 2010, we had significant interests in ~~seven~~six VIEs for which we were not the primary beneficiary. WeOther than the obligations listed in the table below, we have not provided any material financial or other support to these entities during the quarter ended March 31, 2010 and ~~six months ended June 30, 2009.~~

~~Table of Contents~~we do not intend to provide any additional financial or other support to these entities in the future.

The nature of these entities and our involvement with them are described in the following table:

VIE Category	Nature of Entity Financing	Nature of Constellation Energy Involvement	Obligations or Requirement to Provide Financial Support	Date of Involvement


Power contract monetization entities (2 entities)	Combination of debt and equity financing	Power sale agreements, loans, and guarantees	$~~40.4~~33.0 million in letters of credit	March 2005
Power projects and fuel supply entities (4 entities)	Combination of debt and equity financing	Equity investments and guarantees	$~~2.0~~5.0 million debt guarantee and working capital funding	Prior to 2003
~~Retail gas supply contract (1 entity)~~	~~Equity financing and proceeds from gas sales~~	~~Gas supply agreement~~	~~$3.8 million in obligations under gas supply agreement~~	~~February 2008~~

For purposes of aggregating the various VIEs for disclosure, we evaluated the risk and reward characteristics for, and the significance of, each VIE. We discuss the nature of our involvement with the power contract monetization VIEs in detail inNote 4 of our ~~2008~~2009 Annual Report on Form 10-K.

We concluded that power over the most economically significant activities of two of the power project VIEs is shared equally among the equity holders. Accordingly, neither of the equity holders consolidate these VIEs. The equity holders own 50% interests in these VIEs and all of

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the significant decisions require the mutual consent of the equity holders.

The following is summary information available as of ~~June 30, 2009~~March 31, 2010 about these entities:

Power
Contract
Monetization
VIEs
All
Other
VIEs
Total

(In millions)

Total assets
$ 574.0 $ 322.2 $ 896.2
Total liabilities
466.1 92.3 558.4
Our ownership interest
— 56.4 56.4
Other ownership interests
107.9 173.5 281.4
Our maximum exposure to loss
40.4 62.2 102.6
Carrying amount and location of variable interest on balance sheet:

-Other investments
— 56.4 56.4

		Power Contract Monetization VIEs		All Other VIEs		Total


		(In millions)
Total assets		$	566.6	$	344.6	$	911.2
Total liabilities			458.7		114.3		573.0
Our ownership interest			—		59.4		59.4
Other ownership interests			107.9		170.9		278.8
Our maximum exposure to loss			33.0		65.4		98.4
Carrying amount and location of variable interest on balance sheet:
	-Other investments		—		60.4		60.4

Our maximum exposure to loss is the loss that we would incur in the unlikely event that our interests in all of these entities were to become worthless and we were required to fund the full amount of all ~~guarantees~~obligations associated with these entities. Our maximum exposure to loss as of ~~June 30, 2009~~March 31, 2010 consists of the following:

•: ~~outstanding receivables, loans, and letters of credit totaling $44.2 million,~~
•: the carrying amount of our investment totaling ~~$56.4~~$60.4 million, and
•: debt and payment guarantees totaling ~~$2.0~~$38.0 million.

We assess the risk of a loss equal to our maximum exposure to be remote and, accordingly have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would affect the fair value or risk of our variable interests in these ~~variable interest entities.~~

~~Impairment Losses and Other Costs~~

~~Available for Sale Securities~~

We evaluated certain of our investments in equity securities during the six months ended June 30, 2009. The investments we evaluated included our nuclear decommissioning trust fund assets and other marketable securities. We record an impairment charge if an investment has experienced a decline in fair value to a level less than our carrying value and the decline is "other than temporary."

In making this determination, we evaluate the reasons for an investment's decline in value, the extent and duration of that decline, and factors that indicate whether and when the value will recover. For securities held in our nuclear decommissioning trust fund for which the market value is below book value, the decline in fair value is considered other than temporary and we write them down to fair value. We discuss our impairment policy for our nuclear decommissioning trust fund assets and other marketable securities in more detail in~~Note 1~~ ~~to our 2008 Annual Report on Form 10-K.~~

The fair values of certain of our marketable securities and certain of the securities held in our nuclear decommissioning trust fund declined below book value. As a result, we recorded a $1.9 million pre-tax impairment charge for the quarter ended June 30, 2009 and a $62.4 million pre-tax impairment charge for the six months ended June 30, 2009 for our nuclear decommissioning trust fund assets in the "Other income (expense)" line in our Consolidated Statements of Income (Loss). In addition, we recorded all other changes in the fair value of our nuclear decommissioning trust fund assets that are not impaired in other comprehensive (loss) income. We also recorded an impairment charge of $0.5 million for other marketable securities during the six months ended June 30, 2009.

The estimates we utilize in evaluating impairment of our available for sale securities require judgment and the evaluation of economic and other factors that are subject to variation, and the impact of such variations could be material.

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~~Equity Method Investments~~

~~Shipping Joint Venture~~

We record an impairment if an equity method investment has experienced a decline in fair value to a level less than our carrying value and the decline is "other than temporary." During the quarter ended June 30, 2009, we contemplated several potential courses of action together with our partner relating to the strategic direction of our shipping joint venture and our continuing involvement. This led to a decision to explore a plan to sell our 50% interest to a party related to our joint venture partner for negligible proceeds. During July 2009, a definitive purchase and sale agreement was executed between the parties and we expect the transaction to close in the third quarter of 2009. Upon completion, we will have no further continuing involvement associated with the activities of the joint venture.

As a result of the events that occurred during the second quarter of 2009, it became apparent that a decline in fair value to a level below the carrying value existed and that this decline was "other than temporary." As such, we recorded a pre-tax impairment charge of $59.0 million associated with our equity investment in our shipping joint venture within the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss), and reported the charge in our merchant energy business results for the second quarter of 2009.

~~Constellation Energy Partners LLC~~

As of March 31, 2009, the fair value of our investment in Constellation Energy Partners LLC (CEP) based upon its closing unit price was $10.0 million, which was lower than its carrying value of $24.0 million.

~~The decline in fair value of our investment in CEP reflected a number of other factors, including:~~

•: ~~continuing difficulties in the financial and credit markets in the United States,~~
•: ~~decreases in the market price of natural gas and oil,~~
•: ~~the effect of these factors on market perceptions of gas exploration and production master limited partnerships, and~~
•: ~~factors related to Constellation Energy's financial condition and possible sale of its investment in CEP.~~

As a result of evaluating these factors, we determined that the decline in the value of our investment is other than temporary. Therefore, we recorded a $14.0 million pre-tax impairment charge at March 31, 2009 to write-down our investment to fair value. We recorded this charge in "Impairment losses and other costs" in our Consolidated Statements of Income (Loss). We did not record an impairment charge in the second quarter of 2009. To the extent that the market price of our investment declines further in future quarters, we may record additional write-downs if we determine that those additional declines are other than temporary.

~~Other Costs~~

During the quarter and six months ended June 30, 2009, we recorded $8.2 million and $22.3 million pre-tax charges, respectively, in the "Impairment losses and other costs" line in our Consolidated Statements of Income (Loss) primarily related to certain long-lived assets that ceased to be used in connection with the divestiture of a majority of our international commodities operation and our Houston-based gas trading operation as well as the write-off of an uncollectible advance to an affiliate.

~~Workforce Reduction Costs~~

We incurred workforce reduction costs during the six months ended June 30, 2009 primarily related to the divestiture of a majority of our international commodities operation as well as some smaller restructurings elsewhere in our organization. We recognized an $11.2 million pre-tax charge during the six months ended June 30, 2009 related to the elimination of approximately 180 positions. We expect these restructurings will be completed within the next 12 months. The following table summarizes the status of the involuntary severance liability at June 30, 2009:

(In millions)

Initial severance liability balance
$ 10.8
Additional expense recorded in the second quarter of 2009
0.4
Amounts recorded as pension and postretirement liabilities
—

Net cash severance liability
11.2
Cash severance payments
(8.1 )
Other
—

Severance liability balance at June 30, 2009
$ 3.1

~~We also incurred costs related to workforce reduction efforts initiated across all of our operations in 2008.~~

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~~The following table summarizes the status of this involuntary severance liability at June 30, 2009:~~

(In millions)

Initial severance liability balance
$ 19.7
Amounts recorded as pension and postretirement liabilities
(3.0 )

Net cash severance liability
16.7
Cash severance payments
(10.5 )
Other
—

Severance liability balance at June 30, 2009
$ 6.2

~~We discuss our 2008 workforce reduction costs in more detail in~~~~Note 2~~ ~~of our 2008 Annual Report on Form 10-K.~~VIEs.

Earnings Per Share

Basic earnings per common share (EPS) is computed by dividing ~~earnings applicable~~net income (loss) attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

Our dilutive common stock equivalent shares consist of stock options and other stock-based compensation awards. The following table presents stock options that were not dilutive and were excluded from the computation of diluted EPS in each period, as well as the dilutive common stock equivalent shares:

Quarter Ended June 30,
Six Months Ended June 30,

2009
2008
2009
2008

(In millions)

Non-dilutive stock options
5.0 1.3 5.3 0.9
Dilutive common stock equivalent shares
0.8 1.8 0.5 1.9

	Quarter Ended March 31,

	2010		2009

	(In millions)
Non-dilutive stock options		4.9		5.5
Dilutive common stock equivalent shares		1.6		0.4

As a result of the Company incurring a loss for the ~~six months~~quarter ended ~~June 30,~~March 31, 2009, dilutive common stock equivalent shares were not included in calculating diluted ~~EPS.~~EPS for that reporting period.

~~We issued to MidAmerican 19,897,322 shares of Constellation Energy's common stock upon~~Acquisitions

Criterion Wind Project

In April 2010, we completed the ~~conversion~~acquisition of the ~~Series A Preferred Stock, which happened upon~~Criterion wind project in Garrett County, Maryland. The completed cost of this project is expected to be approximately $140 million. This 70 MW wind energy project will be developed, constructed, owned, and operated by us. We expect this facility to be in commercial operation by the ~~termination~~end of ~~the merger agreement with MidAmerican on December 17, 2008. We discuss the conversion feature of the Series A Preferred Stock in more detail in~~2010.

~~Note 9~~Texas Combined Cycle Generation Facilities ~~of our 2008 Annual Report on Form 10-K. These additional shares impacted our earnings per share for the quarter and six months ended June 30, 2009.~~

~~Accretion~~In April 2010, we signed an agreement to purchase the 550 MW Colorado Bend Energy Center and the 550 MW Quail Run Energy Center natural gas combined cycle generation facilities in Texas for $365 million, subject to normal closing adjustments. The transaction is expected to close in the second quarter of ~~Asset Retirement Obligations~~2010, subject to certain state and federal regulatory approvals.

Divestiture

~~We discuss our asset retirement obligations~~In January 2010, BGE completed the sale of its interest in ~~more detail~~a nonregulated subsidiary that owns a district chilled water facility to a third party. BGE received net cash proceeds of $20.9 million. No gain or loss was recorded on this transaction in~~Note 1~~ 2010. BGE has no further involvement in the activities of ~~our 2008 Annual Report on Form 10-K. The change~~this entity.

Investment in ~~our "Asset retirement obligations" liability during 2009 was as follows:~~

(In millions)

Liability at January 1, 2009
$ 987.3
Accretion expense
36.1
Liabilities incurred
0.1
Liabilities settled
(0.3 )
Revisions to cash flows
(0.4 )
Other
(0.2 )

Liability at June 30, 2009
$ 1,022.6

~~Divestitures~~Constellation Energy Nuclear Group, LLC (CENG)

InOn November 6, 2009, we ~~continued to implement many of~~completed the ~~strategic initiatives we identified in 2008 to improve liquidity and reduce our business risk. We discuss these initiatives in the~~~~Strategy~~ ~~section of our 2008 Annual Report on Form 10-K.~~

~~The transactions to sell a majority of our international commodities, our Houston-based gas trading and other operations were structured in two parts:~~

•: ~~the assignment and transfer~~sale of a ~~majority of the portfolio,~~49.99% membership interest in CENG, our nuclear generation and
•: ~~the execution of a Total Return Swap (TRS) mechanism for the remainder of the portfolio.~~

~~Under the TRS, we entered into offsetting trades with the buyers that matched the terms of the remaining third party contracts for which we were unable~~ operation business, to complete assignment to the buyers as of the transaction dates. This structure transferred the risks associated with changes in commodity prices as of the transaction dates to the buyers in all instances. However, the trades under the TRS are newly executed transactions,EDF Group and we remain the principal under both the unassigned third party trades and the matching trades with the buyers under the TRS with no right of either financial or legal offset. We continue to pursue the assignment of these remaining contracts to the buyers.

The matching contracts under the TRS include both derivatives and non-derivatives and were executed at prices that differed from market prices at closing, which resulted in a net cash payment to/from the buyers. We recorded the underlying contracts at fair value on a gross basis as assets or liabilities in our Consolidated Balance Sheets depending on whether the contract prices were above- or below-market prices at closing.affiliates (EDF). As a result of this transaction, we retained a 50.01% economic interest in CENG, but we and EDF have equal voting rights over the ~~derivative contracts have been included in "Derivative Assets~~activities of CENG. Accordingly, we deconsolidated CENG and ~~Liabilities" and the nonderivative contracts have been included in "Unamortized Energy Contract Assets and Liabilities." The derivative~~began to record our investment

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contracts are subject to mark-to-market accounting until they are realized or assigned. The nonderivative contracts will be amortized into earnings as the underlying contracts are realized, or sooner if those contracts are assigned.

~~We record the cash proceeds we pay or receive at the inception of energy purchase and sale contracts based upon whether the contracts are in-the-money or out-of-the-money as follows:~~



~~In-the-money contracts—proceeds paid~~		~~Investing Outflow~~
~~Out-of-the-money contracts—proceeds received~~		~~Financing Inflow~~

After inception, we record the cash flows from all energy purchase and sale contracts as operating activities, except for out-of-the-money derivative contracts that were liabilities at inception. We record the ongoing cash flows from these out-of-the-money derivative contracts as financing activities, regardless of whether they are purchase or sale contracts.

~~International Commodities Operation~~

In January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation. We completed this transaction on March 23, 2009 and recognized the following impacts during the six months ended June 30, 2009:

•: ~~a pre-tax loss of approximately $334.5 million representing net consideration paid to the buyer, the book value of net assets sold, and transaction costs,~~
•: ~~a reclassification of $165.7 million~~ in losses on previously designated cash-flow hedge contracts, for which the forecasted transactions are now deemed probable of not occurring, from "Accumulated Other Comprehensive Loss" to "Nonregulated revenues" in the Consolidated Statements of Income (Loss),
•: ~~workforce reduction costs of $10.2 million, recorded as part of "Workforce reduction costs" in the Consolidated Statements of Income (Loss), and~~
•: other costs of $10.1 million related to leasehold improvements, furniture and computer hardware and software, recorded as part of "Impairment losses and other costs" in the Consolidated Statements of Income (Loss).

We removed the contracts that were assigned from our balance sheet, paid the buyer approximately $90 million, and reflected the impact of this payment on our working capital in the operating activities section of our Consolidated Statements of Cash Flows.

The net cash payment to the buyer upon completion of the TRS was $2.5 million. As part of the consideration, we acquired matching nonderivative contracts that resulted in a net liability of approximately $75 million, which will be amortized into earnings as the underlying contracts are realized, or sooner if the original nonderivative contracts are assigned.

~~We have reflected the contracts~~CENG under the ~~TRS on a gross basis in cash flows from investing and financing activities in our Consolidated Statements~~equity method of ~~Cash Flows as follows:~~

Six Months Ended June 30, 2009

(In millions)

Investing activities—Contract and portfolio acquisitions
$ (866.3 )
Financing activities—Proceeds from contract and portfolio acquisitions
863.8

Net cash flows from contract and portfolio acquisitions
$ (2.5 )

In addition to the March 23, 2009 transaction for a majority of our international commodities operation, on June 30, 2009 we completed the sale of a uranium market participant that we owned. We received cash proceeds of approximately $43 million and recorded a $27.2 million loss on this sale. This loss from our merchant energy segment is included in the "Net (loss) gain on divestitures" line in our Consolidated Statements of Income (Loss).

~~Houston-Based Gas and Other Trading Operations~~

On February 3, 2009, we entered into a definitive agreement to sell our Houston-based gas trading operation. We transferred control of this operation on April 1, 2009. In addition, in the second quarter of 2009 we also sold certain other trading operations. In total, we received proceeds of approximately $56 million, and recorded a $102.4 million net loss on these sales inaccounting. For the quarter ended ~~June 30, 2009. The~~March 31, 2010, we recorded $19.2 million of equity investment losses in CENG, which represents our share of earnings from CENG of $23.4 million, net ~~loss on sale primarily relates~~of the amortization of the basis difference in CENG of $42.6 million. Our equity investment earnings in CENG include $1.2 million of expense related to ~~nonderivative accrual contracts, which were not recorded on our Consolidated Balance Sheet,~~ the ~~cost associated with disposing~~portion of ~~an entire portfolio and not merely individual contracts, and~~ the cost of ~~capital, including contingent capital,~~certain share-based awards that we fund on behalf of EDF. The basis difference is the difference between the fair value of our investment in CENG at closing and our share of the underlying equity in CENG, because the underlying assets of CENG were retained at their carrying value. SeeNote 2 to ~~support the operation.~~our 2009 Annual Report on Form 10-K for a more detailed discussion.

The matching derivative and nonderivative transactions under the TRS discussed above were executed at prices that differed from market prices at closing. As a result, we record the ongoing cash flows related to the out-of-the-money derivative contracts that were liabilities at inception as financing cash flows in accordance with SFAS No. 149. This resulted in cash outflows related to financing activities of $378.0 million and $695.4 million in our

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~~Consolidated Statements of Cash Flows~~Summarized income statement information for CENG for the quarter ~~and six months~~ ended ~~June 30, 2009, respectively, associated with derivative liabilities that were out-of-the-money.~~

The net cash receipt from the buyers upon completion of the TRS was $91.9 million in the second quarter of 2009. We have reflected these contracts on a gross basis in cash flows from investing and financing activities in our Consolidated Statements of Cash FlowsMarch 31, 2010 is as follows:

Six Months Ended June 30, 2009

(In millions)

Investing activities—Contract and portfolio acquisitions
$ (1,287.4 )
Financing activities—Proceeds from contract and portfolio acquisitions
1,379.3

Net cash flows from contract and portfolio acquisitions
$ 91.9

In addition, we incurred other costs of $1.5 million and $5.5 million for the quarter and six months ended June 30, 2009, respectively, related to leasehold improvements, furniture, computer hardware and software costs, which are recorded as part of "Impairment losses and other costs" on our Consolidated Statements of Income (Loss).

On April 1, 2009, we executed an agreement with the buyer of our Houston-based gas trading operation under which the buyer will provide us with the gas supply needed to support our retail gas customer supply business through March 31, 2011. This agreement was structured such that our requirements to post collateral are reduced. The supplier has liens on the assets of the retail gas supply business as well as our investment in the stock of these entities to secure our obligations under the gas supply agreement. In connection with this agreement, we posted approximately $160 million of collateral. This was subsequently reduced to $100 million. The initial $160 million posted represents approximately 25 percent of the previous collateral requirements to support this operation. We discuss the impact of the gas supply agreement on our retail gas customer supply business in more detail on page 12.

~~Investments Classified as Available-for-Sale~~

~~We classify the following investments as available-for-sale:~~

•: ~~nuclear decommissioning trust funds,~~
•: ~~marketable equity securities, and~~
•: ~~trust assets securing certain executive benefits.~~

~~This means we do not expect to hold these investments to maturity, and we do not consider them trading securities. We record these investments at fair value on our Consolidated Balance Sheets.~~

We show the fair values, gross unrealized gains and losses, and adjusted cost basis for all of our available-for-sale securities in the following tables. We use specific identification to determine cost in computing realized gains and losses.

At June 30, 2009
Adjusted
Cost
Unrealized
Gains
Unrealized
Losses
Fair
Value

(In millions)

Money market funds
$ 12.3 $ — $ — $ 12.3
Marketable equity securities
196.0 70.3 — 266.3
Mutual fund / common collective trusts
478.5 49.6 — 528.1
Corporate debt
159.4 18.6 — 178.0
U.S. agencies
42.4 2.2 — 44.6
U.S. treasuries
19.6 0.8 — 20.4
State municipal bonds
45.3 2.8 — 48.1

Totals
$ 953.5 $ 144.3 $ — $ 1,097.8

~~The unrealized gains in the preceding table consist primarily of $143.2 million at June 30, 2009 associated with the nuclear decommissioning trust funds.~~

The investments in our nuclear decommissioning trust funds are managed by third parties who have independent discretion over the purchases and sales of securities. We recognize impairments for any of these investments for which the fair value declines below our book value. We recognized $1.9 million and $62.4 million in pre-tax impairment losses on our nuclear decommissioning trust investments during the quarter and six months ended June 30, 2009, respectively. These impairments are included as part of gross realized losses in the following table.

~~Gross and net realized gains and losses on available-for-sale securities were as follows:~~

Quarter Ended
June 30, 2009
Six Months Ended
June 30, 2009

(In millions)

Gross realized gains
$ 4.3 $ 15.2
Gross realized losses
(3.7 ) (72.0 )

Net realized gains
$ 0.6 $ (56.8 )

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~~The corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule:~~

At June 30, 2009

(In millions)

Less than 1 year
$ 11.9
1-5 years
90.7
5-10 years
93.8
More than 10 years
94.7

Total maturities of debt securities
$ 291.1

Quarter Ended March 31, 2010

	(In millions)
Revenues	$	360.9
Fuel and purchased energy expenses		58.4
Income from operations		37.6
Net income		49.1

Information by Operating Segment

In connection with the strategic initiatives that were undertaken in 2008 and 2009, we decided to re-align our reporting structure, beginning January 1, 2010, to reflect our current view of managing the business. As a result, as of January 1, 2010, we changed our reportable segments and have recast prior period information to conform with the current presentation.

Our reportable operating segments ~~are—Merchant Energy,~~are Generation, NewEnergy (referred to as Customer Supply in our 2009 Annual Report on Form 10-K), Regulated Electric, and Regulated Gas:

•

Our ~~merchant energy~~Generation business is nonregulated and includes:

—: a power generation and development operation that owns, operates and maintains fossil ~~nuclear,~~ and ~~interests in hydroelectric~~renewable generating facilities, ~~and~~a fuel processing facility, qualifying facilities, and power projects in the United States,
—: an operation that manages certain contractually owned physical assets, including generating facilities,
—: an interest in a nuclear generation joint venture (CENG) that owns, operates, and maintains five nuclear generating units, and
—: an interest in a joint venture (UniStar Nuclear Energy, LLC (UNE)) to develop, own, and operate new nuclear projects in the United States.

•

Our NewEnergy business is nonregulated and includes:

—: full requirements load-serving sales of energy and capacity to utilities, cooperatives, and commercial, industrial, and governmental customers,
—: ~~gas~~sales of retail energy products and services to residential, commercial, industrial, and governmental customers,
—: structured transactions and risk management services for various customers (including hedging of output from generating facilities and fuel costs), and trading in energy and energy-related commodities to facilitate portfolio management,
—: risk management services for our Generation business,
—: design, construction, and operation of renewable energy, heating, cooling, and cogeneration facilities for commercial, industrial, and governmental customers throughout North America, including energy performance contracting and energy efficiency engineering services,
—: upstream (exploration and production) natural gas ~~operations,~~activities, and
—: ~~generation operations~~sales of home improvements, servicing of electric and ~~maintenance.~~gas appliances, and heating, air conditioning, plumbing, electrical, and indoor air quality systems, and providing electric and natural gas to residential customers in central Maryland.

•

Our regulated electric business purchases, transmits, distributes, and sells electricity in Central Maryland.

•

Our regulated gas business purchases, transports, and sells natural gas in Central Maryland.

Our ~~remaining nonregulated businesses:~~

•: ~~design, construct, and operate renewable energy, heating, cooling, and cogeneration facilities for commercial, industrial, and governmental customers throughout North America,~~
•: provide home improvements, service electric and gas appliances, service heating, air conditioning, plumbing, electrical, and indoor air quality systems, and provide natural gas marketing to residential customers in Central Maryland, and
•: ~~develop and deploy new nuclear plants in North America.~~

Prior to June 30, 2009, our merchant energy business segment included additional activities that have been divested as part of our strategy to improve our liquidity and reduce our business risk. The divested activities include:

•: ~~our international commodities operation, which was divested in March 2009,~~
•: ~~our gas trading operation, which was divested on April 1, 2009,~~
•: ~~our ownership of a uranium market participant, which was divested on June 30, 2009, and~~
•: ~~our investment in a shipping joint venture, which is expected to be divested in the third quarter of 2009.~~

~~Additionally, we entered into an Investment Agreement with EDF on December 17, 2008. See~~~~Note 15~~ ~~of our 2008 Annual Report on Form 10-K for more detail on the Investment Agreement with EDF.~~

We believe that the successful execution of these initiatives, as well as our other initiatives that we have undertaken to reduce risk in our merchant energy business, have reduced our exposure to activities that require contingent capital support and improved our liquidity. In turn, the results for our merchant energy business segment will be materially different from prior periods. We discuss these strategies and their effect on liquidity in~~Note 8~~ ~~of our 2008 Annual Report on Form 10-K.~~

~~Our Merchant Energy,~~Generation, NewEnergy, Regulated Electric, and Regulated Gas reportable segments are strategic businesses based principally upon regulations, products, and services that require different technologies and marketing strategies. We evaluate the performance of these segments based on net income. We account for intersegment revenues using market prices. A summary of information by operating segment is shown in the table below.

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Reportable Segments

Holding
Company
and Other
Nonregulated
Businesses

Merchant
Energy
Business
Regulated
Electric
Business
Regulated
Gas
Business
Eliminations
Consolidated

(In millions)

For the quarter ended June 30,

2009

Unaffiliated revenues
$ 3,045.7 $ 655.7 $ 111.1 $ 51.6 $ — $ 3,864.1
Intersegment revenues
155.3 — 0.6 — (155.9 ) —

Total revenues
3,201.0 655.7 111.7 51.6 (155.9 ) 3,864.1
Net income (loss)
20.9 22.1 (6.2 ) (8.5 ) — 28.3
Net income (loss) attributable to common stock
4.1 19.5 (6.9 ) (8.6 ) — 8.1
2008

Unaffiliated revenues
$ 4,058.3 $ 448.7 $ 183.1 $ 66.0 $ — $ 4,756.1
Intersegment revenues
221.8 — 5.0 0.1 (226.9 ) —

Total revenues
4,280.1 448.7 188.1 66.1 (226.9 ) 4,756.1
Net income (loss)
280.0 (101.7 ) (2.3 ) (1.0 ) — 175.0
Net income (loss) attributable to common stock
279.7 (104.2 ) (3.1 ) (0.9 ) — 171.5
For the six months ended June 30,

2009

Unaffiliated revenues
$ 6,100.7 $ 1,462.5 $ 495.4 $ 108.9 $ — $ 8,167.5
Intersegment revenues
379.8 — 3.2 — (383.0 ) —

Total revenues
6,480.5 1,462.5 498.6 108.9 (383.0 ) 8,167.5
Net (loss) income
(181.8 ) 67.5 33.4 (10.5 ) — (91.4 )
Net (loss) income attributable to common stock
(199.1 ) 62.4 31.9 (10.6 ) — (115.4 )
2008

Unaffiliated revenues
$ 7,711.1 $ 1,158.0 $ 574.1 $ 125.1 $ — $ 9,568.3
Intersegment revenues
516.0 0.1 10.4 0.2 (526.7 ) —

Total revenues
8,227.1 1,158.1 584.5 125.3 (526.7 ) 9,568.3
Net income (loss)
352.7 (65.5 ) 37.9 (0.7 ) — 324.4
Net income (loss) attributable to common stock
351.9 (70.5 ) 36.3 (0.5 ) — 317.2

	Reportable Segments

	Reportable Segments									Holding Company and Other
	Generation		NewEnergy			Regulated Electric		Regulated Gas		Holding Company and Other			Eliminations			Consolidated

	(In millions)
Quarter ended March 31,
2010
Unaffiliated revenues	$	291.2	$	2,227.0		$	751.3	$	317.1	$	—		$	—		$	3,586.6
Intersegment revenues		288.7		123.9			—		0.9		—			(413.5	)		—

Total revenues		579.9		2,350.9			751.3		318.0		—			(413.5	)		3,586.6
Net income (loss)		27.1		104.1			27.2		37.2		(4.3	)		—			191.3
Net income (loss) attributable to common stock		27.1		107.6			24.6		36.5		(4.3	)		—			191.5
2009
Unaffiliated revenues	$	181.8		2,928.0		$	806.8	$	384.3	$	2.5		$	—		$	4,303.4
Intersegment revenues		603.7		86.8			—		2.6		—			(693.1	)		—

Total revenues		785.5		3,014.8			806.8		386.9		2.5			(693.1	)		4,303.4
Net income (loss)		41.5		(246.3	)		45.4		39.6		0.1			—			(119.7	)
Net income (loss) attributable to common stock		41.5		(246.8	)		42.9		38.8		0.1			—			(123.5	)

Certain prior-period amounts have been ~~reclassified~~restated to conform with the current period's reportable segment presentation.

Our ~~merchant energy~~Generation business operating results for the quarter ~~and six months~~ ended ~~June 30, 2009~~March 31, 2010 include the following after-tax charges:

•: ~~impairment losses and other costs~~deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of ~~$62.2~~$0.8 million ~~and $73.4 million, respectively,~~as a result of healthcare reform legislation enacted in March 2010,
•: ~~merger termination and strategic alternatives costs~~amortization of ~~$4.0~~basis difference in investment in CENG of $25.7 million, ~~and $46.3 million, respectively,~~
•: ~~net loss on sale~~impact of ~~a majority~~power purchase agreement with CENG of $25.7 million (amount represents the amortization of our ~~international commodities operation,~~"unamortized energy contract asset" less our ~~Houston-based gas trading operation, certain other trading operations, and a uranium market participant, the reclassification~~50.01% equity in CENG's amortization of losses on previously designated cash-flow hedges from Accumulated Other Comprehensive Loss, and earnings that are no longer part of our core business totaling $123.8 million and $308.0 million, respectively,its "unamortized energy contract liability"),
•: ~~impairment charge related to our nuclear decommissioning trust fund assets~~loss on early retirement of ~~$6.1~~2012 Notes of $30.9 million, ~~and $29.8 million, respectively,~~
•: ~~workforce reduction costs of $1.1 million and $5.3 million, respectively,~~ and
•: amortization of credit facility amendment fees in connection with the EDF transaction of ~~$5.2 million and $8.9 million, respectively.~~$1.9 million.

Our NewEnergy business operating results for the quarter ended March 31, 2010 include the following after-tax charges:

•: deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of $0.1 million as a result of healthcare reform legislation enacted in March 2010, and
•: amortization of credit facility amendment fees in connection with the EDF transaction of $1.0 million.

Our Regulated Electric business operating results for the quarter ended March 31, 2010 include an after-tax charge for the deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of $3.1 million as a result of healthcare reform legislation enacted in March 2010.

Our Holding Company and Other ~~Nonregulated~~ businesses operating results for the quarter ~~and six months~~ ended ~~June 30, 2009 reflect impairment losses and other costs~~March 31, 2010 include an after-tax charge for the deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits of ~~$3.2~~$4.8 million ~~after-tax.~~as a result of healthcare reform legislation enacted in March 2010.

Total assets ~~decreased~~declined approximately ~~$2.3~~$1.4 billion during ~~the six months ended June 30, 2009. The~~2010 due primarily to a decrease ~~primarily relates to:~~

•: ~~our Holding Company~~in cash and ~~Other Nonregulated Businesses and is primarily related to the approximately $1 billion decline in restricted~~ cash equivalents as a result of income taxes paid on the ~~repayment of the 14% Senior Notes to MidAmerican in January 2009, and~~
•: our Merchant Energy Business and is primarily related to the decrease in derivative assets, net of fair value collateral, of $533.2 million and a decrease in other net collateral and margin posted of $728.6 million, primarily associatedtransaction with ~~the divestitures~~EDF and the ~~activities to reduce risk in our Global Commodities portfolio.~~

Our allowance for uncollectible accounts receivable increased $19.6 million from December 31, 2008 to June 30, 2009. This increase is primarily attributable to our regulated electric and gas businesses. In the second quarterretirement of ~~2009, the Maryland PSC issued a ruling which delayed BGE's ability to terminate service to customers with arrearages and offered those customers the option to enter into extended payment plans.~~debt.

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Pension and Postretirement Benefits

We show the components of net periodic pension benefit cost in the following table:

Quarter Ended
June 30,
Six Months Ended
June 30,

2009
2008
2009
2008

(In millions)

Components of net periodic pension benefit cost

Service cost
$ 14.4 $ 12.8 $ 29.6 $ 27.8
Interest cost
31.1 22.7 58.3 50.2
Expected return on plan assets
(38.9 ) (25.0 ) (68.5 ) (55.9 )
Recognized net actuarial loss
11.1 6.5 21.7 12.4
Amortization of prior service cost
2.5 2.6 5.8 5.5
Amount capitalized as construction cost
(2.8 ) (2.1 ) (5.4 ) (4.8 )

Net periodic pension benefit cost¹
$ 17.4 $ 17.5 $ 41.5 $ 35.2

	Quarter Ended March 31,

	2010			2009

	(In millions)
Components of net periodic pension benefit cost
Service cost	$	9.5		$	15.2
Interest cost		21.7			27.2
Expected return on plan assets		(26.7	)		(29.6	)
Recognized net actuarial loss		8.1			10.6
Amortization of prior service cost		1.0			3.3
Amount capitalized as construction cost		(1.9	)		(2.6	)

Net periodic pension benefit cost¹	$	11.7		$	24.1

1 BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $4.9 million for the quarter ended June 30, 2009 and $4.2 million for the quarter ended June 30, 2008. BGE's portion of our net periodic pension benefit cost, excluding amounts capitalized, was $9.9 million for the six months ended June 30, 2009 and $8.7 million for the six months ended June 30, 2008. Net periodic pension benefit costs exclude settlement charges of $7.7$6.3 million in ~~the quarter~~2010 and ~~six months ended June 30,~~$7.2 million in 2009.

We show the components of net periodic postretirement benefit cost in the following table:

Quarter Ended
June 30,
Six Months Ended
June 30,

2009
2008
2009
2008

(In millions)

Components of net periodic postretirement benefit cost

Service cost
$ 2.0 $ 1.9 $ 3.6 $ 3.6
Interest cost
6.3 7.2 12.1 13.9
Amortization of transition obligation
0.6 0.7 1.1 1.2
Recognized net actuarial loss
0.4 0.1 1.1 1.1
Amortization of prior service cost
(1.0 ) (1.1 ) (1.8 ) (2.0 )
Amount capitalized as construction cost
(1.8 ) (1.9 ) (3.3 ) (4.0 )

Net periodic postretirement benefit cost¹
$ 6.5 $ 6.9 $ 12.8 $ 13.8

	Quarter Ended March 31,

	2010			2009

	(In millions)
Components of net periodic postretirement benefit cost
Service cost	$	0.7		$	1.6
Interest cost		4.7			5.8
Amortization of transition obligation		0.5			0.5
Recognized net actuarial loss		0.3			0.7
Amortization of prior service cost		(0.7	)		(0.8	)
Amount capitalized as construction cost		(1.3	)		(1.5	)

Net periodic postretirement benefit cost¹	$	4.2		$	6.3

1 BGE's portion of our net periodic postretirement benefit cost, excluding amounts capitalized, was ~~$3.5~~$4.8 million ~~for the quarter ended June 30, 2009~~in 2010 and ~~$4.0~~$4.6 million for the quarter ended June 30, 2008. BGE's portion of our net periodic postretirement benefit costs, excluding amounts capitalized, was $6.7 million for the six months ended June 30, 2009 and $7.7 million for the six months ended June 30, 2008.in 2009.

Our non-qualified pension plans and our postretirement benefit programs are not funded; however, we have trust assets securing certain executive pension benefits. We estimate that we will incur approximately ~~$22~~$9.3 million in pension benefit payments for our non-qualified pension plans and approximately ~~$30~~$25.7 million for retiree health and life insurance ~~benefit payments during 2009. As of June 30, 2009, we~~costs in 2010. We contributed ~~$297~~$12.2 million to our qualified pension ~~plans. We contributed an~~plans in April 2010.

Healthcare Reform Legislation

During March 2010, the Patient Protection and Affordable Care Act and the Healthcare and Education Reconciliation Act of 2010 were signed into law. These laws eliminate the tax exempt status of drug subsidies provided to companies under Medicare Part D after December 31, 2012. As a result of this new legislation, we recorded a noncash charge to reflect additional ~~$20~~deferred income tax expense of $8.8 million in ~~July 2009.~~

~~Table of Contents~~the quarter ended March 31, 2010.

Financing Activities

Credit Facilities and Short-term Borrowings

Our short-term borrowings may include bank loans, commercial paper, and bank lines of credit. Short-term borrowings mature within one year from the date of issuance. We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates.

~~Constellation Energy~~

~~Constellation Energy had bank and other lines of credit under committed unsecured credit facilities totaling $5.6 billion at June 30, 2009 for short-term financial needs.~~ We enter into these facilities to ensure adequate liquidity to support our operations.

Constellation Energy

Our liquidity requirements are funded with credit facilities and cash. We fund our short-term working capital needs with existing cash and with our credit facilities, which support direct cash borrowings and the issuance of commercial paper, if available. We also use our credit facilities to support the issuance of letters of credit, primarily for our ~~merchant energy~~NewEnergy business.

~~These~~Constellation Energy had bank lines of credit under committed credit facilities ~~can issue~~totaling $4.0 billion at March 31, 2010 for short-term financial needs as follows:

Type of Credit Facility		Amount (In billions)		Expiration Date	Capacity Type


Syndicated Revolver		$	2.32	July 2012	Letters of credit and cash
Commodity-linked			0.50	August 2014	Letter of credit
Bilateral			0.55	September 2014	Letters of credit
Bilateral			0.25	December 2014	Letters of credit and cash
Bilateral			0.25	June 2014	Letters of credit and cash
Bilateral			0.15	September 2013	Letters of credit

	Total	$	4.02

Collectively, these facilities currently support the issuance of letters of credit ~~commercial paper, if available,~~ and/or cash borrowings up to ~~approximately $5.6 billion as shown below. As of June 30, 2009,~~$4.0 billion. At March 31, 2010, we had approximately ~~$2.8~~$1.9 billion in letters of credit issued ~~against those~~including $0.4 billion in letters of credit issued under the commodity-linked credit facility discussed below and no commercial paper outstanding or direct borrowings under these facilities.

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~~We have also included in~~The commodity-linked credit facility currently allows for the ~~table below~~issuance of letters of credit up to a maximum capacity of $0.5 billion. This commodity-linked facility is designed to help manage our contingent collateral requirements associated with the ~~pro forma effect on~~hedging of our ~~credit facilities, which are reduced or terminated upon the closing~~NewEnergy business because its capacity increases as natural gas price levels decrease compared to a reference price that is adjusted periodically.

At March 31, 2010, Constellation Energy had $21.1 million of ~~the transactions contemplated by the Investment Agreement~~short-term notes outstanding with ~~EDF, which is expected to occur in the fourth quarter~~a weighted average effective interest rate of ~~2009:~~

Facility Expiration
Facility
Size
Facility Size
Upon Completion
of the EDF
Transaction

(In billions)

July 2012
$ 3.85 $ 2.32
November 2009¹
1.23 —
September 2013
0.35 —
December 2009
0.15 —

Total
$ 5.58 $ 2.32

~~1 Size of facility may be reduced by proceeds received from certain securities offerings or asset sales.~~6.33%.

BGE

BGE has a ~~$400.0~~$600.0 million ~~five-year~~ revolving credit facility expiring in 2011. BGE can borrow directly from the banks, use the facility to allow commercial paper to be issued, if available, or issue letters of credit. ~~As of June 30, 2009,~~At March 31, 2010, BGE had ~~$0.5 million in~~no commercial paper or direct borrowings outstanding. There were immaterial letters of credit ~~issued under~~outstanding at March 31, 2010.

Debt

Constellation Energy

As part of our voluntary commitment to reduce our debt by $1 billion with funds received from the EDF transaction, we retired the following debt during the quarter ended March 31, 2010 completing this ~~facility.~~commitment.

7.00% Notes due April 1, 2012

In ~~addition,~~February 2010, we retired an aggregate principal amount of $486.5 million of our 7.00% Notes due April 1, 2012 pursuant to a cash tender offer, at ~~June 30, 2009, BGE had $339.9~~a premium of approximately 11%. We recorded a loss on this transaction of $50.1 million ~~in commercial paper outstanding.~~within "Interest expense" on our Consolidated Statements of Income (Loss).

Tax-Exempt Notes

In March 2010, we repurchased our outstanding $47 million and $65 million variable rate tax-exempt notes. Since these notes are variable rate instruments, there was no gain or loss recorded upon repurchase.

Net Available Liquidity

The following table provides a summary of our, and BGE's, net available liquidity at ~~June 30, 2009:~~March 31, 2010.

As of June 30, 2009

Constellation
Energy
BGE
Total
Consolidated

(In billions)

Credit facilities
$ 5.6 $ 0.4 $ 6.0
Less: Letters of credit issued
(2.8 ) — (2.8 )
Less: Cash drawn on credit facilities
— — —

Undrawn facilities
2.8 0.4 3.2
Less: Commercial paper outstanding
— (0.3 ) (0.3 )

Net available facilities
2.8 0.1 2.9
Add: Cash
1.0 — 1.0
Add: EDF put arrangement
1.1 — 1.1

Net available liquidity
$ 4.9 $ 0.1 $ 5.0

At March 31, 2010	Constellation Energy			BGE


	(In billions)
Credit facilities¹	$	3.5		$	0.6
Less: Letters of credit issued¹		(1.5	)		—
Less: Cash drawn on credit facilities		—			—

Undrawn facilities		2.0			0.6
Less: Commercial paper outstanding		—			—

Net available facilities		2.0			0.6
Add: Cash and cash equivalents		1.6			0.3

Cash and facility liquidity		3.6			0.9
Add: EDF put arrangement		1.1			—

Net available liquidity	$	4.7		$	0.9

1 Excludes $0.5 billion commodity-linked credit facility due to its contingent nature and $0.4 billion in letters of credit posted against it.

Other Sources of Liquidity

~~In December 2008, we executed an~~Our Investment Agreement with EDF ~~that~~ includes an asset put arrangement that provides us with an option at any time through December 31, 2010 ~~(or the termination of the Investment Agreement by EDF if we breach that agreement)~~ to sell certain non-nuclear generation assets, at pre-agreed prices, to EDF for aggregate proceeds of no more than $2 billion pre-tax, or approximately $1.4 billion after-tax. The amount of after-tax proceeds will be impacted by the assets actually sold and the related tax impacts at that time.

Exercise of the put arrangement is conditioned upon the receipt of regulatory approvals and ~~third-party~~third party consents, the absence of any material liens on such assets, and the absence of a material adverse effect, as defined in the Investment Agreement. ~~During April 2009, we~~We have received regulatory approvals and consents for the majority of the assets covered by the put arrangement. As of ~~June 30, 2009,~~March 31, 2010, we have approximately $1.1 billion after-tax of liquidity available through the put arrangement. We expect to receive regulatory approval for an additional asset in the ~~first~~second quarter of 2010, which will increase the net after-tax

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liquidity from the put arrangement to approximately $1.4 billion.

We are actively seeking to increase available liquidity and to reduce our business risk. Specifically, we are reducing capital spending and ongoing expenses, scaling down the expected variability in long-term earnings and short-term collateral usage, and limiting our exposure to business activities that require contingent capital support. During 2009, we made progress on several other initiatives as discussed in more detail in the~~Divestitures~~ ~~section beginning on page 15 and the~~~~Variable Interest Entities~~ ~~section on page 12. As of June 30, 2009 we have realized substantially all of the $1 billion of the net reduction in collateral that was expected from the divestiture of these operations.~~

We believe that the actions that we have taken and our current net available liquidity will be sufficient to support the ongoing liquidity requirements over the next 12 months. Our liquidity projections include assumptions for commodity price changes, which are subject to significant volatility, and we are exposed to certain operational risks that could have a significant impact on our liquidity.

Credit Facility Compliance and Covenants

~~The credit facilities of Constellation Energy and BGE have limited material adverse change clauses, none of which would prohibit draws under the existing facilities.~~

Certain credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At ~~June 30, 2009,~~March 31, 2010, the debt to capitalization ratio as defined in the credit agreements was ~~51%~~32%.

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Under our ~~$3.85 billion and $1.23~~$2.32 billion credit ~~facilities,~~facility, we ~~will be required to grant~~granted a lien on certain of our generating facilities and ~~pledge~~pledged our ownership interests in our nuclear business to the lenders upon the ~~earlier of (i) the closing~~completion of the ~~Investment Agreement~~transaction with EDF or (ii) the date on which both the Investment Agreement is terminated and our Standard & Poors (S&P) or Fitch senior unsecured debt credit rating is below BBB- or our Moody's senior unsecured debt credit rating is below Baa3.

Our $1.23 billion credit facility requires us to maintain consolidated earnings before interest, taxes, depreciation, and amortization to consolidated interest expense ratio of at least 2.75 when our S&P senior unsecured debt rating is BBB- or lower and our Moody's senior unsecured debt rating is Baa3 or lower. Compliance with the covenant is not required as of July 31, 2009 as S&P's senior unsecured debt rating is above BBB-.EDF.

The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At ~~June 30, 2009,~~March 31, 2010, the debt to capitalization ratio for BGE as defined in this credit agreement was ~~52%~~44%.

Decreases in Constellation Energy's or BGE's credit ratings would not trigger an early payment on any of our, or BGE's, credit facilities. However, the impact of a credit ratings downgrade on our financial ratios associated with our credit facility covenants would depend on our financial condition at the time of such a downgrade and on the source of funds used to satisfy the incremental collateral obligation resulting from a credit ratings downgrade. For example, if we were to use existing cash balances or exercise the put option with EDF to fund the cash portion of any additional collateral obligations resulting from a credit ratings downgrade, we would not expect a material impact on our financial ratios. However, if we were to issue long-term debt or use our credit facilities to fund any additional collateral obligations, our financial ratios could be materially affected. Failure by Constellation Energy, or BGE, to comply with these covenants could result in the acceleration of the maturity of the borrowings outstanding and preclude us from issuing letters of credit under these facilities.

The credit facilities of Constellation Energy and BGE contain a material adverse change representation but draws on the facilities are not conditioned upon Constellation Energy and BGE making this representation at the time of the draw. However, to the extent a material adverse change has occurred and prevents Constellation Energy or BGE from making other representations that are required at the time of the draw, the draw would be prohibited.

Income Taxes

We compute the income tax expense (benefit) ~~expense~~ for each quarter based on the estimated annual effective tax rate for the year. The effective tax rate was ~~78.3% and 60.4%~~33.3% for the quarter ~~and six months~~ ended ~~June 30, 2009, respectively,~~March 31, 2010 compared to ~~38.0% and 36.1%~~66.9% for the same ~~periods~~period of ~~2008.~~2009. The lower effective tax rate for 2010 reflects the impact of favorable adjustments (primarily related to reductions of uncertain tax positions and higher deductions for qualified production activities). The higher effective tax rate ~~for the quarter and six months ended June 30,~~in 2009 reflects the impact of unfavorable nondeductible adjustments (primarily related to nondeductible dividends on the Series B Preferred Stock and the write-off of the unamortized debt discount on the 14% Senior Notes) in relation to the lower estimated 2009 taxable income (primarily attributable to losses on the divestiture of a majority of our international commodities and our Houston-based gas trading operations).

The BGE effective tax rate was ~~39.8% and 39.6%~~41.6% for the quarter ~~and six months~~ ended ~~June 30, 2009, respectively,~~March 31, 2010 compared to ~~33.1% and 36.7%~~39.5% for the same ~~periods~~period of ~~2008. This reflects~~2009. The higher effective tax rate for 2010 is primarily due to the impact of the ~~lower 2008 taxable income related to~~healthcare reform legislation enacted in the ~~Maryland settlement agreement,~~first quarter of 2010, which ~~increased~~eliminates the ~~relative impact~~tax exempt status of ~~favorable permanent tax adjustments on BGE's 2008 effective tax rate.~~prescription drug subsidies received under Medicare Part D.

Unrecognized Tax Benefits

The following table summarizes the change in unrecognized tax benefits during ~~2009~~2010 and our total unrecognized tax benefits at ~~June 30, 2009:~~March 31, 2010:

At June 30, 2009

(In millions)

Total unrecognized tax benefits, January 1, 2009
$ 189.7
Increases in tax positions related to the current year
3.0
Reductions in tax positions related to prior years
(7.8 )
Reductions in tax positions as a result of a lapse of the applicable statute of limitations
(0.8 )

Total unrecognized tax benefits, June 30, 2009¹
$ 184.1

At March 31, 2010

	(In millions)
Total unrecognized tax benefits, January 1, 2010	$	312.5
Increases in tax positions related to the current year		4.3
Increases in tax positions related to prior years		2.8
Reductions in tax positions related to prior years		(28.8	)
Reductions in tax positions as a result of a lapse of the applicable statute of limitations		(0.6	)

Total unrecognized tax benefits, March 31, 2010¹	$	290.2

1 BGE's portion of our total unrecognized tax benefits at ~~June 30, 2009~~March 31, 2010 was ~~$3.9~~$104.3 million.

Increases in tax positions related to the current year and ~~reductions in~~ prior ~~year tax positions~~years are primarily due to unrecognized tax benefits for repair and depreciation deductions measured at amounts

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consistent with prior IRS examination results and state income tax accruals. ~~Statutes of limitations lapsed for 2003 and 2004~~

Decreases in tax positions related to ~~Maryland taxes~~prior years are primarily due to the resolution of the tax treatment of distributions received from our shipping joint venture in July 2008 and repair deductions.

Total unrecognized tax benefits as of March 31, 2010 of $290.2 million include outstanding claims of approximately $63.0 million, including $51.6 million in state tax credits, for which no tax benefit was recorded on our Consolidated Balance Sheet because refunds were not received and the ~~gas plant sale that occurred in 2006.~~claims do not meet the "more-likely-than-not" threshold.

If the total amount of unrecognized tax benefits of ~~$184.1~~$290.2 million were ultimately realized, our income tax

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expense would decrease by approximately ~~$158~~$167 million. However, the ~~$158~~$167 million includes state tax refund claims of ~~approximately $48~~$51.6 million that have been disallowed by tax authorities and ~~we believe that there is a remote likelihood of ultimately realizing any benefit from these refund claim amounts.~~are subject to appeals. These state refund claims may be resolved by ~~December~~March 31, ~~2009.~~2011. For this reason, we believe it is reasonably possible that reductions to our total unrecognized tax benefits ~~in the range~~ of ~~$40 to~~approximately $50 million may occur by ~~June 30, 2010,~~March 31, 2011, although these reductions are not expected to materially impact income tax expense.

Interest and penalties recorded in our Consolidated Statements of Income (Loss) as tax expense (benefit) relating to liabilities for unrecognized tax benefits were as follows:

Quarter Ended
June 30,
Six Months Ended
June 30,

2009
2008
2009
2008

(In millions)

Interest and penalties recorded as tax expense
$ 1.5 $ 0.7 $ 0.7 $ 1.7

	For the Quarter Ended March 31,

	2010		2009

	(In millions)
Interest and penalties recorded as tax expense (benefit)	$	3.4	$	(0.7	)

BGE's portion of interest and penalties was immaterial for both periods presented.

Accrued interest and penalties recognized in our Consolidated Balance Sheets were ~~$11.0~~$26.5 million, of which BGE's portion was ~~$0.8~~$2.6 million, at ~~June 30, 2009,~~March 31, 2010, and ~~$10.3~~$23.1 million, of which BGE's portion was ~~$0.7~~$1.6 million, at December 31, ~~2008.~~2009.

Taxes Other Than Income Taxes

~~BGE collects from certain customers~~Taxes other than income taxes primarily include property and gross receipts taxes along with franchise taxes and other non-income taxes, surcharges, and fees.

BGE and our NewEnergy operations collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. ~~We include these types of taxes in "Taxes other than income taxes" in our Consolidated Statements of Income (Loss).~~ Some of these taxes are imposed on the customer and others are imposed on ~~BGE. We account for the~~BGE and our NewEnergy business. Where these taxes, such as sales taxes, are imposed on the customer, we account for these taxes on a net basis which means we do not recognize revenue and an offsetting tax expense for the taxes collected from customers. We account for the taxes imposed on BGE on a gross basis, which means we recognize revenue for the taxes collected from customers. Accordingly, we record the taxes accounted for on a gross basis as revenues in the accompanyingwith no impact to our Consolidated Statements of Income (Loss). However, where these taxes, such as gross receipts taxes or other surcharges or fees, are imposed on BGE or our NewEnergy business, we account for ~~BGE~~these taxes on a gross basis. Accordingly, we recognize revenues for these taxes collected from customers along with an offsetting tax expense, which are both included in our and BGE's Consolidated Statements of Income (Loss). The taxes, surcharges, or fees that are included in revenues were as follows:

Quarter Ended
June 30,
Six Months Ended
June 30,

2009
2008
2009
2008

(In millions)

Taxes other than income taxes included in revenues—BGE
$ 18.5 $ 14.3 $ 40.1 $ 35.2

Quarter Ended March 31,	2010		2009


	(In millions)
Constellation Energy (including BGE)	$	31.0	$	30.7
BGE		21.9		21.6

Guarantees

Our guarantees do not represent incremental Constellation Energy obligations; rather they primarily represent parental guarantees of subsidiary obligations. The following table summarizes the maximum exposure by guarantor based on the stated limit of our outstanding guarantees:

At June 30, 2009
Stated Limit

(In billions)

Constellation Energy guarantees
$ 13.7
Merchant energy business guarantees
0.1
BGE guarantees
0.3

Total guarantees
$ 14.1

At March 31, 2010	Stated Limit


	(In billions)
Constellation Energy guarantees	$	9.6
BGE guarantees		0.3

Total guarantees	$	9.9

At ~~June 30, 2009,~~March 31, 2010, Constellation Energy had a total of ~~$14.1~~$9.9 billion in guarantees outstanding related to loans, credit facilities, and contractual performance of certain of its subsidiaries as described below.

•

Constellation Energy guaranteed a face amount of ~~$13.7~~$9.6 billion as follows:

•: ~~Constellation Energy guaranteed a face amount of $12.7~~$8.8 billion on behalf of our ~~merchant energy subsidiaries~~Generation and NewEnergy businesses to allow ~~those subsidiaries~~them the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our estimated net exposure for obligations under commercial transactions covered by these guarantees was approximately ~~$2.5~~$2 billion at ~~June 30, 2009,~~March 31, 2010, which represents the total amount the parent company could be required to fund based on ~~June 30, 2009~~March 31, 2010 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets.
•: ~~Constellation Energy guaranteed $0.9~~$0.6 billion primarily on behalf of ~~our~~CENG's nuclear generating facilities for nuclear insurance and credit support to ensure these plants have funds to meet

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expenses and obligations to safely operate and maintain the plants.

•: ~~Constellation Energy guaranteed $0.1~~$0.2 billion to its other nonregulated businesses.

•: ~~Our merchant energy business guaranteed $72.0 million for loans, performance guarantees and other payment obligations primarily related to certain power projects in which we have an investment.~~
•: BGE guaranteed the Trust Preferred Securities of $250.0 million of BGE Capital Trust II.

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Commitments and Contingencies

We have made substantial commitments in connection with our ~~merchant energy,~~Generation, NewEnergy, regulated electric and gas, and other nonregulated businesses. These commitments relate to:

•: purchase of electric generating capacity and energy,
•: procurement and delivery of fuels,
•: the capacity and transmission and transportation rights for the physical delivery of energy to meet our obligations to our customers, and
•: long-term service agreements, capital for construction programs, and other.

Our ~~merchant energy business enters~~Generation and NewEnergy businesses enter into various long-term contracts for the procurement and delivery of fuels to supply our generating plant requirements. In most cases, our contracts contain provisions for price escalations, minimum purchase levels, and other financial commitments. These contracts expire in various years between ~~2009~~2010 and ~~2028.~~2018. In addition, our ~~merchant energy~~NewEnergy business enters into long-term contracts for the capacity and transmission rights for the delivery of energy to meet our physical obligations to our customers. These contracts expire in various years between ~~2009~~2010 and 2030.

Our ~~merchant energy business~~Generation and NewEnergy businesses also ~~has~~have committed to long-term service agreements and other purchase commitments for our plants.

Our regulated electric business enters into various long-term contracts for the procurement of electricity. ~~As of June 30, 2009, these~~These contracts expire ~~during 2009,~~between 2010 and ~~2011~~2012 and represent BGE's estimated requirements ~~for residential customers~~ as follows:

Contract Duration


From ~~June 30, 2009~~April 1, 2010 to May ~~2010~~2011	100	%
From June ~~2010~~2011 to September ~~2010~~2011	75
From October ~~2010~~2011 to May ~~2011~~2012	50
From June ~~2011~~2012 to September ~~2011~~2012	25

The cost of power under these contracts is recoverable under the Provider of Last Resort agreement reached with the Maryland PSC.

Our regulated gas business enters into various long-term contracts for the procurement, transportation, and storage of gas. Our regulated gas business has gas procurement contracts that expire between ~~2009~~2010 and 2011, and transportation and storage contracts that expire between ~~2012~~2010 and 2027. The cost of gas under these contracts is recoverable under BGE's gas cost adjustment clause discussed inNote 1 of our ~~2008~~2009 Annual Report on Form 10-K.

~~Our other nonregulated businesses have committed to gas purchases, as well as to contribute additional capital for construction programs and joint ventures in which they have an interest.~~

We have also committed to long-term service agreements and other obligations related to our information technology systems.

At ~~June 30, 2009,~~March 31, 2010, the total amount of commitments was ~~$4,973.4 million.~~$6.2 billion. These commitments are primarily related to our ~~merchant energy business.~~Generation and NewEnergy businesses.

Long-Term Power Sales Contracts

We enter into long-term power sales contracts in connection with our load-serving activities. We also enter into long-term power sales contracts associated with certain of our power plants. Our load-serving power sales contracts extend for terms through 2019 and provide for the sale of energy to electricity distribution utilities and certain retail customers. Our power sales contracts associated with power plants we own extend for terms into ~~2015~~2016 and provide for the sale of all or a portion of the actual output of certain of our power plants. Substantially all long-term contracts were executed at pricing that approximated market rates, including profit margin, at the time of execution.

Contingencies

Litigation

In the normal course of business, we are involved in various legal proceedings. We discuss the significant matters below.

Merger with MidAmerican

Beginning September 18, 2008, seven shareholders of Constellation Energy filed lawsuits in the Circuit Court for Baltimore City, Maryland challenging the then-pending merger with MidAmerican. Four similar suits were filed by other shareholders of Constellation Energy in the United States District Court for the District of Maryland.

The lawsuits claim that the merger consideration was inadequate and did not maximize value for shareholders, that the sales process leading up to the merger was

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~~unreasonably short and procedurally~~ flawed, and that unreasonable deal protection devices were agreed to in order to ward off competing ~~bids and coerce shareholders into accepting the merger.~~bids. The federal lawsuits also assert that the conversion of the Preferred Stock issued to MidAmerican into debt is not permitted under Maryland law. The lawsuits seek declaratory judgments establishing the unenforceability of the merger based on the alleged breaches of duty, injunctive relief to enjoin the merger, rescission of the merger or rescissory damages, the imposition of a constructive trust in favor of shareholders of any benefits received by the individual members of the Board of Directors of Constellation Energy, and reasonable costs and expenses, including attorney's fees.

The termination of the MidAmerican merger renders moot the claims attempting to enjoin the merger with MidAmerican. One of the federal merger cases was voluntarily dismissed on December 31, ~~2008. The~~2008, and the other federal merger cases ~~filed in the United States District Court for the District of Maryland~~ were dismissed as moot on May 27, 2009. ~~We believe there are meritorious defenses to~~Plaintiffs' counsel in six of the ~~remaining claims or requests for relief. However, we are unable at this time to determine~~seven state merger cases have filed dismissals without prejudice of their MidAmerican merger claims. On April 16, 2010, the ~~ultimate outcome~~seventh merger case was dismissed without prejudice by the Court, thereby concluding these cases.

Table of ~~these lawsuits or their possible effect on our financial results.~~Contents

Securities Class Action

Three federal securities class action lawsuits have been filed in the United States District Courts for the Southern District of New York and the District of Maryland between September 2008 and November 2008. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation Energy between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation Energy, a number of its present or former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation Energy's June 27, 2008 offering of Debentures. The securities class actions also allege that Constellation Energy issued false or misleading statements or was aware of material undisclosed information which contradicted public statements including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions seek, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages.

The Southern District of New York granted the defendants' motion to transfer the two securities class actions filed there to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On June 18, 2009, the court appointed a lead plaintiff, who ~~we expect to file~~filed a consolidated amended ~~complaint.~~complaint on September 17, 2009. On November 17, 2009, the defendants moved to dismiss the consolidated amended complaint in its entirety. We are unable at this time to determine the ultimate outcome of the securities class actions or their possible effect on our, or BGE's financial results.

ERISA Actions

In the fall of 2008, multiple class action lawsuits were filed in the United States District Courts for the District of Maryland and the Southern District of New York against Constellation Energy; Mayo A. Shattuck III, Constellation Energy's Chairman of the Board, President and Chief Executive Officer; and others in their roles as fiduciaries of the Constellation Energy Employee Savings Plan. The actions, which have been consolidated into one action in Maryland (the Consolidated Action), allege that the defendants, in violation of various sections of ERISA, breached their fiduciary duties to prudently and loyally manage Constellation Energy Savings Plan's assets by designating Constellation Energy common stock as an investment, by failing to properly provide accurate information about the investment, by failing to avoid conflicts of interest, by failing to properly monitor the investment and by failing to properly monitor other fiduciaries. The plaintiffs seek to compel the defendants to reimburse the plaintiffs and the Constellation Energy Savings Plan for all losses resulting from the defendants' breaches of fiduciary duty, to impose a constructive trust on any unjust enrichment, to award actual damages with pre- and post-judgment interest, to award appropriate equitable relief including injunction and restitution and to award costs and expenses, including attorneys' fees. On October 2, 2009, the defendants moved to dismiss the consolidated complaint in its entirety. We are unable at this time to determine the ultimate outcome of the Consolidated Action or its possible effects on our, or BGE's, financial results.

Mercury

Since September 2002, BGE, Constellation Energy, and several other defendants have been involved in numerous actions filed in the Circuit Court for Baltimore City, Maryland alleging mercury poisoning from several sources, including coal plants formerly owned by BGE. The plants are now owned by a subsidiary of Constellation Energy. In addition to BGE and Constellation Energy, approximately 11 other defendants, consisting of pharmaceutical

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companies, manufacturers of vaccines, and manufacturers of Thimerosal have been sued. Approximately 70 cases, involving claims related to approximately 132 children, have been filed to date, with each claimant seeking $20 million in compensatory damages, plus punitive damages, from us.

~~In rulings applicable to all but three of the cases, involving claims related to approximately 47 children, the Circuit Court for Baltimore City dismissed with prejudice all~~The claims against BGE and Constellation ~~Energy.~~Energy have been dismissed in all of the cases either with prejudice based on rulings by the Court or without prejudice based on voluntary dismissals by the plaintiffs' counsel. Plaintiffs may attempt to pursue appeals of the rulings in favor of BGE and Constellation Energy once the cases are finally concluded as to all defendants. We believe that we have meritorious defenses and intend to defend the ~~remaining~~ actions vigorously. However, we cannot predict the timing, or outcome, of these cases, or their possible effect on our, or BGE's, financial results.

Asbestos

Since 1993, BGE and certain Constellation Energy subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and Constellation Energy knew of and exposed individuals to an asbestos

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hazard. In addition to BGE and Constellation Energy, numerous other parties are defendants in these cases.

Approximately ~~512~~482 individuals who were never employees of BGE or Constellation Energy have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and ~~third-party~~third party claims brought by other defendants may also be filed against BGE and Constellation Energy in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment and a small minority have been resolved for amounts that were not material to our financial results.

BGE and Constellation Energy do not know the specific facts necessary to estimate their potential liability for these claims. The specific facts we do not know include:

•: the identity of the facilities at which the plaintiffs allegedly worked as contractors,
•: the names of the plaintiffs' employers,
•: the dates on which and the places where the exposure allegedly occurred, and
•: the facts and circumstances relating to the alleged exposure.

Until the relevant facts are determined, we are unable to estimate what our, or BGE's, liability might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, the potential effect on our, or BGE's, financial results could be material.

Environmental Matters

Solid and Hazardous Waste

In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, which is its list of sites targeted for clean-up and enforcement, and sent a general notice letter to BGE and 19 other parties identifying them as potentially liable parties at the site. In March 2004, we and other potentially responsible parties formed the 68th Street Coalition and entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the EPA and 19 of the potentially responsible parties, including BGE, with respect to investigation of the site became effective. The settlement requires the potentially responsible parties, over the course of several years, to identify contamination at the site and recommend clean-up options. BGE is ~~fully~~ indemnified by a wholly owned subsidiary of Constellation Energy for most of the costs related to this settlement ~~as well as any~~and clean-up ~~costs.~~of the site. The clean-up costs will not be known until the investigation is closer to ~~completion. However, those~~completion, which is expected by mid-2010. The completed investigation will provide a range of remediation alternatives to the EPA, and the EPA is expected to select one of the alternatives by the end of the first quarter of 2011. The clean-up costs we incur could have a material effect on our financial results.

Air Quality

In May 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment to resolve alleged violations of air quality opacity standards at three fossil fuel plants in Maryland. The consent decree requires the subsidiary to pay a $100,000 penalty, provide $100,000 to a supplemental environmental project, and install technology to control emissions from those plants.

In January 2009, the EPA issued a notice of violation (NOV) to a subsidiary of Constellation Energy, as well as the other owners and the operator of the Keystone coal-fired power plant in Shelocta, Pennsylvania. We hold an approximately 21% interest in the Keystone plant. The NOV alleges that the plant performed various capital projects beginning in 1984 without complying with the new source review permitting requirements of the Clean Air Act. The EPA also contends that the alleged failure to comply with those requirements are continuing violations under the plant's air permits. The EPA could seek civil penalties under the Clean Air Act for the alleged violations.

The owners and operator of the Keystone plant are investigating the allegations and have entered into discussions with the EPA. We believe there are meritorious defenses to the allegations contained in the NOV. However, we cannot predict the outcome of this proceeding and it is not possible to determine our actual liability, if any, at this time.

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Water Quality

In October 2007, a subsidiary of Constellation Energy entered into a consent decree with the Maryland Department of the Environment relating to groundwater contamination at a third party facility that was licensed to accept fly ash, a byproduct generated by our coal-fired plants. The consent decree requires the payment of a $1.0 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. We recorded a liability in our Consolidated Balance Sheets of approximately ~~$7.9~~$10.6 million, which includes the $1 million penalty and our estimate of probable costs to remediate contamination, replace drinking water supplies, monitor groundwater conditions, and otherwise comply with the consent decree. We have paid approximately ~~$4.1~~$5.1 million of these costs as of ~~June 30, 2009,~~March 31,

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2010, resulting in a remaining liability at ~~June 30, 2009~~March 31, 2010 of ~~$3.8~~$5.5 million. We estimate that it is reasonably possible that we could incur additional costs of up to approximately $10 million more than the liability that we accrued.

Insurance

We discuss our ~~nuclear and~~ non-nuclear insurance programs inNote 12 of our ~~2008~~2009 Annual Report on Form 10-K.

Derivative Instruments

Nature of Our Business and Associated Risks

Our business activities primarily include our ~~merchant energy business and our~~Generation, NewEnergy, regulated electric and gas ~~business.~~businesses. Our ~~merchant energy business includes:~~Generation and NewEnergy businesses include:

•: the generation of electricity from our owned and contractually-controlled physical assets,
•: the sale of power, gas, and other energy commodities to wholesale and retail customers, and
•: risk management services and energy trading activities.

Our regulated electric and gas businesses engage in electricity and gas transmission and distribution activities in Central Maryland at prices set by the Maryland PSC that are generally designed to recover our costs, including purchased fuel and energy. Substantially all of our risk management activities involving derivatives occur outside our regulated businesses.

In carrying out our ~~merchant energy~~ business activities, we purchase and sell power, fuel, and other energy-related commodities in competitive markets. These activities expose us to significant risks, including market risk from price volatility for energy commodities and the credit risks of counterparties with which we enter into contracts. The sources of these risks include, but are not limited to, the following:

•: the risks of unfavorable changes in power prices in the wholesale forward and spot markets in which we sell a portion of the power from our power generation facilities and purchase power to meet our load-serving requirements,
•: the risk of unfavorable fuel price changes for the purchase of a portion of the fuel for our generation facilities under short-term contracts or on the spot market. Fuel prices can be volatile, and the price that can be obtained for power produced from such fuel may not change at the same rate ~~or direction~~ as fuel costs.
•: the risk that one or more counterparties may fail to perform under their obligations to make payments or deliver fuel or power,
•: interest rate risk associated with variable-rate debt and the fair value of fixed-rate debt used to finance our operations; and
•: foreign currency exchange rate risk associated with international investments and purchases of equipment and commodities in currencies other than U.S. dollars.

Objectives and Strategies for Using Derivatives

Risk Management Activities

To lower our exposure to the risk of unfavorable fluctuations in commodity prices, interest rates, and foreign currency rates, we routinely enter into derivative contracts, such as fixed-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges, for hedging purposes. The objectives for entering into such hedging transactions primarily include:

•: fixing the price for a portion of anticipated future electricity sales from our generation operations,
•: fixing the price of a portion of anticipated fuel purchases for the operation of our power plants,
•: fixing the price for a portion of anticipated energy purchases to supply our load-serving customers, and
•: managing our exposure to interest rate risk and foreign currency exchange risks.

Non-Risk Management Activities

In addition to the use of derivatives for risk management purposes, we also enter into derivative contracts for trading purposes primarily ~~to achieve the following objectives:~~for:

•: optimizing the margin on surplus electricity generation and load positions and surplus fuel supply and demand positions,

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•: ~~obtaining knowledge of prices~~price discovery and ~~developing expertise in less-liquid markets,~~verification, and
•: deploying limited risk capital in an effort to generate returns.

Accounting for Derivative Instruments

The accounting requirements for derivatives ~~requires~~require recognition of all qualifying derivative instruments on the balance sheet at fair value as either assets or liabilities.

Accounting Designation

We must evaluate new and existing transactions and agreements to determine whether they are derivatives, for which there are several possible accounting treatments. Mark-to-market is required as the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria,

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both at the time of designation and on an ongoing basis. The permissible accounting treatments include:

•: normal purchase normal sale (NPNS),
•: cash flow hedge,
•: fair value hedge, and
•: mark-to-market.

We discuss our accounting policies for derivatives and hedging activities and their impacts on our financial statements inNote 1 toof our ~~2008~~2009 Annual Report on Form 10-K.

NPNS

We elect NPNS accounting for derivative contracts that provide for the purchase or sale of a physical commodity that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Once we elect NPNS classification for a given contract, we cannot subsequently change the election and treat the contract as a derivative using mark-to-market or hedge accounting.

Cash Flow Hedging

We generally elect cash flow hedge accounting for most of the derivatives that we use to hedge market price risk for our physical energy delivery activities because hedge accounting more closely aligns the timing of earnings recognition and cash flows for the underlying business activities. Management monitors the potential impacts of commodity price changes and, where appropriate, may enter into or close out (via offsetting transactions) derivative transactions designated as cash flow hedges.

Commodity Cash Flow Hedges

~~Our merchant energy business has~~We have designated fixed-price forward contracts as cash-flow hedges of forecasted sales of energy and forecasted purchases of fuel and energy for the years ~~2009~~2010 through 2016. ~~Our merchant energy business~~We had net unrealized pre-tax losses on these cash-flow hedges recorded in "Accumulated other comprehensive loss" of ~~$1,845.3~~$1,146.4 million at ~~June 30, 2009~~March 31, 2010 and ~~$2,614.9~~$951.3 million at December 31, ~~2008.~~2009.

We expect to reclassify ~~$1,326.2~~$951.2 million of net pre-tax losses on cash-flow hedges from "Accumulated other comprehensive loss" into earnings during the next twelve months based on market prices at ~~June 30, 2009.~~March 31, 2010. However, the actual amount reclassified into earnings could vary from the amounts recorded at ~~June 30, 2009,~~March 31, 2010, due to future changes in market prices.

When we determine that a forecasted transaction originally hedged has become probable of not occurring, we reclassify net unrealized gains or losses associated with those hedges from "Accumulated other comprehensive loss" to earnings. We recognized in earnings the following pre-tax amounts on such contracts:

Quarter Ended
June 30,
Six Months Ended
June 30,

2009
2008
2009
2008

(In millions)

Pre-tax (losses) gains
$ (74.6 ) $ — $ (241.0 ) $ 0.7

The pre-tax loss reclassified in 2009 resulted from the sale of a majority of our international commodities operation and our termination of certain contracts as part of our efforts to improve liquidity and reduce risk. The forecasted transactions associated with previously designated cash-flow hedge contracts were deemed probable of not occurring.

Quarter ended March 31,	2010			2009


	(In millions)
Pre-tax losses	$	(1.4	)	$	(166.4	)

Interest Rate Swaps Designated as Cash Flow Hedges

We use interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances and to manage our exposure to fluctuations in interest rates on variable rate debt. The effective portion of gains and losses on these interest rate cash flow hedges, net of associated deferred income tax effects, is recorded in "Accumulated other comprehensive loss" in our Consolidated Statements of Comprehensive Income (Loss). We reclassify gains and losses on the hedges from "Accumulated other comprehensive loss" into "Interest expense" in our Consolidated Statements of Income (Loss) during the periods in which the interest payments being hedged occur.

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Accumulated other comprehensive loss includes net unrealized pre-tax gains on interest rate cash-flow hedges of prior debt issuances totaling ~~$12.1~~$7.4 million at ~~June 30, 2009~~March 31, 2010 and ~~$12.0~~$11.3 million at December 31, ~~2008.~~2009. We expect to reclassify ~~$1.9~~$0.6 million of pre-tax net gains on these cash-flow hedges from "Accumulated other comprehensive loss" into "Interest expense" during the next twelve months. We had no hedge ineffectiveness on these swaps.

Fair Value Hedging

We elect fair value hedge accounting for a limited portion of our derivative contracts including certain interest rate ~~swaps and certain forward contracts and price and basis swaps associated with natural gas fuel in storage.~~swaps. The objectives for electing fair value hedging in these situations are to manage our exposure and to optimize the mix of our fixed and floating-rate ~~debt, and to hedge the value of our natural gas in storage. We did not have any fair value hedges related to the value of our natural gas in storage during the second quarter of 2009.~~debt.

Interest Rate Swaps Designated as Fair Value Hedges

We use interest rate swaps designated as fair value hedges to optimize the mix of fixed and floating-rate debt. We record any gains or losses on swaps that qualify for fair value hedge accounting treatment, as well as changes in the fair value of the debt being hedged, in "Interest expense." We record changes in fair value of the swaps in "Derivative assets and liabilities" and changes in the fair value of the debt in "Long-term debt" in our Consolidated Balance Sheets. In addition, we record the difference between interest on hedged fixed-rate debt and floating-rate swaps in "Interest expense" in the periods that the swaps settle.

~~During 2004, we entered into~~We have interest rate swaps qualifying as fair value hedges relating to ~~$450~~$400 million of our fixed-rate debt

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maturing in 2012 and 2015, and converted this notional amount of debt to floating-rate. The fair value of these hedges was an unrealized gain of ~~$40.4~~$44.4 million at ~~June 30, 2009~~March 31, 2010 and ~~$55.9~~$35.8 million at December 31, ~~2008~~2009 and was recorded as an increase in our "Derivative assets" and an increase in our "Long-term debt." We had no hedge ineffectiveness on these interest rate swaps. On July 15, 2009, we terminated an interest rate swap relating to $50 million of the $450 million of our fixed-rate debt and received approximately $4.5 million in cash. This transaction will be recorded in the third quarter of 2009.

Hedge Ineffectiveness

For all categories of derivative instruments designated in hedging relationships, we recorded in earnings the following pre-tax gains (losses) related to hedge ineffectiveness:

Quarter Ended
June 30,
Six Months Ended
June 30,

2009
2008
2009
2008

(In millions)

Cash-flow hedges
$ 23.5 $ (44.7 ) $ 52.6 $ (89.8 )
Fair value hedges
— 6.4 23.9 12.9

Total
$ 23.5 $ (38.3 ) $ 76.5 $ (76.9 )

Quarter ended March 31,	2010		2009


	(In millions)
Cash-flow hedges	$	13.3	$	29.1
Fair value hedges		—		23.9

Total	$	13.3	$	53.0

~~In addition, we~~We did not recognize any gain or loss during ~~the quarter or six months ended June 30,~~2010 and 2009 ~~and 2008~~ relating to changes in value for the portion of our fair value hedges excluded from our hedge effectiveness assessment.

Mark-to-Market

We generally apply mark-to-market accounting for risk management and trading activities for which changes in fair value more closely reflect the economic performance of the underlying business activity. However, we also use mark-to-market accounting for derivatives related to the following physical energy delivery activities:

•: our nonregulated retail gas customer supply activities, which are managed using economic hedges that we have not designated as cash-flow hedges in order to match the timing of recognition of the earnings impacts of those activities to the greatest extent permissible, and
•: economic hedges of activities that require accrual accounting for which the related hedge requires mark-to-market accounting.

Quantitative Information About Derivatives and Hedging Activities

~~Background~~

~~Effective January 1, 2009, we adopted SFAS No. 161,~~~~Disclosures About Derivative Instruments and Hedging Activities,~~ ~~(SFAS No. 161). SFAS No. 161 does not change the accounting for derivatives; rather, it requires expanded disclosure about derivative instruments and hedging activities regarding:~~

•: ~~the ways in which an entity uses derivatives,~~
•: ~~the accounting for derivatives and hedging activities, and~~
•: ~~the impact that derivatives have (or could have) on an entity's financial position, financial performance, and cash flows.~~

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Balance Sheet Tables

We present our derivative assets and liabilities in our Consolidated Balance Sheets on a net basis, including cash collateral, whenever we have a legally enforceable master netting agreement with a counterparty to a derivative contract. We use master netting agreements whenever possible to manage and substantially reduce our potential counterparty credit risk. The net presentation in our Consolidated Balance Sheets reflects our actual credit exposure after giving effect to the beneficial effects of these agreements and cash collateral, and our credit risk is reduced further by other forms of collateral.

The following ~~table provides~~tables provide information about the types of market risks we manage using derivatives. ~~This table~~These tables only ~~includes~~include derivatives and ~~does~~do not reflect the price risks we are hedging that arise from physical assets or nonderivative accrual contracts within our ~~generating plants, customer supply,~~Generation and ~~global commodities activities.~~NewEnergy businesses.

As discussed more fully following the ~~table,~~tables, we present this information by disaggregating our net derivative assets and liabilities into gross components on a contract-by-contract basis before giving effect to the risk-reducing benefits of master netting arrangements and collateral. As a result, we must present each individual contract as an "asset value" if it is in the money or a "liability value" if it is out of the money, regardless of whether the individual contracts offset market or credit risks of other contracts in full or in part. Therefore, the gross amounts in ~~this table~~these tables do not reflect our actual economic or credit risk associated with derivatives. This gross presentation is intended only to show separately the various derivative contract types we use, such as commodities, interest rate, and foreign exchange.

In order to identify how our derivatives impact our financial position, at the bottom of the ~~table~~tables we provide a reconciliation of the gross fair value components to the net fair value amounts as presented in theFair Value Measurements ~~section of this~~ note and our Consolidated Balance Sheets.

The gross asset and liability values in the ~~table~~tables below are segregated between those derivatives designated in qualifying hedge accounting relationships and those not designated in hedge accounting relationships. Derivatives not designated in hedging relationships include our NewEnergy retail gas ~~customer supply operation,~~operations, economic hedges of accrual activities, the total return swaps entered into to effect the sale of the international commodities and Houston-based gas trading operations, ~~that we have divested,~~ and risk management and trading activities which we have substantially curtailed as part of our effort to reduce risk in our business. We use the end of period accounting designation to determine the classification for each derivative position.

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As of June 30, 2009
Derivatives
Designated as Hedging
Instruments for
Accounting Purposes
Derivatives Not
Designated As Hedging
Instruments for
Accounting Purposes
All Derivatives
Combined

Contract type
Asset
Values³
Liability
Values⁴
Asset
Values³
Liability
Values⁴
Asset
Values³
Liability
Values⁴

(In millions)

Power contracts
$ 2,871.4 $ (4,146.8 ) $ 24,500.4 $ (25,291.8 ) $ 27,371.8 $ (29,438.6 )

Gas contracts
2,215.4 (1,593.1 ) 8,602.6 (8,300.6 ) 10,818.0 (9,893.7 )

Coal contracts
9.7 (123.5 ) 1,650.3 (1,679.6 ) 1,660.0 (1,803.1 )

Other commodity contracts¹
25.1 (19.4 ) 239.4 (201.7 ) 264.5 (221.1 )

Interest rate contracts
40.4 — 43.2 (62.4 ) 83.6 (62.4 )

Foreign exchange contracts
— (5.9 ) 29.6 (12.7 ) 29.6 (18.6 )

Total gross fair values
$ 5,162.0 $ (5,888.7 ) $ 35,065.5 $ (35,548.8 ) $ 40,227.5 $ (41,437.5 )

Netting arrangements⁵
(39,093.8 ) 39,093.8

Cash collateral
(193.4 ) 133.4

Net fair values
$ 940.3 $ (2,210.3 )

Net fair value by balance sheet line item:

Accounts receivable²
$ (843.3 )
Derivative assets—current
1,036.4
Derivative assets—noncurrent
747.2
Derivative liabilities—current
(1,272.8 )
Derivative liabilities—noncurrent
(937.5 )

Total Derivatives
$ 940.3 $ (2,210.3 )

As of March 31, 2010		Derivatives Designated as Hedging Instruments for Accounting Purposes					Derivatives Not Designated As Hedging Instruments for Accounting Purposes					All Derivatives Combined


Contract type		Asset Values³		Liability Values⁴			Asset Values³		Liability Values⁴			Asset Values³			Liability Values⁴

		(In millions)
	Power contracts	$	2,889.0	$	(3,530.5	)	$	16,954.3	$	(17,645.2	)	$	19,843.3		$	(21,175.7	)
	Gas contracts		2,615.6		(2,342.5	)		5,945.3		(5,647.3	)		8,560.9			(7,989.8	)
	Coal contracts		19.9		(55.0	)		475.0		(486.3	)		494.9			(541.3	)
	Other commodity contracts¹		—		—			73.5		(34.4	)		73.5			(34.4	)
	Interest rate contracts		44.4		—			30.4		(39.1	)		74.8			(39.1	)
	Foreign exchange contracts		—		—			12.2		(9.8	)		12.2			(9.8	)

Total gross fair values		$	5,568.9	$	(5,928.0	)	$	23,490.7	$	(23,862.1	)	$	29,059.6		$	(29,790.1	)

	Netting arrangements⁵												(27,878.0	)		27,878.0
	Cash collateral												(105.6	)		192.5

Net fair values												$	1,076.0		$	(1,719.6	)

Net fair value by balance sheet line item:
Accounts receivable²												$	(341.4	)
Derivative assets—current													686.0
Derivative assets—noncurrent													731.4
Derivative liabilities—current																(906.7	)
Derivative liabilities—noncurrent																(812.9	)

Total Derivatives												$	1,076.0		$	(1,719.6	)

1 Other commodity contracts include oil, freight, emission allowances, and weather contracts.

2 Represents the unrealized fair value of exchange traded derivatives, exclusive of cash margin posted.

3 Represents in-the-money contracts without regard to potentially offsetting out-of-the-money contracts under master netting agreements.

4 Represents out-of-the-money contracts without regard to potentially offsetting in-the-money contracts under master netting agreements.

5 Represents the effect of legally enforceable master netting agreements.

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As of December 31, 2009		Derivatives Designated as Hedging Instruments for Accounting Purposes					Derivatives Not Designated As Hedging Instruments for Accounting Purposes					All Derivatives Combined


Contract type		Asset Values³		Liability Values⁴			Asset Values³		Liability Values⁴			Asset Values³			Liability Values⁴

		(In millions)
	Power contracts	$	1,737.3	$	(2,292.1	)	$	11,729.3	$	(12,414.3	)	$	13,466.6		$	(14,706.4	)
	Gas contracts		1,860.6		(1,380.0	)		4,159.1		(3,857.1	)		6,019.7			(5,237.1	)
	Coal contracts		20.1		(40.8	)		609.5		(627.2	)		629.6			(668.0	)
	Other commodity contracts¹		1.4		(0.8	)		83.1		(32.1	)		84.5			(32.9	)
	Interest rate contracts		35.8		—			28.5		(39.9	)		64.3			(39.9	)
	Foreign exchange contracts		—		—			13.2		(9.0	)		13.2			(9.0	)

Total gross fair values		$	3,655.2	$	(3,713.7	)	$	16,622.7	$	(16,979.6	)	$	20,277.9		$	(20,693.3	)

	Netting arrangements⁵												(19,261.0	)		19,261.0
	Cash collateral												(92.6	)		125.6

Net fair values												$	924.3		$	(1,306.7	)

Net fair value by balance sheet line item:
Accounts receivable²												$	(348.7	)
Derivative assets—current													639.1
Derivative assets—noncurrent													633.9
Derivative liabilities—current																(632.6	)
Derivative liabilities—noncurrent																(674.1	)

Total Derivatives												$	924.3		$	(1,306.7	)

1 Other commodity contracts include oil, freight, emission allowances, and weather contracts.

2 Represents the unrealized fair value of exchange traded derivatives, exclusive of cash margin posted.

3 Represents in-the-money contracts without regard to potentially offsetting out-of-the-money contracts under master netting agreements.

4 Represents out-of-the-money contracts without regard to potentially offsetting in-the-money contracts under master netting agreements.

5 Represents the effect of legally enforceable master netting agreements.

The magnitude of and changes in the gross derivatives components in ~~this table~~these tables do not indicate changes in the level of derivative activities, the level of market risk, or the level of credit risk. The primary factors affecting the magnitude of the gross amounts in the ~~table~~tables are changes in commodity prices and the total number of contracts. If commodity prices change, the gross amounts could increase, even if the level of contracts stays the same, because separate presentation is required for contracts that are in the money from those that are out of the money. As a result, the gross amounts of even fully hedged positions could increase if prices change. Additionally, if the number of contracts increases, the gross amounts also could increase. Thus, the execution of new contracts to reduce economic risk could actually increase the gross amounts in the table because of the requirement to present the gross value of each individual contract separately.

The primary purpose of ~~this table~~these tables is to disaggregate the risks being managed using ~~derivatives.~~derivatives by contract type and accounting treatment. In order to achieve this objective, we prepare ~~this table~~these tables by separating each individual derivative contract that is in the money from each contract that is out of the money and present such amounts on a gross basis, even for offsetting contracts that have identical quantities for the same commodity, location, and delivery period. We must also present these components excluding the substantive credit-risk reducing effects of master netting agreements and collateral. As a result, the gross "asset" and "liability" amounts for each contract type far exceed our actual economic exposure to commodity price risk and credit risk. Our actual economic exposure consists of the net derivative position combined with our nonderivative accrual contracts, such as those for load-serving, and our physical assets, such as our power plants. Our actual derivative credit risk exposure after master netting agreements and cash collateral is reflected in the net fair value amounts shown at the bottom of the ~~table~~tables above. Our total economic and credit exposures, including derivatives, are managed in a comprehensive risk framework that includes risk measures such as economic value at risk, stress testing, and maximum potential credit exposure.

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Gain and (Loss) Tables

The tables below summarize the gain and loss impacts of our derivative instruments segregated into the following categories:

•: cash flow hedges,
•: fair value hedges, and
•: mark-to-market derivatives.

The tables only include this information for derivatives and do not reflect the related gains or losses that arise from generation and generation-related assets, nonderivative accrual contracts, or NPNS contracts within our Generation ~~Customer Supply,~~ and ~~Global Commodities activities,~~NewEnergy businesses, other than fair value hedges, for which we separately show the gain or loss on the hedged asset or liability. As a result, for mark-to-market and cash-flow hedge derivatives, these tables only reflect the impact of derivatives themselves and therefore do not necessarily include all of the income statement impacts of the transactions for which derivatives are used to manage risk. For a more complete discussion of how derivatives affect our financial performance, see our accounting policy for Revenues, Fuel and Purchased Energy Expenses, and Derivatives and Hedging Activities inNote 1 toof our ~~2008~~2009 Annual Report on Form 10-K.

The following ~~table presents~~tables present gains and losses on derivatives designated as cash flow hedges. As discussed more fully in our accounting policy, we record the effective portion of unrealized gains and losses on cash flow hedges in Accumulated Other Comprehensive Loss until the hedged forecasted transaction affects earnings. We record the ineffective portion of gains and losses on cash flow hedges in earnings as they occur. When the hedged forecasted transaction settles and is recorded in earnings, we reclassify the related amounts from Accumulated Other Comprehensive Loss into earnings, with the result that the combination of revenue or expense from the forecasted transaction and gain or loss from the hedge are recognized in earnings at a total amount equal to the hedged price. Accordingly, the amount of derivative gains and losses recorded in Accumulated Other Comprehensive Loss and reclassified from Accumulated Other Comprehensive Loss into earnings does not reflect the total economics of the hedged forecasted transactions. The total impact of our forecasted transactions and related hedges is reflected in our Consolidated Statements of Income (Loss).

Cash Flow Hedges

Quarter Ended June 30, 2009
Six Months Ended June 30, 2009

Amount of
Derivative Gain
(Loss) Recorded
in AOCI

Contract type:
Quarter
Ended
June 30,
2009
Six Months
Ended
June 30,
2009
Statement of Income (Loss) Line Item
Amount of Gain
(Loss) Reclassified
from AOCI into
Earnings
Amount of Derivative
Ineffectiveness
Gain (Loss) Recorded
in Earnings
Amount of Gain
(Loss) Reclassified
from AOCI into
Earnings
Amount of Derivative
Ineffectiveness
Gain (Loss) Recorded
in Earnings

(In millions)

Hedges of forecasted sales:
Nonregulated revenues

Power contracts
$ 100.4 $ 262.2 $ (37.5 ) $ 21.2 $ (129.6 ) $ 81.0

Gas contracts
7.9 (23.9 ) (0.6 ) 4.5 (22.0 ) 6.5

Coal contracts
— 10.0 — — (229.9 ) —

Other commodity contracts¹
(7.1 ) 6.6 (0.8 ) (2.2 ) (3.6 ) (5.1 )
Interest rate contracts
— (0.3 ) (0.2 ) — (0.2 ) —
Foreign exchange contracts
— 0.3 — — (0.9 ) —

Total gains (losses)
$ 101.2 $ 254.9 Total included in nonregulated revenues $ (39.1 ) $ 23.5 $ (386.2 ) $ 82.4

Hedges of forecasted purchases:
Fuel and purchased energy expense

Power contracts
$ (112.8 ) $ (886.8 ) $ (611.9 ) $ (0.3 ) $ (1,038.4 ) $ (29.5 )

Gas contracts
(21.2 ) 154.5 66.7 1.9 92.7 2.6

Coal contracts
(40.5 ) (125.1 ) (52.0 ) (1.6 ) (65.3 ) (2.9 )

Other commodity contracts²
(3.7 ) (2.1 ) (2.7 ) — 23.1 —
Foreign exchange contracts
— 0.1 — — 0.1 —

Total gains (losses)
$ (178.2 ) $ (859.4 ) Total included in fuel and purchased energy expense $ (599.9 ) $ — $ (987.8 ) $ (29.8 )

Hedges of interest rates:
Interest expense

Interest rate contracts
— — (0.1 ) — (0.2 ) —

Total gains (losses)
$ — $ — Total included in interest expense $ (0.1 ) $ — $ (0.2 ) $ —

Grand total gains (losses)
$ (77.0 ) $ (604.5 ) $ (639.1 ) $ 23.5 $ (1,374.2 ) $ 52.6

Cash Flow Hedges		Quarter Ended March 31,


		Gain (Loss) Recorded in AOCI							Gain (Loss) Reclassified from AOCI into Earnings						Ineffectiveness Gain (Loss) Recorded in Earnings

								Statement of Income (Loss) Line Item
Contract type:		2010			2009			Statement of Income (Loss) Line Item	2010			2009			2010			2009

		(In millions)
Hedges of forecasted sales:								Nonregulated revenues
	Power contracts	$	202.5		$	161.8			$	(59.2	)	$	(92.0	)	$	21.8		$	59.8
	Gas contracts		(34.9	)		(31.8	)			20.2			(21.4	)		(1.1	)		2.1
	Coal contracts		—			10.0				—			(229.9	)		—			—
	Other commodity contracts¹		—			13.7				(0.7	)		(2.8	)		—			(3.0	)
Foreign exchange contracts			—			0.3				—			(0.9	)		—			—

Total gains (losses)		$	167.6		$	154.0		Total included in nonregulated revenues	$	(39.7	)	$	(347.0	)	$	20.7		$	58.9

Hedges of forecasted purchases:								Fuel and purchased energy expense
	Power contracts	$	(455.5	)	$	(774.1	)		$	(203.1	)	$	(426.5	)	$	(9.3	)	$	(29.3	)
	Gas contracts		(73.6	)		175.2				78.0			25.9			—			0.7
	Coal contracts		(10.8	)		(84.6	)			(12.5	)		(13.3	)		1.7			(1.2	)
	Other commodity contracts²		(0.2	)		1.8				(0.3	)		25.8			0.2			—
Foreign exchange contracts			—			0.1				—			0.1			—			—

Total losses		$	(540.1	)	$	(681.6	)	Total included in fuel and purchased energy expense	$	(137.9	)	$	(388.0	)	$	(7.4	)	$	(29.8	)

Hedges of interest rates:								Interest expense
	Interest rate contracts		—			(0.3	)			3.9			(0.1	)		—			—

Total gains		$	—		$	(0.3	)	Total included in interest expense	$	3.9		$	(0.1	)	$	—		$	—

Grand total (losses) gains		$	(372.5	)	$	(527.9	)		$	(173.7	)	$	(735.1	)	$	13.3		$	29.1

1 Other commodity sale contracts include oil and freight contracts.

2 Other commodity purchase contracts include freight and emission allowances.

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The following table presents gains and losses on derivatives designated as fair value hedges and, separately, the gains and losses on the hedged item. As discussed earlier, we record the unrealized gains and losses on fair value hedges as well as changes in the fair value of the hedged asset or liability in earnings as they occur. The difference between ~~these amounts represents hedge ineffectiveness. Due to~~ the ~~sale of our Houston-based gas trading operation, we do not have any second quarter activity under~~gains and losses on derivatives designated as fair value hedges ~~related to gas contracts.~~and the gains and losses on the hedged item represents the recognition of locked-in gains on terminated interest rate swaps.

Fair Value Hedges
Quarter Ended June 30, 2009
Six Months Ended June 30, 2009

Contract type:
Statement of Income (Loss) Line Item
Amount of Gain (Loss)
Recognized in Income
on Derivative
Amount of Gain (Loss)
Recognized in Income
on Hedged Item
Amount of Gain (Loss)
Recognized in Income
on Derivative
Amount of Gain (Loss)
Recognized in Income
on Hedged Item

(In millions)

Commodity contracts:

Gas contracts
Nonregulated revenues $ — $ — $ 40.6 $ (16.7 )
Interest rate contracts
Interest expense (20.4 ) 20.4 (15.5 ) 15.5

Total gains (losses)
$ (20.4 ) $ 20.4 $ 25.1 $ (1.2 )

Fair Value Hedges		Quarter Ended March 31,


			Amount of Gain (Loss) Recognized in Income on Derivative				Amount of Gain (Loss) Recognized in Income on Hedged Item
Contract type:		Statement of Income (Loss) Line Item	2010		2009		2010			2009

			(In millions)
Commodity contracts:
	Gas contracts	Nonregulated revenues	$	—	$	40.6	$	—		$	(16.7	)
Interest rate contracts		Interest expense		13.2		4.9		(11.1	)		(4.9	)

Total gains (losses)			$	13.2	$	45.5	$	(11.1	)	$	(21.6	)

The following table presents gains and losses on mark-to-market ~~derivatives, contracts that have not been designated as hedges for accounting purposes.~~derivatives. As discussed more fully inNote 1 to our ~~2008~~2009 Annual Report on Form 10-K, we record the unrealized gains and losses on mark-to-market derivatives in earnings as they occur. While we use mark-to-market accounting for risk management and trading activities because changes in fair value more closely reflect the economic performance of the activity, we also use mark-to-market accounting for certain derivatives related to portions of our physical energy delivery activities. Accordingly, the total amount of gains and losses from mark-to-market derivatives does not necessarily reflect the total economics of related transactions.

Mark-to-Market Derivatives

Quarter Ended June 30, 2009
Six Months Ended June 30, 2009

Contract type:
Statement of Income (Loss) Line Item
Amount of Gain (Loss)
Recorded in Income
on Derivative
Amount of Gain (Loss)
Recorded in Income
on Derivative

(In millions)

Commodity contracts:

Power contracts
Nonregulated revenues $ 58.4 $ 147.0

Gas contracts
Nonregulated revenues (116.9 ) (279.5 )

Coal contracts
Nonregulated revenues 52.1 9.8

Other commodity contracts¹
Nonregulated revenues 4.3 0.4

Coal contracts
Fuel and purchased energy expense (2.2 ) (107.7 )
Interest rate contracts
Nonregulated revenues (20.1 ) (20.6 )
Foreign exchange contracts
Nonregulated revenues 1.9 9.7

Total gains (losses)
$ (22.5 ) $ (240.9 )

Mark-to-Market Derivatives		Quarter Ended March 31,


			Amount of Gain (Loss) Recorded in Income

		Statement of Income (Loss) Line Item
Contract type:		Statement of Income (Loss) Line Item	2010			2009

			(In millions)
Commodity contracts:
	Power contracts	Nonregulated revenues	$	(64.9	)	$	88.6
	Gas contracts	Nonregulated revenues		25.7			(162.6	)
	Coal contracts	Nonregulated revenues		0.1			(42.3	)
	Other commodity contracts¹	Nonregulated revenues		4.9			(3.9	)
	Coal contracts	Fuel and purchased energy expense		—			(105.5	)
Interest rate contracts		Nonregulated revenues		(1.1	)		(0.5	)
Foreign exchange contracts		Nonregulated revenues		(0.9	)		7.8

Total gains (losses)			$	(36.2	)	$	(218.4	)

1 Other commodity contracts ~~for the quarter ended June 30, 2009~~ include oil, freight, uranium, weather, and emission allowances. ~~For the six months ended June 30, 2009, other commodity contracts also include uranium.~~

In computing the amounts of derivative gains and losses in the above tables, we include the changes in fair values of derivative contracts up to the date of maturity or settlement of each contract. This approach facilitates a comparable presentation for both financial and physical derivative contracts. In addition, for cash flow hedges we include the impact of intra-quarter transactions (i.e., those that arise and settle within the same quarter) in both gains and losses recognized in Accumulated Other Comprehensive Loss and amounts reclassified from Accumulated Other Comprehensive Loss into earnings.

Volume of Derivative Activity

The volume of our derivatives activity is directly related to the fundamental nature and scope of our business and the risks we manage. We own or control electric generating

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facilities, which exposes us to both power and fuel price risk; we serve electric and gas wholesale and retail customers within our ~~customer supply~~ NewEnergy

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business, which exposes us to electricity and natural gas price risk; and we provide risk management services and engage in trading activities, which can expose us to a variety of commodity price risks. We conduct our business activities throughout the United States and internationally. In order to manage the risks associated with these activities, we are required to be an active participant in the energy markets, and we routinely employ derivative instruments to conduct our business.

Derivative instruments provide an efficient and effective way to conduct our business and to manage the associated risks. We manage our generating resources and ~~customer supply activities~~NewEnergy business based upon established policies and limits, and we use derivatives to establish a portion of our hedges and to adjust the level of our hedges from time to time. Additionally, we engage in trading activities which enable us to execute hedging transactions in a cost-effective manner. We manage those activities based upon various risk measures, including position limits, economic value at risk (EVaR) and value at risk (VaR), and we use derivatives to establish and maintain those activities within the prescribed limits. We are also using derivatives to execute, control, and reduce the overall level of our trading positions and risk as well as to manage a portion of our interest rate risk associated with debt and our foreign currency risk from non-dollar denominated transactions. Accordingly, the use of derivative instruments is integral to the conduct of our business, and derivative instruments are an important tool through which we are able to manage and mitigate the risks that are inherent in our activities.

The following ~~table presents~~tables present information designed to provide insight into the overall volume of our derivatives usage. However, the volumes presented in ~~this table~~these tables are subject to a number of limitations and should only be used as an indication of the extent of our derivatives usage and the risks they are intended to manage.

First, the volume information is not a complete representation of our market price risk because it only includes derivative contracts. Accordingly, ~~this table does~~these tables do not present a complete picture of our overall net economic exposure, and should not be interpreted as an indication of open or unhedged commodity positions, because the use of derivatives is only one of the means by which we engage in and manage the risks of our business. For example, ~~the table does~~these tables do not include power or fuel quantities and risks arising from our physical assets, non-derivative contracts, and forecasted transactions that we manage using derivatives; a portion of these volumes reduce those risks. ItThey also ~~does~~do not include volumes of commodities under nonderivative contracts that we use to serve customers or manage our risks. Our actual net economic exposure from our generating facilities and ~~customer supply~~NewEnergy activities is reduced by derivatives, and the exposure from our trading activities is managed and controlled through the risk measures discussed above. Therefore, the information in the ~~table~~tables below is only an indication of that portion of our business that we manage through derivatives and serves primarily to identify the extent of our derivatives activities and the types of risks that they are intended to manage.

Additionally, the disclosure of derivative quantities potentially could reveal commercially valuable or otherwise competitively sensitive information that could limit the effectiveness and profitability of our business activities. Therefore, in the ~~table~~tables below, we have computed the derivative volumes for commodities by aggregating the absolute value of net ~~open long (purchase) and short (sell)~~ positions within commodities for each year. This provides an indication of the level of derivatives activity, but it does not indicate either the direction of our position (long or short), or the overall size of our position. We believe this presentation gives an appropriate indication of the level of derivatives activity without unnecessarily revealing the size and direction of our derivatives positions.

Finally, the volume information for commodity derivatives represents "delta equivalent" quantities, not gross notional amounts. We make use of different types of commodity derivative instruments such as forwards, futures, options, and swaps, and we believe that the delta equivalent quantity is the most relevant measure of the volume associated with these commodity derivatives. The delta-equivalent quantity represents a risk-adjusted notional quantity for each contract that takes into account the probability that an option will be exercised. Therefore, the volume information for commodity derivatives represents the delta equivalent quantity of those contracts, computed on the basis described above. For interest rate contracts and foreign currency contracts we have presented the notional amounts of such contracts in the ~~table~~tables below.

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The following ~~table presents~~tables present the volume of our derivative activities as of ~~June 30,~~March 31, 2010 and December 31, 2009 shown by contractual settlement year.

Quantities¹ Under Derivative Contracts

As of June 30, 2009

Contract Type (Unit)
2009
2010
2011
2012
2013
Thereafter
Total

(In millions)

Power (MWh)
21.6 23.6 8.3 4.9 — 3.7 62.1
Gas (MMBTU)
30.6 15.1 14.7 15.8 5.5 43.2 124.9
Coal (Tons)
3.9 4.7 0.9 0.4 — — 9.9
Oil (BBL)
0.2 0.1 — — — — 0.3
Emission Allowances (Tons)
5.5 0.2 — — — — 5.7
Interest Rate Contracts
$ 1,534.3 $ 516.4 $ 238.6 $ 486.5 $ 93.2 $ 325.0 $ 3,194.0
Foreign Exchange Rate Contracts
$ 6.7 $ 37.0 $ 24.5 $ 16.7 $ 16.7 $ 32.3 $ 133.9

Quantities¹ Under Derivative Contracts			As of March 31, 2010


Contract Type (Unit)	2010		2011		2012		2013		2014		Thereafter		Total

	(In millions)
Power (MWh)		26.3		28.7		0.5		2.7		4.2		1.0		63.4
Gas (MMBTU)		42.2		64.0		25.4		17.0		47.1		18.8		214.5
Coal (Tons)		4.0		8.0		0.6		—		—		—		12.6
Oil (BBL)		0.3		0.1		0.2		—		—		—		0.6
Emission Allowances (Tons)		10.0		—		—		—		—		—		10.0
Interest Rate Contracts	$	582.3	$	29.4	$	321.3	$	1.8	$	455.0	$	—	$	1,389.8
Foreign Exchange Rate Contracts	$	13.5	$	84.9	$	7.0	$	16.7	$	16.8	$	15.5	$	154.4

Quantities¹ Under Derivative Contracts			As of December 31, 2009


Contract Type (Unit)	2010		2011		2012		2013		2014		Thereafter		Total

	(In millions)
Power (MWh)		32.7		1.6		3.2		3.2		0.1		0.9		41.7
Gas (MMBTU)		37.3		37.4		22.1		21.0		22.7		21.3		161.8
Coal (Tons)		3.9		3.9		0.2		—		—		—		8.0
Oil (BBL)		0.3		—		—		—		—		—		0.3
Emission Allowances (Tons)		7.2		—		—		—		—		—		7.2
Interest Rate Contracts	$	972.3	$	140.6	$	440.5	$	58.2	$	255.0	$	200.0	$	2,066.6
Foreign Exchange Rate Contracts	$	27.9	$	72.4	$	16.7	$	16.7	$	16.8	$	15.5	$	166.0

1 Amounts in the ~~table~~tables are only intended to provide an indication of the level of derivatives activity and should not be interpreted as a measure of any derivative position or overall economic exposure to market risk. Quantities are expressed as "delta equivalents" on an absolute value basis by contract type by year. Additionally, quantities relate only to derivatives and do not include potentially offsetting quantities associated with physical assets and nonderivative accrual contracts.

In addition to the commodities in the tables above, we also hold derivative instruments related to weather ~~and freight~~ that are insignificant relative to the overall level of our derivative activity.

Credit-Risk Related Contingent Features

Certain of our derivative instruments contain provisions that would require additional collateral upon a credit-related event such as an adequate assurance provision or a credit rating decrease in the senior unsecured debt of Constellation Energy. The amount of collateral we could be required to post would be determined by the fair value of contracts containing such provisions that represent a net liability, after offset for the fair value of any asset contracts with the same counterparty under master netting agreements and any other collateral already posted. This collateral amount is a component of, and is not in addition to, the total collateral we could be required to post for all contracts upon a credit rating decrease.

The following ~~table presents~~tables present information related to these ~~derivatives.~~derivatives at March 31, 2010 and December 31, 2009. Based on contractual provisions, we estimate that if Constellation Energy's senior unsecured debt were downgraded, our total contingent collateral obligation for derivatives in a net liability position was ~~$0.3~~$0.2 billion as of ~~June 30,~~March 31, 2010 and at December 31, 2009, which represents the additional collateral that we could be required to post with counterparties, including both cash collateral and letters of credit, in the event of a credit downgrade to below investment grade. These amounts are associated with net derivative liabilities totaling ~~$1.5~~$1.4 billion at March 31, 2010 and $1.0 billion at December 31, 2009 after reflecting legally binding master netting agreements and collateral already posted.

~~Interpretations of SFAS No. 161 indicate that~~We present the gross fair value of derivatives in a net liability position that have credit-risk-related contingent features ~~should be disclosed, and we present this amount~~ in the first column in the ~~table~~tables below. This gross fair value amount represents only the out-of-the-money contracts containing such features that are not fully collateralized by cash on a stand-alone basis. Thus, this amount does not reflect the offsetting fair value of in-the-money contracts under legally-binding master netting agreements with the same counterparty, as shown in the second column in the ~~table.~~tables. These in-the-money contracts would offset the amount of any gross liability that could be required to be collateralized, and as a result, the actual potential collateral requirements would be based upon the net fair value of derivatives containing such features, not the gross amount. The amount of any possible

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contingent collateral for such contracts in the event of a downgrade would be further reduced to the extent that we have already posted collateral related to the net liability.

Because the amount of any contingent collateral obligation would be based on the net fair value of all derivative contracts under each master netting agreement, we believe that the "net fair value of derivative contracts containing this feature" as shown in the ~~table~~tables below is the most relevant measure of derivatives in a net liability position with credit-risk-related contingent features. This amount reflects the actual net liability upon which existing collateral postings are computed and upon which any additional contingent collateral obligation would be based.

~~Table of Contents~~

Credit-Risk Related Contingent Feature	Credit-Risk Related Contingent Feature						As of June 30, 2009				Credit-Risk Related Contingent Feature						As of March 31, 2010


Gross Fair Value of Derivative Contracts Containing This Feature¹	Gross Fair Value of Derivative Contracts Containing This Feature¹	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Agreements²			Net Fair Value of Derivative Contracts Containing This Feature³		Amount of Posted Collateral⁴		Contingent Collateral Obligation⁵		Gross Fair Value of Derivative Contracts Containing This Feature¹	Offsetting Fair Value of In-the-Money Contracts Under Master Netting Agreements²			Net Fair Value of Derivative Contracts Containing This Feature³		Amount of Posted Collateral⁴		Contingent Collateral Obligation⁵

(In billions)	(In billions)										(In billions)
$	18.1	$	(16.6	)	$	1.5	$	1.0	$	0.3	11.7	$	(10.3	)	$	1.4	$	1.1	$	0.2

1 Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features that are not fully collateralized by posted cash collateral on an individual, contract-by-contract basis ignoring the effects of master netting agreements.

2 Amount represents the offsetting fair value of in-the-money derivative contracts under legally-enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which we potentially could be required to post collateral.

3 Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

4 Amount includes cash collateral posted of ~~$133.4~~$192.5 million and letters of credit of ~~$882.1 million.~~$889.3 million at March 31, 2010 and $125.6 million and letters of credit of $585.2 million at December 31, 2009.

5 Amounts represent the additional collateral that we could be required to post with counterparties, including both cash collateral and letters of credit, in the event of a credit downgrade to below investment grade after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

~~Concentrations of Derivative-Related Credit Risk~~

Constellation Energy's wholesale and retail credit risk management policies establish the guidelines under which we extend unsecured credit to counterparties and customers. Based on the counterparty analysis and limits established by Constellation Energy, collateral or other security may be required to enter into transactions based on the potential exposure. Under most agreements we have entered into, collateral is in the form of cash or letters of credit. These forms of collateral are held by us and can be drawn upon should a counterparty default on its obligations under its agreement.

As a best practice, we enter into commodity master agreements and cross-commodity netting agreements in order to achieve the benefits of netting in terms of exposure and collateral capital reductions. Where beneficial to the risk profile of the company, we will seek credit protections that include upfront collateral, margining, material adverse change clauses (based on credit ratings downgrades or other financial ratios events), and adequate assurances clauses in our master agreements that can be utilized to request security from our counterparties in order to cover our potential risk of loss.

We consider a significant concentration of credit risk to be any single obligor or counterparty whose concentration exceeds 10% of total credit exposure. As of June 30, 2009, no single counterparty concentration comprises more than 10% of the total exposure of the portfolio, and no collection of counterparties based in a single country other than the United States comprises more than 10% of the total exposure of the portfolio.

~~Fair Value Measurements~~

~~SFAS No. 157,~~~~Fair Value Measurements~~, (SFAS No. 157) defines fair value, establishes a framework for measuring fair value, and requires certain disclosures about fair value measurements. Fair value is the price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

~~SFAS No. 157 also creates a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:~~

•: ~~Level 1—Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities.~~
•: ~~Level 2—Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date.~~
•: ~~Level 3—Significant inputs that are generally not observable from market activity.~~

We determine the fair value of our assets and liabilities using unadjusted quoted prices in active markets (Level 1) or pricing inputs that are observable (Level 2) whenever that information is available. We use unobservable inputs (Level 3) to estimate fair value only when relevant observable inputs are not available.

~~We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is~~

On November 6, 2009, upon the ~~FASB issued SFAS No. 167,~~~~Amendments to FASB Interpretation No. 46R~~~~, which is effective for interim and annual reporting periods beginning after November 15, 2009. The standard includes the following significant provisions:~~

~~We are currently evaluating the impacts of this standard on our, and BGE's, financial results, which could be material.~~

~~In June 2009, the FASB issued SFAS No. 168,~~~~The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles~~, which is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The FASB Accounting Standards Codification (Codification) will become the sole source of authoritative generally accepted accounting principles in the United States of America (GAAP) and will supersede all existing non-SEC accounting and reporting standards. Once the Codification is in effect, all of its content will carry the same level of authority, and any accounting guidance not contained within the Codification will become non-authoritative. Because the Codification is not intended to change GAAP, the adoption of this standard will not have an impact on our, or BGE's, financial results. However, our disclosures and references to accounting standards will change to reflect the new Codification structure beginning with our Form 10-Q for the quarter ending September 30, 2009.

~~In December 2007, the FASB issued SFAS No. 160,~~~~Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51~~~~. SFAS No. 160 provides that a noncontrolling~~membership interest in ~~a subsidiary is an ownership~~CENG, our nuclear generation and operation business, to EDF, we deconsolidated CENG and began accounting for our 50.01% membership interest in ~~the consolidated entity that should be reported~~CENG as an equity in the consolidated financial statements. This presentation is based upon the view of the consolidated business as a single economic entity and considers minority ownership interests in consolidated subsidiaries as equity in the consolidated entity.

~~Effective January 1, 2009, we presented and disclosed noncontrolling interests in our Consolidated Financial Statements in accordance with SFAS No. 160.~~

~~The total change in Constellation Energy's noncontrolling interest amount of $25.8 million is primarily due to income earned at one entity in which we have a noncontrolling interest.~~

~~The total change in BGE's noncontrolling interest amount of $8.1 million is primarily due to a contribution by its noncontrolling interest owner.~~

In March 2008, the FASB issued SFAS No. 161. SFAS No. 161 requires entities to provide expanded disclosure about derivative instruments and hedging activities, but does not change the accounting for derivatives. We adopted SFAS No. 161 on January 1, 2009 and provide these additional disclosures beginning on page 29.

~~In May 2009, the FASB issued SFAS No. 165,~~~~Subsequent Events~~, which establishes the general standards of accounting for and disclosure of events that occur subsequent to the balance sheet date but before financial statements are issued or are available to be issued. Because this standard does not change the fundamental requirements for accounting for subsequent events, it does not have a significant impact on our, or BGE's financial results. However, this standard does require the disclosure of the date through which subsequent events have been evaluated as well as whether that date is the date the financial statements were issued. We adopted SFAS No. 165 as of June 30, 2009 and have provided the additional required disclosures on page 11.method investment.

In ~~April 2009,~~connection with the ~~FASB issued Staff Position (FSP) SFAS No. 115-2 and SFAS No. 124-2,~~~~Recognition and Presentation~~closing of ~~Other-Than-Temporary Impairments~~,the transaction with EDF, we entered into a power purchase agreement (PPA) with CENG with a fair value of $0.8 billion under which ~~amends~~we will purchase between 85-90% of the ~~other-than-temporary guidance for debt securities and expands the disclosure requirements for debt and equity securities. The available-for-sale investments in our~~output of CENG's nuclear ~~decommissioning trust funds are managed by~~plants that is not sold to third parties ~~who have independent discretion~~under pre-existing PPAs over the ~~purchases~~five year term of the PPA.

In addition to the PPA, we entered into a power services agency agreement (PSA) and ~~sales~~an administrative service agreement (ASA). The PSA is a five-year agreement under which we will provide scheduling, asset management and billing services to CENG and recognize average annual revenue of ~~securities. As such,~~approximately $16 million. The ASA is a one year agreement that is renewable annually under which we will provide administrative support services to CENG for a fee of approximately $66 million for 2010. The fees for administrative support services will be subject to change in future years based on the ~~amended guidance for other-than-temporary impairments will not affect our policy~~level of ~~recognizing impairments for any~~services provided. The charges under this agreement are intended to represent the actual cost of the services provided to CENG from us.

The impact of transactions under these investments for which fair value declines below its book value. The FSP also requires disclosures regarding available-for-sale securities in interim financial statements as well as in annual financial statements. We adopted FSP SFAS No. 115-2 and SFAS No. 124-2 as of April 1, 2009 and provide the additional disclosures regarding available for sale securities beginning on page 17.agreements is summarized below:

~~In April 2009, the FASB issued FSP SFAS No. 107-1 and APB No. 28-1,~~~~Interim Disclosures about Fair Value of Financial Instruments~~, which amends SFAS No. 107 to require disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements. We adopted FSP SFAS No. 107-1 and APB No. 28-1 as of April 1, 2009 with no effect on our, or BGE's financial results. We provide the disclosures regarding fair value of financial instruments on page 40.

~~In February 2008, the FASB issued FSP SFAS No. 157-2,~~~~Effective Date of FASB Statement No. 157~~. FSP SFAS No. 157-2 delayed the effective date of SFAS No. 157 for many nonfinancial assets and liabilities, including asset retirement obligations, long-lived assets, and goodwill, to fiscal years beginning after November 15, 2008. Prospectively, we will disclose subsequent measurements of nonfinancial assets and liabilities at fair value as part of our SFAS No. 157 footnote. We adopted FSP SFAS No. 157-2 on January 1, 2009 with no effect on our, or BGE's, financial results. See page 36 for our disclosures about fair value measurements.

~~In April 2009, the FASB issued FSP SFAS No. 157-4,~~~~Determining Fair Value When the Volume and Level of Activity for the Asset or Liability have Significantly Decreased and Identifying Transactions That Are Not Orderly~~, which provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have decreased. The FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly. Finally, the FSP expands the disclosure requirements for fair value measurements to include further disaggregation in the tabular disclosures. We adopted FSP SFAS No. 157-4 as of April 1, 2009 with no effect on our, or BGE's, financial results. See page 36 for our disclosures about fair value measurements.

~~In September 2008, the FASB ratified EITF No. 08-5,~~~~Third Party Credit Enhancements~~. EITF No. 08-5 clarifies that an entity shall not include the effects of a third party credit enhancement in the fair value measurement of a liability. We adopted EITF No. 08-5 on January 1, 2009 and recorded a reduction in our derivative liability of approximately $4 million.

BGE is obligated to provide market-based standard offer service to all of its electric customers for varying periods. Bidding to supply BGE's market-based standard offer service to electric customers will occur from time to time through a competitive bidding process approved by the Maryland PSC.

�� Our ~~merchant energy~~NewEnergy business will supply a portion of BGE's market-based standard offer service obligation to electric customers through September 30, ~~2011.~~2012.

The cost of BGE's purchased energy from nonregulated subsidiaries of Constellation Energy to meet its standard offer service obligation was ~~as follows:~~$124.0 million for the quarter ended March 31, 2010 compared to $204.3 million for the same period in 2009.

In addition, Constellation Energy charges BGE for the costs of certain corporate functions. Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. We believe this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. Under the Maryland PSC's October 30, 2009 order approving the transaction with EDF, we are limited to allocating no more than 31% of these costs to BGE. These costs were approximately $36.2 million for the quarter ended March 31, 2010 compared to $29.6 million for the quarter ended March 31, 2009. Other nonregulated affiliates of BGE also charge BGE for the costs of certain services provided.

~~The following table presents the costs Constellation Energy charged to BGE in each period.~~

Throughout 2009, BGE ~~participates~~participated in a cash pool under a Master Demand Note agreement with Constellation Energy. Under this arrangement, participating subsidiaries may invest in or borrow from the pool at market interest rates. Constellation Energy administers the pool and invests excess cash in short-term investments or issues commercial paper to manage consolidated cash requirements. Under this arrangement, BGE had invested ~~$154.0 million at June 30, 2009 and had invested $148.8~~$314.7 million at December 31, ~~2008.~~2009.

As part of the ring-fencing measures required by the Maryland PSC in its order approving the transaction with EDF, BGE ceased participation in the cash pool on January 7, 2010.

BGE's Consolidated Balance Sheets include intercompany amounts related to BGE's purchases to meet its standard offer service obligation, ~~BGE's gas purchases,~~ BGE's charges to Constellation Energy and its nonregulated affiliates for certain services it provides them, Constellation Energy and its nonregulated affiliates' charges to BGE, ~~for certain services provided to BGE,~~ and the participation of BGE's employees in the Constellation Energy defined benefit plans.

~~We believe our allocation methods are reasonable and approximate the costs that would be charged to unaffiliated entities.~~

Management's Discussion and Analysis of Financial Condition and Results of Operations

Constellation Energy Group, Inc. (Constellation Energy) is an energy company that conducts its business through various subsidiaries including ~~a merchant energy business~~nonregulated businesses and Baltimore Gas and Electric Company (BGE). We describe our operating segments in theNotes to Consolidated Financial Statements ~~beginning~~ on page ~~18.~~14.

This Quarterly Report on Form 10-Q is a combined report of Constellation Energy and BGE. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "regulated business(es)" are to BGE. We discuss our business and strategy in more detail inItem 1—Business section of our ~~2008~~2009 Annual Report on Form 10-K and we discuss the risks affecting our business inItem 1A. Risk Factors section of our ~~2008~~2009 Annual Report on Form 10-K.

Our ~~2008~~2009 Annual Report on Form 10-K includes a detailed discussion of various items impacting our business, our results of operations, and our financial condition. These include:

Critical accounting policies are the accounting policies that are most important to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective, or complex judgment. Our critical accounting policies include derivative accounting and the evaluation of assets for impairment and other than temporary decline in ~~value, and asset retirement obligations.~~value.

In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy and BGE including:

As you read this discussion and analysis, refer to our Consolidated Statements of Income (Loss) on page 3, which present the results of our operations for the quarters ended March 31, 2010 and ~~six months ended June 30, 2009 and 2008.~~2009. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income (Loss).

Various factors affect our financial results. We discuss these various factors in theForward Looking Statements section on page 7563 and inItem 1A. Risk Factors section of our ~~2008~~2009 Annual Report on Form 10-K. We discuss our market risks in theRisk Management section beginning on page ~~70.~~57.

The volatility of the financial, credit and global energy markets impacts our liquidity and collateral requirements as well as our credit risk. We discuss our liquidity and collateral requirements in theFinancial Condition section and our customer (counterparty) credit and other risks in more detail in theRisk Management section.

In this section, we discuss in more detail events which have impacted our business during ~~2009.~~

The United States Congress and the Commodity Futures Trading Commission are evaluating additional regulations for the derivatives markets, including position limits and eliminating hedge regulatory exemptions. We are unable to determine the final form any regulations may take, but such regulations could have a material effect on our business.2010.

In June 2009, the Maryland Public Service Commission (Maryland PSC) determined that EDF Group and related entities (EDF) would obtain the power to exercise substantial influence over the policies and actions of BGE under Constellation Energy's proposed transaction with EDF, and, therefore, that the Maryland PSC must review the transaction to determine that it is in the public interest with benefits and no harm to consumers. EDF has filed an application with the Maryland PSC to commence the Maryland PSC's review and a decision is expected in mid-October 2009. In addition, Constellation Energy, BGE and EDF filed suit in the Baltimore City Circuit Court appealing the Maryland PSC's decision, which was dismissed by the court. Constellation Energy and BGE have appealed the court's decision.

We cannot predict the outcome of the Maryland PSC or court proceedings. A delay in obtaining the required review or the imposition of unfavorable terms or conditions in connection with such review could affect our ability to complete the transaction with EDF and could have a negative impact on our credit ratings and financial results.

~~As discussed~~In January 2010, the U.S. Environmental Protection Agency (EPA) proposed rules to adopt NAAQs for ozone that are stricter than the NAAQs adopted in March 2008, based on the EPA's reevaluation of scientific evidence about ozone and ozone's effects on humans and the environment. We are unable to determine the impact that complying with the stricter NAAQS for ozone will have on our ~~2008 Annual Report~~financial results until the states in which our generating facilities are located adopt plans to meet the new standards. However, costs associated with compliance with these plans could be material.

In March 2010, the New York Department of Environmental Conservation issued a draft policy designating closed-cycle cooling as the best technology available for cooling water intake structures for minimizing adverse environmental impacts. At this time we cannot predict whether this policy will be adopted. However, if the policy is adopted and CENG is required to retrofit its two nuclear generating facilities in New York to implement this technology, our share of the compliance costs could be material.

In May 2010, the EPA proposed rules to regulate coal combustion by-products, such as fly ash, either as a special hazardous waste or as a nonhazardous waste. Depending on ~~Form 10-K, we expect~~the scope of any final rules that are adopted, additional federal regulation has the potential to ~~incur~~result in additional ~~environmental capital expenditures to comply with air quality laws~~compliance requirements and ~~regulations. Based on updated information from vendors, we expect our estimated environmental capital requirements for these air quality projects to~~costs that could be ~~approximately $325 million in 2009, $25 million in 2010, $5 million in 2011 and $30 million from 2012-2013.~~

Our estimates may change further as we implement our compliance plan. As discussed in our 2008 Annual Report on Form 10-K, our estimates of capital expenditures continue to be subject to significant uncertainties.material.

We discuss recently ~~issued and~~ adopted accounting standards in theAccounting Standards ~~Issued~~ ~~and~~~~Accounting Standards~~ Adopted ~~sections~~section of theNotes to Consolidated Financial Statements ~~beginning~~ on page ~~40.~~36.

In ~~January 2009, we entered into a definitive agreement to sell a majority of our international commodities operation. We completed this transaction in March 2009.~~

~~In February 2009, we entered into a definitive agreement to sell our gas trading operation. We transferred control of this operation in~~ April 2009. Simultaneously, we entered into an agreement with the buyer of our Houston-based gas trading operation under which that company will provide us with the gas supply needed to support our retail gas customer supply business.

~~In June 2009,~~2010, we completed the ~~sale~~acquisition of ~~a uranium market participant that provides marketing services~~the Criterion wind project in Garrett County, Maryland.

In April 2010, we signed an agreement to ~~uranium producers, utilities~~purchase the 550 MW Colorado Bend Energy Center and ~~an investment fund~~the 550 MW Quail Run Energy Center natural gas combined cycle generation facilities in ~~the North American and European markets.~~Texas for $365 million, subject to closing adjustments.

We discuss these ~~divestitures and the gas supply agreement~~transactions in more detail on page 13 in ~~the~~Notes to Consolidated Financial ~~Statements~~Statements. ~~beginning on page 15.~~

~~During~~In January 2010, BGE completed the ~~quarter and six months ended June 30, 2009, we incurred merger termination and strategic alternatives costs related~~sale of its interest in a nonregulated subsidiary that owns a district chilled water facility to ~~the terminated merger with MidAmerican Energy Holdings Company (MidAmerican), the conversion of our Series A Preferred Stock, the transactions related to EDF, and other strategic alternatives costs.~~a third party. We discuss ~~costs related to the mergers and strategic alternatives~~this transaction in more detail on page 1113 inNotes to Consolidated Financial Statements.

In February 2010, we retired certain of our 7.00% Notes due April 1, 2012 as part of a cash tender offer launched in January 2010 and in March 2010 we repurchased certain tax exempt notes. We discuss these transactions in more detail on page 17 inNotes to Consolidated Financial Statements.

~~During~~In March 2010, the Patient Protection and Affordable Care Act and the Healthcare and Education Reconciliation Act of 2010 (Reconciliation Act) were signed into law. We discuss the impact of these new laws on our earnings for the quarter ~~and six months~~ ended ~~June 30, 2009, we recorded impairment losses and other costs on certain of our equity method investments, investments in equity securities and other assets. We discuss these charges~~March 31, 2010 in more detail on page 16 in ~~the~~Notes to Consolidated Financial Statements ~~beginning on page 13.~~

During the six months ended June 30, 2009, we incurred workforce reduction costs primarily related to the divestiture of a majority of our international commodities operation as well as some smaller restructurings elsewhere in our organization. We recognized an $11.2 million pre-tax charge in 2009 related to the elimination of approximately 180 positions. We expect all of these restructurings will be completed within the next 12 months. We discuss our workforce reduction costs in more detail in the~~Notes to Consolidated Financial Statements~~ ~~beginning on page 14.~~.

Results of Operations for the Quarter ~~and Six Months~~ Ended ~~June 30, 2009~~
March 31, 2010 Compared with the Same ~~Periods~~Period of ~~2008~~2009

In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments. Significant changes in other (expense) income, ~~and expense,~~ fixed charges, and income taxes are discussed, as necessary, in the aggregate for all segments in theConsolidated Nonoperating Income and Expenses section on page ~~61.~~51.

~~1 Amounts~~Our total net income attributable to common stock for ~~the quarter ended June 30, 2009 include income tax adjustments relating to activity during~~ the quarter ended March 31, 2010 was favorable compared to the net loss attributable to common stock for the same period of 2009 ~~based on updated estimates~~by $315.0 million, or $1.57 per share, primarily due to the following:

1 The net impact to the Company of the power purchase agreement with CENG was $42.1 million pre-tax for the quarter ended March 31, 2010. This amount represents the amortization of our ~~2009 annual effective tax rate.~~$0.8 billion "Unamortized energy contract asset" less our 50.01% equity in CENG's amortization of its $0.8 billion "Unamortized energy contract liability."

2 These amounts include the ~~net losses~~loss on ~~the sales~~sale of the international commodities operation, ~~gas~~the reclassification of losses on previously designated cash-flow hedges from Accumulated Other Comprehensive Loss because the forecasted transactions are probable of not occurring, and earnings that are no longer part of our core business. The impairment losses and other costs and workforce reduction costs line items also include amounts related to the operations we divested.

In the following sections, we discuss our net loss by business segment in greater detail.

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 1915 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

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        Net income attributable to common stock from the regulated electric business ~~for~~decreased $18.3 million during the quarter ended ~~June 30,~~March 31, 2010 compared to the same period in 2009, ~~exceeded the net loss attributable to common stock from the regulated electric business for the quarter ended June 30, 2008 by $123.7 million, mostly~~primarily due to ~~the absence~~a decrease in 2009 of the impact of the accrual of the Maryland settlement credit of $125.3 million after-tax in 2008. This was partially offset by the absence in 2009 of the favorable impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $2.0 million in 2008.
        Net income attributable to common stock from the regulated electric business for the six months ended June 30, 2009 exceeded the net loss attributable to common stock from the regulated electric business for the six months ended June 30, 2008 by $132.9 million, mostly due to increased revenues less electricity purchased for resale expenses of ~~$142.7~~$2.3 million after-tax, ~~due to the absence in 2009~~increased operations and maintenance expenses of ~~the impact of the accrual of the Maryland settlement credit of $125.3 million after-tax in 2008. The increase was partially offset by increased depreciation and amortization of $7.2~~$13.3 million after-tax, and the ~~absence~~additional deferred income tax expense of $3.1 million relating to federal subsidies for providing post-employment prescription drug benefits as a result of new legislation in ~~2009 of the favorable impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $5.0 million in 2008.~~March 2010.
Electric Revenues
The changes in electric revenues ~~in 2009~~during the quarter ended March 31, 2010 compared to ~~2008~~the same period of 2009 were caused by:

Quarter Ended
June 30,
2009 vs. 2008
Six Months Ended
June 30,
2009 vs. 2008

(In millions)

Distribution volumes
$ (3.4 ) $ 0.7
Nuclear decommissioning charges
4.3 9.1
Smart energy savers program surcharges
5.8 11.1
Maryland settlement credit
188.2 188.2
Revenue decoupling
8.3 10.4
Standard offer service
(0.2 ) 69.3
Rate stabilization recovery
0.4 2.3
Financing credits
0.1 1.1
Senate Bill 1 credits
2.2 7.4

Total change in electric revenues from electric system sales
205.7 299.6
Other
1.3 4.8

Total change in electric revenues
$ 207.0 $ 304.4

Quarter Ended
March 31,
2010 vs. 2009

(In millions)

Distribution volumes
$ (1.1 )
Smart Energy Savers Program^SM surcharges
(1.3 )
Standard offer service
(52.4 )
Rate stabilization recovery
(1.2 )

Total change in electric revenues from electric system sales
(56.0 )
Other
0.5

Total change in electric revenues
$ (55.5 )

Distribution Volumes
Distribution volumes are the amount of electricity that BGE delivers to customers in its service territory.
        The percentage changes in our electric distribution volumes, by type of customer, ~~in 2009 compared to 2008 were:~~

Quarter Ended
June 30,
2009 vs. 2008
Six Months Ended
June 30,
2009 vs. 2008

Residential
(4.8 )% (3.1 )%
Commercial
1.3 3.2
Industrial
(5.7 ) (8.0 )
        ~~During~~during the quarter ended ~~June 30, 2009~~March 31, 2010 compared to the same period of 2009 were:

Quarter Ended
March 31,
2009 vs. 2008
Residential
0.6 %
Commercial
0.9
Industrial
(1.7 )
        During the quarter ended March 31, 2010, we distributed less electricity to residential customers mostly due to milder weather and decreased usage per customer, partially offset by an increased number of customers. We distributed more electricity to commercial customers due to increased usage per customer and an increased number of customers. We distributed less electricity to industrial ~~customers primarily~~

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~~due to decreased usage per customer and a decreased number of customers.~~
        ~~During the six months ended June 30, 2009 compared to the same period of 2008, we distributed less electricity to residential~~ customers mostly due to decreased usage per customer, partially offset by colder weather and an increased number of customers. We distributed more electricity to commercial customers due to increased usage per customer and an increased number of customers. We distributed less electricity to industrial customers primarily due to decreased usage per customer and a decreased number of customers.
~~Nuclear Decommissioning Charges~~
Effective January 1, 2009, BGE and Calvert Cliffs Nuclear Power Plant Inc. (Calvert Cliffs) mutually agreed to terminate the decommissioning funds collection agent agreement, which was effective from July 1, 2000 to December 31, 2008. As a result, BGE ceased transferring funds to provide for the decommissioning of Calvert Cliffs Unit 1 and Unit 2. Calvert Cliffs retains the obligation to provide adequate assurances of funding pursuant to Nuclear Regulatory Commission requirements. Under the 2008 Maryland settlement agreement, BGE will continue to provide certain credits to residential customers and assess certain charges to all customers relating to decommissioning.customer.
Smart Energy Savers Program ~~Surcharges~~^SM Surcharges
Beginning in 2009, the Maryland PSC approved customer surcharges through which BGE recovers costs associated with certain programs designed to help BGE manage peak demand and encourage customer energy conservation.
~~Maryland Settlement Credit~~
In 2008, BGE entered into a settlement agreement with the State of Maryland and other parties, which provided residential electric customers a credit totaling $170 per customer. The total settlement of $188.2 million was accrued in the second quarter of 2008 and was paid in the third quarter of 2008.
~~Revenue Decoupling~~
Beginning in 2008, the Maryland PSC allows us to record a monthly adjustment to our electric distribution revenues from residential and small commercial customers to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes. Beginning in February 2009, the Maryland PSC allows us to record a monthly adjustment to our electric distribution revenues from the majority of our large commercial and industrial customers to eliminate the effect of abnormal weather and usage patterns per customer on our electric distribution volumes. This means our monthly electric distribution revenues for these customers are based on weather and usage that is considered "normal" for the month. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions.
Standard Offer Service
BGE provides standard offer service for customers that do not select an alternative supplier. We discuss the provisions of Maryland's Senate Bill 1 related to residential electric rates in ~~the~~Item 7. Management's Discussion and Analysis—Business Environment—Regulation—Maryland—Senate Bills 1

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and 400 section of our ~~2008~~2009 Annual Report on Form 10-K.
        Standard offer service revenues ~~increased~~decreased during the ~~six months~~quarter ended ~~June 30, 2009~~March 31, 2010 compared to the same period of ~~2008,~~2009 mostly due to ~~an increase~~a decrease in the standard offer service rates ~~partially offset by~~and lower standard offer service volumes.
Rate Stabilization Recovery
In late June 2007, BGE began recovering amounts deferred during the first rate deferral period that ended on May 31, 2007. The recovery of the first rate stabilization plan will occur over approximately ten years. In April 2008, BGE began recovering amounts deferred during the second rate deferral period that ended on December 31, 2007. The recovery of the second rate deferral ~~will occur~~occurred over a 21-month period that began April 1, 2008 and ~~ends~~ended on December 31, 2009. ~~The recovery of the first rate stabilization plan will occur over approximately ten years.~~
~~Financing Credits~~
Concurrent with the recovery of the deferred amounts related to the first rate deferral period, we are providing credits to residential customers to compensate them primarily for income tax benefits associated with the financing of the deferred amounts with rate stabilization bonds.
~~Senate Bill 1 Credits~~
As a result of Senate Bill 1, beginning January 1, 2007, we were required to provide to residential electric customers a credit equal to the amount collected from all BGE electric customers for the decommissioning of Calvert Cliffs and to suspend collection of the residential return component of the administrative charge collected through residential standard offer service rates through May 31, 2007. Under an order issued by the Maryland PSC in May 2007, as of June 1, 2007, we were required to reinstate collection of the residential return component of the administration charge in rates and to provide all residential electric customers a credit for the residential return component of

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the administrative charge. Under the 2008 Maryland settlement agreement, BGE was allowed to resume collection of the residential return portion of the administrative charge from June 1, 2008 through May 31, 2010 without having to rebate it to residential customers.
        The increase in revenues during the quarter and six months ended June 30, 2009 compared to the same period in 2008 is primarily due to the absence of the credit for the residential return component of the administrative charge which was suspended under the Maryland settlement agreement, partially offset by lower distribution volumes.
Electricity Purchased for Resale Expenses
Electricity purchased for resale expenses include the cost of electricity purchased for resale to our standard offer service customers. These costs do not include the cost of electricity purchased by delivery service only customers. The following table summarizes our regulated electricity purchased for resale expenses:

Quarter Ended
June 30,
Six Months Ended
June 30,

2009
2008
2009
2008

(In millions)

Actual costs
$ 392.0 $ 393.1 $ 901.4 $ 834.3
Recovery under rate stabilization plans
10.5 11.2 26.3 25.3

Electricity purchased for resale expenses
$ 402.5 $ 404.3 $ 927.7 $ 859.6

Quarter Ended
March 31,

2010
2009

(In millions)

Actual costs
$ 458.1 $ 509.4
Recovery under rate stabilization plan
15.5 15.8

Electricity purchased for resale expenses
$ 473.6 $ 525.2

Actual Costs
BGE's actual costs for electricity purchased for resale ~~increased $67.1~~decreased $51.3 million during the ~~six months~~quarter ended ~~June 30, 2009~~March 31, 2010 compared to the same period of ~~2008,~~2009 primarily due to ~~higher~~lower contract prices to purchase electricity for our customers ~~partially offset by~~and lower volumes.
Recovery ~~Under~~under Rate Stabilization Plan
In late June 2007, we began recovering previously deferred amounts from customers. ~~During~~We recovered $15.5 million during the quarter ~~and six months~~ ended ~~June 30, 2009, $9.7 million and $24.3 million, respectively, of the amount recovered secures~~March 31, 2010 in deferred electricity purchased for resale expenses. These collections secure the payment of principal and interest and other ongoing costs associated with rate stabilization bonds issued by a subsidiary of BGE in June 2007.
Electric Operations and Maintenance Expenses
Regulated electric operations and maintenance expenses increased ~~$5.7~~$22.7 million in the quarter ended ~~June 30, 2009~~March 31, 2010 compared to the same period in ~~2008,~~2009 primarily due to increased uncollectible accounts receivable expense of $13.0 million, partially offset by the absence of $5.3 million of incremental distribution service restoration expenses associated with 2008 storms and $2.9 million of lower labor and benefit costs.
        Regulated electric operations and maintenance expenses increased $2.1 million in the six months ended June 30, 2009 compared to the same period in 2008, primarily due to increased uncollectible accounts receivable expense of $16.7 million, partially offset by the absence of $6.9$17.3 million in incremental distribution service restoration expenses associated with ~~2008~~2010 storms and ~~$7.2 million of lower labor and benefit costs.~~
        ~~We discuss the Allowance for Uncollectible Accounts Receivable in more detail beginning on page 61.~~
~~Electric Depreciation and Amortization~~
Regulated electric depreciation and amortization expense increased $7.2 million during the quarter ended June 30, 2009, compared to the same period in 2008, primarily due to $9.8 million in increased amortization expense associated with the Smart Energy Savers Program^SM and additional property placed in service in 2009, partially offset by $3.8 million in lower depreciation expense as a result of revised depreciation rates which were implemented on June 1, 2008 for regulatory and financial reporting purposes as part of the Maryland settlement agreement.
        Regulated electric depreciation and amortization expense increased $11.9 million during the six months ended June 30, 2009, compared to the same period in 2008, primarily due to $17.7 million in increased amortization expense associated with the smart energy savers programs and additional property placed in service in 2009, partially offset by $9.5 million in lower depreciation expense as a result of revised depreciation rates which were implemented on June 1, 2008 for regulatory and financial reporting purposes as part of the Maryland settlement agreement.
        ~~The Maryland settlement agreement is discussed in more detail in~~~~Note 2 to Consolidated Financial Statements~~ ~~of our 2008 Annual Report on Form 10-K.~~
~~Taxes Other Than Income Taxes~~
Taxes other than income taxes increased $4.4 million and $5.5 million during the quarter and six months ended June 30, 2009, respectively, compared to the same periods in 2008, primarily due to the absence of the impact of ~~the Maryland settlement agreement~~inflation on ~~franchise taxes.~~

~~Table~~other costs of ~~Contents~~$2.9 million.
Regulated Gas Business
Our regulated gas business is discussed in detail inItem 1. Business—Gas Business section of our ~~2008~~2009 Annual Report on Form 10-K.
Results

Quarter Ended
June 30,
Six Months Ended
June 30,

�� 2009
2008
2009
2008

(In millions)

Revenues
$ 111.7 $ 188.1 $ 498.6 $ 584.5
Gas purchased for resale expenses
(51.6 ) (127.7 ) (309.7 ) (397.7 )
Operations and maintenance expenses
(45.0 ) (38.6 ) (80.9 ) (77.5 )
Depreciation and amortization
(10.7 ) (11.2 ) (22.1 ) (23.1 )
Taxes other than income taxes
(8.5 ) (8.4 ) (18.9 ) (18.8 )

(Loss) Income from operations
$ (4.1 ) $ 2.2 $ 67.0 $ 67.4

Net (Loss) Income
$ (6.2 ) $ (2.3 ) $ 33.4 $ 37.9

Net (Loss) Income attributable to common stock
$ (6.9 ) $ (3.1 ) $ 31.9 $ 36.3

Other Items Included in Operations (after-tax):

Effective tax rate impact of Maryland settlement agreement
$ — $ 0.1 $ — $ 3.7

Quarter Ended
March 31,

2010
2009

(In millions)

Revenues
$ 318.0 $ 386.9
Gas purchased for resale expenses
(194.5 ) (258.1 )
Operations and maintenance expenses
(35.2 ) (35.9 )
Depreciation and amortization
(11.3 ) (11.4 )
Taxes other than income taxes
(10.4 ) (10.4 )

Income from operations
$ 66.6 $ 71.1

Net Income
$ 37.2 $ 39.6

Net Income attributable to common stock
$ 36.5 $ 38.8

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 1915 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.

        ~~Net loss attributable to common stock from the regulated gas business increased $3.8 million during the quarter ended June 30, 2009, compared to the same period~~Table of 2008, primarily due to increased operations and maintenance expenses of $3.9 million after-tax, which consisted primarily of $3.0 million after-tax of increased uncollectible accounts receivable expense.Contents
        Net income attributable to common stock from the regulated gas business decreased $4.4 million during the six months ended June 30, 2009, compared to the same period of 2008, primarily due to the absence in 2009 of the impact of reduced earnings from the Maryland settlement agreement on our effective tax rate of $3.7 million.
Gas Revenues
The changes in gas revenues ~~in 2009~~during the quarter ended March 31, 2010 compared to ~~2008~~the same period of 2009 were caused by:

Quarter Ended
June 30,
2009 vs. 2008
Six Months Ended
June 30,
2009 vs. 2008

(In millions)

Distribution volumes
$ (0.9 ) $ 5.4
Conservation surcharge
0.2 0.7
Gas revenue decoupling
0.9 (5.1 )
Gas cost adjustments
(46.8 ) (31.9 )

Total change in gas revenues from gas system sales
(46.6 ) (30.9 )
Off-system sales
(29.3 ) (53.8 )
Other
(0.5 ) (1.2 )

Total change in gas revenues
$ (76.4 ) $ (85.9 )

Quarter Ended
March 31,
2010 vs. 2009

(In millions)

Distribution volumes
$ (2.7 )
Conservation surcharge
(0.5 )
Gas revenue decoupling
2.7
Gas cost adjustments
(73.9 )

Total change in gas revenues from gas system sales
(74.4 )
Off-system sales
4.2
Other
1.3

Total change in gas revenues
$ (68.9 )

Distribution Volumes
The percentage changes in our distribution volumes, by type of customer, ~~in 2009~~during the quarter ended March 31, 2010 compared to ~~2008~~the same period of 2009 were:

Quarter Ended
June 30,
2009 vs. 2008
Six Months Ended
June 30,
2009 vs. 2008

Residential
2.2 % 6.7 %
Commercial
(22.3 ) (5.8 )
Industrial
13.2 6.8

Quarter Ended
March 31,
2010 vs. 2009
Residential
(1.5 )%
Commercial
(10.3 )
Industrial
17.9
        During the quarter ended ~~June 30, 2009~~March 31, 2010, we distributed less gas to residential customers compared to the same period ~~in 2008, we distributed more gas~~of 2009 mostly due to ~~residential customers, due to~~milder weather, partially offset by increased usage per customer and an increased number of ~~customers, partially offset by milder weather.~~customers. We distributed less gas to commercial customers ~~compared to the same period of 2008,~~ mostly due to decreased usage per customer and milder weather, partially offset by an increased number of customers. We distributed more gas to industrial customers mostly due to increased usage ~~by customers, partially offset by a decreased number of customers.~~
        During the six months ended June 30, 2009 compared to the same period in 2008, we distributed more gas to residential customers due to colder weather and an increased number of customers, partially offset by decreased usage per customer. ~~We distributed less gas to commercial customers due to decreased usage per customer, partially~~

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offset by an increased number of customers and colder weather. We distributed more gas to industrial customers mostly due to increased usage per customer, partially offset by a decreased number of customers.
Conservation Surcharge
Beginning February 2009, the Maryland PSC approved a customer surcharge through which BGE recovers costs associated with certain programs designed to help BGE encourage customer conservation.
Gas Revenue Decoupling
The Maryland PSC allows us to record a monthly adjustment to our gas distribution revenues to eliminate the effect of abnormal weather and usage patterns per customer on our gas distribution ~~volumes.~~volumes, thereby recovering a specified dollar amount of distribution revenues per customer, by customer class, regardless of changes in consumption levels. This means ~~our monthly gas~~BGE recognizes revenues at Maryland PSC-approved levels per customer, regardless of what actual distribution ~~revenues are based on weather and usage that is considered "normal"~~volumes were for ~~the month.~~a billing period. Therefore, while these revenues are affected by customer growth, they will not be affected by actual weather or usage conditions. We then bill or credit impacted customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.
Gas Cost Adjustments
We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC as described inNote 1 of our ~~2008~~2009 Annual Report on Form 10-K. However, under the market-based rates mechanism approved by the Maryland PSC, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers.
        Customers who do not purchase gas from BGE are not subject to the gas cost adjustment clauses because we are not selling gas to them. However, these customers are charged base rates to recover the costs BGE incurs to deliver their gas through our distribution system, and the rates charged are included in the gas distribution volume revenues.
        Gas cost adjustment revenues decreased ~~$46.8 million and $31.9~~$73.9 million during the quarter ~~and six months~~ ended ~~June 30, 2009, respectively,~~March 31, 2010 compared to the same period of ~~2008,~~2009 because we sold less gas at lower ~~prices.~~rates.
Off-System ~~Gas~~ Sales
Off-system ~~gas~~ sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas cost adjustments. The Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Changes in off-system sales do not significantly impact earnings.
        Revenues from off-system gas sales ~~decreased~~increased $4.2 million during the quarter ~~and six months~~ ended ~~June 30, 2009~~March 31, 2010 compared to the same period of ~~2008 because we sold less gas at~~2009 primarily due to higher prices, partially offset by lower ~~prices.~~volumes.
Gas Purchased For Resale Expenses
Gas purchased for resale expenses include the cost of gas purchased for resale to our customers and for off-system

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sales. These costs do not include the cost of gas purchased by delivery service only customers.
        Gas costs decreased ~~$76.1~~$63.6 million during the quarter ended ~~June 30, 2009~~March 31, 2010 compared to the same period of ~~2008~~2009 because we purchased less gas at lower prices.
        ~~Gas costs decreased $88.0 million during the six months ended June 30, 2009 compared to the same period of 2008 because we purchased gas at lower prices, partially offset by higher volumes.~~
~~Gas Operations and Maintenance Expenses~~
Regulated gas operation and maintenance expenses increased $6.4 million in the quarter ended June 30, 2009 compared to the same period in 2008, primarily due to increased uncollectible accounts receivable expense of $5.0 million.
        Regulated gas operation and maintenance expenses increased $3.4 million during the six months ended June 30, 2009 compared to the same period in 2008, primarily due to increased uncollectible accounts receivable expense of $6.5 million, partially offset by $2.9 million in lower labor and benefit costs.

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Other Nonregulated Businesses
Results

Quarter Ended
June 30,
Six Months Ended
June 30,

2009
2008
2009
2008

(In millions)

Revenues
$ 51.6 $ 66.1 $ 108.9 $ 125.3
Operating expense
(41.3 ) (53.6 ) (83.6 ) (99.0 )
Impairment losses and other costs
(6.7 ) — (6.7 ) —
Depreciation and amortization
(18.2 ) (14.8 ) (36.3 ) (29.3 )
Taxes other than income taxes
(1.2 ) (0.6 ) (2.0 ) (1.1 )

(Loss) Income from Operations
$ (15.8 ) $ (2.9 ) $ (19.7 ) $ (4.1 )

Net (Loss) Income
$ (8.5 ) $ (1.0 ) $ (10.5 ) $ (0.7 )

Net (Loss) Income attributable to common stock
$ (8.6 ) $ (0.9 ) $ (10.6 ) $ (0.5 )

Other Items Included in Operations (after-tax):

Impairment losses and other costs
$ (3.2 ) $ — $ (3.2 ) $ —

Quarter Ended
March 31,

2010
2009

(In millions)

Revenues
$ — $ 2.5
Operating expenses
15.7 15.2
Depreciation and amortization
(13.9 ) (16.4 )
Taxes other than income taxes
(0.9 ) (0.8 )

Income from Operations
$ 0.9 $ 0.5

Net (Loss) Income
$ (4.3 ) $ 0.1

Net (Loss) Income attributable to common stock
$ (4.3 ) $ 0.1

Other Items Included in Operations (after-tax):

Deferred income tax expense relating to federal subsidies for providing post-employment prescription drug benefits
$ (4.8 ) $ —

Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements. The Information by Operating Segment section within the Notes to Consolidated Financial Statements on page 1915 provides a reconciliation of operating results by segment to our Consolidated Financial Statements.
        Net loss attributable to common stock ~~increased $7.7 million during~~for the quarter ended ~~June 30, 2009 and $10.1 million during the six months ended June 30, 2009 compared~~March 31, 2010 exceeded net income attributable to common stock for the same ~~periods of 2008~~period in 2009 by $4.4 million primarily due to ~~increased losses from UniStar Nuclear Energy, LLC of $3.4~~$4.8 million ~~and $5.3 million, respectively, increased impairment losses and other costs due to a write-off of an uncollectible advance to an affiliate of $3.2 million after-tax and depreciation and amortization~~in deferred income tax expense recorded as a result of ~~increased property additions during 2008.~~healthcare reform legislation enacted in March 2010 that eliminated the tax exempt status of prescription drug subsidies received by companies under Medicare Part D.
Consolidated Nonoperating Income and Expenses
Other (Expense) Income ~~(Expense)~~
InOther expenses decreased $34.0 million during the ~~six months~~quarter ended ~~June 30, 2009, we had other expenses of $15.4 million and, in the six months ended June 30, 2008, we had other income of $58.0 million. The $73.4 million decrease in 2009~~March 31, 2010 compared to ~~2008 is~~the same period of 2009 mostly due to ~~an increase~~the absence in 2010 of other-than-temporary impairment charges related to ~~our~~ nuclear decommissioning trust fund assets of ~~$49.9 million.~~$60.5 million recorded in 2009.
Fixed Charges
~~Our fixed~~Fixed charges increased $12.4 million during the quarter ~~and six months~~ ended June 30, 2009 compared to the same periods of 2008 mostly due to a higher level of interest expense associated with new debt issuances, primarily the Series A and Series B Preferred Stock issuances, in 2008 and higher amortization of debt issuance and credit facility costs.
        Fixed charges at BGE increased during the quarter and six months ended June 30, 2009 compared to the same periods of 2008 mostly due to a higher level of interest expense associated with new debt issuances in 2008 and higher amortization of debt issuance and credit facility costs.
~~Income Taxes~~
~~Income tax expense decreased $322.4 million during the six months ended June 30, 2009~~March 31, 2010 compared to the same period of ~~2008 mostly~~2009 due to lower capitalized interest and allowance for borrowed funds used for construction and a higher level of interest expense.
Income Taxes
In the first quarter of 2010, we had income tax expense of $95.6 million and, in the first quarter of 2009, we had income tax benefits of $242.2 million. The $337.8 million change is primarily due to higher income before income taxes in 2010 compared to a loss before income taxes in ~~2009 compared to income before income taxes in 2008.~~2009. Additionally, a higher effective tax rate in 2009 decreased income tax expense because it produced a higher income tax benefit when applied to the loss before income taxes.
        BGE's income tax expense ~~for~~decreased $9.6 million during the quarter ~~and six months~~ ended ~~June 30,~~March 31, 2010 compared to the same period of 2009 ~~exceeded the income tax benefit for the quarter and six months ended June 30, 2008 by $62.1 million and $82.2 million, respectively,~~ mostly due to ~~higher pre-tax income. In addition, for the quarter and six months ended June 30, 2008, BGE had~~ a ~~lower effective tax rate. BGE projected a reduction~~decrease in ~~its 2008 taxable~~ income ~~as a result of the impact of certain provisions of the 2008 Maryland settlement agreement, which increased the relative impact of the favorable permanent tax adjustments on its effective tax rate.~~
~~Allowance for Uncollectible Accounts Receivable~~
Our allowance for uncollectible accounts receivable increased $19.6 million from $240.6 million at December 31, 2008 to $260.2 million at June 30, 2009, primarily related to our regulated electric and gas businesses, whose allowance for uncollectible accounts receivable increased $17.9 million from December 31, 2008. We discuss the earnings impact to regulated electric and gas businesses on pages 58 and 60.
        The increase in allowance for uncollectible accounts receivable from our regulated electric and gas businesses is primarily driven by a Maryland PSC ruling in the second quarter of 2009, which delayed BGE's ability to terminate service to customers with arrearages and offered thosebefore income taxes.

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~~customers the option to enter into extended payment plans. In addition, the economic downturn continues to cause a decreased ability of customers to pay their utility bills.~~
        If the current economic recession continues on a prolonged basis and the Maryland PSC continues to require BGE to offer extended payment plans, our and BGE's bad debt expense could materially increase in the future despite our efforts to mitigate those risks. We discuss our credit risk in more detail in the~~Risk Management~~ ~~section of our 2008 Annual Report on Form 10-K.~~

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Financial Condition
Cash Flows
The following table summarizes our cash flows for ~~2009~~the quarter ended March 31, 2010 and ~~2008, excluding~~2009.

2010 Segment
Cash Flows
Consolidated
Cash Flows

Quarter Ended
March 31, 2010
Quarter Ended
March 31,

Generation
NewEnergy
Regulated
Eliminations,
Holding
Company and
Other
2010
2009

(In millions)

Operating Activities

Net income (loss)
$ 27.1 $ 104.1 $ 64.4 $ (4.3 ) $ 191.3 $ (119.7 )

Non-cash merger termination and strategic alternatives costs
— — — — — 37.2

Derivative contracts classified as financing activities¹
— 39.1 — — 39.1 296.8

Other non-cash adjustments to net income (loss)
136.2 (97.5 ) 136.6 26.8 202.1 335.5

Changes in working capital

Derivative assets and liabilities, excluding collateral
(2.0 ) (74.2 ) 0.3 — (75.9 ) 67.6

Net collateral and margin
— (110.0 ) 0.9 — (109.1 ) 211.6

Accrued taxes
(1,091.5 ) 374.6 (0.2 ) 2.4 (714.7 ) 88.3

Other changes
(82.9 ) 223.2 (82.6 ) (146.5 ) (88.8 ) 304.1

Defined benefit obligations²
— — — — 5.1 (251.5 )

Other
15.2 (46.8 ) (8.7 ) 27.8 (12.5 ) 19.9

Net cash (used in) provided by operating activities
(997.9 ) 412.5 110.7 (93.8 ) (563.4 ) 989.8

Investing activities

Investments in property, plant and equipment
(77.7 ) (24.5 ) (87.2 ) (1.5 ) (190.9 ) (392.1 )

Change in cash pool³
700.7 (277.8 ) 314.7 (737.6 ) — —

Contributions to nuclear decommissioning trust funds
— — — — — (18.7 )

Proceeds from sale of investments and other assets
— 3.9 — 20.9 24.8 31.4

Contract and portfolio acquisitions
— (3.4 ) — — (3.4 ) (866.3 )

(Increase) decrease in restricted funds
— (42.7 ) (23.8 ) 0.4 (66.1 ) 979.3

Other investments
(0.2 ) 1.8 — (0.1 ) 1.5 (0.9 )

Net cash (used in) provided by investing activities
622.8 (342.7 ) 203.7 (717.9 ) (234.1 ) (267.3 )

Cash flows from operating activities plus cash flows from investing activities
$ (375.1 ) $ 69.8 $ 314.4 $ (811.7 ) (797.5 ) 722.5

Financing Activities²

Net repayment of debt
(625.6 ) (803.4 )

Proceeds from issuance of common stock
11.0 5.8

Debt issuance costs
(4.0 ) (62.7 )

Common stock dividends paid
(46.3 ) (85.7 )

BGE preference stock dividends paid
(3.3 ) (3.3 )

Proceeds from contract and portfolio acquisitions
— 863.8

Derivative contracts classified as financing activities¹
(39.1 ) (296.8 )

Other
2.6 4.3

Net cash used in financing activities
(704.7 ) (378.0 )

Net (decrease) increase in cash and cash equivalents
$ (1,502.2 ) $ 344.5

Certain prior-period amounts have been reclassified to conform with the ~~impact of changes in intercompany balances.~~current period's presentation.

2009 Segment
Cash Flows
Consolidated
Cash Flows

Six Months Ended
June 30, 2009
Six Months Ended
June 30,

Merchant
Regulated
Holding
Company and
Other
2009
2008

(In millions)

Operating Activities

Net (loss) income
$ (181.8 ) $ 100.9 $ (10.5 ) $ (91.4 ) $ 324.4

Non-cash merger termination and strategic alternatives costs
37.2 — — 37.2 —

Derivative contracts classified as financing activities under SFAS No. 149
785.3 — — 785.3 0.5

Other non-cash adjustments to net (loss) income
679.5 212.9 56.2 948.6 369.8

Changes in working capital:

Derivative assets and liabilities, excluding collateral
177.5 (0.1 ) 7.8 185.2 (700.6 )

Net collateral and margin
1,093.3 1.6 — 1,094.9 525.9

Other changes
116.9 138.5 (37.9 ) 217.5 58.6

Defined benefit obligations¹
— — — (263.9 ) (44.8 )

Other
(40.8 ) (20.1 ) 111.9 51.0 6.2

Net cash provided by operating activities
2,667.1 433.7 127.5 2,964.4 540.0

Investing Activities

Investments in property, plant and equipment
(635.5 ) (166.5 ) (7.1 ) (809.1 ) (869.5 )

Asset and business acquisitions, net of cash acquired
— — — — (312.4 )

Contributions to nuclear decommissioning trust funds
(18.7 ) — — (18.7 ) (18.7 )

Proceeds from sale of investments and other assets
49.7 — 31.2 80.9 —

Proceeds from sales of property, plant and equipment
— — — — 217.0

Contract and portfolio acquisitions
(2,153.7 ) — — (2,153.7 ) —

Decrease (increase) in restricted funds²
— 0.6 1,003.8 1,004.4 (196.9 )

Other
(1.7 ) — (0.1 ) (1.8 ) 12.9

Net cash (used in) provided by investing activities
(2,759.9 ) (165.9 ) 1,027.8 (1,898.0 ) (1,167.6 )

Cash flows from operating activities less cash flows from investing activities
$ (92.8 ) $ 267.8 $ 1,155.3 1,066.4 (627.6 )

Financing Activities¹

Net (repayment) issuance of debt
(1,587.1 ) 938.6

Debt issuance costs
(62.8 ) (15.6 )

Proceeds from issuance of common stock
13.6 8.3

Common stock dividends paid
(133.7 ) (165.0 )

BGE preference stock dividends paid
(6.6 ) (6.6 )

Proceeds from contract and portfolio acquisitions
2,243.1 —

Derivative contracts classified as financing activities under SFAS No. 149
(785.3 ) (0.5 )

Other
11.8 3.2

Net cash (used in) provided by financing activities
(307.0 ) 762.4

Net increase in cash and cash equivalents
$ 759.4 $ 134.8

1 All ongoing cash flows from derivative contracts deemed to contain a financing element at inception must be reclassified from operating activities to financing activities.
2 Items are not allocated to the business segments because they are managed for the company as a whole.
2 The decrease in restricted funds at our Holding Company and Other is primarily related to $1.0 billion of restricted cash related to the issuance of Series B Preferred Stock to EDF in December 2008. These funds were held at the holding company and were restricted for payment3 As part of the ~~14% Senior~~ring-fencing measures required by the Maryland PSC in its 2009 order approving the transaction with EDF, BGE ceased participation in the cash pool on January 7, 2010. We discuss this ring-fencing measure in Notes ~~held by MidAmerican. The 14% Senior Notes were repaid in full in January 2009.~~to Consolidated Financial Statements.

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Cash Flows from Operating Activities
~~Cash provided by~~In the first quarter of 2010, cash used in operating activities was ~~$2,964.4 million~~$0.6 billion, primarily driven by $0.8 billion in income tax payments, most of which related to the federal taxes associated with the EDF transaction, which closed in the fourth quarter of 2009.
        In the first quarter of 2009, the company generated $1.0 billion in cash from operating activities, mostly due to:
•
$0.7 billion in working capital including $0.3 billion for materials, supplies, and fuel stocks, $0.2 billion for net collateral and margin, and $0.2 billion for a federal tax refund, and
•
$0.3 billion of derivative contracts deemed to contain a financing element at inception that must be classified as financing activities rather than operating activities related to the divestiture of our Houston-based gas trading business.
Partially offsetting these cash inflows was $0.3 billion of contributions to our defined benefit pension plans.
        The $1.6 billion decrease in operating cash flows for the first quarter of 2010 compared to ~~$540.0 million in 2008. This $2,424.4 million increase in~~the same period of 2009 is primarily due to:
•
$1.0 billion higher income taxes paid,
•
$0.2 billion of lower operating cash flows ~~was~~from our regulated businesses, primarily due to ~~$1,613.7 million~~the residential customer rate credit in the first quarter of ~~net favorable changes in working capital~~2010 and ~~a net increase of $784.8 million as a result of a reclassification of proceeds from~~higher distribution service restoration expenses associated with 2010 storms,
•
$0.3 billion lower derivative ~~contracts~~contract settlements reclassified as financing activities ~~under SFAS No. 149. We discuss the impact on cash flows from financing activities below.~~
        ~~The net favorable changes~~ in ~~working capital of $1,613.7 million included $885.8 million related to net derivative assets~~2010, and liabilities. Changes in derivative assets and liabilities are driven by fluctuations in commodity prices and the realization of contracts at settlement within our merchant energy business. There was also $569.0 million
•
$0.3 billion more in net collateral and margin ~~returned~~posted in ~~2009~~2010 as compared to ~~2008.~~
        ~~We continue to improve our collateral position in 2009. Total net cash collateral posted in~~ 2009 ~~decreased compared to the balance as of December 31, 2008~~ as follows:

(In millions)

Net collateral and margin posted, December 31, 2008
$ (1,445.6 )
Return of collateral held associated with nonderivative contracts
(5.4 )
Net return of collateral posted associated with nonderivative contracts
320.9
Return of initial and variation margin posted on exchange-traded transactions recorded in accounts receivable
407.7
Return of fair value net cash collateral posted (netted against derivative assets / liabilities)*
371.7

Change in net collateral and margin posted
1,094.9

Net collateral and margin posted, June 30, 2009
$ (350.7 )

March 31,

2010
2009

(In millions)

Net collateral and margin held (posted), January 1,
$ 77.2 $ (1,445.6 )
(Return of) additional collateral held associated with nonderivative contracts
(10.2 ) 26.3
Net (additional) return of collateral posted associated with nonderivative contracts
(2.1 ) 128.2
(Additional) return of initial and variation margin posted on exchange-traded transactions recorded in accounts receivable
(42.9 ) 178.7
Additional fair value net cash collateral posted (netted against derivative assets / liabilities)*
(53.9 ) (121.6 )

Change in net collateral and margin (posted) held
(109.1 ) 211.6

Net collateral and margin posted, March 31,
$ (31.9 ) $ (1,234.0 )

* We discuss our netting of fair value collateral with our derivative assets / liabilities in more detail in Note 13 to Consolidated Financial Statements of our ~~2008~~2009 Annual Report on Form 10-K.
        ~~The $1,094.9 million decrease in net collateral and margin posted during 2009 primarily reflects the following:~~
•
~~fewer contracts as a result of reducing the risk in our portfolio,~~
•
collateral returned/reduced as part of the divestiture of a majority of our international commodities operation and gas trading operation as well as the execution of a gas supply agreement with the buyer of the gas trading operation, and
•
~~the termination of in-the-money contracts.~~
        ~~These decreases were offset by changes in commodity prices and the level of our open positions.~~
        We discuss all forms of collateral in terms of their impact on our ~~net available liquidity~~business in the~~Available Sources of Funding~~Collateral section.
        Partially offsetting these decreases in operating cash flows was $0.3 billion of lower contributions to our defined benefit pension plans.
Cash Flows from Investing Activities
Cash used in investing activities for the first quarter of 2010 was ~~$1,898.0 million in 2009~~$0.2 billion, compared to ~~$1,167.6 million in 2008. The $730.4 million increase in cash~~$0.3 billion used in ~~2009 compared to 2008~~the first quarter of 2009. The $0.1 billion decrease from the prior year was ~~primarily~~ due ~~to $2,153.7 million for~~to:
•
$0.9 billion lower outflows associated with contract and portfolio ~~acquisitions. As~~acquisitions as a result of the structure of the ~~divestitures~~divestiture of a majority of our international commodities ~~Houston-based gas trading~~operation in March 2009, and ~~other trading operations, we are required~~
•
$0.2 billion of lower investments in property, plant, and equipment, primarily related to ~~present in-the-money contracts on a gross basis separate from out-of-the-money contracts executed simultaneously. We discuss~~environmental additions at our ~~divestitures~~Brandon Shores coal-fired generating plant that went into service in ~~more detail beginning on page 15~~the fourth quarter of 2009 and the~~Notes~~ absence of nuclear capital spending in 2010 due to ~~Consolidated Financial Statements~~the deconsolidation of CENG in 2009.

Table of Contents~~. There was no such~~
        These decreases were offset by $1.0 billion of lower restricted funds activity in ~~2008.~~
        ~~This increase was partially offset by:~~
•
~~a $1,201.3 million decrease in~~2010. In January 2009, our restricted funds decreased by $1.0 billion, primarily due to the release of restricted funds for the repayment of ~~the~~ $1 billion of 14% Senior Notes to ~~MidAmerican in January 2009, and~~
•
the absence of cash used for acquisitions. $312.4 million was used in the six months ended June 30, 2008 for the acquisition of the Hillabee Energy Center, a partially completed 774 MW gas-fired combined cycle power generation facility in Alabama, the West Valley Power Plant, a 200MW gas-fired peaking plant, and a uranium market participant.
MidAmerican.
Cash Flows from Financing Activities
Cash used in financing activities was ~~$307.0 million~~$0.7 billion in ~~2009~~the first quarter of 2010, compared to cash ~~provided~~used in financing activities of ~~$762.4 million~~$0.4 billion in ~~2008.~~the first quarter of 2009. The $0.3 billion increase in cash used ~~for~~in financing activities ~~of $1,069.4 million~~ was primarily due ~~to:~~to $0.9 billion of lower proceeds from contract and portfolio acquisitions related to the structure of the divestiture of the majority of our international commodities operation in March 2009.
        This increase was partially offset by:
•
$~~1,534.7 million net increase in cash used to repay short-term borrowings and long-term debt primarily due to the repayment of the $1~~0.3 billion ~~14% Senior Notes to MidAmerican in January 2009,~~
•
~~$991.0 million net decrease in cash received from the issuance of long-term debt, and~~

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•
~~$784.8 million in~~lower cash outflows ~~related~~associated with derivative contracts deemed to ~~derivative contracts~~contain a financing element at inception that must be classified as financing ~~activity under SFAS No. 149.~~activities rather than operating activities in the first quarter of 2010 compared to the same period in 2009. These contracts ~~relate~~primarily related to transactions associated with the divestiture of our ~~international commodities operation,~~ Houston-based gas trading ~~operation and certain other trading operations.~~operation. During ~~the six months ended June 30,~~March 2009, we executed transactions at prices that differed from market prices. As a result, for cash flows associated with the out-of-the money derivative transactions executed, we recorded the ongoing cash flows related to these contracts as financing cash ~~flows. We discuss our divestitures~~flows in ~~more detail beginning on page 16~~March 2009, and
•
$0.2 billion lower net debt repayments in the first quarter of ~~the~~~~Notes~~2010 compared to ~~Consolidated Financial Statements.~~
        ~~This increase~~the same period in ~~cash used for financing activities was partially~~2009. In the first quarter of 2009, we repaid $1.0 billion of 14% Senior Notes, offset by ~~$2,243.1 million for contract~~$0.2 billion in short term borrowings on our credit facilities. In the first quarter of 2010, we retired $0.5 billion 7.00% Notes due April 1, 2012 pursuant to a cash tender offer and portfolio acquisitions. As a result of the structure of the divestitures of a majority of our international commodities, Houston-based gas trading and other trading operations, we are required to present out-of-the-money contracts on a gross basis separate from in-the-money contracts executed simultaneously. We discuss our divestitures in more detail beginning on page 15 of the~~Notes to Consolidated Financial Statements.~~ ~~There was no such activity in 2008.~~
repurchased outstanding tax exempt notes totaling $0.1 billion.
Security Ratings
We discuss our security ratings in our ~~2008~~2009 Annual Report on Form 10-K.
        ~~On July 31, 2009, Fitch Ratings downgraded Constellation Energy's senior unsecured debt rating from BBB to BBB- and~~In March 2010, Moody's Investor Service updated BGE's ~~senior unsecured debt rating from A- to BBB+. Fitch Ratings also updated both companies'~~ ratings outlook from ~~Watch Evolving~~Stable to ~~Stable.~~Positive.
Available Sources of Funding
In addition to cash generated from ~~business~~ operations, we rely upon access to capital for our capital expenditure programs and for the liquidity required to operate and support our commercial businesses. Our liquidity requirements are funded by credit facilities and cash. We fund our short-term working capital needs with existing cash and with our credit facilities, many of which support direct cash borrowings and the issuance of commercial paper. We also use our credit facilities to support the issuance of letters of credit, primarily for our ~~merchant energy~~NewEnergy business.
        The primary drivers of our use of liquidity have been our capital expenditure requirements and collateral requirements associated with hedging our generating assets and hedging our ~~Customer Supply~~NewEnergy business in both power and gas. ~~As part of our strategic initiatives,~~In order to reduce these collateral requirements, we have modified the structure of certain transactions, ~~and~~ terminated others, ~~in order to reduce these~~and entered into new contracts that either do not have a collateral ~~requirements.~~requirement or allow the posting of alternative forms of collateral. Significant changes in the prices of commodities, depending on hedging strategies we have employed, could require us to post additional letters of credit, and thereby reduce the overall amount available under our credit facilities or to post additional cash, and thereby reduce our available cash balance. Additional regulation of the derivatives markets, as has been proposed recently, could also require us to post additional cash collateral.
~~Constellation Energy~~
~~At June 30, 2009, we had approximately $5.6 billion in committed~~        We discuss our, and BGE's, credit facilities ~~available as shown below. We have also included~~ in ~~the table below the pro forma effect~~detail beginning on ~~our credit facilities of closing the EDF transactions:~~

Facility Expiration
Facility
Size
Facility Size
Upon Completion
of the EDF
Transactions

(In billions)

July 2012
$ 3.85 $ 2.32
November 2009¹
1.23 —
September 2013
0.35 —
December 2009
0.15 —

Total
$ 5.58 $ 2.32

~~1 Size of facility may be reduced by proceeds received from certain securities offerings or asset sales.~~
        Collectively, these facilities currently support the issuance of letters of credit and/or cash borrowings up to approximately $5.6 billion as of June 30, 2009. At June 30, 2009, we had approximately $2.8 billion in letters of credit issued, and we had no commercial paper outstanding.
        In connection with the Investment Agreement with EDF, EDF has provided us with up to $2 billion pre-tax, or approximately $1.4 billion after-tax, of additional liquidity pursuant to a put arrangement that will allow us to require EDF to purchase certain non-nuclear generation assets. The amount of after-tax proceeds will be impacted by the assets actually sold and the related tax impacts at that time.
        ~~During April 2009, we received regulatory approvals and consents for the majority~~page 16 of the assets covered by the put arrangement. As of July 31, 2009, we have approximately $1.1 billion after-tax of liquidity available under the put arrangement. We expect to receive regulatory approval for an additional asset in the first quarter of 2010, which will increase the net after-tax liquidity from the put arrangement to approximately $1.4 billion. The put arrangement will expire at the earlier of December 31, 2010 or the termination of the Investment Agreement by EDF in the event of a breach of contract by us.

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        Certain credit facilities of Constellation Energy contain a provision requiring Constellation Energy to maintain a ratio of debt to capitalization equal to or less than 65%. At June 30, 2009, the debt to capitalization ratios as defined in the credit agreements were no greater than 51%.
        Our $1.23 billion credit facility requires us to maintain consolidated earnings before interest, taxes, depreciation, and amortization to consolidated interest expense ratio of at least 2.75 when our Standard and Poors (S&P) senior unsecured debt rating is BBB- or lower and our Moody's senior unsecured debt rating is Baa3 or lower. Compliance with the covenant is not required as of July 31, 2009 as S&P's senior unsecured debt rating is above BBB-.
        The terms of the Series B Preferred Stock allow us to issue debt without the consent of the holders of the majority of the Series B Preferred Stock only if, after issuance of such debt, we maintain a ratio of debt to capitalization equal to or less than 65%.
        ~~Under our $3.85 billion and $1.23 billion credit facilities, we will be required to grant a lien on certain generating facilities and pledge our ownership interests in our nuclear business~~Notes to the lenders upon the earlier of (i) the closing of the Investment Agreement with EDF or (ii) the date on which both the Investment Agreement is terminated and our S&P or FitchRatings senior unsecured debt credit rating is below BBB- or our Moody's senior unsecured debt credit rating is below Baa3.
Consolidated Financial Statements~~BGE~~.
BGE currently maintains a $400.0 million five-year revolving credit facility expiring in 2011. BGE can use the facility to issue letters of credit or to issue short-term debt through the issuance of commercial paper or through direct borrowing against the facility. At June 30, 2009, BGE had $0.5 million outstanding on its $400 million credit facility to secure funds in advance of maturing commercial paper and other obligations.
        ~~At June 30, 2009, BGE had $339.9 million in commercial paper outstanding.~~
        The credit agreement of BGE contains a provision requiring BGE to maintain a ratio of debt to capitalization equal to or less than 65%. At June 30, 2009, the debt to capitalization ratio for BGE as defined in this credit agreement was 52%.
        ~~Decreases in Constellation Energy's or BGE's credit ratings would not trigger an early payment on any of our, or BGE's, credit facilities.~~
Net Available Liquidity
~~The following tables provide a summary of our~~Constellation Energy's and BGE's net available liquidity at ~~December~~March 31, ~~2008~~2010 was $4.7 billion and ~~June 30, 2009:~~

As of December 31, 2008

Constellation
Energy
BGE
Total
Consolidated

(In billions)

Credit facilities
$ 6.2 $ 0.4 $ 6.6
Less: Letters of credit issued
(3.6 ) — (3.6 )
Less: Cash drawn on credit facilities
(0.5 ) (0.4 ) (0.9 )

Undrawn facilities
2.1 — 2.1
Less: Commercial paper outstanding
— — —

Net available facilities
2.1 — 2.1
Add: Cash
0.2 — 0.2

Net available liquidity
$ 2.3 $ — $ 2.3

As of June 30, 2009

Constellation
Energy
BGE
Total
Consolidated

(In billions)

Credit facilities
$ 5.6 $ 0.4 $ 6.0
Less: Letters of credit issued
(2.8 ) — (2.8 )
Less: Cash drawn on credit facilities
— — —

Undrawn facilities
2.8 0.4 3.2
Less: Commercial paper outstanding
— (0.3 ) (0.3 )

Net available facilities
2.8 0.1 2.9
Add: Cash
1.0 — 1.0
Add: EDF put arrangement
1.1 — 1.1

Net available liquidity
$ 4.9 $ 0.1 $ 5.0

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        ~~Net available liquidity increased from December 31, 2008 through June 30, 2009 by $2.7~~$0.9 billion, ~~as follows:~~

(In billions)

Decrease in cash drawn on facilities
$ 0.9
Decrease in letters of credit issued
0.8
Increase in cash
0.8
EDF put arrangement
1.1
Decrease in credit facilities
(0.6 )
Increase in commercial paper issued
(0.3 )

Increase in net available liquidity
$ 2.7

        Through our efforts to reduce risk, we have significantly improved our liquidity. Specifically, we executed on our planned divestitures, significantly reduced the activities of our Global Commodities operation, and restructured and terminated existing transactions and amended certain agreements, all of which have led to lower collateral requirements. Through June 30, 2009 we received substantially all of the $1 billion of total net collateral expected to be returned as a result of the successful execution of our divestitures. The change in credit facilities and EDF put arrangement was due to the receipt of required regulatory approvals on the majority of assets covered by the EDF put arrangement, which resulted in the termination of the EDF interim backstop liquidity facility. Finally, cash flows from operating activities funded the repayment of all outstanding cash draws on our credit facilities, and BGE was able to issue $339.9 million of commercial paper, demonstrating an ability to access the capital market in a more traditional manner.
        ~~Our liquidity needs vary as commodity prices change.~~respectively. We regularly evaluate the effects of changing price levels on our liquidity needs by estimating the impacts of volatile power, gas, and coal prices on our price sensitive sources and uses of liquidity. For example, energy contracts settling in the current year may impact our cash flows and changing price levels may impact our collateral requirements. Additionally, we consider the impact of other sources and uses of liquidity, including planned business divestitures, anticipated new business, capital expenditures, operating expenses and credit charges.
        ~~We believe that the actions that we have taken and our current~~discuss net available liquidity will be sufficient to support the ongoing liquidity requirements over the next 12 months. Our liquidity projections include assumptions for commodity price changes, which are subject to significant volatility, and we are exposed to certain operational risks that could have a significant impact on our liquidity. We discuss significant items that could negatively impact our liquidityin more detail in the~~Risk Factors~~Notes to Consolidated Financial Statements ~~section of our 2008 Annual Report~~ on ~~Form 10-K.~~page 17.

Collateral
Constellation Energy's collateral requirements generally arise from the needs of its ~~merchant energy business' need to participate~~NewEnergy business as a result of its participation in certain organized markets, such as Independent System Operators (ISOs) or financial exchanges, as well as from ~~our~~its margining on over-the-counter (OTC) contracts.
        To support wholesale and retail power ~~Customer Supply~~NewEnergy obligations ~~as well as some~~and our limited trading activities, Constellation Energy posts collateral to ISOs. Forward hedging of our Generation and ~~Customer Supply obligations, as well as our Global Commodities trading activities,~~NewEnergy businesses creates the need to transact with exchanges such as New York Mercantile Exchange and Intercontinental Exchange. We post initial margin based on exchange rules, as well as variation margin related to the change in value of the net open position with the exchange. Constellation Energy's initial margin requirements increased during the third quarter of 2008 as a result of changes in exchange rules and decreased during the fourth quarter of 2008 as a result of portfolio risk reduction and downsizing activities.
        During the six months ended June 30, 2009, our initial margin requirements continued to decrease. In March 2009 and April 2009, we closed out our exchange positions related to our international commodities operation and Houston-based gas trading operation, respectively, which reduced our margin posted with each exchange with which we transact. Daily variation margin postings to each exchange depend on price moves in the underlying power, gas and coal exchange traded forward and option contracts.
        In addition to the collateral posted to ISOs and exchanges, we post collateral with certain OTC

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counterparties. These collateral amounts may be fixed or may vary with price levels.
        There are certain inherent asymmetries relating to the use of collateral that create liquidity requirements for our ~~merchant energy~~Generation and NewEnergy businesses. These asymmetries arise ~~as a result of~~from our actions to be economically hedged, as well as market conditions or conventions for conducting business that result in some transactions being collateralized while others are not, including:
•
In our ~~Customer Supply operation,~~NewEnergy business, we generally do not receive collateral under contractual obligations to supply power or gas to our customers but ~~our Global Commodities operation hedges~~we hedge these transactions through purchases of power and gas that generally require us to post collateral. By entering into a gas supply agreement with the buyer of our gas trading operation, we have reduced our collateral requirements to support our retail gas operation. We ~~discuss this gas supply agreement~~also intend to further align our load obligations by buying generation assets in ~~more detail~~regions where we do not have a significant generation presence and entering into longer-tenor agreements with merchant generators, further reducing our dependence on ~~page 17 of the~~~~Notes to Consolidated Financial Statements~~.exchange-traded products, thereby lowering our collateral requirements.
•
In our Generation operation, we may have to post collateral on our power sale or fuel purchase contracts.

~~Table~~        Finally, collateral types may asymmetrically impact our liquidity. For example, in margining with OTC counterparties, we may post letter of ~~Contents~~
~~contracts, but~~credit (LC) collateral for an out-of-the money counterparty. However, we may receive LC collateral when we are in-the-money with a counterparty. Posting LCs reduces our ~~generating plants are~~liquidity while the receipt of LC collateral does not ~~a source of collateral.~~increase our liquidity.
        Customers of our ~~merchant energy~~NewEnergy business rely on the creditworthiness of Constellation Energy. In this regard, we have certain agreements that contain provisions that would require us to post additional collateral upon a credit rating downgrade in the senior unsecured debt of Constellation Energy. Based on contractual provisions at ~~June 30, 2009,~~March 31, 2010, we estimate that if Constellation Energy's senior unsecured debt were downgraded to one level below the investment grade threshold we would have the following additional collateral obligations:

Credit Ratings Downgraded to*
Level Below
Current Rating
Additional
Obligations**

(In billions)

Below investment grade
1 $ 1.5

Credit Ratings
Downgraded to¹
Level Below
Current Rating
Additional
Obligations²

(In billions)

Below investment grade
1 $ 1.1

*1 If there are split ratings among the independent credit-rating agencies, the lowest credit rating is used to determine our incremental collateral obligations.
**2 Includes ~~$0.3~~$0.2 billion related to derivative contracts as discussed in Notes to Consolidated Financial Statements beginning on page ~~35.~~31.
        Based on market conditions and contractual obligations at the time of a downgrade, we could be required to post additional collateral in an amount that could exceed the obligation amounts specified above, which could be material. We discuss our credit facilities in the~~Available Sources of Funding~~Notes to Consolidated Financial Statements ~~section.~~beginning on page 16.

Capital Resources
Our estimated annual cash requirement amounts for the years ~~2009~~2010 and ~~2010~~2011 are shown in the table below.
        We will continue to have cash requirements for:
•
working capital needs,
•
payments of interest, distributions, and dividends,
•
capital expenditures, and
•
the retirement of ~~debt and redemption of preference stock.~~debt.
        Capital requirements for ~~2009~~2010, 2011, and ~~2010~~2012 include estimates of spending for existing and anticipated projects. We continuously review and modify those estimates. Actual requirements may vary from the estimates included in the table below because of a number of factors including:
•
regulation, legislation, and competition,
•
BGE load requirements,
•
environmental protection standards,
•
the type and number of projects selected for construction or acquisition,
•
the effect of market conditions on those projects,
•
the cost and availability of capital,
•
potential capital contributions to CENG and UNE,
•
the availability of cash from operations, and
•
business decisions to invest in capital projects.
        Our estimates are also subject to additional factors. Please see theForward Looking Statements section on page 7563 andRisk Factors section in our ~~2008~~2009 Annual Report on Form 10-K. We discuss the potential impact of environmental legislation and regulation in more detail inBusiness Environment section beginning on page 4538 and

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Item 1. Business—Environmental Matters section of our ~~2008~~2009 Annual Report on Form 10-K.

Calendar Year Estimates
2009
2010

(In billions)

Nonregulated Capital Requirements:

Merchant energy

Generation plants¹
$ 0.4 $ 0.2

Environmental controls
0.3 —

Portfolio acquisitions/investments
0.1 0.1

Technology/other
0.1 —

Nuclear Fuel¹
0.2 —

Total merchant energy capital requirements
1.1 0.3

Other nonregulated capital requirements
0.1 —

Total nonregulated capital requirements
1.2 0.3

Regulated Capital Requirements:

Regulated electric
0.4 0.7

Regulated gas
0.1 0.1

Total regulated capital requirements
0.5 0.8

Total Capital Requirements
$ 1.7 $ 1.1

Calendar Year Estimates
2010
2011

(In billions)

Generation and Other Capital Requirements:

Major Environmental
$ 0.1 $ 0.1

Maintenance
0.1 0.1

Growth
0.1 —

Total Generation and Other Capital Requirements
0.3 0.2

NewEnergy Capital Requirements:

Maintenance
0.1 —

Growth
0.1 0.1

Total NewEnergy Capital Requirements
0.2 0.1

Regulated Capital Requirements:

Electric / Gas Distribution
0.4 0.4

Electric Transmission
0.1 0.1

Smart Energy Savers^SM Initiatives
0.1 0.2

Total Regulated Capital Requirements
0.6 0.7

Total Capital Requirements
$ 1.1 $ 1.0

~~1 Assumes~~Eligible capital projects are shown net of anticipated investment tax credits or grants.

As of the ~~Investment Agreement with EDF closes in the fall~~date of ~~2009 and~~this report, we ~~deconsolidate~~estimate our ~~nuclear generation and operation business. As a result, we are reflecting nine months of nuclear plant related and nuclear fuel~~2012 capital requirements ~~for 2009 and none for 2010.~~will be approximately $1.0 billion.

Capital Requirements

~~Merchant Energy Business~~Nonregulated Businesses

Our ~~merchant energy business'~~nonregulated businesses' capital requirements consist of its continuing requirements, including expenditures for:

•: ~~improvements~~maintenance and growth to generating plants,
•: ~~nuclear fuel costs,~~
•: costs of complying with the ~~EPA,~~Environmental Protection Agency (EPA), Maryland, and Pennsylvania environmental regulations and legislation, and
•: enhancements to our information technology infrastructure.

~~Cost for Decommissioning Nuclear Facilities~~

Every two years, the U. S. Nuclear Regulatory Commission (NRC) requires us to demonstrate reasonable assurance that funds will be available to decommission our nuclear generating facilities after these facilities cease operation. In response to our March 2009 biennial report, the NRC notified us that they had identified a potential "shortfall" in

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the decommissioning fund balance for certain of our nuclear reactors. This condition was a result of declining market performance during the last two quarters of 2008 for the investments held by our decommissioning trusts.

In July 2009, we filed with the NRC a plan that we expect will enable us to demonstrate by December 2009 reasonable assurance for adequate decommissioning funding in accordance with NRC regulations. Our plan proposes the use of a safe storage approach which allows funds to grow during the extended safe storage period following license termination but prior to decommissioning. In the event the NRC requires additional funding assurance beyond consideration of the safe storage approach, we will provide parental guarantees which would be subject to review and updating as necessary, but which are expected to be less than $70 million in the aggregate as of December 2009. We discuss the costs for decommissioning our nuclear generating facilities in more detail in the~~Business Overview~~ ~~section of our 2008 Annual Report on Form 10-K.~~

Regulated Electric and Gas

Regulated electric and gas construction expenditures primarily include new business construction needs and improvements to existing facilities, including projects to improve reliability and support demand response and conservation initiatives.

In July 2009, BGE filed with the Maryland PSC a proposal for a comprehensive ~~and advanced~~ smart grid initiative. The proposal includes the planned installation of 2 million residential and commercial electric and gas smart meters. We expect the total cost of the program to be approximately $480 ~~million, although potential stimulus funding from~~million. In October 2009, the United States Department of Energy ~~could reduce~~(DOE) selected BGE as a recipient of $200 million in federal funding for our smart grid initiative. This grant allows BGE to be reimbursed for smart grid expenditures up to $200 million, substantially reducing the total cost of this initiative. In April 2010, BGE and the DOE executed an agreement governing the terms and conditions of the grant. The Maryland PSC held hearings on this proposed program in late 2009 and expects to issue an order in the second quarter of 2010. If BGE's proposal is approved by the Maryland PSC, BGE plans to proceed with this program as ~~much~~soon as ~~$200 million. If approved, this proposal would have a material impact on future regulated electric and gas construction expenditures.~~practical.

Funding for Capital Requirements

We discuss our funding for capital requirements in our ~~2008~~2009 Annual Report on Form 10-K.

Contractual Payment Obligations and Committed Amounts

We enter into various agreements that result in contractual payment obligations in connection with our business activities. These obligations primarily relate to our financing arrangements (such as long-term debt, preference stock, and operating leases), purchases of capacity and energy to support ~~the growth in~~ our ~~merchant energy~~nonregulated business activities, and purchases of fuel and transportation to satisfy the fuel requirements of our power generating facilities.

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We detail our contractual payment obligations at ~~June 30, 2009~~March 31, 2010 in the following table:

Payments

2009
2010-
2011
2012-
2013
There-
after
Total

(In millions)

Contractual Payment Obligations

Long-term debt:¹

Nonregulated

Principal
$ 1,500.5 $ 0.4 $ 721.8 $ 2,625.0 $ 4,847.7

Interest
151.0 314.9 264.3 3,016.6 3,746.8

Total
1,651.5 315.3 986.1 5,641.6 8,594.5

BGE

Principal
38.4 138.2 639.1 1,422.8 2,238.5

Interest
66.7 258.1 231.3 1,336.6 1,892.7

Total
105.1 396.3 870.4 2,759.4 4,131.2
BGE preference stock
— — — 190.0 190.0
Operating leases²

Operating leases, gross
133.8 431.6 382.1 569.1 1,516.6

Sublease rentals
(39.9 ) (133.6 ) (77.5 ) (139.1 ) (390.1 )

Operating leases, net
93.9 298.0 304.6 430.0 1,126.5
Purchase obligations:³

Purchased capacity and energy⁴
295.8 285.0 188.5 229.8 999.1

Fuel and transportation
528.3 1,143.9 580.5 1,368.1 3,620.8

Other
152.8 122.0 50.8 27.9 353.5
Other noncurrent liabilities:

FIN 48 tax liability
— 123.1 2.9 9.8 135.8

Pension benefits⁵
49.2 360.5 292.9 (63.4 ) 639.2

Postretirement and postemployment benefits⁶
22.5 83.0 95.9 278.4 479.8

Total contractual payment obligations
$ 2,899.1 $ 3,127.1 $ 3,372.6 $ 10,871.6 $ 20,270.4

			Payments

			2010			2011- 2012			2013- 2014			There- after			Total

			(In millions)
Contractual Payment Obligations
Long-term debt:¹
	Nonregulated
		Principal	$	0.2		$	260.8		$	20.0		$	1,799.6		$	2,080.6
		Interest		111.7			241.2			235.7			2,772.5			3,361.1

	Total			111.9			502.0			255.7			4,572.1			5,441.7
	BGE
		Principal		56.5			254.2			537.0			1,352.4			2,200.1
		Interest		114.4			247.2			194.9			1,253.4			1,809.9

	Total			170.9			501.4			731.9			2,605.8			4,010.0
BGE preference stock				—			—			—			190.0			190.0
Operating leases²
	Operating leases, gross			166.0			393.0			332.5			338.6			1,230.1
	Sublease rentals			(43.1	)		(102.3	)		(56.3	)		(114.8	)		(316.5	)

	Operating leases, net			122.9			290.7			276.2			223.8			913.6
Purchase obligations:³
	Purchased capacity and energy⁴			201.4			517.1			129.6			328.7			1,176.8
	Purchased energy from CENG			402.1			1,329.6			1,941.4			—			3,673.1
	Fuel and transportation			440.8			390.2			95.1			218.7			1,144.8
	Other			92.5			56.1			8.6			6.7			163.9
Other noncurrent liabilities:
	Uncertain tax positions liability			—			191.8			4.6			14.5			210.9
	Pension benefits⁵			37.1			217.5			203.7			(47.1	)		411.2
	Postretirement and postemployment benefits⁶			23.1			72.9			82.8			193.6			372.4

Total contractual payment obligations			$	1,602.7		$	4,069.3		$	3,729.6		$	8,306.8		$	17,708.4

1 Amounts in long-term debt reflect the original maturity ~~date and include $697.7 million of principal for the Zero Coupon Senior Notes, assuming the notes are not redeemed prior to June 19, 2023 and the original issue discount accrues until redemption.~~date. Investors may require us to repay ~~$483.8~~$95.0 million early through remarketing ~~and put~~ features. Interest on variable rate debt is included based on the forward curve for interest rates.

2 Our operating lease commitments include future payment obligations under certain power purchase agreements as discussed further in Note 11 of our ~~2008~~2009 Annual Report on Form 10-K.

3 Contracts to purchase goods or services that specify all significant terms. Amounts related to certain purchase obligations are based on future purchase expectations, which may differ from actual purchases.

4 Our contractual obligations for purchased capacity and energy are shown on a gross basis for certain transactions, including both the fixed payment portions of tolling contracts and estimated variable payments under unit-contingent power purchase agreements.

5 Amounts related to pension benefits reflect our current 5-year forecast of contributions for our qualified pension plans and participant payments for our nonqualified pension plans. Refer to Note 7 of our ~~2008~~2009 Annual Report on Form 10-K for more detail on our pension plans.

6 Amounts related to postretirement and postemployment benefits are for unfunded plans and reflect present value amounts consistent with the determination of the related liabilities recorded in our Consolidated Balance Sheets.

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Off-Balance Sheet Arrangements

We discuss our off-balance sheet arrangements in our ~~2008~~2009 Annual Report on Form 10-K.

At ~~June 30, 2009,~~March 31, 2010, Constellation Energy had a total face amount of ~~$14.1~~$9.9 billion in guarantees outstanding, of which ~~$12.7~~$8.8 billion related to our ~~merchant energy business.~~Generation and NewEnergy businesses. These amounts do not represent incremental consolidated Constellation Energy obligations; rather, they primarily represent parental guarantees of certain subsidiary obligations to third parties in order to allow our subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Our estimated net exposure for obligations under commercial transactions covered by these guarantees was ~~approximately $2.5~~$2 billion at ~~June 30, 2009,~~March 31, 2010, which represents the total amount the parent company could be required to fund based on ~~June 30, 2009~~March 31, 2010 market prices. For those guarantees related to our derivative liabilities, the fair value of the obligation is recorded in our Consolidated Balance Sheets. We believe it is unlikely that we would be required to perform or incur any losses associated with guarantees of our subsidiaries' obligations.

We discuss our other guarantees in theNotes to Consolidated Financial Statements ~~beginning~~ on page ~~23.~~19.

Risk Management

Market Risk

Economic Value at Risk (EVaR)

EVaR ~~is a measure that attempts to estimate~~measures the ~~sensitivity~~potential pre-tax loss in the fair value of ~~our total portfolio economic value~~the Generation and NewEnergy businesses due to changes in market prices. The EVaR measure includes all positions of our merchant business, including Generation, Customer Supply, and Global Commodities operations. Each business day, the Company undertakes EVaR calculations that include both its trading and its non-trading risks. EVaR for non-trading positions measures the amount of potential change in the fair values of the exposures related to accrual exposures.risk factors. EVaR is a one-day value-at-risk measure calculated at a 95% confidence level onassuming a standard normal distribution of prices over the ~~portfolio through 2013. At June 30, 2009,~~most recent rolling 3-month period. EVaR includes all positions over a forward rolling 60-month time horizon that expose us to market price risk, regardless of accounting treatment and business line.

Positions included in EVaR are comprised of all positions, regardless of accounting treatment, that create market risk including:

•

derivative and nonderivative commodity contracts associated with our ~~EVaR was approximately $97 million, which represents a 29% decline from its level of $136 million at December 31, 2008.~~

~~Due to the inherent limitations of statistical measures~~Generation and NewEnergy businesses,

•

physical assets, such as ~~EVaR~~our owned and contractually-controlled generating plants, and

•

our share of investments in generating plants.

We include the ~~seasonality of changes in market prices, the EVaR calculation may not reflect the full extent~~positions related to physical assets to provide a more complete presentation of our commodity market risk exposures. EVaR includes illiquid products and positions for which there is limited price ~~risk exposure. Additionally, because our EVaR methodology uses a linear approximation method, actual changes in~~discovery. Modeling the ~~value of options~~positions in our ~~portfolio resulting from significant price changes may differ from~~Generation and NewEnergy businesses involves a number of assumptions, and includes

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projections of generation, emission rates and costs, customer load growth, load response to weather, and customer response to competitive supply. Changes in our forecast or management estimates ~~generated using this methodology. As a result, actual changes in~~will affect the fair value of ~~derivative assets and liabilities subject to mark-to-market accounting could differ from the calculated EVaR, and such changes could have~~these positions in a ~~material impact on our financial results.~~manner not captured by EVaR.

~~While~~ EVaR reflects the risk of loss due to market prices under normal market conditions. An inherent limitation of our value-at-risk measures is the reliance on historical prices. A sudden shift in market conditions can cause the future behavior of market prices to differ materially from the past. We use stress ~~testing captures Constellation Energy's~~tests and scenario analysis to better understand extreme events as a complement to EVaR. This includes exposure to unlikely but plausible events in abnormal ~~markets. We regularly conduct economic value stress tests for our market activities using multiple scenarios that assume stressed~~markets, sensitivity to changes in ~~both~~management projections of customer demand or forecasted generation output, and price ~~level~~sensitivity to illiquid points and regional basis spreads. ~~Additional scenarios focus~~

EVaR is monitored daily and is subject to regional and overall guidelines for the NewEnergy business. We place guidelines on the ~~risks predominant in individual portions of~~risk associated with illiquid delivery locations and regional basis within our ~~business segments~~NewEnergy business. Additionally, we monitor generation plant hedge ratios relative to guidelines specified by management. Stress tests and ~~include scenarios that focus on loss of generation, customer demand growth or demand destruction, or a shift in~~scenario analysis are conducted regularly and the ~~composition of load serving customers.~~

Along with EVaR, stress testing is important in measuring and controlling risk. Stress testing enhances the understanding of Constellation Energy's risk profile and loss potential, and stress losses are monitored against limits. We also use stress testing in approvals of non-standard transactions and for cross-business risk measurement, as well as an input to economic capital allocation. Stress test results, trends, and explanations are ~~provided each month to Constellation Energy's~~reviewed by senior management and torisk committees.

The EVaR amounts below represent the ~~lines~~potential pre-tax change in the fair values of ~~business to help them better measure~~our Generation and ~~manage risks and to understand event risk-sensitive positions.~~NewEnergy businesses positions over a one-day holding period.

EVaR		Quarter Ended March 31, 2010


95% Confidence Level, One-Day Holding Period
	Quarter end	$	45.7
	Average		60.3
	High		71.6
	Low		44.8

Value at Risk (VaR)

~~Where EVaR is a measure that attempts to estimate~~VaR measures the ~~sensitivity~~potential pre-tax loss in the fair value of ~~our total portfolio economic value, VaR is a measure that attempts to measure~~ the ~~sensitivity of our~~ mark-to-market energy contracts ~~of our Global Commodities operation~~due to ~~potential~~ changes in market ~~prices.~~risk factors. VaR is calculated assuming a ~~statistical model designed to predict risk~~standard normal distribution of loss based on historical market price volatility. We calculate VaR using a historical variance/covariance technique that models option positions using a linear approximation of their value. Additionally, we estimate variances and correlation using historical commodity price changesprices over the most recent rolling ~~three-month~~3-month period. ~~Our~~ VaR ~~calculation~~ includes all ~~of our Global Commodities operation derivative assets and liabilities~~positions subject to mark-to-market accounting, including contracts ~~for energy commodities~~that hedge the economics of NewEnergy nonderivative power and ~~derivatives that result in physical settlement~~fuel contracts, which do not receive hedge accounting treatment, and contracts ~~that require cash settlement.~~designated for trading. Thus, the positions for which we monitor VaR ~~is a statistical risk measurement model~~are included within, and are not incremental, to the positions subject to ~~limitations similar to those of~~ EVaR.

VaR and EVaR have similar limitations. VaR may include some products and positions for which there is limited price discovery or market depth. The modeling of option positions included in VaR ~~calculation does not include~~involves a number of assumptions and approximations. An inherent limitation of our VaR measures is the reliance on historical prices. A sudden shift in market ~~risks associated with activities~~conditions can cause the future behavior of market prices to differ materially from that ~~are subject to accrual accounting, primarily our generating facilities and our customer supply load-serving activities.~~of the past.

The VaR amounts below represent the potential pre-tax loss in the fair value of our ~~Global Commodities operation derivative assets~~Generation and ~~liabilities~~NewEnergy businesses positions subject to mark-to-market accounting, including both trading and

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non-trading activities, over one and ten-day holding periods.

Total Wholesale VaR
Quarter Ended
June 30, 2009

(In millions)

99% Confidence Level, One-Day Holding Period

Average
$ 17.6

High
22.9
95% Confidence Level, One-Day Holding Period

Average
13.4

High
17.4
95% Confidence Level, Ten-Day Holding Period

Average
42.4

High
55.1

Total Mark-to-Market VaR		Quarter Ended March 31, 2010


		(In millions)
99% Confidence Level, One-Day Holding Period
	Quarter end	$	9.7
	Average		7.5
	High		12.4
	Low		5.1
95% Confidence Level, One-Day Holding Period
	Quarter end		7.4
	Average		5.7
	High		9.5
	Low		3.9
95% Confidence Level, Ten-Day Holding Period
	Quarter end		23.4
	Average		18.0
	High		30.0
	Low		12.4

Constellation Energy's proprietary trading activities are greatly reduced from previous years and are largely focused on price discovery. These activities continue to be managed with daily VaR limits, stop loss limits and liquidity guidelines and are immaterial relative to the overall portfolio VaR.

Wholesale Credit Risk

We measure wholesale credit risk as the replacement cost for open energy commodity and derivative transactions (both mark-to-market and accrual) adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff. We monitor and manage ~~the~~our credit risk ~~of our Global Commodities operation~~ through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral, or prepayment arrangements, and the use of master netting agreements.

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As of ~~June 30, 2009~~March 31, 2010 and December 31, ~~2008,~~2009, counterparties in ~~the~~our credit portfolio ~~of our Global Commodities operation~~ had the following public credit ratings:

June 30,
2009
December 31,
2008

Rating

Investment Grade¹
57 % 52 %

Non-Investment Grade
9 15

Not Rated
34 33




Rating
	Investment Grade¹	50	%	43	%
	Non-Investment Grade	2		2
	Not Rated	48		55

1 Includes counterparties with an investment grade rating by at least one of the major credit rating agencies. If split rating exists, the lower rating is used.

Our exposure to "Not Rated" counterparties was $1$1.4 billion at ~~June 30, 2009~~March 31, 2010 compared to $1.5 billion at December 31, ~~2008.~~2009. This decrease was mostly ~~due to~~driven by a reduction in our CENG credit concentration exposure, which is not externally rated and a decrease in our portfolio's credit exposure to unrated natural gas customers, international coal customers, and freight ~~companies~~customers that do not have public credit ratings as a result of the divestiture of ~~a majority of our international commodities operation.~~these operations in 2009.

Many of our not rated counterparties are considered investment grade equivalent (including CENG) based on our internal credit ratings. We utilize internal credit ratings to evaluate the creditworthiness of our wholesale customers, including those companies that do not have public credit ratings. Based on internal credit ratings, approximately ~~$528.5 million~~$1.1 billion or ~~52%~~81% of the exposure to not rated counterparties was rated investment grade equivalent at ~~June 30, 2009~~March 31, 2010 and approximately ~~$883.7 million~~$1.2 billion or ~~60%~~81% was rated investment grade equivalent at December 31, ~~2008.~~

2009. The following table provides the breakdown of the credit quality of our wholesale credit portfolio based on our internal credit ratings:

June 30,
2009
December 31,
2008

Investment Grade Equivalent
77 % 74 %
Non-Investment Grade
23 26




Investment Grade Equivalent	89	%	88	%
Non-Investment Grade	11		12

Our total exposure, net of collateral, to counterparties across our entire wholesale portfolio is $3$2.8 billion as of ~~June 30, 2009.~~March 31, 2010. The top ten counterparties account for ~~37%~~approximately 51% of our total ~~exposure. As shown in the table below, no single counterparty concentration comprises more than 10%~~exposure with approximately 4% of ~~the total~~that exposure ~~of the portfolio.~~being non-investment grade.

If a counterparty were to default on its contractual obligations and we were to liquidate transactions with that entity, our potential credit loss would include all forward and settlement exposure plus any additional costs related to termination and replacement of the positions. This would include contracts accounted for using the mark-to-market, hedge, and accrual accounting methods, the amount owed or due from settled transactions, less any collateral held from the counterparty. In addition, if a counterparty were to default under an accrual contract that is currently favorable to us, we may recognize a material adverse impact on our results in the future delivery period to the extent that we are required to replace the contract that is in default with another contract at current market prices. To reduce our credit risk with counterparties, we attempt to enter into agreements that allow us to obtain collateral on a contingent basis, seek third-party guarantees of the counterparty's obligation, and enter into netting agreements that allow us to offset receivables and payables with forward exposure across many transactions.

~~Table~~ We consider a significant concentration of ~~Contents~~

~~Our~~credit risk to be any single obligor or counterparty whose concentration exceeds 10% of total credit exposure. As of March 31, 2010, two counterparties, CENG and a large power cooperative, comprise exposure concentrations of 14% and 11%, respectively. No counterparties based in a single country other than the United States in aggregate comprise more than 10% of the total exposure of $3 billion, net of collateral, includes accrual positions and derivatives. The portion of our wholesale credit risk related to transactions that are recorded in our Consolidated Balance Sheets, net of collateral, totals approximately $1 billion and primarily relates to open energy commodity positions from our Global Commodities operation that are accounted for using mark-to-market accounting, derivatives that qualify for designation as hedges, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid.

~~The following table highlights~~ the ~~credit quality and exposures related to these activities at June 30, 2009:~~portfolio.

Rating
Total Exposure
Before Credit
Collateral
Credit
Collateral
Net
Exposure
Number of
Counterparties Greater
than 10% of Net
Exposure
Net Exposure of
Counterparties Greater
than 10% of Net
Exposure

(In millions)

Investment grade
$ 1,319 $ 493 $ 826 — $ —
Split rating
18 1 17 — —
Non-investment grade
117 66 51 — —
Internally rated—investment grade
72 — 72 — —
Internally rated—non-investment grade
67 — 67 — —

Total
$ 1,593 $ 560 $ 1,033 — $ —

Due to volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, fail to deliver the power ~~our Global Commodities operation~~we had contracted for), we could incur a loss that could have a material impact on our financial results.

If a counterparty were to default and we were to liquidate all contracts with that entity, our credit loss would include the loss in value of derivative contracts recorded at fair value, the amount owed for settled transactions, and additional payments, if any, that we would have to make to settle unrealized losses on accrual contracts. In addition, if a counterparty were to default under an accrual contract that is currently favorable to us, we may recognize a material adverse impact in our results in the future delivery period to the extent that we are required to replace the contract that is in default with another contract at current market prices. These potential losses would be limited to the extent that the in-the-money amount exceeded any credit mitigants such as cash, letters of credit, or parental guarantees supporting the counterparty obligation.

We also enter into various wholesale transactions through ~~Independent System Operators (ISOs).~~ISOs. These ISOs are exposed to counterparty credit risks. Any losses relating to counterparty defaults impacting the ISOs are allocated to and borne by all other market participants in the ISO. These ISOs have

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established credit policies and practices to mitigate the exposure of counterparty credit risks. As a market participant, we continuously assess our exposure to the credit risks of each ISO.

BGE is exposed to wholesale credit risk of its suppliers for electricity and gas to serve its retail customers. BGE may receive performance assurance collateral to mitigate electricity suppliers' credit risks in certain circumstances. Performance assurance collateral is designed to protect BGE's potential exposure over the term of the supply contracts and will fluctuate to reflect changes in market prices. In addition to the collateral provisions, there are supplier "step-up" provisions, where other suppliers can step in if the early termination of a full-requirements service agreement with a supplier should occur, as well as specific mechanisms for BGE to otherwise replace defaulted supplier contracts. All costs incurred by BGE to replace the supply contract are to be recovered from the defaulting supplier or from customers through rates.

Interest Rate Risk, Retail Credit Risk, Foreign Currency Risk, Security Price Risk, and Operational Risk

We discuss our exposure to interest rate risk, retail credit risk, foreign currency risk, security price risk and operational risk in theRisk Management section of our ~~2008~~2009 Annual Report on Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We discuss the following information related to our market risk:

•: hedging activities in theNotes to Consolidated Financial Statements beginning on page ~~27,~~23,
•: activities of our ~~Global Commodities operation~~Generation and NewEnergy businesses in ~~the~~~~Merchant Energy Business~~their respective section ofManagement's Discussion and Analysis beginning on page ~~50,~~41,
•: evaluation of commodity and credit risk in theRisk Management section ofManagement's Discussion and Analysis beginning on page ~~70,~~57, and
•: changes to our business environment in theBusiness Environment section ofManagement's Discussion and Analysis beginning on page ~~44.~~38.

Items 4 and 4(T). Controls and Procedures

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Constellation Energy or BGE have been detected. These inherent limitations include errors by personnel in executing controls due to faulty judgment or simple mistakes, which could occur in situations such as when personnel performing controls are new to a job function or when inadequate resources are applied to a process. Additionally, controls can be circumvented by the individual acts of some persons or by collusion of two or more people.

The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no absolute assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions or personnel, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Evaluation of Disclosure Controls and Procedures

The principal executive ~~officers~~officer and principal financial ~~officers~~officer of ~~both~~ Constellation Energy ~~and BGE~~ have each evaluated the effectiveness of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the fiscal quarter covered by this quarterly report (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, Constellation Energy's disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports that Constellation Energy files and submits under the Exchange Act is recorded, processed, summarized, and reported when required and is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required disclosure.

The principal executive officer and principal financial officer of BGE have each evaluated the effectiveness of the disclosure controls and procedures as of the Evaluation Date. Based on such evaluation, such officers have concluded that, as of the Evaluation Date, BGE's disclosure controls and procedures are ~~effective.~~effective in providing reasonable assurance that information required to be disclosed in the reports that BGE files and submits under the Exchange Act is recorded, processed, summarized, and reported when required and is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended ~~June 30, 2009,~~March 31, 2010, there has been no change in either Constellation Energy's or BGE's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, either Constellation Energy's or BGE's internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We discuss our Legal Proceedings in theNotes to Consolidated Financial Statements beginning on page ~~24.~~20.

Item 2. Issuer Purchases of Equity Securities

The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.

Period
Total Number
of Shares
Purchased¹
Average Price
Paid for Shares
Total Number
of Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs

Maximum Dollar
Amounts of
Shares that
May Yet Be
Purchased Under
the Plans and
Programs (at
month end)²

April 1 – April 30, 2009
15,533 $ 20.42 — $ 750 million
May 1 – May 31, 2009
1,129 23.14 — 750 million
June 1 – June 30, 2009
2,067 26.83 — 750 million

Total
18,729 $ 21.29 — —

Period		Average Price Paid for Shares


January 1 – January 31, 2010	37	$	35.63	—	—
February 1 – February 28, 2010	185,400		34.74	—	—
March 1 – March 31, 2010	196		36.44	—	—

Total	185,633	$	34.74	—	—

1 Represents shares surrendered by employees to satisfy tax withholding obligations on vested restricted stock and restricted stock units.
2 In October 2007, our Board of Directors approved a common share repurchase program for up to $1 billion of our outstanding common shares over the 24 months following approval. Pursuant to the terms of our Series B Preferred Stock, we are prohibited from engaging in a common share repurchase in an aggregate amount in excess of $100 million without the approval of the holders of more than 50% of the then outstanding shares of Series B Preferred Stock.

~~Item 4. Submission of Matters to Vote of Security Holders~~

~~On May 29, 2009, we held our annual meeting of shareholders. At that meeting, the following matters were voted upon:~~

1.: ~~Directors nominated by Constellation Energy were elected to serve for a term to expire in 2010 and until their successors are duly elected and qualified as follows:~~

COMMON SHARES CAST:

For
Against
Abstain

Yves C. de Balmann
165,975,225 5,556,613 2,559,713
Ann C. Berzin
165,915,138 5,659,901 2,516,513
James T. Brady
164,989,362 8,148,322 953,874
James R. Curtiss
167,249,182 5,844,567 997,804
Freeman A. Hrabowski III
153,038,551 20,120,649 932,357
Nancy Lampton
166,360,505 6,724,875 1,006,172
Robert J. Lawless
152,871,815 20,224,820 994,921
Lynn M. Martin
155,696,864 17,372,666 1,022,024
Mayo A. Shattuck III
148,029,915 25,207,202 854,445
John L. Skolds
166,282,660 5,303,808 2,505,089
Michael D. Sullivan
147,786,173 25,308,509 996,873

2.: The ratification of PricewaterhouseCoopers LLP as independent registered public accounting firm for 2009 was approved. With respect to holders of common stock, the number of affirmative votes cast was 170,190,530, the number of votes cast against was 2,977,483, and the number of abstentions was 923,544.

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Item 5. Other Information

Forward Looking Statements

We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "anticipates," "expects," "intends," "plans," and other similar words. We also disclose non-historical information that represents management's expectations, which are based on numerous assumptions. These statements and projections are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to:

•: the timing and extent of changes in commodity prices and volatilities for energy and ~~energy related~~energy-related products including coal, natural gas, oil, electricity, nuclear fuel, ~~freight,~~ and emission allowances, and the impact of such changes on our liquidity requirements,
•: the liquidity and competitiveness of wholesale and retail markets for energy commodities,
•: the conditions of the capital markets, interest rates, foreign exchange rates, availability of credit facilities to support business requirements, liquidity, and general economic conditions, as well as Constellation Energy Group's (Constellation Energy) and Baltimore Gas and Electric's (BGE) ability to maintain their current credit ratings,
•: the effectiveness of Constellation Energy's and BGE's risk management policies and procedures and the ability and willingness of our counterparties to satisfy their financial and performance commitments,
•: ~~the ability to complete our strategic initiatives to improve our liquidity and the impact of such initiatives on our business and financial results,~~
•: losses on the sale or write-down of assets due to impairment events or changes in management intent with regard to either holding or selling certain assets,
•: the ability to successfully identify, finance, and complete acquisitions and sales of businesses and assets,
•: ~~the likelihood~~ including generating facilities and timing of the completion of the pending transaction with EDF Group and related entities (EDF), the terms and conditions of any required regulatory approvals for the pending transaction, potential impact of a termination of the pending transaction and potential diversion of management's time and attention from our ongoing business during this time period,new nuclear generation development projects,
•: the effect of weather and general economic and business conditions on energy supply, demand, prices, and customers' and counterparties' ability to perform their obligations or make payments,
•: the ability to attract and retain customers in our ~~Customer Supply activities~~NewEnergy business and to adequately forecast their energy usage,
•: the timing and extent of deregulation of, and competition in, the energy markets, and the rules and regulations adopted in those markets,
•: ~~uncertainties associated with estimating natural gas reserves, developing properties, and extracting natural gas,~~
•: regulatory or legislative developments federally, in Maryland, or in other states that affect energy deregulation, the price of energy, transmission or distribution rates and revenues, demand for energy, or increases in costs, including costs related to ~~nuclear power plants,~~ safety, or environmental compliance,
•: the ability of our regulated and nonregulated businesses to comply with complex and/or changing market rules and regulations,
•: the ability of BGE to recover all its costs associated with providing customers service,
•: operational factors affecting commercial operations of our generating facilities ~~(including nuclear facilities)~~ and BGE's transmission and distribution facilities, including ~~catastrophic~~ weather-related damages, unscheduled outages or repairs, unanticipated changes in fuel costs or availability, unavailability of coal or gas transportation or electric transmission services, workforce issues, terrorism, liabilities associated with catastrophic events, and other events beyond our control,
•: the impact of industry consolidation,
•: the impact of increased energy conservation and use of renewable energy,
•: the actual outcome of uncertainties associated with assumptions and estimates ~~using~~requiring judgment when managing our business, applying critical accounting policies and preparing financial statements, including factors that are estimated in determining the fair value of energy contracts, such as the ability to obtain market prices and, in the absence of verifiable market prices, the appropriateness of models and model inputs (including, but not limited to, estimated contractual load obligations, unit availability, forward commodity prices, interest rates, correlation and volatility factors),
•: changes in accounting principles or practices, and
•: cost and other effects of legal and administrative proceedings that may not be covered by insurance, including environmental liabilities.

Given these uncertainties, you should not place undue reliance on these forward looking statements. Please see the other sections of this report and our other periodic reports filed with the Securities and Exchange Commission (SEC) for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report.

Changes may occur after that date, and neither Constellation Energy nor BGE assumes responsibility to update these forward looking statements.

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Item 6. Exhibits


~~Exhibit No. 4(a)~~	*	Indenture and Security Agreement dated as of July 9, 2009, between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee (including form of Baltimore Gas and Electric Company Officer's Certificate and form of Senior Secured Bond) (Designated as Exhibits 4(u) and 4(u)(1) to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, File Nos. 333-157637 and 333-157637-01).
~~Exhibit No. 4(b)~~	*	Baltimore Gas and Electric Company Deed of Easement and Right-of-Way Grant dated as of July 9, 2009 (Designated as Exhibit 4(u)(2) to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, File Nos. 333-157637 and 333-157637-01).
Exhibit No. 12(a)		Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges.
Exhibit No. 12(b)		Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
Exhibit No. 31(a)		Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(b)		Certification of Senior Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(c)		Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 31(d)		Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(a)		Certification of Chairman of the Board, President and Chief Executive Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(b)		Certification of Senior Vice President and Chief Financial Officer of Constellation Energy Group, Inc. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(c)		Certification of President and Chief Executive Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 32(d)		Certification of Senior Vice President and Chief Financial Officer of Baltimore Gas and Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. 101.INS		XBRL Instance Document
Exhibit No. 101.SCH		XBRL Taxonomy Extension Schema Document
Exhibit No. 101.PRE		XBRL Taxonomy Presentation Linkbase Document
Exhibit No. 101.LAB		XBRL Taxonomy Label Linkbase Document
Exhibit No. 101.CAL		XBRL Taxonomy Calculation Linkbase Document
Exhibit No. 101.DEF		XBRL Taxonomy Definition Linkbase Document

*: ~~Incorporated by reference~~

In accordance with Rule 402 of Regulation S-T, the XBRL related information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

Table of Contents

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		CONSTELLATION ENERGY GROUP, ~~INC~~INC. (Registrant)
Date:~~August~~May 7, ~~2009~~2010		/s/ JONATHAN W. THAYER Jonathan W. Thayer, Senior Vice President of Constellation Energy Group, Inc. and as Principal Financial Officer
		BALTIMORE GAS AND ELECTRIC COMPANY (Registrant)
Date:~~August~~May 7, ~~2009~~2010		/s/ KEVIN W. HADLOCK Kevin W. Hadlock, Senior Vice President of Baltimore Gas and Electric Company and as Principal Financial Officer


Commission File Number	Exact name of registrant as specified in its charter	IRS Employer Identification No.
1-12869	CONSTELLATION ENERGY GROUP, INC.	52-1964611


Large accelerated filerý		Accelerated filero		Non-accelerated filero		Smaller reporting companyo


Large accelerated filero		Accelerated filero		Non-accelerated filerý		Smaller reporting companyo

			Page

Part I—Financial Information			3
	Item 1—Financial Statements		3
		Constellation Energy Group, Inc. and Subsidiaries
		Consolidated Statements of Income (Loss)	3
		Consolidated Statements of Comprehensive Income ~~(Loss)~~	3
		Consolidated Balance Sheets	4
		Consolidated Statements of Cash Flows	6
		Baltimore Gas and Electric Company and Subsidiaries
		Consolidated Statements of Income ~~(Loss)~~	7
		Consolidated Balance Sheets	8
		Consolidated Statements of Cash Flows	10
		Notes to Consolidated Financial Statements	11
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations		4438
		Introduction and Overview	4438
		Business Environment	4438
		Events of ~~2009~~2010	4539
		Results of Operations	4640
		Financial Condition	6352
		Capital Resources	6855
	Item 3—Quantitative and Qualitative Disclosures About Market Risk		7361
	Items 4 and 4(T)—Controls and Procedures		7361
Part II—Other Information			7462
	Item 1—Legal Proceedings		7462
	Item 2—Issuer Purchases of Equity Securities		74
	~~Item 4—Submission of Matters to Vote of Security Holders~~		7462
	Item 5—Other Information		7563
	Item 6—Exhibits		7664
	Signature		7765

		Three Months Ended March 31,

		2010			2009

		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	2,518.2		$	3,112.3
	Regulated electric revenues		751.3			806.8
	Regulated gas revenues		317.1			384.3

	Total revenues		3,586.6			4,303.4
Expenses
	Fuel and purchased energy expenses		2,362.1			3,273.2
	Fuel and purchased energy expenses from affiliate		198.5			—
	Operating expenses		396.4			581.7
	Merger termination and strategic alternatives costs		—			42.3
	Impairment losses and other costs		—			28.6
	Workforce reduction costs		—			10.8
	Depreciation, depletion, and amortization		131.4			148.6
	Accretion of asset retirement obligations		0.5			17.9
	Taxes other than income taxes		66.8			77.9

	Total expenses		3,155.7			4,181.0
Equity Investment Losses			(20.7	)		—
Net Gain (Loss) on Divestitures			4.9			(334.5	)

Income (Loss) from Operations			415.1			(212.1	)
Other Expense			(22.3	)		(56.3	)
Fixed Charges
	Interest expense		121.5			115.1
	Interest capitalized and allowance for borrowed funds used during construction		(15.6	)		(21.6	)

	Total fixed charges		105.9			93.5

Income (Loss) from Continuing Operations Before Income Taxes			286.9			(361.9	)
Income Tax Expense (Benefit)			95.6			(242.2	)

Net Income (Loss)			191.3			(119.7	)
Less: Net (Loss) Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends			(0.2	)		3.8

Net Income (Loss) Attributable to Common Stock		$	191.5		$	(123.5	)

Average Shares of Common Stock Outstanding—Basic			200.3			198.5
Average Shares of Common Stock Outstanding—Diluted			201.9			198.5

Earnings (Loss) Per Common Share—Basic		$	0.96		$	(0.62	)

Earnings (Loss) Per Common Share—Diluted		$	0.95		$	(0.62	)

Dividends Declared Per Common Share		$	0.24		$	0.24

		Three Months Ended June 30,						Six Months Ended June 30,

		2009			2008			2009			2008

		(In millions, except per share amounts)
Revenues
	Nonregulated revenues	$	3,097.3		$	4,124.3		$	6,209.6		$	7,836.2
	Regulated electric revenues		655.7			448.7			1,462.5			1,158.0
	Regulated gas revenues		111.1			183.1			495.4			574.1

	Total revenues		3,864.1			4,756.1			8,167.5			9,568.3
Expenses
	Fuel and purchased energy expenses		2,631.6			3,559.4			5,904.8			7,302.5
	Operating expenses		561.2			711.5			1,142.9			1,301.6
	Merger termination and strategic alternatives costs		4.0			—			46.3			—
	Impairment losses and other costs		67.2			—			95.8			—
	Workforce reduction costs		0.4			—			11.2			—
	Depreciation, depletion, and amortization		148.9			141.9			297.5			290.2
	Accretion of asset retirement obligations		18.2			17.0			36.1			33.6
	Taxes other than income taxes		72.4			71.1			150.3			145.9

	Total expenses		3,503.9			4,500.9			7,684.9			9,073.8
Net (loss) gain on divestitures			(129.6	)		76.5			(464.1	)		91.5

Income from Operations			230.6			331.7			18.5			586.0
Other Income (Expense)			12.1			15.3			(15.4	)		58.0
Fixed Charges
	Interest expense		133.2			73.5			277.1			152.3
	Interest capitalized and allowance for borrowed funds used during construction		(21.6	)		(8.6	)		(43.2	)		(15.7	)

	Total fixed charges		111.6			64.9			233.9			136.6

Income (Loss) from Continuing Operations Before Income Taxes			131.1			282.1			(230.8	)		507.4
Income Tax Expense (Benefit)			102.8			107.1			(139.4	)		183.0

Net Income (Loss)			28.3			175.0			(91.4	)		324.4
Less: Net Income Attributable to Noncontrolling Interests and BGE Preference Stock Dividends			20.2			3.5			24.0			7.2

Net Income (Loss) Attributable to Common Stock		$	8.1		$	171.5		$	(115.4	)	$	317.2

Average Shares of Common Stock Outstanding—Basic			199.2			178.4			198.9			178.3
Average Shares of Common Stock Outstanding—Diluted			200.0			180.2			198.9			180.2
Earnings (Loss) Per Common Share—Basic		$	0.04		$	0.96		$	(0.58	)	$	1.78

Earnings (Loss) Per Common Share—Diluted		$	0.04		$	0.95		$	(0.58	)	$	1.76

Dividends Declared Per Common Share		$	0.24		$	0.4775		$	0.48		$	0.955

Six Months Ended June 30,				2009			2008


				(In millions)
Cash Flows From Operating Activities
	Net (loss) income			$	(91.4	)	$	324.4
	Adjustments to reconcile to net cash provided by operating activities
		Depreciation, depletion, and amortization			297.5			290.2
		Amortization of nuclear fuel			67.0			59.1
		Amortization of energy contracts			(86.7	)		(117.1	)
		All other amortization			74.9			8.3
		Accretion of asset retirement obligations			36.1			33.6
		Deferred income taxes			(121.6	)		39.2
		Investment tax credit adjustments			(3.0	)		(3.2	)
		Deferred fuel costs			32.4			19.7
		Defined benefit obligation expense			64.7			55.5
		Defined benefit obligation payments			(328.6	)		(100.3	)
		Workforce reduction costs			11.2			—
		Impairment losses and other costs			95.8			—
		Impairment losses on nuclear decommissioning trust assets			62.4			12.5
		Merger termination and strategic alternatives costs			37.2			—
		Loss (gain) on divestitures			464.1			(99.2	)
		Gains on termination of contracts			—			(68.9	)
		Accrual of Maryland settlement agreement credit			—			188.2
		Equity in earnings of affiliates less than dividends received			18.5			7.4
		Derivative contracts classified as financing activities under SFAS No. 149			785.3			0.5
		Changes in:
			Accounts receivable, excluding margin		599.2			(521.7	)
			Derivative assets and liabilities, excluding collateral		185.2			(700.6	)
			Net collateral and margin		1,094.9			525.9
			Materials, supplies, and fuel stocks		323.4			(235.5	)
			Other current assets		237.0			11.2
			Accounts payable and accrued liabilities		(786.1	)		1,051.7
			Other current liabilities		(156.0	)		(247.1	)
		Other			51.0			6.2

	Net cash provided by operating activities				2,964.4			540.0

Cash Flows From Investing Activities
	Investments in property, plant and equipment				(809.1	)		(869.5	)
	Asset and business acquisitions, net of cash acquired				—			(312.4	)
	Investments in nuclear decommissioning trust fund securities				(233.4	)		(282.7	)
	Proceeds from nuclear decommissioning trust fund securities				214.7			264.0
	Proceeds from sales of investments and other assets				80.9			217.0
	Contract and portfolio acquisitions				(2,153.7	)		—
	Decrease (increase) in restricted funds				1,004.4			(196.9	)
	Other				(1.8	)		12.9

	Net cash used in investing activities				(1,898.0	)		(1,167.6	)

Cash Flows From Financing Activities
	Net (repayment) issuance of short-term borrowings				(515.8	)		103.7
	Proceeds from issuance of common stock				13.6			8.3
	Proceeds from issuance of long-term debt				109.0			1,100.0
	Repayment of long-term debt				(1,180.3	)		(265.1	)
	Debt issuance costs				(62.8	)		(15.6	)
	Common stock dividends paid				(133.7	)		(165.0	)
	BGE preference stock dividends paid				(6.6	)		(6.6	)
	Proceeds from contract and portfolio acquisitions				2,243.1			—
	Derivative contracts classified as financing activities under SFAS No. 149				(785.3	)		(0.5	)
	Other				11.8			3.2

	Net cash (used in) provided by financing activities				(307.0	)		762.4

Net Increase in Cash and Cash Equivalents					759.4			134.8
Cash and Cash Equivalents at Beginning of Period					202.2			1,095.9

Cash and Cash Equivalents at End of Period				$	961.6		$	1,230.7



	(In millions)
Current assets	$	542.0
Noncurrent assets		63.0

Total Assets	$	605.0

Current liabilities	$	467.6
Noncurrent liabilities		479.8

Total Liabilities	$	947.4

		Power Contract Monetization VIEs		All Other VIEs		Total


		(In millions)
Total assets		$	574.0	$	322.2	$	896.2
Total liabilities			466.1		92.3		558.4
Our ownership interest			—		56.4		56.4
Other ownership interests			107.9		173.5		281.4
Our maximum exposure to loss			40.4		62.2		102.6
Carrying amount and location of variable interest on balance sheet:
	-Other investments		—		56.4		56.4



	(In millions)
Initial severance liability balance	$	10.8
Additional expense recorded in the second quarter of 2009		0.4
Amounts recorded as pension and postretirement liabilities		—

Net cash severance liability		11.2
Cash severance payments		(8.1	)
Other		—

Severance liability balance at June 30, 2009	$	3.1



	(In millions)
Liability at January 1, 2009	$	987.3
Accretion expense		36.1
Liabilities incurred		0.1
Liabilities settled		(0.3	)
Revisions to cash flows		(0.4	)
Other		(0.2	)

Liability at June 30, 2009	$	1,022.6

Six Months Ended June 30, 2009

	(In millions)
Investing activities—Contract and portfolio acquisitions	$	(866.3	)
Financing activities—Proceeds from contract and portfolio acquisitions		863.8

Net cash flows from contract and portfolio acquisitions	$	(2.5	)

Six Months Ended June 30, 2009

	(In millions)
Investing activities—Contract and portfolio acquisitions	$	(1,287.4	)
Financing activities—Proceeds from contract and portfolio acquisitions		1,379.3

Net cash flows from contract and portfolio acquisitions	$	91.9

At June 30, 2009	Adjusted Cost		Unrealized Gains		Unrealized Losses		Fair Value


	(In millions)
Money market funds	$	12.3	$	—	$	—	$	12.3
Marketable equity securities		196.0		70.3		—		266.3
Mutual fund / common collective trusts		478.5		49.6		—		528.1
Corporate debt		159.4		18.6		—		178.0
U.S. agencies		42.4		2.2		—		44.6
U.S. treasuries		19.6		0.8		—		20.4
State municipal bonds		45.3		2.8		—		48.1

Totals	$	953.5	$	144.3	$	—	$	1,097.8

	Quarter Ended June 30, 2009			Six Months Ended June 30, 2009


	(In millions)
Gross realized gains	$	4.3		$	15.2
Gross realized losses		(3.7	)		(72.0	)

Net realized gains	$	0.6		$	(56.8	)

At June 30, 2009

	(In millions)
Less than 1 year	$	11.9
1-5 years		90.7
5-10 years		93.8
More than 10 years		94.7

Total maturities of debt securities	$	291.1

	Reportable Segments

	Reportable Segments									Holding Company and Other Nonregulated Businesses
	Merchant Energy Business			Regulated Electric Business			Regulated Gas Business			Holding Company and Other Nonregulated Businesses			Eliminations			Consolidated

	(In millions)
For the quarter ended June 30,
2009
Unaffiliated revenues	$	3,045.7		$	655.7		$	111.1		$	51.6		$	—		$	3,864.1
Intersegment revenues		155.3			—			0.6			—			(155.9	)		—

Total revenues		3,201.0			655.7			111.7			51.6			(155.9	)		3,864.1
Net income (loss)		20.9			22.1			(6.2	)		(8.5	)		—			28.3
Net income (loss) attributable to common stock		4.1			19.5			(6.9	)		(8.6	)		—			8.1
2008
Unaffiliated revenues	$	4,058.3		$	448.7		$	183.1		$	66.0		$	—		$	4,756.1
Intersegment revenues		221.8			—			5.0			0.1			(226.9	)		—

Total revenues		4,280.1			448.7			188.1			66.1			(226.9	)		4,756.1
Net income (loss)		280.0			(101.7	)		(2.3	)		(1.0	)		—			175.0
Net income (loss) attributable to common stock		279.7			(104.2	)		(3.1	)		(0.9	)		—			171.5
For the six months ended June 30,
2009
Unaffiliated revenues	$	6,100.7		$	1,462.5		$	495.4		$	108.9		$	—		$	8,167.5
Intersegment revenues		379.8			—			3.2			—			(383.0	)		—

Total revenues		6,480.5			1,462.5			498.6			108.9			(383.0	)		8,167.5
Net (loss) income		(181.8	)		67.5			33.4			(10.5	)		—			(91.4	)
Net (loss) income attributable to common stock		(199.1	)		62.4			31.9			(10.6	)		—			(115.4	)
2008
Unaffiliated revenues	$	7,711.1		$	1,158.0		$	574.1		$	125.1		$	—		$	9,568.3
Intersegment revenues		516.0			0.1			10.4			0.2			(526.7	)		—

Total revenues		8,227.1			1,158.1			584.5			125.3			(526.7	)		9,568.3
Net income (loss)		352.7			(65.5	)		37.9			(0.7	)		—			324.4
Net income (loss) attributable to common stock		351.9			(70.5	)		36.3			(0.5	)		—			317.2

Facility Expiration	Facility Size		Facility Size Upon Completion of the EDF Transaction


	(In billions)
July 2012	$	3.85	$	2.32
November 2009¹		1.23		—
September 2013		0.35		—
December 2009		0.15		—

Total	$	5.58	$	2.32

	As of June 30, 2009

	Constellation Energy			BGE			Total Consolidated

	(In billions)
Credit facilities	$	5.6		$	0.4		$	6.0
Less: Letters of credit issued		(2.8	)		—			(2.8	)
Less: Cash drawn on credit facilities		—			—			—

Undrawn facilities		2.8			0.4			3.2
Less: Commercial paper outstanding		—			(0.3	)		(0.3	)

Net available facilities		2.8			0.1			2.9
Add: Cash		1.0			—			1.0
Add: EDF put arrangement		1.1			—			1.1

Net available liquidity	$	4.9		$	0.1		$	5.0

At June 30, 2009

	(In millions)
Total unrecognized tax benefits, January 1, 2009	$	189.7
Increases in tax positions related to the current year		3.0
Reductions in tax positions related to prior years		(7.8	)
Reductions in tax positions as a result of a lapse of the applicable statute of limitations		(0.8	)

Total unrecognized tax benefits, June 30, 2009¹	$	184.1

Cash Flow Hedges									Quarter Ended June 30, 2009						Six Months Ended June 30, 2009


		Amount of Derivative Gain (Loss) Recorded in AOCI

Contract type:		Quarter Ended June 30, 2009			Six Months Ended June 30, 2009			Statement of Income (Loss) Line Item	Amount of Gain (Loss) Reclassified from AOCI into Earnings			Amount of Derivative Ineffectiveness Gain (Loss) Recorded in Earnings			Amount of Gain (Loss) Reclassified from AOCI into Earnings			Amount of Derivative Ineffectiveness Gain (Loss) Recorded in Earnings

		(In millions)
Hedges of forecasted sales:								Nonregulated revenues
	Power contracts	$	100.4		$	262.2			$	(37.5	)	$	21.2		$	(129.6	)	$	81.0
	Gas contracts		7.9			(23.9	)			(0.6	)		4.5			(22.0	)		6.5
	Coal contracts		—			10.0				—			—			(229.9	)		—
	Other commodity contracts¹		(7.1	)		6.6				(0.8	)		(2.2	)		(3.6	)		(5.1	)
Interest rate contracts			—			(0.3	)			(0.2	)		—			(0.2	)		—
Foreign exchange contracts			—			0.3				—			—			(0.9	)		—

Total gains (losses)		$	101.2		$	254.9		Total included in nonregulated revenues	$	(39.1	)	$	23.5		$	(386.2	)	$	82.4

Hedges of forecasted purchases:								Fuel and purchased energy expense
	Power contracts	$	(112.8	)	$	(886.8	)		$	(611.9	)	$	(0.3	)	$	(1,038.4	)	$	(29.5	)
	Gas contracts		(21.2	)		154.5				66.7			1.9			92.7			2.6
	Coal contracts		(40.5	)		(125.1	)			(52.0	)		(1.6	)		(65.3	)		(2.9	)
	Other commodity contracts²		(3.7	)		(2.1	)			(2.7	)		—			23.1			—
Foreign exchange contracts			—			0.1				—			—			0.1			—

Total gains (losses)		$	(178.2	)	$	(859.4	)	Total included in fuel and purchased energy expense	$	(599.9	)	$	—		$	(987.8	)	$	(29.8	)

Hedges of interest rates:								Interest expense
	Interest rate contracts		—			—				(0.1	)		—			(0.2	)		—

Total gains (losses)		$	—		$	—		Total included in interest expense	$	(0.1	)	$	—		$	(0.2	)	$	—

Grand total gains (losses)		$	(77.0	)	$	(604.5	)		$	(639.1	)	$	23.5		$	(1,374.2	)	$	52.6

			As of March 31, 2010

			Assets			Liabilities

			(In millions)
Cash equivalents			$	1,325.8		$	—
Equity securities				40.3			—
Derivative instruments:
	Classified as derivative assets and liabilities:
		Current		686.0			(906.7	)
		Noncurrent		731.4			(812.9	)

		Total classified as derivative assets and liabilities		1,417.4			(1,719.6	)
	Classified as accounts receivable*			(341.4	)		—

	Total derivative instruments			1,076.0			(1,719.6	)

Total recurring fair value measurements			$	2,442.1		$	(1,719.6	)

At June 30, 2009		Level 1			Level 2			Level 3			Netting and Cash Collateral*			Total Net Fair Value


		(In millions)
Cash equivalents		$	734.0		$	12.3		$	—		$	—		$	746.3
Debt and equity securities:
	Marketable equity securities		266.3			—			—			—			266.3
	Mutual funds / common collective trusts		48.4			505.6			—			—			554.0
	Corporate debt securities		—			178.0			—			—			178.0
	U.S. Agencies		—			44.6			—			—			44.6
	U.S. Treasuries		20.4			—			—			—			20.4
	State municipal bonds		—			48.1			—			—			48.1

Debt and equity securities			335.1			776.3			—			—			1,111.4
Derivative assets			180.9			36,104.9			3,941.7			(39,287.2	)		940.3
Derivative liabilities			(160.5	)		(37,158.8	)		(4,118.2	)		39,227.2			(2,210.3	)

	Net derivative position		20.4			(1,053.9	)		(176.5	)		(60.0	)		(1,270.0	)

Total		$	1,089.5		$	(265.3	)	$	(176.5	)	$	(60.0	)	$	587.7

At June 30, 2009		Carrying Amount		Fair Value


		(In millions)
Investments and other assets—Constellation Energy		$	1,253.6	$	1,253.5
Fixed-rate long-term debt:
	Constellation Energy (including BGE)		5,974.3		5,794.1
	BGE		2,238.5		2,177.0
Variable-rate long-term debt:
	Constellation Energy (including BGE)		677.4		677.4
	BGE		—		—

At March 31, 2010		Carrying Amount		Fair Value


		(In millions)
Investments and other assets—Constellation Energy		$	220.0	$	219.8
Fixed-rate long-term debt:
	Constellation Energy (including BGE)		3,736.2		3,984.2
	BGE		2,200.1		2,312.8
Variable-rate long-term debt:
	Constellation Energy (including BGE)		544.5		544.5
	BGE		—		—

	Quarter Ended March 31,

	2010			2009

	(In millions, after-tax)
Generation	$	27.1		$	41.5
NewEnergy		104.1			(246.3	)
Regulated electric		27.2			45.4
Regulated gas		37.2			39.6
Other nonregulated		(4.3	)		0.1

Net Income (Loss)	$	191.3		$	(119.7	)

Net Income (Loss) attributable to common stock	$	191.5		$	(123.5	)

Change from prior year	$	315.0

	2010 vs. 2009


	(in millions, after-tax)
Generation gross margin	$	(132	)
NewEnergy gross margin		117
Generation operating expenses, primarily performance-based labor and benefit costs due to the deconsolidation of CENG		100
Gain on NewEnergy international coal contract assignment		38
NewEnergy hedge ineffectiveness		(6	)
Regulated businesses		(18	)
Total change inOther Items included in Operations per table below		175
All other changes		41

Total Change	$	315

	2010 vs. 2009


	(In millions)
Decrease in volume of output from nuclear generating assets due to the deconsolidation of CENG	$	(159	)
Decrease due to higher planned outages at our fossil plants		(61	)
All other		14

Total decrease in Generation revenues	$	(206	)

	2010 vs. 2009


	(In millions)
Increase in purchased energy costs due to power purchase agreement with CENG compared with nuclear fuel costs in 2009	$	160
Decrease due to higher planned outages at our fossil plants		(40	)
All other		(15	)

Total increase in Generation fuel and purchased energy expenses	$	105

	Quarter Ended June 30,			Six Months Ended June 30,

	2009 vs. 2008

	(In millions, after-tax)
Generation gross margin	$	66		$	73
Customer supply gross margin		(26	)		12
Global Commodities gross margin		(253	)		(401	)
Hedge ineffectiveness		45			96
Absence of sale of upstream gas assets		(46	)		(55	)
Credit loss—coal supplier bankruptcy		—			33
Emissions allowance write-down		13			13
Merchant interest expense		(25	)		(53	)
Regulated businesses, primarily related to absence of Maryland settlement agreement credit		120			129
Other nonregulated businesses		(9	)		(11	)
Total change in Other Items included in operations perOverview—Results table		(45	)		(283	)
All other changes		(3	)		14

Total Change	$	(163	)	$	(433	)

	2010 vs. 2009


	(In millions)
Realization of lower volumes on wholesale load	$	(503	)
Decrease in volume and contract prices related to our domestic coal operation		(115	)
Realization of lower volumes primarily due to the absence of revenues at our gas trading operation, which we divested in 2009		(73	)
Change in wholesale mark-to-market revenues due to more favorable changes in power and gas prices		33
All other		(6	)

Total decrease in NewEnergy revenues	$	(664	)

	Quarter Ended June 30,			Six Months Ended June 30,

	2009 vs. 2008

	(In millions)
Decrease in Global Commodities mark-to-market revenues due to significantly lower trading volumes and unfavorable changes in power and gas prices	$	(465	)	$	(440	)
Decrease in volume of business primarily related to our international coal and freight operation, which we have divested		(99	)		(509	)
Increase in contract prices and volume related to our domestic coal operation		85			172
Realization of lower prices and volume of business at our gas trading operation, which we have divested, and absence of revenue due to the sales of certain of our upstream gas properties in 2008		(122	)		(213	)
Realization of lower volumes on wholesale and retail load at our Global Commodities and Customer Supply operations, partially offset by higher contract prices		(496	)		(763	)
All other		18			6

Total decrease in merchant revenues	$	(1,079	)	$	(1,747	)

	Quarter Ended June 30,			Six Months Ended June 30,

	2009 vs. 2008

	(In millions)
(Decrease) increase in Global Commodities mark-to-market expenses related to international coal purchase contracts due to changes in prices and divestiture of operations	$	(61	)	$	108
Decrease in volume of business primarily related to our international coal and freight operation, which we have divested		(106	)		(439	)
Increase in contract prices and volume related to our domestic coal operation		40			120
Realization of lower volumes at our gas trading operations, which we have divested		(67	)		(143	)
Realization of lower contract prices and volumes on wholesale and retail power purchases at our Global Commodities and Customer Supply operations		(726	)		(1,194	)
All other		13			36

Total decrease in merchant energy fuel and purchased energy expenses	$	(907	)	$	(1,512	)

	2010 vs. 2009


	(In millions)
Realization of lower volumes on wholesale power purchases	$	(538	)
Decrease due to the absence of costs at our international coal and freight operation, which we divested in 2009		(129	)
Decrease in volume and contract prices related to our domestic coal operation		(116	)
Decrease in wholesale mark-to-market expenses due to the absence of losses on international coal purchase contracts, which we divested in 2009		(106	)
Realization of lower volumes primarily due to the absence of costs at our gas trading operations, which we divested in 2009		(74	)
All other		(18	)

Total decrease in NewEnergy fuel and purchased energy expenses	$	(981	)

	June 30, 2009			December 31, 2008


	(In millions)
Current Assets	$	1,036.4		$	1,465.0
Noncurrent Assets		747.2			851.8

Total Assets		1,783.6			2,316.8

Current Liabilities		1,272.8			1,241.8
Noncurrent Liabilities		937.5			1,115.0

Total Liabilities		2,210.3			2,356.8

Net Derivative Position	$	(426.7	)	$	(40.0	)

Composition of net derivative position:
Hedges	$	(1,167.9	)	$	(1,837.6	)
Mark-to-market		801.2			1,485.9
Net cash collateral included in derivative balances		(60.0	)		311.7

Net Derivative Position	$	(426.7	)	$	(40.0	)