John R. Collins		750 E. Pratt Street
Executive Vice President		17th Floor
Chief Financial Officer and Chief Risk Officer		Baltimore, Maryland 21202-3106
		410-783-3230

September 10, 2007

By Electronic Transmission

Mr. Robert Babula

Staff Accountant

Division of Corporation Finance

Securities and Exchange Commission

100 F Street, N.E.

Washington, DC 20549

		Re:		Constellation Energy Group, Inc.
				Baltimore Gas and Electric Company
				Form 10-K for the year ended December 31, 2006
				Filed February 27, 2007
				File Nos. 1-12869 and 1-1910

Dear Mr. Babula:

This letter is in response to your letter dated August 17, 2007. For your convenience, we have restated each of your comments and followed them with our responses.

Form 10-K for the Year Ended December 31, 2006

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 30

Base Rates, page 32

1. We note your discussion of base rates which includes a profit in addition to recovering your plant investment and operating costs. Prospectively, please enhance the discussion to quantify the equity return included in base rates.

Response:

Effective with our 2007 Combined Annual Report on Form 10-K, we will expand our discussion within the Regulation by the Maryland PSC — Base Rates section of Management’s Discussion and Analysis of Financial Condition and Results of Operation (MD&A) to include disclosure of authorized equity returns included in the base rates of Baltimore Gas & Electric Company (BGE).

September 10, 2007

Critical Accounting Policies, page 34

2. None of the critical accounting policies that you include in your current disclosures include the sensitivity analysis or other quantitative information. Revise your disclosures to include sensitivity analysis and other quantitative information when it is reasonably available. You should address the questions that arise once the critical accounting estimate or assumption has been identified, by analyzing, to the extent material, such factors as how they arrived at the estimate, how accurate the estimate/assumption has been in the past, how much the estimate/assumption has changed in the past, and whether the estimate/assumption is reasonably likely to change in the future.

For additional guidance, refer to Item 303 of Regulation S-K as well as section five of the Commission’s Interpretive Release on Management’s Discussion and Analysis of Financial Condition and Results of Operation which is located on our website at: www.sec.gov/rules/interp/33-8350.htm.

Response:

In the Critical Accounting Policies section of MD&A of our 2006 Combined Annual Report on Form 10-K, we have identified three critical accounting policies:

· Accounting for Derivatives,

· Evaluation of Assets for Impairment and Other Than Temporary Decline in Value, and

· Asset Retirement Obligations.

In the following sections, we have responded to the comment above with respect to each of these three critical accounting policies.

Accounting for Derivatives

The accounting for derivatives is a critical accounting policy for several reasons, including that it requires judgment in estimating the factors used to determine fair value for those derivatives recorded at fair value, and those factors are subject to change in the future.

We describe on page 35 of our 2006 Combined Annual Report on Form 10-K the estimates we use in determining the value of derivatives. We agree that sensitivity analysis is relevant and appropriate, and we believe that the primary source of sensitivity in these estimates in our financial statements is variations in the market prices that affect the fair value of our mark-to-market energy contracts. We analyze our sensitivity to market risk, including sensitivity of mark-to-market derivatives, on pages 60-61 of our 2006 Combined Annual Report on Form 10-K, and we cross-reference that analysis on page 35 in our Critical Accounting Policies section of MD&A.

September 10, 2007

Our sensitivity analysis on pages 60-61 uses a value-at-risk calculation. We believe this measure provides an appropriate sensitivity analysis for our mark-to-market derivatives. We present this measure using several confidence levels and holding period combinations for the current and prior year. We also discuss the extent to which actual market price movements indicate that this is a statistically valid measure consistent with the confidence level selected.

Evaluation of Assets for Impairment and Other Than Temporary Decline in Value

As it relates to the impairment or other than temporary decline in value of assets, we believe the availability and relevance of sensitivity analysis or other quantitative information is event-specific as opposed to being disclosure that would be made on a continuing basis. For example, in one impairment situation there might be one or more particular assumptions used for developing future cash flows for which it would be appropriate to provide sensitivity analysis. In another, it might be appropriate to discuss management’s judgment in weighting of alternative courses of action that are available. In yet another case, there may be subjectivity around the remaining useful life of an asset. Or, at the other end of the spectrum, management may have made a decision to abandon an asset and there is no significant uncertainty that lends itself to sensitivity analysis.

In future filings, when one or more material impairment or other-than-temporary decline events have occurred, we will include appropriate sensitivity analysis or other reasonably available quantitative information when there are difficult, subjective, or complex judgments made by management with respect to underlying assumptions or other uncertainties associated with those events.

Asset Retirement Obligations

As disclosed in the Accretion Expense section of Note 1 on page 86 of our 2006 Combined Annual Report on Form 10-K, $950.4 million of our total asset retirement obligations (AROs) of $974.8 million at December 31, 2006 was associated with the decommissioning of our nuclear power plants. There are numerous key assumptions involved in estimating the future nominal cash flows of nuclear decommissioning, which, in turn, are discounted in order to develop the related ARO liability. In developing those assumptions, we consider available experience with respect to past and currently underway decommissioning efforts of others in this industry. We also utilize both internal and third party consulting expertise to develop our estimates. Because the actual decommissioning of these facilities is not expected to begin for at least 25 years and may not be completed for decades afterward, future estimates and the ultimate actual cost of decommissioning will vary from our current estimates due to changes that we presently cannot anticipate.

September 10, 2007

We utilize discrete sets of assumptions for each of our five nuclear units, located at our three nuclear facilities, and we assign relative probabilities to three alternative scenarios (i.e., sets of assumptions) for each of those units. The following are some of the more significant assumptions that are required to be made:

· decommissioning methods, technologies deployed, industry practice, and regulatory requirements,

· timing of plant shut down,

· timing of the Department of Energy (DOE) first accepting spent fuel and the amount of time required for all spent fuel to be accepted by the DOE,

· timing for completion of all decommissioning work, and

· separate cost-escalation assumptions for hazardous waste, low-level radioactive waste, labor, property taxes, and general inflation.

While we believe that our current disclosure is adequate, the inclusion of sensitivity analysis disclosure may provide additional information with respect to nuclear decommissioning AROs. Because of the number and nature of the assumptions underlying our estimate of these AROs, the long time horizons involved, and the reality that all of our assumptions are subject to uncertainty and may change over time in ways that may or may not offset each other, we do not believe it would be appropriate for us to provide sensitivity analysis for specific assumptions. For example, while changes in inflation rates may increase or decrease the estimated future nominal cash flows of decommissioning over time, the underlying economic factors affecting inflation may also produce changes in discount rates that could mitigate some or all of the impact of changes in estimated inflation rates. Similarly, while changes in regulatory requirements may increase the estimated cost of decommissioning under today’s methods, technological advances and other efficiencies may reduce the amount of inputs required, thereby mitigating the effects of regulatory changes on the decommissioning estimate.

In view of the significant number of estimates and assumptions underlying the decommissioning cost estimate and potential interrelationships between these factors, we believe it may be more meaningful to disclose a sensitivity analysis for our ARO liability as a whole. Therefore, in our Combined Quarterly Report on Form 10-Q for the Period Ended September 30, 2007, we will disclose the dollar and percentage sensitivity analysis with respect to the impact of a 10% increase or decrease in our estimate of the future nominal cash flows for nuclear decommissioning. We will disclose the pro forma impacts of this sensitivity analysis on our ARO liability and annual ARO amortization and accretion expense.

We believe that this approach is consistent with the nature of how changes in the ARO liability are determined. Those changes generally result from periodic site specific cost studies that are performed on a regular basis but less frequently than annually. These studies update all relevant inputs and assumptions based upon the most currently available information, thereby accounting for interrelationships between factors underlying multiple assumptions.

September 10, 2007

Synthetic Fuel Facilities, page 38

3. Please explain to us if idling your South Carolina facility has been given any consideration in light of the recent market price of oil. In this regard, we note your disclosure of a full phase out of the tax credit given market prices above $70 per barrel. If applicable, please supplement your response with any impairment testing that may have recently been performed.

Response:

Our current estimate for 2007 synthetic fuel tax credit phase-out of 37% (as of August 31, 2007) has not risen to a level where we would consider reducing production or idling our synthetic fuel facilities. We continuously monitor oil prices and their impact on our estimate of synthetic fuel tax credit phase-out percentage and the resulting implications for the operation of these facilities.

While NYMEX oil prices for light, sweet, crude oil for the balance of 2007 average $73.38 per barrel (as of August 31, 2007), the current NYMEX price is not necessarily indicative of the expected phase-out percentage for 2007. As explained on page 38 of our 2006 Combined Annual Report on Form 10-K, the actual 2007 oil price phase-out will be computed based on average annual wellhead oil prices for all domestic oil production as published monthly by the Energy Information Administration (EIA). For the first six months of the year (the only months published to date by the EIA), the monthly EIA wellhead price averaged $56.10 per barrel compared to average NYMEX prices for the same period of $61.61. Our current estimate of the 2007 phase-out percentage of 37% is based on actual oil prices to date as well as forward market prices and volatilities, adjusted for the relationship between historical forward prices and actual oil prices used to calculate the synthetic fuel tax credit phase-out.

With respect to the year ended December 31, 2006, during the summer of that year, oil prices rose significantly and resulted in an estimated synthetic fuel tax credit phase-out of 68% at June 30, 2006. This level of synthetic fuel tax credit phase-out indicated that there was a potential that we might not be able to recover our investments in synthetic fuel facilities. We made detailed disclosure in our Combined Quarterly Report on Form 10-Q for the Period Ended June 30, 2006 regarding potential impairment and the results of our evaluation (see pages 27-28 of that filing).

Since June 2006, we have performed impairment testing on our synthetic fuel investments on a quarterly basis. The impairment tests are based on probability weighting of various synthetic fuel tax credit phase-out and production scenarios. As of June 30, 2007, our impairment analysis indicated that we would be able to recover our investments in synthetic fuel facilities. Our current estimated phase-out of 37%, while higher than our June 30, 2007 phase-out estimate of 29%, has not risen to a level where we would consider reducing production or idling the plants. As a result, no additional impairment analysis has been performed subsequent to June 30, 2007.

September 10, 2007

We will continue to monitor the level of synthetic fuel tax credit phase-out and perform impairment analyses as new information becomes available. A future increase in synthetic fuel tax credit phase-out could result in an impairment. However, the current remaining investments related to our synthetic fuel facilities of approximately $7 million will be fully amortized by the end of 2007, concurrent with the expiration of the synthetic fuel tax credits.

Results of Operations, page 39

4. You indicate that margins were impacted by higher costs. We realize that the cost of generation has increased significantly over the recent past. It would be helpful for a reader if you specifically quantified your generation cost by fuel type, and source (e.g. the cost per megawatt for owned generation by fuel source, and the cost of purchased power). Please revise in future filings.

Response:

BGE owns no generation facilities and purchases 100% of the power it delivers to its customers through a bidding process under the supervision and subject to the approval of the Maryland Public Service Commission. Our 2006 Combined Annual Report on Form 10-K indicates that all of BGE’s purchased power costs are passed through to its customers, subject to regulatory review and approval. We discuss the issues surrounding BGE’s regulatory environment at length and in detail in our 2006 Combined Annual Report on Form 10-K. Since BGE is not subject to the risk of recovery of purchased power costs other than as a function of the regulatory process we describe, cost per megawatt for power purchased is not a factor that affects BGE’s earnings. Further, this is not a measure used by BGE’s management to operate its business, manage its risk, or evaluate its performance. For these reasons, we do not believe that presentation of this measure would provide additional information that would assist readers in understanding BGE’s results of operations from the perspective of management.

With respect to Constellation Energy’s nonregulated business, as discussed in the Business section on page 3 of our 2006 Combined Annual Report on Form 10-K, our merchant energy business integrates electric generation assets with the marketing and risk management of energy and energy-related products to wholesale and retail customers, allowing us to manage energy price risk. Accordingly, as described on page 41 of our 2006 Combined Annual Report on Form 10-K, we believe that gross margin (rather than revenues or fuel and purchased energy expenses) is more useful for assessing the profitability of our merchant energy business. Subsequent detailed discussions of the performance of the merchant energy business within MD&A focus on this measure.

September 10, 2007

While generation and purchased power cost is a component of gross margin, other factors may have as much or more impact on the level of gross margin. For example, while generation costs (such as fuel) may increase in the spot market, the results of our hedging activities may largely negate the effect of those increased costs on our gross margin. Similarly, because there is correlation in many markets between the market price for power and the market price for fuels used to generate power, changes in fuel cost do not necessarily have a direct effect on gross margin or earnings. As a result, management does not focus on generation cost by fuel type and source in evaluating performance.

Based upon the foregoing factors, we believe that our MD&A’s focus on gross margin provides readers the most relevant information to evaluate operating performance. Accordingly, we do not believe that quantifying our generation cost by fuel type and source would provide incremental information that would assist readers in understanding the results of our operations from the perspective of management.

5. You discuss the business reasons for changes in the various line items of your statements of operations. However, in circumstances where there is more than one business reason for the change, you should quantify the incremental impact of each individual business reason discussed on the overall change in the line item. For example, you indicate on page 43 various factors that caused a decrease in gross margin from your retail competitive supply accrual activities in 2005 compared to 2004. While this information is helpful, you do not quantify the extent to which income was affected by each of these reasons. Whenever possible, please quantify all line item changes with more than one business reason. Please refer to Item 303(a)(3) of Regulation S-K, Financial Reporting Codification 501.04, and SEC Release No. 33-8350.

Response:

Whenever possible, in future filings, we will quantify the extent to which individual changes contribute to an overall material change in a financial statement line item between periods.

6. Reference is also made to your disclosure on page 47 where you indicate that operating expenses increased in 2006 due to an increase of $139.2 million at your competitive supply operations primarily related to higher labor and benefit costs, although you do not quantify the incremental impact of such items.

Response:

As indicated in our response to Comment 5 above, whenever possible, in future filings, we will quantify the extent to which individual changes contribute to an overall material change in a financial statement line item between periods. As a point of clarification to your comment above, we consider “higher labor and benefit costs” to be a single business reason for the increase in operating expenses. We did not intend for “labor and benefit costs” to be considered two separate items.

September 10, 2007

Off-System Sales, page 51

7. Prospectively, please quantify the amount of margin that is being shared between shareholders and customers.

Response:

Based on the sharing arrangement authorized by the Maryland Public Service Commission, after-tax gross margin from BGE’s off-system sales of approximately $0.8 million, $0.4 million, and $0.2 million for 2006, 2005, and 2004, respectively, was retained by shareholders and thereby impacted BGE’s and our net income in those years. In the above-referenced section of our 2006 Combined Annual Report on Form 10-K, we state: “Changes in off-system sales do not significantly impact earnings.” We believe that these amounts are de minimis and on that basis do not believe that the disclosure of these amounts would provide meaningful material information beyond what is already disclosed in our Combined Annual Report on Form 10-K. However, in the future, if these amounts become material, we will include appropriate disclosure.

Contractual Payment Obligations, page 57

8. Please explain in detail what consideration you gave to including contractual payments associated with derivative instruments.

Response:

We review all of our derivatives, whether recognized in the financial statements under the provisions of SFAS No. 133 or excluded from that statement’s scope under the normal purchase normal sale exception, to determine whether they should be included in the contractual payment obligations table. Based on the criteria in the governing release, FR-67, we include all derivatives in the purchase obligations section of the table that meet the definition of a contractual purchase obligation. Thus, we include in the table all derivatives for the purchase of physical commodities where delivery of the underlying commodity is not discretionary.

By contrast, where the derivative does not require physical delivery but requires or permits financial settlement, those derivatives have been excluded from the table because they do not reflect a contractual obligation to purchase goods or services. Under such financially settling derivatives, the contract may be settled at any time at the discretion of management based upon fair value, and there is no payment obligation until the contract settles. Additionally, the settlement amount varies based upon changes in the market price of the commodity as compared to the contract price and could result in payments being made or received depending upon whether the derivative is “in the money” or “out of the money.”

For all derivatives within the scope of the requirements of FR-67 for inclusion in the table, the amount included in the table is the gross contractual payment requirements, not the fair value of the contract. The fair value may vary over time and may be an asset or a liability. However, regardless of the variation in fair value, the underlying payment obligation is based upon the interaction of the contract price and quantity, and it is this gross amount that is included in the table.

September 10, 2007

Consolidated Statements of Income, page 67

9. Please advise why you do not separately present fuel and purchased energy expenses for both your regulated and non-regulated electric operations. See Rule 5-03.2 of Regulation S-X.

Response:

We present regulated and nonregulated purchased fuel and energy (PF&E) expenses in our filings as follows:

· The regulated portion of our PF&E expenses is presented in the separate line item Electricity purchased for resale expense on the face of BGE’s Statement of Income.

· We segregate the regulated and nonregulated PF&E expenses in separate tables within the Merchant Energy and Regulated Electric Business segment discussions within MD&A on pages 41 and 48, respectively.

· We provide the amount of electricity purchased for resale by BGE from a subsidiary of Constellation Energy in Note 16—Related Party Transactions—BGE.

We do not present regulated and non-regulated PF&E expenses separately on the face of Constellation Energy’s Consolidated Statements of Income. This is because a substantial portion of BGE’s regulated PF&E expense is eliminated in consolidation (approximately 92%, 75%, and 71% in 2004, 2005, and 2006, respectively) and, as a result, we believe that separately disclosing the remaining portion that has not been eliminated in consolidation on Constellation Energy’s Consolidated Statements of Income would not be meaningful.

We believe that this presentation enables the reader of Constellation Energy’s Consolidated Statements of Income to focus on PF&E for the consolidated entity while at the same time providing relevant information about regulated PF&E in BGE’s Statement of Income, MD&A, and the notes to the financial statements.

September 10, 2007

1. Significant Accounting Policies, page 78

Revenues, page 79

10. Please explain how BG&E accounts for estimated receivables with respect to energy delivered but not yet billed at period end. To the extent applicable, please disclose the amount of unbilled receivables.

Response:

To the extent that deliveries have occurred but a bill has not been issued at the end of each month, BGE accrues an estimate of the revenues for energy delivered since the latest billings. BGE calculates the estimate based upon several factors including billings through the last billing cycle in a month, estimated volumes, estimated line loss factors, and prices in effect.

In future filings, we will include separate line items for billed and unbilled receivables on BGE’s balance sheet. At December 31, 2006, the amount of unbilled receivables included in BGE’s accounts receivable balance was $154.4 million.

State and Local Taxes, page 83

11. EITF Issue No. 06-3 was effective for interim and annual reporting periods beginning after December 15, 2006. Please note the disclosure requirements with respect to gross presentation of income taxes collected on behalf of governmental authorities.

Response:

In connection with the preparation of our 2006 Combined Annual Report on Form 10-K, we evaluated the impact of the disclosure requirements contained in EITF Issue No. 06-3 with respect to the gross presentation of taxes imposed by governmental authorities on revenue and have determined that the amount of such tax collections on revenue that we have reported on a gross basis is not material to our results of operations (i.e., less than 1% of revenues for Constellation Energy and less than 2.5% of revenues for BGE). As a result, we determined that no disclosure was necessary. In the future, if these amounts become material we will provide the required disclosures.

September 10, 2007

4. Investments, page 94

12. Please explain in detail why you have not provided summarized financial information for your equity method investments. In this regard, it appears that equity method income was material for 2004 when compared to income from continuing operations. See paragraph 20 of APB No. 18

Response:

We evaluated the significance of our equity method investments relative to the required investment, asset, and income tests provided for in Accounting Series Release (ASR) 302, Unconsolidated Subsidiaries and 50 Percent or Less Owned Persons, and determined that summarized financial information was not required for any of the three years presented in our 2006 Combined Annual Report on Form 10-K.

With respect to the $18.0 million of total equity method income we recognized in 2004, this represented only 3% of our $598.8 million of income from continuing operations before income taxes, extraordinary items, and cumulative effect of accounting changes (excluding equity earnings). In addition, during 2004 no equity method investment, individually or in combination with other equity method investments, had earnings in excess of the threshold that would require the disclosure of summarized financial information.

We will continue to monitor the significance of our equity method investments relative to the requirements of ASR 302 and provide any required disclosures.

13. Please explain to us the regulatory requirements with respect to the investment oversight of the NDT assets. In this regard, we assume a trustee is responsible for managing the trust funds; if our assumption is incorrect, please clarify. If correct, explain how you still maintain the intent and ability to retain investments which are in an unrealized loss position. Lastly, explain in detail the investments that have been in an unrealized loss position for greater than twelve months and your detailed reasoning for not recording an other than temporary impairment charge. See SAB Topic 5M.

Response:

Our nuclear decommissioning trust funds are managed by third parties who have independent discretion over purchases and sales of securities. We account for our nuclear decommissioning trust investments in accordance with FSP FAS 115-1 and FAS 124-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments and SEC SAB Topic 5M.

In late January 2007, we became aware of the SEC Staff’s interpretation that investors in nuclear decommissioning trust funds do not meet the “intent and ability” criteria under SAB Topic 5M because these investments are managed by third parties who have independent discretion over purchases and sales of securities. We believe that the implication of this interpretation is that all securities held in nuclear decommissioning trusts for which market value is below cost at a reporting date are other than temporarily impaired. As a result, we determined that $3.0 million of unrealized losses at December 31, 2006 would need to be recognized as impairments. Because of the timing of when we became aware of this interpretation, we evaluated the materiality of this item, and we concluded that it was immaterial to our financial condition and results of operations for 2006. Therefore, we determined that we would begin recognizing all unrealized losses on nuclear decommissioning trust investments at the end of each reporting period as impairments effective with the quarter ended March 31, 2007. We recorded an other-than-temporary impairment in the first quarter of 2007 consistent with SAB Topic 5M.

September 10, 2007

Investments in Variable Interest Entities, page 95

14. Please provide to us your accounting analysis used to determine you were not the primary beneficiary of the power contract monetization variable interest entities.

Response:

We present below relevant background information and our accounting analysis used to determine that we were not the primary beneficiary of the power contract monetization variable interest entities (VIEs).

Background

In March 2005, our merchant energy business closed a transaction in which we assumed from a counterparty two power sales contracts with two existing VIEs. Under the contracts, we sell power to the VIEs which, in turn, sell that power to an electric distribution utility through 2013. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. The difference between the contract prices at which the VIEs purchase and sell power is used to service the debt of the VIEs.

The market price for power at the closing of our transaction was higher than the contract price under the existing power sales contracts we assumed. Therefore, we received compensation equal to the net present value of the difference between the contract price under the power sales contracts and the market price of power at closing. We loaned a portion of the compensation received to the third-party holder of the equity in the VIEs.

If the electric distribution utility were to default under its obligation to buy power from the VIEs, the third-party equity holder could transfer its equity interests to us in lieu of repaying the loan. In this event, the third-party equity holder would absorb a portion of expected losses equal to its initial investment (i.e., its equity at risk), and we would have the right to seek recovery of our losses, if any, from the electric distribution utility.

September 10, 2007

Accounting Analysis

The variable interests for these VIEs include the third-party equity holder’s equity investment at risk, our loan to the equity holder (if the equity holder were to default on the loan and transfer its equity interests to us), and the third-party debt of the VIEs. We evaluated these variable interests to determine which party, if any, would constitute the primary beneficiary in accordance with FIN 46R, Consolidation of Variable Interest Entities, as follows:

· We projected the cash flows of the VIEs exclusive of variable interests.

· Using this information, we prepared estimates of cash flows of the VIEs reflecting the assumption that the electric distribution utility might default on its power purchase agreements (PPAs) and considering a number of possible market price scenarios that could prevail after such a default.

· The possible scenarios were then probability-weighted based on the electric distribution utility’s projected default rate reflecting the utility’s credit rating/default probability for the duration period and the resulting probability-weighted cash flows were discounted using a risk free rate based on a treasury rate which approximated the remaining term of the PPAs after the projected default.

· We then allocated the resulting expected losses in each scenario to the variable interest holders of the VIEs from the most subordinated interest to the most senior interest to determine which variable interest holder would absorb the majority of the expected losses of the VIEs.

For both VIEs, we determined that Constellation Energy was not the primary beneficiary in accordance with FIN 46R.

As a reasonableness check on our calculations, we performed sensitivity calculations to determine how high the electric distribution utility’s default rate would have to be in order to result in Constellation Energy absorbing more than 50% of the expected losses and thus become the primary beneficiary of the VIEs. We determined that the utility’s default rate would need to exceed 50% to result in Constellation Energy becoming the primary beneficiary of the VIEs. A probability of default at that level is more than 10 times greater than the actual default probability rate implied by the utility’s credit rating at the inception of the transaction.

Based on the foregoing analyses, we concluded that Constellation Energy was not the primary beneficiary of either of the power contract monetization VIEs.

September 10, 2007

12. Commitments, Guarantees, and Contingencies, page 108

68th Street Dump, page 110

15. We note your disclosure that the possible liability associated with this matter could be material to your financial results. Tell us whether you have been able to estimate a range of possible loss. Also, tell us if you will be able to recover these costs from your regulated business.

Response:

As disclosed in Note 12 to our 2006 Combined Annual Report on Form 10-K, we and 19 other potentially responsible parties agreed to identify contamination at the site and recommend clean-up options. The potentially responsible parties are conducting an investigation at the site under an agreed order with the EPA to identify and determine the scope of contamination. It is too early in the investigation to develop a range of possible loss. The potentially responsible parties also have to determine how to allocate the clean-up costs among the group and the allocation method will depend in part on the findings of the investigation. We will continue to monitor the status of the investigation and update our disclosure in future filings as appropriate.

We also have disclosed in Note 12 that BGE, our regulated business, is fully indemnified by a wholly-owned affiliate of Constellation Energy. Therefore, no costs will be recovered from our regulated business.

14. Stock Based Compensation, page 115

16. Please explain how you accounted for the excess tax benefit associated with your exercised stock options. In this regard, we note no stock compensation tax related items in your Consolidated Statements of Common Shareholders’ Equity.

Response:

We account for excess tax benefits associated with our exercised stock options in accordance with paragraphs 62 and 63 of SFAS No. 123R, Share-Based Payment. If a deduction reported on a tax return for an award of equity instruments exceeds the cumulative compensation cost for those instruments recognized for financial reporting purposes, any resulting realized tax benefit that exceeds the previously recognized deferred tax asset for those instruments (the excess tax benefit) is recognized as common shareholders’ equity. However, to the extent that the deduction reported on a tax return is less than the cumulative compensation cost for those instruments recognized for financial reporting purposes, the deficiency will first be recorded as a reduction of previously recorded tax benefits in common shareholders’ equity and second to the income statement if all tax benefits from previous awards have been utilized.

September 10, 2007

We have included the excess tax benefits associated with stock option exercises of $10.8 million, $43.4 million, and $4.1 million in 2006, 2005, and 2004, respectively, in the “Common stock issued” line of the Consolidated Statements of Common Shareholders’ Equity. This presentation is consistent with our view that these tax benefits are proceeds from the issuance of stock similar to the exercise price received from issuing the related shares to employees exercising options.

17. Please explain to us how you account for equity awards given to employees who are retirement eligible. Please revise future disclosure accordingly.

Response:

Our executive compensation plans provide for a pro-rata acceleration of vesting upon retirement. Retirement eligible employees do not receive full vesting acceleration upon retirement, but rather are only entitled to receive the portion of the award that has been earned for service performed prior to retirement at the point in time when they retire. As a result, we accrue compensation expense ratably as awards vest, including awards granted to employees who are retirement eligible. Therefore, we do not believe adding separate disclosure about equity awards granted to retirement eligible employees would provide meaningful information beyond what is already disclosed in our 2006 Combined Annual Report on Form 10-K.

18. Prospectively, please disclose the tax benefit recognized for your restricted stock awards. See paragraph A240g.1 of SFAS No. 123(R).

Response:

Effective with our 2007 Combined Annual Report on Form 10-K, we will begin disclosing the tax benefit recognized for restricted stock awards.

Exhibit 12—Ratio of Earnings to Fixed Charges

19. Please note that capitalized interest included in fixed charges should exclude AFUDC. Please refer to Item 503(d) of Regulation S-K.

Response:

Our Computation of Ratio of Earnings to Fixed Charges in Exhibit 12 reflects gross fixed charges, and thus we have not reduced our fixed charges by the allowance for funds used during construction (AFUDC) consistent with the requirements of Item 503(d) of Regulation S-K. Following is an explanation of our presentation.

September 10, 2007

In our Consolidated Statements of Income on page 67 of our 2006 Combined Annual Report on Form 10-K, we present fixed charges beginning with the gross interest expense amount and then reduce that amount by the portion of our interest charges that is capitalized (including the borrowed funds portion of AFUDC), in order to arrive at the net fixed charges expense included in earnings for each year presented. This compares to our presentation of the Computation of Ratio of Earnings to Fixed Charges on Exhibit 12, which begins with a net interest expense amount to which we add back capitalized interest and AFUDC to arrive at a gross fixed charge amount.

While our computations are consistent with the requirements of Item 503(d) of Regulation S-K, in order to improve the transparency of our disclosure for Exhibit 12, in future filings, we will modify the following line item descriptions in our Computation of Ratio of Earnings to Fixed Charges by adding the wording in bolded text below:

· “Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness, net of amounts capitalized”—This will indicate to the reader that we are beginning the calculation with a net interest amount.

· “Capitalized Interest and Allowance for Funds Used During Construction”—This will clarify that we are adding back all of our capitalized interest in order to arrive at a gross fixed charges number that has not been reduced by AFUDC.

In connection with our responses to your letter, Constellation Energy Group, Inc. acknowledges that:

· the company is responsible for the adequacy and accuracy of the disclosure in its filings;

· the Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

· the company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under federal securities laws of the United States.

* * * * *

Please feel free to contact me if you have any questions.

Sincerely,

/s/ John R. Collins

John R. Collins