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Response Letter

August 17, 2011

 VIA EDGAR SUBMISSION AND COURIER

 Securities and Exchange Commission

 100 F Street,
N.E.

 Washington, D.C. 20549-3561

 Attention: James
Allegretto

Re:

Exelon Corporation

Registration Statement on Form S-4

Filed June 27, 2011

File No. 333-175162

Form 10-K for Fiscal Year Ended December 31, 2010

Filed February 10, 2011

Form 8-K

Filed April 27, 2011

File No. 001-16169

 Ladies and Gentlemen:

 We are writing in response to the comments contained in the Staff’s comment letter dated July 25, 2011 (the “2011 Comment Letter”) with respect to Exelon Corporation’s (“Exelon”)
Registration Statement on Form S-4, as filed with the Securities and Exchange Commission (“Commission”) on June 27, 2011 (“Form S-4”), Form 10-K for Fiscal Year Ended December 31, 2010, as filed with the Commission on
February 10, 2011 (“2010 Form 10-K”), and Form 8-K, as filed with the Commission on April 27, 2011 (“Form 8-K”).

 For the convenience of the Staff’s review, we have set forth the comments contained in the Staff’s Comment Letter along with Exelon’s responses. All responses to this letter are provided on a
supplemental basis.

 *  *  *  *

 1

 Form S-4 Registration Statement Filed June 27, 2011

Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, page 162

 Note 5. Pro Forma Adjustments to Financial Statements, page 171

1.
 Please tell us your basis in GAAP for recognizing a regulatory asset offset for the adjustment to reflect Constellation’s third-party debt at
estimated fair value. Please include a detailed discussion of facts and circumstances supporting your conclusion including a discussion of whether and how each regulatory jurisdiction incorporate interest or other debt-related costs in base rates.
Please explain whether any of BGE’s regulatory jurisdictions utilize a hypothetical debt structure and what effect you believe it will or should have on your recording of a regulatory offset relating to debt. We may have further comment.

 Response:

Regulated utilities generally recover their long-term debt costs through a cost-of-capital component incorporated into the rates the utility
charges its customers for its services. Specifically, a utility is granted by its rate regulatory commission an allowed rate of return that is applied to the amounts the utility has prudently invested in the property, plant and equipment used
to distribute electricity or gas to its customers. This aggregate investment amount is generally referred to as the utility’s rate base.

 A utility’s revenue requirement is the total amount of revenues determined by the regulator that the utility is allowed to recover from across its customer base. A utility’s allowed revenue
requirement is generally comprised of (1) a component for recovery of the day-to-day operating and maintenance costs necessary to maintain the utility’s routine operations and (2) a component for a reasonable return on the capital
invested by the utility to serve its customers (i.e., a return on the rate base).

 The rate of return allowed by the rate regulatory
commission generally is designed to provide a fair return to debt and equity investors, and is usually based on a utility’s actual capital structure. That is, the allowed rate of return reflects a weighted average cost of capital based on
a utility’s proportionate debt and equity capitalization structure and specific allowed return rates for both debt and equity. Allowed debt returns are generally based on the actual cost of the utility’s actual outstanding
debt. The allowed rate of return may be reset annually or as part of the general rate cycle, depending on the jurisdiction and individual utility.

 Under this rate making approach, the utility’s interest expense is a direct input in the ratemaking process and the utility generally recovers the actual costs of its debt (i.e., actual interest costs based on
its outstanding debt’s stated interest rates). Fluctuations in the fair value of such debt instruments, then, generally do not impact the amount of debt costs recovered by the utility. Because there is a mechanism to estimate
allowable costs as discussed in ASC 980-10-05-3 (and further discussed in the Basis for Conclusions section of FAS 71, paragraph 57), we believe it is appropriate to offset the purchase accounting adjustments to reflect debt at fair value with the
establishment of corresponding regulatory assets or regulatory liabilities. Such accounting best reflects the true economics associated with the utility’s debt costs whereby interest expense recognized matches the actual interest being
incurred and recovered by the utility. Specifically, in periods subsequent to the application of purchase accounting, the amortization of the regulatory asset or regulatory liability will offset the amortization of the purchase accounting
adjustment to reflect debt at fair value, thereby resulting in recognition of interest expense at the actual amounts being incurred and recovered by the utility under the regulatory rate construct.

In certain jurisdictions, the determination of a utility’s authorized rate of return may assume a theoretical (or hypothetical) capital
structure—that is, a prescribed proportionate split between debt and equity rather than the utility’s actual debt to equity capital structure percentages. Usually the hypothetical capital structure is not significantly different from
the utility’s actual capital structure; and in such cases, we believe it continues to be appropriate to apply the regulatory accounting described. However, situations where the hypothetical capital structure is materially different from a
utility’s actual capital structure would require careful assessment as to whether the criteria set forth in ASC 980 are still appropriately met.

 2

 In the case of Baltimore Gas and Electric Company (BGE), the Maryland Public Service Commission (PSC)
and the Federal Energy Regulatory Commission (FERC) have allowed the utility to recover its debt costs based on its actual capital structure. For example, in its most recent March 2011 rate order, the PSC established the allowed rate of return
based on BGE’s actual capital structure as of the last day of its rate case test year (i.e., June 30, 2010). Another example comes from the FERC method for determining BGE’s transmission rates. Through its formula rate approach,
FERC utilizes the actual capital structure and the actual cost of debt to establish an allowed rate of return on BGE’s transmission rate base. As such, we believe the establishment of a regulatory asset offset to the purchase accounting
adjustment made to reflect BGE’s debt at fair value is appropriate.

2.
 Please tell us your basis in GAAP for recognizing Constellation’s regulatory assets and liabilities, particularly those not earning a return, at
carrying value as opposed to their acquisition-date fair value.

 Response:

Based on our initial review as well as on preliminary discussions with Constellation’s management, we believe there will be no significant
acquisition-date fair value adjustments required for the majority of Constellation’s regulatory assets and liabilities as they are earning a return or accruing interest at reasonable rates, respectively. However, we plan to adjust the carrying
value to fair value for Constellation regulatory assets that are not in BGE’s rate base and therefore not earning a return.

 The
regulatory assets not earning a return are a result of the deregulation of electric generation in Maryland when BGE ceased to meet the requirements for accounting for a regulated business for the previous electric generation portion of its business
and the related tax impacts. As a result, BGE wrote-off its individual, generation-related regulatory assets and liabilities. BGE established generation-related regulatory assets, a portion of which are in rate base and a portion of which are not in
rate base, to be collected through its regulated rates, which are being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. The book value of the regulatory assets was approximately $80 million
at June 30, 2011 and will be amortized through 2017. Although not significant to Exelon, we will include a fair value adjustment for these assets in the pro forma financial statements included in Amendment No. 1 to the Form S-4.

3.
 We note a number of blank spaces. Please complete the information by filling in the blanks prior to effectiveness.

Response:

 We have included in Amendment
No. 1 to the Form S-4 all omitted information other than dates and related information that are not yet determinable, such as (i) date, time and place of the special meeting, (ii) the record date for the special meeting,
(iii) the mailing date of the proxy statement/prospectus and (iv) certain information to be provided as of the record date or the last practicable date before the date of the proxy statement/prospectus.

Form 10-K for Fiscal Year Ended December 31, 2010

 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 63

 Critical Accounting Policies and Estimates, page 75

 Nuclear Decommissioning Asset Retirement
Obligations (Exelon and Generation), page 76

 3

4.
 Please tell us the escalation percentages you used to estimate future decommissioning costs for the past three years and whether you use blended escalation
factors or separate escalation factors for labor, equipment and other materials, energy, LLRW disposal and other costs. Please also tell us the indices upon which the escalation factors are based, if indices were used. In short, please show us why
your inflation assumptions related to future decommissioning costs are supportable with historical experience and similar assumptions used by other licensees.

 Response:

 We use four separate escalation factors applied to the five major cost categories to
estimate future decommissioning costs. The five major cost categories and the four indices from the U.S. Bureau of Labor Statistics used to determine the escalation rates are as follows:

•

 Labor – Employment Compensation Index, Compensation All Private Industry Workers

•

 Equipment and materials – Producer Price Index, Machinery & Equipment

•

 Energy – Producer Price Index, Fuels & Related Products & Power

•

 Burial – Consumer Price Index, Services

•

 Other – Consumer Price Index, Services

 The following table represents the long-term (30-year) escalation rates used to estimate future decommissioning costs for the past three years:

Long-Term Escalation Rates

Q3 2010 Update

Q3 2009 Update

Q3 2008 Update

Labor

2.95%

3.11%

3.38%

 Equipment and
Materials

0.47%

0.53%

0.30%

Energy

5.58%

4.43%

6.46%

 Burial &
Other

2.78%

3.02%

3.18%

 Given the rates are intended to reflect long-term cost escalation patterns, and given escalation rate forecasts
have fluctuated significantly from year-to-year, we utilize a model in which both actual historical and forecasted future escalation rates are considered in deriving the escalation rates used in our future decommissioning costs as follows:

•

 70% weighting based on the most recent 15 years of actual historical escalation experience

•

 10% weighting based on the forecasted escalation rates from two years prior

•

 10% weighting based on the forecasted escalation rates from one year prior

•

 10% weighting based on current year forecasted escalation rates

 A 70% weighting is applied to actual historical escalation rates as we believe actual changes in the various cost factors over a long duration (i.e., 15 years) are the most relevant and objectively determinable
indicators for estimating future costs. The 30% weighting applied to forecasted escalation rates is derived by equally blending the latest three years of forecasted escalation rates to take into account the short-term volatility in such forecasts
relative to the long-term nature of the decommissioning costs estimates being determined.

 We obtain the forecasted escalation rates
annually from IHS Global Insights, a third-party expert in the area of price and cost analysis. Although we have not formally benchmarked the methodology used to calculate the escalation factors with other nuclear operators, we understand that other
large nuclear operators use similar indices.

 Item 8. Financial Statements and Supplementary Data, page 150

Combined Notes to Consolidated Financial Statements, page 178

 12. Asset Retirement Obligations (Exelon, Generation, ComEd and PECO), page 260

 4

 Nuclear Decommissioning Trust Fund Investments, page 262

NRC Minimum Funding Requirements, page 264

5.
 We note that you determine the ARO using multiple scenarios where decommissioning activities are completed under three possible scenarios ranging from 10
to 70 years after the cessation of plant operations. Please tell us your consideration of disclosing:

•

 The degree to which any of the multiple scenario based cost estimates are lower than the Nuclear Regulatory Commission’s minimum formula amount, and
if so, the reasons why such estimates are lower than the NRC formula amount.

•

 The model you use and a sensitivity analysis of changes in assumptions.

 Response:

 As discussed in our response to your comments contained in the Staff’s letter
dated August 25, 2010 (“2010 Comment Letter”) with respect to Exelon’s Form 10-K for the fiscal year ended December 31, 2009, as filed with the Commission on February 5, 2010, the underlying decommissioning liability
considered in the NRC minimum funding calculation is inherently different from the corresponding decommissioning liability reflected in the GAAP ARO.

 The NRC minimum funding and GAAP ARO determinations differ primarily given disparate assumptions regarding (1) the alternative decommissioning approaches to be used and (2) the likelihood of operating the
nuclear units through an anticipated license renewal period; as well as the requirement under ASC 410-20 to escalate and discount the estimated decommissioning costs to a present value in the determination of the GAAP ARO. In response to your 2010
Comment Letter, we included incremental disclosures in Note 12, Asset Retirement Obligations (page 264), in the 2010 Form 10-K to inform the reader of the differences between the NRC minimum funding calculation and the measurement of the GAAP ARO
under ASC 410-20.

 In addition to the factors disclosed in the 2010 Form 10-K, there are also differences between the NRC minimum
funding and GAAP ARO determinations in (1) how decommissioning costs are estimated and (2) the types of decommissioning costs included in the determinations.

 Cost estimation methodology – For each unit, the NRC allows a nuclear licensee the option of determining the required minimum funding amount through either a formulaic rate or a site-specific cost
estimate. The generic NRC formulaic rate is applied as the first method to determine adequate funding assurance. If adequate funding assurance is not demonstrated using the formulaic rate, the regulations allow for a site-specific cost estimate to
be utilized to determine whether Generation is adequately funded under the NRC regulations for that particular unit. The NRC formulaic rate approach is based on generic, non-site specific decommissioning cost studies performed for the NRC in the
early 1980’s with specified static cost estimates (adjusted for inflation) based on the reactor type (PWR or BWR) and power level of the reactor.

 In its most recent minimum funding filing with the NRC, Generation applied the formulaic rate for twelve of its nineteen operating units and derived a site-specific cost estimate for the other seven units. In
contrast, the GAAP ARO is determined for each unit on a site-specific cost estimate basis (and not a generic formulaic rate approach).

The site-specific de