Baltimore Gas & Electric 8-K Announces Plans to Raise Dividend

Earnings Conference Call

4

th

Quarter 2015

February 3, 2016

Exhibit 99.2

2

Q4 2015  Earnings Release Slides

Cautionary Statements Regarding Forward-Looking Information

This presentation contains certain forward-looking statements within the meaning of

the Private Securities Litigation Reform Act of 1995, that are subject to risks and

uncertainties. The factors that could cause actual results to differ materially from the

forward-looking statements made by Exelon include those factors discussed herein, as

well as the items discussed in (1)  Exelon’s 2014 Annual Report on Form 10-K in (a)

ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial

Condition and Results of Operations and (c) ITEM 8. Financial Statements and

Supplementary Data: Note 22; (2) Exelon’s Third Quarter 2015 Quarterly Report on

Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial

Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and

Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial

Statements: Note 19; and (3) other factors discussed in filings with the SEC by Exelon.

Readers are cautioned not to place undue reliance on these forward-looking

statements, which apply only as of the date of this presentation. Exelon does not

undertake any obligation to publicly release any revision to its forward-looking

statements to reflect events or circumstances after the date of this presentation.

3

Q4 2015  Earnings Release Slides

Delivering Value to Shareholders Through a Defined Capital

Allocation Policy

•

Our strong balance sheet underpins our capital allocation policy

•

Capital

decisions

are

made

to

maximize

value

to

our

customers

and

shareholders

•

We are harvesting free cash flow from Exelon Generation to:

–

First, invest in utilities where we can earn an appropriate return,

–

Invest in contracted assets where we can meet return thresholds,

and/or

–

Return capital to shareholders by retiring debt, repurchasing our

shares, or increasing our dividend

•

We are committed to maintaining an attractive dividend

•

Our board has approved a policy to raise our dividend 2.5% each year

for

the

next

three

years,

beginning

with

the

June

2016

dividend

(1)

(1) Quarterly dividends are subject to declaration by the board of directors.

4

Q4 2015  Earnings Release Slides

•

1

st

Quartile SAIFI performance

•

1

st

Quartile CAIDI performance

•

1

st

Quartile Customer Satisfaction –

best ever scores at ComEd and BGE

Strong

Financial

Performance

Leading

Operational

Excellence

Positive

Regulatory

Outcomes

•

1

st

Quartile SAIFI performance

•

1

st

Quartile CAIDI performance

•

1

st

Quartile Customer Satisfaction

•

Improve PHI operational performance

•

Unanimous approval of PECO’s rate

case settlement and Long Term

Infrastructure Improvement Plan

•

4

th

year of constructive outcomes in

ComEd’s

formula rate filings

•

Close PHI transaction

•

BGE rate case decision in June

•

ComEd formula rate filing in April

•

Develop and implement regulatory

strategies for PHI

Exelon Utilities –

Operational Excellence Driving Strong

Financial Performance and Positive Regulatory Outcomes

2015 Results

2016 Goals

•

Exceeded $1B in operating net income

•

Invested $3.7B to make the grid

smarter, more reliable, and provide

better services to customers

•

Quickly integrate PHI to drive synergies

and financial results

•

Invest $3.95B in capital across our

three utilities and additional $1.38B at

PHI ($18B over the next 5 years, $25B

including PHI)

•

Improve system infrastructure

•

Better customer experience

5

Q4 2015  Earnings Release Slides

World Class Operational Performance

2016 Goals

Industry Leading Load Serving Business

•

Full-year Nuclear Capacity Factor: 93.7%

•

Best average refueling outage duration since

2002: 22 days

•

Full-year Power dispatch match: 98.6%

•

Full-year Renewables energy capture: 95.5%

•

Generation to Load matching strategy

meaningfully contributed to 2015 earnings

•

Industry Leading Load Serving Business:

•

Served 195 TWhs

of wholesale and retail

load –

40 TWhs

more than in 2014

•

~ 80% power renewal rate

•

~30% new customer win rate

•

Increased our delivered retail gas by 40%

to 710 BCF

•

>90% gas retention rate

•

Continue to be best in class in operational

performance across the generation fleet

•

Execute on 350MW of contracted renewable

projects (Michigan Wind 3 & Bluestem Wind)

•

Achieve target of serving 210 TWhs

of wholesale

and retail load

•

Achieve proper valuation for our nuclear

generation assets that rewards their carbon free

footprint

210

180

155

195

155

2016

2015

(1)

2014

Target

Actual

Delivering on electric load serving targets and

poised to continue growth

Exelon

Generation

Delivered

Strong

Operational

and

Financial

Performance in 2015

(1) 2015 target includes 15 TWhs from the Integrys  acquisition

(TWhs)

6

Q4 2015  Earnings Release Slides

($0.13)

$1.40

$0.48

$0.43

$0.31

PECO

ExGen

ComEd

BGE

HoldCo

ExGen

ComEd

PECO

BGE

2016 Guidance

$2.40 -

$2.70

(2)

~($0.05)

$1.25 -

$1.35

$0.50 -

$0.60

$0.40 -

$0.50

$0.25 -

$0.35

2015 Actual

$2.49

(1)

HoldCo

2016 Adjusted Operating Earnings Guidance

Expect

Q1

2016

Adjusted

Operating

Earnings

of

$0.60

-

$0.70

per

share

Key Year-Over-Year Drivers

•

BGE: higher O&M for storms

and bad debt, partially offset

by higher distribution rates

•

PECO:  higher distribution

rates, partially offset by

higher O&M for storms and

bad debt

•

ComEd: increased capital

investments in distribution

and transmission

•

ExGen: normalized load

optimization in 2016

(1)

2015 results based on 2015 average outstanding shares of 893M. Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-

GAAP) operating EPS to GAAP EPS.

(2)

2016 earnings guidance based on expected average outstanding shares of 890Mand assumes that equity and debt issued for Pepco Holdings acquisition is unwound in2016. Earnings

guidance for OpCos may not add up to consolidated EPS guidance. Refer to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

7

Q4 2015  Earnings Release Slides

Key Financial Metrics Impacted by Bonus Depreciation

2016

11.8

2018

13.6

2017

12.8

Distribution

Transmission

Standalone Bonus Depreciation Impacts

Updated

Exelon

Utilities

Net

Income

($M)

(3)

Updated

ComEd

Rate

Base

($B)

(4)

$1,400

$1,300

$0

$1,200

$1,100

$1,325

2016

$1,250

2018

$1,400

2017

$1,250

$1,175

$1,100

2016

2017

2018

Earnings per

Share

(1)

($0.09)

($0.11)

($0.06)

Cash Flow

(2)

$625M

$675M

$600M

•

Bonus Depreciation reduces earnings in 2016-2018

primarily due to its impact on ExGen’s ability to take

the Domestic Production Activities Deduction and

impacts to ComEd’s rate base

•

No re-investment of the incremental cash is

contemplated in the earnings impacts listed

Exelon Utilities projected average earnings growth is

still in the 7-9% range per year from 2015-2018

Exelon Utilities Rate Base growing by $5.5B, more

than 25% from 2015 to 2018, despite impact of

bonus depreciation

8.6

9.3

10.0

3.2

3.5

3.6

(1)

2016: ExGen ($0.06), ComEd ($0.03); 2017: ExGen ($0.07), ComEd ($0.04); 2018: ComEd ($0.05), BGE ($0.01), PECO ($0.01), ExGen $0.01

(2)

Numbers rounded to nearest $25M

(3)

Does not include PHI net income and represents adjusted (non-GAAP) operating earnings.  Refer to slide 38 for a list of adjustments from GAAP EPS to adjusted (non-GAAP)

operating earnings.

(4)

Rate base represents end-of-year.  Numbers may not add due to rounding

8

Q4 2015  Earnings Release Slides

Maintaining Investment Grade Credit Ratings is a Top

Financial Priority

Current

Ratings

(2)(3)

ExCorp

ComEd

PECO

BGE

ExGen

Moody’s

Baa2

A2

Aa3

A3

Baa2

S&P

BBB-

A-

A-

A-

BBB

Fitch

BBB+

A-

A

A-

BBB

ExGen

Debt/EBITDA Ratio

(5)

Exelon and ExGen

S&P FFO/Debt %

(1)

•

Key credit metrics expected to remain above

target after including PHI

(4)

Credit Ratings by Operating Company

ExGen

Free Cash Flow 2016-2018 ($M)

(6)

~$3,200

~$5,350

($1,350)

Committed

Non-Contracted

Generation

Growth CapEx

($800)

Cumulative ExGen

FCF 2016-18

Available Free

Cash Flow

Committed

Contracted

Generation

Growth CapEx

3.2x

3.0x

2.3x

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

2018

2017

2016

~$4,150

EEI

Disclosure

~$2,700

EEI

Disclosure

0%

10%

20%

30%

40%

50%

2016

2017

2018

Exelon Target (22%)

Exelon

ExGen

ExGen Target (27%)

(1)

Metrics exclude PHI and financing associated with PHI. Due to ring-fencing, S&P deconsolidates BGE's financial profile from Exelon and analyzes it  solely as an equity investment

(2)

Current senior unsecured ratings as of 2/2/2016 for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd and PECO

(3)

All ratings have “Stable” outlook, except for at Fitch, which has ComEd on “Positive” and Exelon on “Ratings Watch Negative,” and Moody’s, which has ComEd on “Positive” outlook

(4)

Exelon Consolidated and ExGen thresholds based on the S&P Exelon Corp and ExGen Summary Reports published on August 5, 2015.  On a combined basis with PHI, the consolidated threshold is 18%

(5)

Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA. EBITDA, a non-GAAP measure, is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel

amortization expense.

(6)

Free Cash Flow = Adjusted Cash Flow from Operations less Base CapEx and Nuclear Fuel.  Free Cash Flow is midpoint of a range based on December 31, 2015 market prices. Adjusted Cash Flow From Operations (non-

GAAP) primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures.  Includes an extension of bonus depreciation. Does not include impacts of PHI

9

Q4 2015  Earnings Release Slides

Cost Management Initiative Update

•

Cost savings of $350M have been identified and incorporated into current long range

plan, reflecting our high level of confidence in achieving the reductions

•

Additional $50 million of nuclear fuel savings already reflected in the hedge disclosure

•

Savings to be achieved at:

o

Exelon Generation -

$175M

o

Corporate Shared Services -

$175M

•

Approximately $100M of savings coming from Information Technology organization

•

Remaining savings split among our centralized Corporate functions (e.g. Finance,

Legal, Supply, and Human Resources)

•

Savings to be allocated roughly 50% to Exelon Generation and 50% to Exelon

Utilities

•

Run-rate savings impact on EPS remains within range communicated at EEI  ($0.13 –

$0.18)

(1)

•

~35% of run-rate savings will be achieved by end of 2016

Our enterprise-wide O&M CAGR over the 2015 to 2018 period will be negative with a (1.0%)

CAGR at Exelon Generation

(1)

Based on projected 2018 share count of 965M shares, which assumes PHI merger closes

10

Q4 2015  Earnings Release Slides

Adjusted O&M Forecast

(2)

•

2016 forecast of $7.18B

(1)

•

Expect CAGR of ~(0.5)% for 2015-2018

$4,475

$1,275

$775

$750

$4,675

$1,300

$675

$675

ComEd

ComEd

BGE

HoldCo

HoldCo

PECO

ExGen

2016 Guidance

ExGen

BGE

PECO

$7,175

$7,250

-$75

2015 Actual

-$100

Key Year-over-Year Drivers

(2)

•

Inflation:  $150M

•

PECO & BGE Storm Costs: $50M

•

Utility Bad Debt Costs:  $50M

•

Baltimore City Conduit Fee

(3)

:  $25M

•

Pension/OPEB:  ($75M)

•

Fewer Nuclear Outages:  ($75M)

•

Cost Management Initiative:

($125M) 

(1)

Refer to the Appendix for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M.  Further, the Utilities adjusted O&M excludes regulatory O&M costs that are P&L neutral. ExGen adjusted

O&M excludes direct cost of sales for certain Constellation businesses, P&L neutral decommissioning costs and the impact from O&M related to variable interest entities.

(2)

All amounts rounded to the nearest $25M

(3)

The Baltimore City Board of Estimates' decision to more than triple the lease fee on BGE’s approximately 12 million linear feet of electric cable in the City-owned conduit system became

effective in Q4 2015.

11

Q4 2015  Earnings Release Slides

Exelon Generation: Gross Margin Update

1)

Gross margin categories rounded to nearest $50M

2)

Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and

fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon

Nuclear Partners, operating services agreement with Fort Calhoun and variable interest

entities. Total Gross Margin is also net of direct cost of sales for certain Constellation

businesses.  See Slide 29

for a Non-GAAP to GAAP reconciliation of Total Gross Margin.

3)

Excludes EDF’s equity ownership share of the CENG Joint Venture

4)

Mark-to-Market of Hedges assumes mid-point of hedge percentages

•

Ginna

RSSA reflected in gross margin updates

•

Behind ratable hedging position reflects the fundamental upside we see in power prices

•

Generation ~37-40% open in 2017

•

Power position ~5-8% behind ratable, considering cross-commodity hedges

Recent Developments

Gross Margin Category ($M)

(1)

2016

2017

2018

2016

2017

2018

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

$5,200

$5,800

$6,150

$(450)

-

$50

Mark-to-Market of Hedges

(3,4)

$1,700

$800

$250

$500

$50

-

Power New Business / To Go

$450

$800

$1,000

$(50)

-

-

Non-Power Margins Executed

$250

$150

$100

$50

$50

$50

Non-Power New Business / To Go

$200

$300

$400

$(50)

$(50)

$(50)

Total Gross Margin

(2)

$7,800

$7,850

$7,900

-

$50

$50

December 31, 2015

Change from Sept. 30, 2015

12

Q4 2015  Earnings Release Slides

Exelon Generation Disclosures

December 31, 2015

13

Q4 2015  Earnings Release Slides

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

Strategic Policy Alignment

•Aligns hedging program with

financial policies and financial

outlook

•Establish minimum hedge targets

to meet financial objectives of the

company (dividend, credit rating)

•Hedge enough commodity risk to

meet future cash requirements

under a stress scenario

Three-Year Ratable Hedging

•Ensure stability in near-term cash

flows and earnings

•Disciplined approach to hedging

•Tenor aligns with customer

preferences and market liquidity

•Multiple channels to market that

allow us to maximize margins

•Large open position in outer years

to benefit from price upside

Bull / Bear Program

•Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

Exercising Market Views

Purely ratable

Actual hedge %

Market views on timing, product

allocation, and regional spreads

reflected in actual hedge %

High End of Profit

Low End of Profit

% Hedged

Open Generation

with LT Contracts

Portfolio Management &

Optimization

Portfolio Management Over Time

Align Hedging & Financials

Establishing Minimum Hedge Targets

Credit Rating

Capital &

Operating

Expenditure

Dividend

Capital

Structure

14

Q4 2015  Earnings Release Slides

Components of Gross Margin Categories

Open Gross

Margin

•Generation Gross

Margin at current

market prices,

including capacity

and ancillary

revenues, nuclear

fuel amortization

and fossils fuels

expense

•Exploration and

Production

(4)

•Power Purchase

Agreement (PPA)

Costs and

Revenues

•Provided at a

consolidated level

for all regions

(includes hedged

gross margin for

South, West and

Canada

(1)

)

MtM

of

Hedges

(2)

•Mark-to-Market

(MtM) of power,

capacity and

ancillary hedges,

including cross

commodity, retail

and wholesale load

transactions

•Provided directly at

a consolidated

level for five major

regions. Provided

indirectly for each

of the five major

regions via

Effective Realized

Energy Price

(EREP), reference

price, hedge %,

expected

generation

“Power” New

Business

•Retail, Wholesale

planned electric

sales

•Portfolio

Management new

business

•Mid marketing new

business

“Non-Power”

Executed

•Retail, Wholesale 

executed gas sales

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

“Non-Power”

New Business

•Retail, Wholesale

planned gas sales

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

(5)

Margins move from “Non power new business” to

“Non power executed” over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

(1) Hedged gross margins for South, West & Canada regions will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region

(2) MtM of hedges provided directly for the five larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh 

(3) Proprietary trading gross margins will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion

(4) Gross margin for these businesses are net of direct “cost of sales”

(5) Margins for South, West & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin

15

Q4 2015  Earnings Release Slides

ExGen Disclosures 

(1)

Gross margin categories rounded to nearest $50M  

(2)

Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power

and fuel expense, excluding revenue related to decommissioning, gross receipts tax,

Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable

interest entities. Total Gross Margin is also net of direct cost of sales for certain

Constellation businesses.  See Slide 29 for a Non-GAAP to GAAP reconciliation of Total

Gross Margin.

(3)

Excludes EDF’s equity ownership share of the CENG Joint Venture

(4)

Mark-to-Market of Hedges assumes mid-point of hedge percentages

(5)

Based on December 31, 2015 market conditions

Gross Margin Category ($M)

(1)

2016

2017

2018

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$5,200

$5,800

$6,150

Mark-to-Market of Hedges

(3,4)

$1,700

$800

$250

Power New Business / To Go

$450

$800

$1,000

Non-Power Margins Executed

$250

$150

$100

Non-Power New Business / To Go

$200

$300

$400

Reference Prices

(5)

2016

2017

2018

Henry Hub Natural Gas ($/MMbtu)

$2.49

$2.79

$2.91

Midwest: NiHub ATC prices ($/MWh)

$28.46

$29.23

$29.22

Mid-Atlantic: PJM-W ATC prices ($/MWh)

$34.51

$35.22

$34.16

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$4.79

$4.66

$4.49

New York: NY Zone A ($/MWh)

$31.82

$34.52

$33.60

New England: Mass Hub ATC Spark Spread($/MWh)

ALQN Gas, 7.5HR, $0.50 VOM

$9.60

$11.32

$9.71

$7,800

$7,850

$7,900

Total Gross Margin

(2)

16

Q4 2015  Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2016

2017

2018

Exp. Gen (GWh)

(1)

199,900

206,500

207,400

Midwest

97,300

96,400

96,800

Mid-Atlantic

(2)

63,600

61,600

60,700

ERCOT

17,400

26,500

31,500

New York

(2)

9,300

9,200

9,100

New England

12,300

12,800

9,300

% of Expected Generation Hedged

(3)

90%-93%

60%-63%

28%-31%

Midwest

88%-91%

55%-58%

21%-24%

Mid-Atlantic

(2)

91%-94%

64%-67%

35%-38%

ERCOT

98%-101%

67%-70%

32%-35%

New York

(2)

83%-86%

71%-74%

41%-44%

New England

94%-97%

49%-52%

16%-19%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$34.50

$33.50

$33.00

Mid-Atlantic

(2)

$47.00

$46.00

$42.50

ERCOT

(5)

$11.00

$8.00

$3.50

New York

(2)

$58.50

$44.50

$38.00

New England

(5)

$20.50

$14.50

$7.00

(1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated

dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected

generation assumes 12 refueling outages in 2016, 15 in 2017, and 14 in 2018 at Exelon-operated nuclear plants, and Salem.  Expected generation assumes capacity factors

of  94.1%, 93.4% and 93.7% in 2016, 2017 and 2018 respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2017 and 2018 do

not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Excludes EDF’s equity ownership share

of CENG Joint Venture. (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation.  Includes all hedging products, such as wholesale

and retail sales of power, options and swaps.  (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has

been hedged.  It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin.

It excludes uranium costs and RPM capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load

obligations.  It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges.

(5) Spark spreads shown for ERCOT and New England.

17

Q4 2015  Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

(1)

Based on December 31, 2015 market conditions and hedged position; Gas price sensitivities are based on an assumed gas-power relationship derived from an internal model

that is updated periodically; Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant; Due to correlation of

the various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when

correlations between the various assumptions are also considered; Sensitivities based on commodity exposure which includes open generation and all committed transactions;

Excludes EDF’s equity share of CENG Joint Venture 

Gross Margin Sensitivities (With Existing Hedges)

(1)

2016

2017

2018

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$10

$380

$695

-

$1/Mmbtu

$(5)

$(380)

$(695)

NiHub ATC Energy Price

+ $5/MWh

$55

$225

$380

-

$5/MWh

$(50)

$(220)

$(380)

PJM-W ATC Energy Price

+ $5/MWh

$15

$100

$200

-

$5/MWh

$(10)

$(110)

$(205)

NYPP Zone A ATC Energy Price

+ $5/MWh

$5

$15

$25

-

$5/MWh

$(5)

$(15)

$(25)

Nuclear Capacity Factor

+/-

1%

+/-

$40

+/-

$40

+/-

$40

18

Q4 2015  Earnings Release Slides

ExGen Hedged Gross Margin Upside/Risk

$8,050

$7,500

$8,800

$7,100

(1)

(2)

Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions

(3)

Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear

Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses.  See Slide

29

for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture.

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

11,000

2016

2017

2018

$9,750

$6,550

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is

sold into the spot market; Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and

potential modeling changes; These ranges of approximate gross margin in 2017 and 2018 do not represent earnings guidance or a forecast of future results as Exelon has not completed

its planning or optimization processes for those years; The price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options

as of December 31, 2015

19

Q4 2015  Earnings Release Slides

Illustrative Example of Modeling Exelon Generation                  

2017 Gross Margin

(1)

Mark-to-market rounded to the nearest $5 million

(2)

Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear

Row

Item

Midwest

Mid-Atlantic

ERCOT

New York

New England

South, West &

Canada

(A)

Start with fleet-wide open gross margin

(B)

Expected Generation (TWh)

96.4

61.6

26.5

9.2

12.8

(C)

Hedge % (assuming mid-point of range)

56.5%

65.5%

68.5%

72.5%

50.5%

(D=B*C)

Hedged Volume (TWh)

54.5

40.3

18.2

6.7

6.5

(E)

Effective Realized Energy Price ($/MWh)

$33.50

$46.00

$8.00

$44.50

$14.50

(F)

Reference Price ($/MWh)

$29.23

$35.22

$4.66

$34.52

$11.32

(G=E-F)

Difference ($/MWh)

$4.27

$10.78

$3.34

$9.98

$3.18

(H=D*G)

Mark-to-market value of hedges  ($ million)

$235

$435

$60

$65

$20

(I=A+H)

Hedged Gross Margin ($ million)

(J)

Power New Business / To Go ($ million)

(K)

Non-Power Margins Executed ($ million)

(L)

Non-Power New Business / To Go ($ million)

(N=I+J+K+L)

Total Gross Margin

$150

$300

$7,850 million

$5.8 billion

$6,600

$800

Partners operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses.  See Slide 29

for a Non-GAAP to GAAP reconciliation of Total Gross Margin.

(1)

(2)

20

Q4 2015  Earnings Release Slides

Additional Disclosures

21

Q4 2015  Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key Drivers –

4Q15

(2)

vs. 4Q14

:

BGE

(+0.02):

•

Increased revenues due to increased distribution rates and

transmission earnings: $0.02

PECO (-0.02):

•

Unfavorable weather (RNF): $(0.03)

•

Decreased uncollectible accounts expense: $0.01

ComEd

(+0.00):

•

Unfavorable weather and volume

(3)

: $(0.02)

•

Increased distribution

(3)

and transmission earnings due to

increased capital investments: $0.02

4Q 2015

$0.26

$0.09

$0.09

$0.08

4Q 2014

$0.26

$0.09

$0.11

$0.06

BGE

ComEd

Numbers may not add due to rounding.

(1)

(2)

(3)

PECO

Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

There is a $(0.01) share differential impact spread across the utilities in Q4 2015.

Due to the distribution formula rate, changes in ComEd’s earnings are driven primarily by changes in 30-year U.S. Treasury rates  (inclusive  of ROE), rate base and capital structure

in addition to weather, load and changes in customer mix.

22

Q4 2015  Earnings Release Slides

ExGen Adjusted Operating EPS Contribution

(1)

$0.15

Q4

$0.27

2015

2014

Numbers may not add due to rounding

(1)

(excludes Salem)

Q4

2014 Actual

Q4

2015

Actual

Planned Refueling Outage

Days

97

103

Non-refueling Outage Days

8

21

Nuclear Capacity Factor

94.8%

93.3%

Key Drivers –

Q4 2015 vs. Q4 2014

ExGen

(-0.12):

•

Increased costs primarily due to timing of nuclear projects: $(0.03)

•

Unfavorable impact associated with nuclear refueling outages:

$(0.05)

•

Higher depreciation costs primarily due to increased nuclear

decommissioning amortization and ongoing capital expenditures:

$(0.02)

•

Favorable settlement of certain state income tax positions: $0.04

•

Other: $(0.04)

•

Share differential: $(0.02)

Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

23

Q4 2015  Earnings Release Slides

2016

(4)(5)

$0.50 -

$0.60

Other

($0.02)

($0.01)

Depreciation &

Amortization

($0.05)

O&M

(3)

$0.01

RNF

(2)

2015

(1)

ComEd Adjusted Operating EPS Bridge 2015 to 2016

Note: Drivers add up to mid-point of 2016 adjusted operating EPS range

(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(2) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense.

(3) O&M excludes regulatory items that are P&L neutral.

(4) Shares Outstanding (diluted) are 893M in 2015 and 890M in 2016. Refer to slide 38 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(5) Guidance assumes an effective tax rate for 2016 of 39.6%.

Interest

$0.07 Distribution

$0.06 Transmission

$0.01 Weather

$0.01 Pension/OPEB

$0.01 Storm Costs

($0.01) Inflation

$0.14

$0.48

24

Q4 2015  Earnings Release Slides

2016

(4)(5)

$0.40 -

$0.50

Other

($0.01)

O&M

(3)

($0.04)

RNF

(2)

PECO Adjusted Operating EPS Bridge 2015 to 2016

Note: Drivers add up to mid-point of 2016 adjusted operating EPS range

(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(2) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense.

(3) O&M excludes regulatory items that are P&L neutral.

(4) Shares Outstanding (diluted) are 893M in 2015 and 890M in 2016. Refer to slide 38 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(5) Guidance assumes an effective tax rate for 2016 of 26.9%.

2015

(1)

$0.08    Electric Distribution Rate Case

($0.01)   Weather

($0.01)   Weather Normal RNF

($0.02)   Weather Related (Storm ($0.01, Bad Debt ($0.01))

($0.01)   Rate Case Related (Veg. Mgmt. & Cap Settlement)

($0.01)   Inflation

$0.07

$0.43

25

Q4 2015  Earnings Release Slides

O&M

(3)

$0.01

RNF

(2)

2015

(1)

2016

(4)(5)

$0.25 -

$0.35

Other

BGE Adjusted Operating EPS Bridge 2015 to 2016

($0.02) Storm Costs

($0.02) Bad Debt

($0.02) Baltimore City Conduit Fee

$0.02 Pricing/Mix

$0.02 Transmission

Note: Drivers add up to mid-point of 2016 adjusted operating EPS range.

(1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

(2) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense.

(3) O&M excludes regulatory items that are P&L neutral.

(4) Shares Outstanding (diluted) are 893M in 2015 and 890M in 2016. Refer to slide 38 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(5) Guidance assumes an effective tax rate for 2016 of 39.5%.

$0.04

$(0.06)

$0.31

26

Q4 2015  Earnings Release Slides

$1.25 -

$1.35

2016

(5)(6)

2015

(1)

($0.04)

Gross Margin

(2)

O&M

(3)

($0.09)

Other

Depreciation &

Amortization

(4)

($0.08)

ExGen Adjusted Operating EPS Bridge 2015 to 2016

Note: Drivers add up to mid-point of 2016 adjusted operating EPS range.

(1)

Refer

to

the

Earnings

Release

Attachments

for

additional

details

and

to

the

Appendix

for

a

reconciliation

of

adjusted

(non-GAAP)

operating

EPS

to

GAAP

EPS.

(2)

Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services

agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses.  See Slide 29 for a Non-GAAP to GAAP reconciliation of Total Gross

Margin.

(3)

O&M excludes items that are P&L neutral (including decommissioning  costs and variable interest entities) and direct cost of sales for certain Constellation businesses.

(4)

Depreciation & Amortization excludes cost of sales for certain Constellation businesses, which are included in gross margin

(5)

Shares Outstanding (diluted) are 893M in 2015 and 890M in 2016.  Refer to slide 38 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(6)

Guidance assumes an effective tax rate for 2016 of 34%.

($0.13) Normalized load optimization in 2016

$0.05 Unplanned Generation Outages

$0.02 Capacity Revenues

$0.02 Higher Load Volumes

($0.06) Capital placed in service

($0.03) Decom Asset Retirement

Cost Depreciation

$0.06 Employee Benefit Costs

$0.06 Cost Management Savings

$0.05 Nuclear outages (2 less in 2016)

$0.02 Pension/OPEB

($0.07) Inflation

($0.02) Decom Asset Retirement Obligation

($0.05) Decrease in DPAD and the

absence of favorable state settlements

partially offset by an increase in tax

credits

($0.04) Decom, primarily unregulated

realized gains

($0.01) Interest

$0.02 Other

$0.11

$1.40

27

Q4 2015  Earnings Release Slides

2016 Projected Sources and Uses of Cash

(1)

All amounts rounded to the nearest

$25M. Figures may not add due to

rounding.

(2)

Excludes counterparty collateral activity.

(3)

Adjusted Cash Flow from Operations

(non-GAAP) primarily includes net cash

flows from operating activities and net

cash flows from investing activities

excluding capital expenditures.

(4)

Figures reflect cash CapEx

and CENG

fleet at 100%

(5)

Other Financing primarily includes

expected changes in short-term debt

and tax sharing from the parent.

(6)

Acquisitions and Divestitures and Equity

Investments previously captured in

Adjusted Cash Flow from Operations

(7)

Dividends are subject to declaration by

the Board of Directors.

(8)

Includes cash flow activity from Holding

Company, eliminations, and other

corporate entities.

Consistent and reliable free cash flows

Enable growth & value creation

Supported by a strong balance sheet

Strong balance sheet enables flexibility to

raise and deploy capital for growth

Exelon intends to return capital to

shareholders and bondholders, if the

merger is not approved

Operational excellence and financial

discipline drives free cash flow reliability

Generating ~$3.7B of free cash flow in

2016, including $1.3B at ExGen and

$2.9B at the Utilities

Creating value for customers, communities

and shareholders

Investing $5.3B, with $4.0B at the Utilities

and $1.3B at ExGen

($ in millions)

(1)

BGE

ComEd

PECO

Total

Utilities

ExGen

Corp

(8)

Exelon

2016E

Cash

Balance

Beginning Cash Balance

(2)

7,750

Adjusted Cash Flow from Operations

(2,3)

650

1,575

700

2,925

3,725

(425)

6,225

Base CapEx and Nuclear Fuel

(4)

0

0

0

0

(2,475)

(100)

(2,550)

Free Cash Flow

650

1,575

700

2,925

1,250

(525)

3,650

Debt Issuances

750

950

450

2,150

0

0

2,150

Debt Retirements

(300)

(675)

(300)

(1,275)

0

(1,875)

(3,150)

Project Financing

n/a

n/a

n/a

n/a

100

n/a

100

Equity Buyback

0

0

0

0

0

(1,600)

(1,600)

Contribution from Parent

0

475

0

475

0

(475)

0

Other Financing

(5)

(75)

450

25

400

0

1,075

1,475

Financing

375

1,200

175

1,750

100

(2,875)

(1,025)

Total Free Cash Flow and Financing Growth

1,025

2,775

850

4,675

1,375

(3,400)

2,625

Utility Investment

(825)

(2,425)

(675)

(3,950)

0

0

(3,950)

ExGen Growth

(4)

0

0

0

0

(1,325)

0

(1,325)

Acquisitions and Divestitures

(6)

0

0

0

0

0

0

0

Equity Investments

(6)

0

0

0

0

(125)

0

(125)

Dividend

(7)

0

0

0

0

0

(1,150)

(1,150)

Other CapEx

and Dividend

(825)

(2,425)

(675)

(3,950)

(1,450)

(1,150)

(6,550)

Total Cash Flow, excl. Collateral

200

350

175

725

(100)

(4,550)

(3,900)

Ending

Cash

Balance

(2)

3,850

28

Q4 2015  Earnings Release Slides

Pension and OPEB Contributions and Expense

(1)    Pension and OPEB expenses assume a ~26% and ~28% capitalization rate in 2015 and 2016, respectively

(2)

The Balanced Funding Strategy for the Qualified Plans provides pension funding of the greater of $250M or minimum required contributions plus amounts required to avoid benefit

restrictions and at-risk status

(3)

Expected return on assets for pension is 7.00% and for OPEB is 6.70% for 2016

(4)

Pension and OPEB discount rates are 4.29% for the majority of plans at 12/31/15

2015

2016

(in $M)

Pre-Tax

Expense

(1)

Contributions

Pre-Tax

Expense

(1)

Contributions

(2)

Qualified

Pension

(3)(4)

$425

$450

$370

$250

Non-Qualified

Pension

15

15

15

20

OPEB

(3)(4)

30

40

5

35

Total

$470

$505

$390

$305

29

Q4 2015  Earnings Release Slides

Additional ExGen Modeling Data

Total

Gross Margin Reconciliation (in $M)

(1)

2016

2017

2018

$8,475

$8,475

$8,525

Other Revenues

(4)

$(325)

$(325)

$(325)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(5)

$(350)

$(300)

$(300)

Total Gross Margin (Non-GAAP, as shown on slide 11)

$7,800

$7,850

$7,900

(1)

All amounts rounded to the nearest $25M

(2)

Revenue net of purchased power and fuel expense (RNF), a non-GAAP measure, is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and fuel

expense. ExGen

does not forecast the GAAP components of RNF separately.  RNF also includes the RNF of our proportionate ownership share of CENG.

(3)

Excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices.

(4)

Other revenues reflects revenues from operating services agreement with Fort Calhoun, variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear

plants through regulated rates and gross receipts tax revenues.  

(5)

Reflects the cost of sales and depreciation expense of certain Constellation businesses of Generation.

(6)

ExGen

amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture. 

(7)

to the Appendix for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M

(8)

TOTI excludes gross receipts tax of $125M

(9)

Depreciation & Amortization excludes the cost of sales impact of ExGen’s non-power businesses of $25M

Key ExGen Modeling Inputs (in $M)

(1)(6)

2016

Other Revenues (excluding Gross Receipts Tax)

(4)

$200

O&M

(7)

$(4,475)

Taxes Other Than Income (TOTI)

(8)

$(350)

Depreciation & Amortization

(9)

$(1,075)

Interest Expense

$(375)

Effective Tax Rate

34.0%

ExGen adjusted O&M excludes direct cost of sales for certain Constellation business, P&L neutral decommissioning costs and the impact from O&M related to variable interest entities. Refer

Revenue Net of Purchased Power and Fuel Expense

(2)(3)

30

Q4 2015  Earnings Release Slides

BGE

Exelon Utilities Load

PECO

Large C&I

Small C&I

Residential

All Customers

ComEd

2016E

2015

2016 load is driven by impacts

of energy efficiency partially

offset by slowly improving

economy that result in 2016

usage being lower than 2015

Chicago GMP

2.3%

Chicago Unemployment

5.8%

2016 load growth is greater

than 2015, attributed to

improving economic conditions

and moderate customer

growth, partially offset by

energy efficiency

Baltimore GMP

2.4%

Baltimore Unemployment

5.3%

2016 load growth is driven by

slowly improving economic

conditions coupled with solid

residential customer growth,

partially offset by energy

efficiency

Philadelphia GMP

1.4%

Philadelphia

Unemployment

5.3%

2015

2016E

2015

1.1%

2016E

(0.3%)

(1.4%)

(0.8%)

(1.5%)

0.1%

(0.9%)

(0.4%)

(2.0%)

0.4%

(0.1%)

(0.2%)

0.3%

(0.3%)

0.6%

1.3%

(0.5%)

0.7%

1.5%

1.0%

1.1%

0.7%

2.0%

0.5%

Notes: Data is weather normalized and not adjusted for leap year.  Source of economic outlook data is IHS (December 2015).  Assumes 2015 GDP of 2.5% and U.S. unemployment of 5.0%. 

ComEd has the ROE collar as part of the distribution formula rate and BGE is decoupled which mitigates the load risk. QTD and YTD actual data can be found in earnings release tables.

BGE amounts have been adjusted for prior quarter true-ups.

31

Q4 2015  Earnings Release Slides

ComEd April 2015 Distribution Formula Rate

Docket #

15-0287

Filing Year

Reconciliation Year

Common Equity Ratio

ROE

Requested Rate of

Return

~ 7% for both the filing and reconciliation years

Rate Base

$8,277 million–

Filing year (represents projected year-end rate base using 2014 actual plus 2015 projected capital

additions).  2015 and 2016  earnings will reflect 2015 and 2016 year-end rate base respectively.

$7,082 million -

Reconciliation year (represents

year-end rate base for 2014)

Revenue Requirement

Decrease

$67M decrease  ($152M decrease due to the 2014 reconciliation offset by a $85M increase related to the filing year). 

The 2014 reconciliation impact on net income was recorded in 2014 as a regulatory asset.

Timeline

•

04/15/15 Filing Date

•

240 Day Proceeding

The 2015 distribution formula rate filing established the net revenue requirement used to set the rates that took effect in January 2016 after the

Illinois Commerce Commission's (ICC’s) review. There are two components to the annual distribution formula rate filing:

•

Filing Year: Based on 2014 costs and 2015 projected plant additions. 

•

Annual Reconciliation: For 2014, this amount reconciles the revenue requirement reflected in rates in effect during 2014 to the actual costs for

2014 Calendar Year Actual Costs and 2015 Projected Net Plant Additions are used to set the rates for calendar year

2016.  Rates currently in effect (docket 14-0312) for calendar year 2015 were based on 2013 actual costs and 2014

projected net plant additions

Reconciles Revenue Requirement reflected in rates during 2014 to 2014 Actual Costs Incurred.  Revenue requirement

2013 and reflects the impacts of PA 98-0015 (SB9)

~ 46% for both the filing and reconciliation year

9.14% for the filing year (2014 30-yr Treasury Yield of 3.34% + 580 basis point risk premium) and 9.09% for the

reconciliation year (2014 30-yr Treasury Yield of 3.34% + 580 basis point risk premium     5 basis points performance

metrics penalty).  For 2015 and 2016, the actual allowed ROE reflected in net income will ultimately be based on the

average of the 30-year Treasury Yield during the respective years plus 580 basis point spread, absent any metric penalties 

–

for 2014 is based on docket 13-0318 (2012 actual costs and 2013 projected net plant additions)approved in December

Given the retroactive ratemaking provision in the Energy Infrastructure Modernization Act (EIMA) legislation, ComEd net income during

the year will be based on actual costs with a regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. 

Revenue Requirement in rate filings impacts cash flow.

that year. The annual reconciliation impacts cash flow in 2016 but the earnings impact has been recorded in 2014 as a regulatory asset.

32

Q4 2015  Earnings Release Slides

PECO Electric Distribution Rate Case & Settlement

Docket #

R-2015-2468981

Test Year

2016 Calendar Year

Requested

Revenue Requirement

$190M

Requested

Common Equity Ratio

(1)

53.36%

Requested Rate of Return

ROE: 10.95%;    ROR:

8.19%

Proposed Rate Base

$4.1B

$127M

Authorized Returns

(2)

N/A

System Average Increase as % of overall bill

2.9%

Timeline

•

3/27/15 –

PECO filed electric distribution rate case with PaPUC

•

12/17/15 –

PaPUC

Final Order

•

Increased rates effective on January 1, 2016

The Revenue Requirement increase of $127M represents 67% of the Company’s

original proposal

(1)

Reflects PECO’s  expected capital structure as of 12/31/2016

(2)

Due to the “black box” nature of the settlement, Authorized Return was not agreed upon by the parties in determining the ultimate revenue requirement increase. 

Revenue Requirement Settlement Increase

33

Q4 2015  Earnings Release Slides

Electric

Gas

Docket #

9406

Test Year

December 2014-

November  2015

Common Equity Ratio

(1)

53.7%

Requested ROE

10.60%

10.50%

Requested Rate of Return

7.95%

7.90%

Rate Base (adjusted)

$3.0B

$1.2B

Revenue

Requirement

Increase

(1)

$120.9M

$79.5M

Proposed

Distribution Increase as %

of overall bill

3.2%

8.8%

Notes

•

11/06/15 BGE

filed application with the MDPSC seeking increases in electric & gas

distribution base rates

•

$140M or ~70% of the total $200M distribution rate increase is for recovery of Smart Grid

investment

•

Requested incremental conduit fees of $31M be recovered through a rider

•

210 Day Proceeding

•

06/03/2016

-

PSC order expected

•

New rates are in effect

shortly after the final order

(1)  Based on the 12 months ended 11/30/2015.

BGE Electric and Gas Distribution Rate Case

34

Q4 2015  Earnings Release Slides

Appendix

Reconciliation of Non-GAAP

Measures

35

Q4 2015  Earnings Release Slides

4Q GAAP EPS Reconciliation

Three Months Ended December 31, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.15

$0.09

$0.09

$0.08

$(0.04)

$0.38

Unrealized gains related to NDT fund investments

0.05

-

-

-

-

0.05

Merger and integration costs

-

-

-

-

(0.01)

(0.01)

Amortization of commodity contract intangibles

(0.01)

-

-

-

-

(0.01)

Long-Lived asset impairments

(0.01)

-

-

-

-

(0.01)

Reassessment of state deferred income taxes

(0.01)

-

-

-

(0.03)

(0.05)

Reduction in state income tax reserve

0.01

-

-

-

-

0.01

PHI merger related redeemable debt exchange

-

-

-

-

(0.01)

(0.01)

CENG non-controlling interest

(0.02)

-

-

-

-

(0.02)

4Q 2015 GAAP Earnings (Loss) Per Share

$0.17

$0.09

$0.09

$0.08

$(0.09)

$0.33

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

Three Months Ended December 31, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.27

$0.09

$0.11

$0.06

$(0.04)

$0.48

Mark-to-market impact of economic hedging activities

(0.08)

-

-

-

-

(0.08)

Unrealized gains related to NDT fund investments

0.03

-

-

-

-

0.03

Merger and integration costs

(0.01)

-

-

-

(0.02)

(0.03)

Mark-to-market impact of PHI merger related interest  rate swaps

-

-

-

-

(0.06)

(0.06)

Reassessment of state deferred income taxes

0.04

-

-

-

(0.01)

0.03

Amortization of commodity contract intangibles

(0.03)

-

-

-

-

(0.03)

Plant retirements and divestitures

0.06

-

-

-

-

0.06

Long-Lived asset impairments

(0.39)

-

-

-

-

(0.39)

Bargain-Purchase gain

0.03

-

-

-

-

0.03

Tax settlements

0.01

-

-

-

-

0.01

CENG non-controlling interest

(0.03)

-

-

-

-

(0.03)

4Q 2014 GAAP Earnings (Loss) Per Share

($0.11)

$0.09

$0.11

$0.06

$(0.13)

$0.02

36

Q4 2015  Earnings Release Slides

4Q YTD GAAP EPS Reconciliation

Year Ended December 31,

2014

ExGen

ComEd

PECO

BGE

Other

Exelon

2014 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.34

$0.47

$0.41

$0.23

$(0.06)

$2.39

Mark-to-market impact of economic hedging activities

(0.42)

-

-

-

-

(0.42)

Unrealized gains related to NDT fund investments

0.10

-

-

-

-

0.10

Asset retirement obligation

0.02

-

-

-

-

0.02

Plant retirements and divestitures

0.28

-

-

-

-

0.28

Long-Lived asset impairment

(0.49)

-

-

-

(0.02)

(0.50)

Gain on CENG integration

0.18

-

-

-

-

0.18

Merger and integration costs

(0.10)

-

-

-

(0.04)

(0.14)

Mark-to-market impact of PHI merger related interest swaps

-

-

-

-

(0.07)

(0.07)

Amortization of commodity contract intangibles

(0.07)

-

-

-

-

(0.07)

Tax settlements

0.12

-

-

-

-

0.12

Reassessment of state deferred income taxes

0.04

-

-

-

(0.01)

0.03

Bargain-Purchase gain

0.03

-

-

-

-

0.03

CENG non-controlling interest

(0.07)

-

-

-

-

(0.07)

4Q 2014 GAAP Earnings Per Share

$0.97

$0.47

$0.41

$0.23

($0.20)

$1.88

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

37

Q4 2015  Earnings Release Slides

4Q YTD GAAP EPS Reconciliation (continued)

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

Year Ended December 31, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.40

$0.48

$0.43

$0.31

$(0.13)

$2.49

Mark-to-market impact of economic hedging activities

0.18

-

-

-

-

0.18

Unrealized losses related to NDT fund investments

(0.13)

-

-

-

-

(0.13)

Merger and integration costs

(0.02)

(0.01)

-

-

(0.03)

(0.07)

Mark-to-market impact of PHI merger related interest rate swaps

-

-

-

-

(0.02)

(0.02)

Long-lived asset impairment

(0.01)

-

-

-

(0.02)

(0.02)

Asset retirement obligation

0.01

-

-

-

-

0.01

Tax settlements

0.06

-

-

-

-

0.06

Midwest generation bankruptcy recoveries

0.01

-

-

-

-

0.01

PHI merger related redeemable debt exchange

-

-

-

-

(0.01)

(0.01)

Reassessment of state deferred income taxes

(0.01)

-

-

-

(0.03)

(0.05)

Reduction in state income tax reserve

0.01

-

-

-

-

0.01

CENG non-controlling interest

0.04

-

-

-

-

0.04

4Q 2015 GAAP Earnings (Loss) Per Share

$1.54

$0.48

$0.42

$0.31

$(0.20)

$2.54

38

Q4 2015  Earnings Release Slides

GAAP to Operating Adjustments

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

•

Exelon’s 2016 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:

–

Mark-to-market adjustments from economic hedging activities

–

Unrealized gains and losses from NDT fund investments to the extent not offset by contractual

accounting as described in the notes to the consolidated financial statements

–

Certain costs incurred associated with the pending Pepco Holdings, Inc. acquisitions

–

Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at

the

date

of

acquisition

of

Integrys

in

2014

–

Generation’s non-controlling interest related to CENG exclusion items

–

Other unusual items

39

Q4 2015  Earnings Release Slides

Adjusted O&M Reconciliations to GAAP

2015

Adjusted

O&M

Reconciliation

(in

$M)

(3)

ExGen

ComEd

PECO

BGE

Other

Exelon

GAAP O&M

$5,300

$1,575

$800

$675

$(25)

$8,325

PHI Acquisition Costs

(25)

-

-

-

(25)

(50)

Long-Lived Asset Impairment

-

-

-

-

(25)

(25)

Regulatory

O&M

(1)

-

(275)

(125)

-

-

(400)

Decommissioning

(1)

50

-

-

-

-

50

Direct cost of sales incurred to generate revenues for

certain

Constellation

businesses

(2)

(250)

-

-

-

-

(250)

O&M for managed plants that are partially owned

(425)

-

-

-

-

(425)

Other

25

-

-

-

-

25

Adjusted O&M (Non-GAAP, as shown on slide 10)

$4,675

$1,300

$675

$675

$(75)

$7,250

(1)

Reflects P&L neutral O&M.

(2)

Reflects the direct cost of sales of certain Constellation businesses of Generation, which are included in Total Gross Margin.

(3)

All amounts rounded to the nearest $25M.

40

Q4 2015  Earnings Release Slides

Adjusted O&M Reconciliations to GAAP

2016

Adjusted

O&M

Reconciliation

(in

$M)

(3)

ExGen

ComEd

PECO

BGE

Other

Exelon

GAAP O&M

$5,175

$1,600

$875

$750

$(100)

$8,300

Regulatory

O&M

(1)

-

(300)

(100)

-

-

(400)

Decommissioning

(1)

50

-

-

-

-

50

Direct cost of sales incurred to generate revenues for certain

Constellation

businesses

(2)

(300)

-

-

-

-

(300)

O&M for managed plants that are partially owned

(400)

-

-

-

-

(400)

Other

(50)

(25)

-

-

-

(75)

Adjusted O&M (Non-GAAP, as shown on slide 10)

$4,475

$1,275

$775

$750

$(100)

$7,175

(1)

Reflects P&L neutral O&M.

(2)

Reflects the direct cost of sales of certain Constellation businesses of Generation, which are included in Total Gross Margin.

(3)

All amounts rounded to the nearest $25M.