Exelon Generation 8K Results of Operations and Financial Condition | SEC 13 Feb 15

Earnings Conference Call

Quarter 2014

February 13

, 2015

Exhibit 99.2

2014 4Q 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 Corporation, Commonwealth Edison

Company,

PECO

Energy

Company,

Baltimore

Gas

and

Electric

Company

and

Exelon

Generation Company, LLC (Registrants) include those factors discussed herein, as well

as the items discussed in (1) Exelon’s 2014 Annual Report on Form 10-K (to be filed

on February 13, 2015) 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 and (2) other factors

discussed in filings with the SEC by the Registrants. Readers are cautioned not to place

undue reliance on these forward-looking statements, which apply only as of the date of

this presentation. None of the Registrants undertakes any obligation to publicly release

any revision to its forward-looking statements to reflect events or circumstances after

the date of this presentation.

2014 4Q Earnings Release Slides

•

Utilities

•

Top decile for safety; top quartile for

outage frequency

•

ExGen

•

Nuclear capacity factor over 94%

(2)

•

Power dispatch match nearly 97%

and renewables energy capture of

95%

•

2014 adjusted operating results of

$2.39/share

(1)

•

Total shareholder return of 41%

•

Successful ~$3B billion forward equity

and mandatory convertible offering

•

$75M in total savings from

consolidation of CENG plants

(3)

•

$675M ExGen Texas Power Financing

2014 In Review

(1)

Represents adjusted (non-GAAP) operating EPS. 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)

Exelon operated plants at ownership

(3)

Total CapEx and O&M savings from consolidation. Includes EDF’s equity ownership share of the CENG Joint Venture

•

Delivered solid 2014 results at the mid-point of our guidance range

Financial

Discipline

Operational

Excellence

Growth

Investments

Regulatory

Advocacy

•

Utilities

•

$3.1 billion invested in technology

and infrastructure

•

PHI Acquisition

•

ExGen

•

Integrys and ProLiance Acquisitions

•

Texas CCGTs, Bloom & NetPower

partnership

•

Added 215 MW of clean generation

•

ComEd and BGE rate cases:

•

consecutive rate case in which

ComEd

achieved

95%

its

ask

•

rate case settlement for BGE

since 1999

•

ExGen

•

HR 1146

•

Capacity Performance Product

•

EPA’s Clean Power Plan (111(d))

2014 4Q Earnings Release Slides

HoldCo

ExGen

ComEd

PECO

BGE

HoldCo

ExGen

ComEd

PECO

BGE

2015 Guidance

$2.25 -

$2.55

(2)

$1.15 -

$1.35

$0.45 -

$0.55

$0.35 -

$0.45

$0.20 -

$0.30

$2.39

(1)

$1.34

$0.47

$0.41

$0.23

2015 Adjusted Operating Earnings Guidance

(1)

2014 results based on 2014 average outstanding shares of 864M. 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)

2015 earnings guidance based on expected average outstanding shares of ~866M. 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.

Expect

2015

Adjusted

Operating

Earnings

$0.60

$0.70

per

2014 Actual

Key Year-Over-Year Drivers

•

Total impact of asset divestitures:

$(0.12)

•

Additional planned nuclear outage

$(0.02)

•

ExGen Pension/OPEB: $(0.02)

•

ComEd: increased capital

investments in distribution and

transmission partially offset by

lower US Treasury Yields: $0.03

•

Capacity Prices: $0.07

•

Full year elimination of DOE fee:

$0.04

2014 4Q Earnings Release Slides

Adjusted O&M Forecast

(2)

•

2015 forecast of $7.225B

(1)

•

Expect CAGR of ~0.2 % for 2015-2017

2015E

$7,225

(1)

$4,525

$1,250

$750

$775

2014 Actuals

$6,950

(1)

$4,350

$1,200

$750

$725

(in $M)

ExGen

ComEd

PECO

BGE

Corp

(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)

Prior

consolidation

April

2014,

CENG

was

under

the

equity

method

accounting.

CENG

0&M

prior

consolidation

not

included.

ExGen

(3)

BGE

Key Year-over-Year Drivers

(2)

•

Growth including Integrys & full

year of CENG: $250M

•

Inflation: $125M

•

Plant Divestitures: $(100M)

•

Pension/OPEB: $50M

•

PECO Storm Costs:

$(50M)

•

BGE & ComEd Storm Costs: $25M

Corp

-75

2014 4Q Earnings Release Slides

Hedging Activity and Market Fundamentals

Heat Rates have expanded throughout 2014

% of Expected Generation Hedged

(1)

Total Portfolio

(1)

Mid-point of disclosed hedge % ranges was used

Impacts of our view on our hedging activity

•

Over the last several quarters, power prices have increased and heat rates have expanded

•

We have adjusted our strategy by reducing our long heat rate position and increasing our fixed-price length

where we see remaining upside

•

During 4Q, we lowered our cross-commodity hedges monetizing our long heat rate view as heat rates

expanded

but

continued

stay

behind

ratable

carrying

long

fixed-price

position

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

1Q14

2Q14

3Q14

4Q14

2014 4Q Earnings Release Slides

Exelon Generation: Gross Margin Update

December 31, 2014

Change from Sept 30, 2014

Gross Margin Category ($M)

(1)

2015

2016

2017

2015

2016

2017

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

$5,700

$5,850

$6,100

$(1,050)

$(650)

$(550)

Mark-to-Market of Hedges

(3,4)

$1,050

$550

$350

$1,050

$400

$200

Power New Business / To Go

$350

$550

$800

$(50)

$50

Non-Power Margins Executed

$200

$100

$50

$100

$50

Non-Power New Business / To Go

$250

$350

$400

$(50)

$50

Total Gross Margin

(2)

$7,550

$7,400

$7,700

$(200)

$(250)

•

Load

serving

business

had

strong

2014

and

off

good

start

2015

•

Cleared 195MW of new peaking generation in ISO-NE Forward Capacity Auction 9. Expected

to be online in mid-2018

•

Natural gas and power prices declined during the fourth quarter

•

Aggressively hedged our PJM East and New England Portfolios in early Q4 when prices were

higher

Recent Developments

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

Note: Inclusive of all asset divestitures as of December 31, 2014 and Quail Run, as well as

the Integrys acquisition.

Gross margin categories rounded to nearest $50M.

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

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

2014 4Q Earnings Release Slides

Properly Valuing Nuclear Energy

2014 4Q Earnings Release Slides

Exelon Generation Disclosures

December 31, 2014

2014 4Q Earnings Release Slides

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

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

•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

•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

•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

Credit Rating

Capital

Structure

Capital &

Operating

Expenditure

Dividend

Strategic Policy Alignment

Three-Year Ratable Hedging

Bull / Bear Program

2014 4Q Earnings Release Slides

Components of Gross Margin Categories

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”

“Non power executed”

over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

Open Gross

Margin

MtM of

Hedges

(2)

“Power”

New

Business

“Non Power”

Executed

“Non Power”

New Business

•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)

)

•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

•Retail, Wholesale

planned electric

sales

•Portfolio

Management

new business

•Mid marketing

new business

•Retail, Wholesale

executed gas sales

•Load Response

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Retail, Wholesale

planned gas sales

•Load Response

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels new

business

•Proprietary trading

(3)

(1)

Hedged gross margins for South, West & Canada region 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

2014 4Q Earnings Release Slides

ExGen Disclosures

Gross Margin Category ($M)

(1)

2015

2016

2017

Open Gross Margin

(including South, West & Canada hedged GM)

$5,700

$5,850

$6,100

Mark to Market of Hedges

(3,4)

$1,050

$550

$350

Power New Business / To Go

$350

$550

$800

Non-Power Margins Executed

$200

$100

$50

Non-Power New Business / To Go

$250

$350

$400

Total

Gross

Margin

$7,550

$7,400

$7,700

(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 36 for a Non-GAAP to GAAP reconciliation of Total

Gross Margin

(3)

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

Reference Prices

(5)

2015

2016

2017

Henry Hub Natural Gas ($/MMbtu)

$3.03

$3.46

$3.76

Midwest: NiHub ATC prices ($/MWh)

$30.13

$30.96

$31.98

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

$37.76

$37.74

$37.83

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$6.38

$6.10

$5.93

New York: NY Zone A ($/MWh)

$36.12

$36.79

$36.64

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

ALQN Gas, 7.5HR, $0.50 VOM

$10.25

$9.08

$8.02

(4)

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

(5)

Based on December 31, 2014 market conditions

(6)

Inclusive of all asset divestitures as of December 31, 2014, and Quail Run, as

well as Integrys acquisition

(2,6)

2014 4Q Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2015

2016

2017

Exp. Gen (GWh)

(1)

191,200

192,400

196,800

Midwest

97,100

97,400

95,900

Mid-Atlantic

(2)

62,400

62,900

60,700

ERCOT

16,800

17,300

25,700

New York

(2)

9,300

New England

5,600

5,500

5,200

% of Expected Generation Hedged

(3)

61%-64%

31%-34%

Midwest

88%-91%

55%-58%

23%-26%

Mid-Atlantic

(2)

99%-102%

67%-70%

36%-39%

ERCOT

94%-97%

77%-80%

48%-51%

New York

(2)

84%-87%

60%-63%

38%-41%

New England

118%-121%

68%-71%

32%-35%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$34.00

$34.50

$36.00

Mid-Atlantic

(2)

$45.00

$47.00

ERCOT

(5)

$10.50

$7.50

$7.00

New York

(2)

$47.50

$43.50

$40.00

New England

(5)

$21.00

$14.50

$9.00

(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 14 refueling outages in 2015, 12 in 2016, and 15 in 2017 at Exelon-operated nuclear plants, and Salem. Expected generation assumes

capacity factors of 93.5%, 94.1% and 93.4% in 2015 , 2016 and 2017 respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in

2015, 2016 and 2017 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. (6) Inclusive of all asset divestitures

as of December 31,2014 and Quail Run, as well as Integrys acquisition

93%-96%

2014 4Q Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges)

(1)

2015

2016

2017

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$25

$340

$730

$1/Mmbtu

$35

$(310)

$(710)

NiHub ATC Energy Price

+ $5/MWh

$35

$215

$370

$5/MWh

$(30)

$(215)

$(365)

PJM-W ATC Energy Price

+ $5/MWh

$(5)

$105

$205

$5/MWh

$10

$(100)

$(205)

NYPP Zone A ATC Energy Price

+ $5/MWh

$ -

$10

$25

$5/MWh

$(5)

$(15)

$(30)

Nuclear Capacity Factor

+/-

$40

+/-

$45

+/-

$45

(1)

Based on December 31, 2014 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; Inclusive of all asset divestitures as of December 31, 2014, and Quail Run, as well as Integrys acquisition

2014 4Q Earnings Release Slides

ExGen Hedged Gross Margin Upside/Risk

$7,800

$7,250

$8,350

$6,650

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

2015

2016

2017

$9,950

$6,050

2014 4Q Earnings Release Slides

(1)

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 2015, 2016 and 2017 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, 2014

(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 36 for a Non-GAAP to GAAP reconciliation of Total Gross Margin Excludes EDF’s equity ownership share of

the CENG Joint Venture

(4)

Inclusive of all asset divestitures as of December 31, 2014 and Quail Run, as well as Integrys acquisition

2014 4Q Earnings Release Slides

Illustrative Example of Modeling Exelon Generation

2016 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin

$5.85 billion

(B)

Expected Generation (TWh)

97.4

62.9

17.3

9.3

5.5

(C)

Hedge % (assuming mid-point of range)

56.5%

68.5%

78.5%

61.5%

69.5%

(D=B*C)

Hedged Volume (TWh)

55.0

43.1

13.6

5.7

3.8

(E)

Effective Realized Energy Price ($/MWh)

34.50

45.00

7.50

43.50

14.50

(F)

Reference Price ($/MWh)

30.96

37.74

6.10

36.79

9.08

(G=E-F)

Difference ($/MWh)

3.54

7.26

1.40

6.71

5.42

(H=D*G)

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

(1)

195

315

(I=A+H)

Hedged Gross Margin ($ million)

$6,400

(J)

Power New Business / To Go ($ million)

$550

(K)

Non-Power Margins Executed ($ million)

$100

(L)

Non-

Power New Business / To Go ($ million)

$350

(N=I+J+K+L)

Total Gross Margin

(2)

$7,400 million

(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 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 36 for a Non-GAAP to GAAP reconciliation of Total Gross Margin

Note: Inclusive of all asset divestitures as of December 31, 2014, and Quail Run as well as Integrys acquisition

2014 4Q Earnings Release Slides

Additional Disclosures

2014 4Q Earnings Release Slides

2014 Adjusted Operating Earnings by Quarter

$ 0.30

$ 0.27

$ 0.15

$ 0.50

$ 0.13

$ 0.11

$ 0.09

$ 0.10

$ 0.11

$ 0.09

$ 0.06

$ 0.05

$ 0.10

ExGen

BGE

ComEd

PECO

$0.48

$0.78

$0.51

$ 0.02

$0.62

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

Amounts may not add due to rounding

2014 4Q Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key

Drivers

–

4Q14

vs.

4Q13

BGE

(+0.00):

•

Higher RNF offset by higher O&M: $(0.00)

PECO (-0.01):

•

Unfavorable weather conditions: $(0.01)

ComEd

(-0.04):

•

Impact of bonus depreciation on ComEd’s distribution and

transmission

(2)

earnings: $(0.02)

•

Unfavorable

weather

conditions

and

volume

(2)

$(0.01)

$0.13

4Q 2014

$0.26

$0.06

$0.11

$0.09

4Q 2013

$0.31

$0.06

$0.12

ComEd

PECO

BGE

(1)

(2)

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.

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.

Numbers may not add due to rounding.

2014 4Q Earnings Release Slides

$0.45 -

$0.55

Other

($0.02)

Depreciation &

Amortization

($0.02)

O&M

(3)

($0.06)

RNF

(2)

2014

(1)

($0.01)

2015

(4)(5)

ComEd Adjusted Operating EPS Bridge 2014 to 2015

Interest

$0.14

$0.47

$0.11

Distribution

$0.02

Transmission

$0.01

Weather/Volumes

($0.01)

Storm

($0.02)

Inflation

($0.01)

Pension/OPEB

($0.01)

Other

(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 866M in 2015 and 864M in 2014. Refer to slide 33 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(5) Guidance assumes an effective tax rate for 2015 of 39.5%.

Note: Drivers add up to mid-point of 2015 adjusted operating EPS range.

2014 4Q Earnings Release Slides

$0.41

RNF

(2)

($0.00)

2015

(4)(5)

$0.35 -

$0.45

Tax

($0.02)

Interest

($0.00)

Depreciation &

Amortization

(0.00)

O&M

(3)

$0.01

PECO Adjusted Operating EPS Bridge 2014 to 2015

2014

(1)

($0.02) Storm Tax Repairs

Benefit

$0.03 Storm

($0.01) Inflation

($0.01) Operational/IT Increases

Note: Drivers add up to mid-point of 2015 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 864M in 2014 and 866M in 2015. Refer to slide 33 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(5) Guidance assumes an effective tax rate for 2015 of 28.5%.

2014 4Q Earnings Release Slides

$0.05

$0.23

Other

O&M

(3)

($0.04)

RNF

(2)

2014

(1)

$0.20 -

$0.30

$0.01

2015

(4)(5)

BGE Adjusted Operating EPS Bridge 2014 to 2015

($0.01) Storm Costs

($0.01) Preventative Maintenance

($0.01) Inflation

($0.01) Other

$0.04 Pricing/Mix

$0.01 Other RNF

Note: Drivers add up to mid-point of 2015 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 864M in 2014 and 866M in 2015. Refer to slide 33 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(5) Guidance assumes an effective tax rate for 2015 of 39.2%.

2014 4Q Earnings Release Slides

$0.08

$1.34

$1.15 -

$1.35

Other

2015

(5)(6)

Depreciation &

Amortization

(4)

$0.04

2014

(1)

Gross Margin

(2)

($0.03)

O&M

(3)

($0.02)

ExGen Adjusted Operating EPS Bridge 2014 to 2015

$0.22 Higher Capacity Revenue, Higher retail

volumes (primarily Integrys), Plant Performance

and Market Conditions

$0.04 Impact of full year DOE fee removal

($0.22) Plant Divestitures

($0.05) Depreciation Additions

$0.03 Plant Divestitures

($0.06) Generation Growth, including

Integrys

($0.05) Inflation

($0.02) Pension / OPEB

($0.02) Nuclear Outages

$0.07 Plant Divestitures

$0.02 Other Divestitures

$0.01 Asbestos Reserve

$0.03 Other

($0.05) Interest

($0.04) Decom, primarily

unregulated realized gains

Note: Drivers add up to mid-point of 2015 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)

(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 36 for a Non-GAAP to GAAP

reconciliation of Total Gross Margin.

(4)

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.

(5)

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

(6)

Shares Outstanding (diluted) are 864M in 2014 and 866M in 2015. Refer to slide 33 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS.

(7)

Guidance assumes an effective tax rate for 2015 of 26%.

2014 Income statement categories have been normalized for a full year comparison of CENG at ownership (50.01)

(

)

2014 4Q Earnings Release Slides

2015 Projected Sources and Uses of Cash

($ in millions)

(1)

BGE

ComEd

PECO

ExGen

Exelon

(3)

2015E

Beginning Cash Balance

3,575

Adjusted Cash Flow from Operations

(4)

600

2,075

600

3,400

6,775

CapEx (excluding other items below):

(675)

(1,875)

(525)

(1,925)

(5,100)

Nuclear Fuel

n/a

(1,125)

Dividend

(5)

(1,075)

Nuclear Uprates

n/a

(100)

Wind

n/a

(100)

Solar

n/a

(125)

Upstream

n/a

(25)

Utility Smart Grid/Smart Meter

(25)

(325)

(25)

n/a

(400)

Net Financing (excluding Dividend):

Debt Issuances

250

700

350

750

2,050

Debt Retirements

(75)

(250)

(550)

(1,675)

Project Finance/Federal Financing Bank

Loan

n/a

200

Other Financing

(6)

(50)

1,075

1,250

Ending Cash Balance

4,125

(1)

All amounts rounded to the nearest $25M.

(2)

Excludes counterparty collateral posted of $1.7 billion at 12/31/2014. In addition, the 12/31/2015 ending cash balance does not include collateral.

(3)

Includes cash flow activity from Holding Company and other corporate entities.

(4)

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.

(5)

Dividends are subject to declaration by the Board of Directors.

(6)

“Other Financing” primarily includes expected changes in short-term debt.

(2)

2014 4Q Earnings Release Slides

Additional 2015 ExGen Modeling

P&L Item

2015 Estimate

ExGen Model Inputs

O&M

(2)

$4,525M

Taxes Other Than Income (TOTI)

(3)

$350M

Depreciation & Amortization

(4)

$925M

Interest Expense

$400M

(1)

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

(2)

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

(3)

TOTI excludes gross receipts tax for retail of $125M.

(4)

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

(1)

2014 4Q Earnings Release Slides

2015 Regulatory and Legislative Timelines

ExGen

Exelon Utilities

PHI Acquisition

Illinois

Legislative

Session

Begins

(Jan 14)

Cert Petition

Filed in

EPSA v.

FERC (Order

745 –

Demand

Response)

(Jan 15)

Supreme

Court

decision on

cert in

EPSA v.

FERC

(Demand

Response)

(March-

April)

Supreme

Court

hearing on

Michigan v.

EPA

(MATS)

(March-

April)

FERC Ruling

on PJM

Capacity

Performance

Proposal

(April)

MATS Rule

in Effect

(April)

PJM BRA

Auction

(May 11)

PJM BRA

Auction

Results

(May 22)

Illinois

Legislative

Session

Adjourns

(May 31)

Supreme

Court

Decision in

Michigan

vs. EPA

(June)

Final Clean

Power Rule

(111d)

Issued

(Mid-

Summer)

Illinois

Legislative

Veto

Session

(Nov)

ComEd Formula Rate Filing

(April)

BGE Electric and Gas Rate

Case Filing (TBD) MD PSC

Ruling Expected 7 Months

after Filing

PECO Electric Rate Case

Filing (TBD) PaPUC Ruling

Expected within 9 Months of

Filing

ICC Rules on ComEd

Formula Rate Filing (Dec)

Settlement

Filed in New

Jersey (Jan 14)

Maryland

Hearings (Jan

26 –

Feb 6)

New Jersey

Approval

(Feb 11)

DC Hearings

(March 30-

April 8)

Maryland

Deadline (April

Expected

Transaction

Close (Q2/Q3)

Exelon Utilities Load

2015E

2014

Large C&I

Small C&I

Residential

All Customers

2015E

2014

2015E

Chicago GMP

1.6%

Chicago Unemployment

5.9%

Philadelphia GMP

0.8%

Philadelphia Unemployment

4.8%

Baltimore GMP

1.4%

Baltimore Unemployment

5.5%

Notes: Data is not adjusted for leap year. Source of economic outlook data is Global Insight (December 2014 ) and Bureau of Economic Analysis. Assumes 2014 GDP of 2.4% and U.S.

unemployment of 5.6%.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 unbilled / true-up load from prior quarters

ComEd

PECO

BGE

2015 load growth is similar to

2014, driven by slowly

improving economic conditions

and partially offset by energy

efficiency

2015 load growth is driven by

modest economic growth

coupled with increased shale

gas transportation and

production, partially offset by

energy efficiency

2015 load growth rate is

driven by weaker economic

conditions, primarily

reflected in residential and

small C&I, further decreased

by energy efficiency

0.4%

0.2%

0.8%

0.3%

0.4%

-0.3%

-0.1%

0.7%

0.8%

0.1%

0.4%

0.5%

-0.7%

0.0%

1.9%

-0.1%

-1.3%

-0.2%

-0.9%

-2.4%

0.1%

0.6%

-1.9%

-0.5%

2014 4Q Earnings Release Slides

2014 4Q Earnings Release Slides

ComEd April 2014 Distribution Formula Rate

Note: Disallowance of any items in the 2014 distribution formula rate filing could impact 2014 earnings in the form of a regulatory asset adjustment. Total disallowances in the 2014

distribution formula rate filing include items that are recoverable via other ratemaking mechanisms.

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.

The 2014 distribution formula rate filing established the net revenue requirement used to set the rates that took effect in January 2015 after the Illinois

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

Filing Year: Based on prior year costs (2013) and current year (2014) projected plant additions.

Annual

Reconciliation:

For

the

prior

calendar

year

(2013),

this

amount

reconciles

the

revenue

requirement

reflected

rates

during

the

prior

year

(2013)

effect

the

actual

costs

for

that

year.

The

annual

reconciliation

impacts

cash

flow

the

following

year

(2015)

but

the earnings

impact has been recorded in the prior year (2013) as a regulatory asset.

2014 4Q Earnings Release Slides

BGE Rate Case Settlement

(1)

Due to the “black box”

nature of the settlement, the Common Equity Ratio, Authorized Returns, and Proposed Rate Base (adjusted) were not agreed upon by the parties in determining the

ultimate revenue requirement increase

(2)

Reflects BGE’s actual capital structure as of 8/31/2014

(3)

ROE and ROR stated in the settlement only apply to AFUDC and carrying costs on regulatory assets

(4)

BGE’s Proposed Adjusted rate base

First BGE rate case settlement agreement since 1999

Electric

Gas

Docket #

9355

Test Year

Common

Equity

Ratio

(1)(2)

52.3%

Authorized

Returns

(1)(3)

ROE: 9.75%; ROR: 7.46%

ROE: 9.65%; ROR: 7.41%

Requested Rate of Return

7.93%

7.88%

Proposed

Rate

Base

(adjusted)

(1)(4)

$2.9B

$1.2B

Revenue Requirement Increase

$22.0M

$38.0M

Distribution Increase as % of

overall bill

Timeline

•

07/02/14 BGE filed application with the MDPSC seeking increases in electric & gas distribution

base rates

•

210 Day Proceeding

•

7/08/14 –

Case delegated to the Public Utility Law Judge Division

•

10/17/14

–

BGE

filed

unanimous

“black

box”

settlement

with

PSC

which

was approved by

the PSC

•

Increased rates effective with service on or after December 15, 2014

September 2013 - August 2014

2014 4Q Earnings Release Slides

Appendix

Reconciliation of Non-GAAP

Measures

2014 4Q Earnings Release Slides

4Q GAAP EPS Reconciliation

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)

Unrealized losses related to NDT fund investments

0.03

Merger and integration costs

(0.01)

(0.08)

(0.09)

Reassessment of state deferred income taxes

0.04

(0.01)

0.03

Amortization of commodity contract intangibles

(0.03)

Plant retirements and divestitures

0.06

Long-lived asset impairment

(0.39)

Bargain-purchase gain

0.03

Tax settlements

0.01

Non-controlling interest

(0.03)

4Q 2014 GAAP Earnings (Loss) Per Share

($0.11)

$0.09

$0.11

$0.06

$(0.13)

$0.02

Three Months Ended December 31, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.21

$0.13

$0.12

$0.06

$(0.02)

$0.50

Mark-to-market impact of economic hedging activities

0.16

Unrealized gains related to nuclear decommissioning trust funds

0.05

Constellation merger and integration costs

(0.02)

Reassessment of state deferred income taxes

0.02

(0.02)

Amortization of commodity contract intangibles

(0.09)

Midwest Generation bankruptcy charges

(0.02)

4Q 2013 GAAP Earnings (Loss) Per Share

$0.31

$0.13

$0.12

$0.06

$(0.04)

$0.58

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

2014 4Q Earnings Release Slides

4Q YTD GAAP EPS Reconciliation

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, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.40

$0.49

$0.45

$0.23

$(0.07)

$2.50

Mark-to-market impact of economic hedging activities

0.35

(0.00)

0.35

Unrealized gains related to nuclear decommissioning trust funds

0.09

Asset retirement obligation

(0.01)

Plant retirements and divestiture

0.02

Long-lived asset impairment

(0.12)

(0.02)

(0.14)

Merger and integration costs

(0.08)

Amortization of commodity contract intangibles

(0.41)

Remeasurement of like kind exchange tax position

(0.20)

(0.11)

(0.31)

Amortization of the fair value of certain debt

0.01

Reassessment of state deferred income taxes

0.01

(0.01)

Midwest Generation bankruptcy charges

(0.02)

4Q 2013 GAAP Earnings (Loss) Per Share

$1.24

$0.29

$0.45

$0.23

$(0.21)

$2.00

2014 4Q Earnings Release Slides

4Q YTD GAAP EPS Reconciliation -

continued

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)

Unrealized gains related to NDT fund investments

0.10

Asset retirement obligation

0.02

Plant retirements and divestitures

0.28

Long-lived asset impairment

(0.49)

(0.02)

(0.50)

Gain on CENG integration

0.18

Merger and integration costs

(0.10)

(0.11)

(0.21)

Amortization of commodity contract intangibles

(0.07)

Tax settlements

0.12

Reassessment of state deferred income taxes

0.04

(0.01)

0.03

Bargain-purchase gain

0.03

Non-controlling interest

(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.

2014 4Q 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 2015 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

–

Financial impacts associated with the sale of interests in generating stations

–

Certain costs incurred associated with the Integrys acquisition and Pepco Holdings, Inc. merger and

integration initiatives

–

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

the date of acquisition of Integrys Energy Services in 2014

–

Other unusual items

2014 4Q Earnings Release Slides

Adjusted O&M Reconciliations to GAAP

2014 Adjusted O&M Reconciliation (in $M)

(3)

ExGen

ComEd

PECO

BGE

Other

Exelon

GAAP O&M

$5,575

$1,450

$875

$700

$(25)

$8,575

PHI Merger and Acquisition Costs

(25)

Regulatory O&M

(1)

(250)

(100)

(350)

Upstream and Power Impairments

(525)

(25)

(525)

Constellation Merger Commitments

(50)

Direct cost of sales incurred to generate revenues for

certain Constellation businesses

(2)

(325)

O&M for managed plants that are partially owned

(300)

Other

(25)

Adjusted O&M (Non-GAAP, as shown on slide 4)

$4,350

$1,200

$750

$700

$(75)

$6,950

(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.

2014 4Q 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

$5,225

$1,550

$850

$775

$(75)

$8,350

PHI Acquisition Costs

(25)

Regulatory O&M

(1)

$(300)

(100)

(425)

Decommissioning

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(2)

(300)

O&M for managed plants that are partially owned

(400)

Adjusted O&M (Non-GAAP, as shown on slide 4)

$4,525

$1,250

$750

$775

$(75)

$7,225

(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.

2014 4Q Earnings Release Slides

ExGen Total Gross Margin Reconciliation to GAAP

Total Gross Margin Reconciliation (in $M)

(4)

2015

2016

2017

Revenue

Net

Purchased

Power

and

Fuel

Expense

(1)(5)

$8,100

$8,000

$8,400

Other Revenues

(2)

$(250)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(3)

$(300)

$(350)

$(450)

Total Gross Margin (Non-GAAP, as shown on slide 6)

$7,550

$7,400

$7,700

(1)

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.

(2)

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.

(3)

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

(4)

All amounts rounded to the nearest $50M.

(5)

Excludes the impact of the operating exclusion for mark-to-market due to the volatility and unpredictability of the future changes to power prices.

2014 4Q Earnings Release Slides

Exelon Generation 8-KResults of Operations and Financial Condition