Commonwealth Edison 8-K Exelon Announces Second Quarter 2015 Results

Earnings Conference Call

2

nd

Quarter 2015

July 29, 2015

Exhibit 99.2

2

Q2 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 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 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 Second Quarter 2015 Quarterly Report on

Form 10-Q (to be filed on July 29, 2015) 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 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.

3

Q2 2015  Earnings Release Slides

•

Pepco Holdings Merger

o

Received regulatory approval in

Maryland and Delaware

•

Nuclear capacity factor of 93.1%

(2)

•

Power dispatch match of 99.2%

and renewables energy capture of

96.1%

•

1

st

quartile Customer Satisfaction

Index (CSI) scores across all

utilities

•

Capacity Performance

•

Illinois Low Carbon Portfolio

Standard legislation

•

EPA Clean Power Plan

•

PECO and ComEd rate cases

•

Delivered Q2 adjusted operating

earnings of $0.59 per share,

exceeding our guidance range

(1)

Q2 2015 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, excluding Salem   

Delivered another strong quarter of financial results and operational performance across the

company

Financial

Discipline

Operational

Excellence

Regulatory

and Policy

Efforts

Opportunistic

Growth

4

Q2 2015  Earnings Release Slides

Forward Market Outlook

Q2 2015  Lower Volatility and Lower Prices

Forward Markets Reacted To Spot Prices

Impacts on Forward Markets

•

While forward natural gas prices stayed relatively flat during

the quarter, we saw a significant decrease in power prices and

subsequently heat rates in 2016 and 2017

•

The lack of liquidity in the forward power markets has

exacerbated the drops in forward power prices and heat rates

Spot Market Update

•

The spot power market in 2015 has been less volatile compared

to 2014

•

Spot market conditions are driving weaker prices:

•

Cooling  degree days

this summer have been below the 30-year

average in Chicago and near normal on the East Coast 

•

NYMEX  gas prices

averaged $2.72 in Q2 2015, while gas prices in

Q2

2014

averaged

$4.64,

a

$1.92

MMBtu

difference

year

over

year

•

TETCo

M3 basis prices

continue to stay weak with Q2 2015

averaging a $1.05 discount to NYMEX

Cool weather in the Midwest has pressured power prices across the region.  Our fundamental

view is that gas and power prices will be stronger in the forward years.

8

9

10

11

12

13

14

15

16

PJMW_HR_2016

PJMW_HR_2017

PJMNiHub_HR_2016

PJMNiHub_HR_2017

Cooling Degree Days -

Chicago

0

2

4

6

8

10

12

30-yr Average

2015

Week Number

5

Q2 2015  Earnings Release Slides

Forward Markets and Hedging Activity

(1)

Mid-point of disclosed total portfolio hedge % range was used

•

Our fundamental view remains relatively unchanged

•

We expect further upside in NiHub

forward market

based on our fundamental forecast given current

natural gas prices, expected retirements, new

generation resources, and load assumptions

We are deploying a behind ratable strategy and a cross–commodity position to broaden

exposure to power upside

•

We align our hedging strategies with our fundamental

views by leaving portfolio exposure to power price

upside

•

We have left a significant amount of our portfolio open

to moves in the power market, when considering our

behind ratable and cross commodity strategies

•

Generation 54-56% open in 2017

•

7-8% behind ratable

NiHub

Market versus Fundamental View

2017: Maintaining a More Open Position

(1)

$/MWh

27.00

28.00

29.00

30.00

31.00

32.00

33.00

34.00

35.00

2016

2017

Market as of 3/31/2015

Internal View

Market as of 6/30/2015

Approximately

$1.00/MWh

upside

Approximately

$3.00/MWh

upside

20%

25%

30%

35%

40%

45%

50%

Q4-14

Q1-15

Q2-15

2017 -

Actual

2017 -

Ratable

2017 -

Actual (excl NG hedges)

6

Q2 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

•

Load serving business had a strong quarter driven by our generation to load matching

strategy

•

Power prices declined, natural gas prices were relatively flat, and heat rates contracted during

the quarter

•

Behind ratable reflecting the fundamental upside we see in power prices in 2016 and 2017

Recent Developments

Gross Margin Category ($M)

(1)

2015

2016

2017

2015

2016

2017

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

$5,250

$5,700

$5,750

$(350)

$(200)

$(300)

Mark-to-Market of Hedges

(3,4)

$1,850

$900

$500

$550

$300

$150

Power New Business / To Go

$100

$450

$900

$(150)

$(50)

$100

Non-Power Margins Executed

$350

$200

$100

$50

$50

$50

Non-Power New Business / To Go

$100

$250

$350

$(50)

$(50)

$(50)

Total Gross Margin

(2)

$7,650

$7,500

$7,600

$50

$50

$(50)

June 30, 2015

Change from Mar 31, 2015

7

Q2 2015  Earnings Release Slides

Key Financial Messages

Expect

Q3

2015

earnings

of

$0.65

-

$0.75/share

and

narrowing

full-year

guidance

range

from

$2.25

-

$2.55/share

to

$2.35

-

$2.55/share

(3,4)

(1)

(2)

Amounts may not add due to rounding

(3)

ComEd ROE based on 30 Year average Treasury yield of 2.94% as of 6/30/15. 25 basis point move in 30 Year Treasury Rate equates to +/-$0.01 impact to EPS.

(4)

2015 earnings guidance based on expected average outstanding shares of ~892M.  Refer to Appendix for a reconciliation of adjusted non-GAAP operating EPS guidance to GAAP EPS.

HoldCo

BGE

ExGen

ComEd

PECO

Q2 2015

$0.59

-$0.01

$0.36

$0.12

$0.08

$0.05

Adjusted Operating EPS Results

(1,2)

•

Delivered adjusted (non-GAAP) operating

earnings in Q2 of $0.59/share exceeding

our guidance range of $0.45-$0.55/share

•

Utilities

Increased distribution revenues

Lower uncollectible expense at BGE

Net neutral weather impacts

•

ExGen

Lower costs to serve load

Strong portfolio management

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

8

Q2 2015  Earnings Release Slides

2015 Projected Sources and Uses of Cash

(1)

All amounts rounded to the

nearest $25M.

(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 at

ownership.

(4)

Other Financing primarily includes

expected changes in short-term

debt

and tax-exempt bond

issuance at ExGen.

(5)

Dividends are subject to

declaration by the Board of

Directors.

(6)

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

Completed financing for PHI Acquisition

including:

$4.2B Long-term debt issuance

$1.9B Equity issuance

HoldCo: Retired $0.8B LTD note at

maturity in June

Operational excellence and financial

discipline drives free cash flow reliability

Generating ~$4B of free cash flow in

2015, including $0.9B at ExGen

and

$3.3B at the Utilities

Creating value for customers, communities

and shareholders

Investing $4.7B, with $3.7B at the

Utilities and $1B at ExGen

($ in millions)

(1)

BGE

ComEd

PECO

Total

Utilities

ExGen

Corp

(6)

Exelon

2015E

Cash

Balance

3,575

Adjusted Cash Flow from Operations

(3)

600

2,000

675

3,300

3,275

25

6,600

Base CapEx and Nuclear Fuel

0

0

0

0

(2,375)

(50)

(2,450)

Free Cash Flow

600

2,000

675

3,300

900

(25)

4,175

Net Financing (excluding items below)

(75)

500

350

775

200

3,400

4,375

Project Financing

n/a

n/a

n/a

n/a

(50)

n/a

(50)

Equity Issuance

0

0

0

0

0

1,875

1,875

Contribution from Parent

0

100

0

100

0

(100)

0

Other Financing

(4)

300

75

0

350

1,125

300

1,800

Financing

225

675

350

1,225

1,275

5,475

7,975

825

2,675

1,025

4,525

2,175

5,425

12,150

Utility Investment

(700)

(2,400)

(600)

(3,700)

0

0

(3,700)

ExGen Growth

0

0

0

0

(1,050)

0

(1,050)

Dividend

(5)

(1,100)

Other CapEx and Dividend

(700)

(2,400)

(600)

(3,700)

(1,050)

0

(5,850)

Total Cash Flow

125

275

450

825

1,125

5,425

6,300

Ending Cash Balance

9,850

Total Free Cash Flow and Financing Growth

Beginning Cash Balance

(2)

(2)

9

Q2 2015  Earnings Release Slides

Exelon Generation Disclosures

June 30, 2015

10

Q2 2015  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

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

Credit Rating

Capital &

Operating

Expenditure

Dividend

Capital

Structure

11

Q2 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

•Load Response

•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

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

12

Q2 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 June 30, 2015 market conditions

Gross Margin Category ($M)

(1)

2015

2016

2017

Open

Gross

Margin

(including

South,

West

&

Canada

hedged

GM)

(3)

$5,250

$5,700

$5,750

Mark-to-Market of Hedges

(3,4)

$1,850

$900

$500

Power New Business / To Go

$100

$450

$900

Non-Power Margins Executed

$350

$200

$100

Non-Power New Business / To Go

$100

$250

$350

Total Gross Margin

(2)

$7,650

$7,500

$7,600

Reference Prices

(5)

2015

2016

2017

Henry Hub Natural Gas ($/MMbtu)

$2.86

$3.17

$3.36

Midwest: NiHub ATC prices ($/MWh)

$28.75

$30.65

$30.17

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

$37.89

$38.27

$36.99

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$3.43

$3.82

$4.06

New York: NY Zone A ($/MWh)

$33.12

$34.03

$33.52

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

ALQN Gas, 7.5HR, $0.50 VOM

$4.85

$8.77

$9.87

13

Q2 2015  Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2015

2016

2017

Exp. Gen (GWh)

(1)

190,300

198,500

204,200

Midwest

96,500

97,300

95,900

Mid-Atlantic

(2)

61,700

63,000

61,000

ERCOT

12,700

16,300

25,300

New York

(2)

9,300

9,300

9,300

New England

10,100

12,600

12,700

% of Expected Generation Hedged

(3)

77%-80%

46%-49%

Midwest

97%-100%

72%-75%

38%-41%

Mid-Atlantic

(2)

100%-103%

82%-85%

55%-58%

ERCOT

99%-102%

93%-96%

60%-63%

New York

(2)

94%-97%

76%-79%

48%-51%

New England

99%-102%

67%-70%

28%-31%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$35.00

$34.00

$34.00

Mid-Atlantic

(2)

$49.50

$45.50

$44.50

ERCOT

(5)

$19.50

$10.00

$7.00

New York

(2)

$46.50

$41.50

$39.00

New England

(5)

$32.50

$19.00

$17.00

(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  93.3%, 94.1% and 93.4% in 2015 , 2016 and 2017 respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 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. 

98%-101%

14

Q2 2015  Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

(1)

Based on June 30, 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)

2015

2016

2017

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$(80)

$140

$400

-

$1/Mmbtu

$90

$(135)

$(385)

NiHub ATC Energy Price

+ $5/MWh

-

$135

$305

-

$5/MWh

-

$(135)

$(305)

PJM-W ATC Energy Price

+ $5/MWh

$(10)

$60

$145

-

$5/MWh

$10

$(55)

$(140)

NYPP Zone A ATC Energy Price

+ $5/MWh

-

$5

$20

-

$5/MWh

-

$(10)

$(20)

Nuclear Capacity Factor

+/-

1%

+/-

$20

+/-

$45

+/-

$40

15

Q2 2015  Earnings Release Slides

ExGen Hedged Gross Margin Upside/Risk

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

$8,950

$6,500

$7,750

$7,500

$8,050

$7,000

(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 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 June 30, 2015

(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 29for a Non-GAAP to GAAP reconciliation of Total Gross Margin Excludes EDF’s equity ownership share of the CENG Joint Venture.

16

Q2 2015  Earnings Release Slides

Illustrative Example of Modeling Exelon Generation                  

2016 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

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.

Row

Item

Midwest

Mid-Atlantic

ERCOT

New York

New England

South, West &

Canada

(A)

(B)

97.3

63.0

16.3

9.3

12.6

(C)

73.5%

83.5%

94.5%

77.5%

68.5%

(D=B*C)

71.5

52.6

15.4

7.2

8.6

(E)

$34.00

$45.50

$10.00

$41.50

$19.00

(F)

$30.65

$38.27

$3.82

$34.03

$8.77

(G=E-F)

$3.35

$7.23

$6.18

$7.47

$10.23

(H=D*G)

$240

$380

$95

$55

$90

(I=A+H)

(J)

(K)

(L)

Start with fleet-wide open gross margin  

Expected Generation (TWh)

Hedge % (assuming mid-point of range)

Hedged Volume (TWh)

Effective Realized Energy Price ($/MWh)

Reference Price ($/MWh)

Difference ($/MWh)

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

(1)

Hedged Gross Margin ($ million)

Power New Business / To Go ($ million)

Non-Power Margins Executed ($ million)

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

$200

$250

$5.7 billion

$6,600

$450

(N=I+J+K+L)

Total Gross Margin

(2)

$7,500 million

17

Q2 2015  Earnings Release Slides

Additional Disclosures

18

Q2 2015  Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key Drivers  –

2Q15 vs. 2Q14

:

BGE

(+0.03):

•

Decreased uncollectible expense: $0.02

•

Increased distribution revenue due to increased rates: $0.01

PECO (-0.02):

•

Increased storm costs: ($0.01)

ComEd

(-0.01):

•

Unfavorable weather

(2)

: $(0.01)

•

Increased distribution

(2)

earnings due to increased capital

investments: $0.01

2Q 2015

$0.25

$0.12

$0.08

$0.05

2Q 2014

$0.25

$0.13

$0.10

$0.02

BGE

ComEd

Numbers may not add due to rounding.

(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.

PECO

(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.

19

Q2 2015  Earnings Release Slides

ExGen Adjusted Operating EPS Contribution

(1)

$0.36

Q2

$0.27

2015

2014

Numbers may not add due to rounding

(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.

(excludes Salem)

Q2

2014 Actual

Q2

2015

Actual

Planned

Refueling

Outage

Days

108

71

Non-refueling

Outage

Days

44

18

Nuclear

Capacity

Factor

91.8%

93.1%

Key Drivers –

Q2 2015 vs. Q2 2014

ExGen

(+0.09)

•

Increased RNF: $0.10

•

Increased nuclear output in 2015, primarily due to a reduction in

outage days: $0.07

•

Favorability from portfolio management optimization activities,

partially offset by the absence of various generating units sold in

2014 and 2015: $0.02

•

Increased capacity revenue: $0.01

•

Higher realized NTDF gains: $0.03

•

Increased income tax expense due to decreased domestic production

activities deduction: ($0.03)

•

Increased interest expense: ($0.01)

20

Q2 2015  Earnings Release Slides

2015 Regulatory and Legislative Timelines

Settlement Filed

in New Jersey

(Jan 14)

New Jersey

Approval

(Feb 11)

Settlement

filed in

Delaware

(Feb 13)

Multi-party

Settlement

filed in

Maryland

(March 16)

Maryland

Settlement

Hearings (April

15-21)

DC Initial

Briefs Due

(May 13)

Maryland PSC

Approval (May

15)

DC Reply

Briefs Due

(May 27)

Delaware

Approval

(June 2)

Expected

Transaction

Close (Q3)

Illinois Legislative

Session Begins

(Jan 14)

IL Senate

Committee

approves LCPS &

ComEd legislation

(March 27)

MATS Rule in

Effect (April)

Supreme Court

decision on cert in

EPSA v. FERC

(Demand

Response) (May)

Illinois Regular

Legislative

Session Ends

(May 31)

Supreme Court

Decision in

Michigan vs. EPA

(MATS) (June)

FERC Approves

Capacity

Performance

(June 9)

PJM BRA Auction

Results (Aug. 21)

Final Clean Power

Rule (111d)

Issued (Aug/Sept)

Illinois Legislative

Veto Session (TBD

Oct/Nov)

ExGen

Exelon Utilities

PHI Acquisition

PECO Electric Rate

Case and LTIIP Filing

(March 27)

ComEd Formula

Rate Filing (April15)

BGE Electric and

Gas Rate Case Filing

(TBD) MD PSC

Ruling Expected 7

Months after Filing

PaPUC

Ruling

Expected on LTIIP

Filing (Q3)

PaPUC

Ruling

Expected on PECO

Electric Rate Case

(Dec)

ICC Rules on ComEd

Formula Rate Filing

(Dec)

21

Q2 2015  Earnings Release Slides

ComEd April 2015 Distribution Formula Rate

Amounts represent ComEd’s

position filed in rebuttal testimony on July 22, 2015.

Note:  Disallowance of any items in the 2015 distribution formula rate filing could impact 2015 earnings in the form of a regulatory asset adjustment.

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.

(1)

Docket #

15-0287

Filing Year

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

Reconciliation

Year

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

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

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

Common Equity

Ratio

~

46%  for both the filing and reconciliation year

ROE

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 

Requested Rate

of Return

~ 7% for both the filing and reconciliation years

$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)

$54M decrease  ($145M decrease due to the 2014 reconciliation offset by a $91M 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

•

ICC order expected to be issued by December 11, 2015

The 2015 distribution formula rate filing establishes the net revenue requirement used to set the rates that will take 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 prior year costs (2014) and current year (2015) projected plant additions. 

•

Annual Reconciliation: For the prior calendar year (2014), this amount reconciles the revenue requirement reflected in rates during the prior

year (2014) in effect to the actual costs for that year. The annual reconciliation impacts cash flow in the following year (2016) but the earnings

impact has been recorded in the prior year (2014) as a regulatory asset.

Revenue 

Requirement 

Decrease

Rate Base

(1)

(1)

22

Q2 2015  Earnings Release Slides

PECO Electric Distribution Rate Case

Docket #

R-2015-2468981

Fully Projected Future Test Year

2016

Common Equity Ratio

53%

10.95%

Overall Rate of Return

8.2%

Proposed Rate Base

$4.1B

$190M

System Average Increase as % of overall bill

4.4%

Timeline

•

3/27/15 –

PECO

filed electric distribution rate case with PaPUC

•

8/11/15 –

8/14/15 –

Evidentiary Hearings

•

October 2015 –

ALJ Recommended Decision

•

December 2015 –

PUC Decision

•

Increased rates effective on January 1, 2016

Basis for Rate Case

•

Since last rate case (2010):

–

Electric Distribution Rate base increased by one third (approximately $1B)

–

Sales declined by 0.6%

–

Operating expenses were essentially flat (less than 1% annually)

•

Proposed investment maintains strong reliability performance with targeted

investment to address pockets with reliability issues

First Electric Distribution Rate Case since 2010

Requested Return on Equity

Revenue Requirement Increase Ask

23

Q2 2015  Earnings Release Slides

PECO

Electric

LTIIP

-

System

2020

•

PECO filed its Electric Long Term Infrastructure Improvement Plan (“LTIIP”) along

with its associated recovery mechanism the Distribution System Improvement

Charge (“DSIC”)  on March 27, 2015 (with Electric Distribution Rate Case)

o

LTIIP includes $275 million in incremental capital spending from 2016-2020

focusing on the following areas:

Cable Replacement

Storm Hardening Programs

Substation replacement and upgrades

o

DSIC mechanism will allow recovery of eligible LTIIP spend between rate

cases if the electric distribution ROE falls below the DSIC ROE established by

PaPUC. The current Electric DSIC ROE is 10.0%.

o

Expected approval in 3Q15

•

PECO also proposed the concept of constructing one or more pilot microgrid

projects as part of a future LTIIP update ($50-$100M). The objective is to

evaluate and test emerging microgrid

technologies that could enhance reliability

and resiliency by replacing obsolete infrastructure as an alternative to traditional

solutions.

24

Q2 2015  Earnings Release Slides

Exelon Utilities Load

2015E

2014

PECO

2015 load growth is driven by

modest economic growth

coupled with solid residential

customer growth, partially

offset by energy efficiency

Philadelphia GMP

1.7%

Philadelphia

Unemployment

5.3%

Notes: Data is not adjusted for leap year.  Source of economic outlook data is IHS (June 2015) and Bureau of Economic Analysis.  Assumes 2015 GDP of 2.1% and U.S. unemployment of

5.3%. 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.

2015E

2014

Large C&I

Small C&I

Residential

All Customers

ComEd

2015 load growth is lower than

2014 (impacts of energy

efficiency partially offset by

slowly improving economy)

with Residential and Large C&I

trending downward

Chicago GMP

1.7%

Chicago Unemployment

6.2%

BGE

2015 load growth is greater

than 2014, attributable to

slowly improving

economic

conditions and moderate

customer growth, partially

offset by energy efficiency

Baltimore GMP

1.3%

Baltimore Unemployment

5.6%

2015E

2014

0.3%

0.1%

1.1%

0.5%

0.0%

0.0%

0.2%

-0.1%

(0.6%)

0.2%

(0.9%)

0.3%

(0.2%)

(0.3%)

(0.9%)

0.7%

-1.2%

0.1%

-0.8%

0.1%

1.1%

-0.6%

0.0%

-1.6%

25

Q2 2015  Earnings Release Slides

Appendix

Reconciliation of Non-GAAP

Measures

26

Q2 2015  Earnings Release Slides

Three Months Ended June 30, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.36

$0.12

$0.08

$0.05

$(0.01)

$0.59

Mark-to-market impact of economic hedging activities

0.16

-

-

-

-

0.16

Unrealized losses related to NDT fund investments

(0.06)

-

-

-

-

(0.06)

Merger and integration costs

(0.01)

-

-

-

(0.01)

(0.02)

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

-

-

-

-

0.08

0.08

Amortization of commodity contract intangibles

(0.01)

-

-

-

-

(0.01)

Long-lived asset impairment

-

-

-

-

(0.02)

(0.02)

CENG Non-Controlling Interest

0.02

-

-

-

-

0.02

2Q 2015 GAAP Earnings Per Share

$0.46

$0.12

$0.08

$0.05

$0.04

$0.74

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 June 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

2014 Adjusted (non-GAAP) Operating Earnings Per Share

$0.27

$0.13

$0.10

$0.02

$-

$0.51

Mark-to-market impact of economic hedging activities

(0.01)

-

-

-

-

(0.01)

Unrealized gains related to NDT fund investments

0.09

-

-

-

-

0.09

Merger and integration costs

(0.02)

-

-

-

(0.01)

(0.03)

Amortization of commodity contract intangibles

(0.03)

-

-

-

-

(0.03)

Long-lived asset impairment

(0.06)

-

-

-

(0.02)

(0.08)

Gain on CENG integration

0.18

-

-

-

-

0.18

CENG Non-Controlling Interest

(0.03)

-

-

-

-

(0.03)

2Q 2014 GAAP Earnings Per Share

$0.39

$0.13

$0.10

$0.02

$-

$0.60

2Q GAAP EPS Reconciliation

27

Q2 2015  Earnings Release Slides

2Q YTD GAAP EPS Reconciliation

Six Months Ended June 30, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.71

$0.22

$0.24

$0.18

$(0.05)

$1.30

Mark-to-market impact of economic hedging activities

0.27

-

-

-

-

0.27

Unrealized losses related to NDT fund investments

(0.04)

-

-

-

-

(0.04)

Merger and integration costs

(0.01)

-

-

-

(0.03)

(0.04)

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

-

-

-

-

0.03

0.03

Amortization of commodity contract intangibles

0.02

-

-

-

-

0.02

Long-lived asset impairment

-

-

-

-

(0.02)

(0.02)

Midwest Generation bankruptcy recoveries

0.01

-

-

-

-

0.01

CENG Non-Controlling Interest

0.01

-

-

-

-

0.01

2Q 2015 GAAP Earnings (Loss) Per Share

$0.97

$0.22

$0.24

$0.18

$(0.07)

$1.54

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

Six Months Ended June 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.57

$0.24

$0.20

$0.12

$(0.01)

$1.12

Mark-to-market impact of economic hedging activities

(0.52)

-

-

-

-

(0.52)

Unrealized gains related to NDT fund investments

0.10

-

-

-

-

0.10

Merger and integration costs

(0.03)

-

-

-

(0.01)

(0.04)

Amortization of commodity contract intangibles

(0.06)

-

-

-

-

(0.06)

Long-lived asset impairment

(0.06)

-

-

-

(0.02)

(0.08)

Tax settlements

0.04

-

-

-

-

0.04

Gain on CENG integration

0.18

-

-

-

-

0.18

CENG Non-Controlling Interest

(0.03)

-

-

-

-

(0.03)

2Q 2014 GAAP Earnings (Loss) Per Share

$0.18

$0.24

$0.20

$0.12

$(0.04)

$0.71

28

Q2 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 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

Certain

costs

incurred

associated

with

the

Integrys

and

pending

Pepco

Holdings,

Inc.

acquisitions

Mark-to-market adjustments from forward-starting interest rate swaps related to the financing for the

pending PHI acquisition

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

the

date

of

acquisition

of

Integrys

in

2014

Impairment of investment in long-term generating leases

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

Other unusual items

29

Q2 2015  Earnings Release Slides

ExGen

Total Gross Margin Reconciliation to GAAP

Total

Gross Margin Reconciliation (in $M)

(4)

2015

2016

2017

Revenue Net of Purchased Power and Fuel Expense

(1)(5)

$8,200

$8,100

$8,300

Other revenues

(2)

$(250)

$(250)

$(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)

$7,650

$7,500

$7,600

(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