Commonwealth Edison 8-K Exelon Announces First Quarter 2014 Results

Earnings Conference Call

1

st

Quarter

2014

April 30, 2014

Exhibit 99.2

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 2013 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 First Quarter 2014 Quarterly Report on

Form 10-Q (to be filed on April 30, 2014) 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 15; 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.

1

Q1 2014 In Review

2014 1Q Earnings Release Slides

2

Q1 Highlights

Adjusted Operating EPS Results

(1,2)

•

Signs of Power Market Recovery

•

Winter Storms

•

Nuclear capacity factor: 94.1%

•

CENG License Transfer

•

ProLiance Acquisition

Regulatory Advocacy

•

PJM Capacity Market Reforms

o

Imports

o

Demand Response

o

Speculation

•

Educating Stakeholders on Nuclear

Economics

ExGen

BGE

ComEd

PECO

Q1 2014

$0.62

$0.30

$0.11

$0.10

$0.10

(1)

(2)

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.

Spot and Forward Market Volatility

2014 1Q Earnings Release Slides

3

Q1 2014 Saw Increased Volatility

Forward Markets Reacted To Spot Prices

•

Forward markets have a tendency to reflect spot market

activity

•

While forward hub natural gas prices stayed relatively flat

during the quarter, we saw a significant increase in power

prices and therefore heat rates in 2015 and 2016

•

This was especially true for PJM West Hub and the largest

impacts were due to the pricing of forward winter months

•

The spot market so far in 2014 has been very volatile

•

Polar vortex resulted in extreme conditions:

•

The spot prices in PJM started to reflect the changing nature of

the grid and new reliance on different resources such as

natural gas supply, demand response, and oil peakers

•

Even if extreme days are taken out, 2014 saw higher prices at

NiHub than previous years

$100

$90

$80

$70

$60

$50

$40

$30

$0

Daily Heating Degree Days

2014

2013

2012

NiHub LMP per Daily HDD

(Days below $100/MWh)

7/1/2013

12.0

11.5

11.0

10.5

10.0

9.5

9.0

0.0

4/1/2014

1/1/2014

4/1/2013

10/1/2013

NiHub On Peak HR -

2016

NiHub On Peak HR -

2015

Whub On Peak HR -

2016

Whub On Peak HR -

2015

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

Capacity Market Developments

2014 1Q Earnings Release Slides

4

New England

During

first

quarter,

Forward

Capacity

Auction

(FCA)

#8

for

planning

year

17/18

cleared

significantly

higher

than

last

auction.

Rest

of

Pool

cleared $7.025/kw-month and NEMA cleared $15.00/kw-month

Clearing results are indicative of a tighter supply/demand situation after the announcement of unit retirements

FCA #9 will feature a sloped demand curve for Rest of Pool resulting in a more stable market design

A  vertical demand curve for constrained zones (i.e., NEMA) remains in place until FCA #10

FERC is expected to rule on the ISO’s proposed Performance Incentives Forward Capacity Market redesign by mid-May

New York ISO

NYISO’s Summer Strip Auction cleared higher year-over-year for both Rest of State (ROS) and NYC

Beginning in May 2014 Lower Hudson Valley (LHV) has been broken out from ROS as a separate capacity zone to enhance reliability

MISO

MISO’s 2    annual capacity auction cleared higher year-over-year but is still lower than recent results in neighboring PJM RTO

We are evaluating recent reports and studies that are showing a tighter supply/demand picture in several MISO zones as plants retire

PJM –

RPM rule/market design changes

Change in DR clearing mechanism which limits total volume of Limited DR and aggregate Sub-Annual products consistent with reliability limits

Standardization of demand response capacity sales plans that require Officer Certification of intent to deliver

Steam units required to apply temperature correction to establish Installed Capacity (ICAP) ratings

Limits on imports into RTO subject to a “pseudo-tie exemption”

FERC is expected to rule on PJM’s proposed speculation reforms before the auction opens

nd

Hedging Activity and Market Fundamentals

5

Fundamental

View

vs.

Market

-

2015

2015: Rotating into a Large Heat Rate Strategy

(1)

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

2015-Actual (excl NG hedges)

2015-Ratable

2015-Actual

•

We align our hedging strategies with our fundamental

views by leaving portfolio exposure to power price upside

•

As forward heat rates have moved, we have shifted

between our two strategies of falling behind ratable and

hedging with Natural Gas

•

When considering our behind ratable and cross commodity

strategies, we have left a significant amount of our portfolio

open to moves in the power market: 

•

Approximately 45% open in 2015

•

Approximately 70% open in 2016

We are deploying a behind ratable strategy and a cross-commodity position in

order to leave exposure to power upside

4Q12

3Q12

1Q14

4Q13

3Q13

2Q13

1Q13

•

Structural changes in the stack and weather drove higher

prices and volatility in the spot energy market during Q1

•

The forward market has incorporated some of the upside

especially for PJM West Hub and more so in winter

months

•

We expect further upside in NiHub forward heat rates

based on our fundamental forecast given current natural

gas prices, expected retirements, new generation

resources, and load assumptions

$60

$55

$50

$45

$40

$35

$15

1Q14

4Q13

3Q13

2Q13

1Q13

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

Market PJMW

Fundamental View PJMW

Market NiHub

Fundamental View NiHub

2014 1Q Earnings Release Slides

10%

20%

30%

40%

50%

60%

70%

80%

Exelon Generation: Gross Margin Update

March 31, 2014

Change from Dec 31, 2013

Gross Margin Category ($M)

(1)

2014

2015

2016

2014

2015

2016

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

7,350

6,350

6,250

1,500

650

600

Mark-to-Market of Hedges

(3,4)

(700)

100

100

(1,450)

(400)

(150)

Power New Business / To Go

250

600

650

(100)

(50)

(50)

Non-Power Margins Executed

250

100

50

150

50

-

Non-Power New Business / To Go

150

300

350

(150)

(50)

-

7,300

7,450

7,400

(50)

200

400

2014 1Q Earnings Release Slides

•

Severe weather in our load serving regions led to significant power and gas volatility, which

allowed

us

to

execute

on

a

significant

piece

of

our

new

business

targets

•

Our balanced generation to load strategy, as well as our geographic and commodity diversity,

allowed us to navigate through several offsetting issues

•

The return of volatility to the markets may lead to more appropriate pricing of risk premiums

Recent Developments

6

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

certain Constellation businesses.  See Slide 25 for a Non-GAAP to GAAP reconciliation of Total

Gross Margin.

3)

Includes Exelon’s proportionate ownership share of the CENG Joint Venture.

4)

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

Key Financial Messages

•

Delivered adjusted (non-GAAP)

operating earnings in Q1 of

$0.62/share within guidance range

provided of $0.60-$0.70/share

Q1 2014 vs. Q1 2013:

•

Utilities

–

Increased distribution revenue

–

Increased storm costs

•

ExGen

–

Lower realized gross margin

–

Increased capacity pricing

2014 1Q Earnings Release Slides

7

Expect

Q2

2014

earnings

of

$0.40

-

$0.50/share

and

re-affirm

full-year

guidance

range

of $2.25

-

$2.55/share

(2)

HoldCo

ExGen

ComEd

PECO

BGE

Q1 2013

$0.70

Q1 2014

$0.62

-$0.02

$0.39

$0.10

$0.14

$0.09

$0.30

$0.11

$0.10

$0.10

Adjusted Operating EPS Results

(1,3)

(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)

2014 earnings guidance based on expected average outstanding shares of ~860M.  Refer to Appendix for a reconciliation of adjusted (non-GAAP operating EPS guidance to GAAP EPS )

(3)

Amounts may not add due to rounding.

2014 1Q Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

BGE

(+0.01):

•

Increased distribution revenue due to rate cases: $0.03

•

Increased storm costs: $(0.01)

PECO

(-0.04):

•

Increased storm costs, primarily due to the February 5,

2014 ice storm: $(0.05)

•

Weather: $0.02

ComEd

(+0.01):

•

Weather

(2)

: $0.01

•

Increased distribution revenue due to increased capital

investment

and

higher

allowed

ROE

(2)

:

$0.01

•

Tax interest related to 1999-2001 IRS tax settlement

adjustment recorded in the first quarter of 2013: ($0.01)

2014 1Q Earnings Release Slides

$0.33

$0.09

$0.14

$0.10

Q1 2014

$0.31

$0.10

$0.10

$0.11

Q1 2013

ComEd

PECO

BGE

8

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.

(2)

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

weather, load and changes in customer mix.

Key Drivers –

Q1 2014 vs. Q1 2013:

ExGen Adjusted Operating EPS Contribution

(1)

2014 1Q Earnings Release Slides

Q1 2014

2014

2013

(excludes Salem and CENG)

Q1 2013

Actual

Q1 2014

Actual

Planned Refueling Outage Days

49

52

Non-refueling Outage Days

6

20

Nuclear Capacity Factor

96.4%

94.1%

•

Lower realized energy prices and higher

procurement costs for replacement power $(0.09)

•

Decrease in nuclear and fossil output in 2014,

primarily due to outage days $(0.05)

•

Higher nuclear fuel amortization and fossil fuel

costs $(0.04)

•

Partially offset by increased capacity pricing $0.08

9

(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.

Key Drivers –

Q1 2014 vs. Q1 2013

2014 Projected Sources and Uses of Cash

Key

Messages

•

Cash from Operations is projected to be $6,200M vs Plan of

$6,100M for a $100M variance. This variance is driven by:

$150M Reclassification of CENG capital expenditure at EXC

ownership

($50M) Lower Constellation gross margin due to plant

underperformance

•

Cash from Financing activities is projected to be equal to Plan

of ($825M)

•

Cash from Investing activities is projected to be ($5,375M) vs

Plan of ($5,475M) for a $100M variance. This variance is driven

by:

$325M early lease termination fee received at Corporate from the

City of San Antonio Public Service (“CPS”)

($150M) Reclassification of CENG Capital Expenditure at EXC

ownership

($50M) Higher PECO CapEx primarily due to January Ice Storm

($25M) ExGen:

additional turbine purchases at Fourmile wind, CENG

capital at ownership, and gas and hydro.

Projected

Sources

&

Uses

(1)

Excludes counterparty collateral of $134 million at 12/31/2013. In addition, the 12/31/2014 ending cash balance does not

include collateral.

(2)

Adjusted Cash Flow from Operations (non-GAAP) primarily includes net cash flow from operating activities

and net cash flows

from investing activities excluding capital expenditures of $5.4B for 2014. For March 31, 2014, includes EDF’s proportionate

ownership share of CENG Joint Venture CapEx and Nuclear Fuel.  For December 31, 2013, includes 100% of CENG Joint

Venture CapEx and Nuclear Fuel.

(3)

For March 31, 2014, excludes EDF’s proportionate ownership share of CENG Joint Venture CapEx and Nuclear Fuel.  For

December 31, 2013, excludes 100% of CENG Joint Venture CapEx and

Nuclear Fuel.

(4)

Dividends are subject to declaration by the Board of Directors.

(5)

“Other”

includes

CENG

distribution

to

EDF,

proceeds

from

stock

options,

and

expected

changes in short-term debt.

(6)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities. CapEx for Exelon is shown net of

$325M CPS early lease termination fee.

(7)

All amounts rounded to the nearest $25M.

(8)

Net 2014 sources and uses for each operating company are expected to be $0M, $325M, $100M and $600M for BGE,

ComEd, PECO and ExGen, respectively

2014 1Q Earnings Release Slides

10

($ in millions)

BGE

ComEd

PECO

ExGen

Exelon

(6)

As of 4Q13

Variance

1,475

1,475

675

1,425

600

3,475

6,200

6,100

100

(525)

(1,575)

(500)

(1,175)

(3,475)

(3,675)

200

n/a

n/a

n/a

(975)

(975)

(900)

(75)

(1,075)

(1,075)

n/a

n/a

n/a

(150)

(150)

(150)

n/a

n/a

n/a

(75)

(75)

(75)

n/a

n/a

n/a

(200)

(200)

(200)

n/a

n/a

n/a

(50)

(50)

(25)

(25)

(75)

(200)

(175)

n/a

(450)

(450)

950

300

1,250

1,200

50

(625)

(250)

(525)

(1,375)

(1,375)

n/a

n/a

n/a

675

675

675

Adjusted Cash Flow from

Operations

(3)

CapEx (excluding other items below):

(3)

Nuclear Fuel

Dividend

(4)

Nuclear Uprates

Wind

Solar

Upstream

Utility Smart Grid/Smart Meter

Net Financing (excluding Dividend):

Debt Issuances

Debt Retirements

Project Finance/Federal Financing

Bank Loan

Other

(5)

(75)

350

125

(400)

(300)

(250)

(50)

1,475

1,275

200

(7)

(7,8)

(2)

Exelon Generation Disclosures

March 31, 2014

2014 1Q Earnings Release Slides

11

2014 1Q 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

2014 1Q Earnings Release Slides

12

Credit Rating

Capital &

Operating

Expenditure

Dividend

Capital

Structure

•

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

Strategic Policy Alignment

Three-Year Ratable Hedging

Bull / Bear Program

Components of Gross Margin Categories

2014 1Q Earnings Release Slides

13

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

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

Load Response

Energy Efficiency

(4)

BGE Home

(4)

Distributed Solar

Portfolio

Management /

origination fuels

new business

Proprietary

Trading

(3)

Retail, Wholesale

executed gas sales

Load Response

Energy Efficiency

(4)

BGE Home

(4)

Distributed Solar

Retail, Wholesale

planned electric

sales

Portfolio

Management new

business

Mid marketing new

business

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

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)

)

(1) Hedged

gross

margins

for

South,

West

and

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

remain

within

“Non

Power”

New

Business

category

and

not

move

to

“Non

Power”

Executed

category.

(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.

Retail, Wholesale

planned gas sales

ExGen Disclosures 

Gross Margin Category ($M)

(1)

2014

2015

2016

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

7,350

6,350

6,250

Mark to Market of Hedges

(3,4)

(700)

100

100

Power New Business / To Go

250

600

650

Non-Power Margins Executed

250

100

50

Non-Power New Business / To Go

150

300

350

Total

Gross

Margin

(2)

7,300

7,450

7,400

2014 1Q Earnings Release Slides

14

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 and variable interest entities. Total Gross Margin is also net of direct cost of

sales for certain Constellation businesses. See Slide 25 for a Non-GAAP to GAAP

reconciliation of Total Gross Margin.

Includes Exelon’s proportionate ownership share of the CENG Joint Venture.

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

(4)

Based on March 31, 2014 market conditions.

(5)

(1)

(2)

(3)

Reference Prices

(5)

2014

2015

2016

Henry

Hub Natural Gas ($/MMbtu)

$4.58

$4.20

$4.15

Midwest: NiHub ATC prices ($/MWh)

$39.73

$31.82

$31.84

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

$54.44

$40.59

$39.45

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$8.76

$8.57

$7.69

New York: NY Zone A ($/MWh)

$53.86

$40.42

$38.16

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

ALQN Gas, 7.5HR, $0.50 VOM

$4.08

$4.85

$2.90

2014 1Q Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2014

2015

2016

Exp. Gen (GWh)

(1)

210,200

203,500

204,600

Midwest

97,300

96,700

97,700

Mid-Atlantic

(2)

75,000

70,800

71,800

ERCOT

16,400

19,000

19,200

New York

(2)

12,700

9,400

9,300

New England

8,800

7,600

6,600

% of Expected Generation Hedged

(3)

91-94%

64-67%

37-40%

Midwest

91-94%

66-69%

36-39%

Mid-Atlantic

(2)

90-93%

63-66%

37-40%

ERCOT

93-96%

61-64%

42-45%

New York

(2)

94-97%

65-68%

47-50%

New England

91-94%

53-56%

15-18%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$36.50

$32.50

$33.00

Mid-Atlantic

(2)

$49.00

$42.00

$43.00

ERCOT

(5)

$12.00

$7.00

$5.00

New York

(2)

$43.00

$43.50

$37.50

New England

(5)

$9.00

$4.00

$0.50

2014 1Q Earnings Release Slides

15

(1) Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity.  Expected generation is

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 2014 and 2015 and 12 refueling outages in 2016 at Exelon-operated nuclear plants, Salem

and CENG.  Expected generation assumes capacity factors of  93.6%, 93.3% and 94.4% in 2014, 2015 and 2016 at Exelon-operated nuclear plants excluding Salem and

CENG. These estimates of expected generation in 2015 and 2016 do not represent guidance or a forecast of future results as Exelon has not completed its planning or

optimization processes for those years. (2) Includes Exelon’s proportionate 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. Uses expected

value on options. (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.

2014 1Q Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges) 

(1, 2)

2014

2015

2016

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$60

$285

$490

-

$1/Mmbtu

$(55)

$(230)

$(455)

NiHub ATC Energy Price

+ $5/MWh

$20

$250

$380

-

$5/MWh

$(20)

$(245)

$(375)

PJM-W ATC Energy Price

+ $5/MWh

$10

$125

$220

-

$5/MWh

$-

$(120)

$(210)

NYPP Zone A ATC Energy Price

+ $5/MWh

$-

$15

$25

-

$5/MWh

$-

$(15)

$(25)

Nuclear Capacity Factor

(3)

+/-

1%

+/-

$50

+/-

$45

+/-

$45

2014 1Q Earnings Release Slides

16

(1) Based on March 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 price 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.  (2) Sensitivities based on commodity exposure which includes open generation and all committed transactions. 

(3) Includes Exelon’s proportionate ownership share of the CENG Joint Venture.

Exelon Generation 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

2016

$9,200

2015

$8,500

2014

$7,550

$7,000

$6,550

$5,950

2014 1Q Earnings Release Slides

17

(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 2014, 2015 and 2016 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 March 31, 2014 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. (3) Gross

margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners and 

variable interest entities . See Slide 25 for a Non-GAAP to GAAP reconciliation of Gross Margin.

Illustrative Example of Modeling Exelon Generation             

2015 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$6.35 billion

(B)

Expected Generation (TWh)

96.7

70.8

19.0

9.4

7.6

(C)

Hedge % (assuming mid-point of range)

67.5%

64.5%

62.5%

66.5%

54.5%

(D=B*C)

Hedged Volume (TWh)

65.3

45.7

11.9

6.3

4.1

(E)

Effective Realized Energy Price ($/MWh)

$32.50

$42.00

$7.00

$43.50

$4.00

(F)

Reference Price ($/MWh)

$31.82

$40.59

$8.57

$40.42

$4.85

(G=E-F)

Difference ($/MWh)

$0.68

$1.41

$(1.57)

$3.08

$(0.85)

(H=D*G)

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

(1)

$45 million

$65 million

$(20) million

$20 million

$(5) million

(I=A+H)

Hedged Gross Margin ($ million)

$6,450 million

(J)

Power New Business / To Go ($ million)

$600 million

(K)

Non-Power Margins Executed ($ million)

$100 million

(L)

Non-

Power New Business / To Go ($ million)

$300 million

(N=I+J+K+L)

Total Gross Margin

(2)

$7,450 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 and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation businesses. See Slide 25 for a Non-GAAP to GAAP reconciliation of Total

Gross Margin.

2014 1Q Earnings Release Slides

18

Additional Disclosures

2014 1Q Earnings Release Slides

19

2014 1Q Earnings Release Slides

BGE

Strong residential growth drives the

load in 2014. Improving economic

conditions are offset by continued

energy efficiency

Exelon Utilities Weather-Normalized Load

2014E

0.5%

-0.4%

0.3%

0.2%

2013

-0.3%

-0.5%

0.0%

-0.2%

Large C&I

Small C&I

Residential

All Customers

ComEd

2014 overall load growth is slightly

above 2013 due to slowly improving

economic conditions with partially

offsetting energy efficiency

2014E

2.0%

-1.7%

0.2%

0.6%

2013

1.5%

-1.1%

0.0%

0.3%

PECO

2014 load growth is driven primarily

by Large C&I, partially offset by

Small C&I. Improved economic &

customer growth is partially offset

by energy efficiency

2014E

-0.1%

0.1%

1.6%

0.6%

2013

-3.2%

2.1%

2.0%

-0.6%

Chicago GMP

2.4%

Chicago Unemployment

8.2%

Philadelphia GMP

1.9%

Philadelphia Unemployment

7.1%

Baltimore GMP

2.4%

Baltimore Unemployment

6.2%

2014 1Q Earnings Release Slides

20

2014 1Q Earnings Release Slides

Notes:  Data is not adjusted for leap year. Source of economic outlook data is Global Insight (February 2014). Assumes 2014 GDP of 2.7% and U.S unemployment of 6.7%.

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 true-up load from prior quarters.

Appendix

Reconciliation of Non-GAAP

Measures

22

2014 1Q Earnings Release Slides

Q1 2014 GAAP EPS Reconciliation

Three Months Ended March 31, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.30

$0.11

$0.10

$0.10

$-

$0.62

Mark-to-market impact of economic hedging activities

(0.52)

-

-

-

-

(0.52)

Unrealized gains related to NDT fund investments

0.01

-

-

-

-

0.01

Merger and integration costs

(0.01)

-

-

-

-

(0.01)

Amortization of commodity contract intangibles

(0.04)

-

-

-

-

(0.04)

Tax Settlements

0.04

-

-

-

-

0.04

Q1 2014 GAAP Earnings (Loss) Per Share

$(0.22)

$0.11

$0.10

$0.10

$-

$0.10

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

2014 1Q Earnings Release Slides

23

Three Months Ended March 31, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings Per Share

$0.39

$0.10

$0.14

$0.09

$(0.02)

$0.70

Mark-to-market impact of economic hedging activities

(0.29)

-

-

-

0.01

(0.27)

Unrealized gains related to nuclear decommissioning trust funds

0.04

-

-

-

-

0.04

Plant retirements and divestitures

0.02

-

-

-

-

0.02

Merger and integration costs

(0.03)

-

(0.00)

0.00

0.00

(0.03)

Amortization of commodity contract intangibles

(0.14)

-

-

-

-

(0.14)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

Remeasurement of like-kind exchange tax position

-

(0.20)

-

-

(0.11)

(0.31)

Nuclear uprate project cancellation

(0.02)

-

-

-

-

(0.02)

Q1 2013 GAAP Earnings (Loss) Per Share

$(0.02)

$(0.09)

$0.14

$0.09

$(0.12)

$(0.01)

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.

2014 1Q Earnings Release Slides

24

•

Exelon’s 2014 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 Constellation and CENG merger and integration initiatives

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

the merger date for 2014

Favorable settlements of certain income tax positions on Constellation’s 2009-2012 tax returns

One-time impacts of adopting new accounting standards

Other unusual items

ExGen Total Gross Margin Reconciliation to GAAP

Total Gross Margin Reconciliation (in $M)

(5)

2014

2015

2016

Revenue

Net

of

Purchased

Power

and

Fuel

Expense

(1)(6)

$7,800

$8,050

$8,050

Non-cash amortization of intangible assets, net, related to

commodity

contracts

recorded

at

fair

value

at

the

merger

date

(2)

$50

-

-

Other Revenues

(3)

$(250)

$(300)

$(300)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(4)

$(300)

$(300)

$(350)

Total Gross Margin (Non-GAAP, as shown on slide 14)

$7,300

$7,450

$7,400

2014 1Q Earnings Release Slides

25

(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)

The exclusion from operating earnings for activities related to the merger with Constellation ends after 2014.

(3)

Reflects revenues from Exelon Nuclear Partners, variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through

regulated rates and gross receipts tax revenues.

(4)

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

(5)

All amounts rounded to the nearest $50M.

(6)

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 1Q Earnings Release Slides