Commonwealth Edison 8-K Results of Operations and Financial Condition

Earnings Conference Call

2  

Quarter 2013

July

31  ,

2013

Exhibit 99.2

nd

st

Cautionary Statements Regarding

Forward-Looking Information

1

2013 2Q Earnings Release Slides

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 2012 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 19; (2) Exelon’s First Quarter 2013 Quarterly Report

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

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

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

Financial Statements: Note 17; 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 press release.

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.

2013 2Q Earnings Release Slides

•

Current 5-year plan includes $16B of 

growth CapEx (~$13.5B at Utilities)

•

Installed 99 MW at AVSR YTD with 

another 102 MW to come on line in 2013

•

Adding 46 MW to wind portfolio in 2014 

with the Beebe 1B project

•

Continued smart meter installation at 

PECO, BGE and ComEd

•

2Q13 nuclear capacity factor of 92.8%

and YTD 2013 capacity factor of 94.6%

•

Entered into agreement with EDF to

operate the CENG plants

•

Dispatch match rate for fossil and hydro

fleet of 99.1% and energy capture rate

for wind and solar fleet of 92.4%

•

Top decile safety performance for

ComEd, PECO and BGE

•

SB9 was enacted clarifying language in

EIMA.  ComEd made annual filing for

distribution with ICC

•

BGE filed a rate case in May with the

MDPSC

•

Engaged in PJM stakeholder process

around RPM

•

Delivered 2Q earnings within our

guidance range

•

Canceled LaSalle and Limerick EPU

projects

•

On track to achieve $550M of annual

run-rate merger synergies by 2014

•

Identified additional O&M savings at

ExGen

2013 2Q Earnings Release Slides

2

2Q13 In Review

2013 Expectations:

•

Deliver

3Q13

operating

earnings

within

guidance

range

of

$0.60

-

$0.70/share

(1)

•

On-track

to

achieve

full-year

operating

earnings

within

guidance

range

of

$2.35

-

$2.65/share

(1)

as

disclosed on 4Q12 earnings call

(1)

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

Financial

Discipline

Operational

Excellence

Opportunistic

Growth &

Investment

Regulatory

Advocacy

AVSR = Antelope Valley Solar Ranch.  EIMA = Energy Infrastructure Modernization Act.   EPU = Extended Power Uprate.  ICC = Illinois Commerce Commission.  MDPSC = Maryland Public Service 

Commission. O&M = Operating  & Maintenance.  RPM = Reliability Pricing Model.

RPM Results

3

Coal

Fired

Gen-BRA

Offers

(2)

(GW)

%

of

Unforced

Capacity

Procured

by

Type

(1)

16/17

59

49

15/16

59

54

14/15

65

56

13/14

67

65

2

Cleared

Uncleared

RPM Clearing Trends

(1)

Sources: (1) PJM RPM Base Residual Auction Results Reports (2) RPM Commitments by Fuel

Type by DY

(2)

Estimated

based

on

PY

16/17

PJM

Base

Residual

Auction

Results.

Includes

imports.

For

comparability, PJM geographical additions included by adding initial BRA offered and cleared

quantities to previous years.

Total

GW

•

Decrease in existing coal-fired

generation

•

6.3 GW of coal retirements in 2012

alone

•

10 GW in the PJM deactivation queue

for 2013 -

2015

•

Internal estimate: ~ 22 GW for 2012 -

2016

•

Increase in planned gas-fired

generation

•

Increase in cleared GW of Energy

Efficiency (EE), Demand Response

(DR), and Imports

95%

85%

90%

100%

80%

0%

169

79%

9%

12%

15/16

165

84%

16/17

14/15

150

87%

1%

5%

153

90%

1%

9%

13/14

Existing Gen as of 13/14 (incl. Wind)

Cumulative New/Gen Uprates since 13/14

Cleared EE, DR and Imports Combined

Recommended Reserve Margin (~15.6%)

12%

12%

9

5

10

2013 2Q Earnings Release Slides

BRA = Base Residual Auction. RPM = Reliability Pricing Model. PY = Plan Year.

Notes: (1) PY 13/14 includes ATSI (2) PY 14/15 includes Duke  (3) PY 15/16 includes significant portion

of AEP and DEOK zone load previously under FRR alternative  (4) PY 16/17 includes EKPC (5) PY 13/14

is base year for cumulative New Gen and Uprates

Hedging Activity and Market Fundamentals

4

2013 2Q Earnings Release Slides

Fundamental

View

vs.

Market

-

2015

%

of

Expected

Generation

Hedged

(1)

-

Total

Portfolio

(1)

Mid-point of disclosed hedge % range was used

$60

$55

$50

$45

$40

$35

$15

1Q13

3Q12

1Q12

3Q11

1Q11

2Q13

1Q13

4Q12

3Q12

2015-Ratable

2015-Actual

2015-Actual (excl NG hedges)

Market PJMW

Fundamental View PJMW

Market NiHub

Fundamental View NiHub

50%

45%

40%

35%

30%

25%

15%

20%

•

Structural changes in the stack are expected to increase volatility in the spot energy market and drive prices

higher than current market

•

Continue to see a disconnect in forward heat rates compared to our fundamental forecast given current

natural gas prices, expected retirements, new generation resources, and load assumptions

•

We align our hedging  strategies with our fundamental views

•

We have widened our deviation from ratable across our entire portfolio over the past 6 months to

approximately 8%

•

Use of natural gas as a cross-commodity hedge leaves more upside to heat rate expansion

Market Fundamentals

Impacts of our view on our hedging activity

2013 2Q Earnings Release Slides

Exelon Generation: Gross Margin Update

June 30, 2013

Delta to March 31, 2013

Gross

Margin

Category

($M)

(1)

(2)

2013

2014

2015

2013

2014

2015

Open Gross Margin

(3)

(including South, West, Canada hedged gross margin)

5,750

5,700

5,900

(250)

(650)

(500)

Mark-to-Market

of

Hedges

(3,4)

1,450

850

400

250

450

150

Power New Business / To Go

200

550

750

(150)

(50)

(50)

Non-Power Margins Executed

350

150

50

50

50

0

Non-Power

New

Business

/

To

Go

(5)

250

450

550

(50)

(50)

0

Total Gross Margin

8,000

7,700

7,650

(150)

(250)

(400)

Key Changes in 2Q 2013

•

2013:

AVSR delays; $50M due to FTR under collection; and $50M due to

lower power new business targets

•

2014:

power new business targets

•

2015:

power new business targets

•

Reducing 2013 ExGen O&M by $100M ($50M at Constellation to

offset lower new business targets) and targeting reductions in

2014 and 2015 to result in a roughly flat O&M CAGR for 2013 -

2015

2013 2Q Earnings Release Slides

Retail & Wholesale Load (TWh)

30-40%

60-70%

150

155

2013E

25-35%

155

2015E

2014E

25-35%

Wholesale Load

Total Contracted

Retail Load

65-75%

65-75%

Numbers and percentages are rounded to the nearest 5.

Index load expected to be 20% to 30% of total forecasted retail load.

5

Reduction of $50M due to unplanned nuclear outages and

$350M reduction due to prices and $50M reduction in

$200M reduction due to prices and $50M reduction in

1)

Gross margin rounded to nearest $50M.

2)

Gross margin does not include revenue related to decommissioning, gross receipts tax,

Exelon Nuclear Partners and entities consolidated solely as a result of the application of

FIN 46R.

3)

Includes CENG Joint Venture.

4)

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

5)

Any changes to new business estimates for our non-power business are presented as

revenue less costs of sales.

200

150

100

50

0

FTR = Financial Transmission Rights.

CAGR = Compound Annual Growth Rate.

Key Financial Messages

6

2013 2Q Earnings Release Slides

•

Delivered non-GAAP operating earnings   

in 2Q

of $0.53/share within guidance range

provided of $0.50 -

$0.60/share

2Q 2013 vs. Guidance

•

Reduction of wholesale new business targets

and unplanned nuclear outages

•

Favorable impacts of SB9 at ComEd

Full Year 2013 vs. Guidance

•

Reduction of wholesale new business targets

•

Reduction of 2013 ExGen O&M by $100M

•

Favorable load at ComEd and PECO

•

Lower ExGen effective tax rate

•

Favorable interest related to tax positions

•

Favorable impacts of SB9 at ComEd

•

Lower depreciation and other favorable items at

ExGen

$0.32

$0.11

$0.09

$0.53

($0.01)

$0.03

HoldCo

ExGen

ComEd

PECO

BGE

2013 2Q Results

Expect 3Q 2013 earnings of $0.60 -

$0.70/share and re-affirm full year guidance

range of $2.35-$2.65/share

2013 2Q Earnings Release Slides

(1)

(1)

Refer to 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. SB9 = Senate Bill 9.

ExGen Operating EPS Contribution

7

2013 2Q Earnings Release Slides

$0.47

$0.32

2Q

2013

2012

(excludes Salem and CENG)

2Q12

Actual

2Q13

Actual

Planned Refueling Outage Days

51

47

Non-refueling Outage Days

16

31

Nuclear Capacity Factor

93.4%

92.8%

Lower RNF, primarily due to lower realized

energy prices, lower capacity pricing and

decreased load volumes: $(0.15)

Increased depreciation expense related to

ongoing capital expenditures: $(0.01)

Lower O&M costs, primarily due to merger

synergies, offset in part by timing of Salem

nuclear refueling outage costs: $0.01

Lower income tax, primarily driven by AVSR

investment tax credit benefits: $0.01

(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

–

2Q13

vs.

2Q12

(1)

RNF = Revenue Net Fuel.

Exelon Utilities Operating EPS Contribution

8

2013 2Q Earnings Release Slides

2Q 2013

2Q 2012

$0.05

$0.11

$0.09

$0.16

$0.10

$0.02

$0.03

$0.22

BGE

PECO

ComEd

Weather

(2)

: $(0.02)

Higher distribution revenue due to higher allowed

ROE

(2)

: $0.01

Impact of Senate Bill 9: $0.01

Discrete impacts of the May 2012 distribution formula

rate order under EIMA

(3)

: $0.07

Higher O&M costs, primarily due to inflation: $(0.01)

Preferred securities redemption: $(0.01)

Lower income tax, primarily due to gas distribution tax

repairs deduction: $0.01

Electric and gas distribution rates: $0.02

PECO

(-0.01):

BGE

(+0.01):

ComEd: (+0.06)

Key

Drivers

–

2Q13

vs.

2Q12

(1):

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.

(3)

Energy Infrastructure Modernization Act

2013 Projected Sources and Uses of Cash

(1)

Exelon beginning cash balance as of  1/1/13. Excludes counterparty collateral activity.

(2)

Cash Flow from Operations primarily includes net cash flows provided by operating activities and net cash flows used in investing activities other than

capital expenditures. 

(3)

Dividends are subject to declaration by the Board of Directors.

(4)

Includes PECO’s $210 million Accounts Receivable (A/R) Agreement with Bank of Tokyo and excludes BGE’s current portion of its rate stabilization

bonds

(5)

“Other”

includes proceeds from options, redemption of PECO preferred stock and expected changes in short-term debt.

(6)

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

9

2013 2Q Earnings Release Slides

10

Exelon Generation Disclosures

June 30, 2013

2013 2Q Earnings Release Slides

2013 2Q Earnings Release Slides

11

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

2013 2Q Earnings Release Slides

•

Aligns hedging program with

financial policies and financial

outlook

•

Establish minimum hedge targets

•

Hedge enough commodity risk to

•

Ensure stability in near-term cash

•

Disciplined approach to hedging

•

Tenor aligns with customer

•

Multiple channels to market that

•

Large open position in outer years

•

Ability to exercise fundamental

market views to create value within

the ratable framework

•

Modified timing of hedges versus

•

Cross-commodity hedging (heat

•

Delivery locations, regional and

Strategic Policy Alignment

Three-Year Ratable Hedging

Bull / Bear Program

Credit Rating

Capital

Structure

Capital &

Operating

Expenditure

Dividend

to meet financial objectives of the

company (dividend, credit rating)

meet future cash requirements

under a stress scenario

flows and earnings

preferences and market liquidity

allow us to maximize margins

to benefit from price upside

purely ratable

rate positions, options, etc.)

zonal spread relationships

2013 2Q Earnings Release Slides

12

Components of Gross Margin Categories

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

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

2013 2Q Earnings Release Slides

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.

Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non Power” Executed category.

(1)

(2)

(3)

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.

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

•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

•BGE Home

•Distributed Solar

•Retail, Wholesale

planned gas sales

•Load Response

•Energy Efficiency

•BGE Home

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

2013 2Q Earnings Release Slides

ExGen Disclosures 

Gross Margin Category ($M)

(1,2)

2013

2014

2015

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$5,750

$5,700

$5,900

Mark to Market of Hedges

(3,4)

$1,450

$850

$400

Power New Business / To Go

$200

$550

$750

Non-Power Margins Executed

$350

$150

$50

Non-Power New Business / To Go

(5)

$250

$450

$550

Total Gross Margin

$8,000

$7,700

$7,650

Reference Prices

(6)

2013

2014

2015

Henry Hub Natural Gas ($/MMbtu)

$3.68

$3.91

$4.14

Midwest: NiHub ATC prices ($/MWh)

$31.00

$29.90

$31.04

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

$37.76

$37.26

$38.53

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$4.93

$7.90

$8.76

New York: NY Zone A ($/MWh)

$36.82

$35.40

$36.22

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

ALQN Gas, 7.5HR, $0.50 VOM

$3.03

$4.59

$3.02

2013 2Q Earnings Release Slides

13

(1)

Gross margin rounded to nearest $50M.

(2)

Gross margin does not include revenue related to decommissioning, gross receipts tax,

Exelon Nuclear Partners and entities consolidated solely as a result of the application of

FIN 46R.

(3)

Includes CENG Joint Venture.

(4)

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

(5)

Any changes to new business estimates for our non-power business are presented as

revenue less costs of sales.

(6)

Based on June 30, 2013 market conditions.

14

ExGen Disclosures

Generation and Hedges

2013

2014

2015

Exp. Gen (GWh)

(1)

215,500

214,400

207,600

Midwest

97,200

97,100

96,400

Mid-Atlantic

(2)

74,200

72,600

69,900

ERCOT

14,600

17,800

18,500

New York

(2)

14,100

12,100

9,300

New England

15,400

14,800

13,500

% of Expected Generation Hedged

(3)

96-99%

78-81%

41-44%

Midwest

95-98%

77-80%

38-41%

Mid-Atlantic

(2)

97-100%

82-85%

48-51%

ERCOT

102-105%

77-80%

34-37%

New York

(2)

96-99%

81-84%

45-48%

New England

97-100%

71-74%

23-26%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$37.00

$34.00

$34.00

Mid-Atlantic

(2)

$49.00

$46.00

$46.50

ERCOT

(5)

$11.50

$9.00

$7.50

New York

(2)

$32.00

$37.00

$44.00

New England

(5)

$5.50

$3.50

$3.50

2013 2Q Earnings Release Slides

(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 12 refueling outages in 2013 and 14 refueling outages in 2014 and 2015 at Exelon-operated nuclear plants, Salem  and CENG.  Expected generation

assumes capacity factors of  93.8%, 93.8%, and 93.3% in 2013, 2014 and 2015 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of expected generation

in 2014 and 2015 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 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.

2013 2Q Earnings Release Slides

15

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges) 

(1, 2)

2013

2014

2015

Henry Hub Natural Gas ($/Mmbtu)

$35

$190

$430

$(20)

$(130)

$(370)

NiHub ATC Energy Price

$10

$130

$355

$(5)

$(125)

$(350)

PJM-W ATC Energy Price

$0

$75

$205

$5

$(75)

$(200)

NYPP Zone A ATC Energy Price

$0

$10

$25

$0

$(10)

$(25)

Nuclear Capacity Factor

(3)

+/-

1%

+/-

$20

+/-

$40

+/-

$45

2013 2Q Earnings Release Slides

(1) Based on June 30, 2013 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.  (2) Sensitivities based on commodity exposure which includes open generation and all committed transactions.  (3) Includes CENG Joint Venture.

+ $1/Mmbtu

-

$1/Mmbtu

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

+ $5/MWh

-

$5/MWh

2013 2Q Earnings Release Slides

16

Exelon Generation Hedged Gross Margin Upside/Risk

$6,000

$6,500

$7,000

$7,500

$8,000

$8,500

$9,000

$9,500

$10,000

2015

$8,700

2014

$8,150

2013

$8,150

$7,850

$7,250

$6,750

(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 and 2015 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, 2013

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

2013 2Q Earnings Release Slides

17

Illustrative Example of Modeling Exelon Generation             

2014 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$5.70 billion

(B)

Expected Generation (TWh)

97.1

72.6

17.8

12.1

14.8

(C)

Hedge % (assuming mid-point of range)

78.5%

83.5%

78.5%

82.5%

72.5%

(D=B*C)

Hedged Volume (TWh)

76.2

60.6

14.0

10.0

10.7

(E)

Effective Realized Energy Price ($/MWh)

$34.00

$46.00

$9.00

$37.00

$3.50

(F)

Reference Price ($/MWh)

$29.90

$37.26

$7.90

$35.40

$4.59

(G=E-F)

Difference ($/MWh)

$4.10

$8.74

$1.10

$1.60

$(1.09)

(H=D*G)

Mark-to-market

value

of

hedges

($

million)

(1)

$315 million

$530 million

$15 million

$15 million

$(10) million

(I=A+H)

Hedged Gross Margin ($ million)

$6,550 million

(J)

Power New Business / To Go ($ million)

$550 million

(K)

Non-Power Margins Executed ($ million)

$150 million

(L)

Non-

Power New Business / To Go ($ million)

$450 million

(N=I+J+K+L)

Total Gross Margin

$7,700 million

(1) Mark-to-market rounded to the nearest $5 million. 

2013 2Q Earnings Release Slides

18

Additional Disclosures

2013 2Q Earnings Release Slides

BGE

2013 load growth largely

driven by the idling of RG Steel

and

energy efficiency partially

offset by improving economic

conditions

19

Exelon Utilities Weather-Normalized Load

2013E

0.4%

0.2%

2012

0.2%

-0.6%

-0.1%

Large C&I

Small C&I

Residential

All Customers

Notes: Data is not adjusted for leap year.  Source of 2013 economic outlook data is Global Insight (May 2013).    Assumes 2013 GDP of 1.8% and U.S unemployment of 7.6%.

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

2013 load growth is similar to

2012, driven by improving

economic conditions & positive

residential load growth partially

offset by energy efficiency

2013E

1.7%

0.5%

2012

-2.3%

-2.2%

PECO

2013 load growth driven by oil

refinery and economic

conditions & customer growth,

offset by energy efficiency

2013E

-2.5%

-1.0%

2012

-2.8%

-1.5%

Chicago GMP

1.7%

Chicago Unemployment

9.4%

Philadelphia GMP

1.7%

Philadelphia Unemployment

7.9%

Baltimore GMP

1.8%

Baltimore Unemployment

7.3%

2013 2Q Earnings Release Slides

0.8%

-0.3%

-0.6%

0.4%

-1.7%

-2.7%

-2.3%

-2.1%

-0.2%

0.4%

0.9%

20

Exelon Utilities Rate Base and ROE Targets

2013E

Long-Term Target

Equity Ratio

~50%

~53%

(3)

Earned ROE

7-8%

2013E

Long-Term Target

Equity Ratio

~46%

~53%

(1)

Earned ROE

8 -9%

Continued investment in Utilities will provide stable earnings growth

Based on 30-yr.

US Treasury

(2)

($ in billions)

$1.1

$0.7

$1.1

2012

$5.1

$3.3

$0.7

$5.9

$3.9

2015E

$1.3

$0.7

$1.2

2013E

$5.3

$3.5

2014E

$5.7

$3.8

$0.7

Electric Distribution

Electric Transmission

Gas Delivery

$2.1

$7.6

$2.7

2014E

$8.7

$7.1

$2.3

2013E

$9.4

$6.6

$10.3

$6.4

2015E

$8.5

$2.1

2012

Transmission

Distribution

$5.1

$3.2

$0.6

$4.4

$0.7

$1.1

$1.2

2013E

$3.0

2014E

$0.6

$1.0

$2.8

$4.7

2012

$5.3

2015E

$1.2

$3.3

$0.8

Electric Distribution

Gas Delivery

Electric Transmission

10%

All rate base amounts are presented as year-end rate base.

(1)

Exelon Utilities sets first quartile goals. The timing of the achievement of each goal will

depend upon specific jurisdictional nuances to each company and how they impact the

desired structure. The current distribution equity ratio for ComEd is ~46% and ComEd

will look to grow this ratio over time.   Currently, ComEd's Transmission capital ratio is

limited to 55%.

(2)

Earned ROE will reflect the weighted average of 11.5% allowed transmission ROE

and distribution ROE resulting from 30-year Treasury plus 580 basis points for each

calendar year.

(3)

Per MDPSC merger commitment, BGE is precluded from paying dividends through

2014. Per MDPSC orders, BGE cannot pay out a dividend to its parent company if

said dividend would cause BGE’s equity ratio to fall below 48% or if BGE is

downgraded by two of three rating agencies.

2013E

Long-Term Target

Equity Ratio

~55%

~53%

Earned ROE

11.5 –

12.5%

10%

2013 2Q Earnings Release Slides

2013 2Q Earnings Release Slides

21

ComEd May 2013 Distribution Formula Rate Updated Filing

Note:  Disallowance of any items in the 2013 distribution formula rate filing could impact 2013 earnings in the form of a regulatory asset adjustment.

Docket #

13-0318

Filing Year

Reconciliation Year

Common Equity Ratio

ROE

Rate Base

Revenue Requirement

Increase

Timeline

The 2013 distribution formula rate filing  establishes the net revenue requirement used to set the rates that will take effect in January 2014 after the

ICC’s review.  The filing was updated to reflect the impact of Senate Bill 9. There are two components to the annual distribution formula rate filing:

Filing Year:   Based on prior year costs (2012) and current year (2013) projected plant additions.

Annual Reconciliation:  For the prior calendar year (2012), this amount reconciles the revenue requirement reflected in rates during the prior year (2012)

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

recorded in the prior year (2012) as a regulatory asset.

04/29/13 Filing Date

240 Day Proceeding

ICC order by year end; rates effective January 2014

2012 Calendar Year Actual Costs and 2013 Projected Net Plant Additions

are used to set the rates for

calendar year 2014. Rates currently in effect (docket 12-0321) for calendar year 2013 were based on 2011 actual

costs and 2012 projected net plant additions.

Reconciles

Revenue

Requirement

reflected

in

rates

during

2012

to

2012

Actual

Costs

Incurred.

Revenue

Requirement for  2012 is based on dockets 10-0467, 11-0721 May Order and 11-0721 October Re-hearing Order.

~ 45%

for both the filing and reconciliation year

8.27%

for both the filing and reconciliation  year (2012 30-yr Treasury Yield of 2.92% + 580 basis point risk premium). 

For 2013 and 2014, 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.

~7%

For the both the filing and reconciliation Year

$6,717 million

$359M

capital additions).  2013 and  2014 earnings will reflect 2013 and 2014 year-end rate base respectively.

-

Reconciliation year (represents year-end ate base for 2012)

$6,390 million

($165M is due to the 2012 reconciliation, $194M relates to the filing year). The 2012 reconciliation impact on

net income was recorded in 2012 as a regulatory asset. This increase also reflects the decrease in 2013 rates as

a result of Senate Bill 9.

Filing year (represents projected year-end rate base using 2012 actual plus 2013 projected

Requested Rate of Return

Given the retroactive ratemaking provision in the 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.

22

BGE Rate Case

Rate Case Request

Electric

Gas

Docket #

9326

Test Year

August 2012 –

July 2013

Common Equity Ratio

49.8%

Requested Returns

ROE: 10.5%; ROR: 7.75%

ROE: 10.35%; ROR: 7.67%

Rate Base (adjusted)

$2.8B

$1.1B

Revenue Requirement Increase

$101.5M

$29.7M

Proposed Distribution Increase as

% of overall bill

3%

4%

Timeline

•5/17/13: BGE filed application with the MDPSC seeking increases in gas & electric distribution base rates

•8/5/13: Staff/Intervenors file direct testimony

•8/23/13: Update 8 months actual/4 month estimated test period data with actuals for last 4 months

(March -

July 2013)

•9/17/13: BGE and staff/intervenors file rebuttal testimony

•10/3/13: Staff/Intervenors  and BGE file surrebuttal testimony

•10/15/13 –

10/29/13: Hearings

•11/12/13: Initial Briefs

•11/22/13: Reply Briefs

•12/13/13: Final Order

•New rates are in effect shortly after the final order

2013 2Q Earnings Release Slides

2Q GAAP EPS Reconciliation

Three

Months

Ended

June

30,

2013

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.32

$0.11

$0.09

$0.03

$(0.01)

$0.53

Mark-to-market impact of economic hedging activities

0.30

-

-

-

(0.01)

0.30

Unrealized gains related to NDT fund investments

(0.03)

-

-

-

-

(0.03)

Constellation merger and integration costs

(0.01)

-

(0.00)

(0.00)

-

(0.02)

Amortization of commodity contract intangibles

(0.13)

-

-

-

-

(0.13)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

Long-lived asset impairment

(0.07)

-

-

-

(0.01)

(0.08)

2Q 2013 GAAP Earnings (Loss) Per Share

$0.38

$0.11

$0.08

$0.03

$(0.03)

$0.57

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,

2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.47

$0.05

$0.10

$0.02

$(0.02)

$0.61

Mark-to-market impact of economic hedging activities

0.14

-

-

-

0.00

0.15

Unrealized losses related to NDT fund investments

(0.02)

-

-

-

-

(0.02)

Plant retirements and divestitures

0.00

-

-

-

-

0.00

Constellation merger and integration costs

(0.07)

-

(0.00)

(0.00)

(0.01)

(0.08)

Amortization of commodity contract intangibles

(0.33)

-

-

-

-

(0.33)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

Non-cash remeasurement of deferred income taxes

-

-

-

-

0.00

0.00

2Q 2012 GAAP Earnings (Loss) Per Share

$0.19

$0.05

$0.09

$0.01

$(0.02)

$0.33

2013 2Q Earnings Release Slides

23

2Q YTD GAAP EPS Reconciliation

Six Months Ended June 30, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.71

$0.22

$0.23

$0.11

$(0.03)

$1.23

Mark-to-market impact of economic hedging activities

0.02

-

-

-

0.00

0.02

Unrealized gains related to NDT fund investments

0.02

-

-

-

-

0.02

Plant retirements and divestitures

0.02

-

-

-

-

0.02

Constellation merger and integration costs

(0.05)

-

(0.00)

0.00

(0.00)

(0.05)

Amortization of commodity contract intangibles

(0.28)

-

-

-

-

(0.27)

Amortization of the fair value of certain debt

0.01

-

-

-

-

0.01

Remeasurement of like kind exchange tax position

-

(0.20)

-

-

(0.11)

(0.31)

Long lived asset impairment

(0.09)

-

-

-

(0.01)

(0.10)

YTD 2013 GAAP Earnings (Loss) Per Share

$0.36

$0.02

$0.23

$0.12

$(0.15)

$0.57

Six Months Ended June 30, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.03

$0.17

$0.23

$0.04

$(0.03)

$1.44

Mark-to-market impact of economic hedging activities

0.20

-

-

-

0.01

0.21

Unrealized gains related to NDT fund investments

0.02

-

-

-

-

0.02

Plant retirements and divestitures

(0.01)

-

-

-

-

(0.01)

Constellation merger and integration costs

(0.13)

(0.00)

(0.01)

(0.00)

(0.09)

(0.23)

Maryland commitments

(0.03)

-

(0.11)

(0.16)

(0.29)

Amortization of commodity contract intangibles

(0.46)

-

-

-

-

(0.46)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

FERC Settlement

(0.22)

-

-

-

-

(0.22)

Non-cash remeasurement of deferred income taxes

0.02

-

-

-

0.14

0.16

Other acquisition costs

(0.00)

-

-

-

-

(0.00)

YTD 2012 GAAP Earnings (Loss) Per Share

$0.43

$0.17

$0.22

(0.07)

$(0.13)

$0.62

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

2013 2Q Earnings Release Slides

24

GAAP to Operating Adjustments

2013 2Q Earnings Release Slides

•

Exelon’s 2013 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 or retirement of generating stations

Certain costs incurred associated with the Constellation merger and integration initiatives

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

the merger date

Non-cash amortization of certain debt recorded at fair value at the merger date, which was retired in the

second quarter of 2013

Non-cash charge to earnings resulting from the remeasurement of Exelon’s like-kind exchange tax

position

Non-cash charge to earnings related to the cancellation of previously capitalized nuclear uprate projects

and the impairment of an investment in a long term lease.

Other unusual items

25