EXELON CORP - FORM 8-K - EX-99.2 - EARNINGS CONFERENCE CALL PRESENTATION SLIDES

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Earnings Conference Call

Quarter 2014

July 31, 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 Second Quarter 2014 Quarterly Report on

Form 10-Q (to be filed on July 31, 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 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

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

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

date of this presentation.

2014 2Q Earnings Release Slides

•

Pepco Holdings Acquisition

•

Successful equity issuance

•

Regulatory filings:

•

FERC, New Jersey, District of

Columbia, Delaware, Virginia

•

Partnership with Bloom Energy

•

AVSR fully operational

•

Nuclear capacity factor over 91.8%

(2)

•

Power dispatch match over 99.2% and

renewables energy capture over 94.7%

•

EPA Greenhouse Gas Rule –

111(d)

•

IL House Resolution 1146 on importance

of nuclear energy

•

ComEd and BGE rate cases

2014 2Q Earnings Release Slides

•

Delivered Q2 adjusted operating earnings

of $0.51 per share, exceeding our

guidance range

(1)

Q2 2014 in Review

(1)

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

(non-GAAP) operating EPS to GAAP EPS

(2)

Exelon operated plants at ownership including CENG. For comparability, Exelon plants excluding CENG had a 92.5% capacity factor

(3) 2014 earnings guidance based on expected average outstanding shares of ~860M

2014 Expectations:

Deliver adjusted operating earnings range of $0.60 to $0.70/share for Q3 2014

On-track to achieve full-year operating earnings within guidance range of $2.25-$2.55/share as disclosed on Q4

2013 earnings call

(3)

Financial

Discipline

Operational

Excellence

Regulatory

Advocacy

Opportunistic

Growth

•

Integrys Energy Services Acquisition

2014 Spot and Forward Market Volatility

Significant

volatility

and

higher

prices

year

over

year

during

and

2014

July weakness on the back of an unusually mild summer

•

Month-to-date CDDs are trending approximately 10% below normal nationally, and 35% in Chicago (NiHub)

•

July spot prices at PJM W and NiHub have cleared lower compared to the previous two years reflecting the lack of weather-related

demand

•

Forward power and gas prices have also pulled back

•

During the first quarter, the polar vortex resulted in some extreme conditions and we saw spot prices in PJM reflecting the changing

nature of the grid and new reliance on different resources such as NG supply, demand response, and oil peakers

•

During the second quarter, we saw continued volatility especially in the higher load ranges

•

Higher peak prices have led to higher average cleared LMP’s compared to the past two years

•

Continuous strength and liquidity in the spot market carried into the forward power market especially for 2015-2016

Q1 Spot Price Volatility

Q2 Spot Price Volatility

(1)

April data excluded; differences in unit outages during the month of April distort year-over-year comparisons

2014 2Q Earnings Release Slides

Forward Markets and Hedging Activity

2015:

Took

profit

our

open

position

prices

moved

(1)

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

•

Over the past several quarters we positioned the portfolio to

increase our exposure to power price upside relative to ratable

•

In response to the power price and heat rate moves during the

second quarter, we switched our strategy from behind ratable to

closer to ratable and we also reduced our cross-commodity

position

•

When considering our move back to ratable and the reduction in

our gas hedges we lowered our total portfolio power exposure by

over 15% quarter-over-quarter

•

Increased market volatility has led to improved margins in the

wholesale and retail load business

2014 2Q Earnings Release Slides

Forward markets continued their upward trend in Q2

•

Forward markets have a tendency to reflect spot market activity

•

While forward hub natural gas prices stayed relatively flat, power

prices continued to trade higher during the second quarter and

as a result heat rates expanded further in 2015 and 2016

•

Increased volatility led to greater market liquidity

•

During July we have seen forward markets soften; our

fundamental view of power upside remains in certain

months/seasons in 2015

Locked in profit during Q2, and reduced power price exposure by over 15% and 10%

respectively for 2015 and 2016

Impacts on Forward Markets

Impacts of our view on our hedging activity

2014 2Q Earnings Release Slides

Exelon Generation: Gross Margin Update

June 30, 2014

Change from March 31, 2014

Gross Margin Category ($M)

(1)

2014

2015

2016

2014

2015

2016

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

7,500

6,800

6,850

150

450

600

Mark-to-Market of Hedges

(3,4)

(700)

(50)

Power New Business / To Go

150

500

550

(100)

Non-Power Margins Executed

300

100

Non-Power New Business / To Go

100

300

350

(50)

Total

Gross

Margin

7,350

7,750

7,850

300

450

2014 2Q Earnings Release Slides

•

Continued market volatility allowed us to execute on a significant piece of our new business

targets bringing us closer to our ratable strategy

•

saw

both

spot

and

forward

prices

trading

higher

than

years

•

The return of volatility to the markets has led to more appropriate pricing of risk premiums

Recent Developments

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

(3)

Includes Exelon’s equity ownership share of the CENG Joint Venture

(4)

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

(2)

Key Financial Messages

•

Delivered adjusted (non-GAAP) operating

earnings in Q2 of $0.51/share exceeding our

guidance range of $0.40-$0.50/share

•

Utilities:

Increased distribution revenue

•

ExGen

Lower realized energy prices

Increased capacity pricing

Elimination of DOE nuclear waste fee

Expect

2014

earnings

$0.60

$0.70/share

and

re-affirm

full-year

guidance

range

$2.25

$2.55/share

(2)

$0.27

$0.13

$0.10

ExGen

ComEd

PECO

BGE

$0.51

$0.02

2014

Adjusted

Operating

EPS

(1,3)

2014 2Q Earnings Release Slides

(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

(3)

Amounts may not add due to rounding

Exelon Utilities Adjusted Operating EPS Contribution

(1)

BGE

(-0.01):

•

Increased O&M costs, primarily due to bad debt expense

and labor, contracting, and materials: $(0.02)

•

Distribution revenue due to rate cases: $0.01

PECO (+0.01):

•

Decreased income tax expense due to an increase in

electric tax repairs deduction: $0.01

ComEd

(+0.02):

•

Increased distribution earnings due to increased capital

investment

(2)

: $0.01

2014 2Q Earnings Release Slides

2Q 2014

$0.25

$0.13

$0.10

$0.02

2Q 2013

$0.23

$0.11

$0.09

$0.03

ComEd

BGE

PECO

Note: 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

–

2Q14

vs.

2Q13

2014 Projected Sources and Uses of Cash

Key

Messages

(1)

•

Cash from Operations is projected to be $6,975M vs. 1Q14E of $6,200M

for a $775M variance. This variance is driven by:

•

Cash from Financing activities is projected to be $250M vs. 1Q14E of

($825M) for a $1,075M variance. This variance is driven by:

•

Cash from Investing activities is projected to be ($5,450M) vs. 1Q14E of

($5,375M) for a ($75M) variance.

Projected

Sources

Uses

(1)

All amounts rounded to the nearest $25M.

(2)

Excludes counterparty collateral of $134 million at 12/31/2013. In addition, the 12/31/2014 ending cash balance does

not include collateral.

(3)

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.

(4)

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

cash flows from investing activities excluding capital expenditures of $5.4B for 2014.

(5)

Dividends are subject to declaration by the Board of Directors.

(6)

“Other Financing”

primarily includes CENG distribution to EDF, expected changes in short-term debt, and proceeds

from issuance of mandatory convertible units.

($ in millions)

BGE

ComEd

PECO

ExGen

Exelon

(3)

As of 1Q14

Variance

Beginning Cash Balance

(2)

1,475

–

Adjusted Cash Flow from Operations

(4)

650

1,575

625

4,200

6,975

6,200

775

CapEx (excluding other items below):

(525)

(1,500)

(525)

(1,150)

(3,450)

(3,475)

Nuclear Fuel

n/a

(1,000)

(975)

(25)

Dividend

(5)

(1,075)

–

Nuclear Uprates

n/a

(150)

–

Wind

n/a

(75)

–

Solar

n/a

(200)

–

Upstream

n/a

(50)

–

Utility Smart Grid/Smart Meter

(75)

(275)

(150)

n/a

(525)

(450)

(75)

Net Financing (excluding Dividend):

Debt Issuances

950

300

–

1,250

–

Debt Retirements

–

(625)

(250)

(525)

(1,375)

–

Project Finance/Federal Financing

Bank Loan

n/a

875

675

200

–

Other Financing

(6)

(50)

200

125

(425)

575

(300)

875

Ending Cash Balance

(2)

3,250

1,475

1,775

–

2014 2Q Earnings Release Slides

$400M Net proceeds from divestitures

$300M Income taxes and settlements

$150M Decreased OPEB contributions (primarily ComEd and ExGen)

($125M) Purchase of PHI preferred stock

$75M Working capital and regulatory assets at Utilities

$1,125 Net proceeds from issuance of mandatory convertible units

$200M Incremental project financing at ExGen

($150M) Decrease in projected commercial paper financing

Exelon Generation Disclosures

June 30, 2014

2014 2Q 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 2Q Earnings Release Slides

Strategic Policy Alignment

Three-Year

Ratable

Hedging

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

Structure

Capital &

Operating

Expenditure

Dividend

•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

Components of Gross Margin Categories

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

(5)

Margins move from “Non power new business”

“Non power executed”

over the course of the year

Gross margin linked to power production and sales

Gross margin from

other business activities

2014 2Q Earnings Release Slides

(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

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

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

•Load Response

•Energy Efficiency

(4)

•BGE Home

(4)

•Distributed Solar

•Portfolio

Management /

origination fuels

new business

•Proprietary

trading

(3)

ExGen Disclosures

Gross Margin Category ($M)

(1)

2014

2015

2016

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

7,500

6,800

6,850

Mark to Market of Hedges

(3,4)

(700)

Power New Business / To Go

150

500

550

Non-Power Margins Executed

300

100

Non-Power New Business / To Go

100

300

350

Total Gross Margin

7,350

7,750

7,850

(4)

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

(5)

Based on June 30, 2014 market conditions

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

Gross Margin

(3)

Includes Exelon’s equity ownership share of the CENG Joint Venture

2014 2Q Earnings Release Slides

Reference Prices

(5)

2014

2015

2016

Henry

Hub Natural Gas ($/MMbtu)

$4.63

$4.22

$4.24

Midwest: NiHub ATC prices ($/MWh)

$41.12

$33.95

$34.78

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

$54.47

$42.26

$41.36

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$5.02

$6.33

$6.34

New York: NY Zone A ($/MWh)

$51.49

$40.99

$39.51

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

ALQN Gas, 7.5HR, $0.50 VOM

$3.68

$5.56

$4.33

(2)

ExGen Disclosures

Generation and Hedges

2014

2015

2016

Expected Generation (GWh)

(1)

208,100

203,700

205,400

Midwest

97,200

96,800

97,900

Mid-Atlantic

(2)

74,600

70,600

71,700

ERCOT

14,300

18,100

19,000

New York

(2)

12,700

9,400

9,300

New England

9,300

8,800

7,500

% of Expected Generation Hedged

(3)

92-95%

75-78%

46-49%

Midwest

95-98%

76-79%

45-48%

Mid-Atlantic

(2)

88-91%

73-76%

45-48%

ERCOT

97-100%

79-82%

56-59%

New York

(2)

97-100%

68-71%

New England

88-91%

76-79%

29-32%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$37.00

$33.50

$35.00

Mid-Atlantic

(2)

$48.50

$43.50

ERCOT

(5)

$14.50

$8.00

$5.00

New York

(2)

$43.50

$43.00

$39.00

New England

(5)

$8.50

$7.00

$3.00

2014 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 14 refueling outages in 2014 and 2015 and 12 refueling outages in 2016 at Exelon-operated nuclear

plants, and Salem. Expected generation assumes capacity factors of 93.5%, 93.5% and 93.7% in 2014, 2015 and 2016 at Exelon-operated nuclear plants, at

ownership. 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 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. 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.

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges)

(1, 2)

2014

2015

2016

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$10

$190

$415

$1/Mmbtu

$(30)

$(125)

$(370)

NiHub ATC Energy Price

+ $5/MWh

$150

$300

$5/MWh

$(5)

$(145)

$(300)

PJM-W ATC Energy Price

+ $5/MWh

$85

$195

$5/MWh

$(75)

$(190)

NYPP Zone A ATC Energy Price

+ $5/MWh

$15

$5/MWh

$(5)

$(15)

Nuclear Capacity Factor

(3)

+/-

$30

+/-

$50

+/-

$50

2014 2Q Earnings Release Slides

(1)

Based on June 30, 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 equity ownership share of the CENG Joint Venture.

ExGen Hedged Gross Margin Upside/Risk

$7,500

$7,150

$8,550

$7,050

2014 2Q Earnings Release Slides

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

2014

2015

2016

$9,400

$6,500

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

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

$6.80 billion

(B)

Expected Generation (TWh)

96.8

70.6

18.1

9.4

8.8

(C)

Hedge % (assuming mid-point of range)

77.5%

74.5%

80.5%

69.5%

77.5%

(D=B*C)

Hedged Volume (TWh)

75.0

52.6

14.6

6.5

6.8

(E)

Effective Realized Energy Price ($/MWh)

$33.50

$43.50

$8.00

$43.00

$7.00

(F)

Reference Price ($/MWh)

$33.95

$42.26

$6.33

$40.99

$5.56

(G=E-F)

Difference ($/MWh)

$(0.45)

$1.24

$1.67

$2.01

$1.44

(H=D*G)

Mark-to-market

value

hedges

million)

(1)

$(35) million

$65 million

$25 million

$15 million

$10 million

(I=A+H)

Hedged Gross Margin ($ million)

$6,850 million

(J)

Power New Business / To Go ($ million)

$500 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)

$7,750 million

2014 2Q Earnings Release Slides

Additional Disclosures

2014 2Q Earnings Release Slides

BGE

2014 load growth is flat to 2013,

due to slower economic conditions

and continued energy efficiency

impacts.

Exelon Utilities Weather-Normalized Load

2014E

0.9%

0.3%

1.2%

0.8%

2013

-0.3%

-0.5%

0.0%

-0.2%

Large C&I

Small C&I

Residential

All Customers

ComEd

2014 overall load growth is greater

than 2013. All three customer

classes have positive growth due to

slowly improving economic

conditions partially mitigated by

energy efficiency.

2014E

1.2%

-0.5%

0.8%

0.7%

2013

1.5%

-1.1%

0.0%

0.3%

PECO

2014 load growth is driven primarily

by Residential and Large C&I,

partially offset by Small C&I.

Slowly

improving

economic conditions &

moderate customer growth are

partially offset by energy efficiency.

-0.4%

0.3%

0.0%

2013

-3.2%

2.1%

2.0%

-0.6%

2014E

-0.2%

Chicago GMP

2.5%

Chicago Unemployment

6.9%

Philadelphia GMP

1.7%

Philadelphia Unemployment

6.4%

Baltimore GMP

2.6%

Baltimore Unemployment

6.0%

2014 2Q Earnings Release Slides

Notes: Data is not adjusted for leap year. Source of economic outlook data is Global Insight (April/May 2014). Assumes 2014 GDP of 2.4% and U.S unemployment of 6.1%.

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.

2014 2Q Earnings Release Slides

ComEd April 2014 Distribution Formula Rate

Docket #

14-0312

Filing Year

2013 Calendar Year Actual Costs and 2014 Projected Net Plant Additions

are used to set the rates for calendar year 2015.

Rates

currently

effect

(docket

13-0318)

for

calendar

year

2014

were

based

2012

actual

costs

and

2013

projected

net

plant

additions

Reconciliation Year

Reconciles

Revenue

Requirement

reflected

rates

during

2013

Actual

Costs

Incurred.

Revenue

requirement

for

2013

based

on docket 13-0386 filed in June 2013 and reflect the impacts of PA 98-0015 (SB9)

Common Equity Ratio

~ 46%

for both the filing and reconciliation year

ROE

9.25%

for

the

filing

year

(2013

30-yr

Treasury

Yield

3.45%

580

basis

point

risk

premium)

and

9.20%

for

the

reconciliation

year

(2013

30-yr

Treasury

Yield

3.45%

580

basis

point

risk

premium

–

basis

points

performance

metrics

penalty).

For

2014

and

2015,

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

the

both

the

filing

and

reconciliation

Year

Rate Base

(1)

$7,369

million–

Filing

year

(represents

projected

year-end

rate

base

using

2013

actual

plus

2014

projected

capital

additions).

2014

and

2015

earnings will reflect 2014 and 2015 year-end rate base respectively.

$6,596 million -

Reconciliation year (represents year-end rate base for 2013)

Revenue Requirement

Increase

(1)

$269M

($95M

due

the

2013

reconciliation,

$174M

relates

the

filing

year).

The

2013

reconciliation

impact

net

income

was

recorded

2013 as a regulatory asset.

Timeline

(1)

Amounts represent ComEd’s position filed in rebuttal testimony on July 23, 2014.

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

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.

•

04/16/14 Filing Date

•

240 Day Proceeding

•

ICC order expected by December 12, 2014

The 2014 distribution formula rate filing establishes the net revenue requirement used to set the rates that will take effect in January 2015 after the ICC’s review.

There are two components to the annual distribution formula rate filing:

•

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

•

Annual Reconciliation:

For the prior calendar year (2013), this amount reconciles the revenue requirement reflected in rates during the prior year (2013) in

effect to the actual costs for that year. The annual reconciliation impacts cash flow in the following year (2015) but the earnings impact has been recorded in

the prior year (2013) as a regulatory asset.

Filing Year:

2014 2Q Earnings Release Slides

BGE July Rate Case Filing

(1)

Revenue requirement based on 9 months of actual data, 3 months of forecasted data. Operating results and capital structure will be updated with actual August 31, 2014

data when the results become available.

Electric

Gas

Docket #

9355

Test Year

September 2013 -

August 2014

Common Equity Ratio

(1)

53.3%

Requested ROE

10.65%

10.55%

Requested Rate of Return

8.07%

8.01%

Rate Base (adjusted)

$2.9B

$1.2B

Revenue Requirement Increase

(1)

$117.6M

$67.5M

Proposed Distribution Increase as

% of overall bill

Timeline

•

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

distribution base rates

•

210 Day Proceeding

•

7/08/14 –

Case delegated to the Public Utility Law Judge Division

•

Delegation of the case to the PULJ Division will add several additional procedural steps

before a final order is issued (PULJ proposed order, appeals of PULJ order) which will

compress the time frame for everything else

•

01/28/2015 -

PSC order expected

•

New rates are in effect shortly after the final order

Appendix

Reconciliation of Non-GAAP

Measures

2014 2Q Earnings Release Slides

2Q GAAP EPS Reconciliation

Three Months Ended June 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.27

$0.13

$0.10

$0.02

$(0.00)

$0.51

Mark-to-market impact of economic hedging activities

(0.01)

Unrealized gains related to NDT fund investments

0.09

Merger and integration costs

(0.02)

Amortization of commodity contract intangibles

(0.03)

Long-Lived Asset Impairment

(0.06)

(0.02)

(0.08)

Gain on CENG Integration

0.18

PHI Acquisition Costs

(0.01)

Non-Controlling Interest

(0.03)

2Q 2014 GAAP Earnings (Loss) Per Share

$0.39

$0.13

$0.10

$0.02

$(0.03)

$0.60

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

2014 2Q Earnings Release Slides

Three Months Ended June 30, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

2013 Adjusted (non-GAAP) Operating Earnings 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 losses related to nuclear decommissioning trust funds

(0.03)

Merger and integration costs

(0.01)

(0.00)

(0.02)

Amortization of commodity contract intangibles

(0.13)

Amortization of the fair value of certain debt

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

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 2Q Earnings Release Slides

•

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 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

the

Constellation

merger

date

and

CENG

integration

date

for

2014

Impairment of certain wind generating assets.

Gain recorded upon consolidation of CENG.

Costs incurred associated with the Pepco Holdings Inc. acquisition.

CENG interest not owned by Generation, where applicable.

ExGen Total Gross Margin Reconciliation to GAAP

Total

Gross

Margin

Reconciliation

(in

$M)

(5)

2014

2015

2016

Revenue

Net

Purchased

Power

and

Fuel

Expense

(1)(6)

$7,750

$8,350

$8,450

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

commodity

contracts

recorded

fair

value

the

merger

date

(2)

$100

Other Revenues

(3)

$(200)

$(250)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(4)

$(300)

$(350)

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

$7,350

$7,750

$7,850

2014 2Q Earnings Release Slides

(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 equity

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. Mark-to-

market losses were ~$750 million for the six months ended June 30, 2014

2014 2Q Earnings Release Slides

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