EXELON CORP - FORM 8-K - EX-99.2

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Earnings Conference Call

Quarter 2015

April 29, 2015

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 2014 Annual Report on Form 10-K in (a) ITEM

1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial

Condition and Results of Operations and (c) ITEM 8. Financial Statements and

Supplementary Data: Note 22; (2) Exelon’s First Quarter 2015 Quarterly Report on

Form 10-Q (to be filed on April 29, 2015) in (a) Part II, Other Information, ITEM 1A. Risk

Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and

Analysis of Financial Condition and Results of Operations and (c) Part I, Financial

Information, ITEM 1. Financial Statements: Note 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.

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

Policy and Business Priorities

2015 1Q Earnings Release Slides

Key Financial Messages

Expect

2015

earnings

$0.45

$0.55/share

and

re-affirm

full-year

guidance

range

$2.25 -

$2.55/share

(3,4)

BGE

ExGen

ComEd

HoldCo

PECO

$0.35

-$0.03

Q1 2015

$0.11

$0.16

$0.12

$0.71

Adjusted Operating EPS Results

(1,2)

•

Delivered adjusted (non-GAAP) operating

earnings in Q1 of $0.71/share exceeding

our guidance range of $0.60-$0.70/share

•

Utilities

Colder than normal winter

No severe storms

Increased distribution revenues

•

ExGen

Benefits of generation to load match

Higher load serving margins

Strong portfolio management

Impacts of unplanned nuclear outages

(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)

Amounts may not add due to rounding.

(3)

ComEd ROE based on 30 Year average Treasury yield of 2.58% as of 3/31/15. 25 basis point move in 30 Year Treasury Rate equates to +/-$0.01 impact to EPS.

(4)

2015 earnings guidance based on expected average outstanding shares of ~866M. Refer to Appendix for a reconciliation of adjusted non-GAAP operating EPS guidance to GAAP EPS.

2015 1Q Earnings Release Slides

Exelon Generation: Gross Margin Update

March 31, 2015

Change from Dec 31, 2014

Gross Margin Category ($M)

(1)

2015

2016

2017

2015

2016

2017

Open Gross Margin

(3)

(including South, West, Canada hedged gross

margin)

$5,600

$5,900

$6,050

$(100)

$50

$(50)

Mark-to-Market of Hedges

(3,4)

$1,300

$600

$350

$250

$50

Power New Business / To Go

$250

$500

$800

$(100)

$(50)

Non-Power Margins Executed

$300

$150

$50

$100

$50

Non-Power New Business / To Go

$150

$300

$400

$(100)

$(50)

Total Gross Margin

(2)

$7,600

$7,450

$7,650

$50

$(50)

•

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

strategy

•

Natural gas declined, power prices were relatively flat, and heat rates expanded during the

quarter

•

Significantly behind ratable in the Midwest reflecting the fundamental upside we see in power

prices in 2016 and 2017

Recent Developments

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

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

Gross margin categories rounded to nearest $50M.

Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel

expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear

Partners, operating services agreement with Fort Calhoun and variable interest entities. Total

Gross Margin is also net of direct cost of sales for certain Constellation businesses. See Slide 27

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

2015 1Q Earnings Release Slides

2015 Projected Sources and Uses of Cash

Key Messages

(1)

•

Cash from Operations is projected to be $6,700M vs. 4Q14E of

$6,775M for a ($75M) variance. This variance is driven by:

–

($75M) MTM pre-issuance interest rate hedges

–

($50M) Income taxes and settlements

–

$25M Working capital favorability

–

$25M Higher net income at PECO primarily due to favorable weather

and volume

•

Cash from Financing activities is projected to be $725M vs.

4Q14E of $750M for a ($25M) variance. This variance is driven

by:

–

($125M) Lower project financing at ExGen

–

$50M Increased ComEd LTD requirements

–

$25M Higher commercial paper requirements at ExGen

•

Cash from Investing activities is projected to be ($7,175M) vs.

4Q14E of ($6,975M) for a ($200M) variance. This variance is

driven by:

–

($200M) Grid reliability investments at ComEd

Projected Sources & Uses

(1)

All amounts rounded to the nearest $25M.

(2)

Does not include collateral.

(3)

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

(4)

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

activities and net cash flows from investing activities excluding capital expenditures at ownership.

(5)

Dividends are subject to declaration by the Board of Directors.

(6)

“Other Financing”

primarily includes expected changes in short-term debt and tax-exempt bond

issuance at ExGen.

($ in millions)

(1)

BGE

ComEd

PECO

ExGen

Exelon

(3)

2015E

As of 4Q14

Variance

3,575

Adjusted Cash Flow from Operations

(4)

600

2,200

625

3,350

6,700

6,775

(75)

CapEx (excluding other items below):

(675)

(2,025)

(500)

(1,925)

(5,225)

(5,100)

(125)

Nuclear Fuel

n/a

(1,125)

Dividend

(5)

(1,075)

Nuclear Uprates

n/a

(100)

Wind

n/a

(100)

Solar

n/a

(125)

Upstream

n/a

(25)

Utility Smart Grid/Smart Meter

(25)

(400)

(50)

n/a

(475)

(400)

(75)

Net Financing (excluding Dividend):

Debt Issuances

250

750

350

750

2,100

2,050

Debt Retirements

(75)

(250)

(550)

(1,675)

Project Finance

n/a

200

(125)

Other Financing

(6)

(25)

1,100

1,300

1,250

3,825

4,125

(300)

2015 1Q Earnings Release Slides

Beginning

Cash

Balance

Ending

Cash

Balance

(2)

Exelon Generation Disclosures

March 31, 2015

2015 1Q Earnings Release Slides

2015 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

2015 1Q Earnings Release Slides

Capital

Structure

Credit Rating

Capital &

Operating

Expenditure

Dividend

Strategic Policy Alignment

•Aligns hedging program with

financial policies and financial

outlook

•Establish minimum hedge targets

to meet financial objectives of the

company (dividend, credit rating)

•Hedge enough commodity risk to

meet future cash requirements

under a stress scenario

Three-Year Ratable Hedging

•Ensure stability in near-term cash

flows and earnings

•Disciplined approach to hedging

•Tenor aligns with customer

preferences and market liquidity

•Multiple channels to market that

allow us to maximize margins

•Large open position in outer years

to benefit from price upside

Bull / Bear Program

•Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

2015 1Q Earnings Release Slides

Components of Gross Margin Categories

Gross margin linked to power production and sales

Gross margin from

other business activities

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)

(1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region

(2) MtM of hedges provided directly for the five larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh

(3) Proprietary trading gross margins will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion

(4) Gross margin for these businesses are net of direct “cost of sales”

(5) Margins for South, West & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin

Margins

move

from

new

business

MtM

hedges

over

the

course

the

year

sales

are

executed

(5)

Margins

move

from

“Non

power

new

business”

“Non

power

executed”

over

the

course

the

year

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

ExGen Disclosures

2015

2016

2017

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

$5,600

$5,900

$6,050

Mark-to-Market of Hedges

(3,4)

$1,300

$600

$350

Power New Business / To Go

$250

$500

$800

Non-Power Margins Executed

$300

$150

$50

Non-Power New Business / To Go

$150

$300

$400

$7,600

$7,450

$7,650

(1)

Gross margin categories rounded to nearest $50M

(2)

Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and

fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon

Nuclear Partners, operating services agreement with Fort Calhoun and variable interest

entities. Total Gross Margin is also net of direct cost of sales for certain Constellation

businesses. See Slide 27 for a Non-GAAP to GAAP reconciliation of Total Gross Margin

(3)

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

(4)

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

(5)

Based on March 31, 2015 market conditions

2015 1Q Earnings Release Slides

Reference

Prices

(5)

2015

2016

2017

Henry Hub Natural Gas ($/MMbtu)

$2.83

$3.11

$3.35

Midwest: NiHub ATC prices ($/MWh)

$30.74

$31.06

$31.23

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

$39.25

$38.73

$38.12

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$4.90

$4.84

$4.97

New York: NY Zone A ($/MWh)

$35.63

$36.54

$35.95

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

ALQN Gas, 7.5HR, $0.50 VOM

$7.54

$9.36

$10.47

Gross

Margin

Category

($M)

(1)

Total

Gross

Margin

(2)

2015 1Q Earnings Release Slides

ExGen Disclosures

Generation and Hedges

2015

2016

2017

Exp. Gen (GWh)

(1)

193,000

200,500

205,100

Midwest

96,400

97,400

95,900

Mid-Atlantic

(2)

61,900

63,200

61,100

ERCOT

15,300

17,400

26,100

New York

(2)

9,200

9,300

New England

10,200

13,200

12,700

% of Expected Generation Hedged

(3)

94%-97%

67%-70%

37%-40%

Midwest

93%-96%

64%-67%

30%-33%

Mid-Atlantic

(2)

99%-102%

75%-78%

47%-50%

ERCOT

98%-101%

83%-86%

53%-56%

New York

(2)

82%-85%

57%-60%

35%-38%

New England

77%-80%

37%-40%

16%-19%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$35.00

$34.00

$35.00

Mid-Atlantic

(2)

$47.50

$44.00

$45.00

ERCOT

(5)

$14.00

$9.50

$8.00

New York

(2)

$47.00

$44.50

$40.50

New England

(5)

$32.50

$17.00

$12.50

2015 1Q Earnings Release Slides

(1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch

model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation

assumes 14 refueling outages in 2015, 12 in 2016, and 15 in 2017 at Exelon-operated nuclear plants, and Salem. Expected generation assumes capacity factors of 93.0%, 94.1% and

93.4% in 2015, 2016 and 2017 respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2016 and 2017 do not represent guidance or a

forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Excludes EDF’s equity ownership share of CENG Joint Venture. (3) Percent

of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and

swaps. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the

energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM capacity revenue,

but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to

calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Spark spreads shown for ERCOT and New England.

2015 1Q Earnings Release Slides

ExGen Hedged Gross Margin Sensitivities

Gross

Margin

Sensitivities

(With

Existing

Hedges)

(1)

2015

2016

2017

Henry Hub Natural Gas ($/Mmbtu)

$(40)

$240

$580

$75

$(225)

$(570)

NiHub ATC Energy Price

$20

$170

$335

$(15)

$(170)

$(330)

PJM-W ATC Energy Price

$(15)

$70

$175

$15

$(65)

$(170)

NYPP Zone A ATC Energy Price

$10

$25

$(10)

$(15)

$(30)

Nuclear Capacity Factor

+/-

$35

+/-

$45

+/-

$45

(1)

Based on March 31, 2015 market conditions and hedged position; Gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated

periodically; Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant; Due to correlation of the various assumptions,

the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when correlations between the various

assumptions are also considered; Sensitivities based on commodity exposure which includes open generation and all committed transactions; Excludes EDF’s equity share of CENG Joint

Venture

2015 1Q Earnings Release Slides

+ $1/Mmbtu

$1/Mmbtu

+ $5/MWh

$5/MWh

+ $5/MWh

$5/MWh

+ $5/MWh

$5/MWh

+/-

ExGen Hedged Gross Margin Upside/Risk

$7,800

$7,400

$8,250

$6,850

$9,500

$6,300

2015

2016

2017

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

10,500

11,000

(1)

Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all

unhedged supply is sold into the spot market; Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market

inputs, future transactions and potential modeling changes; These ranges of approximate gross margin in 2016 and 2017 do not represent earnings guidance or a forecast

of future results as Exelon has not completed its planning or optimization processes for those years; The price distributions that generate this range are calibrated to market

quotes for power, fuel, load following products, and options as of March 31, 2015

(2)

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

(3)

Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon

Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation

businesses. See Slide 27 for a Non-GAAP to GAAP reconciliation of Total Gross Margin Excludes EDF’s equity ownership share of the CENG Joint Venture

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

Illustrative Example of Modeling Exelon Generation

2016 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New York

New

England

South,

West &

Canada

(A)

Start with fleet-wide open gross margin

$5.90 billion

(B)

Expected Generation (TWh)

97.4

63.2

17.4

9.3

13.2

(C)

Hedge % (assuming mid-point of range)

65.5%

76.5%

84.5%

58.5%

38.5%

(D=B*C)

Hedged Volume (TWh)

63.8

48.3

14.7

5.4

5.1

(E)

Effective Realized Energy Price ($/MWh)

34.00

44.00

9.50

44.50

17.00

(F)

Reference Price ($/MWh)

31.06

38.73

4.84

36.54

9.36

(G=E-F)

Difference ($/MWh)

2.94

5.27

4.66

7.96

7.64

(H=D*G)

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

(1)

185

255

(I=A+H)

Hedged Gross Margin ($ million)

$6,500

(J)

Power New Business / To Go ($ million)

$500

(K)

Non-Power Margins Executed ($ million)

$150

(L)

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

$300

(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 operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for

certain Constellation businesses. See Slide 27 for a Non-GAAP to GAAP reconciliation of Total Gross Margin

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

Additional Disclosures

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key Drivers –

1Q15 vs. 1Q14

BGE

(+0.02):

•

Increased distribution revenue due to rate case: $0.02

PECO (+0.06):

•

Decreased storm costs: $0.05

•

Favorable weather and volume: $0.01

ComEd

(0.00):

•

Unfavorable weather and volume

(2)

: $(0.01)

•

Decreased

distribution

(2)

earnings

due

lower

return

common equity: $(0.01)

•

Increased distribution

(2)

earnings due to increased capital

investments: $0.01

1Q 2015

$0.39

$0.11

$0.16

$0.12

1Q 2014

$0.31

$0.11

$0.10

BGE

ComEd

PECO

2015 1Q Earnings Release Slides

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 (inclusive of ROE), rate base and capital

structure in addition to weather, load and changes in customer mix.

2015 1Q Earnings Release Slides

2015 Regulatory and Legislative Timelines

ExGen

Exelon Utilities

PHI Acquisition

Illinois

Legislative

Session

Begins (Jan

14)

FERC Issues

Deficiency

Letter on

PJM Capacity

Performance

Proposal

(March 31)

FERC Agrees

to Delay PJM

BRA Auction

(April 24)

Supreme

Court

decision on

cert in EPSA

v. FERC

(Demand

Response)

(May)

Supreme

Court

Decision in

Michigan vs.

EPA (MATS)

(June)

PJM BRA

Auction (No

later than

August 10-

14)

Illinois

Legislative

Veto Session

(Nov)

IL Senate

Committee

approves

LCPS &

ComEd

legislation

(March 27)

PJM

Responds to

FERC

Deficiency

Letter (April

10)

MATS Rule in

Effect (April)

Illinois

Legislative

Session

Adjourns

(May 31)

FERC

Deadline to

Respond to

Deficiency

(June 9)

Final Clean

Power Rule

(111d)

Issued (Mid-

Summer)

PECO Electric Rate

Case and LTIIP Filing

(March 27)

ComEd Formula

Rate Filing (April15)

BGE Electric and

Gas Rate Case Filing

(TBD) MD PSC

Ruling Expected 7

Months after Filing

PaPUC Ruling

Expected on LTIIP

Filing (Q3)

PaPUC Ruling

Expected on PECO

Electric Rate Case

(Dec)

ICC Rules on ComEd

Formula Rate Filing

(Dec)

Settlement

Filed in New

Jersey (Jan

14)

Maryland

Hearings

(Jan 26 –

Feb 10)

New Jersey

Approval

(Feb 11)

Settlement

filed in

Delaware (Feb

13)

Multi-party

Settlement

filed in

Maryland

(March 16)

DC Hearings

(March 30-

April 8, April

20-22)

Maryland

Settlement

Hearings

(April 15-21)

Initial

Briefs Due

(May 13)

Delaware

Decision

Expected

(June 2)

Reply Briefs

Due

(May 27)

2015 1Q Earnings Release Slides

Maryland

Deadline

(May 15)

Expected

Transaction

Close (Q2/Q3)

2015 1Q Earnings Release Slides

Proposed Low Carbon Portfolio Standard Legislation (HB

3293 / SB1585)

2015 1Q Earnings Release Slides

What is the purpose of the

legislation?

Beginning

January

2016,

the

Illinois

Power

Agency

(IPA)

must

include

electric

utilities’

procurement plans

the procurement of cost-effective low carbon energy credits from low carbon energy resources for all retail

customers. This procurement process follows the existing renewable energy resources procurement process.

What is a low carbon energy

credit?

A tradable credit that represents the environmental attributes of 1 MW of energy produced from a low carbon

energy resource. Low carbon energy credits are created every day that low carbon energy resources are

generating power.

What is a low carbon energy, or

“LCE”, resource?

Energy from a generating unit that does not emit any air pollution, such as sulfur dioxide, nitrogen oxide, or

carbon dioxide, including technology fueled by new and existing solar photovoltaic, solar thermal, wind, hydro,

nuclear, tidal energy, wave energy or clean coal.

What quantity of LCE resources is

being procured?

A maximum of 70% of retail sales per year. Like the renewable energy resources procurement, the LCE

procurement is limited by a separate 2.015% rate increase cap and cannot exceed the IPA’s benchmarks for

renewable energy resources.

Who is purchasing the LCE

credits?

Similar to the renewable portfolio standard, electric utilities would purchase the LCE credits. While the

renewables procurement includes only eligible retail customers, the LCE procurement covers all retail

customers.

How will the utility recover its

costs to purchase LCE credits?

Utilities will recover all costs associated with purchasing LCE credits through a rider that adds a charge to each

retail customer’s bill (consistent with the 2.015% rate cap). Like the renewable portfolio standard, this charge

will remain fixed for the duration of the LCPS.

What is the procurement

process?

The LCE procurement process relies on the same process the IPA uses to procure renewable energy resources.

The key difference is the need to conduct a mid-year procurement. Because the legislation

probably will not become law until after the start of the 2015/2016 procurement year on June 1, 2015,

the

IPA

will

conduct

and

complete

initial

procurement

before

January

2016

that

will

procure

the

LCE

credits

needed

for

the

period

January

2016

through

May

31,

2021,

entering

into

contracts

years

in length.

The

IPA

may

also

conduct

later

procurement

processes

needs

so.

How long will the new LCE

procurement requirements be in

effect?

The

new

LCE

procurement

requirements

will

sunset

December

31,

2021,

long

the

State

has

adopted

and

implemented

plan

under

Section

111(d)

the

federal

Clean

Air

Act.

the

State

has

not

completed these actions by that date, then the new requirements will sunset on December 31 of the year in

which the State adopts and implements that plan.

2015 1Q Earnings Release Slides

Proposed Energy Plan for Illinois’

Future Legislation (HB

3328 / SB 1879)

2015 1Q Earnings Release Slides

Legislative

Change

Description

Customer Benefits

Expand Energy Efficiency

Allows utilities to invest in voltage optimization to meet

energy efficiency goals; spreads costs

to customers over 5

years minimizing initial customer impact;

shifts all energy

efficiency program management to the utilities

•

More energy efficiency

•

More customer cost

savings for most customers

regardless of program participation

Solar Power for the

Community

Changes existing net metering law to enable community solar

and other meter aggregation programs; provides access to

Renewable Energy Resources Fund (RERF) to support

development of community and rooftop solar

•

More customer access to sustainable

generation for customers at all income levels

and dwelling types (rentals, condos, homes with

rooftop limitations, etc.)

Equitable Cost Allocation

Through Rate Design

Modifications

Implements kilowatt-based rates for all retail customers;

breaks-out capacity and transmission charges as separate

bill line items; eliminates the requirement that a residential

customer who elects real-time pricing remain on that rate for

a minimum of a year

•

Allocates costs of grid more fairly and aligns

residential rate design with long-standing C&I

rate design

•

Unbundling charges facilitates comparisons of

energy offerings

•

Adjustment to real-time pricing provides more

pricing choices to customers

Additional Financial

Assistance for those in

need --

2021

Extends access to ComEd shareholder-funded customer

assistance dollars

for low-income customers, including senior

citizens, veterans, small businesses, and community

organizations

•

Provides $50M in customer assistance benefits

Microgrids

for Security and

Resiliency

Pilot program to demonstrate how microgrid

technology can

provide security and resiliency to critical infrastructure

•

Increased security,

resiliency, and reliability for

critical infrastructure

Electric Vehicle Charging

Stations

Initiates a program to increase the number and accessibility

of electric vehicle charging

•

Supports

electrification of transportation sector

Demand Response

Facilitation Service

Enables utility to aggregate demand response procurement

for retail energy providers in service territory;

easing the

administrative burden on retail energy providers

•

Ensures

viability of demand response

participation in Illinois

Renewable Portfolio

Standards Enhancements

Improves access to RERF money which is limited under the

current legislation and streamlines administration

•

Allows

for more competitive service for large

C&I customers

•

Increases RECs purchase

2015 1Q Earnings Release Slides

ComEd April 2015 Distribution Formula Rate

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

Given the retroactive ratemaking provision in the Energy Infrastructure Modernization Act (EIMA) legislation, ComEd net income during the year will

be based on actual costs with a regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. Revenue Requirement in

rate filings impacts cash flow.

Docket #

15-0287

Filing Year

Reconciliation Year

Common Equity Ratio

~ 46%

for both the filing and reconciliation year

ROE

9.14%

for the filing year (2014 30-yr Treasury Yield of 3.34% + 580 basis point risk premium) and 9.09%

for the

reconciliation

year

(2014

30-yr

Treasury

Yield

3.34%

580

basis

point

risk

premium

–

basis

points

performance metrics

penalty). For 2015 and 2016, the actual allowed ROE reflected in net income will ultimately be based on the average of the

30-year Treasury Yield during the respective years plus 580 basis point spread, absent any metric penalties

Requested Rate of Return

~ 7%

for both the filing and reconciliation years

Rate Base

$8,286 million –

Filing

year

(represents

projected

year-end

rate

base

using

2014

actual

plus

2015

projected

capital additions). 2015

and 2016 earnings will reflect 2015 and 2016 year-end rate base respectively.

$7,095 million -

Reconciliation year (represents year-end rate base for 2014)

Revenue Requirement

Decrease

$50M decrease

($142M decrease due to the 2014 reconciliation offset by a $92M

increase related to the filing year).

The 2014 reconciliation impact on net income was recorded in 2014 as a regulatory asset.

Timeline

•

04/15/15 Filing Date

•

240 Day Proceeding

•

ICC order expected to be issued by mid-December 2015

2014 Calendar Year Actual Costs and 2015 Projected Net Plant Additions

are

used

set

the

rates

for

calendar

year 2016.

Rates currently in effect (docket 14-0312) for calendar year 2015 were based on 2013 actual costs and

2014 projected net plant

additions

Reconciles

Revenue

Requirement

reflected

rates

during

2014

Actual

Costs

Incurred.

Revenue requirement

for

2014

based

docket

13-0318

(2012

actual

costs

and

2013

projected

net

plant

additions) approved

December 2013 and

reflects the impacts of PA 98-0015 (SB9)

The 2015 distribution formula rate filing establishes the net revenue requirement used to set the rates that will take effect

in January 2016 after

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

•

Filing Year: Based on prior year costs (2014) and current year (2015) projected plant additions.

•

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

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

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

2015 1Q Earnings Release Slides

PECO Electric Distribution Rate Case

Docket #

R-2015-2468981

Fully Projected Future Test Year

2016

Common Equity Ratio

53%

Requested Return on Equity

10.95%

Overall Rate of Return

8.2%

Proposed Rate Base

$4.1B

Revenue Requirement Increase Ask

$190M

System Average Increase as % of overall bill

4.4%

Timeline

•

3/27/15 –

PECO filed electric distribution rate case with PaPUC

•

9 month Proceeding

•

Increased rates effective on January 1, 2016

Basis for Rate Case

•

Since last rate case (2010):

•

Proposed investment maintains strong reliability performance with targeted

First Electric Distribution Rate Case since 2010

investment to address pockets with reliability issues

–

Electric Distribution Rate base increased by one third

(approximately $1B)

–

Sales declined by 0.6%

–

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

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

PECO Electric LTIIP -

System 2020

•

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

with its associated recovery mechanism the Distribution System Improvement

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

o

LTIIP

includes

$275

million

incremental

capital

spending

from

2016-2020

focusing on the following areas:

Cable Replacement

Storm Hardening Programs

Substation replacement and upgrades

o

DSIC mechanism will allow recovery of eligible LTIIP spend between rate

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

PaPUC. The current Electric DSIC ROE is 10.1%.

o

Expected approval in 3Q15

•

PECO also proposed the concept of constructing one or more pilot

microgrid

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

evaluate and test emerging microgrid technologies that could enhance reliability

and resiliency by replacing obsolete infrastructure as an alternative to traditional

solutions.

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

Notes: Data is not adjusted for leap year. Source of economic outlook data is IHS (February 2015) and Bureau of Economic Analysis. Assumes 2015 GDP of 3.0% and U.S. unemployment

of 5.5%. 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

BGE

2015 load growth is greater

than 2014, attributable to

slowly improving economic

conditions and moderate

customer growth, partially

offset by energy efficiency

Exelon Utilities Load

2015E

2014

Large C&I

Small C&I

Residential

All Customers

ComEd

2015 load growth is similar to

2014 reflecting slowly

improving economy being

offset by energy efficiency

2015E

2014

PECO

2015 load growth is driven by

modest economic growth

coupled with increased shale

gas transportation and NGL

production, partially offset by

energy efficiency.

2015E

2014

Chicago GMP

2.4%

Chicago Unemployment

6.1%

Philadelphia GMP

2.0%

Philadelphia Unemployment

6.6%

Baltimore GMP

1.6%

Baltimore Unemployment

5.8%

-0.1%

0.2%

-0.5%

0.3%

0.2%

-0.3%

0.7%

0.9%

0.1%

0.8%

0.5%

-0.8%

0.0%

2.0%

-0.1%

0.1%

-1.3%

0.2%

-0.9%

-0.2%

0.1%

-1.9%

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

Appendix

Reconciliation of Non-GAAP

Measures

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

1Q GAAP EPS Reconciliation

Three Months Ended March 31, 2015

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.35

$0.11

$0.16

$0.12

$(0.03)

$0.71

Mark-to-market impact of economic hedging activities

0.11

Unrealized gains related to NDT fund investments

0.03

Merger and integration costs

(0.01)

(0.02)

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

(0.06)

Amortization of commodity contract intangibles

0.03

Midwest Generation bankruptcy recoveries

0.01

CENG Non-Controlling Interest

(0.01)

1Q 2015 GAAP Earnings (Loss) Per Share

$0.51

$0.11

$0.16

$0.12

$(0.10)

$0.80

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 March 31, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.30

$0.11

$0.10

$0.62

Mark-to-market impact of economic hedging activities

(0.52)

Unrealized gains related to NDT fund investments

0.01

Merger and integration costs

(0.01)

Amortization of commodity contract intangibles

(0.04)

Tax settlements

0.04

1Q 2014 GAAP Earnings (Loss) Per Share

$(0.22)

$0.11

$0.10

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

GAAP to Operating Adjustments

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

•

Exelon’s 2015 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:

Mark-to-market adjustments from economic hedging activities

Unrealized gains and losses from NDT fund investments to the extent not offset by contractual

accounting as described in the notes to the consolidated financial statements

Certain costs incurred associated with the Integrys and pending Pepco Holdings, Inc. acquisitions

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

the pending PHI acquisition

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

the date of acquisition of Integrys in 2014

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

Other unusual items

2015 1Q Earnings Release Slides

2015 1Q Earnings Release Slides

ExGen Total Gross Margin Reconciliation to GAAP

Total Gross Margin Reconciliation (in $M)

(4)

2015

2016

2017

Revenue

Net

Purchased

Power

and

Fuel

Expense

(1)(5)

$8,150

$8,050

$8,350

Other Revenues

(2)

$(250)

Direct cost of sales incurred to generate revenues for certain

Constellation businesses

(3)

$(300)

$(350)

$(450)

Total Gross Margin (Non-GAAP, as shown on slide 5)

$7,600

$7,450

$7,650

2015 1Q Earnings Release Slides

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.

Reflects revenues from operating services agreement with Fort Calhoun, variable interest entities, funds collected through revenues for decommissioning the former PECO

nuclear plants through regulated rates and gross receipts tax revenues.

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

All amounts rounded to the nearest $50M.

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

(1)

(2)

(3)

(4)

(5)

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