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

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Earnings Conference Call

3 Quarter 2014

October 29, 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 Third Quarter 2014 Quarterly Report on

Form 10-Q (to be filed on October 29, 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 18; 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 3Q Earnings Release Slides

•

Texas combined cycle new

build

•

Integrys Energy Services

acquisition

•

Pepco Holdings Inc. acquisition

•

Virginia approval received

•

Nuclear

capacity

factor

96.5%

(2)

•

Power dispatch match of 98.8%

and renewables energy capture of

94.9%

•

PJM Capacity Performance

proposal

•

NEI Report on the economic impact

of nuclear plants in Illinois

•

ComEd and BGE rate cases

2014 3Q Earnings Release Slides

•

Delivered Q3 adjusted operating

earnings of $0.78 per share,

exceeding our guidance range

(1)

•

ExGen Texas Power, LLC financing

•

Divested three power plants

Q3 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

The integrated business model allows us to invest in each of our businesses driving

shareholder value

Exelon Generation: Gross Margin Update

September 30, 2014

Change from June 30, 2014

Gross Margin Category ($M)

(1)

2014

2015

2016

2014

2015

2016

Open Gross Margin

(3,5)

(including South, West, Canada hedged

gross margin)

7,300

6,750

6,500

(200)

(50)

(350)

Mark-to-Market of Hedges

(3,4)

(350)

150

350

(50)

100

Power New Business / To Go

400

550

(100)

Non-Power Margins Executed

350

100

Non-Power New Business / To Go

300

350

(50)

Total Gross Margin

(2)

7,400

7,550

7,600

(200)

(250)

2014 3Q Earnings Release Slides

Gross Margin decreased in 2015 and 2016 mainly due to divestitures

defined

mild

summer

weather

leading

low

demand

and

strong

natural

gas

storage

injections

Behind ratable hedge percentage in the Midwest is reflective of our bullish view in 2016/2017

Key Financial Messages

2014 3Q Earnings Release Slides

ExGen

ComEd

PECO

BGE

$0.78

$0.50

$0.15

$0.09

$0.05

2014

Adjusted

Operating

EPS

(1,3)

Narrowing 2014 Full-Year Guidance

ComEd

2014 Revised

Guidance

$0.35 -

$0.45

$0.15 -

$0.25

2014 Initial

Guidance

$2.25 -

$2.55

(1)

$1.10 -

$1.30

$0.50 -

$0.60

$0.40 -

$0.50

$0.20 -

$0.30

$2.30 -

$2.50

(1)

PECO

ExGen

ComEd

BGE

ExGen

$1.25 -

$1.35

$0.45 -

$0.55

Narrowing

2014

full-year

guidance

$2.30

$2.50

per

(2)

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

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

Amounts may not add due to rounding

(1)

(2)

(3)

Exelon Utilities Adjusted Operating EPS Contribution

(1)

Key

Drivers

–

3Q14

vs.

3Q13:

BGE

(-0.01):

•

Increased O&M, primarily due to increased storm, labor,

and contracting costs: $(0.02)

•

Higher distribution revenue pursuant to increased rates

effective December 2013: $0.01

PECO (-0.02):

•

Unfavorable weather conditions included in revenue, net of

purchased power and fuel: $(0.01)

•

Increased O&M costs, primarily due to increased storm

costs: $(0.01)

ComEd

(+0.00):

•

Increased transmission and distribution

(2)

earnings due to

increased capital investments: $0.02

•

Unfavorable weather conditions

(2)

: $(0.02)

2014 3Q Earnings Release Slides

3Q 2014

$0.29

$0.15

$0.09

$0.05

3Q 2013

$0.32

$0.15

$0.11

$0.06

ComEd

BGE

PECO

Numbers may not add due to rounding.

(1)

Refer

the

Earnings

Release

Attachments

for

additional

details

and

the

Appendix

for

reconciliation

adjusted

(non-GAAP)

operating

EPS

GAAP

EPS.

(2)

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

addition to weather, load and changes in customer mix.

DRAFT

2014 Projected Sources and Uses of Cash

Key Messages

(1)

•

Cash from Operations is projected to be $7,475M vs. 2Q14E of

$6,975M for a $500M variance. This variance is driven by:

$625M Net proceeds from divestitures

$175M Income taxes

$125M Reclassification of PHI preferred stock purchase

($325M) Integrys acquisition, including working capital

($100M) Working capital at Utilities

•

Cash from Financing activities is projected to be $375M vs.

2Q14E of $250M for a $125M variance. This variance is driven

by:

$175M Incremental project financing at ExGen

($50M) Decreased ComEd LTD requirements

($25M) Decrease in projected commercial paper financings

•

Cash from Investing activities is projected to be ($5,725M) vs.

2Q14E of ($5,450M) for a ($275M) variance. This variance is

driven by:

($125M) ExGen development

($125M) Reclassification of PHI preferred stock purchase

($25M) Upstream

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, and ($125M) purchase of PHI

preferred stock.

(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 $5.7B 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.

2014 3Q Earnings Release Slides

APPENDIX

2014 3Q Earnings Release Slides

PJM’s Proposed Solution -

Capacity Performance Proposal

•

Exelon has been working with PJM and other stakeholders since the spring

•

PJM now recognizes that generation resources procured through its existing forward capacity market (RPM)

may

not

sufficient

meet

future

load

conditions,

especially

winter

peak

o

Additionally, current revenues and penalty structures are insufficient to incent necessary investment

to maintain highly available capacity

•

PJM released a revised “Capacity Performance”

proposal October 7, 2014 revamping initial reform

concepts suggested in August

o

The Capacity Performance concept reforms are intended to encourage commitment of capacity

resources that have secure fuel and other performance characteristics to provide PJM confidence

that

units

will

available

when

dispatched

meet

peak

summer

and

winter

load

o

PJM proposes to increase the capacity market offer cap to Net CONE, but to substantially raise

penalties for performance failure

o

PJM suggests transition mechanisms for delivery years in which it has already made forward capacity

procurements (2015-16, 2016-17, and 2017-18)

o

PJM proposed a method of integrating “wholesale”

demand response through PJM Load Serving

Entities in a manner that would clear by adjusting the RPM demand curve

2014 3Q Earnings Release Slides

Exelon Generation Disclosures

September 30, 2014

2014 3Q Earnings Release Slides

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

2014 3Q Earnings Release Slides

Note: Hedge strategy has not changed as a result of recent and pending asset divestitures

Exercising

Market

Views

Portfolio

Management

Over

Time

Align Hedging & Financials

Establishing Minimum Hedge Targets

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

Dividend

Capital

Structure

Credit Rating

Capital &

Operating

Expenditure

•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

Strategic Policy Alignment

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

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

(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

hedges

provided

directly

for

the

five

larger

regions.

MtM

hedges

not

provided

directly

the

regional

level

but

can

easily

estimated

using

EREP,

reference

price

and

hedged

MWh

(3)

Proprietary

trading

gross

margins

will

generally

remain

within

“Non

Power”

New

Business

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

2014 3Q Earnings Release Slides

ExGen Disclosures

Gross Margin Category ($M)

(1,6)

2014

2015

2016

Open Gross Margin

(including South, West & Canada hedged GM)

(3)

7,300

6,750

6,500

Mark to Market of Hedges

(3,4)

(350)

150

Power New Business / To Go

400

550

Non-Power Margins Executed

350

100

Non-Power New Business / To Go

300

350

Total Gross Margin

(2)

7,400

7,550

7,600

Reference Prices

(5)

2014

2015

2016

Henry Hub Natural Gas ($/MMbtu)

$4.44

$4.00

$4.08

Midwest: NiHub ATC prices ($/MWh)

$39.45

$33.70

$33.21

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

$51.38

$42.75

$40.69

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$3.02

$6.47

$6.14

New York: NY Zone A ($/MWh)

$49.00

$42.14

$38.94

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

ALQN Gas, 7.5HR, $0.50 VOM

$3.04

$8.95

$7.64

2014 3Q Earnings Release Slides

(1)

Gross margin categories rounded to nearest $50M

(2)

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

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

Exelon Nuclear Partners and variable interest entities. Total Gross Margin is also net of

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

GAAP reconciliation of Total Gross Margin

(3)

Excludes EDF’s equity ownership of the CENG joint venture

(4)

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

(5)

Based on September 30, 2014 market conditions

(6)

Reflects the divestiture impact of Fore River, Quail Run and West Valley. Does not

include divestiture impact of Keystone/Conemaugh

ExGen Disclosures

Generation and Hedges

(6)

2014

2015

2016

Expected Generation (GWh)

(1)

205,300

200,800

202,200

Midwest

97,000

96,600

97,500

Mid-Atlantic

(2)

74,300

71,300

72,100

ERCOT

11,400

16,400

16,900

New York

(2)

12,700

9,400

9,300

New England

9,900

7,100

6,400

% of Expected Generation Hedged

(3)

98-101%

86-89%

55-58%

Midwest

97-100%

83-86%

49-52%

Mid-Atlantic

(2)

98-101%

88-91%

55-58%

ERCOT

101-104%

99-102%

82-85%

New York

(2)

98-101%

87-90%

62-65%

New England

102-105%

82-85%

62-65%

Effective Realized Energy Price ($/MWh)

(4)

Midwest

$36.50

$33.50

$34.50

Mid-Atlantic

(2)

$48.50

$42.50

$43.00

ERCOT

(5)

$20.00

$8.50

$5.50

New York

(2)

$42.50

$40.00

New England

(5)

$6.00

$11.50

$4.50

2014 3Q Earnings Release Slides

(1) Expected generation is the volume of energy that best represents our financial exposure 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 in 2016 at Exelon-operated nuclear plants, and Salem. Expected generation assumes capacity factors of 93.6%, 93.5%, and 94.1% in 2014,

2015, and 2016 respectively 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) 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. (6) Reflects the divestiture impact of Fore River, Quail Run

and West Valley. Does not include divestiture impact of Keystone/Conemaugh

ExGen Hedged Gross Margin Sensitivities

(1) Based on September 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) Excludes EDF’s equity

ownership share of the CENG Joint Venture. (4) Reflects the divestiture impact of Fore River, Quail Run and West Valley. Does not include divestiture of impact of Keystone/Conemaugh

Gross Margin Sensitivities (With Existing Hedges)

(1,2,4)

2014

2015

2016

Henry Hub Natural Gas ($/Mmbtu)

+ $1/Mmbtu

$15

$120

$440

$1/Mmbtu

$10

$(60)

$(400)

NiHub ATC Energy Price

+ $5/MWh

$85

$265

$5/MWh

$(85)

$(260)

PJM-W ATC Energy Price

+ $5/MWh

$(5)

$30

$165

$5/MWh

$(25)

$(155)

NYPP Zone A ATC Energy Price

+ $5/MWh

$15

$5/MWh

$(10)

$(20)

Nuclear Capacity Factor

(3)

+/-

$15

+/-

$50

+/-

$45

2014 3Q Earnings Release Slides

ExGen Hedged Gross Margin Upside/Risk

2014 3Q Earnings Release Slides

Note: Reflects the divestiture impact of Fore River, Quail Run and West Valley. Does not include divestiture impact of Keystone/Conemaugh

(1)

Represents

approximate

range

expected

gross

margin,

taking

into

account

hedges

place,

between

the

5th

and

95th

percent

confidence

levels

assuming

all

unhedged

supply

sold

into

the

spot

market.

Approximate

gross

margin

ranges

are

based

upon

internal

simulation

model

and

are

subject

change

based

upon

market

inputs,

future

transactions

and

potential

modeling

changes.

These

ranges

approximate

gross

margin

2015

and

2016

not

represent

earnings

guidance

forecast

future

results

Exelon

has

not

completed

its

planning

optimization

processes

for

those

years.

The

price

distributions

that

generate

this

range

are

calibrated

market

quotes

for

power,

fuel,

load

following

products,

and

options

September

30,

2014

(2)

Gross

Margin

Upside/Risk

based

commodity

exposure

which

includes

open

generation

and

all

committed

transactions.

(1)

Mark-to-market rounded to the nearest $5 million.

(2)

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

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

Gross Margin.

Note: Reflects the divestiture impact of Fore River, Quail Run and West Valley. Does not include divestiture impact of Keystone/Conemaugh

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

$6.75 billion

(B)

Expected Generation (TWh)

97.0

71.3

16.4

9.4

7.1

(C)

Hedge % (assuming mid-point of range)

84.5%

89.5%

100.5%

88.5%

83.5%

(D=B*C)

Hedged Volume (TWh)

82.0

63.8

16.4

8.3

5.9

(E)

Effective Realized Energy Price ($/MWh)

$33.50

$42.50

$8.50

$42.50

$11.50

(F)

Reference Price ($/MWh)

$33.70

$42.75

$6.47

$42.14

$8.95

(G=E-F)

Difference ($/MWh)

$(0.20)

$(0.25)

$2.03

$0.36

$2.55

(H=D*G)

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

(1)

$(15) million

$30 million

$5 million

$15 million

(I=A+H)

Hedged Gross Margin ($ million)

$6,750 million

(J)

Power New Business / To Go ($ million)

$400 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)

$7,550 million

2014 3Q Earnings Release Slides

Additional Disclosures

2014 3Q Earnings Release Slides

BGE

2014 load growth is weaker than

2013, driven by Large C&I. Weaker

economic conditions and continued

energy efficiency impacts are offset

by steady customer growth.

Exelon Utilities Weather-Normalized Load

2014E

0.6%

0.1%

1.4%

0.7%

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

0.0%

-0.6%

1.1%

0.3%

2013

1.5%

-1.1%

0.0%

0.3%

PECO

2014 load growth is driven primarily

by Residential partially offset by

C&I.

Slowly improving

economic

conditions and moderate customer

growth are partially offset by energy

efficiency.

-0.5%

-0.7%

-1.2%

2013

-3.2%

2.1%

2.0%

-0.6%

2014E

-1.8%

Chicago GMP

1.7%

Chicago Unemployment

6.3%

Philadelphia GMP

1.2%

Philadelphia Unemployment

5.9%

Baltimore GMP

2.6%

Baltimore Unemployment

6.0%

Notes: Data is not adjusted for leap year.

Source of economic outlook data is IHS Economics (September 2014).

Assumes 2014 GDP of 2.2% and U.S unemployment of 5.9%.

ComEd

has

the

ROE

collar

part

the

distribution

formula

rate

and

BGE

decoupled

which

mitigates

the

load

risk.

QTD

and

YTD

actual

data

can

found

earnings

release

tables.

BGE

amounts have been adjusted for true-up load from prior quarters.

2014 3Q Earnings Release Slides

2014 3Q 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

set

the

rates

for

calendar

year

2015. Rates

currently in effect (docket 13-0318) for calendar year 2014 were based on 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 is

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 of 3.45% + 580 basis point risk premium –

5 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

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

($96M

due

the

2013

reconciliation,

$173M

relates

the

filing

year).

The

2013

reconciliation

impact

net income was

recorded in 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

the

EIMA

legislation,

ComEd

net

income

during

the

year

will

based

actual

costs

with

regulatory

asset/liability

recorded

reflect

any

under/over

recovery

reflected

rates.

Revenue

Requirement

rate

filings

impacts

cash

flow.

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:

•

Filing Year: 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.

•

04/16/14

Filing

Date

•

240

Day

Proceeding

•

ALJ

Proposed

Order

issued

10/15/14

proposes

$239M

revenue

requirement

increase

•

ICC

order

expected

December

12,

2014

2014 3Q Earnings Release Slides

BGE Rate Case Settlement

Electric

Gas

Docket #

9355

Test Year

September

2013

August

2014

Common

Equity

Ratio

(1)(2)

52.3%

Authorized

Returns

(1)(3)

ROE: 9.75%; ROR: 7.46%

ROE: 9.65%; ROR: 7.41%

Requested Rate of Return

7.93%

7.88%

Proposed

Rate

Base

(adjusted)

(1)(4)

$2.9B

$1.2B

Revenue

Requirement

Increase

$22.0M

$38.0M

Distribution

Increase

overall bill

Timeline

(1)

Due to the “black box”

nature of the settlement, the Common Equity Ratio, Authorized Returns, and Proposed Rate Base (adjusted) were not agreed upon by the parties in determining the

ultimate revenue requirement increase.

(2)

Reflects BGE’s actual capital structure as of 8/31/2014

(3)

ROE and ROR stated in the settlement only apply to AFUDC and carrying costs on regulatory assets

(4)

BGE’s Proposed Adjusted rate base.

First BGE rate case settlement agreement since 1999

•

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

•

10/17/14 –

BGE filed unanimous “black box”

settlement with MD PSC

•

Settlement must be approved by the MD PSC

•

If approved, new rates are expected to be effective no sooner than the middle of

December, 2014

Appendix

Reconciliation of Non-GAAP

Measures

2014 3Q Earnings Release Slides

3Q GAAP EPS Reconciliation

Three Months Ended September 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.50

$0.15

$0.09

$0.05

$(0.01)

$0.78

Mark-to-market impact of economic hedging activities

0.19

0.18

Unrealized losses related to NDT fund investments

(0.03)

Asset retirement obligation

0.02

Plant retirements and divestitures

0.23

Long-lived asset impairment

(0.03)

Merger and integration costs

(0.05)

(0.02)

(0.07)

Amortization of commodity contract intangibles

0.01

Tax settlements

0.08

Noncontrolling interest

(0.02)

3Q 2014 GAAP Earnings (Loss) Per Share

$0.90

$0.15

$0.09

$0.05

$(0.03)

$1.15

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

2014 3Q Earnings Release Slides

Three Months Ended September 30, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$0.47

$0.15

$0.11

$0.06

$(0.02)

$0.78

Mark-to-market impact of economic hedging activities

0.18

0.17

Unrealized gains related to NDT fund investments

0.03

Asset retirement obligation

(0.01)

Long-lived asset impairment

(0.03)

Merger and integration costs

(0.02)

(0.03)

Amortization of commodity contract intangibles

(0.05)

3Q 2013 GAAP Earnings (Loss) Per Share

$0.57

$0.15

$0.11

$0.06

$(0.02)

$0.86

3Q YTD GAAP EPS Reconciliation

Nine Months Ended September 30, 2014

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$1.07

$0.39

$0.30

$0.17

$(0.02)

$1.91

Mark-to-market impact of economic hedging activities

(0.34)

Unrealized gains related to NDT fund investments

0.07

Asset retirement obligation

0.02

Plant retirements and divestitures

0.23

Long-lived asset impairment

(0.10)

(0.02)

(0.11)

Gain on CENG integration

0.18

Merger and integration costs

(0.09)

(0.03)

(0.12)

Amortization of commodity contract intangibles

(0.05)

(0.06)

Tax settlements

0.12

Noncontrolling interest

(0.04)

3Q 2014 GAAP Earnings (Loss) Per Share

$1.07

$0.39

$0.30

$0.17

$(0.07)

$1.86

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

2014 3Q Earnings Release Slides

Nine Months Ended September 30, 2013

ExGen

ComEd

PECO

BGE

Other

Exelon

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

$1.18

$0.36

$0.34

$0.16

$(0.06)

$2.00

Mark-to-market impact of economic hedging activities

0.20

(0.00)

0.21

Unrealized gains related to NDT fund investments

0.04

Asset retirement obligation

(0.01)

Plant retirements and divestiture

0.02

0.01

Long-lived asset impairment

(0.12)

(0.01)

(0.13)

Merger and integration costs

(0.07)

(0.01)

0.00

(0.00)

(0.08)

Amortization of commodity contract intangibles

(0.32)

Remeasurement of like kind exchange tax position

(0.20)

(0.11)

(0.31)

Amortization of the fair value of certain debt

0.01

3Q 2013 GAAP Earnings (Loss) Per Share

$0.93

$0.16

$0.33

$0.17

$(0.18)

$1.42

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 3Q 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 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 increase and decrease in certain decommissioning obligations

Financial impacts associated with the sale of interests in generating stations

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

and the impairment of certain wind generating assets and certain

assets held for sale

Gain recorded upon consolidation of CENG

Certain costs incurred associated with the Constellation and Pepco Holdings, Inc. mergers and

integration initiatives. Also includes costs to integrate CENG

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

the merger date for 2014

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

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 of Purchased Power and Fuel Expense

(1)(6)

$7,800

$8,150

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

commodity contracts recorded at fair value at 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)

$(300)

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

$7,400

$7,550

$7,600

2014 3Q 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 excludes EDF’s 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 ~$500 million for the nine months ended September 30, 2014

Attached files

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