Deutsche Bank 2010 Alternative Energy, Utilities

& Power Conference

William A. Von Hoene, Jr., EVP Finance and Legal

May 12, 2010

Exhibit 99.1

2

Forward-Looking Statements

This presentation includes 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

these forward-looking statements include those discussed herein as well as those

discussed in (1) Exelon’s 2009 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 18; (2) Exelon’s First Quarter 2010 Quarterly Report on

Form 10-Q in (a) Part II, Other Information, Item 1A.  Risk Factors and (b) Part I,

Financial

Information,

Item

1.

Financial

Statements:

Note

12

and

(3)

other

factors

discussed

in

filings

with

the

Securities

and

Exchange

Commission

(SEC)

by

Exelon Corporation, Commonwealth Edison Company, PECO Energy Company

and Exelon Generation Company, LLC (Companies). 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 Companies undertakes any obligation to

publicly release any revision to its forward-looking statements to reflect events or

circumstances after the date of this presentation.

3

10,300 MW

8,700 MW

1,500 MW

RTO

EMAAC

MAAC

Exelon Generation Hedging and

2013/2014 RPM Auction

$44.50

$44.50

$46.50

Midwest

$51.50

$58.00

$36.00

Mid-Atlantic

$(6.50)

$0.50

$0.50

ERCOT North ATC Spark

Spread

Effective Realized

Energy Price

(1)

$32.19

$30.71

$29.73

Ni-Hub ATC ($/MWh)

$43.47

$42.04

$39.69

PJM-W ATC ($/MWh)

Reference Prices

2010

2011

2012

Percentage of Expected

Generation Hedged

(2)

95-98%

79-82%

48-51%

Midwest

92-95

79-82

52-55

Mid-Atlantic

96-99

81-84

44-47

South

97-100

68-71

41-44

Capacity by Region Eligible for 2013/14 RPM

Base Residual Auction

(3)

(3)  All generation values are approximate and not inclusive of wholesale transactions.

Notes: All capacity values are in installed capacity terms (summer ratings) located in the areas.

Eddystone 2 to retire 12/31/13.

MAAC = Mid-Atlantic Area Council; EMAAC = Eastern MAAC; the MAAC area encompasses

EMAAC.

7%

50%

43%

Hedge Profile as of March 31, 2010

Hedging program protects Exelon in market downturns and leaves upside to recovery;

capacity auction should provide modest upside to Exelon Generation in 2013/2014

(1)

See Footnote 3 on page 19

(2)

See Footnote 2 on page 19

4

Utility Load –

Emerging Signs of Recovery

Weather-Normalized Load

Note: C&I = Commercial & Industrial; E = Estimated

2009

(1)

1Q10       2010E

Customer Growth

(0.4)%     (0.1)%       0.1%

Average Use-Per-Customer (1.0)%

0.2%

0.1%

Total Residential

(1.4)%       0.1%        0.2%

Small C&I

(2.2)%    (1.7)%       0.4%

Large C&I

(6.7)%    (1.1)%       1.7%

All Customer Classes

(3.3)%    (0.8)%       0.8%

2009

(1)

1Q10        2010E

Customer Growth

(0.2)%       (0.2)%       (0.0)%

Average Use-Per-Customer (2.1)%

2.1%

1.2%

Total Residential

(2.3)%         1.8%         1.1%

Small C&I

(2.7)%       (0.9)%       (0.2)%

Large C&I

(3.0)%         0.1%        (0.3)%

All Customer Classes

(2.6)%         0.5%         0.3%

ComEd

March 2010 was first month with

positive load growth since July 2008

Positive customer growth in 1Q10;

first time since December 2008

Expected improvement in C&I load

through 2010

PECO

Signs of improving demand earlier

than expected

Increased load in Large C&I in 1Q10

Positive Gross Metro Product

forecasted for Philadelphia in 2010

Weather-Normalized Electric Load

Beginning to see signs of recovery in Chicago and Philadelphia

(1) Not adjusted for leap year effect.

5

Constructive Regulatory

Relationships for ComEd and PECO

ComEd

Uncollectibles expense rider allows ComEd to recover bad debt amounts

not included in base rates ($70M in 2008-2009)

ComEd investing ~$70M in ICC-approved Smart Meter pilot

program

with

rider recovery

ComEd expects to file an electric distribution rate case in 2Q10

PECO

PECO filed electric and gas distribution rate cases in March 2010

•

First electric distribution rate case in 21 years

PECO to invest in Smart Meter/Smart Grid over 10-15 years

•

Received $200M grant from DOE for Smart Grid Investments

•

Costs recoverable through a combination of surcharge and return on rate base

2 of 4 procurements for post 2010-supply complete; preparing residential

customers for overall increases of ~11%

Utility investment is being recovered through rate cases and rider mechanisms

Note: ICC = Illinois Commerce Commission

6

Nuclear Uprates Remain Economic

Exelon investing ~$4.4B through 2017 in nuclear uprate

projects that will

provide an additional 1,300 –

1,500 MWs

of additional generation capacity

Projects have significantly lower cost and shorter timeline than

a new nuclear

plant -

$2,200-2,500/kW overnight cost

Scale of nuclear uprates

that Exelon can execute is unmatched

Uprate program allows us to adjust timing to respond to market conditions

Extended Power

Uprates

(EPUs)

Measurement Uncertainty

Recapture (MURs)

MW Recovery and           

Component Upgrades

Maximum                        

Potential MW

Year Uprates Become Operational

1999-

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2009-

2017

Exelon’s Uprate Plan

1,100 MW

1,300 –

1,500  MW

0

200

400

600

800

1,000

1,200

1,400

1,600

~70 MW

7

316(b)

2010

2011

2012

2013

2014

2015

2016

2017

2018

Hazardous

Air

Pollutants

(HAP)

Criteria

Pollutants

Greenhouse

Gases

Coal

Combustion

By-Products

Compliance with Federal GHG Reporting Rule

Pre-Compliance  Period

PSD/BACT and Title V Applies to GHG Emissions from New and Modified Sources

Develop GHG Cap and Trade

Legislation or EPA GHG

Regulations Under CAA

Compliance with GHG Cap and

Trade Legislation or EPA GHG

Regs

Under CAA

Compliance with MACT

HAP ICR

Pre-Compliance  Period

Develop Coal

and Oil MACT

Interim CAIR Program

Pre-Compliance Period

Develop Clean

Air Transport

Rule (CATR)

Compliance with CATR (to replace CAIR)

SIP provisions developed in response to revised NAAQS

(e.g., Ozone, PM

2.5

, SO2, NO2)

Develop Revised

NAAQS

Pre-Compliance Period

Compliance with Federal CCB

Regulations

Develop Coal

Combustion By-

Products Rule

Pre-Compliance Period

Compliance with 316(b) Regulations

Develop 316(b)

Regulations

EPA Regulation

Note: For definition of the EPA regulations referred to on this slide, please see the EPA’s Terms of Environment (http://www.epa.gov/OCEPAterms/).

8

Appendix

9

Illinois Power Agency (IPA)

RFP Procurement

•

On April 30, 2010, the ICC approved the bids from the RFP Procurement held on

April 28, 2010, for the remaining ComEd 2010-2011 load (~25% of the total) and

a portion of its 2011-2012 load (~7% of the total)

–

Contracts were awarded to 12 successful bidders

–

$32.54

ATC price for 2010-2011 planning year, in addition to:

•

Financial Swap price (ATC baseload energy only) of $50.15 for June 2010 –

December 2010 and $51.26 for January 2011 –

December 2011; increase in

notional quantity to 3,000 MW on June 1, 2010

Delivery

Period

Peak

Off-Peak

June 2010 -

May 2011

5,528

4,344

June 2011 -

May 2012

1,980

549

Volume procured in the 2010 IPA

Procurement Event (GWh)

Note: Chart is for illustrative purposes only.  Data on this slide is rounded.

2009 RFP

2009 RFP

2010 RFP

2010 RFP

2011 RFP

2011 RFP

2011 RFP

2012 RFP

2012 RFP

2013 RFP

Financial

Swap

Auction

Contract

June 2009

June 2010

June 2011

June 2012

June 2013

June 2014

10

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10E

3Q10E

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

ComEd Load Trends

Weather-Normalized Load

Key Economic Indicators

Note: C&I = Commercial & Industrial

Weather-Normalized Load Year-over-Year

(4)

Chicago

Unemployment rate

(1)

10.9%

2010 annualized growth in

gross domestic/metro product

(2)

2.9%

1/10 Home price index

(3)

(4.4)%

(1)  Source: Illinois Dept. of Employment Security (February 2010)

(2)

Source: Global Insight (March 2010)

(3)

Source: S&P Case-Shiller Index

(4)

Not adjusted for leap year effect

2009

(4)

1Q10       2010E

Average Customer Growth

(0.4)%     (0.1)%       0.1%

Average Use-Per-Customer

(1.0)%

0.2%

0.1%

Total Residential

(1.4)%       0.1%        0.2%

Small C&I

(2.2)%    (1.7)%        0.4%

Large C&I

(6.7)%    (1.1)%        1.7%

All Customer Classes

(3.3)%    (0.8)%        0.8%

11

PECO Load Trends

Weather-Normalized Electric Load

Key Economic Indicators

Weather-Normalized Load Year-over-Year

(3)

Philadelphia

Unemployment rate

(1)

9.2%               

2010 annualized growth in

gross domestic/metro product

(2)

0.8%

(1)  Source: U.S Dept. of Labor (PHL -

February 2010)

(2)  Source: Moody’s Economy.com (March 2010)

(3)  Not adjusted for leap year effect

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10E

3Q10E

4Q10E

-10.0%

-7.5%

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

All Customer Classes

Large C&I

Residential

Gross Metro Product

Note: C&I = Commercial & Industrial

2009

(3)

1Q10        2010E

Average Customer Growth

(0.2)%       (0.2)%       (0.0)%

Average Use-Per-Customer

(2.1)%

2.1%

1.2%

Total Residential

(2.3)%         1.8%          1.1%

Small C&I

(2.7)%       (0.9)%       (0.2)%

Large C&I

(3.0)%         0.1%        (0.3)%

All Customer Classes

(2.6)%         0.5%         0.3%

12

PECO –

Electric & Gas Distribution

Rate Case Filings

On March 31, PECO filed electric and gas distribution rate cases

•

First electric distribution rate case since 1989

–

Act 129 energy efficiency and smart meter costs recovered separately through rider

•

Last gas delivery rate case in 2008

53.18%

53.18%

Common Equity Ratio

R-2010-216-1592

R-2010-216-1575

Docket #

2010

(1)

2010

(1)

Test Year

ROE: 11.75%

ROR: 8.95%

ROE: 11.75%

ROR: 8.95%

Requested Returns

$1,100 million

$3,236 million

Rate Base

6.94%

(2)

$316 million

Electric

$44 million

Revenue Requirement Increase

5.28%

2011 Proposed Distribution Price

Increase as % of Overall Customer Bill

Gas

Rate Case Request

The PAPUC has a nine-month process for litigation of the

rate case filings

(1) With pro forma adjustments.

(2) Excluding Alternative Energy Portfolio Standards (AEPS) and default service surcharge.

Note: Electric and gas rate case filings available on PAPUC website or www.peco.com/know.

13

5.03

6.26

6.23

0.51

0.70

2.57

9.01

PECO -

Electric Residential Rate

Increases 2010 to 2011

January 1, 2011

January 1, 2010

Total = 14.7¢

Unit Rates (¢/kWh)

Proposed Total Bill

Increase ~11 %

Total = 16.3¢

AEPS 

~0.6%

Default Service Surcharge       

Mechanism based on results of

first two procurements      ~1.2%

Transmission surcharge                           

mechanism                        ~1.3%

Energy / Capacity

Competitive Transition

Charge

Transmission

Distribution

Distribution rate case     ~8.2%

0.38

Energy Efficiency

Surcharge

Breakdown of 2010 to 2011

~11% Increase (On Total Bill)

Notes:

•

Rates effective January 1, 2010 include Act 129 Energy Efficiency surcharge of 2%.

•

A

Smart

Meter

surcharge,

which

will

likely

be

effective

3Q10,

is

expected

to

be

less

than

1%

and

is

not

expected

to

increase

until

2Q/3Q

of

2011.

As

a

result, the Smart Meter surcharge will have a minimal impact on rate increases effective January 1, 2011.

•

Low income discounted rates were subsidized in the Power Purchase Agreement (PPA) in 2010 and will be recovered through distribution rates in 2011. 

0.29

14

14

14

Exelon Generation Hedging Disclosures

(As disclosed on April 23, 2010)

Exelon Generation Hedging Disclosures

(As disclosed on April 23, 2010)

15

15

15

Important Information

The following slides are intended to provide additional information regarding the hedging

program at Exelon Generation and to serve as an aid for the purposes of modeling Exelon

Generation’s

gross

margin

(operating

revenues

less

purchased

power

and

fuel

expense).

The

information

on

the

following

slides

is

not

intended

to

represent

earnings

guidance

or

a

forecast

of future events.  In fact, many of the factors that ultimately will determine Exelon Generation’s

actual gross margin are based upon highly variable market factors outside of our control.  The

information on the following slides is as of March 31, 2010. Going forward, we plan to update

the information on a quarterly basis.

Certain information on the following slides is based upon an internal simulation model that

incorporates assumptions regarding future market conditions, including power and commodity

prices, heat rates, and demand conditions, in addition to operating performance and dispatch

characteristics of our generating fleet.  Our simulation model and the assumptions therein are

subject to change.  For example, actual market conditions and the dispatch profile of our

generation

fleet

in

future

periods

will

likely

differ

–

and

may

differ

significantly

–

from

the

assumptions underlying the simulation results included in the slides.  In addition, the forward-

looking

information

included

in

the

following

slides

will

likely

change

over

time

due

to

continued refinement of our simulation model and changes in our views on future market

conditions.

16

Portfolio Management Objective

Align Hedging Activities with Financial Commitments

•

Power Team utilizes several product

types and channels to market

•

Wholesale and retail sales

•

Block products

•

Load-following products

and load auctions

•

Put/call options

•

Exelon’s hedging program is designed to

protect the long-term value of our

generating fleet and maintain an

investment-grade balance sheet

•

Hedge enough commodity risk to meet future cash

requirements if prices drop

•

Consider:  financing policy (credit rating objectives,

capital structure, liquidity); spending (capital and

O&M); shareholder value return policy

•

Consider market, credit, operational risk

•

Approach to managing volatility

•

Increase hedging as delivery approaches

•

Have enough supply to meet peak load

•

Purchase fossil fuels as power is sold

•

Choose hedging products based on generation

portfolio –

sell what we own

•

Heat rate options

•

Fuel products

•

Capacity

•

Renewable credits

% Hedged

High End of Profit

Low End of Profit

Open Generation

with LT Contracts

Portfolio

Optimization

Portfolio

Management

Portfolio Management Over Time

17

17

17

17

Percentage of Expected

Generation Hedged

•

How many equivalent MW have been

hedged at forward market prices;  all hedge

products used are converted to an

equivalent average MW volume

•

Takes ALL

hedges into account whether

they are power sales or financial products

Equivalent MWs Sold

Expected Generation

=

•

Our normal practice is to hedge commodity risk on a ratable basis

over the three years leading to the spot market

•

Carry operational length into spot market to manage forced outage and load-following

risks

•

By

using

the

appropriate

product

mix,

expected

generation

hedged

approaches

the

mid-90s percentile as the delivery period approaches

•

Participation in larger procurement events, such as utility auctions, and some flexibility

in the timing of hedging may mean the hedge program is not strictly ratable from

quarter to quarter

Exelon Generation Hedging Program

18

18

18

18

2010

2011

2012

Estimated

Open

Gross

Margin

($

millions)

(1,2)

$5,050

$4,900

$4,750

Open gross margin assumes all expected generation is

sold at the Reference Prices listed below

Reference Prices

(1)

Henry Hub Natural Gas ($/MMBtu)

NI-Hub ATC Energy Price ($/MWh)

PJM-W ATC Energy Price ($/MWh)    

ERCOT

North

ATC

Spark

Spread

($/MWh)

(3)

$4.48

$29.73

$39.69

$0.43

$5.34

$30.71

$42.04

$(0.42)

$5.79

$32.19

$43.47

$0.14

(1)

Based on March 31, 2010 market conditions. 

(2)

Gross margin is defined as operating revenues less fuel expense and purchased power expense, excluding the impact of decommissioning and other incidental revenues. Open

gross margin is estimated based upon an internal model that is developed by dispatching our expected generation to current market power and fossil fuel prices.  Open gross margin

assumes

there

is

no

hedging

in

place

other

than

fixed

assumptions

for

capacity

cleared

in

the

RPM

auctions

and

uranium

costs

for nuclear

power

plants.

Open

gross

margin

contains assumptions for other gross margin line items such as various ISO bill and ancillary revenues and costs and PPA capacity revenues and payments.  The estimation of open

gross margin incorporates management discretion and modeling assumptions that are subject to change.

(3)

ERCOT North ATC spark spread using Houston Ship Channel Gas, 7,200 heat rate, $2.50 variable O&M.

Exelon Generation Open Gross Margin and

Reference Prices

19

19

19

19

(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

10

refueling

outages

in

2010

and

11

refueling

outages

in

2011

and

2012

at

Exelon-operated

nuclear

plants

and

Salem.

Expected

generation

assumes

capacity factors

of 93.5%, 92.8% and 92.8% in 2010, 2011 and 2012 at Exelon-operated nuclear plants. These estimates of expected generation in 2011 and 2012 do not represent guidance or a forecast

of future results as Exelon has not completed its planning or optimization processes for those years.

(2)

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

options, and swaps.  Uses expected value on options. Reflects decision to permanently retire Cromby Station and Eddystone Units 1&2 as of May 31, 2011. 

(3)

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.

2010

2011

2012

Expected Generation

(GWh)

(1)

164,600

161,700

161,200

Midwest

98,600

98,100

97,000

Mid-Atlantic

58,000

56,600

56,600

South

8,000

7,000

7,600

Percentage of Expected Generation Hedged

(2)

95-98%

79-82%

48-51%

Midwest

92-95

79-82

52-55

Mid-Atlantic

96-99

81-84

44-47

South

97-100

68-71

41-44

Effective Realized Energy Price

($/MWh)

(3)

Midwest

$46.50

$44.50

$44.50

Mid-Atlantic

$36.00

$58.00

$51.50

ERCOT North ATC Spark Spread

$0.50

$0.50

$(6.50)

Generation Profile

20

20

20

20

Gross Margin Sensitivities with Existing Hedges ($ millions)

(1)

Henry Hub Natural Gas

+ $1/MMBtu

-

$1/MMBtu

NI-Hub ATC Energy Price

+$5/MWH

-$5/MWH

PJM-W ATC Energy Price

+$5/MWH

-$5/MWH

Nuclear Capacity Factor

+1% / -1%

2010

$40

$(20)

$20

$(15)

$5

$ -

+/-

$30

2011

$125

$(110)

$125

$(115)

$75

$(70)

+/-

$40

2012

$320

$(315)

$235

$(225)

$175

$(170)

+/-

$45

(1)

Based on March 31, 2010 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.

Exelon Generation Gross Margin Sensitivities

(with Existing Hedges)

21

21

21

21

95% case

5% case

$6,500

$6,200

$4,800

$7,200

$6,300

$6,600

Exelon Generation Gross Margin Upside / Risk

(with Existing Hedges)

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2010

2011

2012

(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

2011

and

2012

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,

2010.

22

22

22

22

Midwest

Mid-Atlantic

ERCOT

Step 1

Start

with

fleetwide

open

gross

margin 

$5.05 billion

Step 2

Determine the mark-to-market value

of energy hedges

98,600GWh * 93% *

($46.50/MWh-$29.73/MWh)

= $1.54 billion

58,000GWh * 97% *

($36.00/MWh-$39.69/MWh)

= $(0.21 billion)

8,000GWh * 98% *

($0.50/MWh-$0.43/MWh)

= $0.00 billion

Step 3

Estimate

hedged

gross

margin

by

adding open gross margin to mark-to-

market value of energy hedges

Open gross margin:                              $5.05 billion

MTM value of energy hedges:              $1.54 billion + $(0.21 billion) + $0.00 billion

Estimated hedged gross margin:          $6.38 billion

Illustrative Example

of Modeling Exelon Generation 2010 Gross Margin

(with Existing Hedges)

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23

Market Price Snapshot

Forward NYMEX Natural Gas

PJM-West and Ni-Hub On-Peak Forward Prices

PJM-West and Ni-Hub Wrap Forward Prices

2011

$5.44

2012  $5.92

Rolling 12 months, as of May 3, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.

Forward NYMEX Coal

2011

$69.00

2012

$77.35

2011 Ni-Hub  $40.27

2012 Ni-Hub

$42.15

2012 PJM-West  $53.89

2011 PJM-West

$51.96

2011 Ni-Hub

$24.13

2012 Ni-Hub

$25.61

2012 PJM-West

$39.12

2011 PJM-West

$38.14

24

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24

Market Price Snapshot

2012

$9.04

2011

$8.93

2011

$47.83

2012

$52.73

2011

$5.35

2012

$5.83

Houston Ship Channel Natural Gas

Forward Prices

ERCOT North On-Peak Forward Prices

ERCOT North On-Peak v. Houston Ship Channel

Implied Heat Rate

2011

$6.71

2012

$8.17

ERCOT North On Peak Spark Spread

Assumes a 7.2 Heat Rate, $1.50 O&M, and $.15 adder

Rolling 12 months, as of May 3, 2010. Source: OTC quotes and electronic trading system. Quotes are daily.