Considerations in Setting a Regional CO2 Cap Mark S. Brownstein Director, Enterprise Strategy RGGI Workshop New York, New York. November 30, 2004.

Considerations in Setting a Regional CO2 Cap

Mark S. BrownsteinDirector, Enterprise Strategy

RGGI WorkshopNew York, New York.November 30, 2004

2

Considerations in Setting a Regional CO2 Cap

Effect on Fuel Diversity: The Northeastern Coal Question

The Effect of Environmental Adders and Natural Gas Price on The Competitiveness of Coal

An Unequal Playing Field: The Effect of An Expanded PJM on the Competitiveness of Coal

Why Functioning Capacity Markets Matter

Allowance Allocation: Equity Matters

Timing: The Case for Sufficient Lead Time

3

The Dispatch CurveVariable Cost = Clearing Price = Energy Revenue

In PJM, the last unit running sets the market clearing price for all other units running at that time. Load-following coal or combined-cycle natural gas units typically set the market clearing price, with gas setting the market clearing price approximately 50% of the time, with coal setting the market clearing price the remainder of the time.

Fossil Steam

$75 +Combustion Turbine

$50 - $70

Baseload Coal

$12 - $15Nuclear $8 - $12

Load Following Coal

$15 - $30

CCGT $30 - $50

0

20

40

60

80

100

120

MW

$ /

MW

h

Dispatch Curve 101

1. Your place in the dispatch curve is typically determined by your variable cost.

2. Fuel = 75% of your variable cost.

3. Therefore, fuel cost is a good proxy for your place in the dispatch curve – aka your “dispatch cost.”

Illustrative Dispatch Curve

4

Today’s gas price

Load-Following Coal v. CC Natural Gas in PJMToday

2004 ASSUMPTIONS NAPP CAPP

COAL SPECS (Btu/lb,%S) 13,869,2.1%S 12,942, 0.9%S

HEAT RATE (Btu/kWh) 10,200 10,100

COAL Transportation $15/TON $20/TON

SCR OR Scrubber? NO NO

SO2 Emissions (lb/MMBtu) 2.50 1.30

SO2 COSTS ($/Ton) $500 $500

NOX Emissions (lb/MMBtu) 0.26 0.5

NOX COSTS ($/Ton) $2,300 $2,300

Load-following coal beats combined-cycle natural gas units absent a significant and sustained drop in natural gas price, even in spite of a recent spike in coal prices and emission allowance costs.

$3.92

$5.53

7,338 Btu/kWh CCGT with

burner tip gas prices at:

$7.50

5.53 7.86

5.537.86

4.705.85

4.705.85

5.913.31

5.913.31

23.5721.3811.7911.06

$28.80

$40.58

$55.04

$0

$10

$20

$30

$40

$50

$60

NAPP Contract$30/ton

CAPP Contract$30/ton

NAPP Spot $58/ton CAPP Spot $60/ton

DIS

PA

TC

H C

OS

T (

$/M

WH

)

Coal Price per MWh Transportation per MWh

NOx per MWh SOx per MWh

5

$5.52

$7.80$3.98

$7.58$8.93

$4.60

$21.79$15.89

$11.20$15.48

$1.08

$1.35

$0

$10

$20

$30

$40

$50

$60

NAPP 2008 $30/ton CAPP 2008 $40/ton

DIS

PA

TC

H C

OS

T (

$/M

WH

)

Coal Price per MWh Transportation per MWh NOx per MWh

SOx per MWh Hg per MWh CO2 per MWh

7,338 Btu/kWh CCGT with burner tip gas price at:

Rising environmental compliance costs continue to push load-following coal to the margin, with the future price of natural gas and cost of CO2 compliance emerging as the two wildcards in the viability of load-following coal capacity in the RGGI region.

2008 ASSUMPTIONS NAPP CAPP

COAL SPECS (Btu/lb,%S) 13,869,2.1%S 12,942, 0.9%S

HEAT RATE (Btu/kWh) 10,200 10,100

COAL Transportation $15/TON $20./TON

SCR OR Scrubber? NO NO

SO2 Emissions (lb/MMBtu) 2.50 1.30

SO2 COSTS ($/Ton) $700 $700

NOX Emissions (lb/MMBtu) 0.26 0.5

NOX COSTS ($/Ton) $3,000 $3,000

Hg Emissions (lb/Tbtu) 7.54 6.13

Hg COSTS ($/LB) $35,000 $35,000

CO2 Emissions (lb/MMBtu) 205.1 205.2

CO2 COSTS ($/Ton) $14-$23 $9-$16

Load-Following Coal v. New Natural Gas in PJMTomorrow

$7.20/MMBtu

Nov-2004

2008 Gas Price$52.83

Feb-2004

2008 Gas Price$6.00/MMBtu$44.03

6

The Unlevel Playing FieldMerchant v. Regulated/Re-Regulated Generation

Total U.S. Generation Capacity:

Merchant* 43%

Utility 36%

Public 21%

60% - 80%

20% - 40%

<20%

Merchant Generation Ownership*

>80%

40% - 60% Source: PowerDat* Represents non-utility and non-public power generation ownership

National Distribution of Merchant GenerationOTC

Expanded PJM

7

“Diversified”

S&P Report 11/23/2004

Company Rating/OutlookBusiness

Profile

Keyspan Gen A/Negative 5

FPL A/Negative 8

Exelon Gen A-/Negative 8

PPL Energy BBB/Stable 8

PSEG Power BBB/Negative 8

Duke Energy Trading

BBB-/Stable 10

AES B+/Positive 9

NRG B+/Stable 9

Reliant Mid-Atl. B/Stable 8

Dynegy B/Negative 8

Calpine B/Negative 9

Edison Mission B/Negative 9

El Paso Corp. B-/Negative 8

NEGT D 10

Mirant NR/-- 10

Distribution Companies Merchant Generation

Company Rating/OutlookBusiness

Profile

NSTAR A/Stable 1

Con Edison A/Stable 2

PPL Electric A-/Negative 4

Energy East BBB+/Negative 3

PEPCO BBB+/Negative 3

CL&P BBB+/Negative 3

PSE&G BBB/Negative 3

Duquesne BBB/Negative 4

JCP&L BBB-/Stable 4

S&P Ratings CriteriaDebt, Cash Flow, and Perceived Business Risk

A trend is emerging where the bond market views competitive markets as inherently risky, rewarding rate-based generation with favorable cost of capital.

Business Profile

Lowest Risk

Highest Risk

1 10

S&P Rating

bps Spread from BBB

AAA 420

AA 350

A 280

BBB 0

BB -490

B -1910

CCC -4500

Company Rating/OutlookBusiness

Profile

Keyspan A/Negative 4

Exelon A-/Negative 7

Cinergy BBB+/Stable 5

Constellation BBB+/Stable 7

Northeast Util. BBB+/Negative 5

Pepco BBB+/Negative 5

Conectiv BBB+/Negative 5

Dominion BBB+/Negative 7

AEP BBB/Stable 6

Entergy BBB/Stable 6

Duke BBB/Stable 7

PPL BBB/Stable 7

PSEG BBB/Negative 7

First Energy BBB-/Stable 6

Edison Int’n BB+/Stable 6

Allegheny B+/Positive 7

8

Coal in RGGI v. Coal Outside RGGIThe Crux of The Leakage Concern

$250M capital investment for a 500MW plant

2008 ASSUMPTIONS NAPP CAPP

COAL SPECS (Btu/lb,%S) 13,900,2.1%S 12,900, 0.9%S

HEAT RATE (Btu/kWh) 10,600 10,500

COAL Transportation $15/TON $20/TON

SCR OR Scrubber? YES YES

SO2 Emissions (lb/MMBtu) 0.15 0.07

SO2 COSTS ($/Ton) $400 $400

NOX Emissions (lb/MMBtu) 0.06 0.06

NOX COSTS ($/Ton) $1,900 $1,900

Hg Emissions (lb/TBtu) 2.26 1.84

Hg COSTS ($/LB) $35,000 $35,000

CO2 Emissions (lb/MMBtu) 205.1 205.2

CO2 COSTS ($/Ton) $5 $5

As a consequence of easier access to capital and lack of a CO2 constraint, load-following coal units outside RGGI are set to enjoy, at a minimum, a $13 dispatch cost advantage over similar units in RGGI. Transmission capacity becomes the only limit on this advantage.

$5.72

$8.14

$3.68

$7.80

$5.18

$11.61$16.15

$11.20$15.48

$2.20

$2.20

$0.60

$0.60$3.98

$7.58

$0.32

$0.15$8.93

$4.60$0.66

$0.81

$1.35

$1.08

$5.23

$0

$10

$20

$30

$40

$50

$60

NAPP 2008$30/ton

Controlled

CAPP 2008$40/ton

Controlled

NAPP 2008$30/ton

Uncontrolled

CAPP 2008$40/ton

Uncontrolled

DIS

PA

TC

H C

OS

T (

$/M

WH

)

Coal Price per MWh Variable O&M per MWh Transportation per MWh

NOx per MWh SOx per MWh Hg per MWh

CO2 per MWh

$21.26

$41.72

$34.37$27.89

9

Production Cost v. RevenueEarning Enough to Build & Maintain Generation

0

10

20

30

40

50

60

70

New Gas CCGT New SupercriticalPulverized Coal PJMWest Delivered Coal

Existing 500 MW CoalPlant, Retrofitted PJMEast Delivered Coal

New Wind, 30%Capacity Factor

Fuel Cost Variable O&MCapital & Fixed O&M Without PTC

DIS

PA

TC

H C

OS

T (

$/M

WH

)

Energy Revenue

Capacity Revenue

Market Clearing Price

Basic Market Dynamics

Under current market conditions, energy revenues alone are rarely enough to recover the full cost of new investment making the degree of capacity payments critical to the viability of new investment.

Off Peak Market Clearing Price

Energy Revenue

10

Emission Allocation as National PrecedentSetting Rules That Work for the Region

National CO2 allocations based on an emission performance standard concept favor the

RGGI region.

0.15

0.5

0.1

0.2

0.3

0.4

0.5

0.6

3.2

9

2

4

6

8

10

158

180

50

100

150

200

821

1,322

500

1,000

1,500

1,482

1,868

500

1,000

1,500

2,000

2,500

RGGI U.S. RGGI U.S. RGGI U.S. RGGI U.S. RGGI U.S.

Total MWh(lbs/MWh)

Fossil MWh(lbs/MWh)

Heat Input(lbs/mmBtu)

Population(tons/person)

Gross Product(lbs/$)

11

NJ BGS Auction StructureFixed Price for Consumers = Margin Risk for Generators

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

BG

S L

oad

1 AuctionFor all Load

NJ Avg. Rate 5.06 c/KWh

BGS Fixed Price (34-Month)

NJ Avg. Rate 5.56 c/KWh

2002 2003 2004 2005

BGS Fixed Price

(10-Month)

NJ Avg. Rate 5.27 c/KWh

2006

Fixed Price

Contract

4.4 c/KWh

BGS Fixed Price

(12 Month)NJ Avg. Rate5.48 c/KWh

BGS Fixed Price

(36 Month)NJ Avg. Rate5.52 c/KWh

2007

HEP

NJ Avg. Rate $61.52/MW-day

BGS Fixed Price

36 Month through 8/08

BGS Fixed Price

36 Month through 8/09

HEP HEPHEP

The NJ auction accounts for approximately 21% of the total load in RGGI. It is successful in stabilizing prices for consumers, forcing wholesale generators to compete on price.

12

Case Study: PSEG PowerBGS and Long-term Contracts Through 2008

PSEG Power Term Contracts

100

90

80

70

60

50

40

30

20

10

% o

f P

ow

er

Gen

erat

ion

2003 BGS (34 Month)

United Illuminating

2003

BG

S (

10 M

on

th)

2004 BGS (36 Month)

2004 BGS (12 Month)

Other term energy contracts

Generation output not under contract

20082007200620052004

13

Key Takeaways

The Future Price of Natural Gas Matters. Rising natural gas prices improve energy margins for coal and nuclear, but also raise electricity prices for consumers. Declining natural gas prices eat into margins for nuclear and coal, potentially forcing some coal to retire.

The Price of CO2 Matters. Given current coal and natural gas price trends, a carbon cap that drives CO2 prices above $10 a ton has a high probability of forcing RGGI region coal capacity to close.

Market Rules Matter. Return on capital is a function of energy and capacity revenues. Currently, energy margins are inadequate to fully recover the cost of capital in new or modified plant, making capacity payments critical to the viability of investment in environmental retrofits and new generation.

A Level Regulatory Playing-Field Matters. Companies with the ability to recover the capital cost of emission control equipment through rates enjoy a competitive advantage over those that do not. Companies required to internalize the cost of CO2 or other environmental adders are penalized in competition with those that do not face such restrictions. This is the looming reality of an expanded PJM.

Timing Matters. In an effort to demonstrate positive and certain cash-flows, companies are entering into long-term contracts today, making future CO2 regulation a potential threat to their expected energy margin.