considerations in setting a regional co2 cap mark s. brownstein director, enterprise strategy rggi...
TRANSCRIPT
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.