rsp05 emissions analysis results
DESCRIPTION
RSP05 Emissions Analysis Results. Scott Hodgdon PAC04 – May 4, 2005. Assumptions. Most assumptions used in the analysis have been presented in PAC01, PAC02, and PAC03. Additional assumptions, specific to the IREMM model, are presented here. IREMM Specific Assumptions. Fuel costs - PowerPoint PPT PresentationTRANSCRIPT
RSP05 Emissions Analysis Results
Scott Hodgdon
PAC04 – May 4, 2005
PAC04 05.04.2005 2
Assumptions
• Most assumptions used in the analysis have been presented in PAC01, PAC02, and PAC03.
• Additional assumptions, specific to the IREMM model, are presented here.
PAC04 05.04.2005 3
IREMM Specific Assumptions
• Fuel costs
• Interchange with surrounding Control Areas
• Transmission interface limit assumptions
PAC04 05.04.2005 4
Fuel Price Forecast• Fuel price forecast based on Energy
Information Administration’s forecast
• March 2005 Short Term Energy Outlook (STEO) for 2005 & 2006– “Reference Case” forecast was used
• Dec 2004 Annual Energy Outlook (AEO) for 2008 through 2014
• Fuel price in 2007 is the average of 2006 from STEO and 2008 from AEO
PAC04 05.04.2005 5
Fuel Price Forecast (RSP05)
0.00
2.00
4.00
6.00
8.00
10.00
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Fu
el P
rice
($/
MB
tu)
Distillate Fuel (FO2) Residual Fuel (FO6) Natural Gas Coal
PAC04 05.04.2005 6
Fuel Price ComparisonRSP05 Forecast - RTEP04 Forecast
-0.50
0.00
0.50
1.00
1.50
2.00
2.50
3.00
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Years
Pri
ce
Dif
fere
nc
e (
$/M
Btu
)
Distillate Fuel (FO2) Residual Fuel (FO6) Natural Gas Coal
PAC04 05.04.2005 7
Interchange Assumptions for IREMM
• NY - VT– 85 MW import –NYPA contract (All hours)
• NB - BHE– 200 MW fixed import (All hours)
– 500 MW (800 MW after 2007) import modeled as a gas fired combined cycle unit (Dispatchable based on price)
• Cross Sound Cable - CT– 300 MW load in CT Sub-area (All hours)
PAC04 05.04.2005 8
Interchange Assumptions for IREMM
• HQ Phase II – CMA/NEMA– 300 MW fixed import (All hours)– 500 MW import modeled as a gas fired combined cycle
unit (Dispatchable based on price)– 500 MW import modeled as a gas fired steam unit
(Dispatchable based on price)– 200 MW import modeled as a distillate GT
(Dispatchable based on price)
• HighGate - VT– 210 MW fixed import (All hours)
PAC04 05.04.2005 9
NB
NH
BHEMES-ME
BOSTON
RI SEMACT
SWCTNOR
CMA/NEMA
W-MA
VT
NY
East - WestEast - West
Orrington SouthOrrington South
SurowiecSurowiec South SouthME - NHME - NH
North - SouthNorth - South
BostonBoston
SEMA/RISEMA/RISEMASEMA
NY - NENY - NE
South WestSouth WestCTCT
ConnecticutConnecticut
Norwalk - StamfordNorwalk - Stamford
NB - NENB - NEHQ
PAC04 05.04.2005 10
Transmission Interface Transfer Limit Assumptions (Static Limits Used for Modeling)
Interfaces Interface Limit Assumptions (MW)
New Brunswick ‑ New England
7002007: 1,000
Maine ‑ New Hampshire 1,4002007: 1,500
Orrington South Export 1,0502007: 1,200
Surowiec South 1,150
2007: 1,250
North ‑ South 2,700
HQ‑NE (Highgate) 210
HQ‑NE (Phase II) 1,500
Boston Import 3,6002006: 4,500
PAC04 05.04.2005 11
Transmission Interface Transfer Limit Assumptions (Static Limits Used for Modeling)
Interfaces Interface Limit Assumptions (MW)
SE Mass Export No limit
(A) SE Mass / RI Export(B) East – West
(C) Connecticut Import
(A) 3,000 (B) 2,400(C) 2,200
Connecticut Export 2,030
Southwestern Connecticut Import
2,0002007: 2,5752010: 3,400
Norwalk/Stamford 1,1002007: 1,3002010: 1,650
New York – New England (w/o Cross Sound Cable)
Summer – 1,225/925Winter – 1,475/1,475
Cross Sound Cable 330 NENY/300 NYNE
Basecase Annual Air Emissions
PAC04 05.04.2005 13
Calculated Annual SO2 Totals (kTons)
0
20
40
60
80
100
120
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Year
SO
2 (
kTo
ns)
Decreases in 2007 & 2009 due to state (MA) regulation assumptions.
PAC04 05.04.2005 14
Calculated Annual NOX Totals (kTons)
0
5
10
15
20
25
30
35
40
45
50
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Year
NO
X (
kTo
ns)
Decreases in 2007 due to state (MA) regulation assumptions.
PAC04 05.04.2005 15
Calculated Annual CO2 Totals (kTons)
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Year
CO
2 (k
To
ns) No regulations assumed to affect
generator CO2 emission rates therefore total CO2 emissions increasing
with load growth.
PAC04 05.04.2005 16
Modeled Capacity Factors
Annual Capacity Factor By YearUnit Type BIO CC-DUAL CC-GAS F-COAL F-DUAL F-OIL GT Hydro IC Nuclear
2005 89.0% 40.4% 62.7% 78.0% 7.9% 6.3% 8.6% 32.2% 0.0% 92.6%2006 89.0% 41.3% 61.7% 78.1% 12.5% 10.1% 8.6% 32.2% 0.1% 92.6%2007 89.1% 43.1% 63.4% 78.2% 14.5% 7.9% 8.6% 32.2% 0.1% 92.6%2008 89.3% 44.6% 64.6% 78.3% 16.3% 9.4% 8.6% 32.2% 0.1% 92.6%2009 89.3% 46.2% 64.8% 78.4% 17.2% 10.4% 8.6% 32.2% 0.1% 92.6%2010 88.9% 47.9% 66.3% 78.6% 17.2% 10.7% 8.7% 32.2% 0.1% 92.6%2011 88.9% 49.6% 67.9% 78.8% 18.1% 10.5% 8.7% 32.2% 0.1% 92.6%2012 89.1% 52.0% 69.1% 78.8% 19.1% 11.3% 8.7% 32.2% 0.1% 92.6%2013 89.1% 52.4% 69.7% 79.0% 20.5% 12.2% 8.7% 32.2% 0.2% 92.6%2014 89.1% 53.6% 69.7% 79.2% 22.2% 13.8% 8.8% 32.2% 0.2% 92.6%
2006 Air Emissions and Changes in Price of Natural Gas
PAC04 05.04.2005 18
2006 SO2 Totals (kTons)
-
50
100
150
200
250
300
50% /(2.27)
65% /(1.30)
80% /(0.34)
95% / 0.63 100% /0.95
110% /1.59
125% /2.56
140% /3.52
155% /4.49
170% /5.45
185% /6.42
200% /7.38
Percent of Base NG Price / NG price difference from FO6 ($)
SO
2 (
kTo
ns)
As shown in RTEP04, increases in cost of natural gas will change the dispatch of the system such that total emissions will increase while decreases in the cost of
natural gas will cause lower emissions. Results of this analysis show that, under the specified assumptions, generator emissions will saturate
at 155% and 80% of the base price of natural gas (all else remaining constant).
PAC04 05.04.2005 19
2006 NOX Totals (kTons)
-
10
20
30
40
50
60
70
80
90
50% /(2.27)
65% /(1.30)
80% /(0.34)
95% / 0.63 100% /0.95
110% /1.59
125% /2.56
140% /3.52
155% /4.49
170% /5.45
185% /6.42
200% /7.38
Percent of Base NG Price / NG price difference from FO6
NO
X (
kTo
ns)
As shown in RTEP04, increases in cost of natural gas will change the dispatch of the system such that total emissions will increase while decreases in the cost of
natural gas will cause lower emissions. Results of this analysis show that, under the specified assumptions, generator emissions will saturate
at 155% and 80% of the base price of natural gas (all else remaining constant).
PAC04 05.04.2005 20
2006 CO2 Totals (kTons)
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
50% /(2.27)
65% /(1.30)
80% /(0.34)
95% /0.63
100% /0.95
110% /1.59
125% /2.56
140% /3.52
155% /4.49
170% /5.45
185% /6.42
200% /7.38
Percent of Base NG Price / NG price difference from FO6
CO
2 (
kTo
ns)
As shown in RTEP04, increases in cost of natural gas will change the dispatch of the system such that total emissions will increase while decreases in the cost of
natural gas will cause lower emissions. Results of this analysis show that, under the specified assumptions, generator emissions will saturate
at 155% and 80% of the base price of natural gas (all else remaining constant).
2006 Air Emissions and Changes CMA/NEMA Load
PAC04 05.04.2005 22
2006 New England SO2 Totals (kTons)
109
110
111
112
113
114
115
116
-500 -400 -300 -200 -100 0 100 200 300 400 500 600 700 800 900 1000
Change in Hourly Load
New
En
gla
nd
Ag
gre
gat
e S
O2 (
kTo
ns)
Changes in the hourly load shape have a direct effect on the total New England aggregate emissions.
PAC04 05.04.2005 23
2006 New England NOX Totals (kTons)
43
43
44
44
45
45
46
-500 -400 -300 -200 -100 0 100 200 300 400 500 600 700 800 900 1000
Change in Hourly Load
New
En
gla
nd
Ag
gre
gat
e N
OX (
kTo
ns)
Changes in the hourly load shape have a direct effect on the total New England aggregate emissions.
PAC04 05.04.2005 24
2006 New England CO2 Totals (kTons)
55,000
56,000
57,000
58,000
59,000
60,000
61,000
62,000
63,000
-500 -400 -300 -200 -100 0 100 200 300 400 500 600 700 800 900 1000
Change in Hourly Load
New
En
gla
nd
Ag
gre
gat
e C
O2
(kT
on
s)
Changes in the hourly load shape have a direct effect on the total New England aggregate emissions.
2006 Decreases in CMA/NEMA Load Due to DG/Renewables
PAC04 05.04.2005 26
DG Emission Rate
• As covered in PAC03 presentation, the following emission rates were used in the emission calculations.
Emission Rate (Lbs/MWh)
Type SO2 Rate NOX Rate CO2 Rate Uncontrolled Microturbines 0.008 0.44 1,600Solid Oxide Fuel Cell 0.005 0.01 950Phosphoric Acid Fuel Cell 0.006 0.03 1,080Uncontrolled Diesel Engine 0.454 21.8 1,430Uncontrolled Gas-Fired Lean Burn IC Engine 0.006 2.2 1,110Load Reduction/Renewable Resource 0 0 0
PAC04 05.04.2005 27
Aggregate SO2 After Altering Loads in CMA Sub-area and Assuming Various Distributed
Generation Scenarios - 2006
111.0
111.2
111.4
111.6
111.8
112.0
112.2
112.4
112.6
112.8
0 100 200 300 400 500
Load Decrease Due to DG Assumption (MW)
Ag
gre
gat
e S
O2 (
Kto
ns)
Uncontrolled Microturbines Solid Oxide Fuel Cell Phosphoric Acid Fuel Cell
Uncontrolled Diesel Engine Uncontrolled Gas-Fired Lean Burn IC Engine Load Reduction/Renewable Resource
Assuming that a load reduction was achieved using one of the listed DG options, New England aggregate SO2 emissions
could be decreased from or equal to (Uncontrolled Diesel Engine) those produced without a reduction in New England load.
PAC04 05.04.2005 28
Aggregate NOX After Altering Loads in CMA Sub-area and Assuming Various Distributed
Generation Scenarios - 2006
-
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
0 100 200 300 400 500
Load Decrease Due to DG Assumption (MW)
Ag
gre
gat
e N
OX (
Kto
ns)
Uncontrolled Diesel Engine Uncontrolled Gas-Fired Lean Burn IC Engine
Assuming that a load reduction was achieved using one of the listed DG options, New England aggregate NOX emissions
would increase from the case without a reduction in New England load.
PAC04 05.04.2005 29
Aggregate NOX After Altering Loads in CMA Sub-area and Assuming Various Distributed
Generation Scenarios - 2006
43.0
43.2
43.4
43.6
43.8
44.0
44.2
44.4
44.6
44.8
0 100 200 300 400 500
Load Decrease Due to DG Assumption (MW)
Ag
gre
gat
e N
OX (
Kto
ns)
Uncontrolled Microturbines Solid Oxide Fuel Cell Phosphoric Acid Fuel Cell Load Reduction/Renewable Resource
Assuming that a load reduction was achieved using one of the listed DG options, New England aggregate NOX emissions would
slightly increase (Uncontrolled Microturbines) or decrease (other listed options) from the case without a reduction in New England load.
PAC04 05.04.2005 30
Aggregate CO2 After Altering Loads in CMA Sub-area and Assuming Various Distributed
Generation Scenarios - 2006
55,000
56,000
57,000
58,000
59,000
60,000
61,000
62,000
0 100 200 300 400 500
Load Decrease Due to DG Assumption (MW)
Ag
gre
gat
e C
O2 (
Kto
ns)
Uncontrolled Microturbines Solid Oxide Fuel Cell Phosphoric Acid Fuel Cell
Uncontrolled Diesel Engine Uncontrolled Gas-Fired Lean Burn IC Engine Load Reduction/Renewable Resource
Assuming that a load reduction was achieved using one of the listed DG options, New England aggregate CO2 emissions would increase from the case without a reduction in New England load. If the load reduction was achieved with renewable resources or demand side management, the total CO2 emissions
would decrease.