1. A History of Power Plant Controls in Maryland What Did We Learn
A History of Power Plant Controls in Maryland What Did We Learn? – Where do We go Next?
Part 3 – SO2 Issues

2. Healthy Air Act SO2 Caps
Healthy Air Act caps reduced annual SO2 emissions

3. Issues With SO2 Emissions
The Healthy Air Act’s annual caps – and company-wide averaging concepts - worked extremely well to cost-effectively reduce annual SO2 emissions
These reductions have helped Maryland come into attainment for the fine particulate standard and meet the Regional Haze requirements of the Clean Air Act
The new 1-hour SO2 standard demands an entirely different regulatory scheme
1-hour emission limits instead of an annual cap
Unit-by-unit controls instead of company-wide averaging
Units that under-controlled as part of a company- wide averaging plan are struggling to meet the limits needed because of the new standard
Short-term periods where the scrubbers are not being used (for example during boiler emergencies and CEM QA) are also a problem

4. Very Old Short-Term Emission Limits
The HAA used annual caps to drive very significant annual emission reductions
The short-term limits for SO2 in Maryland regulations date back to the 1990s
They are clearly not appropriate for the new 1-hour SO2 standard
All short-term limits for all units will need to be updated

5. Capacity Factor Trends
Over the past 5 years
we’ve seen a dramatic drop in
how often Maryland coal plants
are called upon to generate
energy

6. Raven Power Brandon Shores - Units 1 and 2
Wagner Power Station
Raven Power
Brandon Shores - Units 1 and 2
Wagner – Units 1, 2, 3 and 4
C.P. Crane – Units 1 and 2

7. 2013-On Annual SO2 Limit, Tons
Raven System Wide Compliance with MD HAA
HAA set annual and ozone season caps and allowed “system-wide” averaging With tougher ozone standard and focus on “peak days” – units that “under-controlled” are now being re-evaluated
This numbers shows Annual tons well below annual limits
Brandon Shores
Unit 1
Unit 2
Crane
Wagner
Unit 3
Total
2012 Annual SO2 Tons
1,547
1,301
1,212
961
2,513
4,960
12,494
Annual SO2 Limit, Tons
7,041
7,347
2,000
2,149
1,618
3,252
23,407
2013-On Annual SO2 Limit, Tons
5,392
5,627
1,532
1,646
1,239
2,490
17,926
Units with red font use credits from units in black font to meet annual HAA Limit

8. Raven Power – Brandon Shores
Built in 1984
Boiler type
Units 1 & 2 are both walled fired coal units manufactured by Babcock & Wilcox
Installed two scrubbers (Fluidized Gas Desulfurization/FGD) in 2010 (about $875 million)
Total capacity = 1,400 MW
Raven Power – Brandon Shores
Unit
Capacity
(MW)
SOx Controls
Brandon 1
(Coal)
700
FGD
Brandon 2

9. Brandon Shores – Capacity Factors

10. Brandon Shores - Unit 1
Very low rates consistent with FGD control efficiency
MDE Current Thinking: Allowable rate of to 500 lb/hr

11. Brandon Shores - Unit 2
Very low rates consistent with FGD control efficiency
MDE Current Thinking: Allowable rate of to 500 lb/hr

12. Wagner Power Station Built in 1959 - 1972 Boiler types
Units 2 & 3 are both wall fired coal units manufactured by Babcock & Wilcox
Units 1 & 4 are both gas and oil wall fired units manufactured by Babcock & Wilcox
No add-on control technology. Coal fired units at times have used lower sulfur coal as a control strategy
Total Coal capacity = 495 MW
Unit
Capacity
(MW)
SOx Controls
Wagner 2
(Coal)
136
None
Wagner 3
359

13. Wagner – Capacity Factors

14. MDE Current Thinking: Allowable rate of 500 to 1000 lb/hr
Wagner - Unit 2
Can see considerable variability in rates resulting from load and coal sulfur content
MDE Current Thinking: Allowable rate of to 1000 lb/hr

15. Wagner – Unit 3
Lack of emission controls and the use of coal with higher sulfur content result in the highest SO2 rates in Maryland and some of the highest in the eastern United States
MDE Current Thinking: Lower end of current emissions still too high. Allowable rate appears to be in the 500 to 1000 lb/hr range

16. C.P. Crane Built in 1963 Boiler types
Units 1 & 2 are both coal fired cyclone units manufactured by Babcock and Wilcox
No add-on control technology. Uses Powder River Basin (PRB) low sulfur coal as a control strategy
Total capacity = 400 MW
Unit
Capacity
(MW)
SOx Controls
CP Crane 1
(Coal)
200
PRB Coal
CP Crane 2

17. Capacity Factors at Crane
Dramatic reductions since 2001 to 2007 timeframe
Units are simply not being called upon to run as much as they used to be called upon

18. MDE Current Thinking: Allowable rate of 700 to 800 lb/hr
Crane - Units 1 & 2
Can also see that there are routine emission spikes. Controlling these spikes is critical for complying with a 1-hour standard
Clearly can see that lower rates can be achieved with low sulfur coal and careful attention to coal blending activities
MDE Current Thinking: Allowable rate of to 800 lb/hr

19. Proposed SO2 Limits (1 hr avg)
Raven Power – Current MDE Thinking
Coal Fired Units
Old SO2 Limit (as lb/hr)
Proposed SO2 Limits (1 hr avg)
Brandon Unit 1
(Scrubber)
1.2 lbs/mmBtu
(~ 9,600 lbs/hr)
300 to 500 lb/hr SO2
Brandon Unit 2
Wagner Unit 2
(None)
1 wt% Sulfur Coal
(~3,355 lbs/hr)
500 to 1000 lb/hr SO2
Wagner Unit 3
(~4,567 lbs/hr)
Crane Unit 1
(Use of PRB Coal)
3.5 lbs/mmBtu (24-hr Average)
(~ 8,750 lbs/hr)
700 to 800 lb/hr SO2
Crane Unit 2

20. Preliminary SO2 Modeling - Raven
MDE and DNR have performed preliminary modeling for the coal fired units in the Raven Power system
Sierra Club has also performed modeling of the Ravens units
More refined modeling is underway
Preliminary modeling indicates that MDE’s current thinking on short- term limits for the Raven coal fired units will model attainment for the 1-hour SO2 standard

21. NRG Energy Inc. Morgantown - Units 1 and 2
Dickerson
Chalk Point
NRG Energy Inc.
Morgantown - Units 1 and 2
Dickerson – Units 1, 2 and 3
Chalk Point – Units 1 and 2

22. 2013-On Annual SO2 Limit, Tons
NRG System Wide Compliance with MD HAA
Each unit, individually, was well under the unit-specific HAA cap for that unit
HAA set annual and ozone season caps and allowed “system-wide” averaging NRG added scubbers at all three of their plants. Because of this
The NRG units all contributed proportionally to system-wide
compliance. There are no units that “under-controlled.
This numbers shows annual tons well below annual limits
Morgantown Unit 1
Morgantown Unit 2
Chalk Pt
Unit 1
Unit 2
Dickerson
Unit 3
Total
2012 Annual SO2 Tons
1,231
1,698
2,470
2,176
275
245
297
8,395
Annual SO2 Limit, Tons
6,108
6,066
3,403
3,568
1,616
1,770
1,678
24,209
2013-On Annual SO2 Limit, Tons
4,678
4,646
2,606
2,733
1,238
1,355
1,385
18,641

23. NRG – Morgantown Built in 1967 Boiler types
Units 1 & 2 are both tangential fired coal units manufactured by Alstom
Installed two scrubbers (FGD) in for approximately $715 million
Total capacity = 1,280 MW coal
Unit
Capacity
(MW)
SO2 Controls
Morgantown 1 (coal)
640
FGD
Morgantown 2 (coal)

24. Morgantown – Capacity Factors

25. Morgantown – Unit 1
During routine operation, emissions are controlled with an FGD and vent to a shorter “FGD” stack. During upset situations, emissions vent to a much taller “bypass” stack
Much higher rates during bypass stack operation
Very low rates consistent with FGD control efficiency
MDE Current Thinking: Allowable FGD rate of 700 to 800 lb/hr

26. Morgantown – Unit 2
During routine operation, emissions are controlled with an FGD and vent to a shorter “FGD” stack. During upset situations, emissions vent to a much taller “bypass” stack
Much higher rates during bypass stack operation
Very low rates consistent with FGD control efficiency
MDE Current Thinking: Allowable FGD rate of 700 to 800 lb/hr

27. Both Units 1 & 2 vent through a common FGD and a common 400 ft stack
NRG – Chalk Point
Built in 1964 & 1965
Boiler types
Units 1 & 2 are both wall fired coal units manufactured by Babcock and Wilcox
Installed scrubber (FGD) in for approximately $475 million
Total capacity = 710 MW coal
Unit
Capacity
(MW)
SO2 Controls
Both Units 1 & 2 vent through a common FGD and a common 400 ft stack
710
FGD

28. Chalk Point – Capacity Factors

29. Chalk Point Units 1 & 2
Both units vent to a common stack. During routine operation, emissions are controlled with an FGD and vent to a shorter “FGD” stack. During upset situations, emissions vent to a much taller “bypass” stack
Much higher rates during bypass stack operations
MDE Current Thinking: Allowable FGD rate of 700 to 1000 lb/hr
Very low rates consistent with FGD control efficiency

30. NRG - Dickerson Built in 1957, 1957, & 1960 Boiler types
Units 1, 2, & 3 are all tangential fired coal units manufactured by Combustion Engineering, Inc.
Installed scrubber (FGD) in 2009 for approximately $475 million
Total capacity = 573 MW coal
Unit
Capacity
(MW)
SO2 Controls
All three Units 1, 2 & 3 vent through a common FGD and a common 400 ft stack
570
FGD

31. Dickerson – Capacity Factors

32. Dickerson – Unit 1, 2 and 3
All three units vent to a common stack. During routine operation, emissions are controlled with an FGD and vent to a shorter “FGD” stack. During upset situations, emissions vent to a much taller “bypass” stack
Much higher rates during bypass stack operations
Very low rates consistent with FGD control efficiency
MDE Current Thinking: Allowable FGD rate of 700 to 1000 lb/hr

33. (Scrubber, Common Stack)
NRG– Current MDE Thinking
Short-Term SO2 Limits
Coal Fired Units
Old SO2 Limit (as lb/hr)
Proposed SO2 Limits
(1 hr Avg)
Chalk Point Unit 1&2
(Scrubber, Common Stack)
1% Sulfur Coal
(~ 10,433 lbs/hr)
700 to 1000 lb/hr
Morgantown Unit 1
(Scrubber)
3.5 lbs/mmBtu
(~ 22,628 lbs/hr)
700 to 800 lb/hr
Morgantown Unit 2
Dickerson Unit 1, 2, & 3
2.8 lbs/mmBtu
(~ 13,826 lbs/hr)

34. Preliminary SO2 Modeling - NRG
MDE and DNR are in the process of performing preliminary modeling for the coal-fired units in the NRG system
Sierra Club has also performed modeling of the NRG units
Preliminary information indicates that MDE’s current thinking on short- term limits for the NRG coal-fired units will model attainment for the 1- hour SO2 standard when the FGDs are running
MDE continues to analyze the NRG SO2 emissions that occur during bypass stack operation when emissions are vented through the taller stacks uncontrolled

35. AES Warrior Run Built in 1999 Boiler type
Coal-fired atmospheric circulating fluidized bed unit, manufactured by ABB
No add-on control technology. Uses fluidized bed technology as a SO2 control strategy
Total capacity = 205 MW coal
Unit
Capacity
(MW)
SO2 Controls
Fluidized Bed Boiler
180
Fluidized bed

36. AES Warrior Run
MDE Current Thinking: No modeling has been completed for Warrior Run. Allowable rate being analyzed
Low rates consistent with inherently clean design of fluidized bed boilers

37. Next Steps – SO2 Significant additional modeling is underway
Continue to analyze options for emission reductions at Crane and Wager 3
Continue to work with EPA on the “Bypass Stack” issues at all three NRG Plants
Additional modeling of by-pass stack issues is underway
Continue to work on start-up/shut-down issues
Continue to work with EPA and other states on the form of the short-term limits needed for the new SO2 standard
Lb/hr or lb/mmBtu with a short-term average
Continue to work with stakeholders on proposed limits
Continue to work with EPA on “early action” provisions of EPA’s draft guidance
Suggest that early December or January meeting focus solely on short-term SO2 limits