EXHIBIT 99.2
SUPPLEMENT TO THE
INDEPENDENT ENGINEER'S REPORT
MIRANT AMERICAS GENERATION, INC.
FACILITIES
[LOGO]
SUPPLEMENT TO THE INDEPENDENT ENGINEER'S REPORT
MIRANT AMERICAS GENERATION, INC. FACILITIES
TABLE OF CONTENTS
Page
----
MIRANT MID-ATLANTIC FACILITIES...............................................S-1
Description of the Chalk Point Facility...................................S-1
Description of the Dickerson Facility.....................................S-4
Description of the Morgantown Facility....................................S-6
Description of the Potomac River Facility.................................S-9
Description of the Other Mirant Mid-Atlantic Facilities..................S-11
Operating and Maintenance................................................S-13
Operating History........................................................S-13
Environmental Assessments................................................S-14
MIRANT CALIFORNIA FACILITIES................................................S-25
Description of the Contra Costa Facility.................................S-25
Description of the Pittsburg Facility....................................S-27
Description of the Potrero Facility......................................S-30
Operation and Maintenance................................................S-32
Operating History........................................................S-36
Environmental Assessment.................................................S-37
MIRANT NEW YORK FACILITIES..................................................S-42
Description of the Bowline Facility......................................S-42
Description of the Lovett Facility.......................................S-45
Descriptions of the NY CT Facilities.....................................S-48
Descriptions of the Hydroelectric Facilities.............................S-48
Operating History........................................................S-48
Environmental Assessment.................................................S-49
MIRANT NEW ENGLAND FACILITIES...............................................S-55
Description of the Canal Facility........................................S-55
Description of the Kendall Facility......................................S-57
Operation and Maintenance................................................S-59
Operating History........................................................S-59
Environmental Assessments................................................S-61
MIRANT TEXAS FACILITY.......................................................S-67
Description of the Bosque Facility.......................................S-67
Operation and Maintenance................................................S-68
Operating History........................................................S-69
Environmental Assessment.................................................S-69
STATE LINE FACILITY.........................................................S-71
Description of the State Line Facility...................................S-71
Operation and Maintenance................................................S-73
Operating History........................................................S-73
Environmental Assessment.................................................S-74
MIRANT WISCONSIN FACILITY...................................................S-78
Description of the Neenah Facility.......................................S-78
Operating History........................................................S-79
Environmental Assessment.................................................S-80
Copyright (C) 2001 R. W. Beck, Inc.
All Rights Reserved
S-i
[LETTERHEAD OF R.W. BECK]
April 26, 2001
Mirant Americas Generation, Inc.
1155 Perimeter Center West
Atlanta, Georgia 30338
Subject: Supplement to the Independent Engineer's Report
on the Mirant Americas Generation, Inc. Facilities
Presented herein is the Supplement to the Independent Engineer's
Report (the "Supplement") of our review and analyses of 73 generating units
owned by subsidiaries and affiliates of Mirant Americas Generation, Inc.
("Mirant Generation") and located in the states of Maryland, Virginia,
California, New York, Massachusetts, Texas, Indiana, and Wisconsin, as described
in more detail in the Report and herein (the "Mirant Generation Facilities").
All capitalized terms used herein but not defined have the same meanings given
to them in the Report.
MIRANT MID-ATLANTIC FACILITIES
Description of the Chalk Point Facility
Mechanical Equipment and Systems
Steam Generators
The Chalk Point Units 1 and 2 steam generators consist of identical
Babcock & Wilcox ("B&W") once through, double reheat, supercritical, balanced
draft, indoor units with two Ljungstrom regenerative secondary air preheaters
operating in parallel with a tubular primary air preheater. The units were
originally designed as positive draft units, but were converted to balanced
draft operation in the early 1980s. Each steam generator has a maximum
continuous capacity of 2,500,000 lb/hr of steam when operating at 3,575 psig and
1,000(degree)F superheater outlet temperature and final reheat temperatures of
1,050(degree)F and 1,000(degree)F. The steam generators are designed to fire
pulverized coal as the primary fuel and have been retrofitted to fire natural
gas as a secondary fuel. In 1994 to 1995, to control NO(X), the 24 wall-mounted
coal burners were replaced with Riley Low-NO(X) burners and a SOFA systems was
installed. Either natural gas or No. 2 distillate oil may be used for start-up
and low load flame stabilization.
The Chalk Point Units 3 and 4 steam generators consist of identical
Combustion Enginereing, Inc. ("CE") controlled circulation, reheat, subcritical,
balanced draft, indoor units with two Ljungstrom regenerative air preheaters.
Each steam generator has a maximum continuous capacity of 4,600,000 lb/hr of
steam when operating at 1,980 psig and 953(degree)F superheater outlet
temperature with a final reheat temperature of 952(degree)F. The steam
generators are designed to fire No. 6 residual oil as the primary fuel and have
been retrofitted to fire natural gas as a secondary fuel. Either natural gas or
No. 2 distillate oil may be used for start-up and low load flame stabilization.
Turbine Generators
Each Chalk Point Units 1 and 2 steam generator provides steam to a
single GE cross-compound, four flow, reheat, condensing steam turbine. Each
turbine is rated at 350,000 kilowatts ("kW") at inlet throttle conditions of
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2,289,000 lb/hr of steam flow at 3,500 psig and 1,000(degree)F with
1,050(degree)F/1,000(degree)F reheat inlet temperatures and 1.25 inches of
mercury ("inches Hg") backpressure.
Each of the Chalk Point Units 1 and 2 steam turbines drives a GE
hydrogen-cooled generator. As these are cross compound steam turbines, each unit
has two generators. Each of the four generators is a 2 pole, 3 phase, 60 cycle,
3,600 revolutions per minute ("rpm"), 20 kV unit rated at 214,000 kVA at 0.85
power factor and 30 psig hydrogen pressure. There are a total of five motor
driven exciters, one for each generator and one spare, for the two units.
Each of the Chalk Point Units 3 and 4 steam turbines also drives a
GE hydrogen and water-cooled generator. However, as these are tandem compound
steam turbines, each unit has a single generator. Each of the two generators is
a 2 pole, 3 phase, 60 cycle, 3,600 rpm, 24 kV unit rated at 732,200 kVA at 0.90
power factor and 60 psig hydrogen pressure. Each unit has its own exciter.
Combustion Turbines
The CTs 1 and 2 at the Chalk Point Facility are used for black
starting the steam units and for peaking service. Chalk Point CT 1 is an 18 MW
Pratt and Whitney FT4A-7 unit. Chalk Point CT 2 is a 30 MW Westinghouse Electric
("Westinghouse") W-251-B2 unit. Both units operate on No. 2 distillate oil and
are also used for peaking service.
Chalk Point CTs 3 through 6 are used for peaking service. Chalk
Point CTs 3 and 4 are 85 MW GE PG7111EA units, and Chalk Point CTs 5 and 6 are
107 MW Kraftwerk Union/Siemens V84.2 units. The SMECO unit is an 84 MW GE unit
that is owned by SMECO and is leased by Mirant Mid-Atlantic. All five of these
units operate on natural gas as the primary fuel and No. 2 distillate oil as a
secondary fuel. CT capacities referenced above are summer ratings.
Fuel System
Coal for Chalk Point Units 1 and 2 is delivered in unit trains to a
rail mounted traveling bucket wheel stacking/reclaiming machine. Normal coal
inventory is 30 to 35 days on site. The coal storage bunkers hold approximately
a 16-hour supply of coal at full load burn rates. An emergency reclaim system is
provided to permit fueling of the plant in the event that the stacker/reclaimer
is out of service.
No. 6 residual oil for Chalk Point Units 3 and 4 is transported to
the site via the Piney Point Pipeline. The oil is stored in three storage tanks,
with a total capacity of 234,000 barrels of No. 6 residual oil with 0.7 percent
sulfur for Chalk Point Unit 4 and 469,000 barrels of No. 6 residual oil with 1.0
percent sulfur for Chalk Point Unit 3. The oil is pumped by three fuel oil
booster pumps to the main oil burners for each of the units.
No. 2 distillate oil is used in the CTs and auxiliary boilers and as
start-up and low load flame stabilization fuel in the steam units. The oil is
delivered by truck to the Chalk Point Facility where there is a total storage
capacity of 1.774 million gallons in two interconnected tanks. In addition,
SMECO owns a 1.18 million-gallon storage tank dedicated to providing fuel solely
to the SMECO CT.
Natural gas can be burned in all the steam units and CTs except for
Chalk Point CTs 1 and 2. Natural gas is received through a 20-inch diameter,
3.5-mile long, 900 psig spur line from the Cove Point LNG, L.P. pipeline.
Washington Gas Light Company owns and operates this spur line.
Ash Systems
Boiler bottom ash and slag are collected in three water-filled,
refractory-lined ash hoppers located under each furnace. Dewatered bottom ash is
loaded into trucks for disposal.
There are three fly ash handling systems installed on each unit. The
system for removing ash from the economizer hoppers utilizes water for
transporting the ash to an outdoor dewatering bin. The other two systems are
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dry pneumatic systems which convey ash to storage silos. Ash from each silo is
loaded into trucks and hauled to Brandywine for disposal.
Water Supply
Raw cooling water for the Chalk Point Unit 1 and 2 condensers and
for makeup water to the Chalk Point Unit 3 and 4 cooling towers is obtained from
the Patuxent River.
Make-up water for the steam generators is produced from well water
from the six on-site artesian wells using pretreatment and demineralizer
systems. Demineralized water is used either directly in the plant or stored in
either of the two Chalk Point Units 1 and 2 250,000-gallon storage tanks, or the
two Chalk Point Unit 3 and 4 450,000-gallon storage tanks.
For the CTs, demineralized water is produced by truck-mounted
portable demineralizers and stored separately from the remainder of the Chalk
Point Facility.
Electrical and Control Systems
Chalk Point Units 1 and 2 each use a three-phase, forced oil, forced
air-cooled main power transformer. Both Chalk Point Unit 1 and Unit 2
transformers are rated 19.3 kV-234 kV, 400 MVA. Chalk Point Units 3 and 4 each
use a three-phase, forced oil, forced air-cooled main power transformer rated 24
kV-234 kV, 650 MVA. One spare 650 MVA main power transformer is shared with the
Morgantown Facility.
Environmental Controls and Equipment
Air Emissions
The basic strategies and air pollution control technologies employed
at the Chalk Point Facility to control air emissions include: (i) purchasing
fuels of the required sulfur content in order to control emissions of SO(2);
(ii) utilizing ESPs on Chalk Point Units 1 and 2 for particulate and opacity
control; (iii) burner modifications and tuning, SOFA systems, and gas re-burn
capability on Chalk Point Units 1 and 2 to reduce NO(X) emissions; (iv)
restoring the SOFA system on Chalk Point Unit 3 to reduce NO(X) emissions and
improved burner nozzles and fuel control systems on Chalk Point Units 3 and 4 to
reduce both NO(X) emissions and opacity; and (v) using water injection on Chalk
Point CTs 5 and 6 to reduce NO(X) emissions when firing No. 2 distillate oil.
All of the steam units are equipped with continuous emissions
monitors ("CEMs") for opacity, SO(2), NO(X), CO(2) as well as flue gas
volumetric flow as required by state and federal regulations. CO probes have
also been installed on each of the steam units.
Wastewater/Solid Waste Disposal
Solid waste at the Chalk Point Facility consists primarily of the
coal processing and combustion by-products generated by Chalk Point Units 1 and
2. Bottom ash from Chalk Point Units 1 and 2 is pumped as a water/ash mixture to
dewatering bins where the water is decanted off and recycled for use in the
bottom ash transporting system. The dewatered bottom ash is loaded into trucks
for disposal.
Fly ash from Chalk Point Units 1 and 2 is collected and transported
to ash storage silos, where it is loaded into trucks for transport to Brandywine
located approximately 16 miles from the Chalk Point Facility.
The small amounts of iron pyrites removed from the pulverizers of
Chalk Point Units 1 and 2 are stored on site in a lined storage area.
Low volume wastewaters such as coal pile runoff, demineralizer
backwash, boiler blowdown, filter backwash, intake screen backwash, sanitary
wastewater, and settling pond discharges, along with storm water run-off are
collected and treated in two settling ponds that have concrete bottoms. The
ponds are arranged in parallel fashion so that one pond is in service while
solids are being cleaned out of the other pond. The pH of the water in the ponds
is
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controlled by the addition of caustic, and the ponds discharge to the cooling
water canal that empties into the Patuxent River. A packaged sewage treatment
plant treats sanitary waste for most of the site. Oil/water separators treat the
storm water runoff from the fuel storage and handling areas.
Off-Site Requirements
Fuel Supply
Chalk Point Units 1 and 2 burn bituminous coal that is delivered by
rail from mines generally located in the northern Appalachian coal-mining
region. Coal is purchased pursuant to four coal contracts that also cover coal
supply to the Dickerson and Morgantown Facilities. These contracts are
short-term which, with certain extension options, will expire between December
31, 2000 and June 30, 2002. In addition to the contracts, coal may be purchased
on the spot market depending on quantity requirements and market conditions.
The No. 6 residual oil burned in Chalk Point Units 3 and 4 is
purchased on the spot market under short-term contracts with no minimum purchase
requirements and delivered to the Chalk Point Facility via the Piney Point
Pipeline. In addition, Mirant Mid-Atlantic leases space for 1.5 million barrels
of storage of No. 6 oil at the Piney Point Terminal. This storage can also
provide service to Morgantown Units 1 and 2 as a back-up fuel. This lease
expires June 30, 2001, with the option to extend an additional five years by
mutual agreement.
No. 2 distillate fuel oil is purchased pursuant to short-term,
renewable contracts with each of three vendors. The oil is delivered to the
Chalk Point Facility by truck from the vendors' terminals.
Natural gas is purchased in the spot market under short-term
agreements. Gas transportation to the Chalk Point Facility is through a
pipeline.
Electrical Interconnection
The Chalk Point Facility's electric output is interconnected to the
grid through the Chalk Point Facility's switchyard. The Chalk Point Facility has
two 500 kV, six 230 kV, and two 60 kV lines connected to the Chalk Point
Facility's switchyard. Chalk Point Units 1 through 4 and Chalk Point CTs 3
through 6 are connected to the Chalk Point 230 kV ring bus. Two 230 kV lines tie
into the Chalk Point 500 kV switchyard, which has one tie to Baltimore Gas and
Electric and one tie to the 500 kV transmission system owned by the
Pennsylvania-New Jersey-Maryland power pool ("PJM").
Description of the Dickerson Facility
Mechanical Equipment and Systems
Steam Generators
The Dickerson Units 1, 2 and 3 steam generators consist of identical
CE controlled circulation twin furnace units with Ljungstrom air preheaters and
tangentially-fired burners. The boilers were designed to operate at 1,300,000
lb/hr superheater steam flow at 2,486 psig. Each corner of each furnace has four
coal burners, four coal pilot oil torches, an oil gun, and an oil pilot torch.
The furnace was retrofitted in 1999 with 32 ABB-CE low-NO(X) burners. The
boilers are designed to fire pulverized coal as the primary fuel and to fire No.
2 fuel oil for start-up, flame stabilization, and as alternate fuel to replace
mill capacity when needed.
Turbine Generators
Each Dickerson Units 1, 2 and 3 steam generator provides steam to a
single GE cross-compound steam turbine. Each turbine is rated at 175,000 kW at
an inlet throttle pressure of 2,400 psig and 1,050(degree)F/1,000(degree)F
reheat and 2.0 inches Hg backpressure. Each of the Dickerson Units 1, 2 and 3
steam turbines drive a GE hydrogen-cooled generator rated at 115 MVA at 0.85
power factor and 13.8 kV.
S-4
Combustion Turbines
CT D1 at the Dickerson Facility is used for black starting the steam
units and for peaking service. Dickerson CT D1 is a 13 MW Pratt and Whitney FT4
unit installed in 1967. The unit operates on No. 2 distillate oil and is also
used for peaking service. Dickerson CTs H1 and H2 were installed for peaking
service in 1992 and 1993. Both units are 139 MW GE 7001F units. Both of these
units operate on either natural gas or No. 2 distillate oil. The CT capacities
referenced above are summer ratings.
Fuel System
Coal for Dickerson Units 1, 2 and 3 is delivered in trains by a
rotary car dumper into a double receiving hopper. There are provisions for
outdoor on-site coal storage of up to 240,000 tons. Coal yard storage coal is
reclaimed by bulldozer and delivered to three reclaim hoppers. No. 2 distillate
oil is used in the CTs and as start-up and low load flame stabilization fuel in
the steam units. The oil is delivered by truck where there is a total storage
capacity of 10.9 million gallons in two aboveground tanks. Natural gas can be
burned in all of the CTs units except for Dickerson CT D1. Natural gas is
received through a 20-inch diameter, spur line capable of supplying the
gas-burning CTs.
Ash Systems
Bottom ash from each boiler furnace is collected in two 150-ton
hydro-bins. Fly ash from each unit is collected in 10 hoppers. Fly ash is
transported from the hoppers to the primary and secondary collectors which dump
fly ash into the fly ash storage silo located in the 400-foot stacks. The fly
ash is then transported from the silo via a rotary unloading unit. The fly ash
is then placed into trucks for hauling to the ash storage site.
Water Supply
Raw cooling water for each of the steam units at the Dickerson
Facility is obtained from the Potomac River. Water for other uses within the
Dickerson Facility is obtained from a potable deep-water well.
Boiler make-up water is generated from river water using a water
pretreatment system and demineralizer. Demineralized water is either used
directly in the plant or stored in three demineralized water storage tanks.
Electrical and Control Systems
Each generator is connected through an isolated phase bus duct to a
separate main generator step-up transformer. Dickerson Units 1, 2 and 3 use a
three-phase outdoor oil-filled unit rated 13.5-234 kV, 217 MVA with forced
oil/forced air-cooling. One spare main generator step-up transformer of the same
rating, manufactured by GE, is on site and available for any of the three units.
Environmental Controls and Equipment
Air Emissions
The basic strategies and air pollution control technologies employed
at the Dickerson Facility to control air emissions include: (i) purchasing fuels
of the required sulfur content in order to control emissions of SO(2); (ii)
utilizing ESPs and wet particulate scrubbers on Dickerson Units 1, 2 and 3;
(iii) upgraded burner tips with modified air distribution system on Dickerson
Units 1, 2 and 3 to reduce NO(X) emissions; and (iv) using water injection on
Dickerson CTs H1 and H2 to reduce NO(X) emissions when firing No. 2 distillate
oil.
All of the steam units are equipped with CEMs for opacity, SO(2),
NO(X), CO(2), as well as flue gas volumetric flow as required by state and
federal regulations.
S-5
Wastewater/Solid Waste Disposal
Solid waste at the Dickerson Facility consists primarily of the coal
processing and combustion by-products generated by Dickerson Units 1, 2 and 3.
Bottom ash from each of the three steam units is collected and transported to
the bottom ash storage silo where it is loaded into trucks for disposal
off-site. Additionally, bottom ash is marketed to several local governments for
use on roads in winter.
Fly ash from each of the three steam units is collected and
transported to one of two fly ash storage silos where it is loaded into trucks
for transport to Westland. Additionally, fly ash is marketed to Genstar, a local
cement company, for mixing into concrete.
Major water treatment equipment at the Dickerson Facility includes
clarifiers, settling ponds, neutralization systems, flow equalization systems,
oil/water separators and sanitary waste treatment. With the exception of
once-through cooling water and clean stormwater, all water is treated prior to
discharge into the Potomac River or C&O Canal. Equalization tanks collect storm
runoff, coal pile runoff, plant process water, floor drain runoff, sewage
treatment runoff, and demineralizer regeneration effluent for discharge to the
industrial wastewater treatment plant. Effluent from the industrial wastewater
treatment plant goes to the plant discharge flume and into the Potomac River.
Scrubber process flows and scrubber runoff is routed to a drain tank and into a
series of cascading settling ponds. After the removal of solids, the water from
the settling ponds goes to the plant discharge flume and into the Potomac River.
Off-Site Requirements
Fuel Supply
Dickerson Units 1, 2 and 3 burn bituminous coal delivered from mines
generally located in the northern Appalachian coal-mining region. Coal is
purchased pursuant to four coal contracts that also cover coal supply to the
Chalk Point and Morgantown Facilities. These contracts are short-term which,
with certain extension options, will expire between December 31, 2000 and June
30, 2002. In addition to the contracts, coal may be purchased on the spot market
depending on quantity requirements and market conditions.
No. 2 distillate fuel oil is purchased pursuant to one-year
contracts with each of three vendors. The oil is delivered to the Dickerson
Facility by truck from the vendors' terminals.
Natural gas is purchased in the spot market under short-term (one to
three months) agreements. There are also two longer-term agreements with the
Washington Gas Light Company for gas supply and delivery. The first agreement is
a non-obligatory contract for the purchase and sale of gas under a set of
commercial parameters. The second is an interruptible transportation agreement
to the Dickerson Facility expiring January 1, 2002.
Electrical Interconnection
The Dickerson Facility's electric output is interconnected to the
grid through the Dickerson Facility's switchyard. The Dickerson Facility is
connected to Pepco's Doubs Substation via two 230 kV lines.
Description of the Morgantown Facility
Mechanical Equipment and Systems
Steam Generators
The Morgantown Units 1 and 2 steam generators consist of identical
CE once through, single reheat, supercritical, balanced draft, indoor units with
two Ljungstrom regenerative secondary air heaters. Each steam generator has a
maximum continuous capacity of 4,250,000 lb/hr of steam when operating at 3,810
psig and 1,000(degree)F superheater outlet temperature and final reheat
temperature of 1,000(degree)F. The steam generators are designed to fire
pulverized coal as the primary fuel and also have the capability to co-fire up
to 75 percent by heat input of No. 6
S-6
residual oil as a secondary fuel. In 1994 through 1995, low-NO(X) concentric
firing system ("LNCFS") Level III and SOFA systems were installed. No. 2
distillate oil is used for start-up and low load flame stabilization.
Turbine Generators
Each Morgantown Units 1 and 2 steam generator provides steam to a
single tandem-compound, four flow, reheat, condensing steam turbine. The
Morgantown Unit 1 ABB steam turbine is rated at 636,021 kW at inlet throttle
conditions of 3,500 psig and 1,000(degree)F with 1,000(degree)F reheat inlet
temperatures and 1.25 inches Hg backpressure. The Morgantown Unit 2 GE steam
turbine is rated at 551,021 kW at inlet throttle conditions of 3,500 psig and
1,000(degree)F with 1,000(degree)F reheat inlet temperatures and 1.25 inches Hg
backpressure.
The Morgantown Unit 1 steam turbine drives a Westinghouse two pole,
3 phase, 60 cycle, 3,600 rpm, 18 kV hydrogen-cooled generator rated at 695,000
kVA at 0.90 power factor and 60 psig hydrogen pressure. The Morgantown Unit 2
steam turbine drives a GE 2 pole, 3 phase, 60 cycle, 3,600 rpm, 24 kV hydrogen
and water-cooled generator rated at 695,000 kVA at 0.90 power factor and 60 psig
hydrogen pressure.
Combustion Turbines
CTs 1 and 2 at the Morgantown Facility are utilized for black
starting the steam units and for peaking service. Morgantown CTs 1 and 2 are 16
MW GE Frame 5 units installed in 1970 and 1971 to provide black start capability
for Morgantown Units 1 and 2. Both units operate on No. 2 distillate oil which
is stored in a 400,000-gallon storage tank.
In 1973, units Morgantown CTs 3 through 6 were installed for peaking
service. These four units are all 54 MW GE Frame 7 units. All of these units
operate with No. 2 distillate oil as the primary fuel, which is stored in a
268,000-gallon storage tank, as the primary fuel. All CT capacities referenced
above are summer ratings.
Fuel System
Coal for Morgantown Units 1 and 2 is delivered in unit trains to a
rotary car dumper. Coal is then conveyed to a rail mounted traveling bucket
wheel stacking/reclaiming machine. The Morgantown Facility's coal storage
bunkers hold approximately a 24-hour supply of coal at full load burn rates. An
emergency reclaim system is provided to permit fueling of the Morgantown
Facility in the event that the stacker/reclaimer is out of service. Coal
inventory is normally maintained at 20 to 30 days.
No. 6 residual oil for Morgantown Units 1 and 2 is generally
transported to the site from Piney Point in southern Maryland via the Piney
Point Pipeline. The secondary means of delivering No. 6 oil to the Morgantown
Facility is by truck. The oil is stored in storage tanks with a total capacity
of 501,000 barrels. Three pumps are utilized to pump the oil from the storage
tank to booster pumps which pump the oil at 1,000 psig to the oil burners in
each of the steam generators.
No. 2 distillate oil is used as a primary fuel in the CTs and
auxiliary boilers and as start-up and low load flame stabilization fuel in the
steam units. The oil is delivered by barge to the Morgantown Facility, where
there is a total storage capacity for No. 2 and No. 6 oil of 11.8 million
gallons in two interconnected tanks.
Ash Systems
Boiler bottom ash and slag are collected by the ash hoppers located
under the furnace. A submerged flight conveyor removes the bottom ash from the
ash hoppers. The bottom ash is transferred on a common transfer conveyor to an
on-site storage location, where it can be loaded onto trucks for disposal.
The fly ash transport system is a pressurized dry pneumatic system.
The fly ash from each unit is transported to silos which are periodically
emptied into trucks and the ash hauled to Faulkner for disposal.
S-7
Water Supply
Raw cooling water for the Morgantown Units 1 and 2 is obtained from
the Potomac River. Water for other uses within the Morgantown Facility is
obtained from the four on-site artesian wells.
Make-up water for the steam generators and auxiliary boilers is
produced from well water from the four on-site artesian wells using a dual-train
demineralizer system. Well water is supplied directly for domestic water
services, pump seal water, and is the source for the fire system's water supply.
Electrical and Control Systems
The Morgantown Units 1 and 2 generator terminals are each connected
through force-cooled isolated phase buswork to the low-voltage terminals of
their main transformer. Each of the units use a three-phase, forced oil, forced
air-cooled main power transformer manufactured by GE. Both transformers are
rated at 650 MVA, with Morgantown Unit 1 at 17.1 kV-234 kV and Morgantown Unit 2
at 22.8 kV-234 kV. One spare main power transformer is shared with the Chalk
Point Facility.
Environmental Controls and Equipment
Air Emissions
The basic strategies and air pollution control technologies employed
at the Morgantown Facility to control air emissions include: (i) purchasing
fuels of the required sulfur content in order to control emissions of SO(2);
(ii) utilizing ESPs on Morgantown Units 1 and 2 for particulate and opacity
control; and (iii) utilizing LNCFS Level III burners and SOFA systems on
Morgantown Units 1 and 2 to reduce NO(X) emissions.
The Morgantown Facility's steam units are equipped with CEMs for
opacity, SO(2), NO(X), CO(2), as well as flue gas volumetric flow as required by
state and federal regulations. CO probes have also been installed on each of the
steam units.
Wastewater/Solid Waste Disposal
Solid waste at the Morgantown Facility consists primarily of the
coal processing and combustion byproducts generated by Morgantown Units 1 and 2.
Bottom ash from Morgantown Units 1 and 2 is pumped as a water/ash mixture to
dewatering bins where the water is decanted off and recycled for use in the
bottom ash transporting system. The dewatered bottom ash is loaded into trucks
for disposal.
Fly ash from Morgantown Units 1 and 2 is collected and transported
to ash storage silos, where it is loaded into trucks for transport to Faulkner.
The small amounts of iron pyrites removed from the pulverizers of
Morgantown Units 1 and 2 are stored on site in a lined storage area.
Major water treatment equipment at the Morgantown Facility includes
settling ponds, neutralization systems, oil/water separators and sanitary waste
treatment. With the exception of once-through cooling water and clean storm
water, all water is treated prior to discharge to the Potomac River or
Pasquahanza Creek. Two settling ponds are arranged in series for the collection
and treatment of contaminated storm waters and all process discharges from the
Morgantown Facility. A caustic injection system is utilized in the secondary
pond to control pH. Solids are removed from the ponds through a sedimentation
process. Both the settling ponds and a packaged sewage treatment plant discharge
into the Morgantown Facility's discharge canal. Also there is a separate
settling pond for the water runoff from the lined coal storage area.
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Off-Site Requirements
Fuel Supply
Morgantown Units 1 and 2 burn bituminous coal that is delivered by
rail from mines generally located in the northern Appalachian coal-mining
region. Coal is purchased pursuant to four coal contracts that also cover coal
supply to the Dickerson and Chalk Point Facilities. These contracts are
short-term which, with certain extension options, will expire between December
31, 2000 and June 30, 2002. In addition to the contracts, coal may be purchased
on the spot market depending on quantity requirements and market conditions.
The No. 6 residual oil burned at the Morgantown Facility is
purchased on the spot market and is primarily delivered to the Morgantown
Facility via the Piney Point Pipeline. The secondary means of delivering No. 6
residual oil to the Morgantown Facility is via truck. No. 6 oil is purchased
under short-term contracts with no minimum purchase requirements. In addition to
the Piney Point Pipeline, delivery of No. 6 oil can be accomplished by barge.
No. 2 distillate fuel oil is purchased with each of three vendors
under short-term contracts with no minimum purchase requirements. The oil is
delivered to the Morgantown Facility by barge from the vendors' terminals.
Electrical Interconnection
The Morgantown Facility's electric output is interconnected to the
grid through the Morgantown Facility's switchyard. Morgantown Units 1 and 2 and
Morgantown CTs 3 through 6 are connected to the Morgantown 230 kV ring bus.
There are six 230 kV transmission lines emanating from the switchyard that tie
into the Hawkins Gate, Oak Grove, Talbert and Ryceville Substations. In
addition, there are two 69 kV lines emanating from the switchyard that tie into
the SMECO system.
Description of the Potomac River Facility
Mechanical Equipment and Systems
Steam Generators
The Potomac River Units 1 and 2 steam generators consist of
identical CE natural circulation units with tubular air preheaters and
tangentially-fired burners. The boilers have a maximum continuous rating of
800,000 lb/hr of superheated steam flow at 875 psig and 925(degree)F. The
boilers are designed to fire pulverized coal as the primary fuel and to fire No.
2 fuel oil for start-up, flame stabilization, and as alternate fuel to replace
mill capacity when needed.
The Potomac River Units 3, 4 and 5 steam generators consist of
identical CE controlled circulation units with tubular air preheaters and
tangentially-fired burners. The boilers have a maximum continuous rating of
725,000 lb/hr of superheated steam flow at 1,875 psig and 1,050(degree)F. The
boilers are designed to fire pulverized coal as the primary fuel and to fire No.
2 fuel oil for start-up, flame stabilization, and as an alternate fuel to
replace mill capacity when needed.
Turbine Generators
Each Potomac River Units 1 and 2 steam generator provides steam to a
single GE straight condensing 1,800 rpm steam turbine. Each turbine is rated at
80,000 kW at an inlet throttle flow of 577,600 lb/hr of steam at 850 psig,
925(degree)F and 1.0 inch Hg backpressure.
Each of the Potomac River Units 1 and 2 1,800 rpm steam turbines
drives a GE hydrogen-cooled generator rated at 94,117 kVA at 0.85 power factor
and 13.8 kV.
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Each Potomac River Units 3, 4 and 5 boiler provides steam to a
single GE tandem-compound double flow reheat 3,600 rpm steam turbine. Each
turbine is rated at 110,000 kW at an inlet throttle flow of 725,000 lb/hr of
steam at 1,800 psig, 1,050(degree)F reheat and 1.0 inch Hg backpressure.
Each of the Potomac River Units 3, 4, and 5 3,600 rpm steam turbines
drives a GE hydrogen-cooled generator rated at 150,882 kVA at 0.85 power factor
and 13.8 kV.
Fuel System
Bituminous coal for Potomac River Units 1, 2, 3, 4 and 5 is
delivered by train to a rotary car dumper. Coal from the 140,000-ton storage
pile is reclaimed into a double receiving hopper and delivered to the boiler
bunkers.
Two No. 2 fuel oil underground storage tanks ("USTs") of 25,000
gallons each supply the five units with start-up fuel.
Ash Systems
The pneumatic ash handling system of the Potomac River Facility is
comprised of four subsystems, including a bottom ash system A serving Potomac
River Units 1, 2 and 3; a bottom ash system B serving Potomac River Units 4 and
5; a fly ash system A serving Potomac River Units 1, 2 and 3; and a fly ash
system B serving Potomac River Units 4 and 5. These subsystems convey ash to two
fly ash silos with wet and dry unloading equipment and one bottom ash silo with
wet unloading equipment.
Water Supply
Raw cooling water for each unit of the Potomac River Facility is
obtained from the Potomac River. Water for other uses within the Potomac River
Facility is obtained from the City of Alexandria water supply.
Boiler make-up water for the Potomac River Facility is generated
from the City of Alexandria water supply using a demineralizer. Demineralized
water is either used directly in the plant or stored in three demineralizer
water storage tanks with a total capacity of 150,000 gallons.
Electrical and Control Systems
Each generator is connected through an isolated phase bus duct to
its main generator step-up transformer. A total of ten main generator step-up
transformers, two per unit, are provided at the Potomac River Facility. Potomac
River Units 1 and 2 use three-phase outdoor oil-filled units rated 13.8-69 kV,
48/60 MVA with self/forced air-cooling. Potomac River Units 3, 4, and 5 use
three-phase outdoor oil-filled units rated 13.8-69 kV, 90 MVA with forced
oil/forced air-cooling.
Environmental Controls and Equipment
Air Emissions
The basic strategies and air pollution control technologies employed
at the Potomac River Facility to control air emissions include: (i) purchasing
fuels of the required sulfur content in order to control emissions of SO(2); and
(ii) utilizing cold-side and hot-side ESPs on all five units.
All five units at the Potomac River Facility are equipped with CEMs
for opacity, SO(2), NO(X), CO(2), as well as flue gas volumetric flow as
required by state and federal regulations.
Wastewater/Solid Waste Disposal
Solid waste at the Potomac River Facility consists primarily of the
coal processing and combustion by-products generated by all five units. Bottom
ash from each of the five units is collected and transported to the bottom ash
storage silo where it is loaded into trucks for disposal off-site.
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Fly ash from each of the five units is collected and transported to
one of two fly ash storage silos where it is loaded into trucks for transport to
Brandywine.
Certain plant drains and storm drains discharge to the Potomac
River. Eight sumps collect storm runoff, coal pile runoff, precipitator runoff,
and ash handling area runoff for discharge to the clarifier. Clarifier effluent
and demineralizer regeneration waste is neutralized in the neutralization tank
prior to discharge into the Potomac River. All sanitary waste from the Potomac
River Facility is discharged to the City of Alexandria sewage system.
Off-Site Requirements
Fuel Supply
All five units of the Potomac River Facility burn bituminous coal
from mines primarily located in the northern Appalachian coal-mining region.
Coal is purchased pursuant to two coal contracts. These contracts are short-term
which, with certain extension options, will expire on May 31, 2002. In addition
to the contracts, coal may be purchased on the spot market depending on quantity
requirements and market conditions.
No. 2 distillate fuel oil is purchased pursuant to one-year
contracts with each of three vendors. The oil is delivered to the Potomac River
Facility by truck.
Electrical Interconnection
The Potomac River Facility's electric output is interconnected to
the grid through the Potomac River Facility's switchyard. Potomac River Units 1
through 4 are connected to one of two 69 kV buses. Potomac River Unit 5 is
connected to both 69 kV buses. The two 69 kV buses are connected to the two Blue
Plains 230 kV buses through four transformers. Additionally, the two 69 kV buses
feed 16 69 kV substations.
Description of the Other Mirant Mid-Atlantic Facilities
The Production Service Center
The PSC is a 145,000-square foot facility located 9 miles from
Washington, D.C. in Upper Marlboro, Maryland. The PSC is within one hour's drive
of all of the Mirant Mid-Atlantic Facilities. The PSC was established in 1985
and serves as the headquarters for the Mirant Mid-Atlantic Facilities.
The PSC facility provides office space for administrative and
engineering functions, classrooms and supporting equipment for training, and a
large machine shop for repairing power plant equipment. In addition, maintenance
staff for all Mirant Mid-Atlantic Facilities are housed at the PSC.
The Piney Point Pipeline
Mirant Mid-Atlantic acquired the Piney Point Pipeline which supplies
No. 6 residual fuel oil to the Chalk Point and Morgantown Facilities. The Piney
Point Pipeline and barge unloading facilities were constructed in 1971 by
Steuart Petroleum and the Piney Point Pipeline was purchased by Pepco in 1976.
It connects the deepwater barge unloading facilities on the Potomac River in
Piney Point, Maryland with the two generating facilities.
The Piney Point Pipeline consists of 51.5 miles of thermally
insulated, buried hot oil pipeline, four pumping stations, and five isolation
valve stations. There are two river crossings at which there is double walled
piping with nitrogen blanketing in the void space between the inner and outer
pipes. Cathodic protection and leak monitoring systems are installed on the
piping.
The four pumping stations are located at the Ryceville Pumping
Station and Piney Point Oil Terminal, and at the Chalk Point and Morgantown
Facilities. There are four electric driven pumps, one back-up diesel driven
pump, and oil heaters at each of the Ryceville Pumping Station and Piney Point
Oil Terminal, and single pumps at both the Chalk Point and Morgantown
Facilities.
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Storage tanks include two 500,000-barrel tanks for No. 6 residual
oil at the Piney Point Oil Terminal, and flushing oil tanks with capacities of
96,000 barrels at the Morgantown Facility, 20,000 barrels at the Chalk Point
Facility, and 54,000 barrels at the Ryceville Pumping Station. Flushing oil is
No. 2 distillate fuel oil that is used to fill the Piney Point Pipeline when it
is not pumping No. 6 residual oil.
Day-to-day operations of the Piney Point Pipeline are performed by
ST Services (formerly Steuart Petroleum) under a contract that expires on May
31, 2001. Mirant Mid-Atlantic has the option to extend the contract for an
additional five years.
The Piney Point Pipeline has been out of service since an April 2000
oil release (see the section of this Supplement entitled "Environmental
Assessment -- The Piney Point Pipeline"). Approval of a Spill Prevention Control
and Countermeasure ("SPCC") plan in connection with the restoration is required
by the U.S. Department of Transportation, the USEPA, and the MDE. While the
Piney Point Pipeline is out of service, No. 6 oil is being transported to the
Chalk Point and Morgantown Facilities by truck.
The Ash Storage Facilities
Mirant Mid-Atlantic acquired the Ash Storage Facilities which
receive and store the solid waste materials such as sludges, bottom ash and fly
ash produced from the combustion of coal at the generating facilities. These
three facilities are the Faulkner, Brandywine and Westland Ash Storage
Facilities. Each site has its own NPDES Permit that requires extensive ground
and surface water monitoring on a periodic basis through the life of the
facility.
Brandywine
Brandywine was developed to store the ash byproducts from the Chalk
Point Facility and, since 1986, it has been storing ash byproducts from the
Potomac River Facility as well. It has been in operation since 1970, and is
located on approximately 232 acres of land in the rural town of Brandywine in
Prince George's County, Maryland.
The amount of ash delivered to Brandywine depends on the ash content
and amount of coal being fired at the Chalk Point and Potomac River Facilities,
and on the amount of ash that can be marketed to third parties. With the
additional 20 feet of elevation available above the original Areas A, B, C, and
E, Brandywine is projected to have approximately 16 years of active life
remaining at expected ash production rates.
Faulkner
Faulkner was developed to store the ash byproducts from the
Morgantown Facility. It has been in operation since 1970, and is located on
approximately 276 acres of land in a rural area on the western edge of the
Zekiah Swamp in south-central Charles County, Maryland.
There are approximately 6.5 million tons of ash in storage at
Faulkner, with approximately 198,000 tons being added each year. The amount of
ash delivered to Faulkner depends on the ash content and amount of coal being
fired at the Morgantown Facility, and on the amount of ash that can be marketed
to third parties. At expected ash production rates, Faulkner is projected to
have approximately 23 years of active life remaining.
Westland
Westland was developed to store the ash byproducts from the
Dickerson Facility. It has been in operation since 1978, and is located on
approximately 300 acres of land adjacent to the Dickerson Facility, east of the
Potomac River in a rural area of western Montgomery County, Maryland.
There are approximately two million tons of ash in storage at
Westland, with approximately 200,000 tons being added each year. The amount of
ash delivered to Westland depends on the ash content and amount of coal being
fired at the Dickerson Facility, and on the amount of ash that can be marketed
to third parties. At expected ash production rates, Westland is projected to
have approximately 48 years of active life remaining.
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Operating and Maintenance
One of the assets acquired by Mirant Mid-Atlantic is the PSC. In
addition to the physical capabilities contained in the PSC facility such as the
machine shop, training areas and offices, the staff of the PSC provides numerous
services to the generating facilities. As the headquarters for Mirant
Mid-Atlantic's generation unit, the PSC staff developed programs and procedures
that have been implemented at all the generating facilities. Thus, while each
generating facility is unique, they all share many similar practices.
The PSC utilizes its own in-house capabilities and staff to provide
qualification training in operations and maintenance, as well as safety,
environmental and other compliance training. Generation facility technicians are
provided with a full range of training and must pass qualification tests before
progressing to the next level. Currently, a program is in place wherein
approximately 600 of 700 bargaining unit plant technicians have been trained and
qualified for both a primary and a secondary job skill, of which one skill must
be in operations. Augmenting the classroom training are a number of specialty
training shops at the PSC, and the boiler control simulators at the PSC and at
the Dickerson Facility. Organizational training such as supervisory development
and equal employment opportunity training has not been conducted by the
Generation Training and Procedures Department in the past since a corporate
Pepco department conducted such training. However, it is anticipated that Mirant
Mid-Atlantic will provide this type of training through the PSC in the future.
The PSC is also responsible for coordinating the development and
management of operating, maintenance and administrative procedures for Mirant
Mid-Atlantic. Mirant Mid-Atlantic has a comprehensive procedures program
administered by the PSC. Virtually all maintenance, operations and
administrative functions have had procedures written for them which are
currently being entered into a computer database. Other than certain facility
specific operating procedures, all procedures must be approved by the PSC.
Approximately 75 percent of all procedures are written by the "process owners"
who are responsible for the work to be performed.
The PSC also provides engineering, technical, project management
services and skilled craftspeople to the Mirant Mid-Atlantic Facilities, and is
responsible for the central maintenance shop located in the PSC facility. The
PCS staff of approximately 162 people is divided into a Major Machinery
Engineering Division, an Outage Management Services Division, a Performance and
Technical Services Division, a Production Services Division and a Clean Air Act
Projects group.
Operating History
Operating data for the past several years of operation of the Mirant
Mid-Atlantic Facilities was provided by Mirant Mid-Atlantic and is presented in
Table 1.
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Table 1
Operating History
Mirant Mid-Atlantic Facilities
Chalk Point Dickerson Morgantown Potomac River
----------- --------- ---------- -------------
Net Capability Rating (MW)(1)
1996 2,423 837 1,412 482
1997 2,423 837 1,412 482
1998 2,423 837 1,412 482
1999 2,423 837 1,412 482
2000 2,423 837 1,412 482
Net Generation (GWh)
1996 4,583.3 3,360.2 7,216.2 1,665.1
1997 4,814.8 3,433.5 6,941.6 1,869.9
1998 6,314.2 3,834.6 7,853.4 2,196.1
1999 7,858.0 3,549.0 7,435.0 2,704.0
2000 5,198.6 2,761.6 7,568.3 2,018.3
Annual Net Heat Rate (Btu/kWh)(2)
1996 10,490 9,594 9,611 11,069
1997 10,654 9,678 9,535 11,143
1998 10,561 9,575 9,269 10,979
1999 10,399 9,848 8,996 10,869
2000 10,897 10,089 9,269 11,288
Net Capacity Factor (%)(2)
1996 48.2 66.0 69.5 45.4
1997 48.3 67.1 67.2 49.3
1998 50.9 76.2 77.1 56.7
1999 55.4 68.2 72.5 67.9
2000 38.2 54.6 73.5 51.2
Equivalent Availability Factor (%)(2)
1996 83.7 86.2 93.9 88.8
1997 83.7 86.3 83.0 88.5
1998 83.3 90.5 86.9 89.6
1999 86.1 78.7 76.7 91.9
2000 73.3 78.9 87.8 89.7
Coal Use (Tons x 1000)
1996 1,302.2 1,187.4 2,591.0 711.8
1997 1,323.0 1,207.1 2,489.9 803.6
1998 1,506.7 1,356.7 2,732.5 934.4
1999 1,664.0 1,231.0 2,496.0 975.5
2000 1,177.8 1,014.4 3,891.7 851.6
Oil Use (Gallons x 1000)
1996 52,107.3 3,211.9 8,561.3 --
1997 54,813.6 1,840.2 8,948.2 --
1998 143,072.0 595.4 6,571.2 --
1999 168,336.0 1,334.0 8,971.0 --
2000 40,854.2 289.5 14,556.0 --
Gas Use (Mcf x 1000)
1996 3,105.7 955.1 -- --
1997 6,111.0 1,433.1 -- --
1998 5,786.3 1,127.4 -- --
1999 11,758.0 2,066.0 -- --
2000 17,993.2 1,046.2 -- --
--------------------
(1) Summer ratings for CTs.
(2) Represents weighted average for annual net heat rate, net
capacity and equivalent availability factor.
Environmental Assessments
Environmental Site Assessments
We have reviewed Phase I ESAs, dated between December 13 and 16,
1999, prepared for each of the generating stations, the Ash Storage Facilities,
the PSC, and the Ryceville Pumping Station and Piney Point Oil
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Terminal prepared by Pepco's environmental consultant to determine the
consistency of their assessment with industry standards. The Phase I ESA
reports, consisted of site reconnaissance, interviews, review of facility files,
and review of relevant government agency files, including files from the MDE and
the VADEQ.
Additionally, we have reviewed comments from Pepco's environmental
consultant regarding their follow-up site visits conducted between March 9 and
10, 2000 to the Mirant Mid-Atlantic Facilities, Ash Storage Facilities, the PSC,
and the Ryceville Pumping Station. Pepco's environmental consultant stated that
"no environmental conditions other than those noted during the initial site
reconnaissance conducted in June 1999, were observed." We have also reviewed an
updated report regarding environmental site conditions at the Mirant
Mid-Atlantic Facilities dated December 15, 2000 prepared by Pepco's
environmental consultant.
Pepco's environmental consultant did not perform Phase II ESAs that
typically identify the nature and extent of potential contamination issues
through soil and groundwater investigations. Rather, Pepco's environmental
consultant and Pepco relied on existing groundwater and surface water sampling
data (as available) for preparation of estimated cost projections to mitigate
numerous potential site contamination issues identified at the facilities during
Phase I ESAs. We understand these cost projections were based on (1) identifying
remediation scenarios and their estimated range of costs; (2) risk profiling of
each issue by estimating probability of occurrence of each environmental issue
and the likelihood that regulatory action would be required; and (3) developing
a model of projected costs based on the previous assumptions. Mirant
Mid-Atlantic has also prepared cost projections for the significant
environmental remedial issues. The total projected costs for environmental
concerns relating to potential site contamination issues are estimated by Mirant
Mid-Atlantic to be approximately $12,500,000, which includes a contingency for
currently unknown site contamination issues, if any, that may potentially
develop in the future. The estimated costs for potential environmental projects
have been included as capital expenditures and operation and maintenance
expenses in the Projected Operating Results presented in the Report.
The Chalk Point Facility
Prior to initial development of the power generating station in the
mid-1960s, the historical use of the approximately 1,160-acre subject property
was agricultural or undeveloped land. As of the date of the investigation by
Pepco's environmental consultant, the majority of the subject property was
undeveloped, with other portions consisting of the power plant facilities. Prior
to 1970, on-site disposal of fly ash and bottom ash from coal combustion
occurred on the property. On-site land disposal areas also contain asbestos
containing building materials and construction debris. Pepco's environmental
consultant reported a 1998 study identifying that leachate from an unlined coal
pile has impacted on-site groundwater with elevated metals, sulfate, and low pH
in groundwater. Mirant Mid-Atlantic has identified an allowance for a coal pile
liner in the capital expenditure estimates included in the Projected Operating
Results.
The Dickerson Facility
Prior to initial development of the power generating station in the
late 1950s, the historical use of the approximately 1,012-acre subject property
was undeveloped land. As of the date of the investigation by Pepco's
environmental consultant, the majority of the subject property was undeveloped
woodlands and fields, with other portions consisting of the power plant
facilities. Prior to 1970, fly and bottom ash from coal combustion was used for
fill material in five areas within the property limits, and there are two areas
used for land disposal which were identified by Pepco's environmental
consultant. Analysis of water extracted from monitoring wells indicates
groundwater has been impacted by coal pile leachate with elevated metals,
sulfates, dissolved solids and low pH levels. Pepco began monitoring groundwater
quality in 1993, and submitted a detailed monitoring plan to the MDE in 1997.
Mirant Mid-Atlantic has identified an allowance for a coal pile liner in the
capital expenditures included in the Projected Operating Results.
The Morgantown Facility
Prior to the development of the power generating facilities in the
1967, the 632-acre subject property had been used for a housing development and
for farming. The subject property includes heavily wooded areas, nature trails,
farming land, a tenant's house and farm buildings, as well as the power
generation building, fuel unloading dock
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for barge transport, ash handling and coal storage facilities. Groundwater and
soil contamination from the historical coal pile handling and storage area have
been under remediation since a consent order was issued by the MDE in 1996.
The Potomac River Facility
Prior to the development of the power generation facility in 1946,
the 28-acre subject property was occupied by the Potomac River Clay Works and
the American Chlorophyll Company. Historical documents indicate that an on-site
refuse pond was associated with the activities of the American Chlorophyll
Company. The report contained information regarding a fill site on the southern
edge of the subject property. According to interviews conducted by Pepco's
environmental consultant with Pepco personnel, an area outside the fence line
may contain fill and demolition or construction debris and coal rejects.
The Production Service Center
Prior to construction of the PSC in approximately 1985, the
historical use of the approximately 70-acre subject property was undeveloped
land and as a gravel-pit mining operation between approximately the 1940s
through some portion of the 1970s. As of the date of the investigation by
Pepco's environmental consultant, the subject property consisted of the PSC
building (including offices, a machine shop, and hazardous waste storage areas),
training areas, and undeveloped woodlands. Pepco's environmental consultant
concluded that their investigation revealed no recognized environmental
conditions at the subject property.
The Piney Point Pipeline
The ESA evaluated potential site contamination issues at the Piney
Point Pipeline, which consists of the 6.8-acre Ryceville Pumping Station
property, the 51.5-mile underground oil pipeline, the Mile Post 15 valve housing
station, and the pumping equipment at the Piney Point Oil Terminal property. The
Piney Point Pipeline includes a 30.25-mile underground run of 16-inch pipe
between the Piney Point Oil Terminal and Ryceville Pumping Station and 11.5-mile
and 9.75-mile underground pipe runs from the Ryceville Pumping Station to the
Chalk Point and Morgantown Facilities, respectively. Prior to use as a pumping
station, the historical use of the 6.8-acre subject property was undeveloped
woodlands and fields. As a result of its site reconnaissance, interviews, and
review of Pepco records, Pepco's environmental consultant reported no
significant history of spills or leaks at the Ryceville Pumping Station, along
the pipeline route, at the valve station, or at the area of the Pepco pumping
equipment at the Piney Point Oil Terminal. Pepco's environmental consultant
concluded that no recognized environmental conditions were observed at the
Ryceville Pumping Station. A significant oil spill occurred from the Piney Point
Pipeline and was detected on April 7, 2000. On December 20, 2000, Pepco received
a Notice of Probable Violation Proposed Civil Penalty and Proposed Compliance
Order from the Department of Transportation, Office of Pipeline Safety. Mirant
Mid-Atlantic will be responsible for complying with the terms of the final
compliance order. Under the terms of the Asset Purchase Agreement, Pepco is
obligated to indemnify Mirant and its affiliates for all environmental liability
relating to the release of fuel oil from the Piney Point Pipeline.
The Ash Storage Facilities
Prior to initial development of Brandywine in the 1960s, the
historical use of the property was reportedly a gravel surface mine,
agricultural, and undeveloped land. As of the date of the investigation by
Pepco's environmental consultant, the subject property consisted of ash fill
areas, leachate-collection and stormwater runoff ponds, various support
facilities, and undeveloped woodlands. Groundwater monitoring conducted at the
property indicates impacts to groundwater (exceeding the USEPA Drinking Water
Regulation standards) from certain metals and other general water quality
parameters, due to the leachate from older ash fill areas. Pepco's environmental
consultant noted that the monitoring results are reported to the MDE.
Prior to initial development of Faulkner in 1970, the historical use
of the property was reportedly agricultural and undeveloped land. As of the date
of the investigation by Pepco's environmental consultant, the subject property
consisted of ash fill areas, leachate-collection and stormwater runoff ponds,
various support facilities, buffer acreage consisting of the Brinsfield
Property, and undeveloped woodlands. Groundwater monitoring is conducted at the
property to monitor impacts from ash storage. Pepco's environmental consultant
reported impacts to surface water
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and groundwater quality within the boundaries of the subject property, but not
outside the boundary. A final consent order was being negotiated for a passive
water treatment system and/or slurry wall to protect surface water quality.
Prior to initial development of Westland in 1978, the historical use
of the property was reportedly agricultural and undeveloped land. As of the date
of the investigation by Pepco's environmental consultant, the subject property
consisted of ash fill areas, leachate-collection and stormwater runoff ponds,
various support facilities, and deserted farm structures. Monitoring conducted
at the property indicates groundwater has been impacted due to the leachate from
older ash fill areas. Elevated levels of sulfate, chloride, dissolved solids and
manganese have been recorded in one of the monitoring wells. Pepco's
environmental consultant also noted that the stream adjacent to the southwest
boundary of the Property is stained from high concentrations of iron
precipitates, which would indicate the potential that leachate has impacted the
soil and groundwater of the area. Pepco's environmental consultant did not
indicate whether water quality results have been reported to the MDE.
Status of Permits and Approvals
The status of key permits and approvals for the Mirant Mid-Atlantic
Facilities are shown in Table 2.
Table 2
Status of Key Permits and Approvals Required for Operation
Chalk Point Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
Federal
- ------------------------------------------------------------------------------------------------------------------------------------
1. Hazardous Waste Generator ID USEPA/MDE Issued ID No. Large quantity generator of hazardous
Number 050399 700 007 H wastes. Waste manifest system must be
followed when disposing hazardous waste.
- ------------------------------------------------------------------------------------------------------------------------------------
2. SPCC Plan USEPA/MDE Prepared Required for prevention of oil spills
from equipment and storage tanks.
- ------------------------------------------------------------------------------------------------------------------------------------
3. Phase II Acid Rain Title IV USEPA/MDE Issued 1/1/00;
Permit Expires 12/31/04 Stack CEMs data used to demonstrate
compliance with allowance allocations.
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
4. Title V Operating Permit MDE Applied for 12/2/96; Incorporates all emission sources at
Deemed complete 1/21/97 plant. Operating under permit shield
since application deemed complete, which
is typical of other facilities.
- ------------------------------------------------------------------------------------------------------------------------------------
5. NPDES Permit MDE Issued 9/1/96; NPDES permit includes coal pile, ash
Expires 8/31/01 ponds and stormwater ponds. Application
for renewal must be made six months prior
to expiration.
- ------------------------------------------------------------------------------------------------------------------------------------
6. Groundwater Appropriation Maryland Department of Issued 8/1/90;
Natural Resources Expires 8/1/02
("MDNR")
- ------------------------------------------------------------------------------------------------------------------------------------
7. Surface Water Appropriation MDE Issued 2/1/94; Required for withdrawal of water from
Expires 2/1/06 river.
- ------------------------------------------------------------------------------------------------------------------------------------
8. NO(X) Budget Rule Consent MDE Issued 9/13/99 Allows for rolling over of emissions
allowances Order from 2000 to 2001.
- ------------------------------------------------------------------------------------------------------------------------------------
9. Consent Order MDE Issued 7/9/92 Covers installation of CEMs and
documentation of compliance.
- ------------------------------------------------------------------------------------------------------------------------------------
10. Consent Agreement MDE Issued 6/21/72 Establishes opacity limit at 20% for
Chalk Point Unit 3.
- ------------------------------------------------------------------------------------------------------------------------------------
11. NO(X) RACT Consent Agreement VADEQ Issued 7/10/98 Establishes NO(X) emission limits under
RACT for NO(X) non-attainment.
- ------------------------------------------------------------------------------------------------------------------------------------
12. Faulkner NPDES Permit MDE Issued 2/1/97; Includes requirements for treatment of
Expires 1/31/02 runoff and groundwater monitoring and
protection. Application for renewal must
be made six months prior to expiration.
====================================================================================================================================
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Table 3
Status of Key Permits and Approvals Required for Operation
Dickerson Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
Federal
- ------------------------------------------------------------------------------------------------------------------------------------
1. Hazardous Waste Generator ID USEPA/MDE Issued ID Nos. Large quantity generator of hazardous
Number MDD 000731596 wastes. Waste manifest system must be
followed when disposing hazardous waste.
- ------------------------------------------------------------------------------------------------------------------------------------
2. SPCC Plan USEPA/MDE Approved 10/21/98 Required if oil spills could reach
navigable waters. Approval of SPCC and
Facility Response Plan.
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
3. Phase II Acid Rain Permit MDE Issued 1/1/00; Permit for Phase II of the SO(2)
Expires 12/31/04 allowance program under Clean Air Act
Title IV.
- ------------------------------------------------------------------------------------------------------------------------------------
4. Title V Operating Permit MDE Submitted 12/2/96; Incorporates all emission sources.
Deemed complete 1/21/97 Preliminary draft permit issued.
Operating under permit shield since
application deemed complete, which is
typical of other facilities.
- ------------------------------------------------------------------------------------------------------------------------------------
5. Opacity Consent Order MDE Issued 4/24/00; To bring units into compliance with
Expires 12/1/03 opacity. Outlines the requirements for
testing and potential conversion to wet
ESPs. Compliance deadline 7/1/03.
- ------------------------------------------------------------------------------------------------------------------------------------
6. NO(X) Budget Rule Consent Order MDE Issued 9/13/99 Allows for rolling over of emissions from
year 2000 to 2001.
- ------------------------------------------------------------------------------------------------------------------------------------
7. NPDES Permit MDE Issued 8/1/96; Discharges of once-through cooling water,
Expires 7/31/01 runoff, sewage treatment effluent,
backwash, treatment plant effluent, metal
cleaning wastes. Discharge to Potomac
River and tributaries. Application for
renewal submitted 1/29/01.
- ------------------------------------------------------------------------------------------------------------------------------------
8. Groundwater Appropriation MDNR Issued 2/1/92; Withdrawal of potable well water.
Expires 2/1/04
- ------------------------------------------------------------------------------------------------------------------------------------
9. Surface Water Appropriation MDNR Issued 1/1/91 Withdrawal of up to 550 million gallons
per day.
- ------------------------------------------------------------------------------------------------------------------------------------
10. Westland NPDES Permit MDE Issued 7/1/95; Includes requirements for treatment of
Expires 6/30/00 runoff and groundwater monitoring and
Renewal application protection. It is typical for facilities
submitted. Operating to operate under expired permits provided
under prior permit. timely renewal application is made.
====================================================================================================================================
S-18
Table 4
Status of Key Permits and Approvals Required for Operation
Morgantown Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
Federal
- ------------------------------------------------------------------------------------------------------------------------------------
1. Hazardous Waste Generator ID USEPA/MDE Issued ID No. Large quantity generator of hazardous
Number 050399 700 007 H wastes. Waste manifest system must be
followed when disposing hazardous waste.
- ------------------------------------------------------------------------------------------------------------------------------------
2. SPCC Plan USEPA/MDE Prepared Required for prevention of oil spills
from equipment and storage tanks
- ------------------------------------------------------------------------------------------------------------------------------------
3. Phase II Acid Rain Title IV USEPA/MDE Effective 1/1/00 Stack CEMs data used to demonstrate
compliance Permit with allowance
allocations
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
4. Title V Operating Permit MDE Applied for 12/2/96; Incorporates all emission sources at
Deemed complete 1/21/97 plant. Operating under permit shield
since application deemed complete, which
is typical of other facilities.
Preliminary draft permit issued.
- ------------------------------------------------------------------------------------------------------------------------------------
5. NPDES Permit MDE Application for renewal NPDES permit includes coal pile, ash
submitted 8/6/99; draft ponds and stormwater ponds. It is typical
permit received from the for facilities to operate under expired
MDE. Plant operating under permits provided timely renewal
previous permit application is made.
- ------------------------------------------------------------------------------------------------------------------------------------
6. Groundwater Appropriation MDE Issued 6/1/98, 7/1/97,
12/1/97;
Expires 9/1/07
- ------------------------------------------------------------------------------------------------------------------------------------
7. Surface Water Appropriation MDE Issued 8/1/97; Required for withdrawal of water from
Expires 12/1/09 river.
- ------------------------------------------------------------------------------------------------------------------------------------
8. Conditional Approval for Use MDE Issued 3/4/85
of Waste Oil
- ------------------------------------------------------------------------------------------------------------------------------------
9. NO(X) Budget Rule Consent Order MDE Issued 9/13/99 Allows for rolling over of emissions
allowances from 2000 to 2001.
- ------------------------------------------------------------------------------------------------------------------------------------
10. NO(X) RACT Consent Agreement VADEQ Issued 7/10/98 Establishes NO(X) emission limits under
RACT for NO(X) non-attainment.
- ------------------------------------------------------------------------------------------------------------------------------------
11. Consent Order MDE Issued 7/9/92 Covers installation of CEMs and
documentation of compliance.
- ------------------------------------------------------------------------------------------------------------------------------------
12. Consent Order MDE Issued 6/10/96 Requires corrective action for
groundwater contamination at plant.
- ------------------------------------------------------------------------------------------------------------------------------------
13. Brandywine NPDES Permit MDE Issued 3/1/97; Includes requirements for treatment of
Expires 2/28/02 runoff and groundwater monitoring and
protection. Application for renewal must
be made six months prior to expiration.
====================================================================================================================================
S-19
Table 5
Status of Key Permits and Approvals Required for Operation
Potomac River Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
Federal
- ------------------------------------------------------------------------------------------------------------------------------------
1. Hazardous Waste Generator ID USEPA/VADEQ Issued ID No. Large quantity generator of hazardous
Number VAD 000731588 wastes. Waste manifest system must be
followed when disposing hazardous
waste.
- ------------------------------------------------------------------------------------------------------------------------------------
2. SPCC Plan USEPA/VADEQ Prepared Required if oil spills could reach
navigable waters. Approval of SPCC and
Facility Response Plan.
- ------------------------------------------------------------------------------------------------------------------------------------
3. NPDES Permit USEPA Issued 4/20/00; Discharges of cooling water, ash
Expires 4/20/05 clarifier, neutralization wastewater,
and misc. drains to the Potomac River.
Application for renewal must be made
six months prior to expiration.
- ------------------------------------------------------------------------------------------------------------------------------------
4. Storm Water Multi-Sector USEPA Issued 1/16/98; For discharges of storm water
General Permit Expires 10/1/00 associated with industrial activities.
Renewal application
submitted. Operating under
prior permit.
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
5. Phase II Acid Rain Permit VADEQ Issued 1/1/98; Permit for Phase II of the SO(2)
Expires 12/31/02 allowance program under Clean Air Act
Title IV.
- ------------------------------------------------------------------------------------------------------------------------------------
6. Title V Operating Permit VADEQ Deemed Complete 3/4/98 Incorporates all emission sources.
Expires 12/31/02 Permit pending. Operating under permit
shield since application deemed
complete, which is typical of other
facilities.
- ------------------------------------------------------------------------------------------------------------------------------------
7. NO(X) RACT Consent Agreement VADEQ Issued 7/10/98 Establishes reasonably available
control technology standards for the
Potomac River Facility.
- ------------------------------------------------------------------------------------------------------------------------------------
8. Volatile Organic Compounds VADEQ Issued 5/8/00 Required control of VOCs by optimizing
Expires 12/31/02 ("VOC") RACT Permit combustion through
a digital control system.
====================================================================================================================================
Regulatory Compliance
The Mirant Mid-Atlantic Facilities are currently subject to various
state and federal regulations with respect to NO(X) and SO(2) emissions
including RACT requirements, Title IV of the Clean Air Act requirements, and
Title I Ozone Transport Commission requirements.
Title I NO(X) RACT Regulations
The location of the Mirant Mid-Atlantic Facilities in designated
ozone non-attainment areas triggered RACT requirements. A NO(X) averaging plan
is used to comply with the requirements. This entails over-controlling at
certain units to cover the other generating unit requirements. A consent
agreement with the VADEQ dated July 10, 1998 (the "VADEQ RACT Consent
Agreement") requires that the RACT averaging plan does not result in any greater
emissions than would have occurred with unit-by-unit RACT controls. The VADEQ
RACT Consent Agreement addresses the Chalk Point, Potomac River, Dickerson and
Morgantown Facilities under a NO(X) averaging plan. The VADEQ RACT Consent
Agreement sets NO(X) emission limits intended to address RACT requirements. The
VADEQ RACT Consent Agreement also implements NO(X) emission reductions designed
to bring northern Virginia and neighboring regions into full attainment with the
national ambient air quality standard for ozone. The VADEQ RACT Consent
Agreement along with the air quality permits contain specific emission limits
and monitoring requirements as well as other conditions that must be complied
with during the operation of the plant. The state of Maryland also
S-20
accepted the VADEQ RACT as representing RACT in accordance with Maryland
regulations by a letter dated August 2, 1996.
Title IV NO(X) Regulations
Chalk Point Units 1 and 2 are subject to Title IV requirements of
the Clean Air Act (these units are Phase I units under the Act) to meet the
presumptive NO(X) emission limit of 0.50 lb/MMBtu but, as allowed under Title
IV, requested and received from the USEPA interim AELs and the opportunity to
demonstrate it could not meet the presumptive limit. Final AEL petitions of 0.73
and 0.76 lb/MMBtu for Chalk Point Units 1 and 2, respectively, were submitted to
the USEPA on June 30, 1999 and are under review by the USEPA.
Dickerson Units 1, 2, and 3 are subject to Title IV of the Clean Air
Act (these units are Phase II units under the Act) to meet the presumptive NO(X)
emission limit of 0.50 lb/MMBtu, but as allowed under Title IV, filed an AEL
demonstration period petition with the USEPA on April 31, 2000, for the
opportunity to demonstrate it could not meet the presumptive limit. Interim AELs
requested in the petition are 0.60 lb/MMBtu for Dickerson Units 1, 2, and 3. The
petition is currently under review by the USEPA.
Morgantown Units 1 and 2 are subject to Title IV requirements (these
units are Phase I units under the Act) to meet the presumptive NO(X) emission
limit of 0.45 lb/MMBtu but, as allowed under Title IV of the Clean Air Act,
requested and received from the USEPA interim AELs and the opportunity to
demonstrate it could not meet the presumptive limit. We were informed by Mirant
that final AEL limits of 0.63 and 0.64 lb/MMBtu for Morgantown Units 1 and 2,
respectively, were received December 27, 2000.
The Potomac River Facility is subject to Title IV requirements of
the Clean Air Act (these are Phase II units under the Act) to meet the
presumptive NO(X) emission limit of 0.40 lb/MMBtu. Under Title IV, the Potomac
River Facility submitted an early election compliance plan for NO(X) and was
required to achieve 0.45 lb/MMBtu by the year 2000 deadline and, assuming
renewal of the Phase II permit in 2002, can defer the requirement to meet the
more stringent Phase II limit of 0.40 lb/MMBtu until 2008.
Title I NO(X) Allowances
The Title I of the Clean Air Act ozone transport requirements and
subsequent regulations pursuant to the Act, including the USEPA NO(X) SIP Call
and Section 126 petitions, target NO(X) emissions during the ozone season (May
through September). The Maryland generating units will be subject to allowance
requirements beginning in 2000. Maryland has adopted regulations allocating
allowances to individual units consistent with federal Title I ozone transport
requirements.
The Potomac River Facility is located in a severe non-attainment
area for ozone. The Clean Air Act called for Virginia to develop a SIP and reach
compliance by November 15, 1999. The VADEQ did not submit a SIP acceptable to
the USEPA and the attainment deadline was missed. The VADEQ subsequently
submitted a revised SIP that included proposed NO(X) emission limits for the
Potomac River Facility and on September 29, 2000, issued a state operating
permit to the Potomac River Facility that allocates 1,019 tons of NO(X)
allowances which cannot be exceeded without the facility purchasing additional
allowances to cover the excess emissions. The compliance date for meeting the
limit is May 1, 2003, the beginning of the ozone season. The permit allows the
trading of emissions from other generating units as a means to meet the emission
limit for the Potomac River Facility. No allowance requirements are in effect
until 2003 because Virginia did not sign the September 1994 MOU among Eastern
Regional Ozone Transport Commission states.
The allocation of allowances to the Mirant Mid-Atlantic Facilities
through 2020 is presented in Table 6.
S-21
Table 6
NO(X) Allowances
Mirant Mid-Atlantic Facilities
(Tons/Year)
Facility 2001-2002 2003-2020(1)
-------- --------- ---------
Chalk Point 5,159 2,551
Dickerson 1,693 1,520
Morgantown 5,057 2,596
Potomac River N/A 1,019
--------------
(1) Represents assumed allowances through the term of the
Projected Operating Results. Allowances beyond 2003 may be
adjusted with changes in regulations.
Mirant Mid-Atlantic will be required to obtain NO(X) allowances for
actual NO(X) emissions in excess of allocations for the year 2000 and beyond.
For NO(X) allowances, the current spot market is approximately $1,000 per ton
with prices fluctuating from approximately $500 to $7,500 per ton during 1999
and 2000. The cost of NO(X) allowances may be impacted in 2003 by the ratcheting
of allowances associated with the USEPA's ozone reduction program and the
associated installations of SCR by many plants. For the purpose of the Projected
Operating Results, we have assumed a NO(X) allowance price of $1,000 per ton
through 2002, $2,300 in 2003, $2,000 in 2004 and $1,700 in 2005. After 2005, the
NO(X) allowance price has been assumed to increase at the rate of inflation.
Title IV SO(2) Limitations - SO(2) Allowances
The Mirant Mid-Atlantic Facilities are subject to Phase II of the
federal Acid Rain Program of the Clean Air Act and, beginning in 2000, Mirant
Mid-Atlantic must possess SO(2) allowances equal to the actual emissions. Each
of the Mirant Mid-Atlantic Facilities was allocated a set of SO(2) allowances
for the years 2000 to 2009 and a second set after 2010. The SO(2) allowances
assumed through 2020 are presented in Table 7.
Table 7
Phase II SO(2) Allowances
Mirant Mid-Atlantic Facilities
(Tons/Year)
Facility 2000-2009 2010-2020(1)
-------- --------- ---------
Chalk Point 37,717 30,498
Dickerson 19,352 19,393
Morgantown 33,111 33,178
Potomac River 13,344 12,049
--------------
(1) Represents assumed allowances through the term of the
Projected Operating Results. Allowances may be adjusted with
changes in regulations.
Mirant Mid-Atlantic will be required to obtain SO(2) allowances for
actual SO(2) emissions in excess of allocations for the year 2000 and beyond.
Future cost of allowances will be market dependent and could be higher or lower
than the current values for such allowances. For the purpose of the Projected
Operating Results, we have assumed the present spot market price of SO(2)
allowances of approximately $150 per ton and have assumed that it would increase
annually at the rate of inflation.
S-22
Air Emissions
The air emissions presented in Table 8 have been used in the
Projected Operating Results to evaluate the need and associated costs of the
NO(X) and SO(2) allowances.
Table 8
Emissions and Limits
Mirant Mid-Atlantic Facilities
(lb/MMBtu)
Facility Current Projected Emission Limit
SO(2) NO(X)(1) SO(2) NO(X)(1)(13) SO(2) NO(X)(1)
----- -------- ----- ------------ ----- --------
Chalk Point
Unit 1 1.9 0.55 1.9 0.05 3.5 0.73
Unit 2 1.9 0.55 1.9 0.05 3.5 0.76
Unit 3 0.22 0.15 0.22 0.15(14) 0.3%-2%(4) 0.32
Unit 4 0.22 0.15 0.22 0.15(14) 0.8; 0.3%(6) 0.3
CTs (2) 0.06-1.2 (2) 0.06-0.15(14) 0.3%-0.8%(7) 25-57(8)
Dickerson
Unit 1 1.78 0.5 1.78 0.36 2.8 0.6
Unit 2 2.09 0.5 2.09 0.36 2.8 0.6
Unit 3 1.9 0.5 1.9 0.36 2.8 0.6
CTs (2) 0.13 (2) 0.13 34(9), 579(10) 42-77(8)
Morgantown
Unit 1 2.17 0.49 2.17 0.13 3.5%; 2%; 3%(11) 0.64
Unit 2 2.12 0.46 2.12 0.13 3.5%; 2%; 3%(11) 0.66
CTs 0.62-1.2 0.62-1.2 0.3%(12) 1.2
Potomac River
Unit 1 1.1 0.41 1.1 0.41 1.52 0.77
Unit 2 1.1 0.37 1.1 0.37 1.52 0.77
Unit 3 1.1 0.44 1.1 0.17 1.52 0.86
Unit 4 1.1 0.44 1.1 0.17 1.52 0.86
Unit 5 1.1 0.44 1.1 0.17 1.52 0.86
- --------------
(1) During ozone season, May through September.
(2) Negligible.
(3) Alternative emission Limit.
(4) 2% sulfur No. 6 fuel oil; 0.35 sulfur No. 2 fuel oil.
(5) No. 6 fuel oil.
(6) 0.8 lb/MMBtu No. 6 fuel oil and 0.3% No. 2 fuel oil.
(7) Natural gas and No. 2 fuel oil.
(8) Range in parts per million, dry volume basis at 15% oxygen for the
various units fired on natural gas and oil.
(9) Pounds per hour on natural gas.
(10) Pounds per hour on oil with 3% sulfur content.
(11) Maximum permitted percentage of sulfur in coal, No. 2 and No. 6 fuel
oil.
(12) Maximum permitted percentage of sulfur in No. 2 fuel oil.
(13) Projected NO(X) emissions based on planned retrofits of: (a)
low-NO(X) burners at Chalk Point Units 1 and 2 in 2002 at an
emission rate of 0.25 lb/MMBtu of NO(X); (b) SCRs at Chalk Point
Units 1 and 2 in 2006 and 2008, respectively; (c) secondary overfire
air at Dickerson Units 1, 2 and 3 in 2002, 2003 and 2003,
respectively; (d) SCRs at Morgantown Units 1 and 2 in 2006 and 2008,
respectively; (e) co-firing of oil and coal at Morgantown Units 1
and 2 in 2002 at 0.36 lb/MMBtu of NO(X); and (f) low-NO(X) burners
and secondary overfire air at Potomac River Units 3, 4 and 5 in
2007, 2007 and 2008, respectively.
(14) Based on gas.
Wastewater Compliance
Chalk Point Units 1 and 2 are permitted to withdraw a maximum of
1,100 million gallons per day ("mgd") of water from the Patuxent River for
once-through condenser cooling. Chalk Point Units 3 and 4 use natural draft
cooling towers for condenser cooling. Up to 43 mgd of water is used for makeup
of Chalk Point Units 3 and 4 losses due to evaporation and for process water
uses throughout the Chalk Point Facility. Process wastewater
S-23
originates from boiler blowdown, neutralized demineralizer regenerant, coal pile
runoff, cooling tower blowdown, ash hopper overflows, plant drains and oil/water
separator effluent. These wastewater streams are directed to a settling basin
before discharge to the cooling water canal. The NPDES permit for the Chalk
Point Facility includes limitations on temperature and total residual oxidants
for cooling water and limitations on total suspended solids, oil and grease and
pH for discharge from the sediment pond. Sanitary sewage is treated by a small
on-site sewage treatment plant and the sludge is hauled off-site for disposal.
The wastewater discharge compliance history of the Chalk Point Facility does not
indicate any future non-compliance trends.
An NPDES Permit regulates the Dickerson Facility's wastewater
effluents. The Dickerson Facility is permitted to discharge once-through cooling
water, runoff, sewage treatment effluent, backwash and other miscellaneous
wastewater into the Potomac River and tributaries. The cooling water temperature
increase and maximum heat rejection are limited under the terms of the permit
along with residual chlorine and pH. The other discharges are limited with
respect to suspended solids, oil and grease, biochemical oxygen demand and fecal
coliform depending upon the source of the effluent. The wastewater discharge
compliance history of the Dickerson Facility does not indicate any future
non-compliance trends.
Morgantown Units 1 and 2 are permitted to withdraw a maximum of
2,400 mgd of water from the Potomac River for once-through condenser cooling and
plant process water. Process wastewater originates from boiler blowdown,
neutralized demineralizer regenerant, coal pile runoff, ash hopper overflows,
plant drains and oil/water separator effluents. These wastewater streams are
directed to a primary settling basin for pH adjustment and then to a secondary
settling pond before discharge to the cooling water canal. The draft NPDES
permit for the Morgantown Facility includes limitations on temperature and total
residual oxidants for the cooling water, limitations on copper and iron for
chemical cleaning wastes, and limitations on total suspended solids, oil and
grease and pH for discharge from the secondary settling pond. Sanitary sewage is
treated by a small on-site sewage treatment plant and the sludge is hauled
off-site for disposal. The wastewater discharge compliance history of the
Morgantown Facility does not indicate any future non-compliance trends.
An NPDES Permit regulates the Potomac River Facility's wastewater
effluents. The permit allows for discharges of cooling water, ash clarifier
water, neutralization wastewater and miscellaneous wastewater to the Potomac
River. The cooling water maximum heat rejection is limited under the terms of
the permit along with residual chlorine. The other discharges are limited with
respect to suspended solids, oil and grease, and pH. The wastewater discharge
compliance history of the Potomac River Facility does not indicate any future
non-compliance trends.
Future Environmental Requirements
Certain future requirements relative to the revised PM(2.5)
standard, regulation of mercury emissions, regional haze, regional visibility,
water intake structure regulations, and potential ratcheting of the SO(2)
allowance program beyond the year 2009 may affect the Mirant Mid-Atlantic
Facilities in the future by imposing more stringent requirements than those in
effect at the present time.
The USEPA is presently collecting particulate ambient data to
classify the attainment status of areas in association with the PM(2.5)
standard. Monitoring data is expected to be complete between 2001 and 2004.
Allowing time for data analysis, the USEPA will likely designate areas as
attainment/non-attainment between 2002 and 2004. State Implementation Plan
revisions for PM(2.5) would be due at the earliest 2005. In addition, PM(2.5) is
viewed as a regional problem (i.e., particulate non-attainment in one county may
be caused by distant sources). Because of the extended compliance schedule,
future emission reduction requirements that may be imposed on the Mirant
Mid-Atlantic Facilities, if any, cannot now be determined.
Section 316(b) of the Clean Water Act, provides that cooling water
intake structures must "reflect the best technology available for minimizing
adverse environmental impact." Although the USEPA issued a final regulation
under section 316(b) in 1976, the regulation was challenged in Court and
subsequently withdrawn by the USEPA. Since then there has been no regulation
governing cooling water intake structures. Because of legal action, the USEPA
and certain environmental organizations entered a consent decree in 1995 that
provided for the USEPA to issue cooling water intake regulations. Delays by the
USEPA resulted in additional legal action and in April of 2000, a
S-24
court order was issued that established new deadlines for proposal of regulation
for existing facilities by July 20, 2001. Until such regulations are issued, the
requirements that may be imposed on the Mirant Mid-Atlantic Facilities, if any,
cannot now be determined.
In November of 1999, the USEPA issued NOVs to owners and operators
of 32 coal-fired electric generating plants, charging that over many years these
plants had been changed or modified in ways that resulted in increased emission
of pollutants and that the plants did not obtain new source permits or
prevention of significant deterioration permits applicable to new or modified
sources. None of the assets included herein have been issued such NOVs. Mirant
received a request for information dated January 10, 2001 from the USEPA,
pursuant to its authority under the Clean Air Act, requiring Mirant to provide
records and information relevant to the operation and maintenance history of the
Potomac River, Chalk Point, Dickerson and Morgantown Facilities. Mirant and
Mirant Mid-Atlantic are in the process of responding to the request for
information. While we cannot predict future USEPA actions, should such notices
of violations be issued to any of the assets, the cost to comply could be
substantial. While we cannot predict the result of future reviews of the Mirant
Mid-Atlantic Facilities, if any, by the USEPA, given: (1) the age of the Mirant
Mid-Atlantic Facilities; (2) the renewals and replacements undertaken; and (3)
that those planned for the future are intended to allow the Mirant Mid-Atlantic
Facilities to operate in a more dependable and reliable manner, we have assumed
that the Mirant Mid-Atlantic Facilities are not subject to New Source Review.
Should the USEPA determine that any renewals and replacements undertaken at the
Mirant Mid-Atlantic Facilities are subject to New Source Review and New Source
Performance Standards, the cost to comply could be substantial.
In April of 2000, the USEPA determined that regulation of fossil
fuel combustion wastes as hazardous wastes under Subtitle C of the Resource
Conservation and Recovery Act ("RCRA") is not warranted. This determination
covers the following wastes: (1) large-volume coal combustion wastes generated
at electric utility and independent power producing facilities that are
co-managed together with certain other coal combustion wastes; (2) coal
combustion wastes generated at non-utilities; (3) coal combustion wastes
generated at facilities with fluidized bed combustion technology; (4) petroleum
coke combustion wastes; (5) wastes from the combustion of mixtures of coal and
other fuels (i.e., co-burning of coal with other fuels where coal is at least 50
percent of the total fuel); (6) wastes from the combustion of oil; and (7)
wastes from the combustion of natural gas.
While these wastes remain exempt from Subtitle C, the USEPA also
determined to establish national regulations under Subtitle D for coal
combustion wastes that are disposed in landfills or surface impoundments or used
to fill surface or underground mines. No schedule for developing the regulations
was proposed and the impact on the Mirant Mid-Atlantic Facilities, if any,
cannot be determined; however, Mirant Mid-Atlantic has included approximately
$34,300,000 in 2000 dollars through 2020 in its capital expenditure budget for
upgrades to liners and/or monitoring associated with ash storage.
MIRANT CALIFORNIA FACILITIES
Description of the Contra Costa Facility
Mechanical Equipment and Systems
Steam Cycle and Heat Rejection Systems and Components
The Contra Costa Facility Units 6 and 7 consist of two B&W
single-drum boilers and two Westinghouse steam turbines. Each unit has two
Westinghouse generators and shaft-driven boiler feed pumps driven by a single
Westinghouse cross compound, four-flow, reheat condensing stream turbine. Contra
Costa Units 6 and 7 both utilize single drum, forced draft, natural
recirculation, gas-fired B&W boilers which each include pressurized radiant-type
furnace, continuous tube superheater, reheater and economizer. Each unit has a
net capacity of 340 MW and both began commercial operation in 1964. Units 1, 2
and 3 were decommissioned in 1994; however, they could run, if required, with
capital expenditure and permit reinstatement. Units 4 and 5 have been converted
to synchronous condensers and are only used for that purpose. The plant utilizes
natural gas as its primary fuel and fuel oil as an alternate boiler fuel.
However, it would take some 30 days to prepare the plant to burn fuel oil.
S-25
Contra Costa Units 6 and 7 both utilize single-drum B&W boilers,
which each include a pressurized radiant-type furnace, continuous tube
superheat, reheater and economizer. The forced-draft boilers deliver 2,160,000
lb/hr of steam at 1,053(degree)F, 2,475 psig at the superheater level and
1,960,000 lb/hr of steam at 1,003(degree)F psig. Both utilize two 179,520 kW
generator nameplate capacity steam turbine generators manufactured by
Westinghouse. The four-flow, cross-compound, condensing, reheat turbines include
shaft-drive boiler feed pumps.
Fuel System
The Contra Costa Facility utilizes natural gas as its primary fuel,
which is supplied via a transmission pipeline from PG&E's Antioch Gas Terminal.
Fuel oil, used as an alternate boiler fuel, has not been used in the generation
process in recent years but is still stored on site in the event of a
curtailment of natural gas to the plant. Nine above ground storage tanks
("ASTs") are at the site with a combined capacity of 2.2 million barrels of fuel
oil. About 20 percent of that capacity remains in storage on site. Additional
fuel oil can be delivered to the plant via an underground pipeline connecting
the Contra Costa Facility with the Pittsburg Facility or via a marine terminal
and 12-inch pipeline located within the Bay Delta. This terminal is not in use
and has been in caretaker status since 1984.
Water Systems
All Contra Costa Facility units use once-through cooling. The
cooling water is supplied from the San Joaquin River. Cooling water is
circulated through condenser tubes to condense the steam driving the turbines.
It is then discharged back to the water source. The Contra Costa Facility
utilizes river water to supply reverse osmosis units that provide make-up water
to the boilers for steam generation. If salinity levels in the river increase,
the Contra Costa Water District supplies the reverse osmosis units. Potable
water is also supplied by this water district.
Fire Protection System
At the Contra Costa Facility, a basin supplies main, auxiliary and
jockey electric monitor pumps to maintain constant pressure on the fire header.
The fire header is also backed up by three diesel fire pumps. The diesel pumps
are only used for emergencies or when maintenance is required on the electric
pumps.
Electrical and Control Systems
Electrical Distribution
The Contra Costa Units 6 and 7 generating station electrical
arrangement includes four generator units connected to a 230 kV bus, with
station auxiliary power derived from the parallel generator output. The two
generators both connect to a single step-up transformer rated 18/230 kV, 384 MVA
with forced oil/air cooling. The 230 kV bus accommodates other Contra Costa
generators and is connected to the Bay area transmission system.
Emergency Power Systems
The Contra Costa Facility has no black start capability.
Plant Control Systems
Contra Costa Units 6 and 7 boiler, burner, management and combustion
controls are provided by Bailey Net 90 DCS with turbine controls provided by a
Westinghouse Electro Hydraulic System as directed by the Bailey DCS.
Environmental Controls and Equipment
Air Emissions
Emissions control is achieved through operating control schemes
incorporating overfire air ports and/or flue gas recirculation ("FGR"). Contra
Costa Unit 7 also uses low-NO(X) burners, which were installed in 1997. NO(X)
and CO emissions from the Contra Costa Facility are and will be controlled to
meet environmental regulatory limits through a combination of recent combustion
modifications, operational practices, such as control of excess air
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levels, and dispatch provisions. Recent combustion modifications in 2000 include
retrofit of the Contra Costa Unit 6 boiler with low-NO(X) burners.
Wastewater/Solid Waste Disposal
The process cooling water is circulated through the condenser and
then discharged back to the San Joaquin River. Sanitary waste is connected to
the city/county system. Solid waste is collected by an independent contractor
for removal from the site and appropriately disposed of.
Off-Site Requirements
Fuel Supply
MAEM is responsible for the procurement and delivery of natural gas
to each of the plant sites, and Mirant Delta pays MAEM its actual fuel supply
and trasnsportation costs.
Electrical Interconnection
The Contra Costa Facility is connected to a 230 kV switchyard that
is a sectionalized, double-bus, single-breaker arrangement with eight
transmission line positions, four connecting to Bay area sources and four
connecting to Bay area load centers.
Description of the Pittsburg Facility
Mechanical Equipment and Systems
Steam Cycle and Heat Rejection Systems and Components
Pittsburg Units 1 through 4 each consist of a single-drum B&W boiler
and a GE steam turbine with net capacities of 150 MW each. Pittsburg Units 1
through 4 began commercial operation in 1954. These units typically run as
peakers.
Pittsburg Units 1 through 4 each consists of a GE tandem compound,
triple-flow, condensing, reheat steam turbine. The units utilize B&W radiant,
single-drum, forced-draft, natural circulation, gas fired, boilers which include
two-stage superheaters and primary and secondary reheaters. The boilers were
originally designed to burn natural gas as a primary fuel with fuel oil as back
up fuel, but are no longer capable of firing oil without changes to the boiler
burners and permits. Each radiant, natural-circulation, single-drum boiler
includes a water-cooled furnace, two-stage convection superheater and reheater
consisting of a horizontal primary and pendant-type secondary unit, and two
Ljungstrom regenerative air preheaters. The boilers each provide 1,134,000 lb/hr
of steam at 1,000(degree)F, 1,850 psig at the superheat outlet and 1,020,000
lb/hr of steam at 1,000(degree)F, 456 psig at the reheater outlet. They also
utilize GE steam turbines operating at 3,600 rpm. The tandem compound,
triple-flow, condensing, reheat steam turbines provide for seven-point,
non-automatic extraction. The units each have a nameplate capacity of 156,230 kW
for the steam turbine generator.
Pittsburg Units 5 and 6 both utilize B&W radiant, single-drum
boilers. The natural-circulation, forced-draft boilers each include a
pressurized furnace, drainable two-stage superheater, drainable continuous
reheater and two-section continuous economizer. Both are capable of generating
2,160,000 lb/hr of steam at 1,050(degree)F, 2,475 psig at the superheater outlet
and 1,965,900 lb/hr of steam at 1,000(degree)F, 505 psig at the reheater outlet.
Pittsburg Unit 5, with a net capacity of 325 MW, consists of a
Westinghouse cross compound, four-flow, condensing reheat steam turbine with two
generators and a shaft-driven boiler feed pump. Pittsburg Unit 6 consists of a
GE cross-compound, four-flow, condensing reheat steam turbine generator and a
shaft-driven boiler feed pump. Both units utilize B&W radiant, single-drum,
forced-draft, natural circulation, gas-fired boilers which include two-stage
superheaters, two-stage reheaters and two-section continuous economizers.
Pittsburg Units 5 and 6 were placed in service in 1960 and 1961, respectively.
The boilers were originally designed to burn natural gas as a primary fuel with
fuel oil as back up fuel, however are no longer capable of firing oil without
substantial changes to the boiler
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burners and permits. Each generator has a nameplate capacity of 163,200 kW and
includes a shaft-driven boiler feed pump.
Pittsburg Unit 7 has a net capacity of 682 MW and began commercial
operation in 1972. Pittsburg Unit 7 is comprised of a Westinghouse generator
driven by a Westinghouse tandem compound, four-flow, condensing, single-reheat
steam turbine driving the generator. Pittsburg Unit 7 utilizes a single drum,
forced draft, combined-circulation, gas fired, supercritical boiler manufactured
by CE which includes primary and secondary superheaters, a reheater,
desuperheating spray systems and an economizer. The turbine-generator has a
751,140 kW generator nameplate capacity. The steam turbine is a four-cylinder,
tandem-compound, condensing, single-reheat unit operating at 3,600 rpm.
The Pittsburg Unit 7 combined-circulation, supercritical boiler was
manufactured by CE and includes a furnace wall system with circulating pumps,
primary and secondary superheaters, a reheater, desuperheating spray systems and
economizer. The radian, forced-draft boiler provided 5,360,400 lb/hr of steam at
1,005(degree)F, 3,818 psig at the superheater outlet and 4,510,240 lb/hr of
steam at 1,005(degree)F, 725 psig at the reheater outlet.
Fuel System
All units at the Pittsburg Facility utilize natural gas, supplied
via a transmission pipeline from PG&E's Antioch Gas Terminal, as a primary fuel.
The plant continues to store fuel oil at the site in the event of a natural gas
shortage or curtailment; however, in recent years it has not been used in the
generation process. It would take at least 30 days to prepare the facility to
burn fuel oil. Fuel oil is stored in four service tanks and 12 ASTs on site. The
tanks, located in two tank farms situated in the northeast and southeast
portions of the site, have a storage capacity of 5.7 million barrels of fuel
oil. About 20 percent of that capacity is currently stored on site. Delivery of
fuels oil is via a marine terminal and 12-inch pipeline located within the Bay
Delta or via an underground pipeline connecting the Pittsburgh Facility with
Chevron's Richmond Refinery. The terminal has not been used for approximately
six years; however, is still considered to be in active status.
Water Systems
All of the Pittsburg Facility units except for Pittsburg Unit 7 use
once-through cooling. The cooling water is supplied from the Suisun Bay for the
Pittsburg Facility. The cooling water is circulated through condenser tubes to
condense the steam driving the turbines. It is then discharged back to the water
source.
Pittsburg Unit 7 uses two cooling towers in a closed-circulating
water cycle. Water is supplied via a mile-long cooling canal to the condenser.
The warm circulating water is discharged back to the canal where it travels to
the towers for cooling and then once again is returned to the canal. Make-up
water is supplied from Suisun Bay.
The Pittsburg Facility utilizes river water to supply reverse
osmosis units that provide make-up water to the boilers for steam generation. A
12-inch supply line from the Contra Costa Water District also supplies the
reverse osmosis units at the Pittsburg Facility when river salinity reaches
established limits. This line is primarily used during summer months. The river
water intake is located west of the fuel oil dock in the Pittsburg Unit 7 and
Pittsburg Unit 7 intake tunnel, providing a single supply line to the reverse
osmosis units.
Potable water is supplied to the Pittsburg Facility by the City of
Pittsburg. Water is also supplied to the switchyard through the city water line.
Fire Protection System
Water for the Pittsburg Facility fire protection system is supplied
via the screen intakes at the headworks located north of the intake screens for
Pittsburg Units 1 through 4. A basin supplies main, auxiliary and jockey
electric monitor pumps to maintain constant pressure n the fire header. The fire
header is also backed up by three diesel fire pumps located on the inlet side of
the cooling towers for Pittsburg Unit 7. The diesel pumps are only used for
emergencies or when maintenance is required on the Pittsburg Units 1 through 4
pumps.
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Electrical and Control Systems
Electrical Distribution
The Pittsburg Facility electrical arrangement includes nine
generator units connected to a 115 kV and 230 kV bus, with station auxiliary
power derived from each generator output. Both buses are connected to the Bay
area transmission system.
Emergency Power Systems
The Pittsburg Facility does not have black start capability.
Plant Control Systems
Most of Pittsburg Units 1 through 4 boiler controls is Bailey
pneumatic controls original to the plant; however, some control loops have been
upgraded to electronic single-loop controllers. Turbine controls for these units
are the original GE MH systems.
Pittsburg Unit 5 boiler controls have been upgraded to Bailey Infi
90 DCS with some boiler temperature and generator gas temperature monitoring
having been changed to a Foxboro Intelligent Automation System. Turbine control
for this unit is provided by a Westinghouse EH System as directed by the Bailey
DCS.
Pittsburg Unit 6 boiler controls have been upgraded to Bailey Infi
90 DCS, and the turbine control is provided by the original GE MH System, as
directed by the Bailey DCS. A data acquisition system has also been installed at
Pittsburg Unit 6.
The Pittsburg Unit 7 boiler, burner management and combustion
controls are provided by the original Westinghouse Prodac 2000 and 250 computers
with the turbine control provided by the original Westinghouse Digital Electric
Hydraulic system. A condenser performance monitoring system is also in place on
Pittsburg Unit 7.
Environmental Controls and Equipment
Air Emissions
Emissions control is achieved through operating control schemes
incorporating overfire air ports and/or FGR. NO(X) and CO emissions from the
Pittsburg Facility are and will be controlled to meet environmental regulatory
limits through a combination of recent and planned combustion modifications and
operational practices. The recent combustion modifications include installation
of low-NO(X) burners on Pittsburg Unit 6. A similar low-NO(X) burner
installation is scheduled for the first half of 2001 on Pittsburg Unit 5.
Wastewater/Solid Waste Disposal
The process cooling water is circulated through the condenser and
then discharged back to the Suisun Bay, except for Pittsburg Unit 7. The
Pittsburg Unit 7 process cooling water goes through a cooling tower prior to
going to the bay. Sanitary waste is connected to the city/county system. Solid
waste is collected by an independent contractor for removal from the site and
appropriately disposed.
Off-Site Requirements
Fuel Supply
MAEM is responsible for the procurement and delivery of natural gas
to each of the plant sites, and Mirant Delta pays MAEM its actual fuel supply
and trasnsportation costs.
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Electrical Interconnection
The Pittsburg Facility is connected to a 115 kV switchyard (Units 1
and 2) and a 230 kV switchyard (Pittsburg Units 3, 4, 5, 6 and 7). The two
switchyards are interconnected with a transformer. The 115 kV switchyard is a
double-bus single-breaker arrangement with six transmission line positions, all
supplying local networks serving different load centers. The 230 kV switchyard
is a double-bus, single-breaker arrangement with eight transmission line
positions, two connecting to Bay area sources and six connecting to Bay area
load centers.
Description of the Potrero Facility
Mechanical Equipment and Systems
Steam Generators
The Potrero Unit 3 boiler is manufactured by Riley Stoker
Corporation and incorporates a pressurized furnace, water cooled walls, two
forced-draft fans, two Ljungstrom regenerative air preheaters, a superheater,
reheater and economizer. The radiant, single drum boiler has a capacity of
generating 1,505,163 lb/hr of steam at 1,003(degree)F, 1,850 psig at the
superheater outlet and 1,338,776 lb/hr of steam at 1,003(degree)F, 545 psig at
the reheater outlet. Potrero Unit 3 was placed in service in 1965. Potrero Unit
3 was set up to fire natural gas and/or No. 6 oil; however, Potrero Unit 3 has
not been fired on oil since 1994.
Turbine Generators
Potrero Unit 3 utilizes a Westinghouse steam turbine-generator with
a generator nameplate capacity of 217,855 kW. The Potrero Unit 3 generator is a
20 kV, two-pole, hydrogen-cooled Westinghouse steam turbine unit rated 256.3 MVA
at a power factor of 0.85, 60 psig. The generator is equipped with a brushless
excitation system and connects to two step-up transformers, each rated 20/115
kV, 120 MVA, with forced oil-air cooling.
The steam turbine, operating at 3,600 rpm, is a two-cylinder, tandem
compound, double-flow, condensing, reheat unit with a shaft-driven boiler feed
pump.
Combustion Turbines
Potrero Units 4 through 6 each have a net capacity of 52 MW and
incorporate dual FT4 Pratt and Whitney aero-derivative CTs in twin-pac
arrangement with Electric Machinery Company generators. In commercial operation
since 1976, Units 4 through 6 utilize distillate fuel as a primary fuel.
Potrero Units 4, 5 and 6 generators are 13.8 kV, two-pole Pratt and
Whitney CT generators rated 74.5 MVA at a power factor of 0.9. Each unit's
generation nameplate capacity is 67,050 kW. Each generator is equipped with a
brushless excitation system and connects through a circuit breaker to an
oil-filled step-up transformer rated 13.8/115 kV, 36/48/60 MVA with two stages
of forced air cooling.
Fuel System
Although fuel oil is available as an alternate boiler fuel for
Potrero Unit 3, this unit utilizes natural gas delivered via a transmission
pipeline that runs along 23rd Street to the site as its primary fuel. Three
separate lines deliver gas to the site from this main transmission line. The
maximum capability of the gas delivery system is 3.6 million standard cubic feet
per hour.
Potrero Units 4 through 6 utilize distillate fuel as a primary fuel,
delivered to the site via a 12-inch pipeline, by barge to the plant dock, or by
truck. The primary method of delivery currently employed is by truck. Distillate
fuel for the CTs 4, 5 and 6 is stored in a 125,000-barrel capacity tank on site.
Although heavy fuel oil is stored on site as an alternate boiler
fuel, it has not been used in the generation process in recent years. Fuel oil
is delivered to the plant via an oil tanker mooring at a marine terminal located
one-half mile north of the plant at Pier 70 and is then off-loaded at the
terminal and delivered to the plant via a
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20-inch pipeline. Two storage tanks with a combined capacity of 393,000 barrels
are located in the northern portion of the plant site.
Water Systems
Potrero Unit 3 draws seawater from the San Francisco Bay through
intake channels on the east side of the plant for once-through cooling. The
cooling water is then circulated through condenser tubes that cool the steam
from the steam turbine generator and return it to the Bay on the east side of
the plant. The city supplies make-up water to the boilers for steam generation
at Potrero Unit 3 and for controlling NO(X) emissions from the CTs at Potrero
Units 4 through 6. A demineralizer is located on the plant site; however, it is
no longer operational and rental equipment is used to demineralize water at the
plant. City water is used for potable water and for the fire system.
Fire Protection System
Fire protection is supplied by the city water system. Pressure and
flow are boosted with fire protection pumps on site.
Electrical and Control Systems
Electrical Distribution
The Potrero Units 3, 4, 5 and 6 generating station electrical
arrangement includes four generators connected to a 115 kV bus, with station
auxiliary power derived from each generator output. The 115 kV bus is connected
to the Bay area transmission system.
Plant Control Systems
Potrero Unit 3, as a result of recent control system upgrades, now
has unit annunciator, boiler steam temperature and NO(X) controls implemented in
a WDPF Level 7 DCS. The remaining combustion and drum-level controls are handled
by the original pneumatic control scheme. The turbine is controlled by the
original Westinghouse 300-pound MH Control System and includes automatic
generation control capacity.
Control system for the CTs located at Potrero Units 4 through 6 was
upgraded in 1992 to a Woodward 5000 DCS, which provides all annunciation and
automatic start-up, paralleling and loading functions. Start, stop and
monitoring functions for the units are preformed remotely from the Potrero Unit
3 control room.
Emergency Power System
By first starting the Potrero Units 4, 5 and 6 gas turbines, the
Potrero Facility has black-start capability.
Environmental Controls and Equipment
Air Emissions
Potrero Unit 3 emissions control is achieved through boiler NO(X)
control schemes incorporating FGR and overfire air ports. Potrero Units 4
through 6 control emissions by injecting water into the unit at a water-to-fuel
ratio of 0.7:1.0.
Wastewater/Solid Waste Disposal
The process cooling water is circulated through the condenser and
then discharged back to the San Francisco Bay. Sanitary waste is connected to
the city/county system. Solid waste is collected by an independent contractor
for removal from the site and appropriately disposed.
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Off-Site Requirements
Fuel Supply
MAEM is responsible for the procurement and delivery of distillate
fuel and natural gas to the plant site, and Mirant Potrero pays MAEM its actual
fuel supply and trasnsportation costs.
Electrical Interconnection
The Potrero Facility is connected to a 115 kV PG&E switchyard that
is a double-bus, single-breaker arrangement. The plant's switchyard is connected
to the transmission grid through five underground cables. Two cables travel
northwest and connect and supply power to the Larkin Substation in San
Francisco. A third cable runs in the same direction and connects and supplies
power to the Mission Substation in San Francisco. Two other cables travel
southward connecting to the Martin Substation in Daly City. Each cable also
supplies a distribution transformer at the Bayshore Substation, which serves the
Bay Area Rapid Transit's needs for traction power. The total capacity of the 115
kV interconnection is 724 MVA.
Additionally, two 115/12 kV distribution transformer banks are
directly connected to and supplied from the Potrero PG&E switchyard. The
capacity of this 12 kV system is 130 MVA.
Operation and Maintenance
The Contra Costa Facility
The Contra Costa Facility is operated utilizing four 12-hour
operating shifts. One full shift is on day shift and is available for shift
relief due to vacation or sickness, to perform maintenance or other support
activities and to participate in the plant training programs. The structured
training program covers the plant systems and is made up of textbooks,
on-the-job training, and specific vendor training. Tests are available for
operations, maintenance, and instrument and control personnel to improve skills.
A training simulator has been available through PG&E and will probably be made
available by Mirant California in the future.
Inspection of main steam and reheat piping and hangars is conducted
on a continuing basis as part of the High Energy Piping System Program.
Inspections of these systems include the hot and cold positions and determining
system condition by using various non-destructive testing techniques. Boiler
water wall tubes are sampled annually and ultrasonic testing or similar testing
is conducted periodically based on wear patterns as part of the High Energy
Piping System Program.
Plant personnel continuously review the plant performance and
condition in order to identify areas of improvement and propose betterment
programs to maintain reliability and efficiency. Performance monitoring is
conducted by tracking and monitoring data that can be utilized to predict the
expected effect of a change in operation. It is used to predict NO(X) and CO
relationships for better control of emissions. Computer modeling capability is
fully installed in Contra Costa Unit 6. It is also used to enhance heat rate and
peak load capability.
The Contra Costa Unit 6 boiler was last inspected in March and April
1998 when the normal boiler permit and waterwall tube inspections were
conducted. The normal permit inspection for Contra Costa Unit 7 was also
completed in April 1998. The Contra Costa Unit 6 boiler received its last
chemical cleaning in June 1999. The Contra Costa Unit 7 boiler was chemically
cleaned in June 1997.
NO(X) reduction modifications were installed on the Contra Costa
Unit 6 boiler in March 1998. Low-NO(X) burners were installed on this boiler in
2000. Low-NO(X) burners were installed in Contra Costa Unit 7 in June 1997.
Contract Costa Unit 7 upgrade included installation of overfire air ports, new
forced draft fan motors, new FGR fan motors and a new burner management system.
The Contra Costa Unit 6 steam turbine generator experienced
excessive vibration on the intermediate pressure ("IP") generator bearings in
May 1995. Hydrogen seal rings were replaced, with special care taken to ensure
that the gland bracket angle was established in accordance with vendor
requirements.
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In November 1996, the Contra Costa Unit 6 auxiliary transformer
shorted out due to operator error with the unit in service. The auxiliary
transformer remained out of service for four months, however, Contra Costa Unit
6 remained in service by utilizing the startup transformer.
In April 1997, the Contra Costa Unit 6 turbine throttle valves stuck
during valve testing, necessitating disassembly, cleaning, honing and
reinstallation. The unit was out of service approximately two weeks.
In September 1997, the Contra Costa Unit 6 main transformer was
shorted out at full load when a disconnect switch came apart and fell across the
transformer. The unit was out of service for about nine months and came back in
service for peak period with a transformer purchased from Los Angeles Department
of Water and Power.
In March 1997, the oil system failed on the Contra Costa Unit 5
synchronous condenser, resulting in wiped bearings. Cause of the event was a
leaking hydrogen cooler that leaked water onto a lube oil pump motor, causing it
to fail. The field was removed and cleaned and the failed hydrogen cooler was
replaced along with bearing repairs. The unit was out of service approximately
three months.
Commencing at the end of 2000 and extending into 2001, Contra Costa
Unit 6 had low-NO(X) burners installed, boiler tube repairs completed and a new
turbine generator seals installed.
The Contra Costa Facility employs a high energy piping inspection
program in which selected portions of piping and components are inspected as
part of the boiler inspection and overhaul outages. The program is designed to
ensure safe and reliable operation to protect personnel and maintain unit
availability. Components that contain steam or water at greater than
200(degree)F, such as longitudinally welded hot reheat lines, feedwater heaters
and boiler feed pump recirculation lines are monitored and periodically
inspected.
The Pittsburg Facility
In December 1995, the main generator exciter was damaged on
Pittsburg Unit 7 when the exciter developed a phase-to-phase short. The unit was
operated with two mobile exciters taken from Pittsburg Unit 5 until the
Pittsburg Unit 7 exciter was rebuilt.
Excessive vibration was noted in the Pittsburg Unit 6 IP/LP turbine
in March 1998. This was caused by a crack in the rotor. Repairs were made and
the unit returned to service in about 10 weeks.
High vibration was noted on the high pressure ("HP")/LP turbine of
Pittsburg Unit 5 in November 1997. A damaged section of turbine blade shroud was
the cause. The unit was off line for about 10 weeks to make repairs to the
shroud. In March 1999, high vibration was again experienced, caused by a crack
in the turbine rotor. Due to the lengthy repair period needed to correct this
deficiency, the unit was put into full overhaul status and was out of service
for 14 weeks.
Pittsburg Unit 3 experienced a short in the generator "C" phase in
December 1997 due to a foreign object stuck in the stator windings. The unit was
out of service approximately four weeks following winding repair and rewrapping.
Boiler chemical cleaning was performed on Pittsburg Unit 7 in March
1998; on Pittsburg Unit 6 in June 2000; and on Pittsburg Unit 5 in March 1998.
Pittsburg Unit 1's last chemical cleaning occurred in January 1990, however,
Pittsburg Units 2 through 4 cleanings are expected to be completed in 2001.
In November 1997, Pittsburg Unit 5 experienced high vibration on the
HP/LP section of the steam turbine which caused the unit to be taken out of
service. A lifted shroud caused the vibration. The shroud was repaired and the
unit returned to service approximately 10 weeks later.
In March 1998, Pittsburg Unit 6 experienced high vibration caused by
a crack in the IP/LP rotor. The rotor was removed and sent to Charlotte, North
Carolina for repairs by Westinghouse. The crack was ground out and welded. The
unit was returned to service approximately 10 weeks later.
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In March 1999, Pittsburg Unit 5 experienced high vibration caused by
a crack in the HP/LP rotor. The rotor was sent to Charlotte, North Carolina for
repairs. The crack was almost 360(degree). The piece was separated and all poor
metal removed and welded back together. With the work scope expanded for
repairs, the unit was put into full overhaul. The unit was returned to service
approximately 14 weeks later.
Pittsburg Units 1 through 4 experienced eight condenser tube leak
incidents from 1994 to 1998, most of them in Pittsburg Unit 2. Only one of these
was a forced outage. The other seven occurrences resulted in forced
curtailments. Of the total forced outage and curtailment hours, all but seven
were charged to Pittsburg Unit 2. Pittsburg Unit 5 experienced a total of five
condenser tube leaks from 1994 to 1998. In this same time frame, 11 feedwater
heater leaks were experienced. Pittsburg Unit 6 experienced seven feedwater
heater leaks or related problems from 1994 to 1998. A total of six condenser
leak incidents occurred during this period. Pittsburg Unit 1 was impacted by
numerous boiler tube leaks and inability to easily control boiler water
chemistry. This was traced back to the condition of the condenser tubes. The
condenser tubes were replaced and the boiler tubes cleaned and repaired as
necessary at the end of 2000 and into 2001. Pittsburg Units 2, 3, and 4 will
have their respective condenser tubes replaced and their boiler tubes cleaned
and repaired as necessary in the first half of 2001.
In 2000, Pittsburg Units 5 and 6 had low-NO(X) burners installed.
Pittsburg Unit 6 also repaired the TG bore, air-preheater seal, and major pumps.
Both generators were re-wound and air preheater baskets were replaced on
Pittsburg Unit 6. In 1999 and 2000, Pittsburg Unit 7 experienced forced outage
hours due to fouling and foreign material getting into the raw water supply. In
2000, the traveling screens were removed and completely rebuilt, the cooling
tower was cleaned and the circulating water pumps repaired.
The Pittsburg Facility employs a high energy piping inspection
program in which selected portions of piping and components are inspected as
part of the boiler inspection and overhaul outages. The program is designed to
ensure safe and reliable operation to protect personnel and maintain unit
availability. Components that contain steam or water at greater than
200(degree)F, such as longitudinally-welded hot reheat lines, feedwater heaters
and boiler feed pump recirculation lines are monitored and periodically
inspected.
The Potrero Facility
Potrero Unit 3 is not currently capable of burning dual fuel without
approximately 30 days to prepare the fuel oil systems for operation in addition
to some capital improvements to permit this capability. As modifications are
made to Potrero Unit 3 to reduce NO(X) and improve efficiency, the plant is
moving further away from being able to burn fuel oil. The unit could be made
dual fuel capable, which would require additional capital expense and additional
annual O&M expense. Cost recovery and need for this capability must be discussed
with the California ISO to resolve this point.
The Potrero Unit 3 boiler was overhauled and modified in 1999 to
reduce NO(X) emissions. Existing overfire air ports were modified in 1999 to
reduce NO(X) emissions. Existing overfire air ports were modified and the burner
windbox modified to accommodate new overfire air ports at the corners of the
boiler. Boiler heat transfer areas were changed with economizer surface area
being increased and the superheater and reheater areas being decreased. The FGR
fan was also retipped to provide increased FGR as part of the low-NO(X) effort.
The target emission level is 75 ppm as a result of these modifications. Prior to
the outage, emissions were 110-115 ppm NO(X) at full load. A NO(X) control
system had previously been installed in 1975. Control system optimization and
tuning was performed in 1997 to reduce NO(X) operating levels to match NO(X)
target reductions
High temperature reheater pendants and some radiant superheater tube
sections were replaced in Potrero Unit 3 in 1986 and 1994, respectively. In 1997
multiple front, back and sidewall waterwall tubes were replaced along with some
high temperature reheater pendant tubes.
The Potrero Unit 3 boiler was chemically cleaned during this outage
as it was during the 1990 and 1997 outages. Beginning in 1994, boiler outage
intervals for permitting and recertification were changed from 24 to 36 months,
reducing the required number of overhauls to obtain State of California
operating permits.
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In 1997, Potrero Unit 3 was off-line on seven occasions due to
boiler tube leaks. Two boiler tube related problems resulted in about eight
hours of curtailment during the year in addition to the approximately 590 hours
the unit was off-line due to forced and scheduled boiler tube leak related
outages. Most of these leaks were in waterwall tubes. The 1997 overhaul included
extensive evaluation of boiler tubes and resulted in replacement of many front,
back and side water wall tubes in the high temperature reheater pendant and
steam drum to sidewall header tubes. Following this work, 1998 operating records
show no forced outages or curtailments due to boiler tube leaks.
In 2000, Potrero Unit 3 the condenser tubes were cleaned, coated and
sleeved where required, boiler tube leaks were fixed, and boiler casing seal was
repaired. Material was ordered to replace the condenser tubes in 2001 and repair
all badly corroded boiler tubes due to the condenser tube leaks.
Review of the Potrero Unit 3 turbine generator operating history
since 1993 shows few problems adversely affecting plant availability. A 1995
forced outage related to wiped turbine bearings resulted in about 1,080 forced
outage hours. This outage occurred while shutting the unit down. Steam seal
problems were the apparent cause of this casualty. Except for 1995, a review of
forced outages for 1994-1998 shows an average of only 42 hours per year in
forced outages attributed to the turbine-generator and turbine valves.
The turbine-generator has been overhauled at about two year
intervals with complete turbine disassembly and inspection occurring roughly
every other major outage. Disassembly occurred during 1986, 1990 and 1997
outages.
The generator was completely disassembled, stator rewedged, field
removed and other repairs completed in 1998. It was again opened, inspected and
minor repairs accomplished in 1992, 1994, 1996, 1997 and 1999.
Low-pressure turbine, throttle and reheat valves were inspected and
repaired as necessary during the 1999 outage. Some valve maintenance, inspection
or modification work is performed at every major outage. In 1997, turbine
non-return valves were overhauled in addition to the steam admission valves,
which are usually included in the work schedule.
Potrero Unit 3 feedwater heater 3-4 was replaced in 1998. The main
condenser was retubed with 70-30 Cu-Ni in 1990. Feedwater heater 3-5 was
rebundled the same year. During the 1997 outage, the condenser was mechanically
cleaned. In 1999, inlet end inserts were installed in the condenser tubes.
Review of operating records from 1993-1998 shows a total of 15 tube leak
incidents in all feedwater heaters. These forced curtailments resulted in a
total of 67 equivalent forced outage hours in this five-year period.
Only two forced outages were attributable to heat exchangers during
this period. In 1997, tube-to-tubesheet leaks and the subsequent repairs
resulted in 120 equivalent forced outage hours. In 1993, LP feedwater heater
tube leaks forced the unit down for about 43 hours.
Feedwater heater performance is monitored regularly on Potrero Unit
3. In the future, feedwater heater performance will be incorporated into the
plant performance monitoring system.
The Potrero Facility employs a high energy piping inspection program
in which selected portions of piping and components are inspected as part of the
boiler inspection and overhaul outages. The program is designed to ensure safe
and reliable operation to protect personnel and maintain unit availability.
Potrero Units 4 through 6 are simple-cycle gas turbine-generator
units; each rated at 52 MW net. They generally run on peak load days during the
peak portion of the year. These units have black start capability, can start in
less than 10 minutes and can operate as synchronous condensers. These units
utilize distillate fuel. Each generator is driven by two gas turbines located at
both ends of the generator and on the same shaft.
In 1998, all three units were hot section inspected. In addition,
Potrero Unit 6 had a "B" engine overhaul. The units had previously received hot
section inspections in 1993 and 1994. In 1975, a NO(X) control system was
installed in Potrero Unit 3. In 1992, the gas turbine control systems were
upgraded to a Woodward 5000 DCS.
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This system performs automatic start-up, paralleling and loading as will as
annunciation functions. A CEM system was installed on Potrero Unit 3 1993. The
system has maintained an average annual availability of 97 percent since it was
installed.
A plant efficiency monitoring system is in place on Potrero Unit 3
which monitors heat rate. The system capability is still being expanded. The
intention is to develop the system to monitor deviation from expected
performance for major equipment and to generate a weekly heat rate curve.
In 1992, the Potrero Unit 3 control system was upgraded to
incorporate the NO(X) controls, boiler steam temperature and associated
annunciators into a WDPF Level 7 DCS. The CO/O2 analyzer was replaced in 1997
along with replacing a Daniels gas flow computer.
Operating History
Operating data for the past several years of operation of the Mirant
California Facilities was provided by Mirant California and is presented in
Table 9.
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Table 9
Operating History
Mirant California Facilities
Contra Costa Pittsburg Potrero
------------ --------- -------
Net Capability Rating (MW)(1)
1996 680 1,932 350
1997 680 1,932 350
1998 680 1,932 350
1999 680 1,932 350
2000 680 1,932 350
Net Generation (GWh)
1996 1,410.4 2,618.5 916.3
1997 1,350.4 3,694.1 764.6
1998 1,919.7 4,873.9 1,188.7
1999 2,349.4 3,530.1 894.3
2000 2,766.8 6,899.4 907.6
Annual Net Heat Rate (Btu/kWh)(2)
1996 10,114 11,104 10,502
1997 10,217 10,883 10,921
1998 9,981 10,427 10,384
1999 10,028 10,888 10,590
2000 10,193 10,545 10,837
Net Capacity Factor (%)(2)
1996 23.9 19.6 48.4
1997 22.7 28.3 35.2
1998 33.8 32.0 59.9
1999 39.7 23.7 43.9
2000 46.7 45.8 48.8
Equivalent Availability Factor(%)(2)
1996 88.8 78.1 84.5
1997 70.3 81.4 72.6
1998 78.8 65.2 94.9
1999 93.4 86.7 79.7
2000 87.4 80.7 80.8
Gas Use (Mcf x 1000)
1996 14,264.9 29,114.5 9,328.6
1997 13,796.9 40,201.8 7,349.9
1998 19,161.1 50,821.3 11,603.1
1999 23.559.4 38,380.9 8,751.1
2000 28,201.0 72,752.4 8,537.7
--------
(1) Summer rating.
(2) Represents weighted average for annual net heat rate, net
capacity and equivalent availability factors.
Environmental Assessment
Environmental Site Assessments
In connection with the sale of the Mirant California Facilities,
PG&E agreed to undertake any remediation (including during decommissioning) that
relates to any pre-closing environmental condition or transmission environmental
condition required by any governmental authority with jurisdiction over the
Mirant California Facilities. If Mirant Delta or Mirant Potrero choose to
develop any plant for a use other than for a fossil-fueled power plant or a
substantially similar industrial purpose, which development would make the costs
of environmental remediation materially higher, PG&E's costs of remediation
would be capped at the costs which would have been incurred if there had been no
change in use. Long-term remediation activities and future remediation of
residual contamination under structures on the plant sites are PG&E's
responsibility. PG&E is not, however, responsible for other remediation work
unless changes in environmental laws or in the environmental cleanup standards
of a governmental authority require additional remediation. Due to the
environmental indemnity in the Purchase and Sale Agreements which obligates PG&E
to indemnify Mirant Potrero and Mirant Delta for pre-existing environmental
conditions, no funds are included in the Projected Operating Results.
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Status of Permits and Approvals
The status of key permits and approvals for the Mirant
California Facilities is shown in Tables 10 through 12.
Table 10
Status of Key Permits and Approvals Required for Operation
Contra Costa Facility
===================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- -----------------------------------------------------------------------------------------------------------------------------------
State/Local
- -----------------------------------------------------------------------------------------------------------------------------------
1. Title V Air Operating BAAQMD Issued 4/1/99 Permit covers all on-site emission
Permit Expires 9/14/03 sources, including Units 6 and 7
(steam) and misc. sources.
Consolidates air emission requirements,
including Rule 9-11, NO(X) controls.
- -----------------------------------------------------------------------------------------------------------------------------------
2. NPDES Wastewater Central Valley Regional Issued 10/27/95 Defines effluent limitations,
Discharge Permit Water Quality Control Expires 10/1/00 monitoring and reporting requirements.
Board ("RWQCB") Renewal application filed 4/3/00 with
subsequent submittals. Plant will operate
under expired permit until renewal is
issued.
- -----------------------------------------------------------------------------------------------------------------------------------
3. Hazardous Waste Treatment California Department of Issued 4/1/93 Notification covers boiler wastewater
Notification Toxic Substance Control management, boiler chemical cleaning
("DTSC") waste, o/w separator, waste storage,
demineralizer and lab waste.
- -----------------------------------------------------------------------------------------------------------------------------------
4. California Endangered California Department of Issued 12/30/97 Multispecies Habitat Conservation Plan
Species Act MOU Fish and Game ("CDFG") prescribes management measures for
listed/ unlisted species potentially
impacted by Pittsburg and Contra Costa
Facilities and habitat
enhancement/monitoring at the Montezuma
Enhancement Site.
===================================================================================================================================
Table 11
Status of Key Permits and Approvals Required for Operation
Pittsburg Facility
===================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- -----------------------------------------------------------------------------------------------------------------------------------
State/Local
- -----------------------------------------------------------------------------------------------------------------------------------
1. Title V Air Operating BAAQMD Issued 4/1/99 Permit covers all on-site emission
Permit Expires 9/14/03 sources, including Units 1 through 7
(steam).
Consolidates air emission requirements,
including Rule 9-11, NO(X) controls.
- -----------------------------------------------------------------------------------------------------------------------------------
2. NPDES Wastewater Discharge Central Valley RWQCB Issued 11/15/95 Defines effluent limitations, monitoring
Permit Expires 11/15/00 and reporting requirements. Renewal
application filed. Application deemed
complete by RWQCB 6/21/2000.
- -----------------------------------------------------------------------------------------------------------------------------------
3. Hazardous Waste Treatment Central Valley RWQCB Issued 9/16/97 Exemption renewal letter from CRWQCB
Notification Expires 9/16/02 (effective September 16, 1997) extending
Toxic Pits Clean-Up Act exemption for
five years.
- -----------------------------------------------------------------------------------------------------------------------------------
4. California Endangered CDFG Issued 12/30/97 MOU and associated multispecies Habitat
Species Act MOU Conservation Plan prescribes management
measures for listed/ unlisted species
potentially impacted by Pittsburg and
Contra Costa Facilities and habitat
enhancement/monitoring at the Montezuma
Enhancement Site.
===================================================================================================================================
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Table 12
Status of Key Permits and Approvals Required for Operation
Potrero Facility
===============================================================================================================================
Permit or Approval Responsible Agency Status Comments
- -------------------------------------------------------------------------------------------------------------------------------
State/Local
- -------------------------------------------------------------------------------------------------------------------------------
1. Title V Air Operating BAAQMD Issued 4/1/99 Permit covers all on-site emission
Permit Expires 9/14/03 sources, including Unit 3 (steam), Units
4, 5 & 6 (gas turbines) and misc.
sources. Consolidates air emission
requirements, including Rule 9-11, NOX
controls.
- -------------------------------------------------------------------------------------------------------------------------------
2. NPDES Wastewater Discharge San Francisco Bay RWQCB Issued 5/99 Defines effluent limitations, monitoring
Permit Expires 5/04 and reporting requirements.
- -------------------------------------------------------------------------------------------------------------------------------
3. Industrial Wastewater City and County of San Issued 7/7/99 Defines effluent limitations, monitoring
Discharge Permit to Sewer Francisco Department of Expires 6/6/02 and reporting requirements.
System Public Works
===============================================================================================================================
Regulatory Compliance
The Mirant California Facilities are currently subject to various
state and federal permits and regulations primarily mandated by the BAAQMD, the
California Regional Water Quality Control Board ("CRWQCB"), and the CDFG. Of
particular importance is BAAQDM's Regulation 9-11 which addresses the control of
NO(X) and CO emissions from the Mirant California Facilities. Title IV of the
Clean Air Act, Acid Rain Program is also applicable the Mirant California
Facilities.
BAAQMD Regulations
In late 1995, the BAAQMD amended Rule 9-11, which regulates the
control of NO(X) and CO emissions from Utility Electric Power Generating Boilers
("Rule 9-11"). Rule 9-11 specifies a "system-wide" (which for purposes of this
Report and Supplement is all power generation owned and/or operated by Mirant
California) emission limitation to be achieved by all steam boilers, each with a
rated heat input of greater than or equal to 250 MMBtu/hr, used for electric
power generation in the geographic area regulated by the BAAQMD. The system-wide
emission limitation imposes a NO(X) average (calculated in accordance with Rule
9-11) emission limitation for all the Mirant California Facilities in addition
to individual unit limitations in the unit's Title V Permit. The fact that
Mirant California owns multiple units provides flexibility in meeting the
system-wide limit.
Rule 9-11 specifies the system-wide NO(X) emission rate limits shown
in Table 13 for gaseous fuels, which are calculated on a clock-hour basis. Rule
9-11 prohibits boilers from being fired with oil unless: (i) natural gas is not
available due to a force majeure event or (ii) the unit is performing limited
oil testing.
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Table 13
NO(X) Emissions Limits
Mirant California Facilities
Effective Date System-Wide
of Limitation Emission Rate Limit
lb/MMBtu ppm(1)
-------- ------
January 1, 1997 0.188 155
January 1, 1998 0.160 132
January 1, 1999 0.115 95
January 1, 2000 0.105 87
January 1, 2002 0.057 47
January 1, 2004 0.037 31
January 1, 2005 0.018 15
--------------------
(1) Parts per million, dry volume at 3% oxygen.
Prior to Mirant California's purchase of the generating units, PG&E
initiated a detailed study, NO(X) Control Strategy Development for PG&E's BAAQMD
Units, prepared by an engineering firm retained by PG&E (the "Engineering
Report"), to determine the best approach to achieve compliance. Based on the
Engineering Report and ongoing evaluations and modifications at the Mirant
California Facilities, Mirant California's current plans are to achieve
compliance with the NO(X) emission limits by the installation of various burner
modifications and SCR installation on many of the units.
Title IV SO(2) Limitations - SO(2) Allowances
The Potrero, Pittsburg and Contra Costa Facilities are Phase II
affected plants under the Title IV Acid Rain Program and will therefore need to
comply with the SO(2) allowance limitations thereunder beginning in the year
2000.
PG&E did not sell any SO(2) allowances allocated to the Mirant
California Facilities to Mirant California as part of the sale agreement. Any
SO(2) allowances required for operation of the Mirant California Facilities will
have to be secured by Mirant California from other sources or purchased on the
open market. Since the Mirant California Facilities are currently operating
exclusively on natural gas and natural gas usage is contemplated in future
operations, the need for SO(2) allowances is minimized. Assuming 100 percent
operation (8,760 hours per year) of the combined Mirant California Facilities,
less than 100 total SO(2) allowances per year would be required based on
standard SO(2) emission factors for natural gas-fueled steam boilers.
If oil fuel were to be utilized in the future, additional SO(2)
allowances would have to be secured and allocated to comply with the Title IV
Acid Rain regulatory requirements.
Air Emissions
The air emissions presented in Table 14 have been used in the
Projected Operating Results.
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Table 14
Emissions and Limits
Mirant California Facilities
(lb/MMBtu)
Facility Current Projected Emission Limit
SO(2) NO(X)(1) SO(2) NO(X)(2) SO(2) NO(X)(3)
----- -------- ----- -------- ----- --------
Contra Costa Unit 6 0.001 0.072 0.001 0.012 NA 175
Contra Costa Unit 7 0.001 0.06 0.001 0.012 NA 175
Pittsburg Units 1-4 0.001 0.09-0.135 0.001 0.012 NA 175
Pittsburg 5 0.001 0.065 0.001 0.012 NA 175
Pittsburg 6 0.001 0.045 0.001 0.012 NA 175
Pittsburg 7 0.001 0.05 0.001 0.012 NA 175
Potrero Unit 3 0.001 0.07 0.001 0.024 NA 175
Potrero Units 4-6(4) 0.001 0.078 0.001 0.078 NA 65(5)
--------------------
(1) Representative of annual average.
(2) Assumes SCRs at Pittsburg Units 1, 2, 3 and 4 in 2003 reducing
emissions to 0.012 lbs/MMBtu; low-NO(X) burners and an SCR at
Pittsburg Unit 5 in 2001 reducing emissions to 0.024 lbs/MMBtu and
in 2002 reducing emissions to 0.012 lbs/MMBtu, respectively; SCRs at
Pittsburg Units 6 and 7 in 2002 and 2003 reducing emissions to 0.012
lbs/MMBtu; an SCR at Potrero Unit 3 in 2004 reducing emissions to
0.024 lbs/MMBtu; low-NO(X) burners and an SCR at Contra Costa Unit 6
in 2001 reducing emissions to 0.048 lbs/MMBtu and in 2003 reducing
emissions to 0.012 lbs/MMBtu; and an SCR at Contra Costa Unit 7 in
2001 reducing emissions to 0.012 lbs/MMBtu.
(3) Parts per million, dry volume at 3% oxygen, clock-hour average.
(4) Potrero Units 4, 5, 6 gas turbines are limited to 877 operating
hours per calendar year.
(5) Parts per million, dry volume at 15% oxygen, clock-hour average.
Wastewater Compliance.
Effluent limitations for the discharge of each of the Delta
Facilities and the Potrero Facility are generally similar between plants and
consistent with USEPA's Effluent Guidelines for Steam Electric Power Plants.
However, a monthly 96-hour flow-through bioassay is required at the Potrero
Facility to demonstrate that the discharge is not toxic to certain test aquatic
species. Monitoring at the Delta Facilities and the Potrero Facility is
conducted by plant operations on a regular basis and reported monthly to the
CRWQCB.
The Potrero Facility is permitted by the CRWQCB for wastewater
discharges to the San Francisco Bay. The Contra Costa and Pittsburg Facilities
are permitted by the CRWQCB to discharge their wastewater to the San Joaquin
River and to the Suisun Bay, respectively. With the exception of Pittsburg Unit
7, all of the steam generating units utilize once-through cooling water for
steam condenser cooling. As a result, specific temperature and flow limits are
included in the NPDES permits for the Delta Facilities and the Potrero Facility
to assure water quality compliance and to minimize aquatic impacts in the
receiving water.
The cooling water intakes for both the Pittsburg and Contra Costa
Facilities are located in a nursery area for striped bass, which is considered a
valued fishery resource. Additionally, recent listings of the Delta Smelt and
Winter-run Chinook Salmon under the State and Federal Endangered Species Act
have focused attention on these species. Since all of these species are or may
be present in the intake/discharge water from these two plants, a Resource
Management Program is required under the NPDES permits for the Pittsburg and
Contra Costa Facilities that includes certain operating restrictions during the
"entrainment period" for striped bass, which typically occurs between May and
July of each year. The operations protocol that defines these restrictions
generally maximizes the power production from Pittsburg Unit 7, attempts to
limit the discharge temperature at the Pittsburg and Contra Costa Facilities to
86(degree)F, restricts scheduling of the overhaul of Pittsburg Unit 7 for each
year during the entrainment period and minimizes circulation flows under certain
conditions. The Mirant California Facilities are presently operating and have
operated in the past under the Resource Management Plan. The renewal of the
NPDES Permits and the need to obtain a federal Take Permit for impacting
endangered species will likely require additional capital expenditures and O&M
expenses at the Mirant California Facilities.
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The wastewater compliance history of the Mirant California
Facilities does not indicate any future non-compliance trends.
California Endangered Species Memorandum of Understanding
On December 30, 1997, CDFG and PG&E entered into an MOU regarding a
Multispecies Habitat Conservation Plan which specifies: (i) management measures
for listed and unlisted endangered species that could be impacted by the
operation and maintenance of the Pittsburg and Contra Costa Facilities and (ii)
habitat enhancement/monitoring activities at the Montezuma Enhancement Site. The
Montezuma Enhancement Site is a 139-acre site located across the San Joaquin
River Basin from the Pittsburg and Contra Costa Facilities.
Design and construction costs for the Montezuma Enhancement Site
were estimated in late 1997 at $500,000 and monitoring over 15 years is
estimated at a total cost of $1,000,000. Future maintenance of the site is
contingent upon negotiations presently ongoing with the NPDES renewal process
and the acquisition of a federal Take Permit for the Delta Facilities.
Future Environmental Requirements
Certain future requirements relative to the revised PM(2.5)
standard, regulation of mercury emissions, regional haze, regional visibility,
water intake structure regulations, and potential ratcheting of the SO(2)
allowance program beyond the year 2009 may affect the Mirant California
Facilities in the future by imposing more stringent requirements than those in
effect at the present time. Since the Mirant California Facilities are fired
primarily on natural gas, the impact of these potential future requirements is
not expected to be significant.
MIRANT NEW YORK FACILITIES
Description of the Bowline Facility
Mechanical Equipment and Systems
Steam Generators
The Bowline Unit 1 steam generator consists of a CE controlled
circulation, radiant reheat unit, tangentially fired, with a balanced draft
furnace. The steam generator has a maximum continuous capacity of 4,200,000
lb/hr of steam when operating at 2,600 psig and 1,005(degree)F superheater
outlet temperature and a final reheat temperature of 1,005(degree)F. The steam
generator is designed to fire either No. 6 fuel oil or natural gas, or both
fuels in combination. Major equipment associated with the steam generator
includes five elevations of burners at each corner of the furnace for a total of
20 burners, two forced draft and two induced draft fans, one gas recirculation
fan, four boiler circulation pumps, two regenerative air preheaters and a
sootblowing system.
The Bowline Unit 2 steam generator consists of a B&W natural
circulation, radiant reheat unit, front and rear wall fired, with a balanced
draft furnace. The steam generator has a maximum continuous capacity of
4,200,000 lb/hr of steam when operating at 2,600 psig and 1,005(degree)F
superheater outlet temperature and a final reheat temperature of 1,005(degree)F.
The steam generator is designed to fire either No. 6 fuel oil or natural gas, or
both fuels in combination. Major equipment associated with the steam generator
includes four elevations of burners arranged with eight burners per elevation,
of which four burners are on the front wall and four are on the rear wall of the
furnace for a total of thirty-two burners, two forced draft and two induced
draft fans, one gas recirculation fan, two regenerative air preheaters and a
sootblowing system. Due to the condition of steam generator's tubing, the
superheater and reheater outlet temperatures for Bowline Unit 2 are currently
being held to approximately 980-990(Degree)F to reduce further deterioration.
The tubing replacements that would be necessary to allow the temperatures to be
restored to their design points of 1005(Degree)F will continue to be evaluated
as part of the overall economic operating plan for the unit. We have not
included costs for this level of tubing replacements in the Projected Operating
Results.
S-42
Turbine Generators
Each of the Bowline Units 1 and 2 steam generators provides steam to
a single GE tandem-compound, four flow, reheat, condensing steam turbine. Each
turbine is capable of producing approximately 566-570 MW at inlet throttle
conditions of 2,400 psig and 1,000(degree)F with 1,000(degree)F reheat inlet
temperature at the maximum guaranteed throttle flow of 3,799,670 lb/hr and 2.0
inches Hg backpressure.
Each of the Bowline Units 1 and 2 steam turbines drives a GE
hydrogen-cooled generator. Each of the generators is a 2 pole, 3 phase, 60
cycle, 3,600 rpm, 20 kV unit rated at 690 MVA at 60 psig hydrogen pressure. Each
generator has a direct driven exciter.
Fuel System
The fuel oil system at the Bowline Facility includes an unloading
pier, a transfer pipeline, a diked tank farm, a pump house, primary and
secondary fuel oil pumps and heater, steam and hot water tracing systems, and
pressure, temperature and viscosity controls and instrumentation. Fuel oil is
delivered via barge at a deepwater port on the Hudson River that can accommodate
both tanker and barge deliveries. No. 6 fuel oil at the Bowline Facility is
stored in six steel AST surrounded by an earthen berm wall. The total storage
capacity of the six tanks is 870,000 barrels, which constitutes approximately 21
days of fuel supply for the Bowline Facility when operating at full load.
The Bowline Facility is connected to the ORU natural gas
distribution system and both of the units at the Bowline Facility have full
natural gas-firing capability. A natural gas metering and pressure-reducing
plant is located on the site. Natural gas is provided to the Bowline Facility
through a single line. Downstream of the Bowline Facility, the 16-inch supply
line increases to 24 inches. The Bowline Facility's system is currently capable
of supplying enough natural gas to support one unit at 100 percent load with the
second unit at 40 percent load. A new high pressure natural gas transmission
line capable of supplying adequate natural gas to fire both units at 100 percent
load is under development.
Propane is used for the ignition of the units. The storage system
consists of three horizontal propane storage tanks, each of 30,000 gallons
capacity, two propane transfer pumps and a waterbath vaporizer.
Ash Systems
The ash handling systems for Bowline Units 1 and 2 consist of
four-compartment, gravity feed, dry storage ash hoppers with water seal troughs.
These ash hoppers are furnished with a manual system to discharge ash into
standard drums to facilitate the disposal of ash to an off-site municipal
landfill.
Water Supply
Circulating water for the condenser and the service water system is
drawn from the Hudson River via six circulating water pumps. Full output of four
of the six circulating water pumps is required to operate the Bowline Facility
at full load, regardless of water temperature, in order to stay within permitted
water thermal discharge regulations. The circulating water system discharges to
an underwater multi-port diffuser in the Hudson River.
Municipal water is used as make-up for the condensate system and is
treated in a demineralizer. In addition, the Bowline Facility uses
electro-dialysis reduction for make-up water treatment.
Electrical and Control Systems
Emergency power is provided by a 615 kW diesel generator. In
addition, emergency DC motors are supplied by 125 volt and 250 volt DC batteries
and chargers. The 125 volt battery also provides DC power for a 120/240 volt AC
uninterruptible power source ("UPS") for critical loads.
The Bowline Facility is equipped with one central control room. Each
unit is operated separately using a Westinghouse digital control system for the
boiler burner management controls. Turbines are controlled by a Leeds and
Northrup Max 1000 system. The primary operator interface is through consoles
that incorporate graphical
S-43
operator interfaces on cathode ray tubes ("CRTs"). The systems are electronic
from the transmitters to the final control element transducers.
Environmental Controls and Equipment
Air Emissions
The control of NO(X) emissions at the Bowline Facility is
accomplished by the use of overfire air injection ports, FGR, low-NO(X) burners
and modified burner management controls. No particulate emission control is
required on either unit. Control of SO(2) emissions is accomplished by the
control of the sulfur content of the fuel burned.
Wastewater/Solid Waste Disposal
A wastewater treatment facility on the Bowline Facility site treats
wastewater prior to discharge to the Huson River under a State Pollutant
Discharge Elimination System ("SPDES") permit. Sanitary waste is discharged
directly to the regional sewer system. The facility also has two wastewater
storage tanks on-site.
Stormwater is collected and discharged under an SPDES permit, which
contains specific monitoring and reporting requirements for various discharge
points.
Off-Site Requirements
Fuel Supply
Under the terms of a fuel supply agreement with MAEM, MAEM is
responsible for procuring and supplying all fuel oil and natural gas required by
the units. Natural gas transmission is provided by the Columbia Gas Transmission
Corporation ("Columbia") pursuant to a service agreement that was executed by
Columbia and ORU in 1991. Under the terms of this agreement, Columbia is to
provide gas transmission services to ORU through December 31, 2003. Columbia's
maximum obligation is to deliver 25,000 decatherms of natural gas per day.
Columbia must provide such services in accordance with the provisions of the
effective OPT Rate Schedule and applicable General Terms and Conditions of
Columbia's gas tariff as filed with the FERC. ORU serves as the local
distribution company which receives the natural gas from Columbia and delivers
the gas to the Bowline Facility. ORU's distribution charges are paid by MAEM and
included in the cost of the natural gas.
Electrical Interconnection
The Bowline Facility's switchyard has a 138 kV bay for incoming
power and a 345 kV bay for outgoing power. The interconnection of Bowline Units
1 and 2 into the ORU transmission system is at the Ladentown 345 kV transmission
bus. The Ladentown bus arrangement is a ring bus with four transmission lines.
Two lines connect to the Bowline Facility and two lines connect to the 345 kV
system. The 345 kV transmission lines connect the Ladentown bus into the bulk
power system.
The interconnection of the Bowline Facility's start-up yard into the
ORU transmission system is via the 138 kV Minisceonogo switching station, which
taps to the overhead transmission lines. The fuel oil circuit breakers located
in the Bowline Facility's start-up yard are contiguous to the ORU transmission
system.
A Continuing Site/Interconnection Agreement between ORU and Mirant
Bowline provides for the continued interconnection of the Bowline Facility to
ORU's transmission system and allows ORU to continue to operate its transmission
and distribution facilities from their present location. In addition, this
agreement defines the continuing responsibilities and obligations of Mirant
Bowline and ORU with respect to the use of each party's property in connection
with their ongoing business operations so as to minimize the impact of such
operations on the other party's property or operations. This agreement is
effective from November 24, 1998 through the date the generating units are
retired and not replaced.
S-44
Description of the Lovett Facility
Mechanical Equipment and Systems
Steam Generators
The Lovett Unit 3 steam generator consists of a CE natural
circulation reheat unit, tangentially fired, with a balanced draft furnace. The
steam generator has a maximum continuous capacity of 500,000 lb/hr of steam when
operating at 1,850 psig and 1,050(degree)F superheater outlet temperature and a
final reheat temperature of 1,000(degree)F. The steam generator was originally
designed to fire either coal or No. 6 fuel oil, with the capability of adding
natural gas firing at a later date. Although the coal firing equipment such as
pulverizers, fuel-air piping and coal burner nozzles are still in place, the
unit currently fires either No. 6 fuel oil or natural gas, or both fuels in
combination. Major equipment associated with the steam generator includes four
elevations of burners at each corner of the furnace for a total of sixteen
burners, two forced draft and two induced draft fans, primary and secondary
tubular air preheaters and a sootblowing system.
The Lovett Unit 4 steam generator consists of a Foster Wheeler
natural circulation reheat unit, front wall fired, that has been converted from
a positive draft to a balanced draft furnace. The steam generator has a maximum
continuous capacity of 1,200,000 lb/hr of steam when operating at 1,890 psig and
1,000(degree)F superheater outlet temperature and a final reheat temperature of
1,000(degree)F. The steam generator was originally designed to fire coal or
natural gas, either separately or in combination. In 1970, the capability to
fire No. 6 fuel oil was added. Major equipment associated with the steam
generator includes two levels of burners, each level with four burners, that are
located on the front wall of the furnace and that were replaced with low-NO(X)
burners in 1995, two forced draft and two induced draft fans, one regenerative
air preheater and a sootblowing system.
The Lovett Unit 5 steam generator consists of a B&W natural
circulation reheat unit, front wall fired, with a positive draft furnace. The
steam generator is designed to fire coal, No. 6 fuel oil or natural gas. When
firing coal or No. 6 fuel oil, the steam generator has a maximum continuous
capacity of 1,400,000 lb/hr of steam when operating at 1,985 psig and
1,000(degree)F superheater outlet temperature and a final reheat temperature of
1,000(degree)F. When firing all natural gas, the unit will deliver a maximum of
1,240,000 lb/hr of steam when operating at 1,890 psig and 975(degree)F
superheater outlet temperature and a final reheat temperature of 975(degree)F.
Major equipment associated with the steam generator includes four levels of
burners, each level with four burners, that are located on the front wall of the
furnace and that were replaced with low-NO(X) burners in 1995, two forced draft
and two induced draft fans, two regenerative air preheater and a sootblowing
system.
Turbine Generators
Each of the Lovett Facility's steam generators provides steam to a
single GE tandem-compound, two flow, reheat, condensing steam turbine. The
Lovett Unit 3 turbine is capable of producing approximately 65 MW at inlet
throttle conditions of 1,800 psig and 1,050(degree)F with 1,000(degree)F reheat
inlet temperature and 1.0 inches Hg backpressure. The Lovett Unit 4 turbine is
capable of producing approximately 173 MW at inlet throttle conditions of 1,800
psig and 1,000(degree)F with 1,000(degree)F reheat inlet temperature and 1.25
inches Hg backpressure. The Lovett Unit 5 turbine is capable of producing
approximately 187 MW at inlet throttle conditions of 1,800 psig and
1,000(degree)F with 1,000(degree)F reheat inlet temperature and 1.25 inches Hg
backpressure.
Each of the Lovett Facility's steam turbines drives a GE
hydrogen-cooled generator. Each of the generators is a 2 pole, 3 phase, 60
cycle, 3,600 rpm unit. The Lovett Unit 3 generator is rated at 84.7 MVA at 25
psig hydrogen pressure, with an output voltage of 13.8 kV. The Lovett Unit 4
generator is rated at 211.2 MVA at 30 psig hydrogen pressure, with an output
voltage of 20 kV. The Lovett Unit 5 generator is rated at 236 MVA at 45 psig
hydrogen pressure, with an output voltage of 20 kV.
Lovett Unit 3 is equipped with two motor-driven exciters, one of
which may be used as a spare for either Lovett Unit 3 or Lovett Unit 4. Lovett
Units 4 and 5 each has its own shaft-driven exciter.
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Fuel System
Coal is delivered to the Lovett Facility by train and is stored in a
stockpile that contains sufficient coal to operate the Facility for
approximately three weeks with the Facility operating at full load. Utilizing
bulldozers, coal is reclaimed from the coal stockpile through a series of
reclaim hoppers and conveyors.
Fuel oil is delivered to the Lovett Facility via barge at a
deepwater port on the Hudson River that can accommodate both tanker and barge
deliveries. Fuel oil storage consists of three tanks that contain sufficient
fuel oil to operate the facility for approximately 2 weeks with the Facility
operating at full load. The system also includes a common dock-to-tank farm
pipeline. No. 2 fuel oil is used for startup of the Lovett Facility units.
The Lovett Facility is connected to the ORU natural gas distribution
system. All three units have full gas-firing capability. A natural gas metering
and pressure-reducing station is located on the site. The capacity of the gas
regulating station is sufficient to operate all three units at 100-percent
capacity.
Ash Systems
The ash handling system for Lovett Unit 3 consists of a bottom ash
storage hopper and associated sluicewater pumps and piping for bottom ash, and a
pneumatic conveying system for fly ash. As coal is not currently being burned in
Lovett Unit 3, the bottom ash and fly ash handling systems are not in service.
The ash handling systems for both Lovett Units 4 and 5 are each
divided into two systems. One system utilizes sluicewater to transport bottom
ash collected in the ash storage hopper at the bottom of the furnace and from
the economizer area, while the second system is a pneumatic conveying system
that removes fly ash from the ESPs, duct hoppers and flues.
An on-site coal ash management facility ("CAMF") is used as a
disposal site for coal ash and a minimal amount of wastewater treatment sludge
produced at the Lovett Facility. In addition to the CAMF, coal ash is being
loaded and transported off site by a third party.
Water Supply
Circulating water for Lovett Units 3, 4, and 5 is obtained through
two 75 percent capacity circulating water pumps for each unit. The Lovett
Facility has surface and subsurface circulating water discharge points into the
Hudson River.
Make-up water for the Lovett Facility from the local potable water
supply flows through a portable reverse osmosis system to the demineralizer.
Demineralizer effluent is piped to the condensate storage tank.
The service water systems for the Lovett Facility supply strained
Hudson River water for oil cooling, circulating water pump bearing lubrication,
bearing water cooling, ash sluicing, and miscellaneous plant utilities.
Electrical and Control Systems
Emergency power for each unit is provided via a bank of batteries
supplying power to emergency oil pumps, DC control power, and a UPS for Lovett
Units 4 and 5 AC control power. A natural gas-fired diesel generator supplies
back-up power to the emergency motor control center which powers critical oil
pumps, fire pumps, Lovett Unit 3 instrument AC power, and other emergency
equipment.
The Lovett Facility is equipped with two separate central control
rooms. One room is assigned to Lovett Units 3 and 4, while the other is assigned
to Lovett Unit 5. The original Lovett Unit 5 boiler control system was replaced
in 1996 with a Westinghouse digital control system for the boiler burner
management system. The operator interface for Lovett Units 4 and 5 is through
control room consoles that incorporate graphical operator interfaces on CRTs.
Lovett Unit 3 has a hard-wired system with pneumatic controllers on a "bench
board" control panel.
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Environmental Controls and Equipment
Air Emissions
The control of NO(X) emissions at the Lovett Facility is
accomplished by the use of low-NO(X) burners on Lovett Units 4 and 5. Control of
particulate emission is accomplished by ESPs on Lovett Units 4 and 5. Control of
SO(2) emissions is accomplished by limiting the sulfur content of the fuel
burned.
Wastewater/Solid Waste Disposal
A wastewater treatment facility treats all of the Lovett Facility's
wastewater and discharges the effluent to the Hudson River. Two wastewater
storage tanks with a capacity of 400,000 gallons each are on-site, and the
Lovett Facility has a separate sanitary waste treatment facility.
Stormwater is collected and discharged under a SPDES permit, which
contains specific monitoring and reporting requirements for various discharge
points. The site has a leachate and runoff pump station and treatment pond.
Off-Site Requirements
Fuel Supply
Under the terms of a fuel supply agreement with MAEM, MAEM is
responsible for procuring and supplying all coal, fuel oil and natural gas
required by the units. Natural gas transmission is provided by Columbia pursuant
to the service agreement described in the Bowline Facility's Fuel Supply section
of this Supplement.
Coal is provided by MAEM pursuant to an agreement with the Massey
Coal Sales Company Inc. ("Massey") and through spot market purchases. The
agreement with Massey, dated April 21, 1999, provides for the supply of coal to
the Lovett Facility through July 31, 2007. Under the agreement, Massey must
provide the Lovett Facility the lesser of (i) 90 percent of the total tonnage of
coal delivered to the Lovett Facility and to off-site storage during the
relevant contract year or (ii) 630,000 tons of coal. There is also an option for
the purchase of up to an additional 100,000 tons of coal.
The coal must meet certain quality specifications and is currently
obtained from mines in Kentucky and West Virginia, but may be supplied from
other sources. The agreement with Massey also provides Mirant Lovett with the
option, under certain conditions, to transport coal ash to one of Massey's mines
for disposal. Spot market coal is supplied by MAEM at either the same price as
the Massey coal if it is procured before the Massey agreement's quantity
requirements have been fulfilled, or at MAEM's actual cost for the coal for
procurements made after the Massey agreement's quantity requirements have been
fulfilled. Coal is currently being delivered to the Lovett Facility in a
single-line rail movement pursuant to a transportation contract entered into
between ORU and CSX Transportation dated June 1, 1999, and expiring on March 31,
2004 which was assigned to Mirant Lovett by ORU.
Electrical Interconnection
Lovett Unit 3 is interconnected with the ORU transmission system at
the 69 kV bus in ORU Substation 33. Lovett Units 4 and 5 are connected to the
ORU transmission system at the 138 kV bus in ORU Substation 47.
A Continuing Site/Interconnection Agreement between ORU and Mirant
Lovett provides for the continued interconnection of the Lovett Facility to
ORU's transmission system and allows ORU to continue to operate its transmission
and distribution facilities from their present location. In addition, this
agreement defines the continuing responsibilities and obligations of Mirant
Lovett and ORU with respect to the use of their own and the other party's
property in connection with their ongoing business operations so as to minimize
the impact of such operations on the other party's property or operations. This
agreement is effective from November 24, 1998 through the date the generating
units are retired and not replaced.
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Descriptions of the NY CT Facilities
The CT units at the Hillburn and Shoemaker Facilities are generally
operated in peaking service and to satisfy transmission outage requirements.
Each unit has black start capability and may be used to provide startup power
for other units in the area, such as the Lovett Facility, that do not have black
start capability. Each of the CTs is a Worthington Model ER-224 unit nominally
rated at 45 MW. Both units are capable of being operated on either natural gas
or No. 2 fuel oil. The units were installed in 1971 and are essentially
identical except that the Shoemaker Facility is equipped with a natural gas
compressor to increase the pressure of the available natural gas.
Descriptions of the Hydroelectric Facilities
The Mongaup Facility consists of 4 units with a combined capacity of
4 MW. These units were placed in service between 1923 and 1926. The Swinging
Bridge Facility consists of 2 units with a combined capacity of 13 MW. These
units were placed in service between 1930 and 1939. The Rio Facility occupies
approximately 537 acres of land located in the Towns of Deerpark, Forestburgh
and Lumberland, New York and consists of the Rio Reservoir with associated dam,
11-foot diameter, 7,000-foot long steel penstock and a powerhouse with two
turbine generator units with a combined capacity of 10 MW. The first unit was
placed in service in 1927.
The Grahamsville Facility occupies approximately 70 acres of land
located just outside the Village of Grahamsville, New York. The Grahamsville
Facility is comprised of a single 17 MW turbine generator unit and auxiliary
equipment including a surge tank. Water for generation comes from New York
City's Pepacton Reservoir through the 25 mile long East Delaware Tunnel, and is
released into the Rondout Reservoir. The Grahamsville Facility was placed in
service in 1956.
Operating History
Operating data for the past several years of operation of the Mirant
New York Facilities was provided by Mirant New York and is presented in Table
15.
Table 15
Operating History
Mirant New York Facilities
Hillburn &
Bowline Lovett Shoemaker Hydros
------- ------ --------- ------
Net Capability Rating (MW)(1)
1996 1,213 442 N/A N/A
1997 1,188 443 N/A N/A
1998 1,190 447 76 44
1999 1,220 427 N/A N/A
2000 1,213 434 N/A N/A
Net Generation (GWh)
1996 840.4 1,919.4 7.2 191.3
1997 1,542.0 2,172.9 13.0 156.8
1998 3,521.4 2,262.6 24.2 131.8
1999 2,972.9 2,047.9 21.1 78.8
2000 1,411.4 1,986.0 21.5 150.4
Annual Net Heat Rate (Btu/kWh)(2)
1996 10,415 10,758 22,259 --
1997 10,342 10,806 18,934 --
1998 10,546 10,847 N/A --
1999 10,699 11,000 N/A --
2000 11,156 11,109 24,321 --
Net Capacity Factor (%)(2)
1996 12.3 56.3 1.4 59.8
1997 22.7 63.2 2.9 61.8
1998 37.3 60.6 N/A N/A
1999 28.1 60.1 N/A N/A
2000 14.8 61.4 0.7 52.9
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Table 15
Operating History
Mirant New York Facilities
Hillburn &
Bowline Lovett Shoemaker Hydros
------- ------ --------- ------
Equivalent Availability Factor (%)(2)
1996 86.6 79.9 93.8 N/A
1997 92.1 81.5 85.3 N/A
1998 92.2 81.5 N/A N/A
1999 75.6 86.4 85.3 83.8
2000 81.3 81.0 93.9 89.1
Coal Use (Tons x 1000)
1996 -- 721.0 -- --
1997 -- 788.5 -- --
1998 -- 748.9 -- --
1999 -- 667.7 -- --
2000 -- 763.2 -- --
Oil Use (Gallons x 1000)
1996 15,814 590.6 56.6 --
1997 19,064 1,555.3 101.6 --
1998 72,058 6.4 52.0 --
1999 56,590 1,165.4 39.8 --
2000 46,349 387.2 145.6 --
Gas Use (Mcf x 1000)
1996 6,146 2,254 145.9 --
1997 12,673 3,050 229.0 --
1998 25,374 5,135 427.4 --
1999 22,696 4,744 452.2 --
2000 8,531 2,209 361.9 --
--------------------
(1) Summer ratings.
(2) Represents weighted average for annual net heat rate, net capacity
and equivalent availability factor.
The equivalent availability and net generation of Bowline Unit 1
were adversely affected by a boiler implosion incident in December
of 1999 that resulted in the unit being out of service for nearly
two months. The implosion occurred following a unit trip after
which the control system allowed the pressure inside the furnace
to go highly negative, putting higher than normal stresses on the
furnace wall supporting structures. In particular, a number of
stirrups which hold the boiler tubes to the buckstays were broken.
Improvements have been made to the boiler's control system in an
effort to prevent future negative furnace pressure excursions. As
Bowline Unit 2 is of a different manufacture and design, a similar
occurrence is not expected on this unit.
In addition to adjusting the boiler control systems to prevent
furnace pressure excursions, Mirant New York has modified the control systems to
allow the Bowline units to operate in automatic, rather than in manual mode,
which allows the units to respond to load change requests more quickly. With
these changes in the boiler control system and with revised oil firing burner
tips, the operators have been able to better control combustion so as to reduce
the level of opacity when firing No. 6 fuel oil.
Environmental Assessment
Environmental Site Assessments
Mirant New York has purchased liability insurance for preexisting,
unknown environmental contamination at the Mirant New York Facilities, with a
10-year term and a $15 million in coverage for the Mirant New York Facilities
other than the Hydroelectric Facilities.
We have reviewed Phase I and II ESA reports dated June 1999 and
August and October 1998 prepared by an environmental consultant for the Mirant
New York Facilities regarding investigations of known or
S-49
potential site contamination issues and environmental liability issues for the
Bowline and Lovett Facilities, the Hydroelectric Facilities and the NY CT
Facilities.
The Bowline Facility is listed on the New York State Department of
Environmental Conservation ("NYSDEC") spills database report. During its site
visit, the environmental consultant observed soil stains apparently due to
spills/releases of fuel oil near on-site ASTs. The environmental consultant to
Mirant New York conducted soil, sediment, and groundwater sampling within areas
of concern in two phases in September and November 1998. Laboratory analyses
revealed exceedances of NYSDEC soil cleanup objectives for PAHs and exceedances
of NYSDEC water quality standards for certain heavy metals at the certain site
locations. The environmental consultant recommended no remedial actions at the
site for contaminated soils, stating that "the PAH results found in the soils at
the site are typical of those expected for generating plants and industrial
(brownfield) sites in the state. Based on past experience with these types of
sites, NYSDEC typically does not require further action." In addition, according
to Mirant New York, the environmental consultant believes that an environmental
risk assessment, if ever required for the Bowline Facility, would likely support
no cleanup action.
The Lovett Facility is listed on USEPA and NYSDEC spills database
reports. During its site visit, the environmental consultant observed soil
stains apparently due to spills/releases of oil, fuel, and transformer fluids.
The environmental consultant conducted soil and groundwater sampling within
areas of concern in two phases in September and November 1998. Laboratory
analyses revealed exceedances of NYSDEC soil cleanup objectives and NYSDEC water
quality standards for heavy metals or PAH's at the certain site locations. The
environmental consultant recommended excavation of stained soils identified by
the Phase I ESA. The environmental consultant recommended no additional remedial
actions, stating that "the PAH and metals results found in the soils at the site
are typical of those expected for generating plants and industrial (brownfield)
sites in the state. Based on past experience with these types of sites, NYSDEC
typically does not require further action." In addition, according to Mirant New
York, the environmental consultant believes that an environmental risk
assessment, if ever required for the Lovett Facility, would likely support no
cleanup action.
The environmental consultant did not identify any potentially
significant site contamination issues at any of the NY CT or Hydroelectric
Facilities. However, the environmental consultant's site investigations revealed
that a former diesel engine repair company was located on the Rio Facility site
at which a cleanup of contaminated soil and free (hydrocarbon) product in one
monitoring well is ongoing under NYSDEC oversight. According to NYSDEC
personnel, the most likely mitigation for the site will consist of long-term
groundwater monitoring. For the purposes of the Projected Operating Results,
Mirant New York has allocated $1,000,000 for the contingency environmental
response work at the Mirant New York Facilities.
Status of Permits and Approvals
The status of key permits and approvals for the Mirant New York
Facilities are shown in Tables 16 and 17.
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Table 16
Status of Key Permits and Approvals Required for Operation
Bowline Facility
====================================================================================================================================
Permit Or Approval Agency Status Comments
====================================================================================================================================
1. Certificate to Operate NYSDEC Extension issued on 5/9/1996. The Permit Extension is valid until 5/15/2001
or until a new Title V permit has been issued,
whichever occurs first.
- ------------------------------------------------------------------------------------------------------------------------------------
2. Title V Operating Permit NYSDEC A Title V Application was Plant operating under Permit Shield due to
submitted to the NYSDEC in completeness determination.
June of 1997. Application
deemed administratively
complete. Draft permit is in
the process of being issued
- ------------------------------------------------------------------------------------------------------------------------------------
3. Title IV Acid Rain Permit NYSDEC Permit was issued 2/01/1999 and Permit requires compliance with SO(2)
will expire on 12/31/2004 allowance allocations in the year 2000.
- ------------------------------------------------------------------------------------------------------------------------------------
4. SPDES Permit #NY-0008010 NYSDEC SPDES Permit expired on Final permit issuance is being delayed pending
10/1/1992. A renewal NYSDEC review of discharges to the Hudson
application was submitted on River. It is typical for plants to operate
3/20/1992. under the conditions of expired permits while
renewal applications are under review.
- ------------------------------------------------------------------------------------------------------------------------------------
5. NPDES Permit NYSDEC
- ------------------------------------------------------------------------------------------------------------------------------------
6. Certificate to Operate RCDH The certificate was issued on These certificates will be incorporated into
Unit 1 Boiler (00001) 8/15/1996 and will expire on the Title V Permit once issued
Unit 2 Boiler (00002) 8/15/2001.
- ------------------------------------------------------------------------------------------------------------------------------------
7. Major Onshore Facility License NYSDEC License was issued on 11/13/1997
and will expire on 3/31/2002
- ------------------------------------------------------------------------------------------------------------------------------------
8. Chemical Bulk Storage Permit NYSDEC Renewed periodically.
- ------------------------------------------------------------------------------------------------------------------------------------
9. Joint Regional Sewer Discharge JRSB Permit was issued on 3/13/97
Permit and will expire on 3/13/2002
====================================================================================================================================
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Table 17
Status of Key Permits and Approvals Required for Operation
Lovett Facility
====================================================================================================================================
Permit Or Approval Agency Status Comments
====================================================================================================================================
State
- ------------------------------------------------------------------------------------------------------------------------------------
1. Certificate to Operate NYSDEC Extension issued on 5/9/1996. The Permit Extension is valid until
5/15/2001 or until a new Title V permit
has been issued, whichever occurs
first.
- ------------------------------------------------------------------------------------------------------------------------------------
2. Title V Operating Permit NYSDEC A Title V Application was submitted Plant operating under Permit Shield due
to the NYSDEC in June of 1997. to completeness determination.
Application deemed administratively
complete. Draft permit is in the
process of being issued
- ------------------------------------------------------------------------------------------------------------------------------------
3. Title IV Acid Rain Permit NYSDEC Permit was issued 2/01/99 and will Permit requires compliance with SO(2)
expire on 12/31/2004 allowance allocations beginning in the
year 2000. Also, NO(X) limits apply to
Lovett Units 4 and 5 in the year 2000.
- ------------------------------------------------------------------------------------------------------------------------------------
4. SPDES Permit #NY0005711 NYSDEC SPDES Permit expired 10/1/1996. Covers discharges to Hudson River.
A renewal application was Final permit issuance is being delayed
submitted on 3/19/1996. pending NYSDEC review of discharges to
the Hudson River. It is typical for
plants to operate under the conditions
of expired permits while renewal
applications are under review.
- ------------------------------------------------------------------------------------------------------------------------------------
5. SPDES Permit #NY-0166456 NYSDEC A new permit was received Covers discharges from CAMF.
6/30/1999. Expires 7/01/2004.
- ------------------------------------------------------------------------------------------------------------------------------------
6. Solid Waste - Part 360 Permit NYSDEC A renewal application was submitted
in December 1998 and is undergoing
review at the NYSDEC.
- ------------------------------------------------------------------------------------------------------------------------------------
7. Certificate to Operate RCHD These certificates will be incorporated
Unit 3 Boiler (00003) Issued: 1/24/96, Expires: 1/24/2001 into the Title V Permit once issued
Unit 4 Boiler (00004) Issued: 6/1/96, Expires: 6/1/2001
Unit 5 Boiler (00005) Issued: 6/1/96, Expires: 6/1/2001
Various Other Emission Points Issued: 1996, Expires: 2001
- ------------------------------------------------------------------------------------------------------------------------------------
8. Major Onshore Facility License NYSDEC License was issued 8/12/1996 and
expired on 3/31/1999
- ------------------------------------------------------------------------------------------------------------------------------------
9. Chemical Bulk Storage Permit NYSDEC Renewed periodically.
- ------------------------------------------------------------------------------------------------------------------------------------
10. Petroleum Bulk Storage Permit NYSDEC Expires 3/31/2002
====================================================================================================================================
Regulatory Compliance
The Mirant New York Facilities are currently subject to various
state and federal permits and regulations with respect to NO(X) and SO(2)
emissions including RACT requirements, Title IV of the Clean Air Act
requirements, and Title I Ozone Transport Commission requirements.
Title I NO(X) RACT Regulations
The location of the Mirant New York Facilities in designated ozone
non-attainment areas triggered RACT requirements. A NO(X) averaging plan is used
to comply with the requirements. This entails over-controlling at certain units
to cover the other generating unit requirements. The NO(X) RACT emission rates
for the Mirant New York Facilities are 0.25 lb/MMBtu while burning gas/oil and
0.45 lb/MMBtu while burning coal. A weighted average (coal/oil) emission rate is
calculated for compliance with RACT.
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Title IV NO(X) Regulations
Title IV does not put in place a NO(X) allowance system comparable
to that established for SO(2). Reduction of NO(X) emissions is accomplished by
imposing emission limits on individual units or a group of units, primarily the
coal-fired units. The existing NYDEC NO(X) limits for the coal-fired Lovett
Units 4 and 5 are more stringent than the Title IV Acid Rain NO(X) Regulations.
Title I NO(X) Limitations - NO(X) Allowances
The Title I ozone transport requirements targets NO(X) emissions
during the ozone season (May through September). New York initially promulgated
regulations pursuant to the September 27, 1994 MOU among Northeast Transport
States and subsequently pursuant to USEPA's SIP Call to further control NO(X)
emissions from power plants beginning in May 1, 1999. Under this rule,
particular generation units have been allocated specific ozone season NO(X)
allowance "caps". Affected units are required to maintain an adequate amount of
NO(X) allowances for their emissions during the ozone season.
Presented in Table 18 is the allocation of allowances to the Mirant
New York Facilities through 2020.
Table 18
NO(X) Allowances
Mirant New York Facilities
(Tons/Year)
Facility 1999-2002 2003-2020(1)
-------- --------- ------------
Bowline Facility 885 800
Lovett Facility 2,585 459
--------------
(1) Represents assumed allowances through the term of the
Projected Operating Results. Allowances beyond 2003 may
be adjusted with changes in regulations.
Mirant New York will be required to obtain NO(X) allowances for
actual NO(X) emissions in excess of allocations for the year 2000 and beyond.
For NO(X) allowances, the current spot market is approximately $1,000 per ton
with prices fluctuating from approximately $500 to $7,500 per ton during 1999
and 2000. The cost of NO(X) allowances will be impacted in 2003 by the
ratcheting of allowances associated with the USEPA's ozone reduction program and
the associated installations of SCR by many plants. For the purpose of the
Projected Operating Results, we have assumed a NO(X) allowance price of $1,000
per ton through 2002, $2,300 in 2003, $2,000 in 2004 and $1,700 in 2005. After
2005, the NO(X) allowance price has been assumed to increase at the rate of
inflation.
Title IV SO(2) Limitations - SO(2) Allowances
The Mirant New York Facilities are subject to Phase II of the
federal Acid Rain Program of the Clean Air Act and, beginning in 2000, Mirant
New York must possess SO(2) allowances equal to the actual emissions. Each of
the Mirant New York Facilities was allocated a set of SO(2) allowances for the
years 2000 to 2009 and a second set beginning 2010. The SO(2) allowances assumed
through 2020 are presented in Table 19.
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Table 19
SO(2) Allowances
Mirant New York Facilities
(Tons/Year)
Facility 2000-2009 2010-2020(1)
-------- --------- ------------
Bowline Facility 8,479 8,495
Lovett Facility 9,779 9,801
----------
(1) Represents assumed allowances through the term of the
Projected Operating Results. Allowances may be adjusted
with changes in regulations.
Mirant New York will be required to obtain SO(2) allowances for
actual SO(2) emissions in excess of allocations for the year 2000 and beyond.
Future cost of allowances will be market dependent and could be higher or lower
than the current values for such allowances. For the purpose of the Projected
Operating Results, we have assumed the present spot market price of SO(2)
allowances of approximately $150 per ton and have assumed that it would increase
annually at the rate of inflation.
Air Emissions
The air emissions presented in Table 20 have been used in the
Projected Operating Results to evaluate the need and associated costs of the
NO(X) and SO(2) allowances.
Table 20
Emissions and Limits
Mirant New York Facilities
(lb/MMBtu)
Facility Current Projected Emission Limit
SO(2) NO(X)(1) SO(2) NO(X)(1) SO(2) NO(X)(1)
----- -------- ----- -------- ----- --------
Bowline Units 1 0.11 0.16 0.11 0.16 0.4 0.25
Bowline Unit 2 0.15 0.2 0.15 0.2 0.4 0.25
Lovett Unit 3 0.05 0.14 0.05 0.14 0.4 0.25
Lovett Unit 4 0.84 0.35 0.84 0.35 1.0(2) 0.45
Lovett Unit 5 0.84 0.36 0.84 0.36 1.0(2) 0.45
--------------
(1) Emissions during ozone season.
(2) SO(2) limit increases to 1.5 lb/MMBtu when only one unit (Lovett
Unit 4 or 5) is operating
Wastewater Compliance
The Bowline Facility is one of a number of power plants that
discharge once-through cooling water to the Hudson River and have been operating
under the requirements of the HRSA signed on December 19, 1980 by the NYSDEC,
the USEPA, the Hudson River utilities, and various environmental groups. Under
the terms of the HRSA (as well as subsequent modifications), the NYSDEC agreed
to authorize the continued use of once-through cooling water systems provided,
among other conditions, that: (i) the utilities maintain reduced cooling water
flow schedules regulating the quantity and timing of water intake at the plants,
and (ii) schedule plant outages during fish spawning cycles.
The HRSA requires that the Bowline Facility have flow reductions
and/or outages at either one or both of the Bowline units for 30 unit days
between May 15 and June 30. Also, another 31 unit days of reductions/outages are
required during the month of July. Mirant is evaluating various options to avoid
the 30-day
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shutdown period. Such options could require additional capital expenditures.
Such expenditures cannot be defined at the present time.
Unit outage credits under the HRSA can be traded between Roseton,
Bowline and Indian Point Facilities for the May 15 through June 30 time period
as long as the credits were accrued during the same year. Such credits allow the
Bowline Facility to continue operating both units as long as Roseton or Indian
Point Facilities had experienced outages that exceeded their respective
requirements. The Bowline Facility can meet the July outage requirement by
drawing outage credits from Indian Point regardless of the year accrued. Mirant
New York has reported that sufficient credits have been available in the past to
operate the Bowline Facility at desired levels without curtailment.
The wastewater compliance history of the Mirant New York Facilities
does not indicate any future non-compliance trends.
Future Environmental Requirements
Certain future requirements relative to the revised PM(2.5)
standard, regulation of mercury emissions, regional haze, regional visibility,
water intake structure regulations, potential ratcheting of SO(2) and NO(X)
emissions by New York, and potential ratcheting of the SO(2) allowance program
beyond the year 2009 may affect the Mirant New York Facilities in the future by
imposing more stringent requirements than those in effect at the present time.
MIRANT NEW ENGLAND FACILITIES
Description of the Canal Facility
Mechanical Equipment and Systems
Steam Cycle and Heat Rejection Systems and Components
Canal Unit 1 has a Westinghouse, tandem-compound, four-flow, double
reheat condensing steam turbine with a B&W, once-through, supercritical,
pressurized furnace, producing 3,720,000 pounds per hour ("lb/hr") of steam at
3,825 pounds per square inch ("psig") and 1,005(degree)F. Canal Unit 1 was
placed in service in 1968. Canal Unit 1 is a double reheat furnace with a reheat
steam temperature of 1,000(degree)F. In 1995, Canal Unit 1 was modified to
reduce NO(X) emissions by installing overfire air injection ports, new low-NO(X)
burners and two gas recirculation fans. In 2000, a new SCR unit and an on-demand
ammonia production unit have been installed to reduce Canal Unit 1 NO(X)
emissions. Canal Unit 1 condenser system is a once through cooling system
utilizing seawater from the Cape Cod Canal. Cooling water is returned to the
canal through diffusers.
The Canal Unit 2 has a Westinghouse, tandem compound, four-flow,
reheat condensing steam turbine with a B&W, natural circulation boiler with a
balanced draft furnace. Canal Unit 2 was placed in service in 1976. The boiler
produces 4,002,000 lb/hr of steam at 2,500 psig and 1,005(degree)F superheat.
The reheat steam temperature is 1,005(degree)F. The Canal Unit 2 condenser
cooling water system is a once-through-cooling system utilizing seawater from
the Cape Cod Canal. Cooling water is returned to the canal through diffusers.
Fuel Systems
A ship's berthing basin and tanker terminal, adjacent to the Canal
Facility along the canal, can accommodate 450,000-barrel tankers. No. 6 fuel oil
is stored in a tank farm with a total capacity of approximately 1.2 million
barrels, which is sufficient for 26 days operation of the Canal Facility at full
load.
In 1996, when Canal Unit 2 was modified to allow co-firing of
natural gas, an 18-inch diameter natural gas pipeline designed for 700 psig
service was constructed under the canal from the north shore to the plant.
S-55
Make-Up Water System
Makeup and service water for the Canal Facility is obtained from two
wells located in the switchyard. Well water is stored in a 200,000-gallon
service water tank which, in an emergency, can also be supplied from the Town of
Sandwich water mains.
Both units at the Canal Facility have makeup water demineralizers
and full flow condensate polishing demineralizers. Demineralized water is stored
in a 150,000-gallon condensate storage tank.
Electrical and Control Systems
Plant Control Systems
Canal Units 1 and 2 are controlled from a single enclosed control
room. A Bailey Infi 90 state-of-the-art DCS with data acquisition features has
been installed to replace the older original analog control systems. The
operator control panels and bench boards were modified as part of the control
system replacement.
Electrical Distribution
The Canal Facility electrical arrangement includes two generators
which are unit-connected to a 345-115 kV substation. Plant auxiliary power is
derived from the generator leads and reserve auxiliary power is derived from a
tertiary winding in the 345-115 kV autotransformer.
Emergency Power Systems
Critical DC loads are served by one 125-volt battery system for
Canal Unit 1 and two 125 volt battery systems for Canal Unit 2. Switching is
provided to allow operation of all plant DC loads from one battery system when
necessary.
Static inverters are provided for critical AC loads. In addition,
for each of Canal Units 1 and 2, there is a Cummins 350 kW 480 V diesel
generator to supply critical motor loads and maintain power to battery chargers
in case of loss of both main generators and all off-site power.
Environmental Controls and Equipment
Air Pollution Control Systems
The basic strategies and air pollution control technologies employed
at the Canal Facility include: (1) purchasing fuels of the required sulfur
content in order to control emissions of SO(2); (2) utilizing ESPs on Canal
Units 1 and 2 for particulate and opacity control; and (3) utilizing low-NO(X)
burners on Canal Unit 2 to reduce NO(X) emissions.
All of the steam units are equipped with a CEMS as required by state
and federal regulations. These monitors measure and record emission levels for
opacity, SO(2), NO(X), CO, O(2), and CO(2), as well as volumetric flow.
Off-Site Requirements
Electrical Interconnection
The electrical output of the Canal Facility is delivered to a single
576 MVA main power transformer for Canal Unit 1 and to two, 300 MVA main power
transformers for Canal Unit 2. Overhead transmission lines carry the power over
the top of the Canal Unit 1 and down to a six breaker, ring bus in the
switchyard. The ring bus supplies two 345 kV transmission lines and two
autotransformers that step down the voltage to supply the local 115 kV system.
The Canal Facility substation includes terminations for two 345 kV
transmission lines and two 400 MVA, 345/115 kV autotransformers, which provide
power to the area 115 kV transmission network.
S-56
Description of the Kendall Facility
Mechanical Equipment and Systems
Steam Generators
The Kendall Facility delivers 300,000 lb/hr of 200 psig steam to a
subsidiary of NSTAR for distribution to industrial users and a major health care
facility located on the Boston side of the Charles River. The Kendall Facility
has three steam generators that burn No. 6 oil and natural gas to produce a
total of 700,000 lb/hr steam at 1,320 psig and 910(degree)F. The first two
boilers were placed in service in 1949. These boilers are B&W, natural
circulation, balanced draft units producing 200,000 lb/hr each. In 1954, the
third boiler was installed and placed in operation. This boiler is a larger B&W,
natural circulation, balanced draft unit producing 300,000 lb/hr.
COM/Energy Steam's industrial and commercial steam users represent a
thermal load which is nearly three times as high in winter than in summer
because the steam is largely used for space heating. In the past, the two
auxiliary boilers have only run in an emergency or in the winter when it is
necessary to make peak electrical and steam output simultaneously.
Steam is supplied from the three boilers to a common header that
supplies the three condensing steam turbine generators.
Turbine Generators
The Kendall Facility includes three steam turbine generators. The
steam turbines were installed in 1949, 1951 and 1958. Kendall Units 1 and 2 are
Westinghouse, single cylinder, single automatic extraction, condensing type
steam turbines. Kendall Unit 1 is rated at 15 MW electric and Kendall Unit 2 is
rated at 20 MW electric. These units have a 200 psig controlled extraction. The
extraction steam is supplied to NSTAR distribution system for local steam
customers in Cambridge and Boston. The Kendall Unit 3 steam turbine generator is
a Westinghouse, 25 MW, single cylinder, and straight condensing turbine. Kendall
Unit 3 is not capable of supplying export steam. Depending on operational
requirements, Kendall Unit 2 or 3 extraction provides steam for feedwater
heating in the common closed feedwater heater serving all three boilers.
Combustion Turbines
The Kendall Facility has two Pratt Whitney, Turbo Power and Marine,
20 MW, "Twin-Pack", FT-4, aeroderivative single-shaft CTs, operated in a simple
cycle mode. These CTs fire Jet A fuel.
Fuel System
No. 6 fuel oil for the Kendall Facility steam units is stored in two
fuel oil ASTs that hold a total of approximately 2,250,000 gallons. There are
two fuel oil pumps and heater houses. Jet A fuel for the Kendall CTs is stored
in three 30,000-gallon underground single wall tanks located adjacent to the
CTs. All fuel oil is delivered to the Kendall Facility by truck. Natural gas is
delivered at 90 psig through a buried 8-inch pipeline to the rear of the Kendall
Facility.
Kendall Units 1 and 2 share a common fuel oil line and are equipped
with two pairs of redundant fuel oil pumps and heaters plus a backup pump.
Kendall Unit 3 has its own dedicated fuel oil line and is also equipped with one
pair of redundant fuel oil pumps and heaters. The Kendall Unit 3 fuel oil line
also supplies the package boilers, which have their own oil pumps, heaters and
strainers.
Water/Wastewater Systems
Makeup water for the Kendall Facility is taken from the City of
Cambridge water supply. There are four demineralizer trains, which treat water
in Kendall Units 1, 2 and 3. There are also three zeolites and two dealkalizers
to treat water for Kendall Facility auxiliary boilers. The Kendall Facility has
a waste neutralization system for storage and treatment of wastes from the
demineralizer system and boiler blowdown. There are five connections to
S-57
the municipal sewers. Stormwater is collected through a number of stormwater
drains, directed to the oil-water separator and then discharged into the Charles
River.
Circulating/Cooling Water
The Kendall Facility has a once-through cooling system. Two
circulating water pumps take suction from the Broad Canal through traveling
water screens and supply cooling water to each condenser. Water in the Broad
Canal is supplied by the Charles River.
Fire Protection Systems
The firewater supply system water for the Kendall Facility is
supplied from the City of Cambridge. A motor-driven fire protection pump takes
suction from the city water line and supplies a wet pipe system covering the
boiler fronts, turbine lube oil sumps, hose stations in the plant and hydrants
in the yard. A Halon, CO(2), and FM2000 deluge system is used to protect the CTs
and CEMS enclosure. Portable carbon dioxide and dry chemical extinguishers are
located throughout the plant.
Electrical and Control Systems
Main Control System
Individual analog control systems are provided for each boiler and
turbine-generator at the Kendall Facility. There is one common control room for
all three boilers. The combustion and feedwater controls have been updated and
are by Fisher Provox. The burner management systems are a relay type by Allen
Bradley.
Environmental Controls and Equipment
Air Pollution Control Systems
Operational practices include control of excess air levels, as well
as the need to restrict output (i.e., thermal fuel input) to the Kendall
Facility. Mirant Kendall staff indicates that regulatory emissions limits
generally restrict plant output to approximately 67 MW, whereas, without
emissions limits, the Kendall Facility could generate up to approximately 74 MW.
Also, the boiler burners have been modified to low-NO(X) burners.
The Kendall Facility has a CEMS installed on Stack Nos. 1 and 2,
which monitors NO(X), CO, SO(2) and opacity. Stack No. 1 services Boiler Nos. 1
and 2, while Stack No. 2 services Boiler No. 3. Kendall CTs 1 and 2 are both
equipped with dedicated stub stacks and no CEMS. Stack No. 3, which services
Boiler Nos. 4 and 5, is equipped for annual stack testing.
Off-Site Requirements
Transmission Interconnection
Each of the five generators at the Kendall Facility is connected to
the 13.8 kV bus system through a generator breaker, a generator bus and two
generator bus ties. Each of the steam turbine generators is connected to a
separate generator bus, which includes one circuit breaker for connection to the
generator buses and two generator bus ties for connection to the Cambridge
Electric Light Company and Commonwealth Energy Systems (collectively referred to
herein as "ComElec") distribution bus system. The two CTs each connect directly
to the ComElec distribution buses.
Off-Site Steam Distribution
The Kendall Facility is required to deliver up to 300,000 lb/hr of
200 psig steam to NSTAR. Steam produced is ultimately delivered to local
industrial users and to the Massachusetts General Hospital located across the
Charles River from the Kendall Facility in Boston. During periods of maximum
electrical delivery, 100,000 lb/hr of this steam can be supplied by each of the
two extraction turbines, Kendall Units 1 and 2. Two auxiliary package boilers
are available to provide additional amounts of 200 psig steam. The package
boilers and the associated auxiliary
S-58
equipment are owned by NSTAR and operated by Mirant Kendall plant operators.
Approximately 65 percent of the steam distributed off-site is returned in the
form of usable condensate.
Operation and Maintenance
Canal Facility staffing presently consists of 115 operating and
maintenance personnel. The two units at the Canal Facility are operated
utilizing five eight-hour operating shifts. Each shift consists of 10 operations
personnel. One full shift is on "days" and is available for shift relief due to
sickness or vacation, to perform maintenance activities and to participate in
the facility training programs.
Kendall Facility staffing presently consists of 42 personnel. The
two units are operated utilizing five eight-hour operating shifts consisting of
five operation and technical personnel per shift. The maintenance department
provides maintenance personnel as required to perform preventive and corrective
maintenance. Mirant Kendall's objective is to maintain the highest reliability
of the export steam supply.
Operating History
The annual historical performance of the Mirant New England
Facilities, as reported by Mirant New England, is set forth in Table 21.
Table 21
Operating History
Mirant New England Facilities
Canal Kendall
----- -------
Net Capability Rating (MW)(1)(2)
1996 1,112 92
1997 1,112 92
1998 1,112 92
1999 1,110 94
2000 1,114 95
Net Generation (GWh)(2)
1996 3,021.7 95.1
1997 5,416.4 107.7
1998 6,107.7 97.6
1999 5,472.3 122.7
2000 3,919.8 112.9
Annual Net Heat Rate
(Btu/kWh)(2)(3)
1996 10,118 11,051
1997 9,733 11,300
1998 9,732 12,310
1999 9,958 11,728
2000 9,877 11,537
Net Capacity Factor (%)(2)(3)(4)
1996 35.5 37.6
1997 56.8 40.8
1998 61.4 33.2
1999 58.8 38.4
2000 46.1 37.9
Equivalent Availability Factor (%)(3)
1996 69.9 94.1
1997 77.8 97.2
1998 80.0 94.8
1999 79.6 93.3
2000 77.9 96.8
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Table 21
Operating History
Mirant New England Facilities
Canal Kendall
----- -------
Oil Use (Gallons x 1000)
1996 N/A N/A
1997 N/A N/A
1998 N/A N/A
1999 351,246 N/A
2000 288,624 N/A
Gas Use (Mcf x 1000)
1996 N/A 14.8
1997 N/A 17.0
1998 N/A 15.3
1999 18.4 14.1
2000 211.2 16.4
--------------------
(1) Summer rating.
(2) Only data available for 1996 through 1998 was the six-year
average for 1993 through 1998.
(3) Represents weighted average for annual net heat rate, net
capacity and equivalent availability factor.
(4) Does not include Kendall CTs, which have a capacity factor of
less than 1 percent.
The Canal Facility
The Canal Unit 1 boiler was chemically cleaned in 2000. The Canal
Unit 2 boiler was chemically cleaned in 1996. Oxygenation of boiler feedwater
has been initiated. This process causes a thin layer of a tightly adhering
corrosion film to form on the walls of the feedwater and therefore reduces the
active corrosion and the transport of corrosion products in to the boiler. This
feed water oxygenation process is expected to reduce boiler-cleaning
requirements to once in a ten-year period. The Canal Unit 2 boiler is scheduled
to be cleaned in 2004.
Canal Facility boilers are inspected annually in accordance with
state licensing requirements. During 1999 and 2000, new soot blower controls
have been installed and the boiler economizer was replaced.
Due to boiler water-wall tube leaks, Canal Unit 1 is in the process
of completing a full furnace wall boiler tube replacement. Half of the furnace
water wall tubes were replaced in 2000 and the remainder of the project will be
completed in the spring of 2001.
In 1982, the Canal Unit 1 generator stator was rewound. The LP
turbine rotors were replaced in 1990 with a new, more rugged and efficient
design. The generator rotor and exciter were replaced during the same extended
unit outage.
In December 1995, the Canal Unit 1 IP turbine sustained major damage
when first row blading broke free and damaged downstream rows. The cause of
failure was diagnosed as blade creep. A number of rotating and stationary blades
had to be replaced. Repairs extended well into 1995. A major steam turbine
overhaul is scheduled for Canal Unit 1 in the spring of 2001. During the outage,
nozzle blocks, control stages and four rows of blading will be replaced.
In 2000, the Canal Unit 1 generator static exciter failed. Canal
Unit 1 is operating with a spare static exciter obtained from
Westinghouse/Siemens. The replacement exciter will be available and installed
during the fall of 2001.
In 1996, the Canal Unit 2 boiler was fitted with low-NO(X) burners
and increased capacity overfire-air ports. Gas firing capability was added at
that time.
S-60
A Canal Unit 2 gas recirculation fan was damaged in August 1998. It
was repaired and returned to service in November 1998. Control logic was changed
to prevent reoccurrence of the problem.
The Canal Unit 1 condenser was retubed in 1978 with Cu-Ni tubes. The
Canal Unit 2 steam turbine was overhauled in the fall of 1993. The generator
stator was rewound in 1994 and re-inspected in 1997.
A complete Canal Unit 2 turbine overhaul was accomplished in 1999 as
scheduled. The first two rows of IP turbine blades were replaced, new cold end
baskets, new control stage blades, new upgraded design nozzle blocks were
replaced. During the turbine a new economizer header was also installed in the
Canal Unit 2 boiler. The next Canal Unit 2 turbine overhaul is scheduled for
2006.
In 2000, the Canal Unit 1 4,160 V switchgear was upgraded.
The Kendall Facility
Low-NO(X) burners were installed in the Kendall Unit 3 boiler in
1999. The Kendall Unit 3 boiler was alkaline cleaned in 1973, 1979 and 1999. The
early generation boilers at the Kendall Facility were originally designed to
burn both coal and oil. Presently they are burning a relatively clean fuel oil.
Recently, the Kendall Facility installed feed-water demineralizers that produce
a high quality feed water. These improvements minimize the challenges and
degradation of the boilers and result in minimal boiler cleaning and
maintenance.
In 2000, the Kendall Unit 3 main condenser was retubed with
aluminum-brass tubes. Aluminum-brass is the material that was installed in the
original installation in the late 1950s. This is the first time the Kendall Unit
3 condenser has been retubed. Both Kendall Unit 1 and 2 condensers have been
retubed in the last five years.
The Kendall Unit 2 turbine is scheduled for a major overhaul in
2001. New nozzle blocks and several rows of blading and associated hardware will
be replaced. The Kendall Unit 2 steam turbine has the highest capacity factor of
the three installed turbines. This major turbine overhaul will improve the
efficiency and prepare the turbine for extended operation following the
installation of the new combined cycle plant that will be connected to the 1,300
psig common steam header.
The Kendall Facility boilers are inspected annually as required by
The Commonwealth of Massachusetts. Inspections of the Kendall Facility boilers
in 2000 by the plant's insurer reported overall conditions to be satisfactory
and that no additional work outside of the regularly scheduled maintenance was
required.
The Kendall Unit 1 superheater and economizer tubes were replaced in
1988. Kendall Unit 2 received new economizer and superheater tubes as well as a
superheater outlet header in 1998. Kendall Units 1 and 2 boilers reportedly have
not had a waterwall tube leak in the past 29 years. The Kendall Unit 3 boiler
has its original pressure parts including economizer and superheater.
No other major Kendall Facility modifications or major capital
improvements are planned scheduled at this time.
Environmental Assessments
Environmental Site Assessments
Canal Electric Company and Cambridge Electric Light Company retained
responsibility for environmental response work under the Massachusetts
Contingency Plan for certain environmental conditions at the Canal and Kendall
Facilities, which have been identified in the relevant Asset Sale Agreements.
The environmental conditions at the Canal and Kendall Facilities that are being
addressed under the Massachusetts Contingency Plan are identified in the Canal
Electric Asset Sale Agreement and were reported in the Phase I and Phase II
environmental studies undertaken in connection with the divestiture process by
an environmental consultant engaged by the Commonwealth subsidiaries.
S-61
In connection with the sale of the Mirant New England Facilities,
Commonwealth and EUA provided a $15 million pollution liability insurance policy
to Mirant Canal and Mirant Kendall which is intended to mitigate the risk of any
unknown contamination at the Canal Facility or the Kendall Facility that could
trigger a legal requirement to perform an environmental cleanup or could give
rise to third party claims within ten years after the closing.
In 1999, we reviewed the various Phase I and II ESA reports
regarding environmental investigations prepared by an environmental consultant
for the Canal and Kendall Facilities, as well as a risk characterization report
for the Kendall Facility during 1997 and 1998, which was prepared by a different
environmental consultant. The Phase I and II environmental consultant
encountered observable and historical evidence of potential site contamination
that resulted in the environmental consultant conducting subsurface
environmental investigations that consisted of soil and groundwater sampling
during various phases at the Canal and Kendall Facilities. We have not been
provided for our review any ESA reports updating the previous environmental
investigations regarding the potential for site contamination issues at the
Canal and Kendall Facility sites.
For the Canal Facility, the Phase I and II environmental consultant
identified several areas at the project site at which historical releases of oil
and hazardous materials had occurred resulting in organic and/or inorganic
contamination to soil and/or groundwater that exceeded reportable
concentrations, as defined by the Massachusetts Contingency Plan. The Phase I
and II environmental consultant concluded that: (i) additional data is required
to determine the response actions in one of the release areas (metals
contaminated groundwater at RTN 4-13525); and (ii) Permanent Solutions (per the
Massachusetts Contingency Plan) have been achieved by Commonwealth Electric at
five of the release areas because a condition of No Significant Risk to human
health, safety, public welfare, or the environment exists.
We understand that Commonwealth Electric's obligation to achieve a
Permanent Solution for the metals contaminated groundwater at RTN 4-13525
expires after the occurrence of the earlier of its expending the aggregate
amount of $500,000 on remediation efforts or the fifth year anniversary of its
sale of the Canal Facility. Costs beyond these thresholds are the responsibility
of Mirant Canal. These potential future costs (monitoring and a likely
groundwater pump and treat system) are estimated to be less than $100,000 per
year and are not included in the Projected Operating Results.
For the Kendall Facility, the Phase I and II environmental
consultant identified three areas at the site at which historical releases of
oil and hazardous materials have occurred resulting in organic and/or inorganic
contamination to soil and/or groundwater that exceeded reportable
concentrations. Mirant Kendall reports that one of the RTNs, a subsurface
release of Jet A fuel (kerosene) that was discovered adjacent to three on-site
underground storage tanks ("USTs") in 1985, has been remediated by Commonwealth.
The Phase I and II environmental consultant concluded that the other two release
areas were suitable for closure under a Class A or B RAOs, with implementation
of Activity and Use Limitations ("AULs") at each area. The AULs are necessary to
eliminate potential pathways of exposure from certain carcinogens to on-site
workers. Implementation of these will require that the contaminated areas be
fenced and paved. The pavement, which must be maintained, is intended to
eliminate exposure pathways by restricting access to subsurface soils. If any
soil intrusive activities, such as utility or construction work, are conducted
within the AUL area, then a Soil Management Plan and a Health and Safety Plan
would have to be prepared and implemented.
Status of Permits and Approvals
The status of key permits and approvals for the Mirant New England
Facilities are shown in Tables 22 and 23.
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Table 22
Status of Key Permits and Approvals Required for Operation
Canal Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
Federal
- ------------------------------------------------------------------------------------------------------------------------------------
1. Hazardous Waste USEPA USEPA ID No. MAD071708929 Classified as small quantity generator of
Generator ID Number hazardous waste, large quantity generator
of waste oil.
- ------------------------------------------------------------------------------------------------------------------------------------
2. NPDES Stormwater Permit USEPA and MADEP Re-authorized 12/31/00 Submitted timely renewal application; MADEP
(for multiple discharges) issued "Notice of Administrative
Completeness."
- ------------------------------------------------------------------------------------------------------------------------------------
3. NPDES Permit for USEPA and MADEP Reapplication deemed Submitted timely renewal application;
discharge to Cape administratively complete currently under USEPA review. Operating
Cod Canal 5/19/94 under existing Permit. It is typical for
plants to operate under conditions of
expired permits while renewal applications
are under review.
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
4. Title V Operating Permit MADEP Timely application filed 5/1/95. Currently operating under a "Permit Shield"
Notice of "Administrative due to completeness determination.
Completeness" received on
9/20/95.
Revised 11/3/99
- ------------------------------------------------------------------------------------------------------------------------------------
5. Water Withdrawal MADEP Reissued 9/24/97 For two on-site wells, average 0.45 mgd and
Registration Expires 1/1/08 164.5 mgd
- ------------------------------------------------------------------------------------------------------------------------------------
6. Title IV Acid Rain Permit MADEP Issued 12/30/97
- ------------------------------------------------------------------------------------------------------------------------------------
7. NO(X) RACT ECP (for MADEP Conditional approval granted
Boiler Nos. 1 and 2) 2/9/95. ECP has been modified
1/23/98.
- ------------------------------------------------------------------------------------------------------------------------------------
8. Final Plan Approval MADEP Issued 11/14/96 For auxiliary boilers
- ------------------------------------------------------------------------------------------------------------------------------------
9. Class A Recycling Permit MADEP Presumptive approval submitted Allows burning 50,000 gallons per year of
12/3/98; valid for 5 years used oil in Boiler 1.
====================================================================================================================================
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Table 23
Status of Key Permits and Approvals Required for Operation
Kendall Facility
================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- --------------------------------------------------------------------------------------------------------------------------------
Federal
- --------------------------------------------------------------------------------------------------------------------------------
1. Hazardous Waste USEPA USEPA-ID No. D000846238 Classified as small quantity
Generator ID Number generator of hazardous waste, large
(hazardous waste quantity generator of waste oil.
disposal tracking)
- --------------------------------------------------------------------------------------------------------------------------------
2. NPDES Stormwater Permit USEPA and Issued 1/20/98 Submitted timely renewal
(general multi-sector MADEP application; the MADEP issued
stormwater permit) "Notice of Administrative
Completeness."
- --------------------------------------------------------------------------------------------------------------------------------
3. NPDES Permit (wastewater USEPA and Issued 8/18/88. Renewal Submitted timely renewal
discharge) MADEP application made and deemed application; currently in USEPA
administratively complete review. Operating under existing
6/17/93. Permit. It is typical for plants to
operate under conditions of expired
permits while renewal applications
are under review.
- --------------------------------------------------------------------------------------------------------------------------------
State
- --------------------------------------------------------------------------------------------------------------------------------
4. Determination of MADEP Issued 10/6/92 Limited to 52.82 mgd.
Non-Consumptive Water Use
(for non-contact cooling
water from the plant)
- --------------------------------------------------------------------------------------------------------------------------------
5. Title V Operating Permit MADEP Timely application filed Currently operating under a "Permit
9/25/95. Notice of Shield" due to completeness
"Administrative determination.
Completeness" issued.
Modified 11/99
- --------------------------------------------------------------------------------------------------------------------------------
6. Title IV Acid Rain Permit MADEP Issued 12/22/97
- --------------------------------------------------------------------------------------------------------------------------------
7. NO(X) RACT ECP MADEP Issued 3/30/98
- --------------------------------------------------------------------------------------------------------------------------------
8. Sewer Use Discharge Permit MWRA Issued 5/22/98 Allows discharge of industrial
Expires 4/15/02 wastewaters to the municipal sewer
system
================================================================================================================================
Regulatory Compliance
The Mirant New England Facilities are currently subject to various
state and federal regulations with respect to NO(X) and SO(2) emissions
including RACT requirements, Title IV of the Clean Air Act limits, and Title I
Ozone Transport Commission requirements as well as state regulations.
RACT Regulations
The location of the Mirant New England Facilities in designated
ozone non-attainment areas triggered RACT requirements. The Emissions Compliance
Plans issued for the Canal and Kendall Facilities have different NO(X) and CO
emissions restrictions based on heat input capacity of the combustion units.
Both Mirant New England plants have been operating within their respective
limits.
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Title I NO(X) Limitations - NO(X) Allowances
The Title I ozone transport requirements targets NO(X) emissions
during the ozone season (May through September). Massachusetts initially
promulgated regulations pursuant to the September 27, 1994 MOU among Northeast
Transport States and subsequently pursuant to USEPA's SIP Call to further
control NO(X) emissions from power plants beginning in May 1, 1999 ("NO(X)
Budget Rule") with further reductions in 2003. Under this rule, particular
generation units have been allocated specific ozone season NO(X) allowance
"caps". Affected units are required to maintain an adequate amount of NO(X)
allowances for their emissions during the ozone season (May 1 through September
30 of each year). Under this same MOU, NO(X) emissions are to be further reduced
beginning with the 2003 ozone season. Massachusetts revised its NO(X) budget
rule to implement a formula-based system for allocating allowances in 2003 and
beyond. This system is based upon the actual utilization of the facility
measured by its actual heat input in a rolling three-year period preceding the
allocation year. In this way, the effects of deregulation and the competitive
market on plant capacity factors will be reflected in the NO(X) allocations.
The draft allocation of allowances to the Mirant New England
Facilities are presented in Table 24.
Table 24
NO(X) Allowances
Mirant New England Facilities
(Tons/Year)
Facility 2001-2002 2003-2020(1)
-------- --------- ------------
Canal 2,168(2) 1,561
Kendall 106 116
--------------
(1) Represents assumed allowances through the term of the
Projected Operating Results. Allowances beyond 2003 may
be adjusted as with changes in regulations.
(2) 14.91% of state allowance cap; may be adjusted in
subsequent years. 2,168 allowances in 2000 (included 48
reserve allowances).
In 2000, the Canal Unit 1 SCR was commissioned during the ozone
season, lowering its NO(X) generation, although a small number of allowances
were purchased to balance the plant's account. In 2000, Mirant Kendall did not
need to purchase additional allowances.
Mirant New England is required to obtain NO(X) allowances for actual
NO(X) emissions in excess of allocations for each ozone season in a given year.
For NO(X) allowances, the current spot market is approximately $1,000 per ton
with prices fluctuating from approximately $500 to $7,500 per ton during 1999
and 2000. The cost of NO(X) allowances will be impacted in 2003 by the
ratcheting of allowances associated with the implementation of Phase III of the
MOU. For the purpose of the Projected Operating Results, we have assumed a NO(X)
allowance price of $1,000 per ton through 2002, $2,300 in 2003, $2,000 in 2004
and $1,700 in 2005. After 2005, the NO(X) allowance price has been assumed to
increase at the rate of inflation.
Title IV SO(2) Limitations - SO(2) Allowances
The Mirant New England Facilities are subject to Phase II of the
federal Acid Rain Program of the Clean Air Act and, beginning in 2000, Mirant
New England must possess SO(2) allowances equal to the actual emissions. Each of
the Mirant New England Facilities was allocated a set of SO(2) allowances for
the years 2000 to 2009 and a second set for the years after 2010. The SO(2)
allowances assumed through 2020 are presented in Table 25.
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Table 25
Phase II SO(2) Allowances
Mirant New England Facilities
(Tons/Year)
Facility 2000-2009 2009-2020(1)
-------- --------- ---------
Canal 31,234 30,358
Kendall 828 828
--------------
(1) Represents assumed allowances through the term of the
Projected Operating Results. Allowances may be adjusted
with changes in regulations.
Mirant New England is required to obtain SO(2) allowances for actual
SO(2) emissions in excess of allocations for the year 2000 and beyond. Future
cost of allowances will be market dependent and could be higher or lower than
the current values for such allowances. For the purpose of the Projected
Operating Results, we have assumed the present spot market price of SO(2)
allowances of approximately $150 per ton and have assumed that it would increase
annually at the rate of inflation. In 2000, the Mirant New England Facilities
did not purchase any additional allowances above those allocated to their
accounts.
Air Emissions
In April 2001, the MADEP promulgated regulations 310 CMR 7.29 to
control emissions of NO(X), SO(2), and CO(2). The regulations also allow for
the future regulation of mercury and particulate matter. The regulations
establish output-based emission rates for these pollutants. The effect of
these new regulations for NO(X), SO(2), and CO(2) has been considered to the
extent possible in the Projected Operating Results. The likely effects of the
regulations for the Canal Facility include: (1) operating the SCR installed
on Canal Unit 1 the entire year rather than only for the ozone season to
achieve an average emission rate for the Canal Facility less than the
regulatory limit beginning October 1, 2004; and (2) lowering the sulfur
content of the fuel burned from approximately 1 percent to 0.6 percent by
October 1, 2004 and to 0.3 percent by October 1, 2006.
The air emissions presented in Table 26 have been used in the
Projected Operating Results to evaluate the need and associated costs of the
NO(X) and SO(2) allowances.
Table 26
Emissions and Limits
Mirant New England Facilities
(lb/MMBtu)
Facility Current Projected Emission Limit
SO(2) NO(X)(1) SO(2) NO(X)(1) SO(2) NO(X)(1)
----- -------- ----- -------- ----- --------
Canal
Unit 1 1.0 0.05 0.3(2) 0.05 0.3(2) 0.15(2)(3)
Unit 2 1.0 0.23 0.3(2) 0.23 0.3(2) 0.15(2)
Kendall
Units 1-3 0.13 0.21 0.13 0.21 0.56 0.28
CTs 0.14 0.22 0.14 0.22 0.34 0.40
--------------------
(1) Emissions during ozone season.
(2) 310 CMR establishes: (1) an annual average NO(X) limit of 1.5
lb/MWh to be met by October 1, 2004; (2) an annual average SO(2)
limit of 6.0 lb/MWh to be met by October 1, 2004 and 3.0 lb/MWh
to be met by October 1, 2006; and (3) an annual average limit of
1,800 lb/MWh of CO(2) to be met by October 1, 2006.
(3) Facility-wide limit.
The Kendall Facility must comply with the terms of an Administrative
Compliance Order for SO(2) emissions, which was issued by the MADEP on March 15,
1995. This order requires the Kendall Facility to limit SO(2) emissions to a
rate of 379.6 lb/hr for any single 10-hour period commencing either at 6:00
a.m., 7:00 a.m., or 8:00 a.m. and further limit SO(2) emission for the next 14
hours (i.e., the balance of a 24-hour day) to a rate of 225.4 lb/hr. These
restrictions limit the ability of the Kendall Facility to operate at full load.
Historically, the Kendall Facility was not required to operate at load factors
that would exceed the above limitations.
Wastewater Compliance
In accordance with the conditions of their NPDES permits, the Mirant
New England Facilities file monthly discharge monitoring reports with the USEPA
and MADEP. Based on a review monthly reports for 4Q98
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through 3Q00 and discussions with plant personnel, the wastewater compliance
history of the Mirant New England Facilities does not indicate any future
non-compliance trends.
Mirant Kendall also submits reports to MWRA regarding its discharge
to the sewer system. Based on a review of these reports for 2000 and discussions
with plant personnel, we did not identify any non-compliance trends.
Future Environmental Requirements
Certain future federal requirements relative to the revised PM(2.5)
standard, regulation of mercury emissions, regional haze, regional visibility,
water intake structure regulations, and potential ratcheting of the SO(2)
allowance program beyond the year 2009 may affect the Mirant New England
Facilities in the future by imposing more stringent requirements than those in
effect at the present time.
MIRANT TEXAS FACILITY
Description of the Bosque Facility
Mechanical Equipment and Systems
Turbine Generator Systems and Components
Bosque Units 1 and 2 are identical base mounted GE Frame 7FA (PG
7241 FA) combustion turbine generators operating in a simple cycle mode. Bosque
Unit 1 was placed in service on May 31, 2000. Bosque Unit 2 was placed in
service on June 1, 2000. The units are equipped with inlet filtration,
evaporative cooling, GE's DLN 2.6 multi-nozzle combustion system, and hydrogen
cooled generators rated at 171.7 MW. An excitation transformer and LCI are
included for each generator. Lubrication is provided by dedicated oil
reservoir/cooling systems for each Unit. Dedicated on-line or off-line water
washing systems are also included.
The Bosque Unit 3 generating equipment consists of one GE Frame 7FA
that is identical to those us incorporated in Bosque Units 1 and 2, one CE heat
recovery steam generator, and one 85 MW ABB-STAL steam turbine generator
operating together as a combined-cycle system. Bosque Unit 3 is scheduled to
begin commercial operation in June 2001.
Fuel Systems
An existing 33-mile natural gas pipeline connects the Bosque
Facility with a PG&E Texas L.P. pipeline. The 750 psig pipeline is owned by
Pinnacle Pipeline Company, which receives an annual capacity payment for its
use. Metering, regulation, filtering and heating of the gas is common for both
Bosque Units 1 and 2. There is no back-up fuel supply.
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Cooling System
A four-cell mechanical draft evaporative cooling tower will provide
cooling water to the Bosque Unit 3 steam condenser. Circulating water pumps take
suction from the cooling tower basin, pump cooling water through the condenser,
and back to the tower.
Water/Wastewater System
Service water for the Bosque Facility is obtained from two wells
located on-site and a Brazos River intake system. Well water is stored in a
300,000-gallon service water tank with appropriate retention for fire
protection. Both units have service water demineralizers which treat water for
use in the equipment wash systems and the evaporative cooler. Demineralized
water is stored in a 150,000-gallon tank. The Bosque Facility is constructing a
river water intake. A new water treatment building is under construction to
treat this additional water for use by the facility currently routed through an
API separator then held in a detention pond, while a discharge clarifier and
outfall to the Brazos River are being considered.
Fire Protection Systems
The firewater supply system water for the Bosque Facility is
supplied from the service water tank. The system consists of an electric
motor-driven jockey pump, and electric motor-driven main pump and a diesel
engine-driven emergency pump which takes suction from the service water tank and
supplies hose stations in the plant and hydrants in the yard. A liquid
carbon-dioxide deluge system is used to protect the CT enclosures generators,
auxiliary enclosures and the bearing tunnel. Portable extinguishers are located
throughout the facility.
Electrical and Control Systems
Plant Control Systems
The Bosque Facility is controlled from an enclosed control room,
located within the administration/maintenance building. GE Speedtronic Mark V
DCS control systems control and monitor the CTs. The steam generator is
controlled by its own ABB DCS control system.
Electrical Distribution
The Bosque Facility electrical arrangement includes four 18 kV
generators. Bosque Units 1 and 2 are unit-connected to the 345 kV substation.
The two generators for Bosque Unit 3 are connected to the 138 kV substation.
Plant auxiliary power be derived from either the 345 kV or the 138 kV to 4.16 kV
auxiliary transformer to a conventional distribution system. A battery backup
system provides emergency power loss control power and safe system shutdown
capability. The substation owner, Brazos Electric is currently installing a 138
kV backfeed into the facility.
Emergency Power Systems
No on-site emergency generation or black-start capability is
provided at the Bosque Facility.
Off-Site Requirements
Electrical Interconnection
The electrical output of the Bosque Facility is delivered to
separate main power transformers for connection with the 138/345 kV substation.
Operation and Maintenance
Bosque Facility staffing presently consists of eleven management,
operating and maintenance personnel. The two existing units at the Bosque
Facility are operated utilizing two operating shifts. Each shift consists of two
operations personnel. One Supervisor is on-duty during days with one foreman and
a maintenance employee
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through the daily, on-peak production cycle. When Bosque Unit 3 begins
commercial operation, two additional operators will be added to each shift.
Operating History
No additional historical performance data has been provided for the
Bosque Facility beyond that included in the Report.
The Bosque Units 1 and 2 simple cycle combustion turbine generators
were newly constructed, achieving commercial operation in June of 2000. During
the next five months the facilities were operated in intermediate-peaking mode,
on an approximately daily schedule and often at less than full load. Between
June and November of 2000 there have been no major maintenance activities.
No major Bosque Unit 1 or 2 modifications or major capital
improvements are planned or scheduled at this time.
Environmental Assessment
Environmental Site Assessment
We have reviewed the "Hazardous Materials Environmental Assessment
Summary Report" dated April 1999 and the Phase I ESA report dated July 1999,
prepared for the Bosque Facility by an environmental consultant. The
environmental consultant noted several buildings, sheds, and barns at the Bosque
Facility site, and observed several on-site dump areas consisting of
non-hazardous household type trash/debris, discarded tires, abandoned
vehicles/farm equipment, wood and metal demolition waste and asbestos piping.
Additionally, the environmental consultant identified a 100-gallon gasoline
container, several containers of herbicides/pesticides and other unlabeled
solids or liquids. As a result of their investigations, the environmental
consultant determined that no further investigations were warranted.
Status of Permits and Approvals
The status of key permits and approvals for the Bosque Facility is
shown in Table 27.
Table 27
Status of Key Permits and Approvals Required for Operation
Bosque Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
1. Air Permit to Construct and TNRCC Permit issued 12/20/99 Includes three gas turbines, two
Operate HRSGs and a cooling tower.
- ------------------------------------------------------------------------------------------------------------------------------------
2. Clean Air Act Title V TNRCC Issued 4/17/00 based on Incorporates acid rain requirements.
Federal Operating Permit abbreviated application.
TNRCC started full review in
8/00
- ------------------------------------------------------------------------------------------------------------------------------------
3. Texas Pollutant Discharge TNRCC TRNCC issued TPDES permit Permit for wastewater discharge from
Elimination System ("TPDES") No. 04167 on 9/21/00 simple cycle units. Application for
Wastewater Discharge amendment made September 28, 2000 to
include the conversion of Bosque Unit
3 to combined cycle.
- ------------------------------------------------------------------------------------------------------------------------------------
4. TPDES Permit for Stormwater USEPA Permit TXR05I598 issued
Runoff - Operation 5/28/00
====================================================================================================================================
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Regulatory Compliance
The Bosque Facility is currently subject to various state and
federal permits and regulations with respect to NO(X) and SO(2) emissions
including Best Available Control Technology requirements, and Title IV of the
Clean Air Act. Of these, Title IV SO(2) allowance requirements are the primary
requirements that will have an impact on future operations.
Title IV SO(2) Allowances
The Bosque Facility is subject to Phase II of the federal Acid Rain
Program of the Clean Air Act, and beginning in 2000, Mirant Texas must possess
SO(2) allowances equal to the actual emissions. Since the Bosque Facility is
operating on gas, the need for SO(2) allowances is minimized.
Air Emissions
The air emissions presented in Table 28 have been used in the
Projected Operating Results to evaluate the need for and associated costs of
SO(2) allowances.
Table 28
Emissions and Limits
Bosque Facility
(lb/MMBtu)
Facility Current Projected Emission Limit
SO(2) NO(X)(1) SO(2) NO(X)(1) SO(2) NO(X)(1)
----- -------- ----- -------- ----- --------
Bosque Units 1, 2 and 3 0.001 0.027 0.001 0.032 0.006 0.032
--------------------
(1) Emissions during ozone season (May through November).
Wastewater Compliance
The Bosque Facility requires water for drinking, sanitary purposes,
plant wash downs and make-up water to the inlet air evaporative cooling systems.
Water is provided to the plant from new water wells. A 300,000-gallon storage
tank is provided with appropriate retention for fire protection
The wastewater is routed through the oil/water separator system and
then to an on-site run-off detention pond. Sanitary wastes are disposed of in a
septic tank/leaching system.
Stormwater runoff from areas of the site south and east of the
developed area are intercepted by a berm and swales to divert it away from the
developed area and return it to the natural drainage pattern. The developed area
is sloped slightly for drainage. Swales and open ditches are provided to convey
the runoff to the detention pond.
Through September 2000 wastewater was disposed of off site by a
contractor. A TPDES permit was issued September 21, 2000 for simple cycle
operation. An amendment application was made September 28, 2000 for the
conversion to combined cycle operation.
Future Environmental Requirements
Certain future requirements relative to the revised PM(2.5)
standard, regulation of mercury emissions, regional haze, regional visibility,
water intake structure regulations, and potential ratcheting of the SO(2)
allowance program beyond the year 2009 may affect the Bosque Facility in the
future by imposing more stringent requirements than those in effect at the
present time. Since the Mirant Texas Generating Facility is fired primarily on
natural gas, the impact of these potential future requirements is not expected
to be significant.
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STATE LINE FACILITY
Description of the State Line Facility
Mechanical Equipment and Systems
Steam Cycle and Heat Rejection Systems and Components
The State Line Unit 3 commenced commercial operation in 1955. The
boiler is a CE, controlled circulation, balanced draft furnace, producing
1,350,000 lb/hr of steam at 2,000 psig and 1,025(degree)F. State Line Unit 3 is
a reheat furnace with a reheat steam temperature of 1,000(degree)F. In 1998,
State Line Unit 3 was modified to reduce opacity emissions by installing a new
baghouse. The State Line Unit 3 condenser system is a once through cooling
system utilizing water from Lake Michigan. Cooling water is collected and
returned to Lake Michigan through a common pump facility.
The State Line Unit 4 was placed in commercial operation in 1962.
The boiler is a B&W, natural circulation, balanced draft furnace with cyclone
burners. The boiler produces 2,200,000 lb/hr of steam at 2,000 psig and
1,025(degree)F superheat. The reheat steam temperature is 1,000(degree)F. The
State Line Unit 4 condenser cooling water system is a once-through-cooling
system utilizing common facilities with State Line Unit 3.
Turbine Generators
The State Line Unit 3 steam turbine generator is a GE, cross
compound, two flow, reheat, condensing type steam turbine. State Line Unit 3 is
nameplate rated at 207 MW. The State Line Unit 4 steam turbine generator is a
Westinghouse, cross compound, two flow, reheat, condensing type steam turbine.
State Line Unit 4 is nameplate rated at 325 MW.
Fuel Systems
Coal for the State Line Facility is received by rail and unloaded
via a common railcar unloader. From the unloader, the coal travels to a fixed
stacker that places it onto the fuel storage pile, which provides a minimum of
40 days of fuel reserve on-site.
The State Line Facility is supplied natural gas, which is used as a
start-up fuel from a 24-inch pipeline interconnected to the Northern Indiana
Public Service Company pipeline system, located approximately 1.5 miles from the
State Line Facility boundary.
Make-Up Water System
Make-up water for the State Line Facility is pumped from Lake
Michigan to a common pre-treatment system. Water pre-treatment includes gravel,
sand and pressure filters plus chemical introduction for removal of suspended
solids. Following pre-treatment, water is demineralized to remove all
impurities. Both units at the State Line Facility have a dedicated
demineralizer. Demineralized water is stored in four 60,000-gallon tanks for
State Line Unit 3 and a single 360,000-gallon tank for State Line Unit 4.
Plant wastewater is treated with polymer and alum prior to flowing
into one of two clarifiers. Clarified water is treated with sulfuric acid and/or
caustic soda prior to being pumped to the discharge flume. Sludge from the
clarifiers is placed on-site, dewatered, and set off-site for disposal.
Electrical and Control Systems
Plant Control Systems
The main plant control system for the State Line Facility is a
Westinghouse Type WDPF digital distributed control system ("DCS"), typical of
those commonly used in large power plants. Major systems have been converted to
the DCS, although some subsystems are still controlled and monitored by
hardwired control systems. The
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State Line Unit 4 turbine control room, State Line Unit 3 boiler control room
and State Line Unit 3 turbine control room are consolidated into the plant
electrical control room.
Electrical Distribution
The State Line Facility electrical arrangement includes two
generators which are unit-connected to a 345-138 kV substation. Plant auxiliary
power is derived from either unit auxiliary power transformers connected to the
generator leads or from station auxiliary power transformers (one per unit)
which are 138 kV-4 kV.
Emergency Power Systems
The on-line emergency power systems for the State Line Facility
consist of three 250-volt DC station battery systems for critical DC-powered
systems. Each bank of batteries is provided with one battery charger and a
fourth charger, which is arranged to be connected to any of the three DC
systems, providing backup in the event of a failure.
A 400-kW diesel generator set is provided on the 480-volt system to
supply critical AC loads in the event of a total AC failure, but is not large
enough to black start the plant. Because of the large number of transmission
lines, the bus arrangement and the number of auxiliary transformers, total
failure of the plant AC auxiliary system would not occur except in the case of a
major regional power system failure.
Environmental Controls and Equipment
Air Emissions
State Line Unit 4 is equipped with a 98 percent efficient ESP to
collect fly ash. There is also a fugitive dust control system that is typical
for solid-fuel projects similar to the State Line Facility.
As part of the State Line Unit 3 deferred maintenance program, the
ESP was replaced with a baghouse. The baghouse is currently providing
significantly improved performance in controlling opacity and reducing
opacity-related deratings. NO(X) emissions are mitigated by the use of the PRB
coal which burns at a lower temperature than Midwestern coals. Emissions of
SO(2) are controlled by limiting the amount of sulfur in the fuel.
Wastewater/Solid Waste Disposal
Plant wastewater is treated with polymer and alum prior to flowing
into one of two clarifiers. Clarified water is treated with sulfuric acid and/or
caustic soda prior to being pumped to the discharge flume. Sludge from the
clarifiers is placed on-site, dewatered, and sent off-site for disposal.
Ash from State Line Unit 3 is generated primarily in the form of fly
ash. State Line Unit 3 fly ash is collected in a baghouse, which was installed
as part of the Unit 3 deferred maintenance program. Ash from State Line Unit 4
is generated primarily in the form of boiler slag with some fly ash. State Line
Unit 4 boiler slag is collected in water filled slag tanks and then pulverized.
State Line Unit 4 fly ash is also collected in an ESP. Boiler slag and fly ash
are conveyed to an unloading plant where they are stored in separate silos for
loading into haulage vehicles. Fly ash and bottom ash are disposed of by the
third party contractor.
Electrical Interconnection
The interconnection facilities at the State Line Facility include
the plant switchyard, a sectionalized single-breaker single-bus configuration,
ten 138 kV transmission lines which are part of the existing ComEd 138 kV grid,
two 138 kV lines owned by Northern Indiana Public Service Company, two 345/138
kV autotransformers and two 345 kV transmission lines owned by ComEd.
S-72
Operation and Maintenance
Prior to the acquisition of the State Line Facility by State Line
Energy, ComEd undertook certain maintenance activities at the facility, a
portion of which was not completed prior to the acquisition. After acquiring the
State Line Facility, State Line Energy completed the remaining portions of the
deferred maintenance.
On February 16, 1998, State Line Unit 3 was taken off-line due to a
failure of the LP steam turbine. On July 28, 1998, during the outage to repair
this LP turbine, but while State Line Unit 4 was operating, the State Line
Facility suffered a fire in the tripper conveyor gallery. The fire propagated
through the conveyor gallery from the State Line Unit 4 fuel bunker to the State
Line Unit 1 fuel bunker causing damage to electrical wiring and equipment, fuel
handling facilities and the State Line Unit 4 auxiliary transformer. State Line
Energy utilized the down time resulting from the fire to replace the State Line
Unit 4 boiler floor, install the State Line Unit 3 baghouse and make
improvements to the fuel conveying system. State Line Energy also implemented
revised cleanliness procedures and made modifications to the conveying system to
reduce coal dust generation. State Line Unit 4 was brought back on line on
January 31, 1999. State Line Unit 3 was returned to service February 8, 1999.
On behalf of ComEd, engineering consultants performed a Project
Condition Assessment (the "Assessment"). These engineering consultants were the
original design engineers for the State Line Facility and have had certain
on-going involvement at the State Line Facility as consulting engineers for
ComEd. Based on the original Assessment and an update to the Assessment by BVCI,
State Line Energy revised its deferred maintenance program. The major focus of
this program is to perform maintenance on, repair and/or replace existing
equipment at the State Line Facility to ensure that the State Line Facility can
meet required heat rates, reliability and availability.
Operating History
The annual historical performance of the State Line Facility, as
reported by State Line Energy, is set forth in Table 29.
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Table 29
Operating History
State Line Facility
Net Capability Rating (MW)(1)
1996 490
1997 490
1998 490
1999 490
2000 515
Net Generation (GWh)
1996 1,851
1997 2,385
1998 314
1999 2,330
2000 2,498
Annual Net Heat Rate (Btu/kWh)(2)
1996 10,463
1997 10,444
1998 10,430
1999 9,901
2000 9,977
Net Capacity Factor (%)(2)
1996 45.3
1997 56.0
1998 10.7
1999 60.6
2000 70.3
Equivalent Availability Factor (%)(2)
1996 58.6
1997 67.3
1998 16.8
1999 89.1
2000 82.3
Coal Use (tons x 1000)
1996 1,008.4
1997 1,306.5
1998 187.5
1999 1,212.1
2000 1,663.0
--------------------
(1) Summer rating.
(2) Represents weighted average for annual net heat rate, net
capacity and equivalent availability factor.
(3) Does not include December 2000
Environmental Assessment
Environmental Site Assessments
Elevated levels of total petroleum hydrocarbons were encountered
during initial Phase II ESA investigations performed by an environmental
consultant for the State Line Facility. In a subsequent Phase II investigation
conducted by the environmental consultant in 1999, additional sampling was
conducted to address this concern. The environmental consultant collected soil
samples for analysis of polynuclear aromatic hydrocarbons ("PAHs"), a typical
constituent of fuels that have been spilled at the State Line Facility site.
Laboratory analytical results of the soil samples confirmed the presence of
PAHs, but at concentrations lower than Indiana Department of Environmental
Management ("IDEM") soil cleanup objectives. The environmental consultant also
collected several groundwater samples for analyses of PAHs and VOCs. Laboratory
analytical results indicate that PAHs and VOCs were not detected. The
environmental consultant concluded that soil and groundwater remediation were
not required at the project site.
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Our review of information regarding the fire at the plant on July
28, 1998 indicates that environmental damage and concerns were related to
dispersal of asbestos containing material debris; release of transformer oil in
the substation yard; and releases of oil into the floor, roof and yard basin
inlet sump. We have reviewed various data regarding the above environmental
concerns and/or have discussed these issues with knowledgeable project site
personnel. Our review indicates that extensive cleanup of asbestos containing
material debris was performed, with subsequent airborne sampling showing no
indications of concern. Separate data indicates that oil contamination occurring
as a result of the transformer fire was remediated. Soil sampling in the
transformer release area indicated that PCBs were encountered at non-regulated
levels. Further, information we have received indicates that releases of oil to
the floor, roof and yard basin inlet sump were recovered, and the sump was
subsequently cleaned up. According to State Line Energy personnel, no
significant environmental concerns remain with regard to the July 28, 1998
incident.
Status of Permits and Approvals
The status of key permits and approvals for the State Line Facility
is shown in Table 30.
Table 30
Status of Key Permits and Approvals Required for Operation
State Line Facility
===================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- -----------------------------------------------------------------------------------------------------------------------------------
Federal
- -----------------------------------------------------------------------------------------------------------------------------------
1. SPCC Plan USEPA/IDEM Prepared Required for prevention of oil spills
from equipment.
- -----------------------------------------------------------------------------------------------------------------------------------
State
- -----------------------------------------------------------------------------------------------------------------------------------
2. Phase II Acid Rain Title IV IDEM Office of Air Issued ID No AR SO(2) allowances specified in permit
Permit Management 089-5164-00210 on 12/31/97. were subsequently increased by USEPA
Effective 1/1/00 through - did not necessitate a revision to
12/31/04 the permit. Stack CEMs data used to
demonstrate compliance with allowance
allocations.
- -----------------------------------------------------------------------------------------------------------------------------------
3. Title V Operating Permit Hammond Department of Applied for 10/23/96; Issued Incorporates all emission sources at
Environmental Management ID #T089-7062-00210 plant. Operating under permit shield
("HDEM")/IDEM Office of Deemed complete since application deemed complete,
Air Management which is typical of other facilities.
Draft permits have been provided to
Mirant for review.
- -----------------------------------------------------------------------------------------------------------------------------------
4. Operation Permits HDEM Issued ID #01469 Unit 3 and ID These permits will be replaced by
Unit 3 Boiler #01470 Unit 4 on 2/29/00 Title V Operating Permit upon
Unit 4 Boiler finalization. Continued renewal will
be made by HDEM until Title V Permit
is final issued.
- -----------------------------------------------------------------------------------------------------------------------------------
5. NPDES Permit IDEM Office of Water Issued 8/1/96 Expires For discharges to Lake Michigan.
Management 5/31/01. Application for
renewal was submitted on
11/29/00.
===================================================================================================================================
Regulatory Compliance
The State Line Facility is currently subject to various state and
federal permits and regulations with respect to NO(X) and SO(2) emissions
including Title I of the Clean Air Act and subsequent regulations including the
USEPA NO(X) SIP Call and Title IV of the Clean Air Act requirements.
Title I NO(X) RACT Regulations
The State Line Facility is located in an ozone non-attainment area;
therefore, NO(X) RACT would generally apply. However, the Chicago area received
a waiver to the RACT requirements from the USEPA. This waiver was granted
because it was demonstrated that NO(X) reductions in the Chicago area do not
necessarily reduce
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ozone. This waiver is considered to be potentially contingent or temporary and
subject to subsequent modeling or monitoring data, which may show attainment
benefits from NO(X) reductions.
Title IV NO(X) Regulations
State Line Units 3 and 4 are subject to Title IV requirements of the
Clean Air Act to meet the presumptive NO(X) emission limitations starting in the
year 2000 in accordance with the acid rain regulations. The final regulations
specified a NO(X) limitation of 0.86 lb/MMBtu of heat input on an average annual
basis for cyclone boilers (State Line Unit 4) and 0.40 lb/MMBtu on an average
annual basis for tangential fired boilers (State Line Unit 3). However, IDEM
approved a NO(X) early election compliance plan for the State Line Unit 3
tangential-fired boiler. Under this compliance plan, the State Line Unit 3
average annual NO(X) emission rate cannot exceed 0.45 lb/MMBtu effective for
calendar year 1997 through 2007. State Line Energy applied for a NO(X)-averaging
plan for the year 2000. Under this plan, State Line Unit 3 was required to meet
its Phase IV limit of 0.40 lb/MMBtu, which it will have to meet in the future.
The State Line Facility was in compliance in 2000 with both the NO(X)-averaging
plan and unit-specific requirements of the Title IV program.
Title I NO(X) Limitations- NO(X) Allowances
The USEPA NO(X) SIP Call requirements target NO(X) emissions during
the ozone season (May through September). The Clean Air Act called for Indiana
to develop a SIP by October 28, 2000. The IDEM did not submit a SIP acceptable
to the USEPA and the deadline was missed. IDEM is proceeding with the
development of an acceptable NO(X) cap and trade program rule which is expected
to be approved by July 2001. The State Line Facility is subject to the NO(X) SIP
Call rule being developed by the IDEM. In response to the SIP Call, IDEM has
proposed regulations to control NO(X) emissions during the normal Ozone Season
of each year beginning May 31, 2004 and beyond. The proposed draft rule provides
an emission trading program that will allocate allowances based on an emission
rate of 0.15 lb/MMBtu and the average of the two highest years of actual
reported historical heat input rates for the years 1995 through 2000. Currently,
reported heat input data available to IDEM is through the end of 1999 only.
Additionally, the proposed rule provides an initial five percent set-aside for
new source allocations which reduces to two percent for subsequent allocations.
Allowances are calculated for the period of 2004 through 2006 and will be issued
on a three-year basis with a reallocation provided every three years considering
new unit generation installed and permitted, and the reduced New Source
Set-Aside. The new unit set-aside program will provide allocations for new
generators for their first three years of operation after which they become part
of the compliance pool. Upon issuance of allocations for the period of 2007
through 2009, the generating units installed during the prior three-year period
will be included in the allowance compliance pool. USEPA has allowed a 17
percent growth in the Indiana Annual NO(X) budget. Depending on the number of
new unit additions, in the three-year period from 2004 through 2006, i.e.,
greater or less than 17 percent NO(X) emissions increases, the reallocation of
allowances can result in an increase or decrease of allocable allowances for
existing units, which includes the currently operating State Line Facility. The
Draft IDEM Rule indicates that the initial three-year allocation in advance of
the 2004, 2005, and 2006 ozone seasons will be submitted to USEPA by September
30, 2001. Therefore, the currently published allowance allocations for the State
Line Facility are forecasts only.
Should additional NO(X) reductions be required to meet the NO(X) SIP
Call, under the State Line PPA, State Line Energy will make the necessary
capital improvements and will be entitled to a monthly NO(X) Compliance Cost
payment, which is intended to allow State Line Energy to recover the annualized
capital costs and incremental O&M costs of the compliance project. Such
reimbursement provisions continue in effect for the term of the State Line PPA,
and the annualized capital costs are based on an amortization of the capital
costs from the in-service date of the capital addition until December 30, 2022.
After the expiration of the State Line PPA, State Line Energy will incur NO(X)
operating and maintenance compliance costs as annual expenses to the State Line
Facility. State Line Energy has assumed that it will install an SCR on State
Line Unit 4 by the end of the State Line PPA. For the purposes of the Projected
Operating Results, we have assumed that an SCR will be in service by January 1,
2013. We have included State Line Energy's estimates of the capital and
operating costs of the SCR, as well as the impact on the NO(X) emissions rate.
The draft allocation of allowances to the State Line Facility are
presented in Table 31.
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Table 31
NO(X) Allowances (1)
State Line Facility
(Tons/Year)
Facility
--------
Unit 3 359
Unit 4 470
------------
(1) Allowances are for period of 2004-2006. These may
be adjusted for the period after 2006 as per the
final state SIP.
For NO(X) allowances, the current spot market is approximately
$1,000 per ton with prices fluctuating from approximately $500 to $7,500 per ton
during 1999 and 2000. The cost of NO(X) allowances may be impacted in 2004 by
the ratcheting of allowances associated with the USEPA's ozone reduction program
and the associated installations of SCR by many plants. During the term of the
State Line PPA, ComEd will supply State Line Energy with the required SO(2)
allowances. For the purpose of the Projected Operating Results, we have assumed
that, beginning in 2013, State Line Energy will purchase the required NO(X)
allowances at a price of $1,700 in 2005 dollars increasing at the rate of
inflation.
Title IV SO(2) Limitations - SO(2) Allowances
The State Line Facility is subject to Phase II of the Federal Acid
Rain Program of the Clean Air Act, and State Line Energy must possess SO(2)
allowances equal to the actual emissions. The State Line Facility was allocated
a set of SO(2) allowances for the years 2000 to 2009 and a second set for the
years after 2010, although these allowances were retained by ComEd. The SO(2)
allowances assumed through 2020 are presented in Table 32.
Table 32
Phase II SO(2) Allowances
State Line Facility
(Tons/Year)
Facility 2000-2009 2010-2020(1)
-------- --------- ---------
Unit 3 4,725 3,452
Unit 4 6,922 6,033
--------------
(1) Represents assumed allowances through the term of the
Projected Operating Results. Allowances may be adjusted
with changes in regulations.
During the term of the State Line PPA, ComEd will supply State Line
Energy with the required SO(2) allowances. For the purpose of the Projected
Operating Results, we have assumed that, beginning in 2013, State Line Energy
will purchase the required SO(2) allowances at a spot market price of $150 per
ton increasing annually at the rate of inflation. Future cost of allowances will
be market dependent and could be higher or lower than the current values for
such allowances.
Air Emissions
The air emissions presented in Table 33 have been used in the
Projected Operating Results to evaluate the need and associated costs of the
NO(X) and SO(2) allowances.
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Table 33
Emissions and Limits
State Line Facility
(lb/MMBtu)
Facility Current Projected Emission Limit
SO(2) NO(X)(1) SO(2) NO(X)(1) SO(2) NO(X)(1)
----- -------- ----- -------- ----- --------
Unit 3 0.61 0.21 0.6 0.21 1.2 0.45
Unit 4 0.52 0.84 0.6 0.17(2) 1.2 0.86
--------------------
(1) Emissions during ozone season.
(2) Based on SCR retrofit in 2013.
Wastewater Compliance
State Line Units 3 and 4 are permitted to withdraw an average of 554
mgd of water from Lake Michigan for once-through condenser cooling. Process
wastewater originates from boiler blowdown, neutralized demineralizer
regenerant, coal pile runoff, bottom ash sluice, metal cleaning wastes, and
plant floor, roof drains and yard runoff effluent. These wastewater streams are
directed to a variety of settling basins and separators before discharge to the
cooling water canal. The NPDES permit for the State Line Facility includes
limitations on temperature and total residual oxidants for cooling water and
limitations on total suspended solids, oil and grease and pH for discharges. The
wastewater discharge compliance history of the State Line Facility does not
indicate any future non-compliance trends.
Future Environmental Requirements
Certain future requirements relative to the revised PM(2.5)
standard, regulation of mercury emissions, regional haze, regional visibility,
water intake structure regulations, and potential ratcheting of the SO(2)
allowance program beyond the year 2009 may affect the State Line Facility in the
future by imposing more stringent requirements than those in effect at the
present time.
MIRANT WISCONSIN FACILITY
Description of the Neenah Facility
Mechanical Equipment and Systems
Turbine Generator Systems and Components
Neenah Unit 1 was placed in service on May 1, 2000. Neenah Unit 2
was placed in service on May 8, 2000. Neenah Units 1 and 2 are identical base
mounted GE Frame 7FA (PG 7241 FA) combustion turbine generators operating in a
simple-cycle mode. The units are equipped with inlet filtration, evaporative
cooling, GE's DLN 2.6 multi-nozzle combustion system, water injection, and
hydrogen cooled generators rated at 171,700 kW. Lubrication is provided by
dedicated oil reservoir/cooling systems for each Unit. Dedicated on-line or
off-line water washing systems are also included.
Fuel Systems
A new natural gas pipeline was constructed by ANR Pipeline Company,
connecting the Neenah Facility with the Green Bay Line pipeline located east of
the site. The pipeline is owned by ANR, which receives an annual capacity
payment for its use. Metering, regulation, filtering and heating of the gas is
common for both Units 1 and 2. The Neenah Facility can also use No 2 fuel oil
which is stored on-site in a 650,000-gallon tank. Using No. 2 fuel oil, the
plant can operate at full load for nearly 24 hours. Oil is delivered by truck to
the on-site unloading and storage facilities.
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Water/Wastewater System
Service water for the Neenah Facility is obtained from two wells
located on-site. Well water is stored in a 300,000-gallon service water tank
with appropriate retention for fire protection. The compressor wash systems and
sanitary water is supplied by the service water system. Demineralized water is
provided by a leased, portable, trailer-mounted demineralizer brought to the
Neenah Facility site when needed. Demineralizer regeneration is conducted
off-site so there is no backwash or wastewater from the system. Demineralized
water is stored on-site in a 750,000 tank and is used in the nozzle injectors
when burning fuel oil, and the evaporative cooler. Wastewater resulting from
equipment washdowns is currently routed through an API separator then discharged
with sanitary wastewater to the municipal sanitary sewer system.
Fire Protection Systems
The firewater supply system water for the Neenah Facility is
supplied from the service water tank. The system consists of an electric
motor-driven jockey pump, and electric motor-driven main pump and a diesel
engine-driven emergency pump which takes suction from the service water tank and
supplies hose stations in the plant and hydrants in the yard. A liquid
carbon-dioxide deluge system is used to protect the CT enclosures generators,
auxiliary enclosures and the bearing tunnel. Portable extinguishers are located
throughout the facility.
Electrical and Control Systems
Plant Control Systems
Neenah Units 1 and 2 are controlled from an enclosed control room,
located within the Administration/Maintenance portion of the Neenah Facility. GE
Speedtronic Mark V DCS control systems control and monitor the turbine
generators. A Maximo system is currently being adapted for use in work order,
inventory and preventative maintenance management.
Electrical Distribution
The Neenah Facility electrical arrangement includes two 18 kV
generators which are unit-connected to a conventional 138 kV single-bus,
single-breaker arrangement with two 138 kV line positions, two step-up
transformer positions and one auxiliary transformer. Plant auxiliary power is
derived from the 138 kV to 4.16 kV auxiliary transformer and conventional
distribution system. A battery backup system provides emergency power loss
control power and safe system shutdown capability. The switchyard and
transmission line was constructed and owned by Wisconsin Electric Power Company.
Emergency Power Systems
No on-site emergency generation or black-start capability is
provided at the Neenah Facility.
Off-Site Requirements
Electrical Interconnection
The electrical output of Neenah Units 1 and 2 is delivered to
separate main power transformer for connection with the 138 kV transmission
line.
Operating History
No additional historical performance data has been provided for the
Neenah Facility beyond that included in the Report.
The Neenah Units 1 and 2 simple cycle combustion turbine generators
were newly constructed, achieving commercial operation in May of 2000. During
the following five months the facilities were operated in peaking mode, on an
approximately daily schedule and often at less than full load. Between June and
November of 2000, there have been no major maintenance activities.
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No major Neenah Unit 1 or 2 modifications or major capital
improvements are planned or scheduled at this time. Mirant Neenah has indicated
the potential to convert one or both Units to combined cycle operation.
Environmental Assessment
Environmental Site Assessment
An environmental consultant for the Neenah Facility completed a
hydrogeologic investigation of the Neenah Facility in February 1999 during which
five on-site groundwater monitoring wells were installed. Several VOCs were
detected in the shallow wells in a December 1998 sampling event. VOCs were not
detected in the deeper wells. Two VOCs, (tetrachloroethene and 1,1,1
trichloroethane) were detected above certain State of Wisconsin threshold
levels. Subsequent groundwater sampling conducted in March 1999 encountered only
one VOC (1,1,1, trichloroethane), but at a concentration less than State of
Wisconsin threshold levels. The environmental consultant concluded that the
on-site groundwater contamination was originating from an off-site source of
solvent contamination located west or northwest of the site. Mirant Neenah and
the environmental consultant have discussed this issue with both the Wisconsin
DNR Bureau for Remediation & Development and the Private Water Systems Section
("PWSS") of the Bureau of Drinking Water and Groundwater. Further, Mirant Neenah
provided documentation that both bureaus have reviewed the data regarding the
VOCs encountered within groundwater at the site, and that PWSS has considered
the data relative to their approval of the plant's high capacity well permit.
According to Mirant Neenah, PWSS issued clarification to Mirant Neenah on July
20, 1999 indicating that the permitting agency was taking no further action
regarding this issue.
Status of Permits and Approvals
The status of key permits and approvals for the Neenah Facility are
shown in Table 34.
Table 34
Status of Key Permits and Approvals Required for Operation
Neenah Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
1. High Capacity Well Department of Natural Issued 6/9/99 Maximum 433 gallons per
Resources minute ("gpm") for
non-contact cooling water
and potable water
- ------------------------------------------------------------------------------------------------------------------------------------
2. Air Permit to Construct (Prevention of Department of Natural Issued 2/25/99 Permit to construct 360 MW
Significant Deterioration) Resources Expires 4/25/01 peaking plant. Includes
emission limits
- ------------------------------------------------------------------------------------------------------------------------------------
3. Title V Air Permit to Operate Department of Natural To be obtained Permit to operate facility
Resources
- ------------------------------------------------------------------------------------------------------------------------------------
4. Sanitary Permit Department of Natural Issued 6/4/99 and 6/14/99 Wastewater discharge to the
Resources sewer
====================================================================================================================================
Regulatory Compliance
The Neenah Facility is currently subject to various state and
federal permits and regulations with respect to NO(X) and SO(2) emissions
including Best Available Control Technology requirements, Title IV of the Clean
Air Act requirements, and requirements that the State of Wisconsin may adopt to
meet National Ambient Air Quality Standards for Ozone under the Clean Air Act.
Of these, Title IV SO(2) allowance requirements are the primary requirements
that will have an impact on future operations.
Title IV SO(2) Allowances
The Neenah Facility is subject to Phase II of the federal Acid Rain
Program of the Clean Air Act and, beginning in 2000, Mirant Neenah must possess
SO(2) allowances equal to the actual emissions. Since the Neenah Facility is
operating on gas, the need for SO(2) allowances is minimized.
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Mirant Neenah will be required to obtain SO(2) allowances for actual
SO(2) emissions. Since the Neenah Facility is a new source, no allowance
allocations were made to it. Future cost of allowances will be market dependent
and could be higher or lower than the current values for such allowances. For
the purpose of the Projected Operating Results, we have assumed the present spot
market price of SO(2) allowances of approximately $150 per ton and have assumed
that it would increase annually at the rate of inflation.
Air Emissions
The air emissions presented in Table 35 have been used in the
Projected Operating Results to evaluate the need and associated costs of the
NO(X) and SO(2) allowances.
Table 35
Emissions and Limits(1)
Neenah Facility
(lb/MMBtu)
Facility Current Projected Emission Limit
SO(2) NO(X)(2) SO(2) NO(X)(2) SO(2) NO(X)(2)
----- -------- ----- -------- ----- --------
Unit 1 (gas) 0.001 0.040 0.001 0.040 0.003 0.054
Unit 1 (No. 2 oil) 0.027 0.128 0.027 0.128 0.059 0.150
Unit 2 (gas) 0.001 0.040 0.001 0.040 0.003 0.054
Unit 2 (No. 2 oil) 0.027 0.128 0.027 0.128 0.059 0.150
--------------------
(1) Based on stack test emission results.
(2) During ozone season, May through September.
Wastewater Compliance
The maximum water usage for the Neenah Facility while firing natural
gas is 266 gpm for both units. While firing No. 2 fuel oil with water injection
for NO(X) control, water consumption increases to 550 gpm. A well permit was
issued on June 9, 1999, for withdrawal of up to 433 gpm on a monthly average.
Raw water is stored in a 50,000-gallon tank, which feeds a
truck-mounted demineralizer. Demineralized water is stored in a 762,500-gallon
tank.
Demineralized water is provided by a rented or leased portable
trailer-mounted demineralizer system which is transported to the Neenah Facility
site when needed. Demineralizer regeneration is performed off-site and no
backwash or regeneration wastes are produced. Demineralized water is stored in a
762,500-gallon tank.
Wastewater discharges are minimal and include evaporative cooler
blowdown, turbine wash water, and sanitary sewer discharges. According to Mirant
Neenah, the Neenah Facility has zero wastewater discharges from any process
except to contained vessels at the site and an NPDES permit is not required.
These effluents will be discharged into the municipal sanitary sewer.
Future Environmental Requirements
Certain future requirements relative to the revised PM(2.5)
standard, regulation of mercury emissions, regional haze, regional visibility,
water intake structure regulations, and potential ratcheting of the SO(2)
allowance program beyond the year 2009 may affect the Neenah Facility in the
future by imposing more stringent requirements than those in effect at the
present time. Since the Neenah Facility is fired primarily on natural gas, the
impact of these potential future requirements is not expected to be significant.
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