ITEM-BY-ITEM
INSTRUCTIONS
|
SCHEDULE 1. IDENTIFICATION
Survey
Contact: Provide
the name, title, address, telephone number, cell phone number,
and email address for the person that will be the primary contact
for this form.
Supervisor
of Survey Contact: Provide
the name, title, address, telephone number, cell phone number and
email address of the primary contact’s supervisor.
Entity
Name and Address: Provide
the name and address of the entity that is reporting for the
plants reported on this form.
Entity
Relationship: Indicate
the relationship between the reporting entity and the power
plants reported on this form. Select all that apply: owner,
operator, asset manager or other. If you select “Other,”
provide details in SCHEDULE 7.
Entity
Type:
Select the category that best describes the entity that owns
and/or operates the plants reported on this form from the list
below:
-
SCHEDULE
2. POWER PLANT DATA
Complete
one section for each power plant. A plant can consist of a single
generator or of multiple generators at a single location. For the
purpose of wind plants and solar plants, a plant can be defined
based on phased expansions or other grouping methodologies used by
the reporting entity. Include all plants that are (1) in
commercial operation, (2) capable of commercial operation but
currently inactive or on standby, or (3) expected to be in
commercial operation within 10 years in the case of coal and
nuclear units, or within 5 years for all other units.
For
line 1,
What are the plant name and EIA Plant Code for this plant?
Enter the name of the power plant. When assigning a name to a
plant, use its full name (i.e. do not shorten Alpha Generating
Station to Alpha) and include as much detail as possible (e.g.
Beta Paper Mill, Gamma Landfill Gas Plant, Delta Dam). The plant
name may include additional details like owner name and business
structure but “Corporation” should be shorted to
“Corp” and “Incorporated” should be
shortened to “Inc.” Enter “NA 1,” “NA
2,” etc., for unnamed planned facilities.
The
EIA Plant Code is generated and provided by EIA upon the initial
submission of the Form EIA-860.
For
line 2, What
is this plant’s physical address? Enter
the physical address where the plant is located or will be
located. Do not enter the plant’s mailing address. Do not
enter the address of the plant’s operator, holding company
or other corporate entity. If the plant does not have a single,
permanent address, indicate it with a note in SCHEDULE 7.
For
line 3, What
is this plant’s latitude and longitude?
Enter the latitude and longitude of the plant in decimal format.
The coordinates should relate to a central point within the
plant’s property such as a generator. Do not enter the
coordinates of the plant’s operator, holding company or
other corporate entity.
For
line 4, Which
North American Electric Reliability Corporation region does this
plant operate in? Select
the North American Electric Reliability Corporation (NERC) region
in which the plant operates.
For
line 5, What
is this plant’s balancing authority?
Select the plant’s Balancing Authority. A balancing
authority manages supply, demand, and interchanges within an
electrically defined area. It may or may not be the same as the
Owner of Transmission/Distribution Facilities, requested below.
If you believe the plant is connected to more than one balancing
authority, explain in SCHEDULE 7.
For
line 6, What
is the name of the principle water source used by this plant for
cooling or hydroelectric generation?
Enter the name of the principal source from which cooling water
or water for generating power for hydroelectric plants is
obtained. If water is from an underground aquifer, provide name
of aquifer, if known. If name of aquifer is not known, enter
“Wells.” Enter “Municipality” if the
water is from a municipality. Enter “UNK” for
planned facilities for which the water source is not known.
Enter “NA” for plants that do not use a water source
for cooling or hydroelectric generation.
The
response for line 7, What
is this plant’s steam plant type?
is entered
by EIA staff for all plants.
If you are filling out this form on EIA’s Internet Data
Collection System and believe that the designation is not
accurate, please contact the survey manager.
For
line 8a, Which
North American Industry Classification System (NAICS) Code that
best describes this plant’s primary purpose?
Enter the North American Industry Classification System (NAICS)
code found in Table 29 at the end of these instructions that best
describes the primary purpose of the plant. Electric utility
plants and independent power producers whose primary purpose is
generating electricity for sale will generally use code 22. For
generators whose primary business is an industrial or commercial
process (e.g., paper mills, refineries, chemical plants, etc.)
and for which generating electricity is a secondary purpose, use
a code other than 22. For plants with multiple purposes, select
the NAICS code corresponding to the line of business that
generates - or where the chartered intent of the line of business
is intended to generate - the highest value for the company.
For
line 8b
Did this plant have a net metering agreement in effect during the
reporting year? If
any primary purpose other than 22 is selected on line 8a above,
indicate whether the facility is net metered.
Net
metering
is defined as a tariff arrangement in which a qualifying customer,
typically generating electricity from a renewable resource, sells
excess power it generates over its load requirement back to a
utility, typically at a rate equivalent to the retail price of
electricity.
For
lines 9a and 9b, Does
this plant have Federal Energy Regulatory Commission Qualifying
Facility (QF) Cogenerator status?
Check “Yes” or “No”; if “Yes”
provide all QF docket numbers granted to the facility. Please do
not include the prefix (e.g. QF, EWG, etc.) when entering the
docket numbers. Only include the numerical portion of the docket
number, including dashes.
For
lines 10a and 10b, Does
this plant have Federal Energy Regulatory Commission Qualifying
Facility (QF) Small Power Producer status?
Check “Yes” or “No”; if “Yes”
provide all QF docket numbers granted to the facility. Please do
not include the prefix (e.g. QF, EWG, etc.) when entering the
docket numbers. Only include the numerical portion of the docket
number, including dashes.
For
lines 11a and 11b, Does
this plant have Federal Energy Regulatory Commission Qualifying
Facility (QF) Exempt Wholesale Generator status?
Check “Yes” or “No”; if “Yes,”
provide all QF docket numbers granted to the facility. Please do
not include the prefix (e.g. QF, EWG, etc.) when entering the
docket numbers. Only include the numerical portion of the docket
number, including dashes.
For
line 12a,
Is there an ash impoundment (e.g. pond, reservoir) at the plant?
Indicate whether there is an impoundment (e.g. pond, reservoir)
at the plant where fly ash, bottom ash or other ash byproducts
can be stored.
If
you entered “yes" to Question 12a, for Question 12b, Is
this ash impoundment lined?
Indicate whether the impoundment is lined and, in Question 12c,
What
was this ash impoundment’s status
as of December 31 of the reporting year?
select
the impoundment’s status from the list of codes in Table 1
below.
Table
1. Ash Impoundment Status Codes and Descriptions
-
Ash
Impoundment Status Code
|
Ash
Impoundment Status Code Description
|
OP
|
Operating
- in service (commercial operation)
|
SB
|
Standby/Backup
- available for service but not normally used for this
reporting period
|
OA
|
Out
of service – was not used for some or all of the
reporting period but is expected to be returned to service in
the next calendar year
|
OS
|
Out
of service – was not used for some or all of the
reporting period and is NOT expected to be returned to service
in the next calendar year
|
For
line 13, Who
is the current owner of the transmission lines and/ or
distribution facilities that this plant is interconnected to?
Enter
the name of the current owner of the transmission or distribution
facilities to which the plant is interconnected and which
receives or may receive the plant’s output. If the plant is
interconnected
to multiple owners, enter the name of the principal owner and
list the other owners and their roles in SCHEDULE 7.
For
line 14, What
is this plant’s grid voltage at the point(s) of
interconnection to transmission or distribution facilities?
Enter up to three grid voltages, in kilovolts, at the points of
interconnection to the transmission/distribution
facilities. If the plant is interconnected to more than three
transmission/distribution facilities, enter the three highest
grid voltages.
Line
15 is reserved for future use.
For
line 16, What
is the name of the natural gas pipeline(s) that is connected to
your facility?
Enter the name(s) of the natural gas pipeline(s) that provide
natural gas to the plant.
SCHEDULE
3. GENERATOR INFORMATION
Complete
SCHEDULE 3 for each generator at this plant that is:
In
commercial operation;
Capable
of commercial operation but currently inactive or on standby;
Retired;
Expected
to be in commercial operation within 10 years in the case of coal
and nuclear generators; or
Expected
to be in commercial operation within 5 years for all generators
other than coal and nuclear generators.
Do
not
report auxiliary generators that are typically used solely for
blackstart or maintenance purposes.
For
generators associated with wind and solar plants, a generator can
be any grouping of photovoltaic panels or wind turbines with
similar characteristics (e.g. manufacturer, technical parameters,
location, commercial operating date, etc.).
Treat
energy storage facilities as generators and provide all necessary
data requested below.
Include
generators with maximum capability of less than 1 MW if located
at a plant with a total nameplate capacity of 1 MW or greater.
To
report a new generator, use a separate and blank section of
SCHEDULE 3.
To
report a new generator that has replaced one that is no longer in
service, update the status of the generator that has been
replaced along with other related information (e.g., retirement
date), then use a separate and blank section of SCHEDULE 3 to
report all of the applicable data about the new generator.
Each
generator must be uniquely identified within a plant. The EIA
cannot use the same generator ID for the new generator that was
used for the generator that was replaced.
SCHEDULE
3. PART A. GENERATOR INFORMATION – GENERATORS
For
line 1, What
is the generator ID for this generator?
Enter the unique generator identification commonly used by plant
management. Generator identification should be the same
identification as reported on other EIA forms to be uniquely
defined within a plant. This
identification code is restricted to five characters and cannot
be changed once provided to EIA.
For
line
2,
What is this generator’s prime mover?
Enter one of the prime mover codes in Table 2. For combined cycle
units, a prime mover code must be entered for each generator.
Table
2. Prime Mover Codes and Descriptions
-
Prime
Mover Code
|
Prime
Mover Description
|
BA
|
Energy
Storage, Battery
|
CE
|
Energy
Storage, Compressed Air
|
CP
|
Energy
Storage, Concentrated Solar Power
|
FW
|
Energy
Storage, Flywheel
|
PS
|
Energy
Storage, Reversible Hydraulic Turbine (Pumped Storage)
|
ES
|
Energy
Storage, Other (specify in SCHEDULE 7)
|
ST
|
Steam
Turbine, including nuclear, geothermal and solar steam (does
not include combined cycle)
|
GT
|
Combustion
(Gas) Turbine (does not include the combustion turbine part of
a combined cycle; see code CT, below)
|
IC
|
Internal
Combustion Engine (diesel, piston, reciprocating)
|
CA
|
Combined
Cycle Steam Part
|
CT
|
Combined
Cycle Combustion Turbine Part
|
CS
|
Combined
Cycle Single Shaft (combustion turbine and steam turbine share
a single generator)
|
CC
|
Combined
Cycle Total Unit (use only for plants/generators that are in
planning stage, for which specific generator details cannot be
provided)
|
HA
|
Hydrokinetic,
Axial Flow Turbine
|
HB
|
Hydrokinetic,
Wave Buoy
|
HK
|
Hydrokinetic,
Other (specify in SCHEDULE 7)
|
HY
|
Hydroelectric
Turbine (includes turbines associated with delivery of water
by pipeline)
|
BT
|
Turbines
Used in a Binary Cycle (including those used for geothermal
applications)
|
PV
|
Photovoltaic
|
WT
|
Wind
Turbine, Onshore
|
WS
|
Wind
Turbine, Offshore
|
FC
|
Fuel
Cell
|
OT
|
Other
(specify in SCHEDULE 7)
|
Combined
heat and power systems often generate steam with multiple sources
and generate electric power with multiple prime movers. For
reporting purposes, a simple cycle prime mover should be
distinguished from a combined cycle prime mover by determining
whether the power generation part of the steam system can operate
independently of the rest of the steam system. If these system
components cannot be operated independently, then the prime movers
should be reported as combined cycle types.
For
line 3, What
is this generator’s unit or multi-generator code? If
this generator operates as a single unit with another generator
(including as a combined cycle unit), enter a unique 4-character
code for the unit. All generators that operate as a unit must
have the same unit code. Leave blank if
this generator does not operate as a single unit with another
generator.
For
line
4, What
is this generator’s ownership code?
Identify the ownership for each generator using the following
codes:
Table
3: Generator Ownership Codes and Descriptions
-
Ownership
Code
|
Ownership
Code Description
|
S
|
Single
ownership by respondent
|
J
|
Jointly
owned with another entity
|
W
|
Wholly
owned by an entity other than respondent
|
For
line 5, Does
this generator have duct burners for the supplementary firing of
the turbine exhaust gas? Check
“Yes” if 1) the generator has a combined cycle prime
mover code of “Combined Cycle Steam Part (CA)”
“Combined
Cycle Single Shaft (CS),”
or “Combined
Cycle Total Unit (CC,)”
and 2) if the unit
has duct-burners for supplementary firing of the turbine exhaust
gas. Otherwise, check “No.”
For
line 6, Can
this generator operate while bypassing the heat recovery steam
generator? Check
“Yes” if 1) the generator has a combined cycle prime
mover code of “Combined
Cycle Combustion Turbine Part
(CT)” or “Combined
Cycle Total Unit (CC)”
and 2) the combustion turbine can operate while bypassing the
heat recovery steam generator. Otherwise, check “No.”
For
line 7a,
For this generator what is the RTO/ISO LMP price node
designation?
If this generator operates in an electric system operated by a
Regional Transmission Organization (RTO) or Independent System
Operator (ISO) and the RTO/ISO calculates a nodal Locational
Marginal Price (LMP) at the generator location, then provide the
nodal designation used to identify the price node in RTO/ISO LMP
price reports.
For
line 7b,
For this generator what is the RTO/ISO location designation for
reporting wholesale sales data to FERC? If
this generator operates in an electric system operated by a
Regional Transmission Organization (RTO) or Independent System
Operator (ISO) and the generator’s wholesale sales
transaction data is reported to FERC for the Electric Quarterly
Report, then provide the designation used to report the specific
location of the wholesale sales transactions to FERC. In many
cases the RTO/ISO location designation may be the same as the
RTO/ISO LMP price node designation submitted in line 7a. In these
cases enter the same response in both line 7a and line 7b.
SCHEDULE
3, PART B. GENERATOR INFORMATION – EXISTING GENERATORS
Complete
one SCHEDULE 3, Part B for each generator at this plant that is in
commercial operation.
For
line 1a, What
is the nameplate capacity for this generator?
Report the highest value on the generator nameplate in MW rounded
to the nearest tenth, as measured in alternating current (AC). If
the nameplate capacity is expressed in kilovolt amperes (kVA),
first convert the nameplate capacity to kilowatts by multiplying
the corresponding power factor by the kVA and then convert to
megawatts by dividing by 1,000. Round this value to the nearest
tenth. If generator nameplate capacity is less than net summer
capacity, provide the reason(s) in SCHEDULE 7.
For
line 1b, What
is the nameplate power factor for this generator?
Enter the power factor stamped on the generator nameplate. This
should be the same power factor used to convert the generator’s
kilovolt-ampere rating (kVA) to megawatts (MW) as directed for
line 1a above. Solar photovoltaic systems, wind turbines,
batteries, fuel cells, and flywheels may skip this question.
For
line 2, What
is this generator’s net capacity?
Enter the generator's net summer and net winter capacities for
the primary energy source. Report in MW rounded to the nearest
tenth, as measured in alternating current (AC). For generators
that are out of service for an extended period or on standby,
report the estimated capacities based on historical performance.
For generators that are tested as a unit, report a single
aggregate net summer capacity and a single aggregate net winter
capacity. For hydroelectric generators, report the instantaneous
capacity at maximum water flow. For solar photovoltaic generators
report the peak net capacity during the day for the generator
assuming clear sky conditions on June 21 for summer capacity and
on December 21 for winter capacity; assume average seasonal
temperatures and average wind speeds for June 21 and December 21,
respectively. If net capacity is only available as direct
current (DC), estimate the effective AC output and explain in
SCHEDULE 7.
For
line 3, What
minimum load can this generator operate at continuously?
Enter the minimum load (MW) at which the unit can operate
continuously. Solar-powered
generators are not required to answer this question.
For generators operating as a single unit that entered a Unit
Code (Multi-Generator Code) on SCHEDULE 3, Part A, Line 3,
provide the load when all generators are operating at their
minimum load.
For
line 4a, Was
an uprate or derate project completed on this generator during
the reporting year? Check
“Yes”
if an uprate or derate project was implemented during the
reporting year. Check “No” if it was not. If both an
uprate and derate were implemented during the reporting year,
check “Yes” and explain in SCHEDULE 7.
For
line 4b, When
was this uprate or derate project completed? Enter
the date when the uprate or derate project identified in line 4a
was completed.
For
line 5a, What
was the status of this generator as of December 31 of the
reporting year?
Enter one of the following status codes:
Table
4. Generator Status Codes and Descriptions
-
Ownership
Code
|
Ownership
Code Description
|
OP
|
Operating
- in service (commercial operation) and producing some
electricity. Includes peaking units that are run on an as
needed (intermittent or seasonal) basis.
|
SB
|
Standby/Backup
- available for service but not normally used (has little or
no generation during the year) for this reporting period.
|
OS
|
Out
of service – was not used for some or all of the
reporting period and is NOT expected to be returned to service
in the next calendar year.
|
OA
|
Out
of service – was not used for some or all of the
reporting period but is expected to be returned to service in
the next calendar year.
|
RE
|
Retired
- no longer in service and not expected to be returned to
service.
|
For
line 5b,
If Is this generator equipped to be synchronized to the grid?
If the status code entered on line 5a is standby (SB), check “Yes”
if the generator is currently equipped to be synchronized to the
grid when operating. Check “No” if it is not.
For
line
6, When
did this generator begin commercial operation?
Enter the month and year of initial commercial operation in the
format MM-YYYY.
For
line
7, When
was this generator retired?
Enter the month and year that the generator was retired in
the format (MM-YYYY).
For
line 8, If
this generator will be retired in the next ten years, what is its
estimated retirement date?
If you expect this generator to be retired in the next 10 years,
enter your best estimate for this planned retirement date in the
format MM-YYYY.
For
line
9
Is this generator associated with a combined heat and power
system?
Check “Yes” if this generator is associated with a
combined heat and power system. Check “No” if it is
not.
For
line
10, Is
this
generator part of a topping or bottoming cycle?
If you checked “Yes” on line 9, check
“Topping” if this generator is part of a topping
cycle. In a topping cycle system, electricity is produced first
and any waste heat from that production is used in a
manufacturing or commercial application. Check “Bottoming”
if this generator is part of a bottoming cycle. In a bottoming
cycle system, thermal output is used in a process other than
electricity production and any waste heat is then used to produce
electricity.
For
line 11, What
is this generator’s predominant energy source?
Enter the energy source code for the fuel used in the largest
quantity (Btus) during the reporting year to power the generator.
For generators that are out of service for an
extended period of time or on standby, report the energy sources
based on the generator’s
latest operating experience. For generators driven by turbines
using steam that is produced from waste heat or reject heat,
report the original energy source used to produce the waste heat
(reject heat). Do not include fuels expected to be used only for
start-up or flame stabilization. Select the appropriate energy
source code from Table 28 in these instructions.
For
line 12, What
are the energy sources used by this generator’s combustion
units for start-up and flame stabilization? If
the prime mover is steam turbine (ST), report the energy sources
used
by the combustion unit(s) associated with this generator for
start-up and flame stabilization; otherwise leave blank. Select
the appropriate energy source code from Table 28 in these
instructions.
For
line 13, What
is this generator’s second most predominant energy source?
Enter the energy source code for the energy source used in the
second largest quantity (Btus) during the reporting year to power
the generator. DO NOT include a fuel used only for start-up or
flame stabilization. For generators driven by turbines using
steam that is produced from waste heat or reject heat, report the
original energy source used to produce the waste heat or reject
heat. Select the appropriate energy source code from Table 28 in
these instructions.
For
line 14, What
other energy sources are used by the generator?
Enter the codes for other energy sources that can be used by the
generator to generate electricity: first, list the energy sources
actually used in order of predominance (based on quantity of
Btus), then list ones that the generator was capable of using but
was not used to generate electricity during the last 12 months.
For generators that are out of service for an extended period of
time or on standby, report the energy sources based on the
generator’s latest operating experience. For generators
driven by turbines using steam that is produced from waste heat
or reject heat, report the original energy source used to produce
the waste heat or reject heat. Select the appropriate energy
source codes from Table 28 in these instructions.
For
line 15, Is
this generator part of a solid fuel gasification system?
Check
“Yes” if this generator
is part of a solid fuel gasification system. Check “No”
if it is not.
For
line 16, What
is the tested heat rate for this generator?
Enter the tested heat rate under full load conditions for all
combustible-fueled generators and nuclear-fueled generators. The
tested heat rate is the amount of fuel, measured in British
thermal units (Btus) necessary to generate one net kilowatt-hour
of electric energy. Do not report the actual heat rate, which is
the quotient of the total Btu(s), consumed and total net
generation. If generators are tested as a unit (not tested
individually), report the same test result for each generator.
For generators that are out of service for an extended period or
on standby, report the heat rate based
on the unit’s latest test. If the generator is associated
with a combined heat and power (CHP) system, and no tested heat
rate data are available, report either the manufacturer’s
specification for heat rate or an estimated heat rate. DO NOT
report a heat rate that includes the fuel used for the production
of useful thermal output. For Internal Combustion units, a
manufacturer’s specification or estimated heat rate should
be reported, if no tested heat rate is available. If the reported
value is not a tested heat rate, specify in SCHEDULE 7.
This
information will be protected and not disclosed to the extent
that it satisfies the criteria for exemption under the Freedom of
Information Act (FOIA), 5 U.S.C. §552, the Department of
Energy (DOE) regulations, 10 C.F.R. §1004.11, implementing
the FOIA, and the Trade Secrets Act, 18 U.S.C. §1905
For
line
17, What
fuel was used to determine this generator’s tested heat
rate?
Enter the fuel code for the fuel used to determine the heat rate
reported in line 16. Enter “M” if multiple fuels were
used to calculate the heat rate reported in line 16. For
generators driven by turbines using steam that is produced from
waste heat or reject heat, report the original energy source used
to produce the waste or reject heat). Select appropriate energy
source codes from Table 28 in these instructions.
For
line 18, Is
the generator associated with a carbon dioxide capture process?
Check “Yes” if this generator is associated with
carbon dioxide capture.
Check “No” if it is not.
For
line 19, How
many wind turbines, inverters, or hydrokinetic
buoys
are there at this generator?
Wind generators should enter the number of wind turbines, solar
photovoltaic generators should enter the number of inverters, and
hydrokinetic generators
should enter the number of hydrokinetic buoys.
All other generators should enter 0.
Line
20 is reserved for future use.
For
line 21, What
is the minimum amount of time required to bring this generator
from cold shut down to full load?
Select the minimum amount of time required to bring the unit to
full load from cold shutdown. Wind and solar-powered generators
should not answer this question.
For
line 22, What
is the minimum amount of time required to bring this generator
from a non-spinning reserve status to full load?
Select the minimum amount of time required to bring the unit to
full load from a non-spinning reserve status. Wind and
solar-powered generators should not answer this question.
Answer
questions on lines 23 and 24 only if generator is fueled by coal
or petroleum coke
For
line 23, What
combustion technology applies to this generator?
Select the appropriate
combustion technology that applies to the generator.
For
line 24, What
steam conditions apply to this generator?
Select the appropriate steam conditions that apply to the unit.
Answer
questions on lines 25 through 29 only if generator is wind-powered
For
line
25, What
is the predominant manufacturer of the turbines at this
generator?
Enter the predominant manufacturer of the turbines at the
generator. If the predominant manufacturer is not known, enter
“UNKNOWN.”
For
line 26, What
is the predominant turbine model number at this generator?
Enter the predominant
model number. If the predominant model number is not known, enter
“UNKNOWN.”
On
line
27a, What
is the design average annual wind speed at this generator?
Enter the design average annual wind speed in miles per hour for
the turbines included in the generator. If more than one value
exists, select the one that best represents the turbines.
On
line 27b, What
is the wind quality class for turbines included in this generator?
Select the wind quality class for the turbines included in the
generator, as defined by the International Electrotechnical
Commission (IEC 61400-1 ed. 2) and Table 5 below. If more than one
wind class exists, select the one that best represents the
turbines.
Table
5. Wind
Quality Class and Descriptions
-
Class
|
Annual
Average Wind Speed
|
Extreme
50-Year Gust
|
Turbulence
Intensity
|
Class
1 – High Wind
|
10
m/s
|
70
m/s
|
A:
0.210
B: 0.180
|
Class
2 – Medium Wind
|
8.5
m/s
|
59.6
m/s
|
A:
0.226
B: 0.191
|
Class
3 – Low Wind
|
7.5
m/s
|
52.5
m/s
|
A:
0.240
B: 0.200
|
Class
4 – Very Low Wind
|
6
m/s
|
42
m/s
|
A:
0.270
B: 0.220
|
On
line 28, What
is the hub height for the turbines in this generator?
Enter the hub height in feet for the turbines at the generator.
If this generator consists of turbines with multiple hub heights,
select the one that best represents all of the turbines.
On
line 29, What
is the FAA Obstacle Number assigned to turbines at this
generator?
Enter the Obstacle Number assigned by the Federal Aviation
Administration. When the generator consists of turbines with
multiple Obstacle Numbers, select the Obstacle Number that best
represents the turbines.
Answer
questions on lines 30 through 32 only if generator is powered by
photovoltaic or concentrated solar thermal technology
On
line 30, What
are the solar tracking, concentrating and collector technologies
used at this generator?
Select all applicable solar tracking, concentrating or collector
technologies used at the unit. If you select “Other,”
provide details in SCHEDULE 7.
On
line 31, What
is the net capacity of this photovoltaic generator in direct
current (DC) under standard test conditions (STC) of 1000 W/m2
solar irradiance and 25 degrees Celsius PV module temperature?
Enter the sum of the DC capacity ratings of the photovoltaic
modules associated with this generator.
On
line 32, What
materials are the photovoltaic panels included in this generator
made of?
Select the material of the Photovoltaic panels. If the panels
included in the “generator” are made of different
materials, select all materials used. If you select “Other,”
provide details on the material in SCHEDULE 7.
Lines
33-37 apply to proposed changes to existing generators
If
a capacity uprate is planned within the next 10 years, answer
Questions 33a – 33c.
For
line 33a,
What is the expected incremental increase in the net summer
capacity?
If an uprate
is planned within the next 10 years enter
the incremental amount by which the net summer capacity is
expected to increase. If no uprate is planned in the next ten
years, leave this blank.
For
line 33b, What
is the expected incremental increase in the net winter capacity?
If
an uprate is planned within the next 10 years, enter
the incremental amount by which the net winter capacity is
expected to increase. If no uprate is planned in the next ten
years, leave this blank.
For
line 33c, What
is the planned effective date for this capacity uprate?
If an uprate is planned within the next 10 years, enter the date
on which the generator is scheduled to re-enter commercial
operation after the planned uprate. Enter the date in the format
MM-YYYY. If no uprate is planned in the next 10 years, leave this
blank.
If
a capacity derate is planned within the next 10 years, answer
Questions 34a – 34c.
For
line 34a,
What is the expected incremental decrease in the net summer
capacity?
If a derate is planned within the next 10 years, enter
the incremental amount by which the net summer capacity is
expected to decrease. If no derate is planned in the next 10
years, leave this blank.
For
line 34b, What
is the expected incremental decrease in the net winter capacity?
If
a derate is planned within the next 10 years, enter
the incremental amount by which the net winter capacity is
expected to decrease. If no derate is planned in the next ten
years, leave this blank.
For
line 34c, What
is the planned effective date for this capacity derate?
If a derate is planned in the next 10 years, enter the date on
which the generator is scheduled to re-enter commercial operation
after the planned derate. Enter the date in the format MM-YYYY.
If no derate is planned in the next 10 years, leave this blank.
For
line 35a, What
is the expected new prime mover for this generator? If
a repowering is planned within the next 10 years, enter the new
prime mover for this generator. Select
the prime mover code from those listed in the instructions for
SCHEDULE 3 Part A, Table 2. If no repowering is planned within
the next 10 years, leave this blank.
For
line 35b, What
is the expected new energy source for this generator?
If
a repowering is planned within the next 10 years, enter the new
energy source for this generator. Select the energy source code
from Table 28 in these instructions. If no repowering is planned
in the next ten years, leave this blank.
For
line 35c, What
is the expected new nameplate capacity for this generator?
If
a repowering is planned for within the next 10 years,
enter the new nameplate capacity for this generator.
For
line 35d, What
is the planned effective date for this repowering?
Enter the date on which this generator is scheduled to re-enter
operation after the repowering. Enter the date in the format
MM-YYYY. If no repowering is planned, leave this blank.
On
line 36a, Are
any other modifications planned within the next 10 years? Check
“Yes” if any other significant modifications are
planned for this
generator in the next 10 years. Explain these modifications on
SCHEDULE 7 of this form. Check “No” If no other
significant modifications are planned within the next 10 years.
On
line 36b, What
is the planned date of these other modifications? If
you checked “Yes” on line 36a, enter the date on which
this generator will reenter service after the modification. Enter
the date in the format MM-YYYY. If you selected “No,”
leave this blank.
On
line 37a, Can
this generator co-fire fuels?
Indicate yes if the combustion system that powers each generator
has both:
The
regulatory permits necessary to co-fire fuels, and
The
equipment, including fuel storage facilities in working order,
necessary to either co-fire fuels or fuel switch.
Note:
Co-firing
means the simultaneous use of two or more fuels by a single
combustion system to meet load. Co-firing excludes the limited use
of a secondary fuel for start-up or flame stabilization.
Line37b
applies only if the generator can co-fire fuels
For
line 37b, What
are the fuel options for co-firing?
Indicate up to six fuels that can be co-fired. Select appropriate
energy source codes from Table 28 in these instructions.
Note:
fuel options listed for co-firing must also be included under
either “Predominant Energy Source,” Second Most
Predominant Energy Source,” or “Other Energy Sources.”
For
line 38a, Can
this generator switch between oil and natural gas?
Check
“Yes” if:
the
primary
energy source of the unit is oil or natural gas;
the
combustion system
that powers the generator has, in working order, the equipment
(including fuel oil storage tanks) necessary to switch between
natural gas and oil; and
this
combustion system has the regulatory permits necessary to switch
between natural gas and oil.
Note:
Fuel
switching
means the ability of a combustion system running on one fuel to
replace that fuel in its entirety with a substitute fuel. Fuel
switching excludes the limited use of a secondary fuel for
start-up or flame stabilization.
Answer
questions on lines 38b through 42 only if generator can fuel
switch between oil and natural gas
For
line 38b, Can
this generator switch between oil and natural gas while operating?
Check
“Yes,”
if
1)
you
checked “Yes” for line 38a, and 2) if the combustion
system that powers this generator is able to switch between
natural gas and oil
while
operating.
For
line 39a, What
is the maximum net summer output achievable when running on
natural gas?
Enter
the
maximum
net summer output in MW that the unit can achieve when running on
natural gas, taking into account all applicable legal,
regulatory, and technical limits.
For
line 39b, What
is the maximum net winter output achievable when running on
natural gas?
Enter
the
maximum
net winter output in MW that the unit can achieve when running on
natural gas, taking into account all applicable legal, regulatory,
and technical limits.
For
line 40a, What
is the maximum net summer output achievable when running on oil?
Enter
the
maximum
net summer output in MW that the unit can achieve when running on
fuel oil, taking into account all applicable legal, regulatory,
and technical limits.
For
line 40b, What
is the maximum net winter output achievable when running on oil?
Enter
the
maximum
net winter output in MW that the unit can achieve when running on
fuel oil, taking into account all applicable legal, regulatory,
and technical limits.
For
lines 41a,
How
much time is required to switch the generator from using 100
percent natural gas to 100 percent oil?
Enter
the amount of time that it takes to
switch the generator from using 100 percent natural gas to 100
percent oil.
For
line 41b, How
much time is required to switch this generator from using 100
percent oil to using 100 percent natural gas? Enter
the amount of time that it takes
to switch the generator from using 100 percent oil to 100 percent
natural gas.
For
line
42a,
Are there factors that limit this generator’s ability to
switch between natural gas and oil? These
factors may include limits on maximum output, limits on annual
operating hours, or other
limitations.
For
line 42b, Which
factors limit this generator’s ability to switch between
natural gas and oil?
If you selected “Yes” on line 42a, select all of the
factors that limit the ability to switch fuels. If you select
“Other” provide explanation in SCHEDULE 7.
SCHEDULE
3, PART C. GENERATOR INFORMATION – PROPOSED GENERATORS
Complete
this Schedule for all generators at this plant that are:
Expected
to be in commercial operation within 10 years in the case of coal
and nuclear generators; or
Expected
to be in commercial operation within 5 years for all generators
other than coal and nuclear generators.
For
line 1a, What
is the expected nameplate capacity for this generator?
Enter the expected nameplate capacity in MW rounded to the
nearest tenth, as measured in alternating current (AC). If the
expected nameplate capacity is expressed in kilovolt amperes
(kVA), first convert the expected nameplate capacity to kilowatts
by multiplying the corresponding power factor by the kVA and then
convert to megawatts by dividing by 1,000. Round this value to
the nearest tenth.
For
line 1b, What
is the expected nameplate power factor for this generator?
Enter the expected power factor. This should be the same power
factor used to convert the generator’s kilovolt-ampere
rating (kVA) to megawatts (MW) as directed for line 1a above.
For
line 2, What
is the expected net capacity for this generator?
Enter the generator’s net summer and net winter capacities
for the primary energy source that are expected when the
generator goes into commercial operation. Report these values in
MW
rounded to the nearest tenth, as measured in alternating current
(AC).
For
line
3, What
was the status of this proposed generator as of December 31 of
the reporting year?
Enter one of the following status codes:
Table
6. Proposed Generator Status Codes and Descriptions
-
Proposed
Generator Status Code
|
Proposed
Generator Status Code Descriptions
|
IP
|
Planned
new generator canceled, indefinitely postponed, or no longer
in resource plan
|
TS
|
Construction
complete, but not yet in commercial operation (including low
power testing of nuclear units)
|
P
|
Planned
for installation but regulatory approvals not initiated; Not
under construction
|
L
|
Regulatory
approvals pending. Not under construction but site preparation
could be underway
|
T
|
Regulatory
approvals received. Not under construction but site
preparation could be underway
|
U
|
Under
construction, less than or equal to 50 percent complete (based
on construction time to date of operation)
|
V
|
Under
construction, more than 50 percent complete (based on
construction time to date of operation)
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 4, What
is the planned original effective date for this generator?
Enter the date on which the generator is scheduled to start
commercial operation. Enter the date in the format MM-YYYY. This
date will not change after it has been reported the first time.
For
line 5, What
is the planned current effective date for this generator?
If a Planned Original Effective Date was submitted an earlier
filing and is no longer accurate, enter the updated date on which
the generator is scheduled to start commercial operation. Enter
the date in the format MM-YYYY. Leave blank if this is your first
time filling out this form.
For
line
6, Will
this generator be associated with a combined heat and power
system? Check
“Yes” if this generator will be associated with
combined heat and power system. If it will not, check “No.”
For
line 7,
Is this generator part of a site that was previously reported as
indefinitely postponed or cancelled?
Check “Yes” if this generator is part of a site that
was previously reported by either your company or a previous
owner as an indefinitely postponed or cancelled plant. Check “No”
if it is not. Check “Unknown” if this history is not
known.
For
line 8, What
is the predominant expected energy source for this generator?
Enter the energy source code for the energy source expected to be
used in the largest quantity, as measured in Btus, when the
generator starts commercial operation.
Select appropriate energy source codes from Table 28 in these
instructions.
For
line 9, What
is the second most predominant expected energy source for this
generator?
Enter
the energy source code for the energy sources expected to be used
in the second largest quantity, as measured in Btus, when the
generator
starts commercial operation. Do not include fuels expected to be
used only for start-up or flame stabilization. Select the
appropriate energy source code from Table 28 in these
instructions.
For
line 10, What
other energy sources do you expect to use for this generator?
Enter the codes for other energy sources that will be used at the
plant to power the generator. Enter up to four codes. Enter these
codes in order of their expected predominance as measured in
Btus. Select appropriate energy source codes from Table 28 in
these instructions.
For
line 11, How
many turbines, inverters, or buoys is this generator expected to
have?
Wind
generators should enter the number of turbines, solar generators
should enter the number of inverters, and hydroelectric
generators
should enter the number of buoys.
For
line 12, What
combustion technology will apply to this generator?
If the generator will be fired by coal or petroleum coke, select
the appropriate combustion technology. If
you select “Other” provide explanation in SCHEDULE 7.
For
line 13 What
steam conditions will apply to this generator?
If the generator will be fired by coal or petroleum coke, select
the appropriate steam conditions.
For
line 14, Will
this generator be part of a solid fuel gasification system?
Check
“Yes” if this generator will be part of a solid fuel
gasification system. Check “No” if it will not be.
For
line 15,
Will this generator be associated with a carbon dioxide capture
process?
Check “Yes” if this generator will be associated with
a carbon capture process. Check “No” if it will not
be associated with carbon capture.
Line
16 applies only if the generator will be able to fuel switch.
Lines
17a and 17b apply only if the generator will be able to co-fire
fuels.
Note:
Co-firing
means the simultaneous use of two or more fuels by a single
combustion system to meet load. Fuel
switching
means the ability of a combustion system running on one fuel to
replace that fuel in its entirety with a substitute fuel.
Co-firing and fuel switching exclude the limited use of a
secondary fuel for start-up or flame stabilization
For
line 16, Will
the combustion system that powers this generator be able to
switch between natural gas and oil? Check
“Yes” if 1) the primary energy source of the
generator will be natural gas or oil and 2) the combustion system
that
will power the generator will have the ability and equipment
necessary (including fuel oil storage tanks) to switch between
natural gas and oil. Check “No” if it will not.
Check “Undetermined” if a determination on switching
between natural gas and oil has not yet been made.
For
line 17a, Will
the combustion system that powers this generator be able to
co-fire fuels?
Indicate whether or not the combustion system that will power
the generator will have the necessary equipment and regulatory
permits to co-fire fuels.
For
line 17b, What
are the fuel options for co-firing?
Indicate up to six fuels that the generator will be designed to
co-fire. Select the energy source codes from Table 28 in these
instructions. Note: fuel options listed for co-firing must also
be included under “Predominant Energy Source,” Second
Most Predominant Energy Source,” and/or “Other Energy
Sources.”
SCHEDULE
4. OWNERSHIP OF GENERATORS OWNED JOINTLY OR BY OTHERS
Complete
SCHEDULE 4 for each operable or planned generator that is or will
be either jointly owned with another entity or wholly owned by an
entity other than the reporting entity as entered on SCHEDULE 1,
Line 3.
For
each generator that is either jointly owned with another entity
or wholly owned by another specify the Plant
Name, EIA Plant Code, and Generator Identification Code,
as listed on SCHEDULE 3, PART A.
For
each owner of either a jointly owned generator or wholly owned by
an entity other than the reporting entity generator, enter the
name, address and percentage owned. The total percentage of
reported ownership must equal 100 percent.
If
known, enter the EIA
Owner Code
for the owner, otherwise leave blank. The EIA Owner Code is the
same as the EIA Utility Identification Code and EIA Entity
Identification Code.
Enter
the Percent
Owned
to two decimal places, i.e., 12.5 percent as “12.50.”
Include
any notes or comments in SCHEDULE 7.
SCHEDULE
5. GENERATOR CONSTRUCTION COST INFORMATION
The
reporting year is the calendar year that you are filing the
survey for. For example, if
you are reporting
data as of December 31, 2013, then the reporting year is 2013.
Include
all construction costs in SCHEDULE 5 regardless of
which party is ultimately responsible for those costs. All
disputed costs must be included in the reported estimated or
final project costs. If disputed costs
are included in the reported estimated or final project costs,
you can note this in SCHEDULE 7.
SCHEDULE
5, PART A. GENERATOR CONSTRUCTION COST INFORMATION - COAL
AND NUCLEAR
GENERATORS
Complete
a separate SCHEDULE 5, PART A for each coal or nuclear generator
that, during the reporting year:
Began
commercial operation; or
Was
under
construction, in final testing or in the process of receiving
permits and regulatory approvals; or
Was
a nuclear generator that has applied for a combined operating
license (COL) from the Nuclear Regulatory Commission.
Enter
the Plant
Name,
EIA
Plant Code,
and Generator
ID
as previously reported in SCHEDULE 3, PART A.
For
line 1, What
is the total construction cost for this generator (in thousands
of dollars)?
If the generator did
not enter commercial operation during the reporting year, provide
the best available projection of the total construction cost to
completion. If the project entered commercial operation during
the reporting year, provide the best available estimate of total
construction costs. Total Construction Costs should be provided
in nominal dollars (do
not discount future costs to reflect the time value of money and
do not adjust past costs to reflect inflation) and
typically include the following items:
Civil
and structural costs
- allowance for site preparation, drainage, installation of
underground utilities, structural steel supply, and construction
of buildings on the site. Exclude land acquisition or leasing
costs.
Mechanical
equipment supply and installation
- major equipment, including but not limited to, boilers, flue
gas desulfurization scrubbers, cooling towers, steam turbine
generators, condensers, and other auxiliary equipment.
Electrical
and instrumentation control – electrical
transformers, switchgear, motor control centers, switchyards,
distributed control systems, and other electrical commodities.
Project
indirect costs – engineering,
distributable labor and materials, craft labor overtime and
incentives, scaffolding costs, construction management start up
and commissioning, and fees for contingency (including contractor
overhead costs, fees, profits, and construction).
Owner
Costs –
development costs, preliminary feasibility and engineering
studies, environmental studies and permitting, legal fees,
insurance costs, property taxes during construction, and the
electrical interconnection costs, including a tie-in to a nearby
electrical transmission system.
Exclude
financing, government grants, tax benefits, or other incentives
from this number.
For
line 2, What
are
the total financing costs for construction of this generator (in
thousands of dollars)?
Enter the total financing costs including
(1) the interest cost of debt financing, (2) any imputed cost of
equity financing, and (3) funds recovered to maintain a debt
service coverage ratio for the project. In the cast of
investor-owned utilities, financing costs include any allowance
for funds used during construction (AFUDC). For example, the net
cost for the period of construction of borrowed funds used for
construction purposes and a reasonable rate on other funds when
so used.
For
line 3, What
is the total cost to construct this generator including financing
costs (in thousands of dollars)?
Enter the total cost to construct the generator including both
construction costs and financing. This value should be the sum of
the answers to the two previous questions.
SCHEDULE
5, PART B. GENERATOR CONSTRUCTION COST INFORMATION - OTHER
THAN
COAL AND NUCLEAR GENERATORS
Complete
a separate SCHEDULE 5, PART B for each generator other
than
coal or nuclear generators that, during the reporting year:
Do
not
report for any units reported on SCHEDULE 5, PART A.
Enter
the Plant
Name,
EIA
Plant Code,
and Generator
ID
as previously reported in SCHEDULE 3, PART A.
For
line 1, What
is the total construction cost for this generator (in thousands
of dollars)?
Enter the total construction cost to
completion. Total Construction Costs should be provided in
nominal dollars (do
not discount future costs to reflect the time value of money and
do not adjust past costs to reflect inflation) and
typically include the following items:
Civil
and structural costs
- allowance for site preparation, drainage, installation of
underground utilities, structural steel supply, and construction
of buildings on the site. Exclude land acquisition or leasing
costs.
Mechanical
equipment supply and installation
- major equipment, including but not limited to, boilers, flue
gas desulfurization scrubbers, cooling towers, steam turbine
generators, condensers, photovoltaic modules, combustion
turbines, and other auxiliary equipment.
Electrical
and instrumentation control – electrical
transformers, switchgear, motor control centers, switchyards,
distributed control systems, and other electrical commodities.
Project
indirect costs – engineering,
distributable labor and materials, craft labor overtime and
incentives, scaffolding costs, construction management start up
and commissioning, and fees for contingency (including contractor
overhead costs, fees, profits, and construction).
Owner
Costs –
development costs, preliminary feasibility and engineering
studies, environmental studies and permitting, legal fees,
insurance costs, property taxes during construction, and the
electrical interconnection costs, including a tie-in to a nearby
electrical transmission system.
Exclude
financing, government grants, tax benefits, or other incentives
from this number.
For
line 2, What
are
the total financing costs for construction of this generator (in
thousands of dollars)?
Enter the total financing costs including
(1) the interest cost of debt financing, (2) any imputed cost of
equity financing, and (3) funds recovered to maintain a debt
service coverage ratio for the project. In the cast of
investor-owned utilities, financing costs include any allowance
for funds used during construction (AFUDC). For example, the net
cost for the period of construction of borrowed funds used for
construction purposes and a reasonable rate on other funds when
so used.
For
line 3, What
is the total cost to construct this generator including financing
costs (in thousands of dollars)?
Enter the total cost to construct the generator including both
construction costs and financing. This value should be the sum of
the answers to the two previous questions.
SCHEDULE
6. INFORMATION ON BOILERS AND ASSOCIATED EQUIPMENT
SCHEDULE
6 collects information on existing and planned boilers and
associated equipment serving steam electric generators, including
units burning combustible fuels, nuclear units, and solar thermal
units. Complete for EACH boiler.
Complete
SCHEDULE 6 as follows:
Required
Respondents
|
Schedule
6 Parts
to be Completed
|
Plants
where the sum of the nameplate capacity of the steam-electric
generators, including duct fired steam components of combined
cycle units, sum to 100 MW or more.
|
Parts
A - G
|
All
nuclear plants, solar thermal plants and steam components of
combined cycle units without duct firing where the sum of the
nameplate capacity of the steam-electric generators is 100 MW
or more.
|
Part
A
Part
D
|
Plants
where the sum of the nameplate capacity of the steam-electric
generators, including duct fired steam components of combined
cycle units, sum to 10 MW or more, but less than 100 MW.
|
Part
A
Part
B, Lines 6 to 8 and 11 to 14 (NOx
and Mercury questions)
Part
C, Lines 1 to 3
Part
E
Part
F
|
SCHEDULE
6, PART A. PLANT CONFIGURATION AND ENVIRONMENTAL EQUIPMENT
INFORMATION
Complete
SCHEDULE 6, Part A, if you are reporting for
a plant where the sum of the nameplate capacity of the
steam-electric generators, including duct-fired steam components
of combined cycle units, sum to 10 MW or more.
For
line 1, What
equipment is associated with each boiler at this plant?
Enter
the unique identification codes commonly used by plant management
to identify the boiler and all associated equipment: generators,
cooling systems, particulate matter control systems, sulfur
dioxide control systems, NOx control, mercury control and stacks.
These
identification codes are generally restricted to six characters
and cannot be changed once provided to EIA. However, the
identification codes for generators are restricted to five
characters.
Include
all equipment that:
Was
operable in the past calendar year; or
Is
expected to be in commercial operation within 10 years in the
case of equipment associated with coal and nuclear generators; or
Is
expected to be in commercial operation within 5 in the case of
equipment not associated with coal and nuclear generators
If
two or more pieces of equipment (e.g., two generators) are
associated with a single boiler, report each identification code
separated by commas under the appropriate boiler.
If
any equipment is associated with multiple boilers, repeat the
equipment identification code under each boiler. Do not change
prepopulated equipment identification codes.
Note
equipment such as selective catalytic reduction, activated carbon
injection, and dry sorbent injection into a fluidized bed boiler
will require an identification code entry as these were not
collected in past reporting years.
Row
1 – Enter boiler ID
Row
2 – Enter all generator ID(s) associated with the boiler
(Generator ID must match those entered on SCHEDULE 3 PART A.
Row
3 – Enter associated cooling system ID(s)
Row
4 – Enter associated particulate matter control system
ID(s)
Row
5 – Enter associated sulfur dioxide control system ID(s)
including dry sorbent injection (DSI) in a fluidized bed
combustion boiler
Row
6 – Enter associated nitrogen oxide (NOx) control equipment
ID(s) (assign an ID to each selective catalytic reduction and
selective noncatalytic reduction device).
Row
7 – Enter associated mercury control ID(s), including
activated carbon injection (assign an ID to each mercury control
system).
Row
8 – Enter associated stack (or flue) ID(s)
For
Line 2, What
are the characteristics of each piece of emissions control
equipment?
Enter
in Column A, the Equipment Type code from Table 7.
Table
7. Equipment
Type Code and Description
-
Equipment
Type
Code
|
Equipment
Type Description
|
JB
|
Jet
bubbling reactor (wet) scrubber
|
MA
|
Mechanically
aided type (wet) scrubber
|
PA
|
Packed
type (wet) scrubber
|
SP
|
Spray
type (wet) scrubber
|
TR
|
Tray
type (wet) scrubber
|
VE
|
Venturi
type (wet) scrubber
|
BS
|
Baghouse
(fabric filter), shake and deflate
|
BP
|
Baghouse
(fabric filter), pulse
|
BR
|
Baghouse
(fabric filter), reverse air
|
EC
|
Electrostatic
precipitator, cold side, with flue gas conditioning
|
EH
|
Electrostatic
precipitator, hot side, with flue gas conditioning
|
EK
|
Electrostatic
precipitator, cold side, without flue gas conditioning
|
EW
|
Electrostatic
precipitator, hot side, without flue gas conditioning
|
MC
|
Multiple
cyclone
|
SC
|
Single
cyclone
|
CD
|
Circulating
dry scrubber
|
SD
|
Spray
dryer type / dry FGD / semi-dry FGD
|
DSI
|
Dry
sorbent (powder) injection type (DSI)
|
ACI
|
Activated
carbon injection system
|
LIJ
|
Lime
injection
|
SN
|
Selective
noncatalytic reduction
|
SR
|
Selective
catalytic reduction
|
OT
|
Other
equipment (Specify in SCHEDULE 7)
|
For
Columns B to I:
Enter
the identification codes from the above table in the appropriate
columns for emissions controls. If a piece of equipment controls
multiple air emissions, enter the appropriate code in multiple
columns (for example, if a wet scrubber controls for both sulfur
dioxide, particulate matter and mercury, enter the associated
identification code from the table above in Columns B, C and E).
For
Particulate Control (PM) equipment, enter identification code(s)
in Column B
For
Sulfur Dioxide Control (SO2) equipment, enter the identification
code(s) in Column C
For
Nitrogen Oxide Control (NOx) equipment, enter the identification
code(s) in Column D
For
Mercury Control (Hg) equipment, enter the identification code(s)
in Column E
For
HCl gas control, enter an X in Column F (no identification codes
are required).
For
Column G, enter the status for the equipment as of December 31 of
the reporting year from Table 8 in the instructions.
Table
8. Equipment Status Codes and Descriptions
-
Status
Code
|
Status
Description
|
CN
|
Cancelled
(previously reported as “planned”)
|
CO
|
New
unit under construction
|
OP
|
Operating
(in commercial service or out of service less than 365 days)
|
OS
|
Out
of service (365 days or longer)
|
OZ
|
Operated
only during the ozone season (May through September)
|
PL
|
Planned
(expected to go into commercial service within 10 years)
|
RE
|
Retired
(no longer in service and not expected to be returned to
service)
|
SB
|
Standby
(or inactive reserve); i.e., not normally used, but available
for service
|
SC
|
Cold
Standby (Reserve); deactivated (usually requires 3 to 6 months
to reactivate)
|
TS
|
Operating
under test conditions (not in commercial service)
|
In
Column H,
In-service Date, enter
the date on which the equipment
began commercial operation or the date on which it
is
expected to begin commercial operation (MM/YYYY).
In
Column I,
Total Costs (Thousand Dollars), enter
the nominal installed cost for the existing system or the
anticipated cost to bring a planned piece of equipment into
commercial operation (in thousands of dollars). Installed cost
should include the cost of all major modifications. A major
modification is any physical change which results in a change in
the amount of air emissions or pollutants or which results in a
different pollutant being emitted.
Costs should be provided in nominal dollars (do not discount
future costs to reflect the time value of money and do not adjust
past costs to reflect inflation)
SCHEDULE
6, PART B. BOILER INFORMATION – AIR EMISSION STANDARDS AND
CONTROL STRATEGIES
For
plants with a total steam-electric nameplate capacity of 10 MW or
greater but less than 100 MW:
Complete
ONLY questions 1, 6a to 6d, 7, 8a, 8b, 11,12, 13 and 14 (NOx and
Mercury questions) SCHEDULE 6, Part B for each boiler and its
associated equipment that serve or are expected to serve
combustible-fueled steam electric generators or combined cycle
steam generators with duct firing.
For
plants with a total steam-electric nameplate capacity of 100 MW or
greater:
Complete
one SCHEDULE 6, Part B in its entirety for each boiler and its
associated equipment that serve or are expected to serve
combustible-fueled steam electric generators and combined cycle
steam generators with duct firing.
Include
all boilers that:
Were
operable in the past calendar year; or
Are
expected to be in commercial operation within 10 years in the
case of coal plans; or
Are
expected to be in commercial operation within 5 years in the case
of non-coal plants
For
line 1, What
is this boiler’s identification code? Enter
the boiler identification number corresponding to each boiler
listed on SCHEDULE 6, PART A.
For
Line 2a, Type
of Boiler Standards under Which the Boiler is Operating, indicate
the standards as described in the U. S. Environmental Protection
Agency regulation under 40 CFR. Select from the codes in Table 9
of the New Source Performance Standards (NSPS):
Table
9.
Boiler Standards Codes and Descriptions
-
D
|
Standards
of Performance for fossil-fuel fired steam boilers for which
construction began after August 17, 1971.
|
Da
|
Standards
of Performance for fossil-fuel fired steam boilers for which
construction began after September 18, 1978
|
Db
|
Standards
of Performance for fossil-fuel fired steam boilers for which
construction began after June 19, 1984.
|
Dc
|
Standards
of Performance for small industrial-commercial-institutional
steam generating units
|
N
|
Not
covered under New Source Performance Standards.
|
For
line 2b, Is
this boiler operating under a new Source Review (NSR) permit?,
indicate whether the boiler is operating under a new source review
permit
For
line 2c, if the boiler is operating under a NSR permit, provide
the NSR
Permit List Date and NSR Permit identification
number.
Lines
3-5 apply to sulfur dioxide compliance
For
line
3a, What
is the regulatory level of the most stringent regulation that
this boiler is operating under to meet sulfur dioxide control
standards? Select
the most
stringent
regulation that the boiler operates under to meet sulfur dioxide
control standards.
For
line 3b, What
is the emission rate specified by the most stringent sulfur
dioxide regulation?
Enter the emission rate corresponding to the most stringent sulfur
dioxide regulation. Pounds of sulfur dioxide per million Btu in
fuel is the preferred measurement or use Units of Measurement in
Table 10.
For
line 3c, What
is the percent of sulfur to be scrubbed specified by the most
stringent sulfur dioxide regulation?
If the most stringent regulation specifies a percent (by weight)
of sulfur to be scrubbed enter the percent.
For
line 3d, What
is the unit of measurement specified by the most stringent sulfur
dioxide regulation?
Select the unit of measure corresponding to the emission rate
entered in line 3b from the values in Table 10. Note that DP*,
“Pounds of sulfur dioxide per million Btu in fuel” is
the preferred measurement.
Table
10. Sulfur Dioxide Unit
of Measurement Codes
-
Sulfur
Dioxide Unit of Measurement Code
|
Sulfur Dioxide Unit of Measurement
Code Description
|
DC
|
Ambient
air quality concentration of sulfur dioxide (parts per
million)
|
DH
|
Pounds
of sulfur dioxide emitted per hour
|
DL
|
Annual
sulfur dioxide emission level less than a level in a previous
year
|
DM
|
Parts
per million of sulfur dioxide in stack gas
|
DP*
|
Pounds
of sulfur dioxide per million Btu in fuel
|
SB
|
Pounds
of sulfur per million Btu in fuel
|
SR
|
Percent
sulfur removal efficiency (by weight)
|
SU
|
Percent
sulfur content of fuel (by weight)
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 3e, What
is the time period specified by the most stringent sulfur dioxide
regulation?
Enter the time period corresponding to the emission rate entered
in line 3b from the values in Table 11.
Table
11. Time
Period Codes
-
Time
Period Code
|
Time Period Code Description
|
NV
|
Never
to exceed
|
FM
|
5
minutes
|
SM
|
6
minutes
|
FT
|
15
minutes
|
OH
|
1
hour
|
WO
|
2
hours
|
TH
|
3
hours
|
EH
|
8
hours
|
DA
|
24
hours
|
WA
|
1
week
|
MO
|
30
days
|
ND
|
90
days
|
YR
|
Annual
|
PS
|
Periodic
stack testing
|
DT
|
Defined
by testing
|
NS
|
Not
specified
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 4, In
what year did the boiler became compliant or is expected to
become compliant with the most stringent sulfur dioxide
regulation?
Indicate the year in which the boiler came into compliance or is
expected to come into compliance with Federal, State and Local
Regulations as they relate to sulfur dioxide control.
For
line 5a,
What is your existing strategy for complying with the most
stringent sulfur dioxide regulation?
If the boiler is already in compliance with Federal, State and
local regulations as they relate to sulfur dioxide control,
select up to three compliance strategies from table 12 below.
Table
12. Sulfur
Dioxide Compliance Strategies
-
Sulfur
Dioxide Compliance Codes
|
Sulfur Dioxide Compliance Code
Descriptions
|
CF
|
Fluidized
Bed Combustor
|
CU
|
Control
unit under Phase I extension plan
|
IF
|
Install
flue gas desulfurization
unit or other SO2 control process (other than Phase I
extension plan)
|
NC
|
No
change in historic operation of unit anticipated
|
ND
|
Not
determined at this time
|
RP
|
Repower
Unit
|
SS
|
Switch
to lower sulfur fuel
|
SU
|
Designate
Phase II unit(s) as substitution unit(s)
|
TU
|
Transfer
unit under Phase I extension plan
|
UC
|
Decrease
utilization - designate Phase II unit(s) as compensating
unit(s)
|
UE
|
Decrease
utilization - rely on energy conservation and/or improved
efficiency
|
US
|
Decrease
utilization - designate sulfur-free generators to compensate
|
UP
|
Decrease
utilization - purchase power
|
WA
|
Allocated
allowances and purchase allowances
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 5b, What
is your proposed strategy for complying with the most stringent
sulfur dioxide regulation?
If the boiler is not in compliance with Federal, State and local
regulations as they relate to sulfur dioxide control, select up to
three proposed compliance strategies from table 12 above.
Lines
6-8 apply to nitrogen oxide compliance
For
line
6a, What
is the regulatory level of the most stringent regulation that
this boiler is operating under to meet nitrogen oxide control
standards? Select
the most
stringent
regulation that the boiler operates under to meet nitrogen oxide
control standards.
For
line 6b, What
is the emission rate specified by the most stringent nitrogen
oxide regulation?
Enter the emission rate corresponding to the most stringent
nitrogen oxide regulation. Pounds of nitrogen oxides per million
Btu in fuel is the preferred measurement or use Units of
Measurement in Table 13.
For
line 6c, What
is the unit of measurement specified by the most stringent
nitrogen oxide regulation?
Select the unit of measure corresponding to the emission rate
entered in line 6b from the values in Table 13. Note that “Pounds
of nitrogen oxides per million Btu in fuel” is the preferred
measurement.
Table
13. Nitrogen Oxide Unit
of Measurement Codes
-
Nitrogen
Oxide Unit of Measurement Code
|
Nitrogen Oxide Unit of Measurement
Code Description
|
NH
|
Pounds
of nitrogen oxides emitted per hour
|
NL
|
Annual
nitrogen oxides emission level less than a level in a previous
year
|
NM
|
Parts
per million of nitrogen oxides in stack gas
|
NO
|
Ambient
air quality concentration of nitrogen oxides (parts per
million)
|
NP*
|
Pounds
of nitrogen oxides per million Btu in fuel
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 6d, What
is the time period specified by the most stringent nitrogen oxide
regulation?
Enter the time period corresponding to the emission rate entered
in line 6b from the values in Table 11.
For
line 7, In
what year did the boiler became compliant or is expected to
become compliant with the most stringent nitrogen oxide
regulation?
Indicate the year in which the boiler came into compliance or is
expected to come into compliance with Federal, State and Local
Regulations as they relate to nitrogen oxide control.
For
line
8a,
What is your existing strategy for complying with the most
stringent nitrogen oxide regulation?
If the boiler is already in compliance with Federal, State and
local regulations as they relate to nitrogen oxide control,
select up to three compliance strategies from Table 14 below.
Table
14. Nitrogen Oxide Compliance Codes and Strategies
-
Nitrogen
Oxide Compliance Codes
|
Nitrogen Oxide Compliance Strategies
|
AA
|
Advanced
overfire air
|
BF
|
Biased
firing (alternative burners)
|
CF
|
Fluidized
bed combustor
|
FR
|
Flue
gas recirculation
|
FU
|
Fuel
reburning
|
H2O
|
Water
injection
|
LA
|
Low
excess air
|
LN
|
Low
NOx burner
|
NH3
|
Ammonia
injection
|
NC
|
No
change in historic operation of unit anticipated
|
ND
|
Not
determined at this time
|
OV
|
Overfire
air
|
RP
|
Repower
unit
|
SC
|
Slagging
|
SN
|
Selective
noncatalytic reduction
|
SR
|
Selective
catalytic reduction
|
STM
|
Steam
injection
|
UE
|
Decrease
utilization – rely on energy conservation and/or
improved efficiency
|
NA
|
Not
applicable
|
OT
|
Other
(specify in SCHEDULE 7)
|
BO
|
Burner
out of service
|
MS
|
Currently
meeting standard
|
NP
|
No
plans to control
|
SE
|
Seeking
revision of government regulation
|
For
line 8b, What
is your proposed strategy for complying with the most stringent
nitrogen oxide regulation?
If the boiler is not in compliance with Federal, State and local
regulations as they relate to nitrogen oxide control, select up to
three proposed compliance strategies from Table 14 above.
Lines
9-10 apply to particulate matter compliance
For
line
9a, What
is the regulatory level of the most stringent regulation that
this boiler is operating under to meet particulate matter control
standards? Select
the most
stringent
regulation that the boiler operates under to meet particulate
matter control standards.
For
line 9b, What
is the emission rate specified by the most stringent particulate
matter regulation?
Enter the emission rate corresponding to the most stringent
particulate matter regulation. Pounds of particulate matter per
million Btu in fuel is the preferred measurement or use Units of
Measurement in Table 15.
For
line 9c, What
is the unit of measurement specified by the most stringent
particulate matter regulation?
Select the unit of measure corresponding to the emission rate
entered in line 9b from the values in Table 15. Note that “Pounds
of Particulate matter per million Btu in fuel” is the
preferred measurement.
Table
15. Particulate Matter Unit
of Measurement Codes
-
Particulate
Matter Unit of Measurement Code
|
Particulate Matter Unit of
Measurement Code Description
|
OP
|
Percent
of opacity
|
PB*
|
Pounds
of Particulate matter per million Btu in fuel
|
PC
|
Grains
of particulate matter per standard cubic foot of stack gas
|
PG
|
Pounds
of particulate matter per thousand pounds of stack gas
|
PH
|
Pounds
of particulate matter emitted per hour
|
UG
|
Micrograms
of particulate matter per cubic meter
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 9d, What
is the time period specified by the most stringent particulate
matter regulation?
Enter the time period corresponding to the emission rate entered
in line 9b from the values in Table 11.
For
line 10, In
what year did the boiler became compliant or is expected to
become compliant with the most stringent particulate matter
regulation?
Indicate the year in which the boiler came into compliance or is
expected to come into compliance with Federal, State and Local
Regulations as they relate to particulate matter control.
Lines
11-14 apply to mercury and acid gas compliance
For
line
11, What
is the regulatory level of the most stringent regulation that
this boiler is operating under to meet mercury and acid gas
standards? Select
the most
stringent
regulation that the boiler operates under to meet mercury and
acid gas
control
standards.
For
line 12, In
what year did the boiler became compliant or is expected to
become compliant with the most stringent mercury and acid gas
regulation?
Indicate the year in which the boiler came into compliance or is
expected to come into compliance with Federal, State and Local
Regulations as they relate to mercury and acid gas
control.
For
line 13, What
are the existing strategies to control mercury emissions?
If the boiler is already in compliance with Federal, State and
local regulations as they relate to mercury control, select up to
three compliance strategies from Table 16 below.
Table
16. Mercury Compliance Codes and Descriptions
-
Strategy
Type Code
|
Strategy
Type Description
|
BS
|
Baghouse
(fabric filter), shake and deflate
|
BP
|
Baghouse
(fabric filter), pulse
|
BR
|
Baghouse
(fabric filter),
reverse air
|
CD
|
Circulating
dry scrubber
|
SD
|
Spray
dryer type / dry FGD / semi-dry FGD
|
DSI
|
Dry
sorbent (powder) injection type
|
ACI
|
Activated
carbon injection system
|
LIJ
|
Lime
injection
|
EC
|
Electrostatic
precipitator, cold side, with flue gas conditioning
|
EH
|
Electrostatic
precipitator, hot side, with flue gas conditioning
|
EK
|
Electrostatic
precipitator, cold side, without flue gas conditioning
|
EW
|
Electrostatic
precipitator, hot side, without flue gas conditioning
|
JB
|
Jet
bubbling reactor (wet) scrubber
|
MA
|
Mechanically
aided type (wet) scrubber
|
PA
|
Packed
type (wet) scrubber
|
SP
|
Spray
type (wet) scrubber
|
TR
|
Tray
type (wet) scrubber
|
VE
|
Venturi
type (wet) scrubber
|
OT
|
Other
(specify in SCHEDULE 7)
|
ND
|
Not
determined at this time
|
NA
|
Not
applicable
|
For
line 14,
What are the proposed strategies to control mercury emissions?
If the boiler is not in compliance with Federal, State and local
regulations as they relate to mercury control, select up to three
proposed compliance strategies from Table 16 above.
SCHEDULE
6, PART C. BOILER INFORMATION – DESIGN PARAMETERS
Complete
SCHEDULE 6, Part C, ONLY Lines 1 through 3 if
you are reporting for
a plant where the sum of the nameplate capacity of the
steam-electric generators, including duct fired steam components
of combined cycle units, sum to at least 10 MW, but less than 100
MW.
Complete
SCHEDULE 6, Part C in its entirety if
you are reporting for
a plant where the sum of the nameplate capacity of the
steam-electric generators, including duct fired steam components
of combined cycle units, sum to 100 MW or more.
Complete
one SCHEDULE 6, Part C for each unique Boiler ID as reported on
SCHEDULE 6 PART A, Line 1, Row 1
For
line 1, What
was this boiler’s status
as of December 31 of the reporting year?
Select
the boiler status from Table 17:
Table
17. Boiler Status Codes and Descriptions
-
Boiler
Status
Code
|
Boiler
Status Description
|
CN
|
Cancelled
(previously reported as “planned”)
|
CO
|
New
unit under construction
|
OP
|
Operating
(in commercial service or out of service less than 365 days)
|
OS
|
Out
of service (365 days or longer)
|
PL
|
Planned
(expected to go into commercial service within 10 years)
|
RE
|
Retired
(no longer in service and not expected to be returned to
service)
|
SB
|
Standby
(or inactive reserve); i.e., not normally used, but available
for service
|
SC
|
Cold
Standby (Reserve); deactivated (usually requires 3 to 6 months
to reactivate)
|
TS
|
Operating
under test conditions (not in commercial service)
|
For
line 2, What
is the actual or projected in-service date for this boiler?
Enter the month during which the boiler came into service or is
expected to come into service. The
month-year date should be entered as follows: August 1959 as
08-1959. If the month is unknown, use the month of June.
For
line 3, What
is the actual or projected retirement date for this boiler?
Enter the month during whicht the boiler was retired or is
expected to be retired. The
month-year date should be entered as follows: August 1959 as
08-1959. If the month is unknown, use the month of June.
For
line 4, What
type of boiler is this?
Enter up to three of the firing codes from Table 18.
Table
18. Boiler Firing Type Code and Description
-
Boiler
Type Code
|
Boiler
Type Description
|
CB
|
Cell
Burner
|
CY
|
Cyclone
Firing
|
DB
|
Duct
Burner
|
FB
|
Fluidized
Bed Firing (Circulating Fluidized Bed, Bubbling Fluidized Bed)
|
SS
|
Stoker
(Spreader, Vibrating Gate, Slinger)
|
TF
|
Tangential
Firing / Concentric Firing / Corner Firing
|
VF
|
Vertical
Firing / Arch Firing
|
WF
|
Wall
Fired (Opposed Wall, Rear Wall, Front Wall, Side Wall)
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
lines
5,
What
is the maximum continuous steam flow at 100 percent load for this
boiler?
Enter the maxium, design steam flow for the boiler at 100 percent
load in 1000 pounds per hour.
For
line 6, What
is the design firing rate at the maximum continuous steam flow
for coal and petroleum coke?
Enter the design firing rate data for burning coal and petroleum
coke to the nearest 0.1 tons per hour. Do not enter firing rate
data for startup or flame stabilization fuels. For waste-heat
boilers with auxiliary firing, enter the firing rate for
auxiliary firing.
For
line 7, What
is the design firing rate at the maximum continuous steam flow
for petroleum liquids?
Enter the design firing rate data for burning petroleum liquids
to the nearest 0.1 barrels per hour. Do not enter firing rate
data for startup or flame stabilization fuels. For waste-heat
boilers with auxiliary firing, enter the firing rate for
auxiliary firing.
For
line 8, What
is the design firing rate at the maximum continuous steam flow
for natural gas?
Enter the design firing rate data for burning natural gas to the
nearest 0.1 thousand cubic feet per hour. Do not enter firing
rate data for startup or flame stabilization fuels. For
waste-heat boilers with auxiliary firing, enter the firing rate
for auxiliary firing.
For
line 9, What
is the design firing rate at the maximum continuous steam flow
for energy sources other than coal, petroleum or natural gas?
Enter the design firing rate data for burning any other primary
fuel other than coal, petroleum or natural gas. Do not enter
firing rate data for startup or flame stabilization fuels. For
waste-heat boilers with auxiliary firing, enter the firing rate
for auxiliary firing. Specify the primary fuel (use codes from
Table 28) for which value is provided along with related
measurement unit in SCHEDULE 7.
For
line 10,
What is the design waste-heat input rate at maximum continuous
steam flow for this boiler?
If the boiler receives
all or a substantial portion of its energy input from the
noncombustible exhaust gases of a separate fuel-burning process,
enter the design waste-heat input rate as measured in million Btu
per hour at maximum continuous steam flow.
For
line 11, What
fuels are used by this boiler in order of predominance?
Enter the fuels used by this boiler in order of predominance.
Select energy source codes from Table 28 in the instructions in
order of predominance based on Btu.
For
line 12, What
is the turndown ratio for this boiler?
Calculate (to nearest 0.1) the turndown ratio for the boiler as
the ratio of the boiler’s maximum output to its minimum
output.
For
line 13,
What is the efficiency of this boiler when it is burning the
reported primary fuel at 100 percent load? Enter
the efficiency of the boiler when burning the reported primary
fuel at 100 percent load.
For
line 14,
What is the efficiency of this boiler when it is burning reported
primary fuel at 50 percent load? Enter
the efficiency of the boiler when burning the reported primary
fuel at 50 percent load.
For
line
15, What
is the total air flow (including excess air) at 100 percent load?
Report the total air flow (including excess air) at 100 percent
load. Report air flow at standard temperature and pressure (i.e.,
68 degrees Fahrenheit and one atmosphere pressure).
For
line 16, Does
the boiler have a wet bottom or a dry bottom?
Indicate whether the boiler has a wet bottom or dry bottom.
Report only for coal-capable boilers. Wet
Bottom
is defined as having slag tanks installed at the furnace’s
throat to contain and remove molten ash from the furnace. Dry
Bottom
is defined as having no slag tanks installed at the furnace’s
throat so bottom ash drops through throat to bottom ash water
hoppers.
For
line 17, Is
the boiler capable of fly ash re-injection?
Indicate whether the boiler is capable of re-injecting fly ash.
SCHEDULE
6, PART D. COOLING SYSTEM INFORMATION – DESIGN PARAMETERS
Complete
SCHEDULE 6, PART D for plants with a total steam-electric
nameplate capacity of 100 MW or greater consisting of:
Combustible
fueled steam-electric generators, including combined cycle steam
generators with duct firing;
Combined
cycle steam-electric generators without duct firing;
Nuclear
generators; or
Solar
thermal units using a steam cycle.
Complete
one SCHEDULE 6 PART D for each unique Cooling system ID as
reported on SCHEDULE 6 PART A, Line 1, Row 3.
For
line 1, What
is this identification code of the cooling system?
Enter the cooling system’s identification code commonly
used by plant management to refer to this cooling system. Cooling
system identification should be the same identification as
entered on SCHEDULE 6, PART A, Line 1, Row 3 and as reported on
other EIA forms. This
identification code is restricted to six characters and cannot be
changed once provided to EIA.
For
line 2, What
was the status of this cooling system as of December 31 of the
reporting year? Select
from the cooling system’s status codes in Table 19.
Table
19. Cooling System Status Codes and Descriptions
-
Cooling
System Status Code
|
Cooling
System Status Description
|
CN
|
Cancelled
(previously reported as “planned”)
|
CO
|
New
unit under construction
|
OP
|
Operating
(in commercial service or out of service less than 365 days)
|
OS
|
Out
of service (365 days or longer)
|
PL
|
Planned
(expected to go into commercial service within 10 years)
|
RE
|
Retired
(no longer in service and not expected to be returned to
service)
|
SB
|
Standby
(or inactive reserve); i.e., not normally used, but available
for service)
|
SC
|
Cold
Standby (Reserve); deactivated (usually requires 3 to 6 months
to reactivate)
|
TS
|
Operating
under test conditions (not in commercial service)
|
For
line 3, What
is the actual or projected in-service date of commercial
operation for this cooling system? Enter
either the date on which the cooling system began commercial
operation or the date on which the system is expected to begin
commercial operation.
For
line 4a, What
type of cooling system is this?
Select up to four types from the cooling system type codes in
Table 20 that reflect that components of the cooling system.
If
the plant has a downstream helper tower that is associated with
all boilers at a plant instead of any particular boiler or
combination of boilers, treat it as a distinct cooling system and
select “HT” from the list of codes.
Table
20. Cooling System Type Codes and Descriptions
-
Cooling
System Type Code
|
Cooling
System Type Description
|
DC
|
Dry
(air) cooling system
|
HRC
|
Hybrid:
cooling pond(s) or canal(s) with dry cooling
|
HRF
|
Hybrid:
forced draft cooling tower(s) with dry cooling
|
HRI
|
Hybrid:
induced draft cooling tower(s) with dry cooling
|
OC
|
Once
through with cooling pond(s)
|
ON
|
Once
through without cooling pond(s)
|
RC
|
Recirculating
with cooling pond(s) or canal(s)
|
RF
|
Recirculating
with forced draft cooling tower(s)
|
RI
|
Recirculating
with induced draft cooling tower(s)
|
RN
|
Recirculating
with natural draft cooling tower(s)
|
HT
|
Helper
Tower
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 4b, If
this is a hybrid cooling system, what percent of the cooling load
is served by dry cooling components? In
the case of a hybrid cooling system, indicate the percent of total
cooling load that is served by any dry cooling components.
For
line 5, What
is the name of the water source for this cooling system?
Provide the name of the river, lake, or other water source for
the cooling system if different than the water source listed on
question 6 of SCHEDULE 2.
For
line 6, What
is the name of the cooling system’s discharge body of
water?
If the discharge body of water is different than the source of
the cooling water, enter the name of the water.
For
line 7, What
is the cooling water source code for this system? Select
the appropriate cooling water source from Table 21:
Table
21. Cooling Water Source Code and Description
-
Cooling
Water Source Code
|
Cooling
Water Source Description
|
SW
|
Surface
Water (ex: river, canal, bay)
|
GW
|
Ground
Water (ex: aquifer, well)
|
PD
|
Plant
Discharge Water (ex: wastewater treatment plant discharge)
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 8, What
type of cooling water is used for this system?
Select the type of cooling water used by the cooling system from
Table 22.
Table
22. Cooling Water Type Codes and Description
-
Type
of Cooling Water Code
|
Type
of Cooling Water Description
|
BR
|
Brackish
Water
|
FR
|
Fresh
Water
|
BE
|
Reclaimed
Water (ex: treated wastewater effluent)
|
SA
|
Saline
Water
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 9, What
is the design maximum cooling water flow rate at 100 percent load
at intake?
Enter the design maximum flow rate (gallons per minute) for the
cooling system when operating at 100 percent load.
For
line 10, What
is the actual or projected in-service date for the chlorine
discharge control structures and equipment?
Enter either the date on which the chlorine discharge control
structures and equipment began commercial operation or the date
on which the chlorine discharge control structures and equipment
are expected to begin commercial operation, if applicable.
For
lines 11, What
is the actual or projected in-service date for the cooling
pond(s)? Enter
either the date on which the cooling pond(s) began commercial
operation or the date on which cooling pond(s) is expected to
begin commercial operation, if applicable. A cooling
pond
is a natural or man-made body of water that is used for
dissipating waste heat from power plants.
For
line 12 What
is the total surface area for the cooling pond(s)?
Enter the total surface area for the cooling pond(s), if
applicable. A
cooling
pond
is a natural or man-made body of water that is used for
dissipating waste heat from power plants.
For
line 13,
What is the total volume of the cooling ponds? Enter
the total volume of the cooling pond(s), if applicable. A
cooling
pond
is a natural or man-made body of water that is used for
dissipating waste heat from power plants.
For
line 14, What
is the actual or projected in-service date for cooling towers?
Enter either the date on which the cooling tower(s) began
commercial operation or the date on which the cooling tower(s) is
expected to begin commercial operation, if applicable.
For
line 15, What
types of cooling towers are at this plant or are planned to be at
this plant?
Enter all tower types that apply from the cooling tower codes in
Table 23.
Table
23. Types of Towers
-
Tower
Type Code
|
Tower
Type Description
|
MD
|
Mechanical
draft, dry process
|
MW
|
Mechanical
draft, wet process
|
ND
|
Natural
draft, dry process
|
NW
|
Natural
draft, wet process
|
WD
|
Combination
wet and dry processes
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 16 What
is the design rate of water flow at 100 percent load for the
cooling towers? Enter
the design flow rate (gallons per minute) for the cooling tower
when operating at 100 percent generator load in gallons per
minute.
For
line 17, What
is the maximum power requirement for the cooling towers at 100
percent load? Enter
the maximum design power requirement for the cooling tower when
operating at 100 percent generator load in megawatts.
For
line 18, What
is the total installed cost for this cooling system? Enter
the total nominal installed cost for the existing system or the
anticipated cost to bring a planned system into commercial
operation in thousands of dollars. Installed cost should include
the cost of all major modifications. The Total
System Cost
should include amounts for items such as pumps, piping, canals,
ducts, intake and outlet structures, dams and dikes, reservoirs,
cooling towers, and appurtenant equipment.
For
line 19, What
is the installed cost for the cooling ponds? Enter
the nominal installed cost for the existing ponds or the
anticipated cost to bring a planned pond into commercial
operation in thousands of dollars. Installed cost should include
the cost of all major modifications.
For
line 20, What
is the installed cost for the cooling towers? Enter
the nominal installed cost for the existing towers or the
anticipated cost to bring a planned tower into commercial
operation in thousands of dollars. Installed cost should include
the cost of all major modifications. A major modification is any
physical change which results in a change in the amount of air or
water pollutants or which results in a different pollutant being
emitted.
For
line 21, What
is the installed cost for the chlorine discharge control
structures and equipment? Enter
in thousands of dollars, the nominal installed cost for the
existing chlorine
discharge control structures and equipment
or the anticipated cost to bring planned chlorine
discharge control structures and equipment into
commercial operation. Installed cost should include the cost of
all major modifications. A major modification is any physical
change which results in a change in the amount of air or water
pollutants or which results in a different pollutant being
emitted.
For
line 22a, What
is the maximum distance of water intake from shore?
Enter the maximum distance of the water intake from the shore, in
feet.
For
line 22b, What
is the maximum distance of the water outlet from shore? Enter
the maximum distance of the water outlet from the shore, in feet
(not required for recirculating systems).
For
lines 23a, What
is the average distance of the water intake point below the
surface of the water? Enter
the average distance of the water intake
point
below the surface of the water, in feet.
For
line 23b, What
is the average distance of the water outlet point below the
surface of the water? Enter
the average distance of the water outlet points below the surface
of the water, in feet (not required for recirculating systems).
SCHEDULE
6, PART E. FLUE GAS PARTICULATE COLLECTOR INFORMATION
Complete
SCHEDULE 6, Part E for plants
where the sum of the nameplate capacity of the steam-electric
generators, including duct fired steam components of combined
cycle units, sum to 10 MW or more.
Complete
one SCHEDULE 6 PART E for each unique Particulate Matter Control
system ID as reported on SCHEDULE 6 PART A, Line 1, Row 4.
For
line 1, What
is the identification code for the equipment controlling
particulate matter? Enter
the particulate matter control identification code
as
it was reported on SCHEDULE 6, Part A, Line 1, Row 4 (Associated
Particulate Matter Control Systems).
For
line 2, What
type of flue gas particulate matter control is this?
Select the flue gas particulate matter control type from Table
24. These should be the same equipment type entered on SCHEDULE
6, PART A, Line 2, COLUMN A for Particulate Matter Control.
Enter up to three codes. If more than three exist, enter others
in SCHEDULE 7, COMMENTS.
Table
24. Flue Gas Particulate Matter Control
-
Flue
Gas Particulate Matter Control
|
Flue
Gas Particulate Matter Control Description
|
BS
|
Baghouse
(fabric filter), shake and deflate
|
BP
|
Baghouse
(fabric filter), pulse
|
BR
|
Baghouse
(fabric filter), reverse air
|
EC
|
Electrostatic
precipitator, cold side, with flue gas conditioning
|
EH
|
Electrostatic
precipitator, hot side, with flue gas conditioning
|
EK
|
Electrostatic
precipitator, cold side, without flue gas conditioning
|
EW
|
Electrostatic
precipitator, hot side, without flue gas conditioning
|
MC
|
Multiple
cyclone
|
SC
|
Single
cyclone
|
JB
|
Jet
bubbling reactor (wet) scrubber
|
MA
|
Mechanically
aided type (wet) scrubber
|
PA
|
Packed
type (wet) scrubber
|
SP
|
Spray
type (wet) scrubber
|
TR
|
Tray
type (wet) scrubber
|
VE
|
Venturi
type (wet) scrubber
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 3, What
is the design fuel specification for ash when burning coal or
petroleum coke?
Enter the design fuel specification for ash (as burned) to the
nearest 0.1 percent of weight, when burning coal or petroleum
coke, if applicable.
For
line 4, What
is the design fuel specification for ash when burning petroleum
liquids?
Enter the design fuel specification for ash (as burned) to the
nearest 0.1 percent of weight, when burning petroleum liquids, if
applicable.
For
line 5, What
is the design fuel specification for sulfur when burning coal or
petroleum coke?
Enter the design fuel specification for sulfur (as burned) to the
nearest 0.1 percent of weight, when burning coal or petroleum
coke, if applicable.
For
line 6, What
is the design fuel specification for sulfur when burning
petroleum liquids?
Enter design fuel specification for sulfur (as burned) to the
nearest 0.1 percent of weight, when burning petroleum liquids, if
applicable.
For
line 7,
What
is the design collection efficiency for this flue gas particulate
collector at 100 percent load?
Enter the design collection efficiency (to nearest 0.1 percent)
of the equipment at 100 percent generator load.
For
line 8, What
is the design particulate emission rate for this collector at 100
percent load?
Enter the design particulate emission rate in pounds per hour at
100 percent generator load.
For
line 9, What
is the particulate collector gas exit rate at 100 percent load?
Enter equipment’s gas exit rate in cubic feet per minute at
100 percent generator load.
For
line 10,
What
is the particulate collector gas exit temperature?
Enter the equipment’s gas exit temperature in degrees
Fahrenheit.
SCHEDULE
6, PART F. FLUE GAS DESULFURIZATION UNIT INFORMATION (INCLUDES
COMBUSTION TECHNOLOGIES)
Complete
SCHEDULE 6, Part F for plants
where the sum of the nameplate capacity of the steam-electric
generators, including duct fired steam components of combined
cycle units, sum to 10 MW or more.
Complete
one SCHEDULE 6 PART F for each unique Sulfur Dioxide Control
System ID as reported on SCHEDULE 6 PART A, Line 1, Row 5.
For
line 1, What
is the identification code for the equipment associated with this
sulfur dioxide control?
Enter the sulfur dioxide control identification code as reported
on SCHEDULE 6, PART A, Line 1, Row 5 (Associated Sulfur Dioxide
Control Systems)
For
line 2, What
type of sulfur dioxide control is this?
Select the sulfur dioxide control code from Table 25. Enter up to
three for each Sulfur Dioxide Control Identification Code.
Table
25. Sulfur Dioxide Control Codes and Descriptions
-
Sulfur
Dioxide Control Codes
|
Sulfur
Dioxide Control Description
|
JB
|
Jet
bubbling reactor (wet) scrubber
|
MA
|
Mechanically
aided type (wet) scrubber
|
PA
|
Packed
type (wet) scrubber
|
SP
|
Spray
type (wet) scrubber
|
TR
|
Tray
type (wet) scrubber
|
VE
|
Venturi
type (wet) scrubber
|
CD
|
Circulating
dry scrubber
|
SD
|
Spray
dryer type / dry FGD / semi-dry FGD
|
DSI
|
Dry
sorbent (powder) injection type
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 3, What
type(s) of sorbent(s) is used by this unit?
Select up to four sorbent codes from Table 26.
Table
26. Sorbent Type Codes and Descriptions
-
Sorbent
Type Code
|
Type
of Sorbent
|
AF
|
Alkaline
fly ash
|
AM
|
Ammonia
|
CSH
|
Caustic
Sodium hydroxide
|
DB
|
Dibasic
acid assisted
|
LI
|
Lime
/ slacked lime / hydrated lime
|
LS
|
Limestone
/ dolomitic limestone / calcium carbonate
|
MO
|
Magnesium
oxide
|
SA
|
Soda
ash / Sodium bicarbonate / Sodium carbonate / Sodium formate /
Soda liquid
|
TR
|
Trona
|
WT
|
Water
/ Treated wastewater (select only if no other sorbent is used)
|
OT
|
Other
(specify in SCHEDULE 7)
|
For
line 4, Is
there any salable byproduct recovery?
Enter “Yes” if there is any salable byproduct
recovery. Otherwise, enter “No.”
For
line 5, What
are the annual pond and land fill requirements? Report
the annual pond and land fill requirements in acre feet per year.
For
line 6, Is
the sludge pond lined? Indicate
whether the sludge pond is lined.
For
line 7, Can
flue gas bypass the flue gas desulfurization unit? Indicate
whether the flue gas can bypass the FGD unit.
For
line 8, What
is the design specification for ash when burning coal or
petroleum coke?
Enter the design fuel specifications for ash (as burned) to the
nearest 0.1 percent of weight, when burning coal or petroleum
coke, if applicable.
For
line 9,
What is the design specification for sulfur when burning coal or
petroleum coke?
Enter the design fuel specifications for sulfur (as burned) to
the nearest 0.1 percent of weight, when burning coal or petroleum
coke, if applicable.
For
line 10, What
is the total number of flue gas desulfurization unit scrubber
trains or modules? Enter
the total number of flue gas desulfurization unit scrubber trains
or modules operated.
For
line 11, How
many flue gas desulfurization unit scrubber trains or modules are
operated at 100 percent load? Enter
how many flue gas desulfurization unit scrubber trains or modules
are operated at 100 percent load.
For
line
12, What
is this unit’s design removal efficiency for sulfur dioxide
when operating at 100 percent load?
Report the design removal efficiency to nearest 0.1 percent by
weight of gases removed from the flue gas when operating at 100
percent generator load.
For
line 13, What
is the design sulfur dioxide emission rate for this unit when
operating at 100 percent load? Report
the design sulfur dioxide emission rate in pounds per hour when
operating at 100 percent generator load.
For
line 14, What
is the flue gas exit rate for this unit? Report
the flue gas exit rate in actual cubic feet per minute when
operating at 100 percent generator load.
For
line 15, What
is this unit’s flue gas exit temperature? Report
the flue gas exit temperature in degrees Fahrenheit when
operating at 100 percent generator load.
For
line 16, What
percentage of flue gas enters the flue gas desulfurization unit
when operating at 100 percent load? Enter
the percentage of flue gas entering this FGD unit at a percent of
total gas when operating at 100 percent generator load.
For
line 17, What
are the installed or anticipated costs of all FGD structures and
equipment, excluding land?
Enter the nominal installed costs for the existing flue gas
desulfurization unit or the anticipated costs, in thousand
dollars, to bring a planned flue gas desulfurization unit into
commercial operation. Installed cost should include the cost of
all major modifications. A major modification is any physical
change which results in a change in the amount of air or water
pollutants or which results in a different pollutant being
emitted.
For
line 18, What
are the installed costs of the sludge transport and disposal
system? Enter
the nominal installed costs for the sludge transport and disposal
system, or the anticipated costs, in thousand dollars, to bring a
planned sludge transport and disposal system into commercial
operation. Installed cost should include the cost of all major
modifications. A major modification is any physical change which
results in a change in the amount of air or water pollutants or
which results in a different pollutant being emitted.
For
line 19, What
other installed costs are there pertaining to the installation of
the FGD unit?
Enter
any other nominal installed costs, in thousand dollars,
pertaining to the installation of the flue gas desulfurization
unit, or any other costs related to bringing a planned flue gas
desulfurization unit into commercial operation. Installed cost
should include the cost of all major modifications. A major
modification is any physical change which results in a change in
the amount of air or water pollutants or which results in a
different pollutant being emitted.
For
20, What
are the total installed costs of the FGD unit? Enter
the total nominal installed cost, in thousand dollars, for the
existing flue gas desulfurization unit or the total anticipated
costs to bring a planned flue gas desulfurization unit into
commercial operation. Installed cost should include the cost of
all major modifications. A major modification is any physical
change which results in a change in the amount of air or water
pollutants or which results in a different pollutant being
emitted. This total will be the sum of lines 17, 18, and 19.
SCHEDULE
6, PART G. STACK AND FLUE INFORMATION – DESIGN PARAMETERS
Complete
SCHEDULE 6, Part G for plants
where the sum of the nameplate capacity of the steam-electric
generators, including duct fired steam components of combined
cycle units, sum to 100 MW or more.
NOTE:
A stack
is defined as a vertical structure containing one or more flues
used to discharge products of combustion into the atmosphere. A
flue
is defined as an enclosed passageway within a stack for directing
products of combustion to the atmosphere. If the stack has a
single flue, use the stack identification for the flue
identification
Complete
one SCHEDULE 6 PART G for each Stack ID or Flue ID reported on
SCHEDULE 6 PART A, Line 1, Row 8.
For
line 1, What
is this stack or flue equipment’s identification code?
Enter the identification code for each stack or flue as entered
on SCHEDULE 6 PART A, Line 1, Row 8.
For
line
2, What
is the actual or projected in-service date for this stack or
flue?
Enter either the date on which the stack or flue began commercial
operation or the date (MM/YYYY) on which the stack
or flue are expected
to begin commercial operation.
For
line
3, What
was the status of this stack or flue as of December 31 of the
reporting year?
Select one from the following equipment status codes from Table
27.
Table
27. Stack Status Codes and Description
-
Stack
Status
Code
|
Stack
Status Code Description
|
CN
|
Cancelled
(previously reported as “planned”)
|
CO
|
New
unit under construction
|
OP
|
Operating
(in commercial service or out of service within 365 days)
|
OS
|
Out
of service (365 days or longer)
|
PL
|
Planned
(on order or expected to go into commercial service within 10
years)
|
RE
|
Retired
(no longer in service and not expected to be returned to
service)
|
SB
|
Standby
(or inactive reserve, i.e., not normally used, but available
for service)
|
SC
|
Cold
Standby (Reserve); deactivated. Usually requires 3 to 6 months
to reactivate
|
TS
|
Operating
under test conditions (not in commercial service).
|
For
line 4, What
is this stack’s height at the top, as measured from the
ground?
Enter the height of the stack in feet as measured from the ground
by the plant.
For
line 5, What
is the cross-sectional area at the top of this stack?
Enter the cross-sectional area at the top of the stack as
measured in square feet.
For
line
6, What
is the design flue gas exit rate at the top of the stack at 100
percent load? Enter
the design flue gas exit rate at the top of the stack when
operating at 100 percent load as measured in actual cubic feet
per minute. The rate should be approximately equal to the
cross-sectional area of the flue multiplied by the velocity and
then multiplied by 60.
For
line 7, What
is the design flue gas exit rate at the top of the stack at 50
percent load?
Enter the design flue gas exit rate at the top of the stack when
operating at 50 percent load as measured in actual cubic feet per
minute. The rate should be approximately equal to the
cross-sectional area of the flue multiplied by the velocity and
then multiplied by 60.
For
line 8, What
is the design flue gas exit temperature at the top of the stack
at 100 percent load? Enter
the design flue gas exit temperature in degrees Fahrenheit at the
top of the stack when operating at 100 percent load.
For
line 9, What
is the design flue gas exit temperature at the top of the stack
at 50 percent load? Enter
the design flue gas exit temperature in degrees Fahrenheit at the
top of the stack when operating at 50 percent load.
For
line 10, What
is the design flue gas velocity at the top of the stack at 100
percent load? Enter
the design flue gas exit velocity in feet per second at the top
of the stack when operating at 100 percent load.
For
line 11, What
is the design flue gas velocity at the top of the stack at 50
percent load?
Enter the design flue gas exit velocity in feet per second at the
top of the stack when operating at 50 percent load.
For
line 12,
What is the average flue gas exit temperature for the summer
season?
Enter the seasonal average flue gas exit temperature in degrees
Fahrenheit, based on the arithmetic mean of measurements during
operating hours. Summer season includes June, July, and August.
For
line 13, What
is the average flue gas exit temperature for the winter season?
Enter
the seasonal average flue gas exit temperature in degrees
Fahrenheit, based on the arithmetic mean of measurements during
operating hours. Winter season includes December, January, and
February (for example, when reporting for year 2013, use December
2012, January 2013 and February 2013).
For
line 14, Were
the average flue gas exit temperatures measures or estimated?
Indicate whether the flue gas exit temperatures used to calculate
the mean values reported on Lines 13 and 14 were measured or
estimated.
SCHEDULE
7. COMMENTS
This
schedule provides additional space for comments. Please identify
schedule, part, and question and include identifying information
(e.g., plant code, boiler id, generator id) for each comment. Use
additional pages, if necessary.
|
