Electric Power Surveys

U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC GENERATOR
Energy Information Administration
OMB No. 1905-0129
REPORT
Form EIA-860 (2007)
Approval Expires:
Form EIA-860 collects data on the status of existing electric generating plants and associated
PURPOSE
equipment (including generators, boilers, cooling systems and flue gas desulfurization systems) in
the United States, and those scheduled for initial commercial operation within 5 years of the filing of
this report. The data from this form appear in several EIA publications; including the Electric Power
Monthly, Electric Power Annual, and the Annual Energy Review. The data collected on this form are
used to monitor the current status and trends of the electric power industry and to evaluate the future
of the industry.
REQUIRED
RESPONDENTS

All existing plants and proposed (5-year plans) plants that: 1) have a total generator nameplate
capacity (sum for generators at a single site) of 1 MW or greater; and 2) where the generator(s), or
the facility in which the generator(s) resides, is connected to the local or regional electric power grid
and has the ability to draw power from the grid or deliver power to the grid are reported on Form
EIA-860.
In the case of generators located in Alaska and Hawaii which are not a part of the North American
interconnected grid, generators that are connected to a “public grid,” meaning a local or regional
transmission or distribution system that supplies power to the public, must be reported on Form EIA860.
The operator or planned operator of jointly-owned plants should be the only respondent for those
plants.

RESPONSE DUE
DATE

Submit the completed Form EIA-860 directly to the EIA annually on or before February 15.

METHODS OF
FILING
RESPONSE

Submit your data electronically using EIA’s secure Internet Data Collection system (IDC). This
system uses security protocols to protect information against unauthorized access during
transmission.
•

If you have not registered with EIA’s Single Sign-On system, send an e-mail requesting
assistance to: [email protected]

•

If you have registered with Single Sign-On, log on at
https://signon.eia.doe.gov/ssoserver/login

•

If you are having a technical problem with logging into the IDC or using the IDC contact the
IDC Help Center for further information. Contact the Help Desk at:
E-mail: [email protected]
Phone: 202-586-9595

•

If you need an alternate means of filing your response, contact the Help Desk.

Retain a completed copy of this form for your files.
CONTACTS

Internet System Questions: For questions related to the Internet Data Collection system, see the
help contact information immediately above.
Data Questions: For questions about the data requested on Form EIA-860, contact either Survey
Manager:
Kenneth McClevey
Telephone Number: (202) 586-4258
FAX Number: (202) 287-1960
E-mail: [email protected]

1

Glenn McGrath
Telephone Number: (202) 586-4325
FAX Number: (202) 287-1960
E-mail: [email protected]

U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC GENERATOR
Energy Information Administration
OMB No. 1905-0129
REPORT
Form EIA-860 (2007)
Approval Expires:
1. Verify all EIA provided information. If incorrect, revise the incorrect entry and provide the
GENERAL
correct information. State codes are two-letter U.S. Postal Service abbreviation. Provide any
INSTRUCTIONS
missing information. If filing a paper copy of this form, typed or legible handwritten entries are
acceptable. Allow the original entry to remain readable. See more specific instructions for
correcting data in SCHEDULE 2, “Power Plant Data,” and SCHEDULE 3. “Generator
Information.” If no corrections are needed to the pre-entered data and there are no missing
data, check “No Change Needed” for plant, generator or boiler information, as applicable.
2. Check all data for consistency with the same or related data that appear in more than one
schedule of this or other forms or reports submitted to EIA. Explain any inconsistencies under
SCHEDULE 7,COMMENTS.
3. For planned power plants and/or planned equipment, use planning data to complete the form.
4. Report in whole numbers (i.e., no decimal points), except where explicitly instructed to report
otherwise.
5. Indicate negative amounts by using a minus sign before the number.
6. Report date information as a two-digit month and four-digit year, e.g., “11 - 1980.”
7. Furnish the requested information to reflect the status of your current or planned operations as
of the beginning of the reporting calendar year. If the company no longer operated a
specific power plant as of December 31, report the name of the operator as of December
31 along with related contact information (including contact person’s name, telephone
number and e-mail address, if known) in SCHEDULE 7, "COMMENTS.” Do not complete
the form for that power plant.
8. To request additional blank schedules contact the Energy Information Administration using the
contact information on page 1, or download the form from
http://www.eia.doe.gov/cneaf/electricity/page/forms.html.
9. For definitions of terms, refer to the Energy Information Administration glossary at
http://www.eia.doe.gov/glossary/index.html.
ITEM-BY-ITEM
INSTRUCTIONS

SCHEDULE 1. IDENTIFICATION
1. Survey Contact: Verify contact name, title, address, telephone number, fax number, and e-mail
address.
2. Supervisor of Contact Person for Survey: Verify the contact’s supervisor’s name, title,
address, telephone number, Fax number and e-mail address.
3. Report For: Verify all information, including operator name, operator identification number, and
year for which data are being reported. These fields cannot be revised online. Contact EIA if
corrections are needed.
If any of the above information is incorrect, revise the incorrect entry and provide the correct
information. Provide any missing information.
Operator and Preparer Information:
4. For Legal Name of Operator, verify the name. The operator of the power plant is the electric
power producer owner/joint owner of the plant or a subsidiary of the electric power producer who
has a working interest in the plant and who is responsible for making the strategic decisions
related to the management and physical operation of the power plant. The operator entity may
also be an electric power producer or a subsidiary of an electric power producer who operates a
power plant that is wholly owned by another electric power producer. Operator excludes
energy services companies under contract to operate the plant for the electric power producer;
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U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

in these cases, the electric power producer should be reported as the legal operator.

5. For Current Address of Principal Business Office of Plant Operator, verify the principal
name and address to which this form should be mailed. Include an attention line, room number,
building designation, etc., to facilitate the future handling and processing of this form.
6. For Preparer's Legal Name, verify the name to which this form should be mailed if different
from Legal Name of Operator.
7. For Current Address of Preparer's Office, verify the address to which this form should be
mailed. Include an attention line, room number, building designation, etc., to facilitate the future
handling and processing of this form, if preparer’s address is different from the address of the
Legal Name of Operator .
8. For Is the Operator an Electric Utility; check “Yes” if so. Otherwise check “No.”
SCHEDULE 2. POWER PLANT DATA
Verify or complete one section for each existing power plant and each power plant planned for initial
commercial operation within 5 years. To report a new plant or a plant that is not already identified,
use a blank SCHEDULE 2.
1. For line 1, Plant Name and EIA Plant Code, enter the name of the power plant, and enter or
verify the EIA Plant Code for the power plant. Each power plant must be uniquely identified.
The type of plant does not need to be a part of the plant name, e.g., “Plant x Hydro” needs to
be reported as “Plant x” only. The type of plant is recognized by the prime mover code(s)
reported in SCHEDULE 3. Generator Information. There may be more than one prime mover
type associated with a single plant name (single site). Enter “NA 1,” “NA 2,” etc., for planned
facilities that have no name(s).
2. For line 2, Street Address, enter or verify the street address of the power plant.
3. For line 3, County Name and City Name, enter the county and city in which the plant is (will
be) located. Enter “NA” for planned facilities that have not been sited. If a mobile power plant,
indicate with a note in SCHEDULE 7, COMMENTS.
4. For line 4, State, enter the two-letter U.S. Postal Service abbreviation for the State in which the
plant is located. Enter “NA” for planned facilities for which the State has not been determined.
If the State is “NA,” the county name must be “NA.”
5. For line 5, Zip Code, enter the zip code of the plant. Provide, at a minimum, the five-digit zip
code; however, the nine-digit code is preferred.
6. For line 6, Latitude and Longitude, enter the latitude and longitude of the plant in degrees,
minutes, and seconds.
7. For line 7, Enter Datum for Latitude and Longitude, if Known; Otherwise Enter “UNK”:
The longitude and latitude measurement for a location depends in part on the coordinate
system (or “datum”) the measurement is keyed to. “Datum systems” used in the United States,
include the North American Datum 1927 (NAD27), North American Datum 1983 (NAD83) and
World Geodetic Survey 1984 (WGS84).
If you know the datum system for the plant longitude and latitude, enter the system name (e.g.,
NAD83) on line 7. If you do not know the datum system used, enter UNK.
(For background information on datum and their uses, see: http://biology.usgs.gov/index.html).
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U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

8. For line 8, NERC Region, enter the NERC region in which the plant is located.
9. For line 9, Name of Water Source, enter the name of the principal source from which cooling
water for thermal-electric plants and water for generating power for hydroelectric plants is
directly obtained. If more than one water source is (will be) used, enter the name(s) of the
other sources of water in SCHEDULE 7, COMMENTS. Enter “Municipality” if the water is from
a municipality. Enter “wells” if water is from wells. Enter “NA” for planned facilities for which the
water source is not known.
10. For line 10, Steam Plant Status, and line 11, Steam Plant Type, verify the appropriate status
and type for completing Schedule 6, Boiler information. If either is incorrect, contact EIA.
11. For line 12, Primary Purpose of the Plant, enter the North American Industry Classification
System (NAICS) code that best describes the primary purpose of the reporting plant. Electric
utility plants will generally use code 22. Independent power producers whose sole or primary
business is the sale of electricity will also generally use code 22. For industrial and commercial
generators whose primary business is an industrial or commercial process (e.g., paper mills,
refineries, chemical plants, etc.), use Table 2 in these instructions to determine the code.
12. Line 13, Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying
Facility (QF) Cogenerator Status? Check “Yes” or “No”; if “Yes” provide all QF docket
numbers granted to the facility.
13. Line 14, Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying
Facility (QF) Small Power Producer Status? Check “Yes” or “No”; if “Yes” provide all QF
docket numbers granted to the facility.
14. Line 15, Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying
Facility (QF) Exempt Wholesale Generator Status? Check “Yes” or “No”; if “Yes” provide all
QF docket numbers granted to the facility.
15. For line 16, Owner of Transmission/Distribution Facilities, enter the name of the owner of
the transmission or distribution facilities to which the plant is interconnected and the grid
voltage at the point of interconnection.
SCHEDULE 3. GENERATOR INFORMATION
1. Verify or complete for each existing or planned generator. Complete one column for each
generator (up to three generators can be reported on one page) for all generators that are: (1)
in commercial operation (whether active or inactive), or (2) expected to be in commercial
operation within 5 years and are either planned, under construction, or in testing stage. Do not
report auxiliary generators.
2. To report a new generator, use a separate (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 (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
1. For line 1, Plant Name, enter the official or legal name of the power plant as reported on
SCHEDULE 2.
2. For line 2, EIA Plant Code, enter the EIA plant code as reported on SCHEDULE 2.
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U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

3. For line 3, Operator’s Generator Identification, enter the unique generator identification
commonly used by plant management. Generator identification can have a maximum of four
characters, and should be the same identification as reported on other EIA forms to be uniquely
defined within a plant.
4. For line 4, for organic-fueled steam generators, including heat recovery steam generators, enter
the identification (ID) code for each boiler that provides steam to the generator. The ID should
match those provided in SCHEDULE 6. The applicable parts of SCHEDULE 6 must be
completed for each boiler. Organic-fueled steam-electric generators include fossil-fueled and
combustible renewable-fueled generators.
5. For line 5, Prime Mover, enter one of the prime mover codes below. For combined cycle units,
a prime mover code must be entered for each generator.
Prime Mover Description

Prime Mover Code
ST
GT
IC
CA
CT
CS
CC
HY
PS
BT
PV
WT
CE
FC
OT

Steam Turbine, including nuclear, geothermal and solar steam (does not
include combined cycle).
Combustion (Gas) Turbine – Simple Cycle (includes jet engine design)
Internal Combustion Engine (diesel, piston, reciprocating)
Combined Cycle Steam Part
Combined Cycle Combustion Turbine Part (type of coal or solid must be
reported as energy source for integrated coal gasification).
Combined Cycle Single Shaft (combustion turbine and steam turbine
share a single generator)
Combined Cycle Total Unit (use only for plants/generators that are in
planning stage, for which specific generator details cannot be provided).
Hydraulic Turbine (includes turbines associated with delivery of
water by pipeline)
Hydraulic Turbine – Reversible (pumped storage)
Turbines Used in a Binary Cycle (such as used for geothermal
applications)
Photovoltaic
Wind Turbine
Compressed Air Energy Storage
Fuel Cell
Other (Describe in SCHEDULE 7, COMMENTS)

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.
6. For line 6, Unit Code (Multi-generator code), identify all generators that are operated with other
generators as a single unit. Generators operating as a single unit should have the same unit
(multi-generator code) code or four-character identifier. Identify combined cycle generators
that operate as a unit with a unique four-character identifier. All generators that operate as a
unit in combined cycle must have the same unique identifier. If generators do not operate as a
single unit, this space should be left blank.
7. For line 7, Ownership Code, identify the ownership for each generator using the following
codes: "S" for single ownership by respondent, "J" for jointly owned with another entity or "W"
for wholly owned by an entity other than respondent.
8. For line 8, Is this generator an electric utility or non-utility generator? For each generator,
check “electric utility” or non-utility. (See EIA Glossary for definition of electric utility generator.)
5

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

9. For line 9, Date of Sale, If Sold, enter the month and year of the sale of the generator (e.g., 122007), if the generator has been sold in its entirety. For changes in shares of ownership only,
with no change in operator, report in Schedule 4, OWNERSHIP OF GENERATORS OWNED
JOINTLY OR BY OTHERS. . In SCHEDULE 7, provide the legal name, business address,
contact person, phone number and e-mail address of the entity to which this generator was
sold.
10. For line 10, Can This Generator Deliver Power to the Transmission Grid?, indicate if the
generator can or cannot deliver power to the transmission grid.
11. For line 11, if the prime mover is “CA,” (combined-cycle steam), “CS” or “CC” check “Yes” if
the unit has duct-burners for supplementary firing of the turbine exhaust gas. Otherwise, check
“No.” If “Yes” SCHEDULE 6 must be completed, as applicable.
SCHEDULE 3. PART B. GENERATOR INFORMATION – EXISTING GENERATORS
1. For line 1, Generator Nameplate Capacity, report the highest value on the nameplate in
megawatts rounded to the nearest tenth. If the nameplate capacity is expressed in kilovolt
amperes (kVA), convert to kilowatts by multiplying the corresponding power factor by the kVA,
divide by 1,000 to express in megawatts to the nearest tenth. If generator nameplate capacity
is exceeded by net summer capacity, provide the reason(s) in SCHEDULE 7.
2. For line 2, Net Capacity, enter the generator's (unit's) summer and winter net capacities for the
primary energy sources. Report in megawatts, rounded to the nearest tenth. For generators
that are out of service for an extended period or on standby or have no generation during the
respective seasons, report the estimated capacities based on historical performance. For
generators that are tested as a unit, a single aggregate net summer capacity and a single
aggregate net winter capacity may be reported. For hydroelectric, report the instantaneous
capacity at maximum waterflow.
3. For line 3a, Reactive Power Output (MVAR) Corresponding to Net Summer Capacity for
generators with nameplate capacity of 10 MW or greater, based on the generator power
capability curve for the generator, enter the lagging reactive power output and the leading
reactive power output that correspond to the net summer capacity (line 2), adjusted for any
impacts of exciter limiters. A MVAR is a Mega Voltampere Reactive.
4. For line 3b, Reactive Power Output (MVAR) Corresponding to Net Winter Capacity for
generators with nameplate capacity of 10 MW or greater, based on the generator power
capability curve for the generator, enter the lagging reactive power output and the leading
reactive power output that correspond to the net winter capacity (line 2), adjusted for any
impacts of exciter limiters. A MVAR is a Mega Voltampere Reactive.
5. For line 4, Status Code, enter one of the following status codes:
Status Code
OP

SB
OA

Status Code Description
Operating - in service (commercial operation) and producing some
electricity. Includes peaking units that are run on an as needed (intermittent
or seasonal) basis.
Standby/Backup - available for service but not normally used (has little or no
generation during the year) for this reporting period.
Out of service – was not used for some or all of the reporting period but was
either returned to service on December 31 or will be returned to service in
the next calendar year.
Note: Units undergoing maintenance or repair of less than 12 months
duration and are expected to be returned to service upon completion of
maintenance or repair should be given an operating status.
6

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)
OS
RE

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

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.
Retired - no longer in service and not expected to be returned to service.

6. For line 5, Synchronized to the Grid, if the status code entered on line 4 is standby (SB)
please note if the generator is currently equipped such that, when operating, it can be
synchronized to the grid.
7. For line 6, Initial Date of Operation, enter the month and year of initial commercial operation.
8. For Line 7, Retirement Date, enter the date the generator was retired, in month and year
format.
9. For line 8, Is this generator associated with a Combined Heat and Power system (fuel
input is used to produce both electricity and useful thermal output)? check either "Yes" or
"No". If the answer is “Yes”, check either bottoming cycle or topping cycle, as applicable. In a
topping cycle system, electricity is produced first and any waste heat from that production is
used in a manufacturing process or for direct heating, and/or space heating/cooling. 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.
10. For line 9, 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. Select appropriate energy source codes from Table
1. in these instructions. 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).
11. For line 9a, if the predominant energy source for powering the generator is coal or petroleum
coke, check all types of technology and steam conditions that apply.
12. For line 10, report the Start-up and flame stabilization fuels used by the combustion unit(s)
associated with this generator.
13. For line 11, 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. Select
appropriate energy source codes from Table 1 in these instructions. 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).
14. For line 12, Other Energy Sources, enter the codes for other energy sources: 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.
Select appropriate energy source codes from Table 1 in these instructions. 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)
15. Line 13, Is this generator part of a solid fuel gasification system, check yes or no as
appropriate.
16. For line 14, If Energy Source is Wind, enter the number of turbines.
17. For line 15, Tested Heat Rate, enter the tested heat rate under full load conditions for all
generators that derive their energy from combustion or fission of fuel. Report the heat rate as
the fuel consumed in British thermal units (Btus) necessary to generate one net kilowatthour of
electric energy. Report the tested heat rate under full load, not 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
7

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

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, explain in SCHEDULE 7, COMMENTS.
18. For line 16, Fuel Used for Heat Rate Test, enter the fuel code or “M” for multiple fuels. Select
appropriate energy source codes from Table 1in these instructions. 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).
Proposed Changes to Existing Generators (within the next 5 years)
19. For line 17a, indicate whether there are any planned capacity up-rates/de-rates, re-powering,
other modifications, or generator retirements scheduled for the next 5 years.
20. For line 17b, enter the increase in capacity expected to be realized from the modification to the
equipment. Enter the planned effective date (MM-YYYY) that the generator is scheduled to
enter operation after the modification.
21. For line 17c, enter the decrease in capacity expected to be realized from the modification to the
equipment. Enter the planned effective date (MM-YYYY) that the generator is scheduled to
enter operation after the modification.
22. For line 17d, if a re-powering of the generator is planned, enter the new prime mover and new
energy source, as well as the planned effective date (MM-YYYY) that the generator is
scheduled to enter operation after the re-powering is complete.
23. For line 17e, enter the planned effective date (MM-YYYY) that the generator is scheduled to
enter commercial operation after any other planned change is complete, that is not included in
lines 17b through 17d. Please provide details of the planned change in SCHEDULE 7,
COMMENTS. Other planned changes may include a second up-rate or de-rate to a unit or a
reactivation of a previously retired generator,
24. For line 17f, if the generator is expected to be retired within the next 5 years, enter the planned
effective date (MM-YYYY) of that scheduled retirement.
25. For line 18, Ability to Use Multiple Fuels, indicate if the combustion system that powers each
generator has both:
ƒ

The regulatory permits necessary to either co-fire fuels or fuel switch, and

ƒ

The equipment, including fuel storage facilities, in working order, necessary to either co-fire
fuels or fuel switch.

If the answer to this question is “No”, go to SCHEDULE 3. PART C,.
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 second fuel for start-up or flame stabilization.
26. For line 19, Ability to Co-Fire, indicate whether or not the combustion system that powers the
generator has, in working order, the equipment necessary to co-fire fuels and the regulatory
permits to co-fire fuels.
27. For line 20, Fuel Options for Co-Firing, indicate up to six fuels that can be co-fired. Select
appropriate energy source codes from Table 1in these instructions. (Note: fuel options listed for
co-firing must also be included under either “Predominant Energy Source” (line 9), “Second
Most Predominant Energy Source” (line 11), or “Other Energy Sources (line 12).
28. For line 21, Ability to Co-Fire Oil and Natural Gas, indicate if the combustion system that
powers the generator can co-fire fuel oil with natural gas. If it cannot, skip to line 23.
29. For line 22, Ability to Co-Fire Oil, indicate whether or not the combustion system that powers
8

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

the generator can run on 100 percent oil. If the answer to this question is yes, skip to line 23. If
no, indicate the maximum percentage of the heat input to the combustion system (percent of
MMBtu) that can be supplied by oil when co-firing with natural gas. Also provide the maximum
output (summer net MW) that the unit can achieve, taking into account all applicable technical
limits, when making the maximum use of oil and co-firing natural gas.
30. For line 23, Ability to Fuel Switch, indicate whether or not the combustion system that powers
the generator has, in working order, the equipment necessary to fuel switch and the regulatory
permits to fuel switch.
31. For line 24, Oil – Natural Gas Fuel Switching, (a) indicate whether or not the combustion
system that powers the generator has, in working order, the equipment necessary to switch
between oil and natural gas and the regulatory permits to switch between oil and natural gas
are in effect. If no, go to line 26. If yes:
a) Can the unit switch fuels while operating (i.e., without shutting down the unit)? Check
“Yes” or “No”.
b) Enter the maximum output (summer net MW) that the unit can achieve, taking into
account all applicable legal, regulatory, and technical limits, when running on natural
gas.
c) Enter the maximum output (summer net MW) that the unit can achieve, taking into
account all applicable legal, regulatory, and technical limits, when running on oil.
d) Enter how long it takes to switch the generator from using 100 percent natural gas to
100 percent oil.
32. For line 25, Limits on Oil-fired Operation, indicate whether or not there are factors that limit
the operation of the generator (e.g., limits on maximum output, limits on annual operating
hours), when running on 100 percent oil. Check all factors that limit the ability of this generator
to switch from natural gas to oil.
33. For line 26, Fuel Switching Options, enter the codes for up to six fuels, including (if
applicable) oil and natural gas, which can be used as a sole source of fuel to power the
generator. Select appropriate energy source codes from the table in these instructions. (Note:
fuel options listed for fuel switching must also be included under either “Predominant Energy
Source” (line 9), “Second Most Predominant Energy Source” (line 11), or “Other Energy
Sources (line 12).
SCHEDULE 3. PART C. GENERATOR INFORMATION – PROPOSED GENERATORS
1. For line 1, Generator Nameplate Capacity, enter the highest value on the nameplate in
megawatts rounded to the nearest tenth. If the nameplate capacity is expressed in kilovolt
amperes (kVA), convert to kilowatts by multiplying the corresponding power factor by the kVA,
divide by 1,000 to express in megawatts to the nearest tenth. If the generator nameplate is not
known at this time, estimate the nameplate rating for the generator and note this as an estimate
in SCHEDULE 7. COMMENTS.
2. For line 2, Net Capacity, enter the net summer and net winter capacities in megawatts rounded
to the nearest tenth that are expected when the generator goes into commercial operation.
3. For line 3a, Reactive Power Output (MVAR) Corresponding to Net Summer Capacity for
generators with nameplate capacity 10 MW or greater, using manufacturer provided
design data , enter the lagging reactive power output and the leading reactive power output
that correspond to the net summer capacity (line 2). A MVAR is a Mega Voltampere Reactive.
4. For line 3b, Reactive Power Output (MVAR) Corresponding to Net Winter Capacity for
generators with nameplate capacity 10 MW or greater, using manufacturer provided
design data , enter the lagging reactive power output and the leading reactive power output
that correspond to the net winter capacity (line 2). A MVAR is a Mega Voltampere Reactive.
9

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

5. For line 4, Status Code, enter one of the following status codes:
Status Code
IP
TS
P
L
T
U
V
OT

Status Code Description
Planned new generator canceled, indefinitely postponed, or no longer in
resource plan
Construction complete, but not yet in commercial operation (including low
power testing of nuclear units)
Planned for installation but regulatory approvals not initiated; Not under
construction
Regulatory approvals pending. Not under construction but site preparation
could be underway
Regulatory approvals received. Not under construction but site preparation
could be underway.
Under construction, less than or equal to 50 percent complete (based on
construction time to date of operation)
Under construction, more than 50 percent complete (based on construction
time to date of operation)
Other (describe in SCHEDULE 7, COMMENTS)

6. For line 5, Planned Original Effective Date, enter the month and year of the original effective
date that: 1) the generator was scheduled to start operation after construction is completed.
(Please note that this date does not change once it has been reported the first time.)
7. For line 6, Planned Current Effective Date, enter the month and year of the current effective
date that the generator is scheduled to start operation.
8. For line 7, Will this generator be associated with a Combined Heat and Power system
(fuel input is used to produce both electricity and useful thermal output)? Check either
"Yes" or "No."
9. For line 8, Will this generator be part of a solid fuel gasification system, check yes or no,
as appropriate.
10. For line 9, indicate 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.
11. For line 10, Expected Predominant Energy Source, enter the energy source code for the
energy source expected to be used in the largest quantity (Btus) when the generator starts
commercial operation. Select appropriate energy source codes from Table 1 in these
instructions.
12. For line 11, if the expected predominant energy source for powering the generator is coal or
petroleum coke, check all the types of technology and steam conditions that apply.
13. For line 12, Expected Second Most Predominant Energy Source, enter the energy source
code for the energy sources expected to be used in the second largest quantity (Btus) when the
generator starts commercial operation. Select appropriate energy source codes from Table 1 in
these instructions. Do not include fuels expected to be used only for start-up or flame
stabilization.
14. For line 13, Other Energy Source Options, enter the codes for other energy sources that will
be used at the plant to power the generator. Enter up to four codes in order of their expected
predominance of use, where predominance is based on quantity of Btu(s) to be consumed.
Select appropriate energy source codes from Table 1 in these instructions.
15. For line 14, If Energy Source is Wind, enter the number of turbines.
16. For line 15, Ability to Use Multiple Fuels, indicate if the combustion system that will power
each generator will have both:
ƒ

The regulatory permits necessary to either co-fire fuels or fuel switch, and
10

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)
ƒ

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

The equipment, including fuel storage facilities necessary to either co-fire fuels or fuelswitch.

If the answer is “No” or “Undetermined”, go to SCHEDULE 4.
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 second fuel for start-up or flame stabilization.
17. For line 16, Ability to Co-Fire, indicate whether or not the combustion system that will power
the generator will have the equipment necessary to co-fire fuels and the regulatory permits to
co-fire fuels. If no, skip to line 20.
18. For line 17, Fuel Options for Co-Firing, indicate up to six fuels that the generator will be
designed to co-fire. Select appropriate energy source codes from Table 1 in these instructions.
Note: fuel options listed for co-firing must also be included under either “Predominant Energy
Source” (line 9a), “Second Most Predominant Energy Source” (line 11), or “Other Energy
Sources (line 13).
19. For line 18, Ability to Co-Fire Oil and Natural Gas, indicate if the combustion system that
powers the generator will be able to co-fire fuel oil with natural gas. If it cannot, skip to line 20.
20. For line 19, Ability to Co-Fire Oil, indicate whether or not the combustion system that will
power the generator can run on 100 percent oil. If yes, skip to line 20, if no, indicate the
maximum percentage of the heat input to the combustion system (percent of MMBtu) that will
be able to be supplied by oil when co-firing with natural gas. Also provide the maximum output
(summer net MW) that the unit is expected to achieve, taking into account all applicable legal,
regulatory, and technical limits, when making the maximum use of oil and co-firing natural gas.
21. For line 20, Ability to Fuel Switch, indicate whether or not the combustion system that will
power the generator will have the equipment necessary to fuel switch and have the regulatory
permits to fuel switch. If no, then skip to SCHEDULE 4.
22. For line 21, Oil – Natural Gas Fuel Switching, (a) indicate whether or not the combustion
system that will power the generator will have the equipment necessary to switch between oil
and natural gas and the regulatory permits in place to switch between oil and natural gas. If no,
skip to line 23. If yes:
a) Will the unit be able to switch fuels while operating (i.e., without shutting down the unit)?
b) Enter the maximum output (summer net MW) that the unit can achieve, taking into
account all applicable legal, regulatory, and technical limits, when running on natural gas.
c) Enter the maximum output (summer net MW) that the unit can achieve, taking into
account all applicable legal, regulatory, and technical limits, when running on oil.
d) Enter how long it takes to switch the generator from using 100 percent natural gas to 100
percent oil.
23. For line 22, Limits on Oil-fired Operation, indicate whether or not there will be factors that will
limit the operation of the generator (e.g., limits on maximum output, limits on annual operating
hours), when running on 100 percent oil. Check all factors that will limit the ability of this
generator to switch from natural gas to oil.
24. For line 23, Fuel Switching Options, enter the codes for up to six fuels, including (if applicable)
oil and natural gas, that can be used as a sole source of fuel to power each generator. Select
appropriate energy source codes from Table 1 in these instructions. Note: fuel options listed for
fuel switching must also be included under either “Predominant Energy Source” (line 10),
“Second Most Predominant Energy Source” (line 12), or “Other Energy Sources (line 13).
SCHEDULE 4. OWNERSHIP OF GENERATORS OWNED JOINTLY OR BY OTHERS
11

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

1. Complete a separate SCHEDULE 4 for each existing and planned generator operated by the
respondent that is, or will be, jointly owned; and each generator that the respondent operates
but is 100 percent owned by another entity. Only the current or planned operator of jointlyowned generators should complete this schedule. The total percentage of ownership must
equal 100 percent.
2. For each generator, specify the Plant Name, EIA Plant Code, and Generator Identification,
as listed on SCHEDULE 3. PART A.
3. Enter the Owner/Joint Owner Name and Address, in order of percentage of ownership, of
each generator. Enter the EIA Code for the owner, if known, otherwise leave blank. Enter the
Percent Owned to two decimal places, i.e., 12.5 percent as “12.50.” If a generator is 100
percent owned by an entity other than the operator, then enter the percentage ownership as
“100.00.”
4. Include any notes or comments in SCHEDULE 7, COMMENTS.
SCHEDULE 5. NEW GENERATOR INTERCONNECTION INFORMATION
1. Complete a separate SCHEDULE 5 for each generator that started commercial operation
during the data year (calendar year for which this survey is being filed). For example, if
Reporting is as of December 31, 2007, then data year is 2007.
2. For line 1, enter the Name of the Power Plant and the EIA Power Plant Code, as previously
reported in SCHEDULE 3. PART A.
3. For line 2, enter the Operator’s Generator Identification, as previously reported in
SCHEDULE 3. PART A.
4. For Line 3, Date of Actual Generator Interconnection, report the month and year that the
interconnection was put into place.
5. For line 4, Date of the Initial Interconnection Request, report the month and year that the first
request for interconnection was filed with the grid operator.
6. For line 5, Interconnection Site Location, specify the nearest city or town, and the state,
where the interconnection equipment is located.
7. For line 6, Grid Voltage at the Point of Interconnection, specify the grid voltage, in kV, at
the point of interconnection between the generator and the grid.
8. For line 7, Owner of the Transmission or Distribution Facilities to Which Generator is
Interconnected, provide the name of the owner of the transmission or distribution facilities to
which the generator is interconnected. If the name of the owner of the facilities is unknown,
provide the name of the contracting party.
9. For line 8, Total Cost Incurred for the Direct, Physical Interconnection, specify the total
cost incurred, in thousands of dollars, to accomplish the physical interconnection.
10. For line 9, Equipment Included in the Direct Interconnection Cost, check each of the types
of equipment that are included in the cost amount reported on line 8. If there are significant
types of equipment that are not included in the list, please specify what additional equipment
was needed for the interconnection in SCHEDULE 7, COMMENTS.
11. For line 10, (a)Total Cost for Other Grid Enhancements/Reinforcements Needed to
Accommodate Power Deliveries From the Generator, specify the amount incurred, in
thousands of dollars, for any other grid enhancements or reinforcements that were needed to
accommodate power deliveries from the new generator. If these costs, or some portion of
these costs, will be repaid to your company at some time in the future by the owner of the grid,
or by the party with whom you contracted for the interconnection, please check “yes” in line
10b; otherwise, check “no” in 10b.
12. For line 11, Were Specific Transmission Use Rights Secured As A Result Of The
12

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

Interconnection Costs Incurred, check yes or no.

SCHEDULE 6. BOILER INFORMATION
(This information was formerly collected on Form EIA-767, Steam-Electric Plant Operation
and Design Report)
This schedule is required to be completed for:
•
•

All existing organic-fueled or combustible renewable-fueled steam-electric plants with a total
generator nameplate capacity of at least 10 megawatts; and
All planned (5-year plans) new organic-fueled or combustible renewable-fueled steamelectric plants with a total generator nameplate capacity of at least 10 megawatts.

Some parts of SCHEDULE 6 are not required to be completed for plants with a total generator
nameplate capacity less than 100 megawatts. These parts are specifically noted in the form and/or
the instructions.
SCHEDULE 6. PART A. PLANT CONFIGURATION
1. Identification information should be a code commonly used by plant management for that
equipment (e.g., “2,” “A101,” “7B,” etc.). Select a code for each piece of equipment and use it
for that equipment throughout this form. The code should be a maximum of six characters long
and should conform to codes reported for the same equipment (especially generators) on other
EIA forms. Do not use blanks in the code. Do not enter “NA” for those lines that are not
applicable. Plants less than 100 MW should only complete lines 1, 2, 3, and if applicable, 5 and
6. Planned equipment that is on order and expected to go into commercial service within 5
years must be reported. 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. Do not change preprinted equipment identification.
2. For line 1, using each boiler as a starting point, complete the entire column under the boiler
identification with the requested information on each piece of associated existing or planned
equipment (e.g., generators, cooling systems, etc.). Report waste-heat boilers with auxiliary
firing. Do not report waste-heat boilers without auxiliary firing, or auxiliary house or start-up
boilers. A waste-heat boiler is a boiler that receives all or a substantial portion of its energy
input from the noncombustible exhaust gases of a separate fuel-burning process. Combined
cycle units with auxiliary firing report the heat recovery steam generators (HRSGs) on line1.
3. For lines 2, 4, 5, 6, 7, and 8, if a piece of equipment (e.g., a generator or a cooling system)
serves two or more boilers, repeat the identification information for that equipment under each
appropriate boiler.
4. For line 2, Associated Generator(s), do not report auxiliary generators. Multiple generators
operated as a single unit (e.g., cross compound and topping generators) should be identified as
a group with one identification code. Combined cycle units with auxiliary firing report only the
steam generators. Do not report the combustion turbine portion of the combined cycle unit.
5. For line 3, Generator Associations with Boiler as Actual or Theoretical, indicate “A” for
actual association during year or “T” for theoretical associations.
6. For line 4, Associated Cooling System(s), a cooling system is an equipment system that
13

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

provides water to the condensers and includes water intakes and outlets, cooling towers and
ponds, pumps, and pipes. Identify a single plant cooling system, not separate systems, unless
systems are physically separated, e.g., have separate water intake and outlet structures, where
each system can be operated independently.
7. For line 4, Associated Cooling System(s), a cooling system is an equipment system that
provides water to the condensers and includes water intakes and outlets, cooling towers and
ponds, pumps, and pipes. Identify a single plant cooling system, not separate systems, unless
systems are physically separated, e.g., have separate water intake and outlet structures, where
each system can be operated independently.
8. For line 5, Associated Flue Gas Particulate Collector(s), if a combination particulate collector
is associated with a single boiler, identify the collectors as a single group. If the particulate
collector also removes sulfur dioxide, identify the unit in lines 5 and 6 using the same
identification code.
9. For line 6, Associated Flue Gas Desulfurization Units(s), for reporting purposes identify an
associated flue gas desulfurization unit to include all the trains (or modules) associated with a
single boiler. If the flue gas desulfurization unit also removes particulate matter, identify the unit
in lines 5 and 6 using the same identification code
10. For line 7, Associated Stack(s), a stack is defined as a tall, vertical structure containing one or
more flues used to discharge products of combustion into the atmosphere.
11. For line 8, Associated Flue(s), a flue is defined as an enclosed passageway within a stack for
directing products of combustion to the atmosphere. For stacks with multiple flues, report in one
column all flues that serve the boiler identified in line 1. Separate multiple entries with commas.
If the stack has a single flue, use the stack identification for the flue identification.
SCHEDULE 6. PART B. BOILER INFORMATION – AIR EMISSION STANDARDS
(DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW)
1. Complete a separate page for each existing or planned boiler.
2. 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 following codes of the New Source Performance Standards (NSPS):
D
Da
Db
Dc
N

Subpart D is the Standards of Performance for fossil-fuel fired steam boilers for
which construction began after August 17, 1971.
Subpart Da is the Standards of Performance for fossil-fuel fired steam boilers for
which construction began after September 18, 1978.
Subpart Db is the Standards of Performance for fossil-fuel fired steam boilers for
which construction began after June 19, 1984.
Subpart Dc is the Standards of Performance for small industrial-commercialinstitutional steam generating units.
Not covered under New Source Performance Standards.

For line 2b, Is Boiler Operating Under a New Source Review (NSR) Permit?, check “Yes”
or “No”; if Yes, enter date and identification number of the issued permit.
3. For line 3, Type of Statute or Regulation, select from the following the most stringent type of
statute or regulation code:
FD
Federal
ST
State
LO
Local
4. If there is no standard for nitrogen oxide emissions, report “NA” for line 3, column (c), and skip
the remaining column (c) items.
14

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

5. Line 4, Emission Standard Specified, refers to the numeric value for the unit of measurement
in line 5. If no numeric value is specified, report “NA.” For Sulfur Dioxide (column (b)), if the
standard requires both an emission rate and a percent scrubbed, report both standards
separated by a slash (e.g., 1.2/90 for emission standards specified in line 4, column (b), and
pounds of sulfur dioxide per million Btu in fuel/percent sulfur removal efficiency (by weight) for
units of measurement in line 5, column (b), and indicate in a footnote on SCHEDULE 7.

6. For line 5, Unit of Measurement Specified, column (a), Particulate Matter, select from the
following unit of measurement codes (PB* is the preferred measurement):
Code
OP
PB*
PC
PG
PH
UG
OT

Unit of Measurement
Percent of opacity
Pounds of Particulate matter per million Btu in fuel
Grains of particulate matter per standard cubic foot of stack gas
Pounds of particulate matter per thousand pounds of stack gas
Pounds of particulate matter emitted per hour
Micrograms of particulate matter per cubic meter
Other (specify in SCHEDULE 7, COMMENTS)

7. For line 5, Unit of Measurement Specified, column (b), Sulfur Dioxide, select from the
following unit of measurement codes (DP* is the preferred measurement):
Code
DC
DH
DL
DM
DP*
SB
SR
SU
OT

Unit of Measurement
Ambient air quality concentration of sulfur dioxide (parts per million)
Pounds of sulfur dioxide emitted per hour
Annual sulfur dioxide emission level less than a level in a previous year
Parts per million of sulfur dioxide in stack gas
Pounds of sulfur dioxide per million Btu in fuel
Pounds of sulfur per million Btu in fuel
Percent sulfur removal efficiency (by weight)
Percent sulfur content of fuel (by weight)
Other (specify in SCHEDULE 7, COMMENTS)

8. For line 6, Time Period Specified, select from the following codes to indicate the period over
which measurements were averaged:
Code
NV
FM
SM
FT
OH
WO
TH
EH
DA
WA
MO
ND
YR
PS
DT
NS
OT

Time Period
Never to exceed
5 minutes
6 minutes
15 minutes
1 hour
2 hours
3 hours
8 hours
24 hours
Weekly average
30 days
90 days
Annual
Periodic stack testing
Defined by testing
Not specified
Other (specify in SCHEDULE 7, COMMENTS)

15

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

9. For line 7, Year Boiler Was or Is Expected to Be in Compliance With Federal, State and/or
Local Regulations, if the boiler is currently in compliance, enter the year the boiler came into
compliance or the year of the regulation, whichever came last. Report “9999” only if a revision
of a governing regulation is being sought or no plans have been approved to bring the boiler
into compliance.
10. For line 8, If Not in Compliance, Strategy for Compliance, column (c), select from the
following strategy for compliance codes (separate multiple entries (up to three) with commas):
Code
BO
FR
LA
LN
MS
NC
OV
SE
OT

Strategy for Compliance
Burner out of service
Flue gas recirculation
Low excess air
Low nitrogen oxide burner
Currently meeting standard
No plans to control
Overfire air
Seeking revision of governing regulation
Other (specify in SCHEDULE 7, COMMENTS)

11. For line 9, Existing, and line 10, Planned, Strategies to Meet the Sulfur Dioxide and
Nitrogen Oxides Requirements of Title IV of the Clean Air Act Amendment of 1990,
column (b), select from the following strategy for compliance codes (separate multiple entries
(up to three) with commas):
Code
CF
CU
IF
NC
ND
RP
SS
SU
TU
UC
UE
US
UP
OT
Code
AA
BF
CF
FR
FU
LA
LN
NC
ND
OV
RP
SC

Strategy for Compliance (Sulfur Dioxide)
Fluidized Bed Combustor
Control unit under Phase I extension plan
Install flue gas desulfurization unit (other than Phase I extension plan)
No change in historic operation of unit anticipated
Not determined at this time
Repower Unit
Switch to lower sulfur fuel
Designate Phase II unit(s) as substitution unit(s)
Transfer unit under Phase I extension plan
Decrease utilization - designate Phase II unit(s) as compensating unit(s)
Decrease utilization - rely on energy conservation and/or improved
efficiency
Decrease utilization - designate sulfur-free generators to compensate
Decrease utilization - purchase power
Other (specify in SCHEDULE 7, COMMENTS)
Strategy for Compliance (Nitrogen Oxides)
Advanced Overfire Air
Biased Firing (alternative burners)
Fluidized Bed Combustor
Flue Gas Recirculation
Fuel Reburning
Low Excess Air
Low NOx Burner
No change in historic operation of unit anticipated
Not determined at this time
Overfire Air
Repower Unit
Slagging

16

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

SN
SR
UE

Form Approved
OMB No. 1905-0129
Approval Expires:

Selective Noncatalytic Reduction
Selective Catalytic Reduction
Decrease utilization - rely on energy conservation and/or improved
efficiency
Other (specify in SCHEDULE 7, COMMENTS)

OT

SCHEDULE 6. PART C. BOILER INFORMATION – DESIGN PARAMETERS
(DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW)
1. Complete for each existing or planned boiler. If a procurement contract has been signed for an
upgrade or retrofit of a boiler: 1) complete a separate page for the existing boiler; 2) explain In
SCHEDULE 7. COMMENTS how long the existing equipment will be out of service; and 3)
using the same boiler identification, complete a separate SCHEDULE 6. PART C for the
planned upgrade or retrofit.
For line 2, verify boiler status. Select from the following codes.
Code
CN
CO
OP
OS
PL
RE
SB
SC
TS

Boiler Status
Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service less than 365 days)
Out of service (365 days or longer)
Planned (on order and expected to go into commercial service within 5
years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve); i.e., not normally used, but available for
service
Cold Standby (Reserve); deactivated (usually requires 3 to 6 months to
reactivate)
Operating under test conditions (not in commercial service)

2. For line 3, Boiler Actual or Projected In-service Date, and line 4, Boiler Actual or Projected
Retirement Date, the month-year date should be entered as follows: August 1959 as 8-1959. If
the month is unknown, use the month of June as a default and enter a 6 before the year.
3. For line 5, Boiler Manufacturer, select one code from the following boiler manufacturers’
codes:
Code
AI
AL
AS
AT
BR
BW
DJ
CE
CH
DL
DS
EC
ER
FW
GE
GT
HT
ID
IN

Boiler Manufacturer
Aalborg Industries
Alstrom
American Shack
Applied Thermal Systems
BROS
Babcock and Wilcox
De John Coen bv
Combustion Engineering
Cohn
Deltak
Doosan
Econotherm
Erie City Iron Works
Foster Wheeler
General Electric
Gotaverken
Hitachi
Indeck
Innovative Steam Technology

17

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)
KL
KP
KW
ME
NM
NT
PB
PR
RS
ST
TM
TS
VO
WE
WG
WI
ZN
OT

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

Keeler Dorr Oliver
Kvaerner Pulping
Kawasaki Heavy Industries
Mitchell Engineering
NEM
Nooter/Erickson
Peabody
Pyro Power
Riley Stoker
Sterling
Tampell
Toshiba
Vogt Machine Company/Vogt Power
Westinghouse
Wiegl Engineering
Wickes
Zurn
Other (specify in SCHEDULE 7, COMMENTS)

4. For line 6, Type of Firing Used with Primary Fuels, select from the following firing codes
(separate multiple entries (up to three) with commas):
Firing
Code
AF
CF
CY
DB
FB
FF
OF
RF
SF
SS
TF
VF
OT

Firing Type Description
Arch firing
Concentric Firing
Cyclone firing
Duct burner
Fluidized bed firing
Front firing
Opposed firing
Rear firing
Side firing
Spreader stoker
Tangential firing
Vertical firing (burners mounted on furnace ceiling)
Other (specify in SCHEDULE 7, COMMENTS)

5. For lines 8 through 11, enter firing rate data for primary fuels as entered in line 13. Do not enter
firing rate for startup or flame stabilization fuels. For waste-heat boilers with auxiliary firing, enter
the firing rate for auxiliary firing and complete line 12 for waste heat.
6. For line 12, a waste-heat boiler is a boiler that receives all or a substantial portion of its energy
input from the noncombustible exhaust gases of a separate fuel-burning process.
7. For line 13, Primary Fuels Used, see table of energy source ( fuel) codes. Show design firing
rates for each fuel in the associated lines 8, 9, 10, and 11. Do not include startup fuels.
Predominance is based on Btu.
8. For line 16, Total Air Flow, report at standard temperature and pressure, i.e., 68 degrees
Fahrenheit and one atmosphere pressure.
9. For line 17, Wet or Dry Bottom, enter “W” for Wet or “D” for Dry. Wet Bottom is defined as slag
tanks that are installed at furnace throat to contain and remove molten ash from the furnace. Dry
Bottom is defined as having no slag tanks at furnace throat area; throat area is clear; bottom
ash drops through throat to bottom ash water hoppers. This design is used where the ash
melting temperature is greater than the temperature on the furnace wall, allowing for relatively
dry furnace wall conditions.

18

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

SCHEDULE 6. PART D. BOILER INFORMATION – NITROGEN OXIDE EMISSION CONTROLS
1. Complete a separate page for each existing or planned boiler.
2. For line 2, Nitrogen Oxide Control Status, select from the following status codes:
Code
CN
CO
OP
OS
OZ
PL
RE
SB
SC
TS

Control Status
Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service less than 365 days)
Out of service (365 days or longer)
Operated during the ozone season (May through September)
Planned (on order and expected to go into commercial service within 5
years)
Retired (no longer in service and not expected to be returned to
service)
Standby (or inactive reserve); i.e., not normally used, but available for
service
Cold Standby (Reserve); deactivated (usually requires 3 to 6 months
to reactivate)
Operating under test conditions (not in commercial service)

3. For line 3, Low Nitrogen Oxide Control Process, select from the following low nitrogen oxide
control processes (separate multiple entries (up to three) with commas):
Code
AA
BF
CF
FR
FU
LA
LN
NA
OV
SC
SN
SR
OT

Control Process
Advanced Overfire Air
Biased Firing (alternative burners)
Fluidized Bed Combustor
Flue Gas Recirculation
Fuel Reburning
Low Excess Air
Low NOx Burner
Not Applicable
Overfire Air
Slagging
Selective Noncatalytic Reduction
Selective Catalytic Reduction
Other (specify in SCHEDULE 7, COMMENTS)

4. For line 4, Manufacturer of Low Nitrogen Oxide Control Burners, select from the following
low nitrogen oxide control burner manufacturers:
Code
AB
ABB
AC
AL
AT
AU
AZ
BC
BM
BMD
BW
CE

Manufacturer
Advanced Burner Technologies
ABB
Advanced Combustion Technology
Alstom
Applied Thermal Systems
Applied Utility Systems (AUS)
Alzeta
Babcock Borsig Power
Bloom
Burns & McDonnell
Babcock and Wilcox
Combustion Engineering

19

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)
CM
CN
CT
DB
DD
DQ
DV
EA
EG
EL
EP
ET
FB
FN
FT
FW
GE
GR
HL
HT
IC
ID
IH
JZ
KL
MB
MI
MT
NA
NB
NC
NE
NL
PA
PB
PS
PL
PX
RD
RI
RJ
RR
RS
RV
SC
SW
TC
TM
TS
WG
ZC
OT

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

Combustion Components Associates Inc
Coen
Callidus Technologies
Deutsche-Babcock
Damper Design Inc
Duquesne Light Company & Energy Systems Associates
Davis
Eagle Air
Energy and Environmental Research Corp (EER)
Electric power Technologies
EPRI
Entropy Technology and Environmental Construction Corp (ETEC)
Faber
Forney
Fuel Tech Inc
Foster Wheeler
General Electric
GE Energy and Environmental Research Corp (GEEER)
Holman
Hitachi
International Combustion Limited
Indeck
In house
John Zink Todd Combustion/Todd Combustion
Keeler Dorr Oliver
Mitsui-Babcock
Mitsubishi Industries
Mobotec
Not Applicable
Nebraska Boiler Company
Natcom, Inc
NEI
Noell, Inc
Procedair
Peabody
Peerless Manufacturing Company
Pillard
Phoenix Combustion
Rodenhuis and Verloop
Riley
RJM
Rolls Royce
Riley Stoker/Riley Power
RV Industries
Southern Company
Siemans-Westinghouse
Todd Combustion
Tampella
Toshiba
Weigel Engineering
Zeeco
Other (specify in a footnote in SCHEDULE 7)

SCHEDULE 6. PART E. BOILER INFORMATION – MERCURY EMISSION CONTROLS
1. For line 2, if “Yes” is checked on line 1, Does This Boiler have Mercury Emission Controls,
mark all of the boxes that apply to the type of mercury emission controls used. If the type of
control is “other”, please describe in SCHEDULE 7, COMMENTS.

20

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

SCHEDULE 6 PART F. COOLING SYSTEM INFORMATION – DESIGN PARAMETERS
(DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW)
1. If a procurement contract has been signed for an upgrade or retrofit of a cooling system: 1)
complete a separate page for the existing cooling system; 2) explain on SCHEDULE 7,
COMMENTS how long the existing equipment will be out of service; and 3) using the same
cooling system identification, complete a separate SCHEDULE 6. PART F, for the planned
upgrade or retrofit.
2. For line 2, Cooling System Status, select from the following equipment status codes:
Code
CN
CO
OP
OS
PL
RE
SB
SC
TS

System Status
Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service less than 365
days)
Out of service (365 days or longer)
Planned (on order and expected to go into commercial service
within 5 years)
Retired (no longer in service and not expected to be returned to
service)
Standby (or inactive reserve); i.e., not normally used, but available
for service)
Cold Standby (Reserve); deactivated (usually requires 3 to 6
months to reactivate)
Operating under test conditions (not in commercial service)

3. For line 4, Type of Cooling System, select from the following cooling system codes (separate
multiple entries (up to four) with commas):
Code
OC
OF
OS
RC
RF
RI
RN
OT

Cooling System Description
Once through with cooling pond(s) or canal(s)
Once through, fresh water
Once through, saline water
Recirculating with cooling pond(s) or canal(s)
Recirculating with forced draft cooling tower(s)
Recirculating with induced draft cooling tower(s)
Recirculating with natural draft cooling tower(s)
Other (specify in a footnote on SCHEDULE 7)

4. For line 5, Source of Cooling Water, provide name of river, lake, etc. For line 5 and line 6,
Design Cooling Water Flow Rate, if more than one source of cooling water is used by a
cooling system, enter other sources in a footnote in SCHEDULE 7. If water is purchased, report
“municipal.” If water is taken from wells, report “wells.” If source of water is “municipal” or
“wells,” do not complete lines 19, 20, 21, and 22 and provide the total amount of water used at
100 percent load in line 5.

5. For lines 8, 9, and 10, a cooling pond is a natural or man-made body of water that is used for
dissipating waste heat from power plants.
6. For line 12, Type of Towers, select from the following cooling tower codes (separate multiple
entries (up to two) with commas):

21

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

Code
MD
MW
ND
NW
WD

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

Type of Towers
Mechanical draft, dry process
Mechanical draft, wet process
Natural draft, dry process
Natural draft, wet process
Combination wet and dry processes

7. For lines 15, 16, 17, and 18, enter the actual installed cost for the existing system or the
anticipated cost to bring a planned 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.
8. For line 15, Total System, the 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. The cost of condensers should not be included.
9. For lines 19 through 22, if the cooling system is a zero discharge type (RC, RF, RI, RN), do not
complete column (b). The intake and the outlet are the points where the cooling system meets
the source of cooling water found on line 5. For all longitude and latitude coordinates, provide
degrees, minutes, and seconds.
10. For line 23, Enter Datum for the above Latitude and Longitude, if Known; Otherwise Enter
“UNK”:
The longitude and latitude measurement for a location depends in part on the coordinate
system (or “datum”) the measurement is keyed to. “Datum systems” used in the United States
include the North American Datum 1927 (NAD27), North American Datum 1983 (NAD83) and
World Geodetic Survey 1984 (WGS84).
(For background information on datums and their uses, see: http://biology.usgs.gov/index.html).
SCHEDULE 6. PART G. FLUE GAS PARTICULATE COLLECTOR INFORMATION
1. For line 3, Flue Gas Particulate Collector Status, select from the following equipment status
codes:
Code
CN
CO
OP
OS
PL
RE
SB
SC
TS

Status
Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service within 365 days)
Out of service (365 days or longer)
Planned (on order or expected to go into commercial service within 5
years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve, i.e., not normally used, but available for
service)
Cold Standby (Reserve); deactivated. Usually requires 3 to 6 months to
reactivate
Operating under test conditions (not in commercial service).

2. For line 4, Type of Flue Gas Particulate Collector, select from the following flue gas
particulate collector codes (for combination units, separate multiple entries (up to three) with
commas):
3.
22

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)
Code
BS
BP
BR
EC
EH
EK
EW
MC
SC
WS
OT

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

Description
Baghouse, shake and deflate
Baghouse, pulse
Baghouse, reverse air
Electrostatic precipitator, cold side, with flue gas conditioning
Electrostatic precipitator, hot side, with flue gas conditioning
Electrostatic precipitator, cold side, without flue gas conditioning
Electrostatic precipitator, hot side, without flue gas conditioning
Multiple Cyclone
Single Cyclone
Wet Scrubber
Other (specify in a footnote on SCHEDULE 7 of the form).

4. For line 5, Installed Cost of Flue Gas Particulate Collector Excluding Land, enter the actual
installed cost for the existing system or the anticipated cost to bring a planned 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.
5. For lines 6, 7, 8 and 9 enter value for fuel. Enter range of values, if applicable.
SCHEDULE 6. PART H. FLUE GAS DESULFURIZATION UNIT INFORMATION – DESIGN
PARAMETERS
1. If a procurement contract has been signed for an upgrade or retrofit of a Flue Gas
Desulfurization Unit: 1) complete a separate page for the existing unit; 2) explain on
SCHEDULE 7, COMMENTS, how long the existing equipment will be out of service; and 3)
using the same FGD identification, complete a separate SCHEDULE 6. Part H for the planned
upgrade or retrofit.
1a. For line 2, Flue Gas Desulfurization Unit Status, select from the following equipment status
codes:
Code
CN
CO
OP
OS
PL
RE
SB
SC
TS

Status
Cancelled (previously reported as planned)
New unit under construction
Operating (in commercial service or out of service less than 365 days)
Out of service (365 days or longer)
Planned (on order and expected to go into commercial service within 5
years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve, i.e., not normally used by available for
service)
Cold Standby (Reserve); deactivated. Usually requires 3 to 6 months to
activate
Operating under test conditions (not in commercial service)

If the code selected is “OP” complete lines 4 through 14, otherwise do not
complete these lines.
2. For line 4, Type of Flue Gas Desulfurization Unit, select from the following FGD unit codes
(for combination units, separate multiple entries (up to four) with commas):
Code
BR
CD
MA
PA

Type of Unit
Jet Bubbling Reactor
Circulating Dry Scrubber
Mechanically aided type
Packed type

23

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)
SD
SP
TR
VE

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

Spray dryer type
Spray type
Tray type
Venture type

3. For line 5, Type of Sorbent, select from the following sorbent codes (separate multiple entries
(up to four) with commas):
Code
AF
CC
DB
DL
LA
LF
LI
LS
MO
SA
SC
SL
SS
OT

Type of Sorbent
Alkaline fly ash
Calcium carbide slurry
Dibasic acid
Dolomitic limestone
Lime and alkaline fly ash
Limestone and alkaline fly ash
Lime
Limestone
Magnesium oxide
Soda ash
Sodium carbonate
Soda liquid
Sodium sulfite
Other (specify in SCHEDULE 7)

24

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

4. For line 7, Flue Gas Desulfurization Unit Manufacturer, select one code from the following
flue gas desulfurization unit manufacturer codes:

Code
AA
ABB
AL
AM
AP
API
AX
BE
BI
BL
BMC
BO
BPC
BPE
BT
BW
CA
CC
CE
CO
DA
DC
DM
EE
EEC
EI
FL
FM
FW
GE
HA
IH
JO
KE
KR
MC
MG
MI
MX
NPA
NSP
PA
PB
PR
PU
RC
RS
SHU
SK
TC
TH

Manufacturer
Advanced Air Technologies
ABB Environmental Systems
Alstom
American Air Filter
Airpol
Air Pollution Industries
Amerex Industries
Bact Engineering
Bleco Industries
Bechtel Corporation
Burns and McDonnell
Bionomics
Belco Pollution Control
Babcock Power Environmental Inc (BPEI)
Belco Technologies
Babcock and Wilcox
Chiyoda
Chemico
Combustion Engineering
Combustion Equipment
Delta Conveying Systems
Ducon
Davey McKee
Environmental Engineering
Environmental Elements Corporation
Entoleter Inc
Flakt, Inc
FMC
Foster Wheeler
General Electric
Hamon
In House Design
Joy Manufacturing
M.W. Kellogg
Krebs Equipment
Macrotek
McGill Air Clean
Mitsubishi Industry
Marselex
Neptune Airpol
NSP
Procedair
Peabody
Pyro Power
Pure Air
Research Cottrell
Riley Stoker
Saarberg-Holter Umwelttechnick GmbH
Schenck Weigh Feeders
Turbosonic
Thyssen/CEA

25

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)
UE
UM
UO
WAPC
OT

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

Utility Engineering
United McGill
Universal Oil Products
Wheelabrator Air Pollution Control
Other (specify in a footnote in SCHEDULE 7)

5. For line 15, Removal Efficiency for Sulfur Dioxide, report the removal efficiency as the
percent by weight of gases removed from the flue gas.
6. For lines 20, 21, 22, and 23, enter the actual installed costs for the existing systems or the
anticipated costs to bring a planned 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. The total (line 23) will be the sum of lines 20, 21, and 22 which includes
any other costs pertaining to the installation of the unit.
SCHEDULE 6. PART I. STACK AND FLUE INFORMATION – DESIGN PARAMETERS
(DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW)
1. If a procurement contract has been signed for an upgrade or retrofit of a stack or flue: 1)
complete a page for the existing stack or flue; 2) explain on SCHEDULE 7, COMMENTS, how
long the existing structure will be out of service; and 3) using the same flue and stack
identifications, complete a separate SCHEDULE 6. Part I for the planned upgrade or retrofit.
2. For line 1, Flue ID, and line 2, Stack ID, there must be an entry. If there is only one flue, also
use the stack ID as the flue ID. Identification codes must be the same as reported on
SCHEDULE 6. PART A.
3. For line 3, Stack (or Flue) Actual or Projected In-Service Date of Commercial Operation,
the month-year should be entered as follows: e.g., August 1959 as 08-1959.
4. For line 4, Status of Stack, select one from the following equipment status codes:
Status
CN
CO
OP
OS
PL
RE
SB
SC
TS

Code
Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service within 365 days)
Out of service (365 days or longer)
Planned (on order or expected to go into commercial service within 5
years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve, i.e., not normally used, but available for
service)
Cold Standby (Reserve); deactivated. Usually requires 3 to 6 months to
reactivate
Operating under test conditions (not in commercial service).

5. For lines 13 and 14, seasonal average flue gas exit temperatures should be reported in
degrees Fahrenheit, based on the arithmetic mean of measurements during operating hours.
Summer season includes June, July, and August. Winter season includes January, February,
and December.
6. For line 15, Source, enter “M” for measured or “E” for estimated.
7. For lines 16 and 17, Stack Location, enter the latitude and longitude in degrees, minutes, and
seconds.
26

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

8. For line 18, Enter Datum for Latitude and Longitude, if Known; Otherwise Enter “UNK”:
The longitude and latitude measurement for a location depends in part on the coordinate
system (or “datum”) the measurement is keyed to. “Datum systems” used in the United States,
include the North American Datum 1927 (NAD27), North American Datum 1983 (NAD83) and
World Geodetic Survey 1984 (WGS84).
If you know the datum system for the plant longitude and latitude, enter the system name (e.g.,
NAD83) on line 7. If you do not know the datum system used, enter UNK.
SCHEDULE 7. COMMENTS
This schedule provides additional space for comments. Please identify schedule and line number
and identifying information (e.g., plant code, boiler id, generator id) for each comment.

Table 1. Energy Source Codes and Heat Content

Energy
Source
Code
BIT
LIG
SC
Coal and
Coal
Synfuel

SUB
WC

DFO
JF
KER
Petroleum
Products

Natural
Gas
And Other
Gases

Higher Heating Value”
Range (Million Btu per
Unit of Fuel
MMBtu
MMBtu
Unit Label
Lower
Upper Energy Source Description
Fossil Fuels
tons
20
29
Anthracite Coal and Bituminous Coal
tons
10
14.5
Lignite Coal
tons
10
35
Coal Synfuel. Coal-based solid fuel that
has been processed by a coal synfuel
plant; and coal-based fuels such as
briquettes, pellets, or extrusions, which
are formed from fresh or recycled
coal and binding materials.
tons
15
20
Subbituminous Coal
tons
6.5
16
Waste/Other Coal. Including anthracite
culm, bituminous gob, fine coal, lignite
waste, waste coal.
barrels
5.5
6.2
Distillate Fuel Oil. Including Diesel, No.
1, No. 2, and No. 4 Fuel Oils.
barrels
5
6
Jet Fuel
barrels
5.6
6.1
Kerosene

PC
RFO

tons
barrels

24
5.8

30
6.8

WO

barrels

3.0

5.8

BFG

Mcf

0.07

0.12

Petroleum Coke
Residual Fuel Oil. Including No. 5, No.
6 Fuel Oils, and Bunker C Fuel Oil.
Waste/Other Oil. Including Crude Oil,
Liquid Butane, Liquid Propane, Oil
Waste, Re-Refined Motor Oil, Sludge
Oil, Tar Oil, or other petroleum-based
liquid wastes.
Blast Furnace Gas

NG

Mcf

0.8

1.1

Natural Gas

OG

Mcf

0.32

3.3

Other Gas. Specify in SCHEDULE 7,
COMMENTS

PG

Mcf

2.5

2.75

Gaseous Propane

27

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)

Solid
Renewable
Fuels

Liquid
Renewable
Fuels

All Other
Energy
Sources

ANNUAL ELECTRIC GENERATOR
REPORT
SG
SGC

Mcf
Mcf

AB

tons

MSW
OBS

tons
tons

TDF
WDS

tons
tons

OBL

barrels

SLW

tons

BLQ
WDL

tons
barrels

LFG
OBG

Mcf
Mcf

SUN
WND
GEO
WAT

N/A
N/A
N/A
N/A

PUR
WH

N/A
N/A

NUC
OTH

N/A

Form Approved
OMB No. 1905-0129
Approval Expires:

0.2
1.1
Synthetic Gas, other than coal-derived
0.2
0.3
Synthetic Gas, derived from coal
Renewable Fuels
9
18
Agricultural Crop
Byproducts/Straw/Energy Crops
9
12
Municipal Solid Waste
8
25
Other Biomass Solids
Specify in Comment Section
Tire-derived Fuels
16
32
7
18
Wood/Wood Waste Solids. Including
paper pellets, railroad ties, utility poles,
wood chips, bark, & wood waste solids.
3.5
4.0
Other Biomass Liquids. Specify in
SCHEDULE 7, COMMENTS.
10
16
Sludge Waste
10
8

14
14

Black Liquor
Wood Waste Liquids excluding Black
Liquor, includes red liquor, sludge wood,
spent sulfite liquor, and other woodbased liquids
0.3
0.6
Landfill gas
0.36
1.6
Other Biomass Gas, includes digestor
gas, methane, and other biomass gases.
Specify in Comment Section
0
0
Solar
0
0
Wind
0
0
Geothermal
0
0
Water at a conventional hydroelectric
turbine
All Other Energy Sources
0
0
Purchased Steam
0
0
Waste heat not directly attributed to an
energy source. WH should only be
reported where the energy source for
the waste heat is undetermined
Nuclear including Uranium, Plutonium,
Thorium
0
0
Specify in Comment Section

Table 2. Commonly Used North American Industry Classification System (NAICS)
Codes
Code
111
112
113
114
115
211
2121
2122
2123
23

Description
AGRICULTURE, FORESTRY, AND FISHING
Agriculture production - crops
Agriculture production, livestock and animal specialties
Forestry
Fishing, hunting, and trapping
Agricultural services
MINING
Oil and gas extraction
Coal mining
Metal mining
Mining and quarrying of nonmetallic minerals except fuels
CONSTRUCTION
MANUFACTURING
28

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)
311
3122
314
315
316
321
322
322122
32213
323
324
32411
325
32512
325188
325211
325311
326
327
32731
331
331111
331312
332
333
3345
335
336
337
339
482
485
484
22
2212
2213
22131
22132
481
482
483
484
485
486
487
513
562212
421 to 422
441 to 454
521 to 533

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

Food and kindred products
Tobacco products
Textile and mill products
Apparel and other finished products made from fabrics and similar materials
Leather and leather products
Lumber and wood products, except furniture
Paper and allied products (other than 322122 or 32213)
Paper mills, except building paper
Paperboard mills
Printing and publishing
Petroleum refining and related industries (other than 32411)
Petroleum refining
Chemicals and allied products (other than 325188, 325211, 32512, or 325311)
Industrial organic chemicals
Industrial inorganic chemicals
Plastic materials and resins
Nitrogenous fertilizers
Rubber and miscellaneous plastic products
Stone, clay, glass, and concrete products (other than 32731)
Cement, hydraulic
Primary metal industries (other than 331111 or 331312)
Blast furnaces and steel mills
Primary aluminum
Fabricated metal products, except machinery and transportation equipment
Industrial and commercial equipment and components except computer
equipment
Measuring, analyzing, and controlling instruments, photographic, medical, and
optical goods, watches and clocks
Electronic and other electrical equipment and components except computer
equipment
Transportation equipment
Furniture and fixtures
Miscellaneous manufacturing industries
TRANSPORTATION AND PUBLIC UTILITIES
Railroad transportation
Local and suburban transit and interurban highway passenger transport
Motor freight transportation and warehousing
Electric, gas, and sanitary services
Natural gas transmission
Water supply
Irrigation systems
Sewerage systems
Transportation by air
Railroad Transportation
Water transportation
Motor freight transportation and warehousing
Local and suburban transit and interurban highway passenger transport
Pipelines, except natural gas
Transportation services
Communications
Refuse systems
WHOLESALE TRADE
RETAIL TRADE
FINANCE, INSURANCE, AND REAL ESTATE
SERVICES
29

U.S. Department of Energy
Energy Information Administration
Form EIA-860 (2007)
512
514
514199
541
561
611
622
624
712
713
721
811
8111
812
813
814
92

GLOSSARY

SANCTIONS

REPORTING
BURDEN

ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires:

Motion pictures
Business services
Miscellaneous services
Legal services
Engineering, accounting, research, management, and related services
Education services
Health services
Social services
Museums, art galleries, and botanical and zoological gardens
Amusement and recreation services
Hotels
Miscellaneous repair services
Automotive repair, services, and parking
Personal services
Membership organizations
Private Households
PUBLIC ADMINISTRATION

The glossary for this form is available online at the following URL:
http://www.eia.doe.gov/glossary/index.html
The timely submission of Form EIA-860 by those required to report is mandatory under Section 13(b)
of the Federal Energy Administration Act of 1974 (FEAA) (Public Law 93-275), as amended. Failure
to respond may result in a penalty of not more than $2,750 per day for each civil violation, or a fine
of not more than $5,000 per day for each criminal violation. The government may bring a civil action
to prohibit reporting violations, which may result in a temporary restraining order or a preliminary or
permanent injunction without bond. In such civil action, the court may also issue mandatory
injunctions commanding any person to comply with these reporting requirements. Title 18 U.S.C.
1001 makes it a criminal offense for any person knowingly and willingly to make to any
Agency or Department of the United States any false, fictitious, or fraudulent statements as to
any matter within its jurisdiction.
Public reporting burden for this collection of information is estimated to average 6.0 hours per
response for respondents without environmental information and 11.3 hours per response for
respondents with environmental information, including the time for reviewing instructions, searching
existing data sources, gathering and maintaining the data needed, and completing and reviewing the
collection of information. Send comments regarding this burden estimate or any other aspect of this
collection of information, including suggestions for reducing this burden, to the Energy Information
Administration, Statistics and Methods Group, EI-70, 1000 Independence Avenue S.W., Forrestal
Building, Washington, DC 20585-0670; and to the Office of Information and Regulatory Affairs,
Office of Management and Budget, Washington, D.C. 20503. A person is not required to respond to
the collection of information unless the form displays a valid OMB number.

Information reported on Form EIA-860 will be treated as non-sensitive and may be publicly released
PROVISIONS
in identifiable form except as noted below.
REGARDING
CONFIDENTIALITY
The information reported for the data element “Tested Heat Rate” contained on SCHEDULE 3.
OF INFORMATION
PART B will be treated as sensitive and protected 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
regulations, 10 C.F.R. §1004.11, implementing the FOIA, and the Trade Secrets Act, 18 U.S.C.
§1905.
The Federal Energy Administration Act requires the EIA to provide company-specific data to other
Federal agencies when requested for official use. The information reported on this form may also be
made available, upon request, to another component of the Department of Energy (DOE); to any
Committee of Congress, the Government Accountability Office, or other Federal agencies authorized
by law to receive such information. A court of competent jurisdiction may obtain this information in
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U.S. Department of Energy
Form Approved
ANNUAL ELECTRIC GENERATOR
Energy Information Administration
OMB No. 1905-0129
REPORT
Form EIA-860 (2007)
Approval Expires:
response to an order. The information may be used for any nonstatistical purposes such as
administrative, regulatory, law enforcement, or adjudicatory purposes.
Disclosure limitation procedures are applied to the sensitive statistical data published from
SCHEDULE 3. PART B, Tested Heat Rate, on Form EIA-860 to ensure that the risk of disclosure of
identifiable information is very small.

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