1

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

PURPOSE Form EIA-860 collects data on the status of existing electric generating plants and associated 

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: EIA-860@eia.doe.gov 

 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: CNEAFhelpcenter@eia.doe.gov

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.

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: 

CONTACTS

Patricia Hutchins 

Telephone Number: (202) 586-1029 

FAX Number: (202) 287-1960 

E-mail: Patricia.Hutchins@eia.doe.gov
2

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

GENERAL 

INSTRUCTIONS 

1. Verify all EIA provided information. If incorrect, revise the incorrect entry and provide the 

correct information. State codes are two-letter U.S. Postal Service abbreviation. Provide any 

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.” 

2. Check all data for consistency with the same or related data that appear in more than one 

schedule of this form or in 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; 
3

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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). 

8. For line 8, NERC Region, enter the NERC region in which the plant is located. 
4

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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. Do not include prefixes (e.g. “QF” or “SPP” or “EWG”) before 

the docket number. Include only the numerical portion of the docket number, including dashes. 

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. . Do not include prefixes (e.g. “QF” or “SPP” or “EWG” 

before the docket number. Include only the numerical portion of the docket number, including 

dashes. 

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. . Do not include prefixes (e.g. “QF” or “SPP” or 

“EWG” before the docket number. Include only the numerical portion of the docket number, 

including dashes. 

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. Report voltage in kilovolts (kV). 

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. 
5

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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. 

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 with 

duct firing, 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 fossilfueled 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 Code Prime Mover Description

ST Steam Turbine, including nuclear, geothermal and solar steam (does not 

include combined cycle). 

GT Combustion (Gas) Turbine – Simple Cycle (includes jet engine design) 

IC Internal Combustion Engine (diesel, piston, reciprocating) 

CA Combined Cycle Steam Part 

CT Combined Cycle Combustion Turbine Part (type of coal or solid must be 

reported as energy source for integrated coal gasification). 

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). 

HY Hydraulic Turbine (includes turbines associated with delivery of 

 water by pipeline) 

PS Hydraulic Turbine – Reversible (pumped storage) 

BT Turbines Used in a Binary Cycle (such as used for geothermal 

 applications) 

PV Photovoltaic 

WT Wind Turbine 

CE Compressed Air Energy Storage 

FC Fuel Cell 

OT 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. 
6

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

7. For line 7, Ownership, 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.) 

9. For line 9, Date of Sale, If Sold, enter the month and year of the sale of the generator (e.g., 12-

2007), 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 Status 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 
7

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

generation during the year) for this reporting period. 

OA 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. 

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. 

RE 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 energy sources used by the 

combustion unit(s) associated with this generator. Prime mover = ST (steam units only) 

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.
8

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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 

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: 

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

 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 
9

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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 

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 between oil and natural gas? If No, skip to line 26.

b) Can the unit switch fuels while operating (i.e., without shutting down the unit)? Check 

“Yes” or “No”. 

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 natural 

gas. 

d) 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. 

e) 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. 
10

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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. 

5. For line 4, Status Code, enter one of the following status codes: 

Status Code Status Code Description

 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 (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 
11

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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: 

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

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

or fuel-switch. 

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 between oil and natural gas? If No, skip to line 23

b) Will the unit be able to switch fuels while operating (i.e., without shutting down the unit)? 

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 natural gas. 

d) 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. 

e) Enter how long it takes to switch the generator from using 100 percent natural gas to 100 

percent oil. 
12

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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 

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 
13

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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 

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. 
14

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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 

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 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. 

8. 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 

9. For line 7, 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. 

10. For line 8, 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.

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 Subpart D is the Standards of Performance for fossil-fuel fired steam boilers for 

which construction began after August 17, 1971. 

Da Subpart Da is the Standards of Performance for fossil-fuel fired steam boilers for 

which construction began after September 18, 1978. 

Db Subpart Db is the Standards of Performance for fossil-fuel fired steam boilers for 

which construction began after June 19, 1984. 

Dc Subpart Dc is the Standards of Performance for small industrial-commercialinstitutional steam generating units. 

N 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 
15

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

4. If there is no standard for nitrogen oxide emissions, report “NA” for line 3, column (c), and skip 

the remaining column (c) items. 

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 Unit of Measurement 

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, 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 Unit of Measurement

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, COMMENTS) 

8. For line 5, Unit of Measurement Specified, column (c), Nitrogen Oxides, select from the 

following unit of measurement codes (NP* is the preferred measurement): 

Code Unit of Measurement

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, COMMENTS) 
16

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

9. For line 6, Time Period Specified, select from the following codes to indicate the period over 

which measurements were averaged: 

Code Time Period 

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 Weekly average 

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, COMMENTS) 

10. 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. 

11. 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 Strategy for Compliance 

BO Burner out of service 

FR Flue gas recirculation 

LA Low excess air 

LN Low nitrogen oxide burner 

MS Currently meeting standard 

NC No plans to control 

OV Overfire air 

SE Seeking revision of governing regulation 

OT Other (specify in SCHEDULE 7, COMMENTS) 
17

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

12. 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 Strategy for Compliance (Sulfur Dioxide) 

CF Fluidized Bed Combustor 

CU Control unit under Phase I extension plan 

IF Install flue gas desulfurization unit (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 

OT Other (specify in SCHEDULE 7, COMMENTS) 

Code Strategy for Compliance (Nitrogen Oxides) 

AA Advanced Overfire Air 

BF Biased Firing (alternative burners) 

CF Fluidized Bed Combustor 

FR Flue Gas Recirculation 

FU Fuel Reburning 

LA Low Excess Air 

LN Low NOx Burner 

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 

UE Decrease utilization - rely on energy conservation and/or improved 

efficiency 

OT Other (specify in SCHEDULE 7, COMMENTS) 
18

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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 Boiler Status 

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 (on order and expected to go into commercial service within 5 

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) 

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. 
19

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

3. For line 5, Boiler Manufacturer, select one code from the following boiler manufacturers’ 

codes: 

Code Boiler Manufacturer 

AI Aalborg Industries 

AL Alstrom 

AS American Shack 

AT Applied Thermal Systems 

BR BROS 

BW Babcock and Wilcox 

DJ De John Coen bv 

CE Combustion Engineering 

CN Coen 

DL Deltak 

DS Doosan 

EC Econotherm 

ER Erie City Iron Works 

ET Entek 

FW Foster Wheeler 

GE General Electric 

GT Gotaverken 

HT Hitachi 

ID Indeck 

IH Ishikawajima-Harima Heavy Industries 

IN Innovative Steam Technology 

KL Keeler Dorr Oliver 

KP Kvaerner Pulping 

KW Kawasaki Heavy Industries 

ME Mitchell Engineering 

NB Nebraska Boiler 

NM NEM 

NT Nooter/Erickson 

PB Peabody 

PR Pyro Power 

RS Riley Stoker 

ST Sterling 

TM Tampell 

TS Toshiba 

VO Vogt Machine Company/Vogt Power 

WE Westinghouse 

WG Wiegl Engineering 

WI Wickes 

ZN Zurn 

OT Other (specify in SCHEDULE 7, COMMENTS) 
20

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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

Firing Type Description 

AF Arch firing 

CB Cell Burner 

CF Concentric Firing 

CY Cyclone firing 

DB Duct burner 

FB Fluidized bed firing 

FF Front firing 

OF Opposed firing 

RF Rear firing 

SF Side firing 

SS Spreader stoker 

TF Tangential firing 

VF Vertical firing (burners mounted on furnace ceiling) 

OT 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. 
21

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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 Control Status 

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 during the ozone season (May through September) 

PL Planned (on order and expected to go into commercial service within 5 

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) 

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 Control Process 

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 

NA Not Applicable 

NH3 Ammonia Injection 

OV Overfire Air 

SC Slagging 

SN Selective Noncatalytic Reduction 

SR Selective Catalytic Reduction 

STM Steam Injection 

OT Other (specify in SCHEDULE 7, COMMENTS) 
22

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4. For line 4, Manufacturer of Low Nitrogen Oxide Control Burners, select from the following 

low nitrogen oxide control burner manufacturers: 

Code Manufacturer 

AB Advanced Burner Technologies 

ABB ABB 

AC Advanced Combustion Technology 

AL Alstom 

AP AirPol 

AT Applied Thermal Systems 

AU Applied Utility Systems (AUS) 

AZ Alzeta 

BC Babcock Borsig Power 

BM Bloom 

BMD Burns & McDonnell 

BW Babcock and Wilcox 

CE Combustion Engineering 

CM Combustion Components Associates Inc 

CN Coen 

CSI Combustion Solutions Inc. 

CT Callidus Technologies 

DB Deutsche-Babcock 

DD Damper Design Inc 

DQ Duquesne Light Company & Energy Systems Associates 

DV Davis 

DX Deltex 

EA Eagle Air 

EG Energy and Environmental Research Corp (EER) 

EL Electric power Technologies 

EP EPRI 

ET Entropy Technology and Environmental Construction Corp (ETEC) 

FB Faber 

FN Forney 

FT Fuel Tech Inc 

FW Foster Wheeler 

GE General Electric 

GR GE Energy and Environmental Research Corp (GEEER) 

HL Holman 

HT Hitachi 

IC International Combustion Limited 

ID Indeck 

IH In house 

JZ John Zink Todd Combustion/Todd Combustion 

KL Keeler Dorr Oliver 

MB Mitsui-Babcock 

MI Mitsubishi Industries 

MT Mobotec 

NA Not Applicable 

NB Nebraska Boiler Company 

NC Natcom, Inc 

NE NEI 

NL Noell, Inc 

PA Procedair 

PB Peabody 

PS Peerless Manufacturing Company 
23

U.S. Department of Energy 

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Code Manufacturer 

PL Pillard 

PX Phoenix Combustion 

RD Rodenhuis and Verloop 

RI Riley 

RJ RJM 

RR Rolls Royce 

RS Riley Stoker/Riley Power 

RV RV Industries 

SC Southern Company 

SW Siemans-Westinghouse 

TC Todd Combustion 

TEC Thermal Equipment Corporation 

TM Tampella 

TS Toshiba 

WG Weigel Engineering 

ZC Zeeco 

OT 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.

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 System Status 

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 (on order and expected to go into commercial service 

within 5 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) 
24

U.S. Department of Energy 

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ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

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Approval Expires: 12/31/2010

3. For line 4, Type of Cooling System, select from the following cooling system codes (separate 

multiple entries (up to four) with commas): 

Code Cooling System Description 

DC Dry (air) cooling System 

HRC Hybrid: recirculating cooling pond(s) or canal(s) with dry cooling 

HRF Hybrid: recirculating with forced draft cooling tower(s) with dry 

cooling 

HRI Hybrid: recirculating with induced draft cooling tower(s) with dry 

cooling 

OC Once through with cooling pond(s) or canal(s) 

OF Once through, fresh water 

OS Once through, saline water 

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) 

OT 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): 

Code Type of Towers 

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 

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”: 
25

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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 Status 

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 5 

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). 

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): 

Code Description 

BS Baghouse, shake and deflate 

BP Baghouse, pulse 

BR Baghouse, 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 

WS Wet Scrubber 

OT Other (specify in a footnote on SCHEDULE 7 of the form). 

 

3. 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. 

4. 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) 
26

U.S. Department of Energy 

Energy Information Administration 

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ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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 Status 

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 (on order and expected to go into commercial service within 5 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 by available for service) 

SC Cold Standby (Reserve); deactivated. Usually requires 3 to 6 months to activate 

TS 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 Type of Unit 

BR Jet Bubbling Reactor 

CD Circulating Dry Scrubber 

DP Dry Powder Injection type 

MA Mechanically aided type 

PA Packed type 

SD Spray dryer type 

SP Spray type 

TR Tray type 

VE Venture type 

 

3. For line 5, Type of Sorbent, select from the following sorbent codes (separate multiple entries 

(up to four) with commas): 

Code Type of Sorbent 

AF Alkaline fly ash 

CC Calcium carbide slurry 

CEF CE filtrate 

CSH Caustic sodium hydroxide 

DB Dibasic acid 

DL Dolomitic limestone 

LA Lime and alkaline fly ash 

LF Limestone and alkaline fly ash 

LI Lime 

LS Limestone 

MO Magnesium oxide 

SA Soda ash 

SC Sodium carbonate 

SL Soda liquid 

SS Sodium sulfite 

OT Other (specify in SCHEDULE 7) 
27

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

4. For line 7, Flue Gas Desulfurization Unit Manufacturer, select one code from the following 

flue gas desulfurization unit manufacturer codes: 

Code Manufacturer 

AA Advanced Air Technologies 

ABB ABB Environmental Systems 

AL Alstom 

AM American Air Filter 

AP Airpol 

API Air Pollution Industries 

AX Amerex Industries 

BE Bact Engineering 

BI Bleco Industries 

BL Bechtel Corporation 

BMC Burns and McDonnell 

BO Bionomics 

BPC Belco Pollution Control 

BPE Babcock Power Environmental Inc (BPEI) 

BT Belco Technologies 

BW Babcock and Wilcox 

CA Chiyoda 

CC Chemico 

CE Combustion Engineering 

CO Combustion Equipment 

DA Delta Conveying Systems 

DC Ducon 

DM Davey McKee 

EE Environmental Engineering 

EEC Environmental Elements Corporation 

EI Entoleter Inc 

FL Flakt, Inc 

FM FMC 

FW Foster Wheeler 

GE General Electric 

GF Grafwolff 

HA Hamon 

IH In House Design 

JO Joy Manufacturing 

KC Korea Cottrell 

KE M.W. Kellogg 

KR Krebs Equipment 

LLB Lurgi Lentjes Bischoff 

MB Mobotek 

MC Macrotek 

MG McGill Air Clean 

MI Mitsubishi Industry 

MX Marselex 

NPA Neptune Airpol 

NSP NSP 

PA Procedair 

PB Peabody 

PR Pyro Power 

PU Pure Air 

RC Research Cottrell 

RS Riley Stoker 

SHU Saarberg-Holter Umwelttechnick GmbH 

SK Schenck Weigh Feeders 

TC Turbosonic 

TH Thyssen/CEA 

TK Turbotak 
28

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009)

ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Code Manufacturer

TP Tempala Power 

UE Utility Engineering 

UM United McGill 

UO Universal Oil Products 

WAPC Wheelabrator Air Pollution Control 

ZU Zurn 

OT 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 Code 

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 5 

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). 

5. For lines 7 and 8, the rate should be approximately equal to the cross-sectional area multiplied 

by the velocity, multiplied by 60. 

6. For lines 13 and 14, seasonal average flue gas exit temperatures should be reported in 
29

U.S. Department of Energy 

Energy Information Administration 

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ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

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. 

7. For line 15, Source, enter “M” for measured or “E” for estimated. 

8. For lines 16 and 17, Stack Location, enter the latitude and longitude in degrees, minutes, and 

seconds. 

9. 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. 
30

U.S. Department of Energy 

Energy Information Administration 

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ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

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Approval Expires: 12/31/2010

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 

Higher Heating Value”

Range (Million Btu per 

Energy Unit of Fuel 

Source 

Code Unit Label

MMBtu 

Lower

MMBtu 

Upper Energy Source Description

Fossil Fuels 

BIT tons 20 29 Anthracite Coal and Bituminous Coal 

LIG tons 10 14.5 Lignite Coal 

Coal and 

Coal 

Synfuel 

SC 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. 

SUB tons 15 20 Subbituminous Coal 

WC tons 6.5 16 Waste/Other Coal. Including anthracite 

culm, bituminous gob, fine coal, lignite 

waste, waste coal. 

DFO barrels 5.5 6.2 Distillate Fuel Oil. Including Diesel, No. 

1, No. 2, and No. 4 Fuel Oils. 

JF barrels 5 6 Jet Fuel 

KER barrels 5.6 6.1 Kerosene 

Petroleum PC tons 24 30 Petroleum Coke 

Products RFO barrels 5.8 6.8 Residual Fuel Oil. Including No. 5, No. 

6 Fuel Oils, and Bunker C Fuel Oil. 

WO barrels 3.0 5.8 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. 

BFG Mcf 0.07 0.12 Blast Furnace Gas 

Natural 

Gas 

NG Mcf 0.8 1.1 Natural Gas 

And Other 

Gases OG Mcf 0.32 3.3 Other Gas. Specify in SCHEDULE 7, 

COMMENTS. 

PG Mcf 2.5 2.75 Gaseous Propane 

SG Mcf 0.2 1.1 Synthetic Gas, other than coal-derived 

SGC Mcf 0.2 0.3 Synthetic Gas, derived from coal 
31

U.S. Department of Energy 

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Approval Expires: 12/31/2010

Higher Heating Value”

Range (Million Btu per 

Energy Unit of Fuel

Source 

Code Unit Label

MMBtu 

Lower 

MMBtu 

Upper Energy Source Description 

Renewable Fuels 

AB tons 9 18 Agricultural Crop 

Byproducts/Straw/Energy Crops 

MSW tons 9 12 Municipal Solid Waste 

OBS tons 8 25 Other Biomass Solids 

Specify in SCHEDULE 7, COMMENTS.

Solid 

Renewable 

Fuels 

WDS tons 7 18 Wood/Wood Waste Solids. Including 

paper pellets, railroad ties, utility poles, 

wood chips, bark, & wood waste solids. 

OBL barrels 3.5 4.0 Other Biomass Liquids. Specify in 

SCHEDULE 7, COMMENTS. 

SLW tons 10 16 Sludge Waste 

BLQ tons 10 14 Black Liquor 

Liquid 

Renewable 

Fuels 

WDL barrels 8 14 Wood Waste Liquids excluding Black 

Liquor, includes red liquor, sludge wood, 

spent sulfite liquor, and other woodbased liquids 

Gaseous LFG Mcf 0.3 0.6 Landfill gas 

Renewable 

Fuels 

OBG Mcf 0.36 1.6 Other Biomass Gas, includes digestor 

gas, methane, and other biomass gases.

Specify in SCHEDULE 7, COMMENTS.

SUN N/A 0 0 Solar 

WND N/A 0 0 Wind 

GEO N/A 0 0 Geothermal 

Other 

Renewable 

Energy 

Sources WAT N/A 0 0 Water at a conventional hydroelectric 

turbine 

All Other Energy Sources 

PUR N/A 0 0 Purchased Steam 

All Other 

Energy 

Sources 

WH N/A 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. 

TDF tons 16 32 Tire-derived Fuels 

NUC Nuclear including Uranium, Plutonium, 

Thorium 

OTH N/A 0 0 Specify in SCHEDULE 7, COMMENTS.
32

U.S. Department of Energy 

Energy Information Administration 

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ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Table 2. Commonly Used North American Industry Classification System (NAICS) 

Codes 

Code Description 

AGRICULTURE, FORESTRY, AND FISHING 

111 Agriculture production - crops 

112 Agriculture production, livestock and animal specialties 

113 Forestry 

114 Fishing, hunting, and trapping 

115 Agricultural services 

MINING 

211 Oil and gas extraction 

2121 Coal mining 

2122 Metal mining 

2123 Mining and quarrying of nonmetallic minerals except fuels 

23 CONSTRUCTION 

MANUFACTURING 

311 Food and kindred products 

3122 Tobacco products 

314 Textile and mill products 

315 Apparel and other finished products made from fabrics and similar materials 

316 Leather and leather products 

321 Lumber and wood products, except furniture 

322 Paper and allied products (other than 322122 or 32213) 

322122 Paper mills, except building paper 

32213 Paperboard mills 

323 Printing and publishing 

324 Petroleum refining and related industries (other than 32411) 

32411 Petroleum refining 

325 Chemicals and allied products (other than 325188, 325211, 32512, or 325311) 

32512 Industrial organic chemicals 

325188 Industrial inorganic chemicals 

325211 Plastic materials and resins 

325311 Nitrogenous fertilizers 

326 Rubber and miscellaneous plastic products 

327 Stone, clay, glass, and concrete products (other than 32731) 

32731 Cement, hydraulic 

331 Primary metal industries (other than 331111 or 331312) 

331111 Blast furnaces and steel mills 

331312 Primary aluminum 

332 Fabricated metal products, except machinery and transportation equipment 

333 Industrial and commercial equipment and components except computer 

equipment 

3345 Measuring, analyzing, and controlling instruments, photographic, medical, and 

optical goods, watches and clocks 

335 Electronic and other electrical equipment and components except computer 

equipment 

336 Transportation equipment 

337 Furniture and fixtures 

339 Miscellaneous manufacturing industries 

TRANSPORTATION AND PUBLIC UTILITIES 

482 Railroad transportation 

485 Local and suburban transit and interurban highway passenger transport 

484 Motor freight transportation and warehousing 

22 Electric, gas, and sanitary services 
33

Code Description 

2212 Natural gas transmission 

2213 Water supply 

22131 Irrigation systems 

22132 Sewerage systems 

481 Transportation by air 

482 Railroad Transportation 

483 Water transportation 

484 Motor freight transportation and warehousing 

485 Local and suburban transit and interurban highway passenger transport 

486 Pipelines, except natural gas 

487 Transportation services 

513 Communications 

562212 Refuse systems 

421 to 422 WHOLESALE TRADE 

441 to 454 RETAIL TRADE 

521 to 533 FINANCE, INSURANCE, AND REAL ESTATE 

SERVICES 

512 Motion pictures 

514 Business services 

514199 Miscellaneous services 

541 Legal services 

561 Engineering, accounting, research, management, and related services 

611 Education services 

622 Health services 

624 Social services 

712 Museums, art galleries, and botanical and zoological gardens 

713 Amusement and recreation services 

721 Hotels 

811 Miscellaneous repair services 

8111 Automotive repair, services, and parking 

812 Personal services 

813 Membership organizations 

814 Private Households 

92 PUBLIC ADMINISTRATION 
34

U.S. Department of Energy 

Energy Information Administration 

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ANNUAL ELECTRIC GENERATOR 

REPORT INSTRUCTIONS 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

GLOSSARY The glossary for this form is available online at the following URL: 

http://www.eia.doe.gov/glossary/index.html

SANCTIONS 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. 

REPORTING 

BURDEN

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. 

PROVISIONS 

REGARDING 

CONFIDENTIALITY 

OF INFORMATION 

Information reported on Form EIA-860 will be treated as non-sensitive and may be publicly released 

in identifiable form except as noted below. 

The information reported for the data element “Tested Heat Rate” contained on SCHEDULE 3. 

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 

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. 
35

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT 

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010 

NOTICE: This report is mandatory under the Federal Energy Administration Act of 1974 (Public Law 93-275). Failure to 

comply may result in criminal fines, civil penalties and other sanctions as provided by law. For further information 

concerning sanctions and data protections see the provision on sanctions and the provision concerning the confidentiality of 

information in the instructions. Title 18 USC 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. 

SCHEDULE 1. IDENTIFICATION 

Survey Contact

First Name:________________ Last Name:_________________ 

Title:______________________________ Address:___________________ 

Telephone (include extension):______________ Fax:__________________ 

E-mail:_______________________________ 

Supervisor of Contact Person for Survey

First Name:____________________ Last Name:_____________________ 

Title:___________________________ Address:_______________________ 

Telephone (include extension):______________ Fax:__________________ 

E-mail:________________________________ 

Report For

Operator Name:_____________________________________________

Operator ID:_________________ 

Reporting as of December 31 Year:________________ 

Operator and Preparer Information

Legal Name of Operator: ________________________________________________ 

Current Address of Principal Business 

Office of Plant Operator: ________________________________________________ 

Preparer's Legal Name (If Different 

From Operator’s Legal Name): ________________________________________________ 

Current Address of Preparer's Office 

(If Different From Current Address of 

Principal Business Office of Entity): ________________________________________________ 

Is the Operator an Electric Utility? [ ] Yes [ ] No 

For questions or additional information about the Form EIA-860, contact the Survey Managers: 

Patricia Hutchins 

Telephone Number: (202) 586-1029 

FAX Number: (202) 287-1960 

E-mail: Patricia.Hutchins@eia.doe.gov
36

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 2. POWER PLANT DATA 

(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS) 

LINE PLANT 1. (EXISTING OR PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS) 

1 Plant Name EIA Plant Code 

2 Street Address 

3 County Name City Name: 

4 State 

5 Zip Code 

6 Latitude (Degrees, Minutes, Seconds) Longitude (Degrees, Minutes, Seconds) 

7 Enter Datum for Latitude and Longitude, if Known; Otherwise Enter “UNK” 

8 NERC Region 

9 Name of Water Source (For Purpose of Cooling or Hydroelectric) 

10 Steam Plant Status [ ] existing [ ] planned [ ] retired 

11 Steam Plant Type [ ] Organic 100 MW or more generator nameplate capacity [ ] Organic 10 

MW or Greater to Under 100 MW generator nameplate capacity 

12 Primary Purpose of the Plant (North American Industry Classification System Code) 

13 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) 

Cogenerator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

14 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Small 

Power Producer status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

15 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Exempt 

Wholesale Generator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

16 

Owner of Transmission and/or Distribution Facilities: Enter the name of the owner of the transmission 

or distribution facilities to which the plant is interconnected and the grid voltage (in kilovolts) at the 

point of interconnection. 

__________________________________________________________________ 

Grid Voltage (kV): 

 
37

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 2. POWER PLANT DATA 

(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS) 

LINE PLANT 2. (EXISTING OR PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS)

1 Plant Name EIA Plant Code

2 Street Address 

3 County Name City Name: 

4 State 

5 Zip Code 

6 Latitude (Degrees, Minutes, Seconds) Longitude (Degrees, Minutes, Seconds) 

7 Enter Datum for Latitude and Longitude, if Known; Otherwise Enter “UNK” 

8 NERC Region 

9 Name of Water Source (For Purpose of Cooling or Hydroelectric) 

10 Steam Plant Status [ ] existing [ ] planned [ ] retired 

11 Steam Plant Type [ ] Organic 100 MW or more generator nameplate capacity [ ] Organic 10 

MW or Greater to Under 100 MW generator nameplate capacity 

12 Primary Purpose of the Plant (North American Industry Classification System Code) 

13 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) 

Cogenerator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

14 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Small 

Power Producer status? If Yes, provide all QF docket number(s). Separate by using a comma. 

_________________________________________ 

[ ] Yes [ ] No 

15 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Exempt 

Wholesale Generator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

16 

Owner of Transmission and/or Distribution Facilities: Enter the name of the owner of the transmission or 

distribution facilities to which the plant is interconnected and the grid voltage (in kilovolts) at the point of 

interconnection. 

__________________________________________________________________ 

Grid Voltage (kV): 

 
38

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 2. POWER PLANT DATA 

(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS) 

LINE PLANT 3. (EXISTING OR PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS) 

1 Plant Name EIA Plant Code 

2 Street Address 

3 County Name City Name: 

4 State 

5 Zip Code 

6 Latitude (Degrees, Minutes, Seconds) Longitude (Degrees, Minutes, Seconds) 

7 Enter Datum for Latitude and Longitude, if Known; Otherwise Enter “UNK” 

8 NERC Region 

9 Name of Water Source (For Purpose of Cooling or Hydroelectric) 

10 Steam Plant Status [ ] existing [ ] planned [ ] retired 

11 Steam Plant Type [ ] Organic 100 MW or more generator nameplate capacity [ ] Organic 10 

MW or Greater to Under 100 MW generator nameplate capacity 

12 Primary Purpose of the Plant (North American Industry Classification System Code) 

13 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Cogenerator 

status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

14 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Small Power 

Producer status? If Yes, provide all QF docket number(s). Separate by using a comma. 

_________________________________________ 

[ ] Yes [ ] No 

15 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Exempt 

Wholesale Generator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

16 

Owner of Transmission and/or Distribution Facilities: Enter the name of the owner of the transmission or 

distribution facilities to which the plant is interconnected and the grid voltage (in kilovolts) at the point of 

interconnection. 

 __________________________________________________________________ 

Grid Voltage (kV): 

 
39

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 2. POWER PLANT DATA 

(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS)

LINE PLANT 4. (EXISTING OR PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS)

1 Plant Name EIA Plant Code 

2 Street Address 

3 County Name City Name: 

4 State 

5 Zip Code 

6 Latitude (Degrees, Minutes, Seconds) Longitude (Degrees, Minutes, Seconds) 

7 Enter Datum for Latitude and Longitude, if Known; Otherwise Enter “UNK” 

8 NERC Region 

9 Name of Water Source (For Purpose of Cooling or Hydroelectric) 

10 Steam Plant Status [ ] existing [ ] planned [ ] retired 

11 Steam Plant Type [ ] Organic 100 MW or more generator nameplate capacity [ ] Organic 10 

MW or Greater to Under 100 MW generator nameplate capacity 

12 Primary Purpose of the (North American Industry Classification System Code)

13 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Cogenerator 

status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

14 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Small Power 

Producer status? If Yes, provide all QF docket number(s). Separate by using a comma. 

_________________________________________ 

[ ] Yes [ ] No 

15 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Exempt 

Wholesale Generator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

16 

Owner of Transmission and/or Distribution Facilities: Enter the name of the owner of the transmission or 

distribution facilities to which the plant is interconnected and the grid voltage (in kilovolts) at the point of 

interconnection. 

__________________________________________________________________ 

Grid Voltage (kV): 

 
40

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 2. POWER PLANT DATA 

(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS) 

LINE PLANT 5. (EXISTING OR PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS) 

1 Plant Name EIA Plant Code 

2 Street Address 

3 County Name City Name: 

4 State 

5 Zip Code 

6 Latitude (Degrees, Minutes, Seconds) Longitude (Degrees, Minutes, Seconds) 

7 Enter Datum for Latitude and Longitude, if Known; Otherwise Enter “UNK”

8 NERC Region 

9 Name of Water Source (For Purpose of Cooling or Hydroelectric) 

10 Steam Plant Status [ ] existing [ ] planned [ ] retired 

11 Steam Plant Type [ ] Organic 100 MW or more generator nameplate capacity [ ] Organic 

10 MW or Greater to Under 100 MW generator nameplate capacity 

12 Primary Purpose of the Plant (North American Industry Classification System Code) 

13 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) 

Cogenerator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

14 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Small 

Power Producer status? If Yes, provide all QF docket number(s). Separate by using a comma. 

_________________________________________ 

[ ] Yes [ ] No 

15 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Exempt 

Wholesale Generator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

16 

Owner of Transmission and/or Distribution Facilities: Enter the name of the owner of the transmission 

or distribution facilities to which the plant is interconnected and the grid voltage (in kilovolts) at the 

point of interconnection. 

__________________________________________________________________ 

Grid Voltage (kV): 

 
41

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 2. POWER PLANT DATA 

(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS)

LINE PLANT 6. (EXISTING OR PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS)

1 Plant Name EIA Plant Code 

2 Street Address 

3 County Name City Name: 

4 State 

5 Zip Code 

6 Latitude (Degrees, Minutes, Seconds) Longitude (Degrees, Minutes, Seconds) 

7 Enter Datum for Latitude and Longitude, if Known; Otherwise Enter “UNK” 

8 NERC Region 

9 Name of Water Source (For Purpose of Cooling or Hydroelectric) 

10 Steam Plant Status [ ] existing [ ] planned [ ] retired 

11 Steam` Plant Type [ ] Organic 100 MW or more generator nameplate capacity [ ] Organic 

10 MW or Greater to Under 100 MW generator nameplate capacity 

12 Primary Purpose of the Plant (North American Industry Classification System Code) 

13 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) 

Cogenerator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

14 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Small 

Power Producer status? If Yes, provide all QF docket number(s). Separate by using a comma. 

_________________________________________ 

[ ] Yes [ ] No 

15 

Does this plant have Federal Energy Regulatory Commission (FERC) Qualifying Facility (QF) Exempt 

Wholesale Generator status? If Yes, provide all QF docket number(s). Separate by using a comma. 

________________________________________ 

[ ] Yes [ ] No 

16 

Owner of Transmission and/or Distribution Facilities: Enter the name of the owner of the transmission 

or distribution facilities to which the plant is interconnected and the grid voltage (in kilovolts) at the 

point of interconnection. 

__________________________________________________________________ 

Grid Voltage (kV): 

 
42

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 3. GENERATOR INFORMATION 

(EXISTING GENERATORS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 5 YEARS) 

LINE SCHEDULE 3. PART A. GENERATOR INFORMATION – GENERATORS 

(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT) 

1 Plant Name 

2 EIA Plant Code 

Generator 

(a) 

Generator 

(b)

Generator 

(c)

3 Operator’s Generator Identification 

4 

Associated Boiler Identifications for 

organic-fueled steam generators, 

including heat recovery generators 

with duct-firing, (for plants with a 

total generator nameplate capacity 

of 10 MW or greater) 

1 ____ 5 ___ 

2 ____ 6 ___ 

3 ____ 7 ___ 

4 ____ 8 ___ 

1 ____ 5 ___ 

2 ____ 6 ___ 

3 ____ 7 ___ 

4 ____ 8 ___ 

1 ____ 5 ___ 

2 ____ 6 ___ 

3 ____ 7 ___ 

4 ____ 8 ___ 

5 Prime Mover Code 

6 Unit Code (Required for combined 

cycle generators) 

7 Ownership Code 

8 Is this generator an electric utility or 

non-utility generator? 

[ ] Electric Utility 

 [ ] Non-Utility 

[ ] Electric Utility 

 [ ] Non-Utility 

[ ] Electric Utility 

 [ ] Non-Utility 

9 Date of Sale If Sold (MM-YYYY) 

10 Can This Generator Deliver Power to 

the Transmission Grid? [ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

11 

For Combined-cycle Steam 

Turbines, (prime mover = CA, CS or 

CC) does unit have duct-burners?

[ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No 
43

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:____________________________________ Operator ID:___________ 

Plant Name:_______________________________________ Plant Code:___________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 3. PART B. GENERATOR INFORMATION – EXISTING GENERATORS 

(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT) 

Generator (a) Generator (b) Generator (c)

1 Generator Nameplate 

Capacity (Megawatts) 

 

Summer 2 Net Capacity 

(Megawatts) Winter 

Lagging 

3a 

Reactive Power 

Output (MVAR) 

Corresponding to 

Net Summer 

Capacity 

For generators with 

nameplate capacity 

10 MW or greater 

Leading 

Lagging 

3b 

Reactive Power 

Output (MVAR) 

Corresponding to 

Net Winter Capacity 

For generators with 

nameplate capacity 

10 MW or greater 

Leading 

4 Status Code 

5 

If Status Code is Standby, 

can the generator be 

synchronized to the grid? 

[ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

6 Initial Date of Operation (MMYYYY) 

 

7 Retirement Date (MM-YYYY) 

8 

Is this generator associated 

with a Combined Heat and 

Power system (fuel input is 

used to produce both 

electricity and useful thermal 

output)? 

If Yes: Is this generator part 

of a topping cycle or a 

bottoming cycle? 

[ ] Yes [ ] No 

[ ] Topping [ ] Bottoming

[ ] Yes [ ] No 

[ ] Topping [ ] Bottoming 

[ ] Yes [ ] No 

[ ] Topping [ ] Bottoming

ENERGY SOURCES 

9 Predominant Energy Source 

9a 

If coal-fired or petroleum 

coke fired, check all 

combustion technologies 

that apply to the associated 

boiler(s) and steam 

conditions 

[ ] Pulverized coal 

[ ] Fluidized Bed 

[ ] Sub-critical 

[ ] Super-critical 

[ ] Ultra super-critical 

[ ] Carbon-capture 

[ ] Pulverized coal 

[ ] Fluidized Bed 

[ ] Sub-critical 

[ ] Super-critical 

[ ] Ultra super-critical 

[ ] Carbon-capture 

[ ] Pulverized coal 

[ ] Fluidized Bed 

[ ] Sub-critical 

[ ] Super-critical 

[ ] Ultra super-critical 

[ ] Carbon-capture 

10 

Start-up and flame 

stabilization energy sources 

(prime mover = ST (steam 

units only) 

 

11 Second Most Predominant 

Energy Source 
44

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:____________________________________ Operator ID:___________ 

Plant Name:_______________________________________ Plant Code:___________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 3. PART B. GENERATOR INFORMATION – EXISTING GENERATORS 

(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT) 

Generator (a) Generator (b) Generator (c)

a b c d a b c d a b c d 

12 

Other Energy Sources Enter 

up to four codes in order of 

expected quantity used 

(measured in BTUs). 

13 

Is this generator part of a 

Solid Fuel Gasification 

system? 

[ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

14 

If Energy Source is Wind, 

 Enter the Number of 

Turbines 

 

15 Tested Heat Rate 

(Btu/Kilowatthour) 

 

16 

Fuel Used for Heat Rate Test 

(enter fuel code or M for 

multiple fuels) 

PROPOSED CHANGES TO EXISTING GENERATORS (WITHIN THE NEXT 5 YEARS)

17a 

Are there any planned 

modifications to this 

generator, including 

retirement? 

[ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

 

17b 

Planned uprates: 

1. Incremental Net summer 

capacity (MW) 

2. Incremental Net winter 

capacity (MW) 

3. Planned Effective Date 

MM-YYYY 

 

 

17c 

Planned derates: 

1. Incremental Net summer 

capacity (MW) 

2. Incremental Net winter 

capacity (MW) 

3. Planned Effective Date 

MM-YYYY 

 

 

17d 

Planned Repowering: 

1. New Prime Mover 

2. New Energy Source 

3. Planned Effective Date 

MM-YYYY 

 

[ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

17e 

Other Modifications? (explain 

in Notes) 

Planned Effective Date MMYYYY 
45

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:____________________________________ Operator ID:___________ 

Plant Name:_______________________________________ Plant Code:___________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 3. PART B. GENERATOR INFORMATION – EXISTING GENERATORS 

(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT) 

Generator (a) Generator (b) Generator (c)

17f 

Planned Generator 

Retirement Planned Effective 

Date MM-YYYY 

 

FUEL SWITCHING AND CO-FIRING CAPABILITY 

[ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

18 

Ability to use multiple fuels 

Does the combustion system that 

powers this generator have 1) the 

regulatory permits, and 2), the 

equipment (including fuel storage 

facilities), in working order, 

necessary to either co-fire fuels 

or to fuel switch? 

If No, skip to SCHEDULE 3 

Part C. 

If No, skip to SCHEDULE 3 

Part C. 

If No, skip to SCHEDULE 3 

Part C. 

19 

Ability to Co-Fire 

Can the unit co-fire fuels? 

(Note: co-firing excludes the 

limited use of an alternative 

fuel for startup or flame 

stabilization.) 

[ ] Yes [ ] No

If No, skip to line 23. 

[ ] Yes [ ] No

If No, skip to line 23. 

[ ] Yes [ ] No

If No, skip to line 23. 

a b c a b c a b c 

 

d e f d e f d e f 

20 

Fuel Options for Co-Firing 

Enter the codes for up to six 

fuels that can be co-fired: 

 

21 

Ability to Co-Fire Oil and 

Natural Gas Can the unit co-fire 

fuel oil with natural gas?

[ ] Yes [ ] No

If No, skip to line 23. 

[ ] Yes [ ] No

If No, skip to line 23. 

[ ] Yes [ ] No

If No, skip to line 23. 

22 

Ability to Co-Fire Oil 

a. Can the unit run on 100% oil? 

If Yes, skip to Line 23. 

If No, what is the: 

 Maximum oil heat input (% 

of MMBtus) when co-firing with 

natural gas? 

 Maximum output (net 

summer MW) achievable, when 

making the maximum use of oil 

and co-firing natural gas? 

[ ] Yes [ ] No

________ % 

________ MW 

[ ] Yes [ ] No

________ % 

________ MW 

[ ] Yes [ ] No

________ % 

________ MW 

23 Ability to Fuel Switch 

Can the unit fuel switch?

[ ] Yes [ ] No 

If No, skip to Sch. 3 Part C. 

[ ] Yes [ ] No 

If No, skip to Sch. 3 Part C. 

[ ] Yes [ ] No 

If No, skip to Sch. 3 Part C. 
46

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:____________________________________ Operator ID:___________ 

Plant Name:_______________________________________ Plant Code:___________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 3. PART B. GENERATOR INFORMATION – EXISTING GENERATORS 

(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT) 

Generator (a) Generator (b) Generator (c)

24 

Oil – Natural Gas Fuel 

Switching 

a. Can the unit switch between oil 

and natural gas? 

If No, skip to line 26. 

If Yes: 

 Can the unit switch fuels 

while operating (i.e., without 

shutting down the unit)? 

 Net summer MW achievable 

when running on natural gas: 

 Net summer MW achievable 

when running on fuel oil:

 Time Required to Switch this 

unit from using 100 percent 

natural gas to using 100 percent 

oil (check one box): 

[ ] Yes [ ] No 

[ ] Yes [ ] No 

_______ MW 

_______ MW 

[ ] 0 to 6 hours 

[ ] over 6 to 24 hours 

[ ] over 24 to 72 hours 

[ ] over 72 hours. 

[ ] Unknown or uncertain 

[ ] Yes [ ] No 

[ ] Yes [ ] No 

_______ MW 

_______ MW 

[ ] 0 to 6 hours 

[ ] over 6 to 24 hours 

[ ] over 24 to 72 hours 

[ ] over 72 hours. 

[ ] Unknown or uncertain 

[ ] Yes [ ] No 

[ ] Yes [ ] No 

_______ MW 

_______ MW 

[ ] 0 to 6 hours 

[ ] over 6 to 24 hours 

[ ] over 24 to 72 hours 

[ ] over 72 hours. 

[ ] Unknown or uncertain 

25 

Limits on Oil-Fired 

Operation 

A. Are there factors that limit 

your ability to switch from 

Natural Gas to oil? 

If No, skip to line 26. If Yes: 

B. Check factors that apply.

[ ] Yes [ ] No 

( ) Limited on site fuel 

storage. 

( ) Air Permit limits 

( ) Other 

(explain in SCHEDULE 7) 

[ ] Yes [ ] No 

 

( ) Limited on site fuel 

storage. 

( ) Air Permit limits 

( ) Other 

(explain in SCHEDULE 7) 

[ ] Yes [ ] No 

( ) Limited on site fuel 

storage. 

( ) Air Permit limits 

( ) Other 

(explain in SCHEDULE 7) 

a b c a b c a b C 

 

d e f d e f d e f 

26 

Fuel Switching Options 

Enter the codes for up to six fuels 

that can be used as a sole source 

of fuel for this unit. 

 

 
47

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 3. PART C. GENERATOR INFORMATION – PROPOSED GENERATORS 

(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT) 

Plant Name 

EIA Plant Code 

Operator’s Generator Identification

Generator 

(a) 

Generator 

(b)

Generator 

(c)

1 Generator Nameplate Capacity 

(Megawatts) 

 

Summer 

2 Net Capacity (Megawatts) Winter 

Lagging 

3a 

Reactive Power Output 

(MVAR) Corresponding to 

Net Summer Capacity 

For generators with 

nameplate capacity 10 

MW or greater 

Leading 

Lagging 

3b 

Reactive Power Output 

(MVAR) Corresponding to 

Net Winter Capacity 

For generators with 

nameplate capacity 10 

MW or greater 

Leading 

4 Status Code 

5 Planned Original Effective Date (MMYYYY) 

6 Planned Current Effective Date (MMYYYY) 

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)? 

[ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No 

8 Will this generator be part of a Solid 

Fuel Gasification system? [ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No 

 9 

Is this generator part of a site that was 

previously reported as indefinitely 

postponed or cancelled? 

[ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No 

PLANNED ENERGY SOURCES 

10 Expected Predominant Energy Source 

11 

If coal-fired or petroleum coke fired, 

check all combustion technologies 

that apply to the associated boiler(s) 

and steam conditions 

[ ] Pulverized coal 

[ ] Fluidized Bed 

[ ] Sub-critical 

[ ] Super-critical 

[ ] Ultra super-critical 

[ ] Carbon-capture 

[ ] Pulverized coal 

[ ] Fluidized Bed 

[ ] Sub-critical 

[ ] Super-critical 

[ ] Ultra super-critical 

[ ] Carbon-capture 

[ ] Pulverized coal 

[ ] Fluidized Bed 

[ ] Sub-critical 

[ ] Super-critical 

[ ] Ultra super-critical 

[ ] Carbon-capture 

12 Expected Second Most Predominant 

Energy Source 

 

a b c d a b c d a b c d 

13 

Other Energy Source Options. Enter 

up to four codes in order of expected 

quantity used (measured in Btus). 
48

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 3. PART C. GENERATOR INFORMATION – PROPOSED GENERATORS 

(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT) 

Plant Name 

EIA Plant Code 

Operator’s Generator Identification

Generator 

(a) 

Generator 

(b)

Generator 

(c)

14 If Energy Source Is Wind, Enter The 

Number Of Turbines 

 

COMBUSTIBLE FUEL CAPABILITY 

15 

Ability to use multiple fuels 

Will the combustion system that powers 

this generator have 1) the regulatory 

permits, and 2) the equipment (including 

fuel storage facilities), in working order, 

necessary to either co-fire fuels or to fuel 

switch? 

[ ] Yes [ ] No 

[ ] Undetermined 

If No or Undetermined, skip to 

Sch. 4. 

[ ] Yes [ ] No 

[ ] Undetermined 

If No or Undetermined, skip 

to Sch. 4. 

[ ] Yes [ ] No 

[ ] Undetermined 

If No or Undetermined, skip 

to Sch. 4. 

16 

Ability to Co-Fire 

Will the unit be able to co-fire fuels? 

(Note: co-firing excludes the limited use 

of an alternative fuel for startup or flame 

stabilization.)

[ ] Yes [ ] No 

If No, skip to line 20. 

[ ] Yes [ ] No 

If No, skip to line 20. 

[ ] Yes [ ] No 

If No, skip to line 20. 

a b c a b c a b c 

d e f d e f d e f 

17 

Fuel Options for Co-Firing 

Enter the codes for up to six fuels that 

can be co-fired: 

18 

Ability to Co-Fire Oil and Natural Gas 

Will the unit be able to co-fire fuel oil with 

natural gas? 

[ ] Yes [ ] No

If No, skip to line 20. 

[ ] Yes [ ] No

If No, skip to line 20. 

[ ] Yes [ ] No

If No, skip to line 20. 

19 

Ability to Co-Fire Oil 

a. Will the unit be able to run on 100% 

oil? 

If Yes, skip to Line 20.

If No, what is: 

 Maximum oil heat input (% of MMBtus) 

when co-firing with natural gas? 

 Maximum output (net summer MW) 

achievable, when making the maximum 

use of oil and co-firing natural gas? 

[ ] Yes [ ] No 

________ % 

________ MW 

[ ] Yes [ ] No 

________ % 

________ MW 

[ ] Yes [ ] No 

________ % 

________ MW 

20 Ability to Fuel Switch 

Will the unit be able to fuel switch? 

[ ] Yes [ ] No 

If No, skip to Sch. 4. 

[ ] Yes [ ] No 

If No, skip to Sch. 4. 

[ ] Yes [ ] No 

If No, skip to Sch. 4. 
49

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 3. PART C. GENERATOR INFORMATION – PROPOSED GENERATORS 

(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT) 

Plant Name 

EIA Plant Code 

Operator’s Generator Identification

Generator 

(a) 

Generator 

(b)

Generator 

(c)

21 

Oil – Natural Gas Fuel Switching 

a. Will the unit be able to switch between 

oil and natural gas? 

If No, skip to line 23. If Yes: 

 Will the unit be able to switch 

fuels while operating (i.e., without 

shutting down the unit)? 

 Expected net summer MW achievable 

running on natural gas:

 Expected net summer MW achievable 

running on fuel oil: 

 Expected Time Required to Switch this 

unit from using 100 percent natural gas 

to using 100 percent oil (check one box) 

[ ] Yes [ ] No 

[ ] Yes [ ] No 

_______ MW 

_______ MW 

[ ] 0 to 6 hours 

[ ] over 6 to 24 hours 

[ ] over 24 to 72 hours 

[ ] over 72 hours 

[ ] unknown or uncertain

[ ] Yes [ ] No 

[ ] Yes [ ] No 

_______ MW 

_______ MW 

[ ] 0 to 6 hours 

[ ] over 6 to 24 hours 

[ ] over 24 to 72 hours 

[ ] over 72 hours. 

[ ] unknown or uncertain

[ ] Yes [ ] No 

[ ] Yes [ ] No 

_______ MW 

_______ MW 

[ ] 0 to 6 hours 

[ ] over 6 to 24 hours 

[ ] over 24 to 72 hours 

[ ] over 72 hours 

[ ] unknown or uncertain

22 

Limits on Oil-Fired Operation 

A. Are there factors that will limit your 

ability to switch from Natural Gas to oil? 

If No, skip to line 23. If Yes: 

B. Check factors that apply. 

[ ] Yes [ ] No 

( ) Limited on site fuel 

storage. 

( ) Air Permit limits 

( ) Other 

(explain in SCHEDULE 7) 

[ ] Yes [ ] No 

( ) Limited on site fuel 

storage. 

( ) Air Permit limits 

( ) Other 

(explain in SCHEDULE 7) 

[ ] Yes [ ] No 

( ) Limited on site fuel 

storage. 

( ) Air Permit limits 

( ) Other 

(explain in SCHEDULE 7) 

a b c a b c a b c 

d e f d e f d e f 

23 

Fuel Switching Options 

Enter the codes for up to six fuels that 

can be used as a sole source of fuel for 

this unit.
50

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC GENERATOR 

REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 Year:________________ 

SCHEDULE 4. OWNERSHIP OF GENERATORS OWNED JOINTLY OR BY OTHERS 

PLANT NAME (a) 

EIA PLANT CODE (b) 

OPERATOR’S GENERATOR IDENTIFICATION (c) 

IDENTIFICATION OF OWNERS - OWNER NAME(S) AND CONTACT INFORMATION (d) 

Owner/Joint Owner 1: Name % OWNED (e): 

Street Address 

City, State and Zip Code EIA CODE: 

JOINT OWNER 2: Name % OWNED (e): 

Street Address 

City, State and Zip Code EIA CODE:

JOINT OWNER 3: Name % OWNED (e):

Street Address 

City, State and Zip Code EIA CODE:

JOINT OWNER 4: Name % OWNED (e):

Street Address 

City, State and Zip Code EIA CODE:

JOINT OWNER 5: Name % OWNED (e):

Street Address 

City, State and Zip Code EIA CODE:

JOINT OWNER 6: Name % OWNED (e):

Street Address 

City, State and Zip Code EIA CODE:

JOINT OWNER 7: Name % OWNED (e):

Street Address 

City, State and Zip Code EIA CODE:

JOINT OWNER 8: Name % OWNED (e):

Street Address 

City, State and Zip Code EIA CODE:

JOINT OWNER 9: Name % OWNED (e): 

Street Address 

City, State and Zip Code EIA CODE:

JOINT OWNER 10: Name % OWNED (e): 

Street Address 

City, State and Zip Code EIA CODE:

Total 100% 

 
51

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 5. NEW GENERATOR INTERCONNECTION INFORMATION 

(COMPLETE FOR EACH GENERATOR ENTERING SERVICE DURING CALENDAR YEAR 2007) 

LINE

Name: Name: Name: 

1 Plant Name and EIA Plant Code 

Code: Code: Code: 

2 Operator’s Generator Identification 

3 Date Of Actual Generator 

Interconnection (MM-YYYY) 

4 Date Of The Initial Interconnection 

Request (MM-YYYY) 

5 Interconnection Site Location 

(Nearest City or Town, State) 

City: 

State: 

City: 

State: 

City: 

State: 

6 Grid Voltage At The Point Of 

Interconnection (kV) 

7 

Owner Of The Transmission Or 

Distribution Facilities To Which 

Generator is Interconnected 

 

8 

Total Cost Incurred For The Direct, 

Physical Interconnection (Thousand 

$) 

 

Equipment Included In The Direct 

Interconnection Cost (Check All Of 

The Following That Apply:) 

 

a. Transmission Or Distribution Line: [ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

b. Transformer [ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

c. Protective Devices [ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

d. Substation Or Switching Station [ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

9 

e. Other Equipment (specify in 

SCHEDULE 7, Footnotes) [ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

a. Total Cost For Other Grid 

Enhancements/ Reinforcements Needed 

To Accommodate Power Deliveries 

From the Generator (Thousand $) 

 10 

b. Will This Cost Be Repaid? [ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No

11 

Were Specific Transmission Use Rights 

Secured As A Result Of The 

Interconnection Costs Incurred? 

[ ] Yes [ ] No [ ] Yes [ ] No [ ] Yes [ ] No
52

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_____________________________________ Operator ID:_________ 

Plant Name:_________________________________________ Plant Code: _________ 

Reporting as of December 31 Year:____________ ___ 

SCHEDULE 6. BOILER INFORMATION 

PART A. PLANT CONFIGURATION 

(FOR PLANTS EQUAL TO OR GREATER THAN 10 MW BUT LESS THAN 100 MW, 

COMPLETE ONLY LINES 1, 2, 3, AND IF APPLICABLE LINES 5 AND 6) 

LINE EQUIPMENT TYPE 

EQUIPMENT 

IDENTIFICATION 

(a) 

EQUIPMENT 

IDENTIFICATION 

(b) 

EQUIPMENT 

IDENTIFICATION 

(c) 

EQUIPMENT 

IDENTIFICATION 

 (d) 

EQUIPMENT 

IDENTIFICATION 

(e) 

1 Boiler ID 

 

2 Associated 

Generator(s) ID 

 

3 

Generator 

Associations with 

Boiler as Actual or 

Theoretical (indicate 

"A" for actual 

association or "T" for 

theoretical 

association) 

 

4 Associated Cooling 

System(s) ID 

 

5 

Associated Flue Gas 

Particulate 

Collector(s) ID

(include flue gas 

desulfurization units 

that also remove 

particulate matter) 

 

6 

Associated Flue Gas 

Desulfurization 

Unit(s) ID (include 

flue gas particulate 

collectors that also 

remove sulfur 

dioxide) 

 

7 Associated Flue(s) ID 

8 Associated 

Stack(s) ID 
53

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator 

Name:_______________________________________ Operator ID:___________ 

Plant Name:_______________________________________ Plant Code:___________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 6. PART B. BOILER INFORMATION – AIR EMISSION STANDARDS 

(DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW) 

(COMPLETE A SEPARATE PAGE FOR EACH BOILER)

LINE 

1 

Boiler ID (as reported on SCHEDULE 6. PART A. line 

1) 

2a Type Of Boiler Standards Under Which The Boiler Is 

Operating (use codes) 

D [ ] Da [ ] Db [ ] 

Dc [ ] N [ ] 

2b 

Is Boiler Operating Under a New 

Source Review (NSR) Permit? If 

Yes, list date and identification 

number of the issued permit. 

[ ] Yes [ ] No Date (MM-YYYY) Permit Number

CATEGORY PARTICULATE MATTER 

(a) 

SULFUR DIOXIDE 

(b) 

NITROGEN OXIDES 

(c) 

3 Type of Statute or Regulation 

(use codes) 

 FD [ ] ST [ ] 

 LO [ ] NA [ ] 

 FD [ ] ST [ ] 

 LO [ ] NA [ ] 

 FD [ ] ST [ ] 

 LO [ ] NA [ ] 

4 Emission Standard Specified 

5 Unit of Measurement Specified 

(use codes) 

6 Time Period Specified (use 

codes) 

7 

Year Boiler Was or is Expected 

to Be in Compliance With 

Federal, State and/or Local 

Regulation 

8 If Not in Compliance, Strategy 

for Compliance (use codes) 

9 

Select Existing Strategies to 

meet the Sulfur Dioxide and 

Nitrogen Oxides Requirements 

of Title IV of the Clean Air Act 

Amendment of 1990 

(use codes) 

10 

Select Planned Strategies to 

meet the Sulfur Dioxide and 

Nitrogen Oxides Requirements 

of Title IV of the Clean Air Act 

Amendment of 1990 

(use codes) 

 
54

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009) ANNUAL ELECTRIC GENERATOR 

REPORT

Form Approved 

OMB No. 1905-0129

 

Approval Expires: 

12/31/2010

Operator Name:_________________________________________ Operator ID:_________ 

Plant Name:_________________________________________ Plant Code: _________ 

Reporting as of December 31 Year:_______________ 

SCHEDULE 6. PART C. BOILER INFORMATION – DESIGN PARAMETERS 

(DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW) 

(COMPLETE A SEPARATE PAGE FOR EACH BOILER) 

LINE 

1 Boiler ID (as reported on SCHEDULE 6 PART A. line 1) 

2 Boiler Status (use codes) 

3 Boiler Actual or Projected Date of Commercial Operation 

(e.g., 12-2001) 

4 Boiler Actual or Projected Retirement Date (e.g., 12-2001) 

5 Boiler Manufacturer (use code) 

6 Type of Firing Used with Primary Fuels (use codes) 

7 Maximum Continuous Steam Flow at 100 Percent Load 

(thousand pounds per hour) 

8 Design Firing Rate at Maximum Continuous Steam Flow for 

Coal (nearest 0.1 ton per hour) 

9 Design Firing Rate at Maximum Continuous Steam Flow for 

Petroleum (nearest 0.1 barrels per hour) 

10 Design Firing Rate at Maximum Continuous Steam Flow for 

Gas (nearest 0.1 thousand cubic feet per hour) 

11 Design Firing Rate at Maximum Continuous Steam Flow for 

Other (specify fuel and unit on SCHEDULE 7) 

12 Design Waste Heat Input Rate at Maximum Continuous 

Steam Flow (million Btu per hour) 

13 Primary Fuels Used in Order of Predominance (use codes) 

14 Boiler Efficiency When Burning Primary Fuel at 100 Percent 

Load (nearest 0.1 percent) 

15 Boiler Efficiency When Burning Primary Fuel at 50 Percent 

Load (nearest 0.1 percent) 

16 Total Air Flow Including Excess Air at 100 Percent Load 

(cubic feet per minute at standard conditions) 

17 Wet Or Dry Bottom (for coal-capable boilers), (enter "W" for 

Wet or "D" for Dry) 

18 Fly Ash Re-injection (enter "Y" for Yes or "N" for No) 

 
55

U.S. Department of Energy 

Energy Information Administration 

Form EIA-860 (2009) ANNUAL ELECTRIC GENERATOR 

REPORT

Form Approved 

OMB No. 1905-0129

 

Approval Expires: 

12/31/2010

Operator Name:______________________________________ Operator ID:_________ 

Plant Name:_________________________________________ Plant Code: _________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 6. PART D. BOILER INFORMATION – NITROGEN OXIDE EMISSION CONTROLS 

(COMPLETE A SEPARATE PAGE FOR EACH BOILER) 

1 Boiler ID (as reported on SCHEDULE 6. 

PART A. line 1) 

2 Nitrogen Oxide Control Status (use codes) 

NITROGEN OXIDE CONTROL EQUIPMENT AND OR PROCESS 

3 Low Nitrogen Oxide Control Process (use 

codes) 

4 Manufacturer of Low Nitrogen Oxide 

Control Burners (use code) 

SCHEDULE 6. PART E. BOILER INFORMATION – MERCURY EMISSION CONTROLS 

1 Does This Boiler Have Mercury Emission 

Controls? (check Yes or No) Yes [ ] No [ ] 

2 

If "Yes," Check all of the boxes that apply below: 

Activated 

carbon 

injection 

system 

[ ] 

Baghouse 

[ ] 

Dry 

scrubber 

[ ] 

Electrostatic 

precipitator 

[ ] 

Flue gas 

desulfurization 

[ ] 

Lime 

injection 

[ ] 

Wet 

scrubber 

[ ] 

Other 

[ ] 

 
56

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:______________________________________ Operator ID:_______ 

Plant Name:_________________________________________ Plant Code: _________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 6. PART F. COOLING SYSTEM INFORMATION - DESIGN PARAMETERS

(DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW) 

(COMPLETE A SEPARATE PAGE FOR EACH COOLING SYSTEM)

LINE 

1 Cooling System ID (as reported on SCHEDULE 6. PART A. line 4) 

2 Cooling System Status (use codes) 

3 Cooling System Actual or Projected In-service Date of Commercial Operation (e.g., 12-2001) 

4 Type of Cooling System (use codes) 

5 Source of Cooling Water Including Makeup Water (name) (if discharge is into different water body, 

footnote in SCHEDULE 7) 

6 Design Cooling Water Flow Rate at 100 percent Load at Intake (cubic feet per second) 

7 Actual or Projected In-Service Date for Chlorine Discharge Control Structures and Equipment 

(month and year of commercial operation, e.g., 12-1982) 

COOLING PONDS 

8 Actual or Projected In-Service Date (month and year of commercial operation, e.g. 12-1982) 

9 Total Surface Area (acres) 

10 Total Volume (acre-feet) 

COOLING TOWERS 

11 Actual or Projected In-service Date (month and year of commercial operation, e.g., 12-1982) 

12 Type of Towers (use codes) 

13 Maximum Design Rate of Water Flow at 100 Percent Load (cubic feet per second) 

14 Maximum Power Requirement at 100 Percent Load (megawatts) 

INSTALLED COST OF COOLING SYSTEM EXCLUDING LAND AND CONDENSERS (thousand dollars) 

15 Total System 

16 Ponds (if applicable) 

17 Towers (if applicable) 

18 Chlorine Discharge Control Structures and Equipment (if applicable) 

COOLING WATER INTAKE AND OUTLET LOCATIONS 

ITEM INTAKE (a) OUTLET (b) 

19 Maximum Distance from Shore (feet) 

20 Average Distance below Water Surface (feet) 

21 Latitude (degrees, minutes, seconds) 

22 Longitude (degrees, minutes, seconds) 

23 Enter Datum for Latitude and Longitude, if Known; Otherwise 

Enter “UNK” 

 
57

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_____________________________________ Operator ID:_________ 

Plant Name:_________________________________________ Plant Code: _________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 6. PART G. FLUE GAS PARTICULATE COLLECTOR INFORMATION

(COMPLETE A SEPARATE PAGE FOR EACH FLUE GAS PARTICULATE COLLECTOR) 

LINE 

1 Flue Gas Particulate Collector ID (as reported on SCHEDULE 6. PART A. line 5) 

2 Flue Gas Particulate Collector Actual or Projected In-Service Date of Commercial Operation (e.g., 

12-2001) 

3 Flue Gas Particulate Collector Status (use code) 

4 Type of Flue Gas Particulate Collector (use codes) 

5 Installed Cost of Flue Gas Particulate Collector Excluding Land (thousand dollars) 

DESIGN FUEL SPECIFICATIONS FOR ASH (AS BURNED, TO NEAREST 0.1 PERCENT BY WEIGHT) 

6 For Coal 

7 For Petroleum 

DESIGN FUEL SPECIFICATIONS FOR SULFUR (AS BURNED, TO NEAREST 0.1 PERCENT BY WEIGHT) 

8 For Coal 

9 For Petroleum 

DESIGN SPECIFICATIONS AT 100 PERCENT GENERATOR LOAD 

10 Collection Efficiency (to nearest 0.1 percent) 

11 Particulate Emission Rate (pounds per hour) 

12 Particulate Collector Gas Exit Rate (actual cubic feet per minute) 

13 Particulate Collector Gas Exit Temperature (degrees Fahrenheit) 

 
58

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_____________________________________ Operator ID:_________ 

Plant Name:_________________________________________ Plant Code: _________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 6. PART H. FLUE GAS DESULFURIZATION UNIT - DESIGN PARAMETERS 

(COMPLETE A SEPARATE PAGE FOR EACH FLUE GAS DESULFURIZATION UNIT) 

LINE 

1 Flue Gas Desulfurization Unit ID (as reported on SCHEDULE 6. PART A. line 6) 

2 Flue Gas Desulfurization Unit Status (use codes) 

3 Flue Gas Desulfurization Unit Actual or Projected In-service Date of Commercial Operation (e.g., 

12-2001) 

4 Type of Flue Gas Desulfurization Unit (use code) 

5 Type of Sorbent (use code) 

6 Salable Byproduct Recovery (enter "Y" for Yes or "N" for No) 

7 Flue Gas Desulfurization Unit Manufacturer (use code) 

8 Annual Pond and Land Fill Requirements (nearest acre foot per year) 

9 Is Sludge Pond Lined (enter "Y" for Yes, "N" for No, or "NA" for Not Applicable) 

10 Can Flue Gas Bypass Flue Gas Desulfurization Unit (enter "Y" for Yes or "N" for No) 

DESIGN FUEL SPECIFICATIONS FOR COAL 

11 Ash (to nearest 0.1 percent by weight) 

12 Sulfur (to nearest 0.1 percent by weight) 

NUMBER OF FLUE GAS DESULFURIZATION UNIT SCRUBBER TRAINS (OR MODULES) 

13 Total 

14 Operated at 100 Percent Load 

DESIGN SPECIFICATIONS OF FLUE GAS DESULFURIZATION UNIT AT 100 PERCENT GENERATOR LOAD 

15 Removal Efficiency for Sulfur Dioxide (to nearest 0.1 percent by weight) 

16 Sulfur Dioxide Emission Rate (pounds per hour) 

17 Flue Gas Exit Rate (actual cubic feet per minute) 

18 Flue Gas Exit Temperature (degrees Fahrenheit) 

19 Flue Gas Entering Flue Gas Desulfurization Unit (percent of total) 

INSTALLED COST OF FLUE GAS DESULFURIZATION UNIT, EXCLUDING LAND (THOUSAND DOLLARS) 

20 Structures and Equipment 

21 Sludge Transport and Disposal System 

22 Other (installed cost of flue gas desulfurization unit) 

23 Total (sum of lines 20, 21, 22) 

 
59

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:____________________________________ Operator ID:_________ 

Plant Name:_________________________________________ Plant Code: _________ 

Reporting as of December 31 Year:________________ 

SCHEDULE 6. PART I. STACK AND FLUE INFORMATION - DESIGN PARAMETERS 

(DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW) 

 (COMPLETE A SEPARATE PAGE FOR EACH STACK AND FLUE)

LINE 

1 Flue ID (as reported on SCHEDULE 6. PART A. line 8) 

2 Stack ID (as reported on SCHEDULE 6. PART A. line 7) 

3 Stack (or Flue) Actual or Projected In-Service Date of Commercial Operation (e.g., 12-2001) 

4 Status of Stack (or Flue) (use code) 

5 Flue Height at Top from Ground Level (feet) 

6 Cross-Sectional Area at Top of Flue (nearest square foot) 

DESIGN FLUE GAS EXIT (AT TOP OF STACK) 

7 Rate at 100 Percent Load (actual cubic feet per minute) 

8 Rate at 50 Percent Load (actual cubic feet per minute) 

9 Temperature at 100 Percent Load (degrees Fahrenheit) 

10 Temperature at 50 Percent Load (degrees Fahrenheit) 

11 Velocity at 100 Percent Load (feet per second) 

12 Velocity at 50 Percent Load (feet per second) 

ACTUAL SEASONAL FLUE GAS EXIT TEMPERATURE (DEGREES FAHRENHEIT) 

13 Summer Season 

14 Winter Season 

15 Source (enter "M" for measured or "E" for estimated) 

STACK LOCATION 

16 Stack Location - Latitude (degrees, minutes, seconds) 

17 Stack Location - Longitude (degrees, minutes, seconds) 

18 Enter Datum for Latitude and Longitude, if Known; Otherwise Enter “UNK” 

 
60

U.S. Department of Energy 

Energy Information 

Administration 

Form EIA-860 (2009) 

ANNUAL ELECTRIC 

GENERATOR REPORT

Form Approved 

OMB No. 1905-0129 

Approval Expires: 12/31/2010

Operator Name:_________________________________________ 

Operator ID:_______ Reporting as of December 31 

Year:________________ 

SCHEDULE 7. COMMENTS 

SCHEDULE 

NUMBER 

(a) 

PART 

(b) 

LINE 

NUMBER (c) 

NOTES 

PROVIDE ALL IDENTIFYING CODES (e.g., plant code, generator id, 

boiler id) to which the comment applies, along with the comment. 

(d)