Respondent Letters

Appendix C
Revised Electric Power Survey Cover Letters,
Forms, and Instructions

•

Form EIA-411, “Coordinated Bulk Power Supply & Demand Program Report”

•

Form EIA-826, “Monthly Electric Sales and Revenue with State Distributions Report”

•

Form EIA-860, “Annual Electric Generator Report”

•

Form EIA-860M, “Monthly Update to the Annual Electric Generator Report”

•

Form EIA-861, “Annual Electric Power Industry Report”

•

Form EIA-923, “Power Plant Operations Report”

1

Subject: United States Department of Energy – EIA Annual Data Collection, Form EIA-411
Dear Respondent:
The U.S. Energy Information Administration (EIA) is now ready for the North American Electric Reliability Corporation (NERC) to
report the annual electric data for the year 2010. NERC is required to file Form EIA-411, “Coordinated Bulk Power Supply and
Demand Program Report" for all regions and subregions. The data are due no later than June 1, 2011 to the NERC who will
submit the regional reports to the EIA by July 15, 2011. The EIA electric surveys are a mandatory collection under the authority of
the Federal Energy Administration Act of 1974 (P.L. 93-275). Non-respondents and late filers are subject to financial penalties.
NERC collects Form EIA-411 data as part of its annual Long Term Reliability Assessment (LTRA) data collection, and as part of the
Transmission Availability Data System (TADS). A subset of the LTRA and TADS data collections are submitted to EIA to fulfill the
Form EIA-411 data requirements. Transmission maps and power flow cases (Schedules 5 and 8 on the Form EIA-411 are submitted
directly to EIA via a secure file transfer. Please contact the Form EIA-411 Survey Manager with any questions on the secure
submission process.
The timely submission of Form EIA-411 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.
Your cooperation is greatly appreciated.
Sincerely,
XXXXXXXXXX
Survey Manager
Electric Power Division
Office of Coal, Nuclear, Electric and Alternate Fuels
Energy Information Administration

2

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)
PURPOSE

REQUIRED
RESPONDENTS

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 17 hours

Form EIA-411 collects information about regional electricity supply and demand projections for a
ten-year advance period and information on the transmission system and supporting facilities.
The data collected on this form appear in the U.S. Energy Information Administration (EIA)
publication, Electric Power Annual. They are also used by the U.S. Department of Energy to
monitor the current status and trends of the electric power industry and to evaluate the future of
the industry.
The Form EIA-411 is mandatory for those entities required to report. With the exception of
Schedule 7, the form is to be completed by each of the Regional Entities of NERC. Each
Regional Entity compiles the responses from data furnished by utilities and other members within
their Region and provided to NERC. Where subregions exist, a subregional submittal is required.
NERC then compiles and coordinates these data and provides them to the U.S. Energy
Information Administration. Schedule 7 data for each Regional Entity will be provided by NERC
from its Transmission Availability Data System database.

RESPONSE DUE
DATE

Annual data, following the end of the calendar year, are due to the North American Electric
Reliability Corporation by June 1st. After review, NERC will submit the completed Form EIA-411
to the EIA by July 15.

METHODS OF
FILING RESPONSE

The North American Reliability Corporation (NERC) will oversee the methods of filing response of
the data by the Regional Entities. NERC then submits the compiled report to EIA.
Maps and power flow cases should be transmitted electronically using a secure file transfer
process. Contact Orhan Yildiz at [email protected] for instructions.
If necessary, CD-ROM disks containing the data can also be mailed via overnight delivery to EIA
at the following address:
Orhan Yildiz, Survey Manager
U.S. Energy Information Administration, Mail Stop EI-23
1000 Independence Avenue, S.W.
Washington, DC. 20585-0690
Please retain a completed copy of this form for your files.

CONTACTS

Data Questions: For questions about the data requested on Form EIA-411, contact the Survey
Manager:
Orhan Yildiz
Telephone Number: (202) 586-5410
FAX Number: (202) 287-1938
Email: [email protected]

1

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)
GENERAL
INSTRUCTIONS

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 17 hours

1. All forecast and projections should represent a ten-year outlook.
2. For schedules which require annual data, the “Actual” column represents the year prior to the
reporting year. For example, for data submitted during 2011 (or, the 2011 reporting year), the
“Actual” column should contain data for the year 2010; the “Year 1” column should contain
data for the year 2011.
3. Provide transmission data for facilities 100kV and above, with the exception of AC circuit and
transformer outages.

ITEM-BY-ITEM
INSTRUCTIONS

SCHEDULE 1: IDENTIFICATION
1. Survey Contact: Verify contact name, title, telephone number, fax number, and email
address.
2. Supervisor of Contact Person for Survey: Verify the contact’s supervisor’s name, title,
telephone number, fax number and email address.
3. Report For: Verify the NERC Regional Entity and reporting party, whether it is a Regional
Entity or subregion.
SCHEDULE 2, Part A and B: HISTORICAL AND PROJECTED PEAK DEMAND AND
ENERGY
GENERAL INSTRUCTIONS
1. The reported peak demand for a Region or subregion should be:
a. non-coincident, comprised of the sum of all peak demands for the various operating
entities within a NERC Region or subregion during the specified period. For Regions or
subregions that provide coincident peak demands, submit justification for providing a
coincident value.
b. the highest hourly integrated (“60-minute net integrated peak”) Net Energy For Load within
a reporting entity occurring within a given period. The integrated peak hour demand (MW)
amount is derived by dividing Net Energy For Load (MWh) by 60 for a given hour.
The term “peak” is defined as:
•
•
•

Summer Peak Hour Demand: The maximum load in megawatts during the period June
through September. The summer peak period begins on June 1 and extends through
September 30.
Winter Peak Hour Demand: The maximum load in megawatts during the period
December through February. The winter peak period begins on December 1 and extends
through the end-of-February.
Peak Hour Demand: The maximum load in megawatts during the specified reporting
period.

The term “Net Energy for Load” is defined as:
• Net Balancing Authority Area generation, plus energy received from other Balancing
Authority Areas, less energy delivered to other Balancing Authority Areas through
interchange. It includes Balancing Authority Area losses but excludes energy required for
storage at energy storage facilities.
2. The fundamental test for determining the adequacy of the power system is to determine
whether resources exceed demand while allowing sufficient margin to address events (loss of
generation for instance). This test requires that demand forecasts be provided and
aggregated. While coincident demand determinations are preferable, this is not feasible given
the number of entities reporting and the time available to build hourly models. Therefore, peak
demand forecasts will need to be aggregated at peak. In some cases this can be done on a
monthly interval during the peak season.

2

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
3. When providing a demand forecast to EIA the fundamental approach is to provide a
normalized forecast. This is defined as a forecast which has been adjusted to reflect normal
weather, and is expected on a 50% probability basis, (i.e., a peak demand forecast level that
has a 50% probably of being under or over achieved by the actual peak). This is also known
as the 50/50 forecast. This forecast can then be used to test against more extreme conditions.
PART A: Enter monthly peak demand and Net Energy for Load for designated months as defined
above.
Monthly peak demands should be reported based on Total Internal Demand (see definition on
Schedule 3A and 3B, line 2.
PART B: Enter seasonal peak demand and Net Energy for Load for designated years as defined
above. The summer peak demands will be the values entered on SCHEDULE 3, Part A, line 2 for
the corresponding year, and the winter peak demands will be the values entered on SCHEDULE
3, Part B, line 2, for the corresponding year. Please Note: as of 2011, all forecasts and
projections should represent a ten-year outlook.

SCHEDULE 3, PART A and B: HISTORICAL AND PROJECTED DEMAND, CAPACITY,
TRANSACTIONS, AND RESERVE MARGINS
GENERAL INSTRUCTIONS
1. PART A should be filled out for the summer seasonal peak. PART B should be filled out for
the winter seasonal peak.
2. Please Note: as of 2011, all forecasts and projections should represent a ten-year outlook.
3. Enter demand and capacity for the summer (PART A) and winter (PART B) peak periods of
the designated years for the NERC Region or subregion. Peak demands reported should
agree with the corresponding entries in SCHEDULE 2, Part B.
4. Where capacity values are entered, values should accumulate through the ten year projection
period. For example, following the table below, in 2011 “0” was added; in 2012 “100” was
added; in 2013 “0” was added; in 2014 “100” was added; in 2015 “100” was added. For the
2011 base-case, by 2015 “300” is planned to be added. The example years given would be
correct for data submitted during 2012.
YEAR

Actual
(2011)

Planned Capacity

Year 1
(2012)
0

100

Year 2
(2013)
100

Year 3
(2014)
200

Year 4
(2015)
300

5. For demand and capacity values, all numbers should be entered as MW in positive values –
no negatives – up to one decimal place. (All subtractions will be shown on the respective line
found in the form).
6. For hydroelectric capacity, explain in SCHEDULE 9, COMMENTS whether the projected
year’s data are for an adverse water year, an average water year, or other.
7. For line 1, Unrestricted Non-coincident Peak Demand is the gross load of the region/subregion, which includes New Conservation (Energy Efficiency) and Estimated Diversity; and
excludes Additions for Non-member Loads and Stand-by Load Under Contract, as defined
below.
•

For line 1a, New Conservation (Energy Efficiency), enter the estimated impact of
incremental passive energy efficiency programs. The increment represents the
increase above the embedded amount from the base year. These impacts should be
associated with programs to increase energy efficiency beyond its natural or normal
growth. Report the expected capacity impacts (MW) during time of peak.
3

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
• For line 1b, Estimated Diversity, enter the difference between the
region’s/subregion’s peak and the sum of the peaks of the reporting entities (LSEs,
balancing area, zones, etc.). The electric utility system's load is made up of many
individual loads that may make demands upon the system at different times of the
day. Within a customer class, the individual loads may follow similar usage patterns,
but these classes place different demands upon the facilities and the system grid. The
service requirements of one electrical system can differ from another by time-of-day
usage, facility usage, and/or demands placed upon the system grid.
• For line 1c, Additions for Non-member Loads, enter adjustments to account for load
of non-members, in accordance with the NERC Reliability Standard MOD-16 that
“data submittal requirements shall stipulate that each Load Serving Entity count its
Demand once and only once, on an aggregated and dispersed basis, in developing its
actual and forecast customer Demand values.”
• For line 1d, Stand-by Load Under Contract, enter the expected demand at time of
system peak required to provide power and energy (under a contract with a customer
as a secondary source or backup for an outage of the customer’s primary source). Do
not report the total (sum) of all contracted stand-by load. Additionally, do not
separately report expected contract standby demand if it is already included in the
forecasted peak data previously provided.
6. For line 2, Total Internal Demand, enter the sum of the metered (net) outputs of all
generators within the system and the metered line flows into the system, less the metered line
flows out of the system. The demands for station service or auxiliary needs (such as fan
motors, pump motors, and other equipment essential to the operation of the generating units)
are not included. Internal Demand includes adjustments for indirect demand-side
management programs such as conservation programs, improvements in efficiency of electric
energy use, all non-dispatchable demand response programs (such as Time-of-Use, Critical
Peak Pricing, Real Time Pricing and System Peak Response Transmission Tariffs) and some
dispatchable demand response (such as Demand Bidding and Buy-Back). Adjustments for
controllable demand response should not be incorporated in this value. These values should
equal those as reported in SCHEDULE 2, Part B, Seasonal Peak Hour Demand for the
corresponding years.
For Lines 2a-2d, do not double count demand response for different Demand Response
categories. All capacity should be counted once and only once and categorized as one for the four
types of dispatchable and controllable Demand Response. Only report demand response here if
the Region/subregion accounts for demand response as a load-reducing resource.
• For line 2a, Direct Control Load Management (Direct Load Control), enter the
magnitude of customer demand that can be interrupted at the time of the seasonal
peak load by direct control of a system operator by interrupting power supply to
individual appliances or equipment on customer premises. This type of control usually
reduces the demand of residential or small commercial customers. Direct Control
Load Management (Direct Load Control) as reported here does not include
Interruptible Demand (line 2b).
• For line 2b, Contractually Interruptible Demand (Curtailable), enter the magnitude
of customer demand that, in accordance with contractual arrangements, can be
interrupted at the time of the Region or subregion’s seasonal peak by direct control of
the system operator or by action of the customer at the direct request of the system
operator. In some instances, the demand reduction may be effected by direct action
of the system operator (remote tripping) after notice to the customer in accordance
with contractual provisions. For example, demands that can be interrupted to fulfill
planning or operating reserve requirements normally should be reported as
Interruptible Demand. Contractually Interruptible Demand as reported here does not
include Direct Control Load Management (line 2a).

4

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
• For line 2c, Critical Peak Pricing (CPP) with Control, enter the magnitude of
customer demand that, in accordance with contractual arrangements, can be
interrupted at the time of the Regional Entity’s seasonal peak by direct control of the
system operator or by action of the customer by responding to high prices of energy
triggered by system contingencies or high wholesale market prices.
• For line 2d, Load as a Capacity Resource, enter the magnitude of customer demand
that, in accordance with contractual arrangements, is committed to pre-specified load
reductions when called upon by a balancing authority. This demand response product
is typically an aggregation of a variety of demand resources which must qualify to
meet specific requirements aligned with traditional generating units (e.g., frequency
response, responsive to AGC). These resources are not limited to being dispatched
during system contingencies and may be subject to economic dispatch from balancing
authorities. Additionally, this capacity may be used to meet resource adequacy
obligations when determining planning reserve margins.
7. For line 3, Net Internal Demand, enter line 2, less line 2a, less line 2b, less 2c, less line 2d
(Total Internal Demand, less Direct Control Load Management, Interruptible Demand, Critical
Peak Pricing (CPP) with Control, and Load as a Capacity Resources).
For lines 4a-4d, enter the amount of Demand Response that can be called upon for the following
types of Demand Response categories. Double counting is permitted here. For example, if an
entity has 100 MW of Direct Load Control Demand Response, all 100 MW can be used for NonSpinning Reserves, and 50 MW can be used for Spinning Reserves, enter 100 on line 2a, 100 on
line 4b, and 50 on line 4a.
8. For line 4a, Demand Response used for Reserves - Spinning, Enter demand-side
resources which can displace generation deployed as operating reserves that are
synchronized and ready to provide solutions for energy supply and demand imbalance within
the first few minutes of an electric grid event.
9. For line 4b, Demand Response used for Reserves – Non-Spinning, enter demand-side
resources, which can displace generation deployed as operating reserves that are not
connected to the system but capable of serving demand within a specified time. Penalties are
assessed for non-performance.
10. For line 4c, Demand Response used for Regulation, enter demand-side resources which
can be responsive to Automatic Generation Control (AGC) to provide normal regulating
margin.
11. For line 4d, Demand Response used for Energy, Voluntary - Emergency, enter demandside resources, which curtail voluntarily when offered the opportunity to do so for
compensation. Demand-side resources which curtail during system and/or local capacity
constraints.
When determining categorization of supply resources, refer to the criteria listed within each supply
category. Determine a supply resource's applicability to a category by assessing the criteria in
each supply category in order of certainty (use logical progression). For example, first assess
whether the resource falls into the Existing-Certain category. If the resource does not meet that
criteria, assess the criteria of Existing-Other. If not, assess the criteria of Existing-Inoperable. If
not, assess the criteria of Future-Planned. If not assess the criteria of Future-Other. If not, assess
the criteria of Conceptual. A resource will qualify within a supply category if one or more of the
listed criteria is true for that resource.

For supply definitions on this form, the criteria for each supply category is based on the “period of
analysis”, which refers to the reported seasonal peak, not the full year.

5

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
12. For line 5, Total Internal Capacity, is the internal capacity for the reporting area. (Defined as
seasonal rated capability during peak period - where full availability of primary fuel, wind, and
water is assumed.) The reported value should include capacity of all generators physically
located and interconnected in the reporting area or planned to be physically located and
interconnected in the reporting area, including the full capacity of those generators wholly or
partially owned by (or with entitlement rights held by) entities outside of the reporting area.
Additionally, where load is considered a capacity resource, this capacity is also included.
This value is the summation of all Existing and Future Capacity Additions (Line 6 + Line 7).
13. For Line 6 – Existing Capacity is the sum of all existing generation connected to the electric
system for the purpose of supplying electric load during the seasonal peak. Existing capacity
does not include generation serving customers behind the meter. This value is automatically
calculated by the summations of all Existing Capacity (Line 6a + Line 6b + Line 6c).
14. For line 6a, Existing, Certain Capacity, included in this category are generation resources
available to operate and deliver power within or into the region during the period of analysis in
the assessment. Resources included in this category may be reported as a portion of the full
capability of the resource, plant, or unit. This category includes, but is not limited to the
following:
1. Contracted (or firm) or other similar resource confirmed able to serve load during the
period of analysis in the assessment.
2. Where organized markets exist, designated market resource that is eligible to bid into
a market or has been designated as a firm network resource.
3. Network Resource, as that term is used in the Federal Energy Regulatory
Commission (FERC) pro forma or other regulatory approved tariffs.
4. Energy-only resources confirmed able to serve load during the period of analysis in
the assessment and are not subject to curtailment
5. Capacity resources that can not be sold elsewhere
6. Other resources not included in the above categories that have been confirmed able
to serve load and are not subject to curtailment during the period of analysis in the
assessment
Do not derate this value by unplanned or “forced” outages. For Actual-Year data, unplanned
outages are to be reported on line 6c1.
• For line 6a1, Wind Expected On-Peak, enter the amount of existing wind
capacity that is expected to be available on the seasonal peak.
• For line 6a2, Solar Expected On-Peak, enter the amount of existing solar
capacity that is expected to be available on the seasonal peak.
• For line 6a3, Hydro Expected On-Peak, enter the amount of existing hydro
capacity that is expected to be available on the seasonal peak.
• For line 6a4, Biomass Expected On-Peak, enter the amount of existing biomass
capacity that is expected to be available on the seasonal peak.
• For line 6a5, Demand Response Expected On-Peak (Load Management
Programs), The total amount of Demand Response capacity that is expected to
be available on the seasonal peak. Values reported on this line are treated as a
capacity resource and are held to the same criteria as an Existing, Certain
resource. Do not double count Demand Response capacity here if already
provided in lines 2a-2d. Only report Demand Response here if your
Region/subregion counts Demand Response as a supply resource, and not a
load-reducing resource.
15. For line 6b, Existing, Other Capacity, included in this category are generation resources that
may be available to operate and deliver power within or into the region during the period of
analysis in the assessment, but may be curtailed or interrupted at any time for any reason.
This category also includes portions of intermittent generation not included in 6a, Existing,
Certain. This category includes, but is not limited to the following:
1. A resource with non-firm or other similar transmission arrangements
2. Energy-only resources that have been confirmed able to serve load for any reason
during the Reporting Period, but may be curtailed for various reason.
3. Mothballed generation (that may be returned to service during the period of analysis)
4. Portions of variable generation not counted in the Existing, Certain category (e.g.
6

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
wind, solar, etc.) that may not be available or de-rated during the period of analysis.
5. Hydro generation not counted as Existing, Certain or de-rated.
6. Generation resources constrained for other reasons.
Do not derate this value by unplanned or “forced” outages. For Actual-Year data, unplanned
outages are to be reported on line 6c2.
• For line 6b1, Wind Derated On-Peak, enter the amount of existing wind capacity
that is expected to be unavailable on seasonal peak.
• For line 6b2, Solar Derated On-Peak, enter the amount of existing solar capacity
that is expected to be unavailable on seasonal peak.
• For line 6b3, Hydro Derated On-Peak, enter the amount of existing hydro
capacity that is expected to be unavailable on seasonal peak.
• For line 6b4, Biomass Derated On-Peak, enter the amount of existing biomass
capacity that is expected to be unavailable on seasonal peak.
• For line 6b5, Load as a Capacity Resource Derated On-Peak (Load
Management Programs), enter the amount of Load as a Capacity Resource that
is expected to be unavailable on seasonal peak.
• For line 6b6, Transmission-Limited Resources, enter the amount of
transmission-limited generation resources that have known physical deliverability
limitations to serve load that they are obligated to serve.
• For line 6b7, All Other Derates, enter all other generation derates not reported in
lines 6b1-6b6 that have known physical limitations during peak demand.
• For line 6b8, Energy Only, enter the amount of generating resources that are
designated as energy-only resources or have elected to be classified as energyonly resources and may include generating capacity that can be delivered within
the area but may be recallable to another area. Do not include any wind, solar,
biomass, or hydro capacity in this category--instead report this capacity on the
associated derate in lines 6b1-6b4. Energy only resources are designated as such
if they are not classified as a network resource. Energy Only resources are
classified as energy-only resources by the FERC interconnection process.
16. For line 6c, Existing, Inoperable Capacity, included in this category are generation
resources that are out-of-service and cannot be brought back into service to serve load during
the period of analysis in the assessment. However, this category can include inoperable
resources that could return to service at some point in the future. This value may vary for
future seasons and can be reported as zero (0). This includes ALL existing generation within
a Region or subregion not included in line 6a, Existing, Certain. or line 6b, Existing, Other, but
is not limited to, the following:
1. Mothballed generation (that can not be returned to service for the period of the
assessment)
2. Other existing but out-of-service generation (that can not be returned to service for the
period of the assessment)
3. This category does not include behind-the-meter generation or non-connected
emergency generators.
4. This category does not include partially dismantled units that are not forecasted to
return to service
For Actual Year values, unplanned or “forced” outage capacity is to be considered as Existing,
Inoperable Capacity. Report these values on lines 6c1 and 6c2.
•
•

For line 6c1, Existing, Certain Capacity Forced
unplanned or “forced” outage of generators in MW,
to any failures at the absolute peak.
For line 6c2, Existing, Other Capacity Forced
unplanned or “forced” outage of generators in MW,
to any failures at the absolute peak.

7

Outage on Peak, enter the
which were out-of-service due
Outage on Peak, enter the
which were out-of-service due

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
17. For line 7, Future Capacity Additions, included in this category are generation resources the
reporting entity has a reasonable expectation of coming online during the period of the
assessment. As such, to qualify in either of the Future categories, the resource must have
achieved one or more of these milestones:
1. Construction has started
2. Regulatory permits (e.g. Site Permit, Construction Permit, Environmental Permit)
being approved
3. Regulatory approval has been received to be in the rate base
4. Approved power purchase agreement
5. Approved and/or designated as a resource by a market operator
18. For line 7a, Future, Planned, included in this category are generation resources anticipated
to be available to operate and deliver power within or into the region during the period of
analysis in the assessment. This category includes, but is not limited to, the following:
1. Contracted (or firm) or other similar resource
2. Where organized markets exist, designated market resource that is eligible to bid into
a market or has been designated as a firm network resource.
3. Network Resource, as that term is used in FERC’s pro forma or other regulatory
approved tariffs.
4. Energy-only resources confirmed able to serve load during the Reporting Period and
will not be curtailed.
5. Where applicable, included in an integrated resource plan under a regulatory
framework that mandates resource adequacy requirements and an obligation to
serve.
For this value, only enter the Net Expected On-Peak Values of Future-Planned resources. Do
not include derates.
•
•
•
•
•
•
•
•
•

•

•

For line 7a1, Wind Expected On-Peak, enter the amount planned wind capacity
that is expected to be available on seasonal peak.
For line 7a2, Wind Derate On-Peak, enter the amount planned wind capacity that
is expected to be unavailable on seasonal peak.
For line 7a3, Solar Expected On-Peak, enter the amount planned solar capacity
that is expected to be available on seasonal peak.
For line 7a4, Solar Derate On-Peak, enter the amount planned solar capacity that
is expected to be unavailable on seasonal peak.
For line 7a5, Hydro Expected On-Peak, enter the amount planned hydro capacity
that is expected to be available on seasonal peak.
For line 7a6, Hydro Derate On-Peak, enter the amount planned hydro capacity
that is expected to be unavailable on seasonal peak.
For line 7a7, Biomass Expected On-Peak, enter the amount planned biomass
capacity that is expected to be available on seasonal peak.
For line 7a8, Biomass Derate On-Peak, enter the amount planned biomass
capacity that is expected to be unavailable on seasonal peak.
For line 7a9, Demand Response Expected On-Peak (Load Management
Programs), The total amount of Demand Response capacity that is expected to
be available on seasonal peak. Values reported on this line are treated as a
capacity resource and are held to the same criteria as a Future-Planned resource.
Do not double count Demand Response capacity here if already provided in lines
2a-2d. Only report Demand Response here if your Region/subregion counts
Demand Response as a supply resource.
For line 7a10, Demand Response Derate On-Peak (Load Management
Programs), The total amount of Demand Response capacity that is expected to
not be available on seasonal peak. Do not double count Demand Response
capacity here if already provided in lines 2a-2d.
For line 7a11, Transmission-Limited Resources, enter amount of transmissionlimited generation resources that have known physical deliverability limitations to
serve load that they are obligated to serve. This value may represent a change
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Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
(+/-) in existing transmission-limited resources. The change in capacity is
classified as Future-Planned.
• For line 7a12, Scheduled Outage – Maintenance, enter the amount of capacity
reductions due to a generator outage that is scheduled well in advance and is of a
predetermined duration. This scheduled outage is classified as Future-Planned
capacity.
• For line 7a13, All Other Derates, enter all other generation derates not reported
in lines above that have known physical limitations during peak demand.
• For line 7a14, Energy Only, enter the amount of generating resources that are
designated as energy-only resources or have elected to be classified as energyonly resources and may include generating capacity that can be delivered within
the area but may be recallable to another area. Do not include any wind, solar,
biomass, or hydro capacity in this category--instead report this capacity on the
associated derate in lines above. Energy only resources are designated as such if
they are not classified as a network resource. Energy Only resources are
classified as energy-only resources by the FERC interconnection process.
19. For line 7b, Future, Other, included in this category are generation resources that do not
qualify as Future, Planned and are not included in the Conceptual category. This category
includes, but is not limited to, generation resources during the period of analysis in the
assessment that may:
1. Be curtailed or interrupted at any time for any reason
2. Energy-only resources that may be able to serve load during the period of analysis
3. Variable generation not counted in the Future, Planned category or may not be
available or is de-rated during the period of analysis
4. Hydro generation not counted in the Future, Planned category or de-rated.
Resources included in this category may be adjusted using a confidence factor to reflect
uncertainties associated with siting, project development or queue position. The
confidence factor for Future, Other resources should be entered on line 16a and only
adjusts the expected on-peak values and not the derated values.
• For line 7b1, Wind Expected On-Peak, enter the amount planned wind capacity
that is expected to be available on seasonal peak.
• For line 7b2, Wind Derate On-Peak, enter the amount proposed wind capacity
that is expected to be unavailable on seasonal peak.
• For line 7b3, Solar Expected On-Peak, enter the amount planned solar capacity
that is expected to be available on seasonal peak.
• For line 7b4, Solar Derate On-Peak, enter the amount proposed solar capacity
that is expected to be unavailable on seasonal peak.
• For line 7b5, Hydro Expected On-Peak, enter the amount planned hydro capacity
that is expected to be available on seasonal peak.
• For line 7b6, Hydro Derate On-Peak, enter the amount proposed hydro capacity
that is expected to be unavailable on seasonal peak.
• For line 7b7, Biomass Expected On-Peak, enter the amount planned biomass
capacity that is expected to be available on seasonal peak.
• For line 7b8, Biomass Derate On-Peak, enter the amount proposed biomass
capacity that is expected to be unavailable on seasonal peak.
• For line 7b9, Energy Only, enter the amount of generating resources that are
designated as energy-only resources or have elected to be classified as energy
only resources and may include generating capacity that can be delivered within
the area but may be recallable to another area.
• For line 7b10, Scheduled Outage – Maintenance, enter the amount of capacity
reductions due to a generator outage that is scheduled well in advance and is of a
predetermined duration. This scheduled outage is classified as Future-Planned
capacity.
• For line 7b11, All Other Derates, enter all other generation derates not reported
in lines above that have known physical limitations during peak demand.

9

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)
•

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Approval Expires: 12/31/2013
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For line 7b12, Energy Only, enter the amount of generating resources that are
designated as energy-only resources or have elected to be classified as energyonly resources and may include generating capacity that can be delivered within
the area but may be recallable to another area. Do not include any wind, solar,
biomass, or hydro capacity in this category--instead report this capacity on the
associated derate in lines above. Energy only resources are designated as such if
they are not classified as a network resource. Energy Only resources are
classified as energy-only resources by the FERC interconnection process.

20. For line 8, Conceptual, included in this category are generation resources that are not in a
prior listed category, but have been identified and/or announced on a resource planning basis
through one or more of the following sources:
1. Corporate announcement
2. Entered into or is in the early stages of an approval process
3. Is in a generator interconnection (or other) queue for study
4. “Placeholder” generation for use in modeling.
For this value, only enter the Net Expected On-Peak Value. Do not include derates or
energy only.
Resources included in this category may be adjusted using a confidence factor to reflect
uncertainties associated with siting, project development or queue position. The confidence
factor for Conceptual resources should be entered on line 16c and only adjusts the expected
on-peak values and not the derated values.
•
•
•
•
•
•
•
•
•

For line 8a1, Wind Expected On-Peak, enter the amount planned wind capacity
that is expected to be available on seasonal peak.
For line 8a2, Wind Derate On-Peak, enter the amount proposed wind capacity
that is expected to be unavailable on seasonal peak.
For line 8a3, Solar Expected On-Peak, enter the amount planned solar capacity
that is expected to be available on seasonal peak.
For line 8a4, Solar Derate On-Peak, enter the amount proposed solar capacity
that is expected to be unavailable on seasonal peak.
For line 8a5, Hydro Expected On-Peak, enter the amount planned hydro capacity
that is expected to be available on seasonal peak.
For line 8a6, Hydro Derate On-Peak, enter the amount proposed hydro capacity
that is expected to be unavailable on seasonal peak.
For line 8a7, Biomass Expected On-Peak, enter the amount planned biomass
capacity that is expected to be available on seasonal peak.
For line 8a8, Biomass Derate On-Peak, enter the amount proposed biomass
capacity that is expected to be unavailable on seasonal peak.
For line 8a9, Energy-Only, enter the amount of generating resources that are
designated as energy-only resources or have elected to be classified as energy
only resources and may include generating capacity that can be delivered within
the area but may be recallable to another area.

21. For line 9, Anticipated Internal Capacity, this value is automatically calculated by the
summations of Existing, Certain and Future, Planned Capacity Additions (Line 6a + Line 7a)

10

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Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
NOTES FOR TRANSACTIONS:
Contracts for capacity are defined as an agreement between two or more parties for the Purchase
(Import) and Sale (Export) of generating capacity. Purchase contracts refer to imported capacity
that is transmitted from an outside Region or subregion to the reporting Region or subregion.
Sales contracts refer to exported capacity that is transmitted from the reporting Region or
subregion to an outside Region or subregion. For example, if a generating resource subject to a
contract is located in one region and sold to another region, the region in which the resource is
located reports the capacity of the resource and reports the sale of such capacity that is being sold
to the outside region. The importing region reports such capacity as an import, and does not
report the capacity as a supply resource (in line 6, 7, or 8).
TRANSMISSION CAPACITY MUST BE AVAILABLE FOR ALL REPORTED IMPORT AND
EXPORT TRANSACTIONS.
DO NOT INCLUDE TRANSMISSION SYSTEM LOSSES WHEN REPORTING IMPORTS AND
EXPORTS TRANSACTIONS.
The following examples are provided to show how unit-specific transactions are handled
between two or more reporting Regions or subregions for Imports and Exports:
1. Unit physically located in Area A that is fully owned by a company in Area B and not
connected to the Area A network but instead has a direct and adequate
transmission connect to the Area A.
Solution: Show the unit completely in Area B with no transfers.
accounted for in Region or Province B.

All derating

2. Unit physically located in Area A that is half owned by a company in Area B.
Solution: Show the unit completely in Area A with an export to Area B of half of the
capacity. Area B would show an import of half of the capacity from Area A, as long
as Area A & B can demonstrate adequate transmission capacity. Unit derating
accounted for in Area A and export reduced by half of the derated amount.
3. Unit physically located in Area A that is fully owned by a company in Area B.
Solution: Show the unit completely in Area A with an export to Area B of the full
amount. Area B would show an import of the full amount of capacity from Area A,
as long as Area A & B can demonstrate adequate transmission capacity. Unit
derating should be accounted for in Area A and the import and export reduced by
derated amounts in both Areas.
4. Unit physically located in Area A that is fully owned by a company in Area C and
“wheeled” through Area B.
Solution: Show the unit completely in Area A with an export to Area C of the full
amount. Area B does not report either import or export. Area C would show an
import of the full amount of capacity from Area A, as long as Areas A, B, and C can
demonstrate adequate transmission capacity.
22. For line 10, Capacity Transactions – Imports, the sum of lines 10a through 10d.
23. For line 10a, Firm, enter the amount of capacity purchases for which a firm contract has been
signed. These transactions will be associated with Existing Certain Capacity.
•

For line 10a1, Full Responsibility Purchases - Enter the total of all purchases for
which the seller is contractually obligated to deliver power and energy to the
purchaser with the same degree of reliability as provided to the seller’s own native
load customers. Each purchaser and seller must agree on which of their
transactions are reported under this heading. Values reported on this line
represent a portion of Line 10a – Firm.

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U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
• For line 10a2, Owned Capacity/Entitlement Located Outside the
Region/subregion – Enter the amount of externally owned capacity or capacity
entitlements that will move from an outside Region or subregion to the reporting
Region or subregion. Values reported on this line represent a portion of Line 10a –
Firm.
24. For line 10b, Non-firm, enter the amount of capacity purchases for which a non-firm contract
has been signed. This value should only be entered for the previous year actual data.
25. For line 10c, Expected, enter the amount of capacity for which a contract has not been
executed, but in negotiation, projected, or other. These transactions will be associated with
Planned Capacity Additions.
•

For line 10c1, Full Responsibility Purchases - Enter the total of all purchases for
which the seller is contractually obligated to deliver power and energy to the
purchaser with the same degree of reliability as provided to the seller’s own native
load customers. Each purchaser and seller must agree on which of their
transactions are reported under this heading. Values reported on this line
represent a portion of Line 10c – Expected.
• For line 10c2, Owned Capacity/Entitlement Located Outside the
Region/subregion - Enter the amount of externally owned capacity or capacity
entitlements that will move from an outside Region or subregion to the reporting
Region or subregion. Values reported on this line represent a portion of Line 10c –
Expected.
26. For line 10d, Provisional, enter the amount of capacity for which the transaction(s) is under
study, but negotiations have not begun.
27. For line 11, Capacity Transactions – Exports, the sum of lines 11a through 11d.
28. For line 11a, Firm, enter the amount of capacity purchases for which a firm contract has been
signed. These transactions will be associated with Existing Certain Capacity.
•

For line 11a1, Full Responsibility Sales - Enter the total of all purchases for
which the seller is contractually obligated to deliver power and energy to the
purchaser with the same degree of reliability as provided to the seller’s own native
load customers. Each purchaser and seller must agree on which of their
transactions are reported under this heading. Values reported on this line
represent a portion of Line 11a – Firm.
• For line 11a2, Owned Capacity/Entitlement Located Outside the
Region/subregion - Enter the amount of externally owned capacity or capacity
entitlements that will move from the reporting Region or subregion to an outside
Region or subregion. Values reported on this line represent a portion of Line 11a –
Firm.
29. For line 11b, Non-firm, enter the amount of capacity purchases for which a non-firm contract
has been signed. This value should only be entered for the previous year actual data.
30. For line 11c, Expected, enter the amount of capacity for which a contract has not been
executed, but in negotiation, projected, or other. These transactions will be associated with
Planned Capacity Additions.
•

For line 11c1, Full Responsibility Sales - Enter the total of all purchases for
which the seller is contractually obligated to deliver power and energy to the
purchaser with the same degree of reliability as provided to the seller’s own native
load customers. Each purchaser and seller must agree on which of their
transactions are reported under this heading. Values reported on this line
represent a portion of Line 11c – Expected.
• For line 11c2, Owned Capacity/Entitlement Located Outside the
Region/subregion - Enter the amount of externally owned capacity or capacity
entitlements that will move from the reporting Region or subregion to an outside
Region or subregion. Values reported on this line represent a portion of Line 11c –
Expected.
31. For line 11d, Provisional, enter the amount of capacity for which the transaction(s) is under
study, but negotiations have not begun.

12

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 17 hours

NOTES FOR MARGIN CALCULATIONS:
Lines 12-15a are calculated automatically and represent the amount of capacity (generating
supply and transactions) that will be counted towards margin calculations.
32. For line 12, Existing, Certain and Net Firm Transactions is calculated by the summation of
Existing, Certain Capacity and the net of Firm Transactions
33. For line 13, Anticipated Capacity Resources is calculated by the summation of Anticipated
Internal Capacity and the net of Firm and Expected Transactions. For the general public, this
is the equivalent of “Planned Capacity Resources” on the older versions of this form.
34. For line 14, Prospective Capacity Resources is calculated by the summation of Anticipated
Capacity Resources, Existing, Other Capacity, and the adjusted Future, Other Capacity (For
this calculation, Future, Other resources are adjusted using the confidence factor reported on
line 16a. This amount is automatically calculated in line 16b). All derates and outages are
subtracted from this calculation.
35. For line 15, Potential Capacity Resources is calculated by the summation of Anticipated
Capacity Resources, Existing, Other Capacity, Future, Other Capacity, Conceptual Capacity,
and the net of Provisional Transactions. All derates and outages are subtracted from this
calculation.
36. For line 15a, Adjusted Potential Capacity Resources is calculated by the summation of
Prospective Capacity Resources, the adjusted Conceptual Capacity (For this calculation,
Conceptual Resources are adjusted using the confidence factor reported on line 16c. This
amount is automatically calculated in line 16d.) and the net of Provisional Transactions. All
derates and outages are subtracted from this calculation.
37. For line 16a, Confidence of Future, Other Resources (line 7b), using reasonable judgment,
enter a value between 0 and 100 that corresponds to the weight of emphasis placed on
Future, Other additions for the given year. This factor only adjusts the expected on peak
values.
38. For line 16b, Net Future, Other Resources After Confidence Percentage Is Applied, line
7b times line 16a.
39. For line 16c, Confidence of Conceptual Resources (line 8), using reasonable judgment,
enter a value between 0 and 100 that corresponds to the weight of emphasis placed on
Conceptual additions for the given year. This factor only adjusts the expected on peak values.
40. For line 16d, Net Conceptual Resources After Confidence Percentage Is Applied, line 8
times line 16c.
41. For line 17, Target Reserve Margin, enter a value between 0 and 100 that represents the
expected target margin (%) set by the Region/subregion. If no value is entered, a reference
margin level will be applied and it is assumed this value will remain constant throughout the
reporting period.

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U.S. Department of Energy
COORDINATED BULK POWER
U.S. Energy Information Administration
SUPPLY AND DEMAND
Form EIA-411 (2011)
PROGRAM REPORT
NOTES FOR MARGINS:
Capacity margin (C) and reserve margins (R) calculations
on behalf of the Region or subregion.

Form Approved OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 17 hours
are computed by NERC and submitted

42. For line 18, Existing Certain and Net Firm Transactions, take the difference between line
12 and line 3. Divide by line 3 for the reserve margin and divide by line 12 for the capacity
margin.
43. For line 19, Anticipated Capacity Resources, take the difference between line 13 and line
3. Divide by line 3 for the reserve margin and divide by line 13 for the capacity margin.
44. For line 20, Prospective Capacity Resources, take the difference between line 14 and line
3. Divide by line 3 for the reserve margin and divide by line 14 for the capacity margin.
45. For line 21, Total Potential Resources, take the difference between line 15 and line 3.
Divide by line 3 for the reserve margin and divide by line 15 for the capacity margin.
46. For line 22, Adjusted Potential Resources, take the difference between line 15a and line 3.
Divide by line 3 for the reserve margin and divide by line 15a for the capacity margin.
NOTES FOR LINES 23, 24, AND 25:
This information comes from other EIA data collection (Form EIA-860 and Form EIA-861), and
NERC is not obligated to supply this information. These categories are placed here for
informational purposes so that the public will be aware of other capacity, which may need to be
included in some analyses. The public can acquire this information from the EIA websites for the
forms listed above.

SCHEDULE 5. BULK ELECTRIC TRANSMISSION SYSTEM MAPS
1. Each Regional Entity is to submit a map(s), in electronic format, showing the existing bulk
electric transmission system 100 kV and above, including ties to all other Regional Entities,
and the bulk electric transmission system additions projected for a ten-year period beginning
with the year following the reporting year. The submission of Computer-Aided Design and/or
Computer-Aided Design and Drafting (CAD/CADD) file types is also allowed.
2. Only major geographic features and State boundaries, bulk electric facilities, and the names
of major metropolitan areas need be shown. The map scale to be used is left to the
discretion of the Regional Entity or Reporting Party, but should be such as to allow
convenient use of the map. Show the voltage level of all bulk electric transmission lines. The
year of installation of all projected system additions may be shown at the option of the
Regional Entity or Reporting Party.
3. The map requirement may be satisfied by either:
(a) A single map in electronic format showing the existing bulk electric transmission
system as of January 1 of the reporting year and system additions for a ten-year
period beginning with the reporting year; or
(b) Separate maps for a set of subregions that comprise the whole region.
4. For Line 1, enter the number of maps provided.
5. For Line 2, enter the requested map information in columns (a) through (d).

14

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U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 17 hours

SCHEDULE 6 PART A & B: EXISTING AND PROJECTED TRANSMISSION CIRCUIT MILES
AND CHARACTERISTICS OF PROJECTED TRANSMISSION ADDITIONS
PART A: Existing Transmission Circuit Miles
1. For the following lines, report transmission lines in WHOLE number circuit miles for the
specified voltages:
Operative Voltage Range(kV)
100-120
121-150
151-199
100-299
200-299
300-399
400-599
600+

Voltage Type
AC
-AC
-AC
--DC
AC
-AC
DC
AC
DC
AC
DC

2. All transmission lines must be classified into one of the following categories:
•
•
•

•

Existing
o Energized line available for transmitting power
Under Construction
o Construction of the line has begun
Planned (any of the following)
o Permits have been approved to proceed
o Design is complete
o Needed in order to meet a regulatory requirement
Conceptual (any of the following)
o A line projected in the transmission plan
o A line that is required to meet a NERC TPL Standard or powerflow model and
cannot be categorized as “Under Construction” or “Planned”
o Projected transmission lines that are not “Under Construction” or “Planned”

3. For line 1, report Existing transmission lines as of the last day in the prior reporting year. (For
example, the 2011 Report Year, enter the amount of circuit miles existing as of 12/31/2010.)
4. For line 2, report Under Construction transmission lines as of the first day in the current
reporting year. (For example, the 2011 Report Year, enter the amount of circuit miles existing
as of 1/1/2011.)
5. For line 3, report Planned transmission lines to be completed within the first 5 years starting
the first day in the current reporting year.
6. For line 4, report Conceptual transmission lines to be completed within the first 5 years
starting the first day in the current reporting year.
7. For line 5, report Planned transmission lines to be completed within the second 5 years
th
starting the first day of the 5 projection year.
8. For line 6, report Conceptual transmission lines to be completed within the second 5 years
starting the first day of the 5th projection year.
9. For line 7, report the sum of all Existing, Under Construction, and Planned transmission line
circuit miles for the ten year projection period.
10. For line 8, report the sum of all Existing, Under Construction, Planned, and Conceptual
transmission line circuit miles for the ten year projection period.

15

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 17 hours

PART B: Characteristics of Projected Transmission Line Additions
1. This SCHEDULE must be completed by each Regional Entity for all transmission line
additions at 100 kV and above projected for the ten-year period beginning with the first day of
the current reporting year.
2. For transmission classified as Conceptual, the assumptions used during the transmission
planning process and in the planning models are to be reported in this schedule.
3. For line 1, Project Name, enter the project name
4. For line 2, Project Status, enter the level of certainty defined by the following criteria:
• Under Construction
o Construction of the line has begun
• Planned (any of the following)
o Permits have been approved to proceed
o Design is complete
o Needed in order to meet a regulatory requirement
• Conceptual (any of the following)
o A line projected in the transmission plan
o A line that is required to meet a NERC TPL Standard or powerflow model and
cannot be categorized as “Under Construction” or “Planned”
o Projected transmission lines that are not “Under Construction” or “Planned”
5. For line 3, Tie line, specify whether this addition interconnects Balancing Authorities
(YES/NO).
6. For line 4a & 4b, Primary and Secondary Driver, specify drivers from the following list:
• Reliability
• Generation integration
• Variable/Renewable (identify by source or combination of sources)
• Nuclear
• Fossil-Fired (identify by source or combination of sources)
• Hydro
• Congestion Relief
• Other (please specify in Schedule 9, Comments)
7. For line 5, Terminal Location (From), enter the name of the beginning terminal point of the
line.
8. For line 6, Terminal Location (To), enter the name of the ending terminal point of the line.
9. For line 7, Company Name, enter the company name.
10. For line 8, EIA Company Code, identify each organization by the six-character code
assigned by EIA.
11. For line 9, Type of Organization, identify the type of organization that best represents the
line owner including the following types of utilities – Investor-owned (I), Municipality (M),
Cooperative (C), State-owned (S), Federally-owned (F), or other (O).
12. For line 10, Percent Ownership, if the transmission line will be jointly-owned, enter the
percentages owned by each transmission owner.
13. For line 11, Circuit Line Length, enter the number of circuit line miles between the beginning
and ending terminal points of the line.
14. For line 12, Line Type, select physical location of the line conductor – overhead (OH),
underground (UG), or submarine (SM).
15. For line 13, Voltage Type, select voltage as alternating current (AC) or direct current (DC).
16. For line 14, Voltage Operating, enter the voltage at which the line will be normally operated
in kilovolts (kV).
17. For line 15, Voltage Design, enter the voltage at which the line is designed to operate in
kilovolts (kV).
18. For line 16, Conductor Size, enter the size of the line conductor in thousands of circular mils
(MCM).
16

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
19. For line 17, Conductor Material Type, enter the line conductor material type – aluminum,
ACCR, ACSR, copper, superconductor, or other.
20. For line 18, Bundling Arrangement, enter the bundling arrangement/configuration of the line
conductors – single, double, triple, quadruple, or other.
21. For line 19, Circuits per Structure Present, enter the current number of three-phase circuits
on the structures of the line.
22. For line 20, Circuits per Structure Ultimate, enter the ultimate number of three-phase
circuits that the structures of the line are designed to accommodate.
23. For line 21, Pole/Tower Type, identify the predominant pole/tower material for the line –
wood, concrete, steel, combination, composite material, or other. Also include the type of
structure – single pole, H-frame structure, tower, underground, or other.
24. For line 22, Capacity Rating, enter the normal load-carrying capacity of the line in millions of
volt-amperes (MVA).
25. For line 23, Original In-Service Date, enter the originally projected date the line was to be
energized under the control of the system operator.
26. For line 24, Expected In-Service Date, enter the currently projected date the line will be
energized under the control of the system operator.
27. For line 25, Line Delayed, enter “Y” if the line has been delayed and “N” if it has not.
28. For line 26, Cause of Delay, if the line has been delayed, enter the cause.

SCHEDULE 7. ANNUAL DATA ON TRANSMISSION LINE
OUTAGES FOR EHV LINES, GENERAL INSTRUCTIONS FOR PARTS A, B, C, and D
Outages are defined below for purposes of reporting on this schedule and are intended to be
consistent with the instructions and definitions in the NERC Transmission Availability Data System
(TADS) Data Reporting Instruction Manual and TADS Definitions (Appendix 7 of the Instructions)
at http://www.nerc.com/page.php?cid=4|62 An Element includes certain specified voltage classes of
AC Circuits, DC Circuits, and Transformers. An In-Service State means an Element that is
energized and connected at all its terminals to the system.
Outages that occur on intertie lines between regions are to be reported only once by one or the
other of the reporting regions. Outages on lines that cross international borders must be reported.
Automatic Outages
An Automatic Outage is an outage which results from the automatic operation of a switching
device, causing an Element to change from an In-Service State to a not In-Service State. A
successful AC single-pole (phase) reclosing event is not an Automatic Outage. If practices are
different from this, please note in SCHEDULE 9 Comments.
•

A Sustained Outage is an Automatic Outage with an Outage Duration of a minute or
greater.

•

A Momentary Outage is an Automatic Outage with an Outage Duration of less than one
(1) minute. Momentary outages should not be included.
An Event is a transmission incident that results in the Automatic Outage (Sustained or
Momentary) of one or more Elements.
Non-Automatic Outages
A Non-Automatic Outage is an outage which results from the manual operation (including
supervisory control) of a switching device, causing an Element to change from an In-Service State
to a not In-Service State. If practices are different from this, please note in SCHEDULE 9
Comments.
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Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
• A Planned Outage is a Non-Automatic Outage with advance notice for the purpose of
maintenance, construction, inspection, testing, or planned activities by third parties that
may be deferred. Outages of Elements of 30 minutes or less in duration resulting from
switching steps or sequences that are performed in preparation for or restoration from an
outage of another Element are not reportable.
•

An Operational Outage is a Non-Automatic Outage for the purpose of avoiding an
emergency (i.e., risk to human life, damage to equipment, damage to property) or to
maintain the system within operational limits and that cannot be deferred.

Automatic Outage Causes
•

•
•
•
•
•
•
•
•
•
•
•
•

•
•
•
•

Weather, excluding lightning, covers all outages in which severe weather conditions
(snow, extreme temperature, rain, tornado, hurricane, ice, high winds, etc.) are the
primary cause of the outage, with the exception of lightning. This includes flying debris
caused by wind.
Lightning
Environmental, includes environmental conditions such as earth movement (earthquake,
subsidence, earth slide), flood, geomagnetic storm, or avalanche.
Foreign Interference, includes objects such as aircraft, machinery, vehicles, kites,
events where animal movement or nesting impacts electrical operations, flying debris not
caused by wind, and falling conductors from one line into another.
Contamination, covers outages caused by bird droppings, dust, corrosion, salt spray,
industrial pollution, smog, or ash.
Fire, includes outages caused by fire or smoke.
Vandalism, Terrorism, or Malicious Acts, includes intentional activity such as
gunshots, removed bolts, or bombs.
Failed AC Substation Equipment, includes equipment inside the substation fence, but
excludes protection system equipment.
Failed AC/DC Terminal Equipment, includes equipment inside the terminal fence,
including power-line carrier filters, AC filters, reactors and capacitors, transformers, DC
valves, smoothing reactors, and DC filters. This excludes protection system equipment.
Failed Protection System Equipment, includes any relay and/or control misoperations
except those that are caused by incorrect relay or control settings that do not coordinate
with other protective devices (these should be categorized as Human Error)
Failed AC Circuit Equipment, includes overhead or underground equipment outside the
substation fence.
Failed DC Circuit Equipment, includes equipment outside the terminal fence.
Human Error, covers any incorrect action traceable to employees and/or contractors for
companies operating, maintaining, and/or providing assistance to the utility. This includes
any human failure or interpretation of standard industry practices and guidelines that
cause an outage.
Power System Condition, include instability, overload trip, out-of-step, abnormal
voltage, abnormal frequency, or unique system configurations.
Vegetation, includes outages initiated by vegetation in the proximity of transmission
facilities. Reporting definition will be consistent with the NERC template and vegetation
management criteria.
Unknown, any unknown causes should be reported in this category.
Other, includes outages for which the cause is known; however, the cause is not included
in the above list.

Non-Automatic, Operational Outage Causes
•
•
•

Emergency, includes outages taken to avoid risk to human life, damage to equipment,
damage to property, or similar threatening consequences
System Voltage Limit Mitigation, covers outages taken to maintain the voltage on the
transmission system within desired levels (i.e., voltage control).
System Operating Limit Mitigation, (excluding voltage limit mitigation) covers outages
18

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
taken to keep the transmission system within System Operating Limits, including facility
ratings, transient stability ratings, and voltage stability ratings covering MW, MVar,
Amperes, Frequency, or Volts.
• Other Operational Outage, includes all other causes, including human error.
Non-Automatic, Planned Outage Causes
•

Maintenance and Construction covers any planned outage associated with
maintenance and construction of electric facilities, including testing.

•

Third Party Requests, covers outages taken at the request of a third party such as
highway department, Coast Guard, etc.

•

Other Planned Outage, includes all other causes, including human error.
PART A: Annual Data on AC Transmission Line Outages

1. All transmission line outages involving Extra High Voltage (EHV) AC Circuit Elements of 200
kV and above are to be aggregated by each Regional Entity and reported on this schedule.
2. For the appropriate outage type (Automatic; Non-Automatic, Planned; or Non-Automatic,
Operational), enter the following:
• Number of Outages (lines 2, 5, and 8), report the total number of outages that occurred in
the reporting period for each voltage class.
• Number of Circuit-Hours Out of Service (lines 3, 6, and 9), report the total circuit-hours
out of service for all of the outages for each voltage class during the year. This is the sum
across all circuits of the number of hours each circuit was not in an In-Service State during
the reporting period.
• Outage Cause (lines 4, 7, and 10), report the number of outages by the pertinent cause
code, as listed above. For Automatic Outages, report the number of outages for both the
Initiating Cause and the Sustained Cause. For the Sustained Cause, use the Cause
Code that describes the cause that contributed to the longest duration of the outage.

PART B: Annual Data on DC Transmission Line Outages
3. All transmission line outages involving Extra High Voltage (EHV) DC Circuit Elements of
±100 kV and above are to be aggregated by each Regional Entity and reported on this
schedule.
4. For the appropriate outage type (Automatic; Non-Automatic, Planned; or Non-Automatic,
Operational), enter the following:
• Number of Outages (lines 2, 5, and 8), report the total number of outages that occurred in
the reporting period for each voltage class.
• Number of Circuit-Hours Out of Service (lines 3, 6, and 9), report the total circuit-hours
out of service for all of the outages for each voltage class during the year. This is the sum
across all circuits of the number of hours each circuit was not in an In-Service State during
the reporting period.
• Outage Cause (lines 4, 7, and 10), report the number of outages by the pertinent cause
code, as listed above. For Automatic outages, report the number of outages for both the
Initiating Cause and the Sustained Cause. For the Sustained Cause, use the Cause
Code that describes the cause that contributed to the longest duration of the outage.

PART C: Annual Data on Transformer Outages
5. All transformer outages involving Transformer Elements with a low-side voltage of ≥200 kV
are to be aggregated by each Regional Entity and reported on this schedule.
6. For the appropriate outage type (Automatic; Non-Automatic, Planned; or Non-Automatic,
Operational), enter the following:
• Number of Outages (lines 2, 5, and 8), report the total number of outages that occurred
in the reporting period for each voltage class based on the high-side voltage of the
19

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
transformer.
• Number of Transformer-Hours Out of Service (lines 3, 6, and 9), report the total
transformer-hours out of service for all of the outages for each voltage class (by high-side
voltage) during the year. This is the sum across all transformers of the number of hours
each transformer was not in an In-Service State during the reporting period.
• Outage Cause (lines 4, 7, and 10), report the number of outages by the pertinent cause
code, as listed above. For Automatic outages, report the number of outages for both the
Initiating Cause and the Sustained Cause. For the Sustained Cause, use the Cause
Code that describes the cause that contributed to the longest duration of the outage.

PART D: Element Inventory and Event Summary
The Element inventory data collected on Part D can be used to normalize the outage data
collected on Parts A, B, and C. The Event summary data can be used to compare with outage
totals collected on Parts A, B, and C.
1. For line 1, report in accordance with the applicable voltage class indicated..
2. For line 2, an AC Circuit is a set of overhead or underground three-phase conductors that are
bound by AC substations. Radial circuits are AC Circuits.
3. For line 2a, enter the Number of Overhead AC Circuits in each voltage class.
4. For line 2b, enter the Number of Underground AC Circuits in each voltage class.
5. For line 3, an AC Circuit Mile is one mile of a set of three-phase AC conductors in an
Overhead or Underground AC Circuit
6. For line 3a, enter the Number of Overhead AC Circuit Miles in each voltage class.
7. For line 3b, enter the Number of Underground AC Circuit Miles in each voltage class.
8. For line 4, enter the Number of Multi-Circuit Structure Miles in each voltage class. A MultiCircuit Structure Mile is a one-mile linear distance of sequential structures carrying multiple
Overhead AC Circuits. (Note: this definition is not the same as the industry term “structure
mile.” A Transmission Owner’s Multi-Circuit Structure Miles will generally be less than its
structure miles since not all structures contain multiple circuits.)
9. For line 5, report in accordance with the applicable voltage class indicated.
10. For line 6, a DC circuit is one pole of an overhead or underground line which is bound by an
AC/DC Terminal on each end.
11. For line 6a enter the Number of Overhead DC Circuits in each voltage class.
12. For line 6b, enter the Number of Underground DC Circuits in each voltage class.
13. For line 7, a DC Circuit Mile is one mile of one pole of a DC Circuit.
14. For line 7a, enter the Number of Overhead DC Circuit Miles in each voltage class.
15. For line 7b, enter the Number of Underground DC Circuit Miles in each voltage class.
16. For line 8, report in accordance with the applicable voltage class indicated based on the highside voltage of the Transformer. Note: To be reported on this form, the Transformer must
have a low-side voltage ≥200 kV.
17. For line 9, enter the Number of Transformers in each voltage class. A Transformer is a bank
of three single-phase transformers or a single three-phase transformer. A Transformer is
bounded by its associated switching or interrupting devices.
18. For line 10, enter the total annual Number of Events associated with the outages reported on
Schedules 7A, 7B, and 7C.

SCHEDULE 8. BULK TRANSMISSION FACILITY POWER FLOW CASES
1. Each Regional Entity is to coordinate the collection of data on basic electrical data and power
flow information on prospective new bulk transmission facilities of 100 kV and above
(including lines, transformers, HVDC terminal facilities, phase shifters, and static VAR
compensators) that have been approved for construction and are scheduled to be energized
over the next two years.
2. If the prospective bulk transmission facilities are represented in the respondent’s current
FERC Form 715 submission, please provide a copy of an annual peak load power flow case
20

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
submitted which represents a period of at least two years into the future and complete (see
Instructions 6 through 13).
3. If the facilities are not represented in the respondent’s current FERC Form 715 submission,
please submit a power flow case(s) representing the prospective facilities. The respondent
may submit a single annual peak load power flow case that includes all prospective facilities
to be energized in the next two years. Alternatively, the respondent may provide a copy of
any annual peak load power flow case that includes the new facility for the year it is to be
energized. If more than one facility is to be energized in a given year, it is acceptable to
provide a single annual peak load power flow case that includes all the new facilities added in
that year. The power flow shall be in the same format as used for the respondent’s FERC
Form 715 filing.
4. For each power flow case that is provided in response to Items 2 and 3 above, please identify
on SCHEDULE 8 all prospective facilities that are not currently in service and the projected
in-service date of those facilities. Complete one page for each new power flow case. In each
case, identify only the new facility by type and list bus numbers and names that the new
facility is connected with electrically.
5. The EIA expects that in nearly all cases the power flow format will be one of the following:
•

6.
7.
8.
9.
10.
11.
12.

The Raw Data File format of the PTI (Power Technologies, Inc.) PSS/E power flow
program;
• The Card Deck Image format of the Philadelphia Electric power flow program;
• The Card Deck format of the WSCC power flow program;
• The Raw Data File format of the General Electric (formerly Electric Power Consultant,
Inc. or EPC), or the PSLF power flow program; or
• The IEEE Common Format for Exchange of Solved Power Flows.
Respondents submitting their own cases must supply the input data to the solved base cases
and associated ACSII output data on compact disk in the format associated with the power
flow program used by the respondents in the course of their transmission studies, as
described above.
For Line 1, enter the case name.
For Line 2, enter the year studied in this power flow case.
For Line 3, enter the case number assigned by respondent.
For Line 4, column a, enter the name and type (e.g. line transformer, etc.) of a prospective
facility included on the power flow case.
For Line 4, column b, enter the projected in-service date of the proposed facility. Please
provide month and year (e.g., 12-2004).
For Line 4, column c and d, enter the number and name respectively of each bus to which the
facility is connected. Use one line for each bus.
Repeat Instructions 9 through 12 for each prospective facility.

SCHEDULE 9. COMMENTS
Identify each comment by the appropriate schedule, part, line number, column identifier and page
number. Use additional sheets, as required. (Any comment referencing sensitive information will
be considered sensitive.)

21

U.S. Department of Energy
Form Approved OMB No. 1905-0129
COORDINATED BULK POWER
U.S. Energy Information Administration
Approval Expires: 12/31/2013
SUPPLY AND DEMAND
Form EIA-411 (2011)
Burden: 17 hours
PROGRAM REPORT
The
glossary
for
this
form
is
available
online
at
the
following
URL:
GLOSSARY
http://www.eia.gov/glossary/index.html
For NERC definitions, see www.nerc.com, or this EIA copy at:
http://www.eia.gov/cneaf/electricity/page/eia411/nerc_glossary_2009.pdf
SANCTIONS

The timely submission of Form EIA-411 by those required to report is requested 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 be 120 hours per response
for the Regional Entities and NERC, and 16 hours per response for the members within each
council, including the time of reviewing instructions, searching existing data sources, gathering and
maintaining the data needed, and completing and reviewing the collection of information. The
weighted average burden for the Form EIA-411 is 17 hours. The burden includes not only the
hours needed by the Regional Entities and NERC, but also for the members within each council.
Send comments regarding this burden estimate or any other aspect of this collection of
information, including suggestions for reducing this burden, to the U.S. Energy Information
Administration, Statistics and Methods Group, EI-70, 1000 Independence Avenue S.W., Forrestal
Building, Washington, D.C. 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.
The information contained on SCHEDULE 5, Bulk Electric Transmission System Maps,
SCHEDULES 7A, 7B, and 7C, Annual Data on AC and DC Transmission Line and Transformer
Outages, and SCHEDULE 8, Bulk Transmission Facility Power Flow Cases, will be protected and
not disclosed to the extent that it satisfies the criteria for exemption under the Freedom of
Information Act (FOIA), 5 U.S.C. §552, the DOE regulations, 10 C.F.R. §1004.11, implementing
the FOIA, and the Trade Secrets Act, 18 U.S.C. §1905. All other information reported on Form
EIA-411 are considered public information and may be publicly released in company identifiable
form.
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 protected statistical data published from
SCHEDULES 5, 7, and 8, on Form EIA-411 to ensure that the risk of disclosure of identifiable
information is very small.

PROVISIONS
REGARDING THE
CONFIDENITALITY
OF INFORMATION

22

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

NOTICE: This report is mandatory under the Federal Energy Administration Act of 1974 (Public Law 93-275) for all parts.
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
Last Name:_________________

First Name:________________
Title:______________________________
Telephone (include extension):______________
Email:_______________________________

Fax:__________________

Supervisor of Contact Person for Survey
First Name:____________________
Last Name:_____________________
Title:___________________________
Telephone (include extension):______________
Fax:__________________
Email:________________________________
Report For
Regional Entity:_________________________________________________
Reporting Party (Regional Entity or subregion):___________________________________________
For questions about the data requested on Form EIA-411, contact the Survey Manager:
Marie Rinkoski Spangler
Telephone Number: (202) 586-2446
FAX Number: (202) 287-1934
Email: [email protected]

23

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 2. PART A. HISTORICAL AND PROJECTED PEAK DEMAND AND ENERGY MONTHLY
Peak Demand
Reported
If coincident,
please explain
why not noncoincident

LIN
E
NO.

1
2
3
4
5
6
7
8
9
1
0
1
1
1
2

MONTH

Non-Coincident _________

Coincident____________

2011 (Prior Year)
NET ENERGY
PEAK HOUR (THOUSANDS OF
DEMAND
MEGA-

YEAR
2012 (Report Year)
2013 (Next Year)
NET ENERGY
PEAK HOUR (THOUSANDS OF PEAK HOUR
NET ENERGY
DEMAND
DEMAND
MEGA(THOUSANDS OF

(MEGAWATTS)

WATTHOURS)

(MEGAWATTS)

WATTHOURS)

(MEGAWATTS)

MEGAWATTHOURS)

(a)

(b)

(a)

(b)

(a)

(b)

January
February
March
April
May
June
July
August
September
October
November
December

SCHEDULE 2. PART B. HISTORICAL AND PROJECTED PEAK DEMAND AND ENERGY - ANNUAL
Actual
Year

1

2
3

Year
1

Year
2

Year
3

Summer Peak Hour
Demand, June-September
(Megawatts)
Winter Peak Hour
Demand, December February (Megawatts)
Net Annual Energy

24

YEAR
Year Year
4
5

Year
6

Year
7

Year
8

Year
9

Year
10

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 3. PART A. HISTORICAL AND PROJECTED DEMAND AND CAPACITY - SUMMER
YEAR
Actual
Year 1
Year 2
….
(eg 2011)
(eg 2012)
(eg 2013)
….
DEMAND (IN MEGAWATTS)

LINE
NO.

1
1a
1b
1c
1d
2
2a
2b
2c
2d

3

4a
4b
4c
4d

Unrestricted Non-coincident
Peak Demand
New Conservation
Estimated Diversity
Additions for nonmember load
Stand-by Load Under
Contract
Total Internal Demand
Direct Control Load
Management
Contractually Interruptible
Critical Peak Pricing with
Control
Load as a Capacity
Resource

Net Internal Demand
Demand Response Used for
Reserves - Spinning
Demand Response Used for
Reserves – Non-Spinning
Demand Response used for
Regulation
Demand Response used for
Energy, Voluntary –
Emergency

CAPACITY (IN MEGAWATTS)
5

6
6a
6a1
6a2
6a3
6a4
6a5

TOTAL INTERNAL CAPACITY
(sum of 6 and 7)

EXISTING CAPACITY
Existing, Certain
Wind Expected On-peak
Solar Expected On-peak
Hydro Expected OnPeak
Biomass Expected OnPeak
Load as a Capacity
Resource Expected OnPeak

25

Year 9
(eg 2020)

Year 10
(eg 2021)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 3. PART A. HISTORICAL AND PROJECTED DEMAND AND CAPACITY - SUMMER
YEAR
Actual
Year 1
Year 2
….
(eg 2011)
(eg 2012)
(eg 2013)
….
CAPACITY (IN MEGAWATTS)

LINE
NO.
6b
6b1
6b2
6b3
6b4
6b5
6b6
6b7
6b8
6c
6c1
6c2
7
7a
7a1
7a2
7a3
7a4
7a5
7a6
7a7
7a8
7a9
7a10
7a11
7a12
7a13
7a14
7a1
7a2
7a3
7a4
7b
7b1
7b2
7b3
7b4
7b5
7b6
7b7
7b8
7b9

Existing, Other
Wind Derate On-peak
Solar Derate On-peak
Hydro Derate On-peak
Biomass Derate On-peak
Load as a Capacity
Resource Derate On-peak
Energy Only
Scheduled Outage –
Maintenance
Transmission-Limited
Resources
Existing, Inoperable
Existing, Certain Capacity
Forced Outage On-peak
Existing, Other Capacity
Forced Outage On-peak
FUTURE CAPACITY ADDITIONS
Future, Planned
Wind Expected On-peak
Wind Derate On-peak
Solar Expected On-peak
Solar Derate On-peak
Hydro Expected On-peak
Hydro Derate On-peak
Biomass Expected On-peak
Biomass Derate On-peak
Demand Response Expected
On-peak
Demand Response Derate
On-peak
Transmission-Limited
Resources
Scheduled Outage –
Maintenance
All Other Derates
Energy Only
Wind Expected On-peak
Wind Derate On-peak
Solar Expected On-peak
Solar Derate On-peak
Future, Other
Wind Expected On-peak
Wind Derate On-peak
Solar Expected On-peak
Solar Derate On-peak
Hydro Expected On-peak
Hydro Derate On-peak
Biomass Expected On-peak
Biomass Derate On-peak
Energy Only

26

Year 9
(eg 2020)

Year 10
(eg 2021)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 3. PART A. HISTORICAL AND PROJECTED DEMAND AND CAPACITY - SUMMER
YEAR
Actual
Year 1
Year 2
(eg 2011)
(eg 2012)
(eg 2013)
CAPACITY - Continued (IN MEGAWATTS)

LINE
NO.
8
8a
8a1
8a2
8a3
8a4
8a5
8a6
8a7
8a8
8a9
9

10
10a
10a1
10a2
10b
10c
10c1
10c2

10d

11
11a
11a1
11a2
11b
11c
11c1
11c2

11d

CONCEPTUAL CAPACITY
Conceptual
Wind Expected On-peak
Wind Derate On-peak
Solar Expected On-peak
Solar Derate On-peak
Hydro Expected On-peak
Hydro Derate On-peak
Biomass Expected OnPeak
Biomass Derate On-peak
Energy Only
ANTICIPATED INTERNAL
CAPACITY
CAPACITY TRANSACTIONS –
IMPORTS
Firm
Full-Responsibility Purchases
Owned Capacity/Entitlement
Located Outside the
Region/subregion
Non-Firm
Expected
Full-Responsibility Purchases
Owned Capacity/Entitlement
Located Outside the
Region/subregion
Provisional – transactions under
study, but negotiations have not
begun.
CAPACITY TRANSACTIONS –
EXPORTS
Firm
Full-Responsibility Purchases
Owned Capacity/Entitlement
Located Outside the
Region/subregion
Non-Firm
Expected
Full-Responsibility Purchases
Owned Capacity/Entitlement
Located Outside the
Region/subregion
Provisional – transactions under
study, but negotiations have not
begun.

27

….
….

Year 9
(eg 2020)

Year 10
(eg 2021)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity: _________________________________________________
Reporting Party:___________________________________________
SCHEDULE 3. PART A. HISTORICAL AND PROJECTED DEMAND AND CAPACITY - SUMMER
YEAR
Actual
Year 1
Year 2
….
(eg 2011)
(eg 2012)
(eg 2013)
….
CAPACITY - Continued (IN MEGAWATTS)

LINE
NO.

12
13
14
15
15a

16a
16b
16c
16d
17C
17R

EXISTING, CERTAIN & NET FIRM
TRANSACTIONS
ANTICIPATED CAPACITY
RESOURCES
PROSPECTIVE CAPACITY
RESOURCES
TOTAL POTENTIAL CAPACITY
RESOURCES
ADJUSTED POTENTIAL CAPACITY
RESOURCES
Confidence of Future, Other (7b)
Net Future, Other Resources
Confidence of Conceptual (8)
Net Conceptual Resources
Region/subregion Target Capacity
Margin
Region/subregion Target Reserve
Margin

Margins

18C

Existing Certain and Net Firm
Transactions

19C
20C
21C
22C

Deliverable Capacity Resources
Prospective Capacity Resources
Total Potential Resources
Adjusted Potential Resources

18R

Existing Certain and Net Firm
Transactions

19R
20R
21R
22R

Deliverable Capacity Resources
Prospective Capacity Resources
Total Potential Resources
Adjusted Potential Resources

23
24
25

Other Capacity < 1 MW
Distributed Generator Capacity
>= 1 MW
EIA-860 Capacity Total

28

Year 9
(eg 2020)

Year 10
(eg 2021)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 3. PART B. HISTORICAL AND PROJECTED DEMAND AND CAPACITY - WINTER
YEAR
Actual
Year 1
Year 2
….
(eg 2011)
(eg 2012)
(eg 2013)
….
DEMAND (IN MEGAWATTS)

LINE
NO.

1
1a
1b
1c
1d
2
2a
2b
2c
2d

3

4a
4b
4c
4d

Unrestricted Non-coincident
Peak Demand
New Conservation
Estimated Diversity
Additions for nonmember load
Stand-by Load Under
Contract
Total Internal Demand
Direct Control Load
Management
Contractually Interruptible
Critical Peak Pricing with
Control
Load as a Capacity
Resource

Net Internal Demand
Demand Response Used for
Reserves - Spinning
Demand Response Used for
Reserves – Non-Spinning
Demand Response used for
Regulation
Demand Response used for
Energy, Voluntary –
Emergency

CAPACITY (IN MEGAWATTS)
5

6
6a
6a1
6a2
6a3
6a4
6a5

TOTAL INTERNAL CAPACITY
(sum of 6 and 7)

EXISTING CAPACITY
Existing, Certain
Wind Expected On-peak
Solar Expected On-peak
Hydro Expected OnPeak
Biomass Expected OnPeak
Load as a Capacity
Resource Expected OnPeak

29

Year 9
(eg 2020)

Year 10
(eg 2021)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 3. PART B. HISTORICAL AND PROJECTED DEMAND AND CAPACITY - WINTER
YEAR
Actual
Year 1
Year 2
….
(eg 2011)
(eg 2012)
(eg 2013)
….
CAPACITY (IN MEGAWATTS)

LINE
NO.
6b
6b1
6b2
6b3
6b4
6b5
6b6
6b7
6b8
6c
6c1
6c2
7
7a
7a1
7a2
7a3
7a4
7a5
7a6
7a7
7a8
7a9
7a10
7a11
7a12
7a13
7a14
7b
7b1
7b2
7b3
7b4
7b5
7b6
7b7
7b8
7b9

Existing, Other
Wind Derate On-peak
Solar Derate On-peak
Hydro Derate On-peak
Biomass Derate On-peak
Load as a Capacity
Resource Derate On-peak
Energy Only
Scheduled Outage –
Maintenance
Transmission-Limited
Resources
Existing, Inoperable
Existing, Certain Capacity
Forced Outage On-peak
Existing, Other Capacity
Forced Outage On-peak
FUTURE CAPACITY ADDITIONS
Future, Planned
Wind Expected On-peak
Wind Derate On-peak
Solar Expected On-peak
Solar Derate On-peak
Hydro Expected On-peak
Hydro Derate On-peak
Biomass Expected On-peak
Biomass Derate On-peak
Demand Response Expected
On-peak
Demand Response Derate
On-peak
Transmission-Limited
Resources
Scheduled Outage –
Maintenance
All Other Derates
Energy Only
Future, Other
Wind Expected On-peak
Wind Derate On-peak
Solar Expected On-peak
Solar Derate On-peak
Hydro Expected On-peak
Hydro Derate On-peak
Biomass Expected On-peak
Biomass Derate On-peak
Energy Only

30

Year 9
(eg 2020)

Year 10
(eg 2021)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 3. PART B. HISTORICAL AND PROJECTED DEMAND AND CAPACITY - WINTER
YEAR
Actual
Year 1
Year 2
(eg 2011)
(eg 2012)
(eg 2013)
CAPACITY (IN MEGAWATTS)

LINE
NO.
8
8a
8a1
8a2
8a3
8a4
8a5
8a6
8a7
8a8
8a9
9

10
10a
10a1
10a2
10b
10c
10c1
10c2

10d

11
11a
11a1
11a2
11b
11c
11c1
11c2

11d

CONCEPTUAL CAPACITY
Conceptual
Wind Expected On-peak
Wind Derate On-peak
Solar Expected On-peak
Solar Derate On-peak
Hydro Expected On-peak
Hydro Derate On-peak
Biomass Expected OnPeak
Biomass Derate On-peak
Energy Only
ANTICIPATED INTERNAL
CAPACITY
CAPACITY TRANSACTIONS –
IMPORTS
Firm
Full-Responsibility Purchases
Owned Capacity/Entitlement
Located Outside the
Region/subregion
Non-Firm
Expected
Full-Responsibility Purchases
Owned Capacity/Entitlement
Located Outside the
Region/subregion
Provisional – transactions under
study, but negotiations have not
begun.
CAPACITY TRANSACTIONS –
EXPORTS
Firm
Full-Responsibility Purchases
Owned Capacity/Entitlement
Located Outside the
Region/subregion
Non-Firm
Expected
Full-Responsibility Purchases
Owned Capacity/Entitlement
Located Outside the
Region/subregion
Provisional – transactions under
study, but negotiations have not
begun.

31

….
….

Year 9
(eg 2020)

Year 10
(eg 2021)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 3. PART B. HISTORICAL AND PROJECTED DEMAND AND CAPACITY - WINTER
YEAR
2008
2009
2010
2011
(eg 2011)
(eg 2012)
(eg 2013)
….
CAPACITY - Continued (IN MEGAWATTS)

LINE
NO.

12
13
14
15
15a

16a
16b
16c
16d
17C
17R

EXISTING, CERTAIN & NET FIRM
TRANSACTIONS
ANTICIPATED CAPACITY
RESOURCES
PROSPECTIVE CAPACITY
RESOURCES
TOTAL POTENTIAL CAPACITY
RESOURCES
ADJUSTED POTENTIAL CAPACITY
RESOURCES
Confidence of Future, Other (7b)
Net Future, Other Resources
Confidence of Conceptual (8)
Net Conceptual Resources
Region/subregion Target Capacity
Margin
Region/subregion Target Reserve
Margin

Margins

18C

Existing Certain and Net Firm
Transactions

19C
20C
21C
22C

Deliverable Capacity Resources
Prospective Capacity Resources
Total Potential Resources
Adjusted Potential Resources

18R

Existing Certain and Net Firm
Transactions

19R
20R
21R
22R

Deliverable Capacity Resources
Prospective Capacity Resources
Total Potential Resources
Adjusted Potential Resources

23
24
25

Other Capacity < 1 MW
Distributed Generator Capacity
>= 1 MW
EIA-860 Capacity Total

32

2012
(eg 2020)

2013
(eg 2021)

SCHEDULE 4 - RESERVED

33

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK
POWER SUPPLY AND
DEMAND PROGRAM
REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 5. BULK ELECTRIC TRANSMISSION SYSTEM MAPS
LINE
NO.

1
2

Specify the Number of Maps
Provided:
For each map provide file name, coverage, and map software:
MAP NUMBER (if applicable)
FILE NAME (if applicable)
(a)
(b)

34

MAP SOFTWARE (if applicable)
(d)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 6A. EXISTING AND PROJECTED CIRCUIT MILES
CIRCUIT MILES
AC (kV)

LINE
NO.

1

2
3
4

5

6

7

8

100120

121150

151199

200299

DC (kV)
300399

Existing (as of last
day of prior report
year)
Under Construction
(as of first day of
current report year)
Planned (completion
within first five years)
Conceptual
(completion within
first five years)
Planned (completion
within second five
years)
Conceptual
(completion within
second five years)
Sum of Existing,
Under Construction,
and Planned
Transmission (full tenyear period)
Sum of Existing,
Under Construction,
Planned, and
Conceptual
Transmission (full tenyear period)

Note: Summation columns for AC, DC, and Grand Total are not shown.

35

400599

600
+

100199

200299

300399

400599

600
+

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 6B. CHARACTERISTICS OF PROJECTED TRANSMISSION LINES
TRANSMISSION LINE
(a)

LINE
NO.

TRANSMISSION LINE
(b)

TRANSMISSION LINE
(c)

TRANSMISSION LINE IDENTIFICATION
1
2
3
4a
4b
5
6

Project Name
Project Status
Tie line
Primary Driver
Secondary Driver
Terminal Location (From)
Terminal Location (To)

TRANSMISSION LINE OWNERSHIP
7
Company Name
8
EIA Company Code
9
Type of Organization
10
Percent Ownership
TRANSMISSION LINE DATA
11
Line Length (miles)
12

Line Type

13

Voltage Type

14
15
16
17
18
19
20
21
22
23
24
25
26

[ ]
OH
[ ]
AC

Voltage Operating
(Kilovolts)
Voltage Design (Kilovolts)
Conductor Size (MCM)
Conductor Material Type
(Select codes from legend
below)
Bundling Arrangement
(Select codes from legend)
Circuits per Structure
Present
Circuits per Structure
Ultimate
Pole/Tower Type
(Select codes from legend)
Capacity Rating (MVA)
Original In-Service Date
Expected In-Service Date
Line Delayed?
Cause of Delay

[ ]
UG
[ ]
DC

[ ]
SM

Pole Material: [
Pole Type: [

[ ]
OH
[ ]
AC

]
]

[ ]
UG
[ ]
DC

[ ]
SM

Pole Material: [
Pole Type: [

[ ]
OH
[ ]
AC

]

[ ]
UG
[ ]
DC

[ ]
SM

Pole Material: [
Pole Type: [

]

LEGEND
Line Type
OH=Overhead
UG=Underground
SM=Submarine

Voltage Type

Conductor Material Type Bundling Arrangement

AC=Alternating
AL = Aluminum
Current
DC=Direct Current ACCR = Aluminum
Composite Conductor
Reinforced
ACSR = Aluminum Core
Steel Reinforced
CU = Copper
SUPER = Superconducting
OT = Other

1 = Single
2 = Double
3 = Triple
4 = Quadruple
OT = Other

36

Pole/Tower Type
Pole Material

Pole Type

W = Wood
C = Concrete
S = Steel
B = Combination
P = Composite
O = Other

P = Single pole
H = H-frame
T = Tower
U = Underground
O = Other

]
]

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 7. PART A, ANNUAL DATA ON TRANSMISSION LINE OUTAGES FOR AC LINES
(Report following data for each applicable EHV Voltage Class)
LINE
NO.

1

2
3
4
4a
4b
4c
4d
4e
4f
4g
4h
4i
4j
4k
4l
4m
4n
4o
4p
4q
5
6
7
7a
7b
7c
7d
8
9
10
10a
10b
10c

Applicable AC Voltage Class

200-299 kV

300-399kV

400-599kV

600-799 kV

Reserved

(a)

(b)

(c)

(d)

(e)

Automatic (Unscheduled), Sustained Outages for Specified Voltage Class
Number of Outages
Number of Circuit-Hours Out of Service
Initiating (I) and Sustained (S) Causes
I
S
I
S
I
S
I
(Count of Outages per Cause Category)
Weather, excluding lightning
Lightning
Environmental
Foreign Interference
Contamination
Fire
Vandalism, Terrorism, or
Malicious Acts
Failed AC Substation Equipment
Failed AC/DC Terminal Equipment
Failed Protection System Equipment
Failed AC Circuit Equipment
Failed DC Circuit Equipment
Human Error
Vegetation
Power System Condition
Unknown
Other
Non-Automatic, Operational Outages for Specified Voltage Class
Number of Outages
Number of Circuit-Hours Out of Service
Outage Cause (Count)
Emergency
System Voltage Limit Mitigation
System Operating Limit Mitigation
(excluding voltage)
Other Operational Outage
Non-Automatic, Planned Outages for Specified Voltage Class
Number of Outages
Number of Circuit-Hours Out of Service
Outage Cause (Count)
Maintenance and Construction
Third Party Request
Other Planned Outage

37

S

I

S

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 7. PART B, ANNUAL DATA ON TRANSMISSION LINE OUTAGES FOR DC LINES
(Report following data for each applicable EHV Voltage Class)
LINE
NO.

1

2
3
4
4a
4b
4c
4d
4e
4f
4g
4h
4i
4j
4k
4l
4m
4n
4o
4p
4q
5
6
7
7a
7b
7c
7d
8
9
10
10a
10b
10c

Applicable DC Voltage Class

± 100199 kV
(a)

± 200299 kV
(b)

± 300399 kV
(c)

± 400499 kV
(d)

± 500599 kV
(e)

Automatic (Unscheduled), Sustained Outages for Specified Voltage Class
Number of Outages
Number of Circuit-Hours Out of Service
Initiating (I) and Sustained (S) Causes
I
S
I
S
I
S
I
S
I
(Count of Outages per Cause Category)
Weather, excluding lightning
Lightning
Environmental
Foreign Interference
Contamination
Fire
Vandalism, Terrorism, or
Malicious Acts
Failed AC Substation Equipment
Failed AC/DC Terminal Equipment
Failed Protection System Equipment
Failed AC Circuit Equipment
Failed DC Circuit Equipment
Human Error
Vegetation
Power System Condition
Unknown
Other
Non-Automatic, Operational Outages for Specified Voltage Class
Number of Outages
Number of Circuit-Hours Out of Service
Outage Cause (Count)
Emergency
System Voltage Limit Mitigation
System Operating Limit Mitigation
(excluding voltage)
Other Operational Outage
Non-Automatic, Planned Outages for Specified Voltage Class
Number of Outages
Number of Circuit-Hours Out of Service
Outage Cause (Count)
Maintenance and Construction
Third Party Request
Other Planned Outage

38

S

± 600799 kV
(f)

I

S

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 7. PART C, ANNUAL DATA ON TRANSFORMER OUTAGES
(Report following data for each applicable class)
LINE
NO.

1

2
3
4
4a
4b
4c
4d
4e
4f
4g
4h
4i
4j
4k
4l
4m
4n
4o
4p
4q
5
6
7
7a
7b
7c
7d
8
9
10
10a
10b
10c

Applicable Transformer High-Side Voltage Class
Note: To be reported on this form, the Transformer
must have a low-side voltage ≥200 kV.

200-299 kV
(a)

300-399
kV
(b)

400-599
kV
(c)

600-799
kV
(d)

Automatic (Unscheduled), Sustained Outages for Specified Voltage Class
Number of Outages
Number of Transformer-Hours Out of Service
Initiating (I) and Sustained (S) Causes (Count of
I
S
I
S
I
S
I
Outages per Cause Category)
Weather, excluding lightning
Lightning
Environmental
Foreign Interference
Contamination
Fire
Vandalism, Terrorism, or
Malicious Acts
Failed AC Substation Equipment
Failed AC/DC Terminal Equipment
Failed Protection System Equipment
Failed AC Circuit Equipment
Failed DC Circuit Equipment
Human Error
Vegetation
Power System Condition
Unknown
Other
Non-Automatic, Operational Outages for Specified Voltage Class
Number of Outages
Number of Transformer-Hours Out of Service
Outage Cause (Count)
Emergency
System Voltage Limit Mitigation
System Operating Limit Mitigation
(excluding voltage)
Other Operational Outage
Non-Automatic, Planned Outages for Specified Voltage Class
Number of Outages
Number of Transformer-Hours Out of Service
Outage Cause (Count)
Maintenance and Construction
Third Party Request
Other Planned Outage

39

S

Reserved
(e)

I

S

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 7. PART D, ELEMENT INVENTORY AND EVENT SUMMARY
(Report following data for each applicable voltage class)
LINE
NO.

1
2

Applicable AC Circuit Voltage Class

Overhead

2b

Underground

Overhead

3b

Underground

5
6

600-799
kV
(d)

± 100199 kV
(a)

± 200299 kV
(b)

± 300399 kV
(c)

± 400 499kV
(d)

200-299
kV
(a)

300-399
kV
(b)

400-599
kV
(c)

600-799
kV
(d)

All Voltages
(e)

Number of AC Multi-Circuit Structure
Miles
Applicable DC Circuit Voltage Class

± 500 599kV
(e)

± 600 799kV
(f)

Number of DC Circuits (Total)

6a

Overhead

6b

Underground

7

400-599
kV
(c)

Number of AC Circuit Miles (Total)

3a

4

300-399
kV
(b)

Number of AC Circuits (Total)

2a

3

200-299
kV
(a)

Number of DC Circuit Miles (Total)

7a

Overhead

7b

Underground

8

Applicable Transformer High-Side
Voltage Class
Note: To be reported on this form, the
Transformer must have a low-side voltage
≥200 kV.

9

Number of Transformers

10

Total Number of Events (all Voltage
Classes)

40

Reserved
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK
POWER SUPPLY AND
DEMAND PROGRAM
REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 8. BULK TRANSMISSION FACILITY POWER FLOW CASES
LINE
NO.

1
2
3

Case Name:
Year of Study:
Case Number:
PROSPECTIVE FACILITIES AND CONNECTIONS
PROJECTED
IN-SERVICE
DATE
CONNECTIONS

4

NAME AND TYPE
OF FACILITY
(a)

(e.g., 12-2004)
(b)

BUS NUMBER
(c)

41

BUS NAME
(d)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-411 (2011)

COORDINATED BULK POWER
SUPPLY AND DEMAND
PROGRAM REPORT

Form Approved OMB No. 1905-0129
Burden: 17 hours
Approval Expires: 12/31/2013

Regional Entity:_________________________________________________
Reporting Party:___________________________________________
SCHEDULE 9. COMMENTS
LINE
NO.

SCHEDULE
(a)

PART
(b)

LINE NO.
(c)

COLUMN
(d)

PAGE
(e)

1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27

42

COMMENT
(f)

Subject: United States Department of Energy – EIA Annual Data Collection, Form EIA-826
Dear Respondent:
The Energy Information Administration’s (EIA), Internet Data Collection (IDC) system is now ready for you to
report your electric data for the year 2008. You are required to file Form EIA-826, “Monthly Electric Sales and
Revenue with State Distributions Report.” The survey is due no later than 30 calendar days following the close
of the reporting month. For example, if reporting data for February, the survey is due on March 30, 2008. The EIA
electric surveys are a mandatory collection under the authority of the Federal Energy Administration Act of 1974
(P.L. 93-275). Non-respondents and late filers are subject to financial penalties. The EIA encourages you to file
your data using our IDC system.
If you are currently registered in the IDC system for secure electronic access with a Single Sign-On (SSO) account,
you can login to the IDC system at: https://signon.eia.doe.gov/ssoserver/login and enter your User ID and Password
to access your EIA surveys. If you are registered and have forgotten your password, but know the User ID, you can
reset your password. Log on to the IDC system at the website listed above. Type your User ID and click on Forgot
Your Password. Follow the prompts and you will be allowed to reset your password. Please pay special attention to
the password rules and be sure to record your new password. If you need assistance resetting your password, please
call the Help Center at (202) 586-9595 or contact us via email at: [email protected].
If you are not registered, please contact the CNEAF Help Center at (202) 586-9595 or via email. Please choose only
one method of contact for the CNEAF Help Center, either telephone or email. Please do not do both.
Edits have been built into the IDC system to assist you in providing accurate data. In order to successfully submit
your forms, you must run the edits and address the warning messages for all flagged data by either correcting and/or
commenting on each of the flagged data elements. Please go to the Error Log and click on the “Run EIA-826 Edits”
button. Once you have corrected and/or commented on the appropriate edit flags, you should be able to submit your
data by pressing the “Submit” button. If your data are accepted you should receive a message stating that your data
have been successfully sent with the current date.
The timely submission of Form EIA-826 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.
Your cooperation is greatly appreciated.
Sincerely,
XXXXXXXXXX
Survey Manager
Electric Power Division
Office of Coal, Nuclear, Electric and Alternate Fuels
Energy Information Administration

3

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)
PURPOSE

REQUIRED
RESPONDENTS

RESPONSE DUE
DATE
METHODS OF
FILING
RESPONSE

MONTHLY ELECTRIC SALES AND Form Approved
OMB No. 1905-0129
REVENUE WITH STATE
Approval Expires: 12/31/2013
DISTRIBUTIONS REPORT
Burden: 1.6 hours
INSTRUCTIONS
Form EIA-826 collects information from electric utilities, energy service providers, and distribution
companies that sell or deliver electric power to end users. Data collected on this form includes
sales and revenue for all end-use sectors (residential, commercial, industrial, and transportation).
The data from this form appear in the following EIA publications: Electric Power Monthly, Monthly
Energy Review, and 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.
The Form EIA-826 is a mandatory report for all investor owned electric utilities, all energy service
providers, and other selected electric utilities and distribution companies that sell or distribute
electric power to end users on a monthly basis. The Form EIA-826 is a statistical sample of
respondents chosen from the respondent frame of the Form EIA-861, “Annual Electric Power
Industry Report.”
Monthly data are due to the Energy Information Administration (EIA) by the last day of the month
following the reporting period. For example, if reporting for July, survey is due on August 31.
Submit your data electronically using EIA’s secure e-filing system. 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 email requesting
assistance to: [email protected].

•

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

•

If you are having a technical problem with logging into the e-filing system or using the efiling system, please contact the e-file Help Desk for further information. Contact the Help
Desk at:
Email: [email protected].
Phone: 202-586-9595

•

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

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

Internet System Questions: For questions related to the e-filing system, see the help contact
information immediately above.
Data Questions: For questions about the data requested on Form EIA-826, contact the Survey
Manager:
Charlene Harris-Russell
Telephone Number: (202) 586-2661
FAX Number: (202) 287-1959
Email: [email protected]

1

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)
GENERAL
INSTRUCTIONS

MONTHLY ELECTRIC SALES AND
REVENUE WITH STATE
DISTRIBUTIONS REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

Monthly data are due to the Energy Information Administration (EIA) by the last day of the month
following the reporting period.
1. Enter zero for States without revenue, megawatthours, or number of customers to report for a
particular sector. Do not leave these data fields blank.
2. Submit revisions to data previously reported as soon as possible after the error or omission is
discovered. Do not wait until the next reporting month's form is due to send resubmission(s).
A new submission must be completed for each revised page.
3. If you are unable to make a revision through the E-filing system because the monthly data file
has been locked, please email your revisions to [email protected].
4. Respondents should coordinate the information submitted on the Form EIA-861, “Annual
Electric Power Report," and the Form EIA-826 to ensure consistency.
5. Count each meter as a separate customer in cases where commercial franchise or residential
customer-buying groups have been aggregated under one buyer representative. The
customer counts for public-street and highway lighting should be one customer per
community.

ITEM-BY-ITEM
INSTRUCTIONS

SCHEDULE 1. IDENTIFICATION
1. Survey Contact: Verify contact name, title, telephone number, fax number, and email
address.
2. Supervisor of Contact Person for Survey: Verify for the supervisor of the survey contact,
the name, title, telephone number, fax number and email address.
3. Report For: Verify all information, including Company Name, Company Identification
Number, and reporting month 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.
SCHEDULE 2. SALES TO ULTIMATE CUSTOMERS
SCHEDULE 2. PART A. SALES TO ULTIMATE CUSTOMERS –
FULL SERVICE - ENERGY AND DELIVERY SERVICE (BUNDLED)
Enter the reporting month revenue (thousand dollars to the nearest .001), megawatthours sold
and delivered (to the nearest .001 MWh), and the number of customers for sales of electricity to
ultimate customers by State and customer class category for whom your utility provided both
energy and delivery service. For public street and highway lighting, count all poles in a
community as one customer. Note: For sales to customer groups using brokers or aggregators,
continue to count each customer separately. For instance, count a group of franchised
commercial establishments aggregated through a single broker as separate customers (as
reported in prior years). Enter the two-letter U.S. Postal Service abbreviation (if not preprinted)
for the State in which the electric sales occur.
SCHEDULE 2. PART B. SALES TO ULTIMATE CUSTOMERS –
ENERGY-ONLY SERVICE (WITHOUT DELIVERY SERVICE)
Enter the reporting month revenue (thousand dollars to the nearest .001), megawatthours sold
(to the nearest .001 MWh), and the number of customers for sales of electricity to ultimate
customers by State and customer class category for which your company provided only the
electricity consumed, where another electric company provided delivery services, including, for
example, billing, administrative support, and line maintenance. Enter the two-letter U.S. Postal
Service abbreviation (if not preprinted) for the State in which the electric sales occur. Submit a
2

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND Form Approved
OMB No. 1905-0129
REVENUE WITH STATE
Approval Expires: 12/31/2013
DISTRIBUTIONS REPORT
Burden: 1.6 hours
INSTRUCTIONS
complete list of the “Names of Transmission and Distribution Companies Within each State
providing Delivery Service for Electricity Delivered to an end use customer“. Do not use
acronyms. Submit this list in January of each year or the first month in which you began
reporting the EIA-826. In subsequent months of the reporting year only revise the list with newly
active/inactive companies for the month being reported. This list of companies will aid the EIA in
matching up sales and delivery service in each State.
SCHEDULE 2. PART C. SALES TO ULTIMATE CUSTOMERS –
DELIVERY-ONLY SERVICE (AND ALL OTHER CHARGES)

Enter the reporting month revenue (thousand dollars to the nearest .001), megawatthours
delivered (to the nearest .001 MWh), and number of customers for sales of electricity to ultimate
customers in your service territory by State and customer class category for which your company
provided energy delivery services, where another electric entity or Power Marketer supplied the
electricity. Do not provide delivery service provided on behalf of another delivery company or
utility which would be defined as a sale for resale. Enter the two-letter U.S. Postal Service
abbreviation (if not preprinted) for the State in which the electric sales occur. Submit a complete
list of the ‘Names of Companies (primarily Power Marketers) Within the State for which
Electricity is Delivered to an end use customer“. Do not use acronyms. Submit this list in
January of each year or the first month in which you began reporting the EIA-826. In subsequent
months of the reporting year only revise the list with newly active/inactive companies for the
month being reported. This list of companies will aid the EIA in maintaining a current list of
entities doing business in each State.
SCHEDULE 2. PART D. SALES TO ULTIMATE CUSTOMERS –
BUNDLED SERVICE BY RETAIL ENERGY PROVIDERS OR ANY POWER MARKETER THAT
PROVIDES “BUNDLED SERVICE.”
Enter the reporting month revenue (thousand dollars to the nearest .001), megawatthours sold and
delivered (to the nearest .001 MWh), and the number of customers for sales of electricity to
ultimate customers by State and customer class category for whom your company provided both
energy and delivery service. For public street and highway lighting, count all poles in a community
as one customer.
Note: For sales to customer groups using brokers or aggregators, continue to count each
customer separately. For instance, count a group of franchised commercial establishments
aggregated through a single broker as separate customers (as reported in prior years). (Note:
Texas Retail Energy Providers (REPs) should include delivery revenues.) Enter the two-letter U.S.
Postal Service abbreviation (if not preprinted) for the State in which the electric sales occur.
SCHEDULE 2, PARTS A-D
1.

For column a, Residential, enter the revenue, megawatthours, and number of customers
for residential (household) purposes. For the residential class, do not duplicate the
customer accounts due to multiple metering for special services (e.g., water heating, etc.).
Show Revenue and Megawattshours Sold to the nearest 0.001 value.

2.

For column b, Commercial, enter the revenue, megawatthours, and number of customers
for commercial purposes. Show Revenue and Megawattshours Sold to the nearest 0.001
value.

3.

For column c, Industrial, enter the revenue, megawatthours, and number of customers for
industrial purposes. Show Revenue and Megawattshours Sold to the nearest 0.001 value.

4.

For column d, Transportation, enter the revenue, megawatthours, and number of
customers for electric energy supplied for transportation purposes. Show Revenue and
Megawattshours Sold to the nearest 0.001 value.
3

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)
5.

MONTHLY ELECTRIC SALES AND Form Approved
OMB No. 1905-0129
REVENUE WITH STATE
Approval Expires: 12/31/2013
DISTRIBUTIONS REPORT
Burden: 1.6 hours
INSTRUCTIONS
For column e, Total, enter, for each State, the sum of the revenue, megawatthours, and
number of customers entered for residential, commercial, industrial, and transportation
sales. Show Revenue and Megawattshours Sold to the nearest 0.001 value.

6.

Previously reported “public street and highway lighting” data should now be included in the
commercial sector. Irrigation data should now be included in the industrial sector.

7.

Attach additional sheet(s), if required.

8.

Refer to the Glossary for the definition of selected terms.
SCHEDULE 3.
SCHEDULE 3, PART A. GREEN PRICING

Green Pricing programs allow electricity customers the opportunity to purchase electricity
generated from renewable resources and to pay for renewable energy development.
Renewable resources include solar, wind, geothermal, hydroelectric power, and wood.
These programs are voluntary where customers pay an additional fee to purchase electricity
generated from renewable sources. Renewable Energy Certificates (RECs), also known as
green certificates, green tags, or tradable renewable certificates, represent the environmental
attributes of the power produced from renewable energy projects and are sold separately
from the electricity commodity. Customers can buy RECs even if they do not have access to
green power through their local utility or a competitive electricity marketer. They can also
purchase RECs without having to switch electricity suppliers.
Line1: Report the Total Green Pricing Revenue for customers in each customer class.
Revenue should be reported in thousands of dollars to the nearest .001 (for example, $1,299
would be reported as 1.299 thousand dollars). Revenue should include revenue from the
green pricing program plus the price of the electricity purchased.
Example: For 1000 kWh of electricity sales, if the normal price for electricity is $0.10 per kWh:
a) An entity sells Green Energy in blocks of $5.50 per 100 kWh block:
Total cost = (1,000kWh x $0.10/kWh) + (($5.50/100kWh block) x (10 blocks of
100 kWh))
= $100.00 + $55.00
= $155.00
b) Alternatively, an Entity which sells Green Energy for a premium of $0.02 per
kWh:
Total cost = (1,000kWh x $0.10/kWh) + (($0.02/kWh) x (1,000kWh))
= $100.00 + $20.00
= $120.00
Line 2: Report the Total Green Pricing Sales, the total amount of megawatthours purchased
by customers for each green pricing customer class (for example, 1,299 kWh would be
reported as 1.299 MWh).
Line 3: Report the Total Green Pricing Customers, the number of customers who purchased
green power for each customer class. The sales volumes and the number of customers
should not exceed the values reported in Schedule 2, Parts A, B, or D.
Line 4: Report the revenue from RECs for each customer class in thousand of dollars to the
nearest tenth. This revenue must not exceed the Total Green Power Revenue reported in line
1 above.
Line 5: Report the sales from RECs in megawatthours for each customer class. This amount
should not exceed the Total Green Pricing Sales reported in line 2 above,
4

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND Form Approved
OMB No. 1905-0129
REVENUE WITH STATE
Approval Expires: 12/31/2013
DISTRIBUTIONS REPORT
Burden: 1.6 hours
INSTRUCTIONS
The Total for each customer class will automatically sum for the electronic online e-file
system.
SCHEDULE 3, PART B. NET METERING

Net Metering tariff arrangements permit a facility, typically generating electricity from a
renewable resource, (using a meter that reads inflows and outflows of electricity) to sell any
excess power it generates over its load requirement back to the electrical grid, typically at a
rate equivalent to the retail price of electricity.
For net metering applications of 2 MW nameplate capacity or less, report the installed net
metering capacity by State, customer class and technology. Report net metering data by
sector and technology type for each state. Capacity should be reported in MW as AC load
capable. Example: 8 kW should be 0.008 MW. Capacities should not exceed limits set up by
each state. Please provide this capacity in MW, to the nearest 0.001 MW by technology. Do
not report for net metering applications larger than 2 MW.
If the data is available, enter the amount of electric energy sold back to the utility (MWh)
through the net metering application. Report the number of net metering customers by
customer class. If you are unable to utilize the e-file system which creates the totals
automatically; then provide the Totals for net metering megawatthours, installed net metering
capacity and customers by State, customer class and technology. Complete all lines for
Schedule 3, Part B.
SCHEDULE 3, PART C. ADVANCED METERING

This schedule should only include customers from Schedule 2 Part A or Part C.
Standard (Electric) Meters are electromechanical or solid state meters measuring aggregated
kWh where data are manually retrieved over monthly billing cycles for billing purposes only.
Standard meters may also include functions to measure time-of-use and/or demand with data
manually retrieved over monthly billing cycles.
Automated Meter Reading (AMR): Meters that collect data for billing purposes only and
transmit this data one way, usually from the customer to the distribution utility. Aggregated
monthly kWh data captured on these meters may be retrieved by a variety of methods including
drive-by vans with short-distance remote reading capabilities and communication over a fixed
network such as a cellular network.
Enter the state and report the total number of AMR meters by sector. The number of AMR
meters may be equal to but not exceed the number of customers on Schedule 2.
Advanced Metering Infrastructure (AMI): Meters that measure and record usage data at a
minimum, in hourly intervals, and provide usage data to both consumers and energy companies
at least once daily. Data are used for billing and other purposes. Advanced meters include
basic hourly interval meters and extend to real-time meters with built-in two-way communication
capable of recording and transmitting instantaneous data.
Enter the state and report the total number of AMI meters by sector.
For AMI meters that are only being used as AMR, report meters as AMR.
Energy Served through AMI (MWh) should be entered in megawatthours for customers
served.
If the data is available, enter the amount of electric energy sold back to the utility (MWh) through
the net metering application.
5

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND Form Approved
OMB No. 1905-0129
REVENUE WITH STATE
Approval Expires: 12/31/2013
DISTRIBUTIONS REPORT
Burden: 1.6 hours
INSTRUCTIONS
SCHEDULE 4. MERGERS AND/OR ACQUISITIONS

If a merger or acquisition has occurred during the reporting period, report those newly-acquired
corporate entities whose operations are now included in this report.
SCHEDULE 5. COMMENTS
Explanations of entries or other comments may be provided in the comment section.
GLOSSARY

The glossary for this form is available online at the following URL:
http://www.eia.gov/glossary/index.html

SANCTIONS

The timely submission of Form EIA-826 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 1.6 hours per
response, 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, D.C. 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

The information reported on Form EIA-826 will be treated as non-sensitive and may be publicly
released in identifiable form, except as noted below.
The information reported on SCHEDULE 2 PARTS B and D, and SCHEDULE 3 PART A on Form
EIA-826 will be protected and not disclosed for nine (9) months after the end of the of the reporting
year to the extent that it satisfies the criteria for exemption under the Freedom of Information Act
(FOIA), 5 U.S.C. §552, the Department of Energy (DOE) regulations, 10 C.F.R. §1004.11,
implementing the FOIA, and the Trade Secrets Act, 18 U.S.C. §1905. After nine (9) months from
the end of the reporting year this information will be considered non-sensitive and may be publicly
released in identifiable form. All other information reported on Form EIA-826 are considered public
information and may be publicly released in company identifiable form
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 2, PARTS B and D, and SCHEDULE 3 PART A on Form EIA-826 relating to
Revenue, Megawatthours Sold, and Number of Customers until nine (9) months after the end of
the reporting year to ensure that the risk of disclosure of identifiable information is very small until
then.
6

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES
AND REVENUE WITH STATE
DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

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:______________________________
Telephone (include extension):______________
Fax:__________________
Email:_______________________________
Supervisor of Contact Person for Survey
First Name:____________________
Last Name:_____________________
Title:___________________________
Telephone (include extension):______________
Fax:__________________
Email:________________________________
Report For
Company Name: _____________________________________________
Company ID:_________________
Reporting Month/Year:________________
Respondent
Type
(check one)

[ ] Federal
[ ] Political Subdivision
[ ] Municipal Marketing Authority
[ ] Cooperative
[ ] Independent Power Producer or
Qualifying Facility

[ ] State
[ ] Municipal
[ ] Investor-Owned
[ ] Retail Power Marketer (or Energy
Service Provider)

For questions or additional information about the Form EIA-826, contact the Survey Manager:
Charlene Harris-Russell
Telephone: (202) 586-2661
FAX Number: (202) 287-1959
Email: [email protected]

7

U.S. Department of Energy
Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND REVENUE
WITH STATE DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

Company Name:_________________________________________
Company ID:_______
Reporting Month/Year:________________
SCHEDULE 2. PART A. SALES TO ULTIMATE CUSTOMERS – FULL SERVICE - ENERGY AND DELIVERY SERVICE (BUNDLED)
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
TRANSPORTATION
TOTAL
(a)
(b)
(c)
(d)
(e)
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Sold and
Delivered
(To nearest 0.001)
Number of Customers
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Sold and
Delivered
(To nearest 0.001)
Number of Customers
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Sold and
Delivered
(To nearest 0.001)
Number of Customers
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Sold and
Delivered
(To nearest 0.001)
Number of Customers

1

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND REVENUE
WITH STATE DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

Company Name:_________________________________________
Company ID:_______
Reporting Month/Year:________________
SCHEDULE 2. PART B. SALES TO ULTIMATE CUSTOMERS – ENERGY-ONLY SERVICE (WITHOUT DELIVERY SERVICE)
RESIDENTIAL
(a)

COMMERCIAL
(b)

INDUSTRIAL
(c)

STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Sold
(To nearest 0.001)
Number of Customers
Names of Companies
within each State providing
Delivery Service
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Sold
(To nearest 0.001)
Number of Customers
Names of Companies
within each State providing
Delivery Service
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Sold
(To nearest 0.001)
Number of Customers
Names of Companies
within each State providing
Delivery Service

2

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND REVENUE
WITH STATE DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours.

Company Name:_________________________________________
Company ID:_______
Reporting Month/Year:________________
SCHEDULE 2. PART C. SALES TO ULTIMATE CUSTOMERS – DELIVERY-ONLY SERVICE (AND ALL OTHER CHARGES)
RESIDENTIAL
(a)

COMMERCIAL
(b)

INDUSTRIAL
(c)

STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Delivered
(To nearest 0.001)
Number of Customers
List Names of Companies
(primarily Power
Marketers) Within the State
for which Electricity is
Delivered to an end use
customer
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Delivered
(To nearest 0.001)
Number of Customers
List Names of Companies
(primarily Power
Marketers) Within the State
for which Electricity is
Delivered to an end use
customer

3

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND REVENUE
WITH STATE DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

Company Name:_________________________________________
Company ID:_______
Reporting Month/Year:________________
SCHEDULE 2. PART D. SALES TO ULTIMATE CUSTOMERS – BUNDLED SERVICE BY RETAIL ENERGY PROVIDERS, OR
ANY POWER MARKETER THAT PROVIDES “BUNDLED SERVICE.”
RESIDENTIAL
(a)

COMMERCIAL
(b)

INDUSTRIAL
(c)

STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Delivered
(To nearest 0.001)
Number of Customers
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Delivered
(To nearest 0.001)
Number of Customers
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Delivered
(To nearest 0.001)
Number of Customers
STATE
Revenue (thousand dollars)
(To nearest 0.001)
Megawatthours Delivered
(To nearest 0.001)
Number of Customers

4

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND REVENUE WITH
STATE DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

Company Name:_________________________________________
Company ID:_______
Reporting Month/Year:________________
SCHEDULE 3. PART A. GREEN PRICING
Green Pricing programs are voluntary programs where customers pay an extra fee to purchase electricity generated from renewable sources. Renewable Energy Certificates
(RECs) are a category of Green Pricing that involves the sale of the renewable attribute created with renewable electricity generation.

Line No.

STATE

1.

Total Green Pricing Revenue
(Thousand Dollars)
(To nearest 0.001)

2.

Total Green Pricing Sales (MWhs)
(To nearest 0.001)

3.

Total Green Pricing Customers

4.
5.

RESIDENTIAL
(a)

COMMERCIAL
(b)

Revenue from RECs
(Thousand Dollars)
(To nearest 0.001)
REC Sales
(MWhs)
(To nearest 0.001)

5

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND REVENUE WITH
STATE DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

Company Name:____________________________________
Company ID:
Reporting Month/Year:_____________
SCHEDULE 3, PART B. NET METERING
Net Metering programs allow customers to sell excess power they generate back to the electrical grid to offset consumption. For net metering applications of 2 MW
nameplate capacity and less, provide the information about programs by State and customer class.
RESIDENTIAL
(a)

STATE

If Available, Enter the Electric Energy
Sold Back to the Utility (MWh)
Photovoltaic

Installed Net Metering Capacity (MW)
Number of Net Metering Customers
If Available, Enter the Electric Energy
Sold Back to the Utility (MWh)

Wind

Installed Net Metering Capacity (MW)
Number of Net Metering Customers
If Available, Enter the Electric Energy
Sold Back to the Utility (MWh)
CHP/Cogen

Installed Net Metering Capacity (MW)
Number of Net Metering Customers
If Available, Enter the Electric Energy
Sold Back to the Utility (MWh)

Other

Installed Net Metering Capacity (MW)
Number of Net Metering Customers
Total Energy Sold Back to the Utility
(MWh)

Total

Installed Net Metering Capacity (MW)
Number of Net Metering Customers
6

COMMERCIAL
(b)

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND REVENUE WITH
STATE DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

Company Name:____________________________________
Company ID:_______
Reporting Month/Year:_____________
SCHEDULE 3. PART C. ADVANCED METERING
Only customers from Schedule 2A and 2C report on this schedule. AMR – transmitted one-way, from the customer to the utility. AMI – data can be
transmitted in both directions, between the delivery entity and the customer.
State
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
TRANSPORTATION
TOTAL
(a)
(b)
(c)
(d)
(e)
Number of AMR Meters
Number of AMI Meters
Energy Served Through AMI Meters (MWh)
(To nearest 0.001)
State

RESIDENTIAL
(a)

COMMERCIAL
(b)

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

RESIDENTIAL
(a)

COMMERCIAL
(b)

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

Number of AMR Meters
Number of AMI Meters
Energy Served Through AMI Meters (MWh)
(To nearest 0.001)
State
Number of AMR Meters
Number of AMI Meters
Energy Served Through AMI Meters (MWh)
(To nearest 0.001)

7

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND REVENUE
WITH STATE DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

Company Name:_________________________________________
Company ID:_______
Reporting Month/Year:________________
SCHEDULE 4. MERGERS AND/OR ACQUISITIONS
Mergers and/or acquisitions during the reporting month:

Yes
No

If Yes, Provide:
Date of Merger or Acquisition ___________________________________
Company merged with or acquired ______________________________
Name of new parent company __________________________________

Address______________________________________________________
Contact name: ______________________ Telephone No. ____________
Email address: _______________________________________________

8

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-826 (2011)

MONTHLY ELECTRIC SALES AND REVENUE
WITH STATE DISTRIBUTIONS REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 1.6 hours

Company Name:_________________________________________
Company ID:_______
Reporting Month/Year:________________
SCHEDULE 5. COMMENTS
If explanation of any provided data is needed, please provide that information here.

9

Subject: United States Department of Energy – EIA Annual Data Collection, Form EIA-860

Dear Respondent:
The Energy Information Administration’s (EIA), e-filing system is now ready for you to report your annual electric
data for the year 2009. You are required to file Form EIA-860, “Annual Electric Generator Report.” The
survey is due no later than May 14, 2010. The 2009 Form EIA-860 survey represents the status of plants and
associated equipment as of December 31, 2009. Please verify and update the data as necessary.
The EIA electric surveys are a mandatory collection under the authority of the Federal Energy Administration Act of
1974 (P.L. 93-275). Non-respondents and late filers are subject to financial penalties. The EIA encourages you to
file your data using our e-filing system.
We currently have the following companies associated with you as the primary contact for the EIA-860:
<%UTILITIES%>
If you are currently registered in the e-filing system for secure electronic access with a Single Sign-On (SSO)
account, you can login to the e-file system at: https://signon.eia.doe.gov/ssoserver/login and enter your User ID and
Password to access your EIA surveys.
If you are registered and have forgotten your password, but know the User ID, you can reset your password. Log on
to the e-filing system at the website listed above. Type your User ID and click on Forgot Your Password. Follow
the prompts and you will be allowed to reset your password. Please pay special attention to the password rules and
be sure to record your new password. If you need assistance resetting your password, please call the Help Center at
(202) 586-9595 or contact us via e-mail at: [email protected].
If you are not registered, please contact the CNEAF Help Center at (202) 586-9595 or via e-mail. Please choose
only one method of contact for the CNEAF Help Center, either telephone or e-mail. Please do not do both. When
you receive your new credentials, register immediately. Your credentials will expire in 30 days.
You must contact us if a record(s) for new or missing plant(s) needs to be added to Schedule 2. However, you have
the capability to add record(s) for new or missing generator(s) in Schedule 3. Fields for certain data are unlikely to
change. These fields (e.g., geographic location of power plant, initial year of commercial operation of generator)
have been locked if data already exist in the fields. For such fields, if the data are incorrect, please contact me at
202-586-1029 with the correct data, or enter the correct data in Schedule 7 along with the identifiers and form
location of the data. Otherwise, if the field is null, please provide the missing data, if applicable. To add a record
for boiler or other equipment in Schedule 6A, please contact the EIA with the identifiers that your company uses to
identify the equipment and we will add them to that schedule.
Edits have been built into the e-filing system to assist you in providing accurate data. In order to successfully
submit your forms, you must run the edits and address the warning messages for all flagged data by either correcting
and/or commenting on each of the flagged data elements. Please go to the Error Log and click on the “Run EIA-860
Edits” button. Once you have corrected and/or commented on the appropriate edit flags, you should be able to
submit your data by pressing the “Submit” button. If your data are accepted you should receive a message stating
that your data have been successfully submitted.
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

4

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.
Your cooperation is greatly appreciated.
Sincerely,

Patricia (Trisha) Hutchins
EIA-860 Survey Analyst
Electric Power Division
Office of Coal, Nuclear, Electric and Alternate Fuels
Energy Information Administration

5

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

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 10 years of the
specified reporting period. 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

The required respondents for Form EIA-860 are all existing plants and proposed (10-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. See General Instructions for related details to determine total capacity at
a site.
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 e-filing system. 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 email requesting
assistance to: [email protected]

•

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

•

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

•

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

Please retain a completed copy of this form for your files.
CONTACTS

Internet System Questions: For questions related to the e-filing system, see the help contact
information immediately above.
Data Questions: For questions about the data requested on Form EIA-860, contact the survey staff:
Patricia Hutchins
Telephone Number: (202) 586-1029
Fax Number: (202) 287-1960
Email: [email protected]
1

Vlad Dorjets
Telephone Number: (202) 586-3141
Fax Number: (202) 287-1960
Email: [email protected]

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)
GENERAL
INSTRUCTIONS

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

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
in 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 end of the data year. If your 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 email
address, if known) in SCHEDULE 7. COMMENTS. Do not complete the form for that
power plant.
8. To request additional blank schedules contact the U.S. Energy Information Administration using
the contact information on page 1, or download the form from
http://www.eia.gov/cneaf/electricity/page/forms.html.
9. For definitions of terms, refer to the U.S. Energy Information Administration glossary at
http://www.eia.gov/glossary/index.html.
10. For the purpose of determining reporting requirements, the capacity of a power plant is the sum
of the maximum ratings (in megawatts) on the nameplates of all applicable generators at a
specific site. For photovoltaic (PV) solar, use the AC ratings of the array for a specific site.

ITEM-BY-ITEM
INSTRUCTIONS

SCHEDULE 1. IDENTIFICATION
1. Survey Contact: Verify contact name, title, address, telephone number, fax number, and email
address.
2. Supervisor of Contact Person for Survey: Verify the contact’s supervisor’s name, title,
address, telephone number, Fax number and email 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, enter 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
2

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

services companies under contract to operate the plant for the electric power producer; 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, enter the principal
name and address of where the operator’s principal office is located. Include an attention line,
room number, building designation, etc.
6. For Preparer's Legal Name, enter the name if different from Legal Name of Operator.
7. For Current Address of Preparer's Office enter preparer’s current address if it is different from
the address of the Legal Name of Operator.
8. For Is the Operator an Electric Utility or Owned by 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 10 years of the specified reporting period. 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 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 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”) to which the measurement is keyed. “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.
8. For line 8a, NERC Region, enter the NERC region in which the plant is located.
9. For line 8b, Does this Plant Belong to a RTO or ISO?, check “Yes” or “No” for whether the
plant belongs to a Regional Transmission Operator or Independent System Operator.
10. For line 8c, Name of RTO or ISO, if you answered “Yes” in line 8b, select the RTO or ISO from
the list. If your RTO or ISO does not appear on the list, select “Other” and explain in SCHEDULE
7. COMMENTS.
11. 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
3

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

directly obtained or the water source for hydrokinetic projects. 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.
12. For line 10, Steam Plant Status, and line 11, Steam Plant Type, enter the appropriate status
and type if this plant is a combustible-fueled steam generators, including heat recovery steam
generators with duct firing and combustible renewable-fueled generators.
13. 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.
14. For 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. Please do not include the prefix (e.g. QF, EWG, etc.)
when entering the docket numbers. Only include the numerical portion of the docket number,
including dashes.
15. For 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. Please do not include the prefix (e.g. QF, EWG,
etc.) when entering the docket numbers. Only include the numerical portion of the docket
number, including dashes.
16. For 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. Please do not include the prefix (e.g. QF,
EWG, etc.) when entering the docket numbers. Only include the numerical portion of the docket
number, including dashes.
17. For line 16a, Owner of Transmission/Distribution Facilities, enter the name of the current
owner of the transmission or distribution facilities to which the plant is interconnected. If the plant
is interconnected to multiple owners, enter the name of the principal owner and list the other
owners and their roles in SCHEDULE 7. COMMENTS.
18. For line 16b, Grid Voltage (in kilovolts), enter the grid voltage at the point of interconnection to
the transmission/distribution facilities. If the plant is interconnected to multiple
transmission/distribution facilities, enter the highest grid voltage and list the other grid voltages in
SCHEDULE 7. COMMENTS.
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 10 years of the specified reporting period 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.

4

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

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. POWER PLANT DATA.
2. For line 2, EIA Plant Code, enter the EIA plant code as reported on SCHEDULE 2. POWER
PLANT DATA.
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, Associated Boiler Identifications, enter, for combustible-fueled steam generators,
including heat recovery steam generators with duct firing and combustible renewable-fueled
generators with total generator nameplate capacity of 10 MW or greater, the identification (ID)
code for each boiler that provides steam to the generator. The ID should match those provided
in SCHEDULE 6. BOILER INFORMATION. The applicable parts of SCHEDULE 6. BOILER
INFORMATION must be completed for each boiler.
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
BA
CP
FW
ES
ST
GT
IC
CA
CT
CS
CC
HA
HB
HK
HY
PS
BT
PV
WT
CE
FC
OT

Prime Mover Description
Energy Storage, Battery
Energy Storage, Concentrated Solar Power
Energy Storage, Flywheel
Energy Storage, Other (specify in SCHEDULE 7. COMMENTS)
Steam Turbine, including nuclear, geothermal and solar steam (does not
include combined cycle)
Combustion (Gas) Turbine (includes jet engine design)
Internal Combustion Engine (diesel, piston, reciprocating)
Combined Cycle Steam Part
Combined Cycle Combustion Turbine Part (type of coal or solid must be
reported as energy source for integrated coal gasification).
Combined Cycle Single Shaft (combustion turbine and steam turbine share
a single generator)
Combined Cycle Total Unit (use only for plants/generators that are in
planning stage, for which specific generator details cannot be provided)
Hydrokinetic, Axial Flow Turbine
Hydrokinetic, Wave Buoy
Hydrokinetic, Other (specify in SCHEDULE 7. COMMENTS)
Hydroelectric Turbine (Conventional Hydroelectric; includes turbines
associated with delivery of water by pipeline)
Hydraulic Turbine, Reversible (pumped storage)
Turbines Used in a Binary Cycle (including those used for geothermal
applications)
Photovoltaic
Wind Turbine
Compressed Air Energy Storage
Fuel Cell
Other (specify 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
5

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

be reported as combined cycle types.
6. For line 6, Unit Code (Multi-Generator Code), identify all generators that are operated with
other generators as a single unit. Generators operating as a single unit should have the same
unit (multi-generator code) code or four-character identifier. Identify combined cycle generators
that operate as a unit with a unique four-character identifier. All generators that operate as a
unit in combined cycle must have the same unique identifier. If generators do not operate as a
single unit, this space should be left blank.
7. For line 7, Ownership, 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 generator?, an electric utility generator shall
mean a generator that is owned by an electric utility, or a jointly owned generator with the
greatest share of the generator being electric utility owned. (Note: If two or more owners have
equal shares of ownership in a generator, it is considered to be an electric utility generator if any
one of the owners meets the definition of electric utility). For each electric utility generator,
check “Yes” or “No.”
9. For line 9, Date of Sale, If Sold, enter the month and year of the sale of the generator (e.g., 122007), if the generator has been sold in its entirety. For changes in shares of ownership only,
with no change in operator, report in SCHEDULE 4. OWNERSHIP OF GENERATORS OWNED
JOINTLY OR BY OTHERS. In SCHEDULE 7. COMMENTS provide the legal name, business
address, contact person, phone number and email 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. BOILER INFORMATION 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. COMMENTS.
2. For line 2, Net Capacity, enter the generator's net summer and net winter capacities for the
primary energy source. 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, Maximum Expected Reactive Power Output (MVAR), enter the maximum reactive
power outputs (MVAR) at the high side of the generator step-up transformer for generators with
nameplate capacity of 10 MW or greater. A MVAR is a Mega Voltampere Reactive.
4. For line 3b, Maximum Reactive Power Absorption (MVAR), enter the maximum reactive
power absorptions of the generator at the high side of the generator step-up transformer for
generators with nameplate capacity of 10 MW or greater. A MVAR is a Mega Voltampere
Reactive.

6

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

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

SB
OA

OS
RE

Status Code Description
Operating - in service (commercial operation) and producing some
electricity. Includes peaking units that are run on an as needed (intermittent
or seasonal) basis.
Standby/Backup - available for service but not normally used (has little or no
generation during the year) for this reporting period.
Out of service – was not used for some or all of the reporting period but was
either returned to service on December 31 or will be returned to service in
the next calendar year.
Out of service – was not used for some or all of the reporting period and is
NOT expected to be returned to service in the next calendar year.
Retired - no longer in service and not expected to be returned to service.

6. For line 5, Synchronized to the Grid, if the status code entered on line 4 is standby (SB)
please note if the generator is currently equipped such that, when operating, it can be
synchronized to the grid.
7. For line 6, Initial Date of Operation, enter the month and year of initial commercial operation.
8. For line 7, Retirement Date, enter the month and year that the generator was retired.
9. For line 8, Is this generator associated with a Combined Heat and Power system check
either "Yes" or "No." If the answer is “Yes,” check whether the generator is part of a topping or
bottoming 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, if the prime mover is ST (steam turbine) report the Start-Up and Flame
Stabilization Energy Sources used by the combustion unit(s) associated with this generator;
otherwise leave blank.
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)
7

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

15. For line 13, Is This Generator Part of a Solid Fuel Gasification System, check “Yes” or “No”
as appropriate.
16. For line 14, Number of Turbines, Buoys, or Inverters, if energy source is wind, enter the
number of turbines; if the energy source is wave energy, enter the number of buoys; if energy
source is other hydrokinetics, enter the number of turbines; if the energy source is solar
photovoltaic, enter the number of inverters.
17. For line 15a, Tested Heat Rate, enter the tested heat rate under full load conditions for all
combustible-fueled generators, nuclear-fueled generators, concentrated solar generators and
geothermal generators. 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. For solar photovoltaic generators, provide the average module efficiency for all
installed modules. If the reported value is not a tested heat rate, specify in SCHEDULE 7.
COMMENTS.
18. For line 15b, Fuel Used for Heat Rate Test, enter the fuel code or “M” for multiple fuels for the
fuel used to calculate the heat rate reported above. 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).
19. For line 16, Annual Average Operating Efficiency for Solar Photovoltaic, Wind and
Hydroelectric Generators, enter the annual average operating efficiency for solar photovoltaic,
wind and hydroelectric generators.
Proposed Changes to Existing Generators (within the next 10 years)
20. For line 17a, indicate whether there are any planned capacity up-rates/de-rates, repowering,
other modifications, or generator retirements scheduled to take place within the next 10 years.
21. For line 17b, Planned Uprates, enter the increase in capacity expected to be realized from the
uprate. Enter the planned effective date (MM-YYYY) that the generator is scheduled to enter
operation after the modification.
22. For line 17c, Planned Derates, enter the decrease in capacity expected to be realized from the
derate. Enter the planned effective date (MM-YYYY) that the generator is scheduled to enter
operation after the modification.
23. For line 17d, Planned Repowering, if a repowering of the generator is planned, enter the new
prime mover, the new energy source, and new nameplate capacity as well as the planned
effective date (MM-YYYY) that the generator is scheduled to enter operation after the repowering is complete.
24. For line 17e, Other Modifications, 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,
25. For line 17f, Retirement, if the generator is expected to be retired within the next 10 years, enter
the planned effective date (MM-YYYY) of that scheduled retirement.
26. For line 18, Can This Generator be Powered by Multiple Fuels?, indicate if the combustion
8

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

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. GENERATOR
INFORMATION - PROPOSED GENERATORS.
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.
27. For line 19, Can This Unit Co-Fire Fuels?, indicate whether or not the combustion system that
powers the generator has, in working order, the equipment and the regulatory permits necessary
to co-fire fuels. If the answer is “No,” skip to line 23.
28. 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 1 in 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).
29. For line 21, Can This Generator be Powered by Co-Fired Fuel Oil and Natural Gas?,
indicate if the combustion system that powers the generator can co-fire fuel oil with natural gas.
If the answer is “No,” skip to line 23.
30. For line 22, Can This Generator be Run on 100% 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 it is “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, taking into account all applicable legal, regulatory, and technical limits. Also provide the
maximum output (summer net MW) that the unit can achieve, taking into account all applicable
legal, regulatory, and technical limits when making the maximum use of oil and co-firing natural
gas.
31. For line 23, Can This Unit 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. If “No,” skip to SCHEDULE 3, PART C, GENERATOR
INFORMATION - PROPOSED GENERATORS.
32. For line 24, Can This Unit Switch Between Oil and Natural Gas?, indicate whether or not the
combustion system that powers the generator has, in working order, the equipment and the
regulatory permits necessary to switch between oil and natural gas. If “No,” go to line 26. If
“Yes,” indicate whether the unit can switch fuels while operating (i.e., without shutting down the
unit). Also 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, 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, and how long it takes to switch the
generator from using 100 percent natural gas to 100 percent oil.
33. For line 25, Are There Factors That Limit the Unit’s Ability to Switch From Natural Gas to
Oil?, 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.
34. 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).
9

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

SCHEDULE 3, PART C. GENERATOR INFORMATION – PROPOSED GENERATORS
1. For line 1, Generator Nameplate Capacity, enter the highest value on the nameplate in
megawatts rounded to the nearest tenth. If the nameplate capacity is expressed in kilovolt
amperes (kVA), convert to kilowatts by multiplying the corresponding power factor by the kVA,
divide by 1,000 to express in megawatts to the nearest tenth. If the generator nameplate is not
known at this time, estimate the nameplate rating for the generator and note this as an estimate
in SCHEDULE 7. COMMENTS.
2. For line 2, Net Capacity, enter the generator’s 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, Maximum Expected Reactive Power Output (MVAR), enter the maximum
expected reactive power outputs (MVAR) at the high side of the generator step-up transformer
for generators with nameplate capacity of 10 MW or greater. A MVAR is a Mega Voltampere
Reactive.
4. For line 3b, Maximum Reactive Power Absorption (MVAR), enter the maximum expected
reactive power absorptions of the generator at the high side of the generator step-up transformer
for generators with nameplate capacity of 10 MW or greater. A MVAR is a Mega Voltampere
Reactive.
5. For line 4, Status Code, enter one of the following status codes:
Status Code
IP
TS
P
L
T
U
V
OT

Status Code Description
Planned new generator canceled, indefinitely postponed, or no longer in
resource plan
Construction complete, but not yet in commercial operation (including low
power testing of nuclear units)
Planned for installation but regulatory approvals not initiated; Not under
construction
Regulatory approvals pending. Not under construction but site preparation
could be underway
Regulatory approvals received. Not under construction but site preparation
could be underway
Under construction, less than or equal to 50 percent complete (based on
construction time to date of operation)
Under construction, more than 50 percent complete (based on construction
time to date of operation)
Other (specify 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?
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
10

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

instructions.
12. For line 11, if the expected predominant energy source for powering the generator is coal or
petroleum coke, check all the types of technology and steam conditions that apply.
13. For line 12, Expected Second Most Predominant Energy Source, enter the energy source
code for the energy sources expected to be used in the second largest quantity (Btus) when the
generator starts commercial operation. Select appropriate energy source codes from Table 1 in
these instructions. Do not include fuels expected to be used only for start-up or flame
stabilization.
14. For line 13, Other Energy Source Options, enter the codes for other energy sources that will
be used at the plant to power the generator. Enter up to four codes in order of their expected
predominance of use, where predominance is based on quantity of Btu(s) to be consumed.
Select appropriate energy source codes from Table 1 in these instructions.
15. For line 14, Number of Turbines, Buoys, or Inverters, if the energy source will be wind, enter
the number of turbines; if the energy source will be wave energy, enter the number of buoys; if
the energy source will be other hydrokinetics, enter the number of turbines; if the energy source
will be solar photovoltaic, enter the number of inverters.
16. For line 15, Will This Generator be Able to be Powered by 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. OWNERSHIP OF GENERATORS
OWNED JOINTLY OR BY OTHERS.
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, Will this Unit be Able to Co-Fire Fuels?, 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, Will This Generator be Able to be Powered by Co-Fired Fuel 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, Will This Generator be able to Run on 100% 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, Will This Unit be Able 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. OWNERSHIP OF
GENERATORS OWNED JOINTLY OR BY OTHERS.
11

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

22. For line 21, Will This Unit be Able to Switch Between Oil and Natural Gas?, indicate whether
or not the combustion system that will power the generator will have the necessary equipment
and the regulatory permits in place to switch between oil and natural gas. If “No,” skip to line 23.
If “Yes,” indicate whether the unit will be able to switch fuels while operating (i.e., without
shutting down the unit). Also enter the maximum output (summer net MW) that the unit is
expected to achieve, taking into account all applicable legal, regulatory, and technical limits,
when running on natural gas, the maximum output (summer net MW) that the unit is expected to
achieve, taking into account all applicable legal, regulatory, and technical limits, when running
on oil, and how long it is expected to take to switch the generator from using 100 percent natural
gas to 100 percent oil.
23. For line 22, Limits Are There Factors That Will Limit the Unit’s Ability to Switch From
Natural Gas to Oil?, 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. GENERATOR INFORMATION – GENERATORS.
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, GENERATOR INFORMATION – GENERATORS.
3. For line 2, enter the Generator ID, as previously reported in SCHEDULE 3, PART A,
GENERATOR INFORMATION – GENERATORS.
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 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
12

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

the interconnection equipment is located.
7. For line 6, Grid Voltage at the Point of Interconnection, specify the grid voltage, in kV, at the
point of interconnection between the generator and the grid.
8. For line 7, Owner of the Transmission or Distribution Facilities to Which Generator is
Interconnected, provide the name of the owner of the transmission or distribution facilities to
which the generator is interconnected. If the name of the owner of the facilities is unknown,
provide the name of the contracting party.
9. For line 8, Total Cost Incurred for the Direct, Physical Interconnection, specify the total cost
incurred, in thousands of dollars, to accomplish the physical interconnection.
10. For line 9, Equipment Included in the Direct Interconnection Cost, check each of the types
of equipment that are included in the cost amount reported on line 8. If there are significant
types of equipment that are not included in the list, please specify what additional equipment
was needed for the interconnection in SCHEDULE 7. COMMENTS.
11. For line 10, (a)Total Cost for Other Grid Enhancements/Reinforcements Needed to
Accommodate Power Deliveries From the Generator, specify the amount incurred, in
thousands of dollars, for any other grid enhancements or reinforcements that were needed to
accommodate power deliveries from the new generator. If these costs, or some portion of these
costs, will be repaid to your company at some time in the future by the owner of the grid, or by
the party with whom you contracted for the interconnection, please check “Yes” in line 10b;
otherwise, check “No” in 10b.
12. For line 11, Were Specific Transmission Use Rights Secured As A Result Of The
Interconnection Costs Incurred, check “Yes” or “No.”
SCHEDULE 6. BOILER INFORMATION
This schedule is required to be completed for all existing and planned (10 year plans) combustiblefueled steam generators, including heat recovery steam generators with duct firing and combustible
renewable-fueled generators, with a total generator nameplate capacity of at least 10 megawatts.
PART B, PART C, PART F, and PART I are only to be completed by those generators that meet the
conditions above but that have a total generator nameplate capacity of at least 100 megawatts.
Nuclear plants and solar plants using a steam cycle should complete PART F only.
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 10 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.
13

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

3. For lines 2, 4, 5, 6, 7, and 8, if a piece of equipment (e.g., a generator or a cooling system)
serves two or more boilers, repeat the identification information for that equipment under each
appropriate boiler.
4. For line 2, Associated Generator(s) ID, 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) ID, 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) ID, 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) ID, 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) ID, 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) ID, 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 as reported on SCHEDULE 6,
PART A, line 1.
2. For line 2a, Type of Boiler Standards Under Which the Boiler Is Operating, indicate the
standards as described in the U.S. Environmental Protection Agency regulation under 40 CFR.
Select from the following codes of the New Source Performance Standards (NSPS):
D
Da
Db
Dc
N

Standards of Performance for fossil-fuel fired steam boilers for which
construction began after August 17, 1971.
Standards of Performance for fossil-fuel fired steam boilers for which
construction began after September 18, 1978.
Standards of Performance for fossil-fuel fired steam boilers for which
construction began after June 19, 1984.
Standards of Performance for small industrial-commercial-institutional steam
generating units.
Not covered under New Source Performance Standards.

3. 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.
4. For line 3, Type of Statute or Regulation, select from the following the most stringent type of
statute or regulation code:
14

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)
FD
ST
LO
NA

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

Federal
State
Local
No Applicable Standard

5. For line 4, Emission Standard Specified, refer 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 the emission
rate in terms of pounds of sulfur dioxide per million Btu on line 4a and report the percent
scrubbed in terms of percent sulfur removal efficiency (by weight) on line 4b.
6. For line 5, Unit of Measurement Specified, column (a), Particulate Matter, select from the
following unit of measurement codes (PB* is the preferred measurement):
Code
OP
PB*
PC
PG
PH
UG
OT

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

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

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

8. For line 5, Unit of Measurement Specified, column (c), Nitrogen Oxides, select from the
following unit of measurement codes (NP* is the preferred measurement):
Code
NH
NL
NM
NO
NP*
OT

Unit of Measurement
Pounds of nitrogen oxides emitted per hour
Annual nitrogen oxides emission level less than a level in a previous
year
Parts per million of nitrogen oxides in stack gas
Ambient air quality concentration of nitrogen oxides (parts per
million)
Pounds of nitrogen oxides per million Btu in fuel
Other (specify in SCHEDULE 7. COMMENTS)

9. For line 6, Time Period Specified, select from the following codes to indicate the period over
which measurements were averaged:
Code
NV
FM

Time Period
Never to exceed
5 minutes
15

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)
SM
FT
OH
WO
TH
EH
DA
WA
MO
ND
YR
PS
DT
NS
OT

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

6 minutes
15 minutes
1 hour
2 hours
3 hours
8 hours
24 hours
1 week
30 days
90 days
Annual
Periodic stack testing
Defined by testing
Not specified
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, select from the following strategy
for compliance codes (separate multiple entries (up to three) with commas):
Code
BO
FR
LA
LN
MS
NC
OV
SE
OT

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

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
CF
CU
IF
NC
ND
RP
SS
SU
TU
UC
UE
US
UP

Strategy for Compliance (Sulfur Dioxide)
Fluidized Bed Combustor
Control unit under Phase I extension plan
Install flue gas desulfurization unit (other than Phase I extension plan)
No change in historic operation of unit anticipated
Not determined at this time
Repower Unit
Switch to lower sulfur fuel
Designate Phase II unit(s) as substitution unit(s)
Transfer unit under Phase I extension plan
Decrease utilization - designate Phase II unit(s) as compensating unit(s)
Decrease utilization - rely on energy conservation and/or improved
efficiency
Decrease utilization - designate sulfur-free generators to compensate
Decrease utilization - purchase power
16

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)
WA
OT

Code
AA
BF
CF
FR
FU
H2O
LA
LN
NH3
NC
ND
OV
RP
SC
SN
SR
STM
UE
NA
OT

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

Allocated allowances and purchase allowances
Other (specify in SCHEDULE 7. COMMENTS)

Strategy for Compliance (Nitrogen Oxides)
Advanced Overfire Air
Biased Firing (alternative burners)
Fluidized Bed Combustor
Flue Gas Recirculation
Fuel Reburning
Water Injection
Low Excess Air
Low NOx Burner
Ammonia Injection
No change in historic operation of unit anticipated
Not determined at this time
Overfire Air
Repower Unit
Slagging
Selective Noncatalytic Reduction
Selective Catalytic Reduction
Steam Injection
Decrease utilization - rely on energy conservation and/or improved
efficiency
Not Applicable
Other (specify in SCHEDULE 7. COMMENTS)

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 as reported on SCHEDULE 6, PART A, line 1. 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.
2. For line 2, enter boiler status. Select from the following codes.
Code
CN
CO
OP
OS
PL
RE
SB
SC
TS

Boiler Status
Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service less than 365 days)
Out of service (365 days or longer)
Planned (expected to go into commercial service within 10 years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve); i.e., not normally used, but available for
service
Cold Standby (Reserve); deactivated (usually requires 3 to 6 months to
reactivate)
Operating under test conditions (not in commercial service)

3. For line 3, 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 08-1959. If
the month is unknown, use the month of June.
4. For line 5, Boiler Manufacturer, select one code from the following boiler manufacturers’ codes:
17

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)
Code
AI
AL
AS
AT
BR
BW
DJ
CE
CN
DL
DS
EC
ER
ET
FW
GE
GT
HT
ID
IH
IHI
IS
KL
KP
KW
ME
NB
NM
NT
PB
PR
RS
ST
TM
TS
VO
WE
WG
WI
ZN
OT

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

Boiler Manufacturer
Aalborg Industries
Alstrom
American Shack
Applied Thermal Systems
BROS
Babcock and Wilcox
De Jong Coen bv
Combustion Engineering
Coen
Deltak
Doosan
Econotherm
Erie City Iron Works
Entek
Foster Wheeler
General Electric
Gotaverken
Hitachi
Indeck
In House Design
Ishikawajima-Harima Heavy Industries
Innovative Steam Technology
Keeler Dorr Oliver
Kvaerner Pulping
Kawasaki Heavy Industries
Mitchell Engineering
Nebraska Boiler
NEM
Nooter/Erickson
Peabody
Pyro Power
Riley Stoker
Sterling
Tampell
Toshiba
Vogt Machine Company/Vogt Power
Westinghouse
Wiegl Engineering
Wickes
Zurn
Other (specify in SCHEDULE 7. COMMENTS)

5. For line 6, Type of Firing Used with Primary Fuels, select from the following firing codes
(separate multiple entries (up to three) with commas):
Firing
Code
AF
CB
CF
CY
DB
FB
FF

Firing Type Description
Arch Firing
Cell Burner
Concentric Firing
Cyclone Firing
Duct Burner
Fluidized Bed Firing
Front Firing
18

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)
OF
RF
SF
SS
TF
VF
OT

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

Opposed Firing
Rear Firing
Side Firing
Spreader Stoker
Tangential Firing
Vertical Firing
Other (specify in SCHEDULE 7. COMMENTS)

6. 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.
7. 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.
8. 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.
9. For line 16, Total Air Flow, report at standard temperature and pressure, i.e., 68 degrees
Fahrenheit and one atmosphere pressure.
10. 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.
SCHEDULE 6, PART D. BOILER INFORMATION – NITROGEN OXIDE EMISSION CONTROLS
1. Complete a separate page for each existing or planned boiler.
2. For line 2, Nitrogen Oxide Control Status, select from the following status codes:
Code
CN
CO
OP
OS
OZ
PL
RE
SB
SC
TS

Control Status
Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service less than 365 days)
Out of service (365 days or longer)
Operated during the ozone season (May through September)
Planned (expected to go into commercial service within 10 years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve); i.e., not normally used, but available for service
Cold Standby (Reserve); deactivated (usually requires 3 to 6 months to
reactivate)
Operating under test conditions (not in commercial service)

3. For line 3, Low Nitrogen Oxide Control Process, select from the following low nitrogen oxide
control processes (separate multiple entries (up to three) with commas):
Code
AA
BF
CF
FR
FU
H2O
LA
LN

Control Process
Advanced Overfire Air
Biased Firing (alternative burners)
Fluidized Bed Combustor
Flue Gas Recirculation
Fuel Reburning
Water Injection
Low Excess Air
Low NOx Burner

19

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

NA
NH3
OV
SC
SN
SR
STM

Not Applicable
Ammonia Injection
Overfire Air
Slagging
Selective Noncatalytic Reduction
Selective Catalytic Reduction
Steam Injection

NC
RP
UE

No change in historic operation of unit anticipated
Repower Unit
Decrease utilization - rely on energy conservation and/or improved
efficiency

OT

Other (specify in SCHEDULE 7. COMMENTS)

4. For line 4, Manufacturer of Low Nitrogen Oxide Control Burners, select from the following
low nitrogen oxide control burner manufacturers:
Code
AB
ABB
AC
AL
AP
AT
AU
AZ
BC
BM
BMD
BW
CE
CM
CN
CSI
CT
DB
DD
DQ
DV
DX
EA
EG
EL
EP
ET
ETE
FB
FN
FT
FW
GE
GR
HL
HT
IC
ID

Manufacturer
Advanced Burner Technologies
ABB
Advanced Combustion Technology
Alstom
AirPol
Applied Thermal Systems
Applied Utility Systems (AUS)
Alzeta
Babcock Borsig Power
Bloom
Burns & McDonnell
Babcock and Wilcox
Combustion Engineering
Combustion Components Associates Inc
Coen
Combustion Solutions Inc
Callidus Technologies
Deutsche-Babcock
Damper Design Inc
Duquesne Light Company & Energy Systems Associates
Davis
Deltex
Eagle Air
Energy and Environmental Research Corp (EER)
Electric Power Technologies
EPRI
Entek
Entropy Technology and Environmental Construction Corp (ETEC)
Faber
Forney
Fuel Tech Inc
Foster Wheeler
General Electric
GE Energy and Environmental Research Corp (GEEER)
Holman
Hitachi
International Combustion Limited
Indeck
20

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)
IH
JZ
KL
MB
MI
MT
NA
NB
NC
NE
NL
PA
PB
PS
PL
PX
RD
RI
RJ
RR
RS
RV
SC
SW
TC
TEC
TM
TS
WG
ZC
OT

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

In House Design
John Zink Todd Combustion/Todd Combustion
Keeler Dorr Oliver
Mitsui-Babcock
Mitsubishi Industries
Mobotec
Not Applicable
Nebraska Boiler
Natcom, Inc
NEI
Noell, Inc
Procedair
Peabody
Peerless Manufacturing Company
Pillard
Phoenix Combustion
Rodenhuis and Verloop
Riley
RJM
Rolls Royce
Riley Stoker/Riley Power
RV Industries
Southern Company
Siemans-Westinghouse
Todd Combustion
Thermal Equipment Corporation
Tampella
Toshiba
Weigel Engineering
Zeeco
Other (specify in SCHEDULE 7. COMMENTS)

SCHEDULE 6, PART E. BOILER INFORMATION – MERCURY EMISSION CONTROLS
1. For line 2, if “Yes” is checked on line 1, select up to three mercury emissions controls codes
from the following list:
Code

Mercury Emission Control

ACI
BS
BP
BR
DS
EC
EH
EK
EW
FGD
LIJ
WS
OT

Activated Carbon Injection System
Baghouse, shake and deflate
Baghouse, pulse
Baghouse, reverse air
Dry Scrubber
Electrostatic precipitator, cold side, with flue gas conditioning
Electrostatic precipitator, hot side, with flue gas conditioning
Electrostatic precipitator, cold side, without flue gas conditioning
Electrostatic precipitator, hot side, without flue gas conditioning
Flue Gas Desulfurization
Lime Injection
Wet Scrubber
Other (specify in SCHEDULE 7. COMMENTS)

SCHEDULE 6, PART F. COOLING SYSTEM INFORMATION – DESIGN PARAMETERS
(DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW)
21

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

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) specify in 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. COOLING SYSTEM
INFORMATION - DESIGN PARAMETERS for the planned upgrade or retrofit.
2. For line 2, Cooling System Status, select from the following equipment status codes:
Code

CN
CO
OP
OS
PL
RE
SB
SC
TS

System Status

Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service less than 365 days)
Out of service (365 days or longer)
Planned (expected to go into commercial service within 10 years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve); i.e., not normally used, but available for
service)
Cold Standby (Reserve); deactivated (usually requires 3 to 6 months to
reactivate)
Operating under test conditions (not in commercial service)

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

Cooling System Description
Dry (air) cooling system
Hybrid: recirculating cooling pond(s) or canal(s) with dry cooling
Hybrid: recirculating with forced draft cooling tower(s) with dry cooling
Hybrid: recirculating with induced draft cooling tower(s) with dry cooling
Once through with cooling pond(s) or canal(s)
Once through, fresh water
Once through, saline water
Recirculating with cooling pond(s) or canal(s)
Recirculating with forced draft cooling tower(s)
Recirculating with induced draft cooling tower(s)
Recirculating with natural draft cooling tower(s)
Other (specify in SCHEDULE 7. COMMENTS)

4. For line 4b, in the case of a hybrid cooling system, indicate the percent of total cooling load that
is served by any dry cooling components.
5. For line 5a, Source of Cooling Water, provide name of river, lake, etc. For line 5b, select the
Type of Cooling Water Source from the following codes:
Code

Type of Water Source

SW

Surface Water (ex: river, canal, bay)

GW

Ground Water (ex: aquifer, well)

PD

Plant Discharge Water (ex: wastewater treatment plant discharge)

OT

Other (specify in SCHEDULE 7. COMMENTS)

22

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

6. For line 5c, Type of Cooling Water, select the Type of Cooling Water from the following
codes:
Code

Type of Water

BR

Brackish water

FR

Fresh water

TW

Treated wastewater effluent

SA

Saline water

OT

Other (specify in SCHEDULE 7. COMMENTS)

7. For line 6, Design Cooling Water Flow Rate at 100 percent Load at Intake, if more than one
source of cooling water is used by a cooling system, enter other sources in a footnote in
SCHEDULE 7. COMMENTS. 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 6.

8. 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.
9. For line 12, Type of Towers, select from the following cooling tower codes (separate multiple
entries (up to two) with commas):
Code
MD
MW
ND
NW
WD
OT

Type of Towers
Mechanical draft, dry process
Mechanical draft, wet process
Natural draft, dry process
Natural draft, wet process
Combination wet and dry processes
Other (specify in SCHEDULE 7. COMMENTS)

10. 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.
11. 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.
12. 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.
13. For line 23, Enter Datum for the above Latitude and Longitude, if Known; Otherwise Enter
“UNK”: The longitude and latitude measurement for a location depends in part on the coordinate
system (or “datum”) the measurement is keyed to. “Datum systems” used in the United States
include the North American Datum 1927 (NAD27), North American Datum 1983 (NAD83) and
World Geodetic Survey 1984 (WGS84).

23

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

SCHEDULE 6, PART G. FLUE GAS PARTICULATE COLLECTOR INFORMATION
1. For line 3, Flue Gas Particulate Collector Status, select from the following equipment status
codes:
Code
CN
CO
OP
OS
PL
RE
SB
SC
TS

Status
Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service within 365 days)
Out of service (365 days or longer)
Planned (expected to go into commercial service within 10 years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve, i.e., not normally used, but available for
service)
Cold Standby (Reserve); deactivated. Usually requires 3 to 6 months to
reactivate
Operating under test conditions (not in commercial service).

2. For line 4, Type of Flue Gas Particulate Collector, select from the following flue gas
particulate collector codes (for combination units, separate multiple entries (up to three) with
commas):
Code
BS
BP
BR
EC
EH
EK
EW
MC
SC
WS
OT

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

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) specify in SCHEDULE
7. COMMENTS, how long the existing equipment will be out of service; and 3) using the same
FGD identification, complete a separate SCHEDULE 6, PART H. FLUE GAS
DESULFURIZATION UNIT - DESIGN PARAMETERS for the planned upgrade or retrofit.

24

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

2. For line 2, Flue Gas Desulfurization Unit Status, select from the following equipment status
codes:
Code
CN
CO
OP
OS
PL
RE
SB

Status
Cancelled (previously reported as planned)
New unit under construction
Operating (in commercial service or out of service less than 365 days)
Out of service (365 days or longer)
Planned (expected to go into commercial service within 10 years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve, i.e., not normally used by available for service)

SC

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

TS

Operating under test conditions (not in commercial service)

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

Type of Unit
Jet Bubbling Reactor
Circulating Dry Scrubber
Dry Powder Injection type
Mechanically aided type
Packed type
Spray dryer type
Spray type
Tray type
Venture type
Other (specify in SCHEDULE 7. COMMENTS)

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

Type of Sorbent
Alkaline fly ash
Calcium carbide slurry
CE filtrate
Caustic Sodium hydroxide
Dibasic acid
Dolomitic limestone
Lime and alkaline fly ash
Limestone and alkaline fly ash
Lime
Limestone
Magnesium oxide
Soda ash
Sodium bicarbonate
Sodium carbonate
Sodium formate
Soda liquid
Sodium sulfite
Treated wastewater
Water
Other (specify in SCHEDULE 7. COMMENTS)

25

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

For line 7, Flue Gas Desulfurization Unit Manufacturer, select one code from the following flue
gas desulfurization unit manufacturer codes:
Code
AA
ABB
AL
AM
AP
API
AX
BE
BI
BL
BMD
BO
BPC
BPE
BT
BW
CA
CC
CE
CO
DA
DC
DM
EE
EEC
EI
FL
FM
FW
GE
GF
HA
IH
JO
KC
KE
KR
LLB
MC
MG
MI
MT
MX
NPA
NSP
PA
PB
PR
PU
RC

Manufacturer
Advanced Air Technologies
ABB Environmental Systems
Alstom
American Air Filter
Airpol
Air Pollution Industries
Amerex Industries
Bact Engineering
Bleco Industries
Bechtel Corporation
Burns and McDonnell
Bionomics
Belco Pollution Control
Babcock Power Environmental Inc (BPEI)
Belco Technologies
Babcock and Wilcox
Chiyoda
Chemico
Combustion Engineering
Combustion Equipment
Delta Conveying Systems
Ducon
Davey McKee
Environmental Engineering
Environmental Elements Corporation
Entoleter Inc
Flakt, Inc
FMC
Foster Wheeler
General Electric
Grafwolff
Hamon
In House Design
Joy Manufacturing
Korea Cottrell
M.W. Kellogg
Krebs Equipment
Lurgi Lentjes Bischoff
Macrotek
McGill Air Clean
Mitsubishi Industry
Mobotec
Marselex
Neptune Airpol
NSP
Procedair
Peabody
Pyro Power
Pure Air
Research Cottrell
26

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)
RS
SHU
SK
TC
TH
TK
TP
UE
UM
UO
WAP
ZN
OT

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

Riley Stoker
Saarberg-Holter Umwelttechnick GmbH
Schenck Weigh Feeders
Turbosonic
Thyssen/CEA
Turbotak
Tempala Power
Utility Engineering
United McGill
Universal Oil Products
Wheelabrator Air Pollution Control
Zurn
Other (specify in SCHEDULE 7. COMMENTS)

6. For line 15, Removal Efficiency for Sulfur Dioxide, report the removal efficiency as the
percent by weight of gases removed from the flue gas.
7. 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) specify in 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. PLANT CONFIGURATION.
3. For line 3, Stack (or Flue) Actual or Projected In-Service Date of Commercial Operation,
the month-year should be entered as follows: e.g., August 1959 as 08-1959.
4. For line 4, Status of Stack, select one from the following equipment status codes:
Status
CN
CO
OP
OS
PL
RE
SB
SC
TS

Code
Cancelled (previously reported as “planned”)
New unit under construction
Operating (in commercial service or out of service within 365 days)
Out of service (365 days or longer)
Planned (on order or expected to go into commercial service within 10
years)
Retired (no longer in service and not expected to be returned to service)
Standby (or inactive reserve, i.e., not normally used, but available for
service)
Cold Standby (Reserve); deactivated. Usually requires 3 to 6 months to
reactivate
Operating under test conditions (not in commercial service).

5. For lines 7 and 8, the rate should be approximately equal to the cross-sectional area multiplied
by the velocity, multiplied by 60.
27

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

6. For lines 13 and 14, seasonal average flue gas exit temperatures should be reported in degrees
Fahrenheit, based on the arithmetic mean of measurements during operating hours. Summer
season includes June, July, and August. Winter season includes January, February, and
December.
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 do not know the datum system used, enter UNK.
SCHEDULE 7. COMMENTS
This schedule provides additional space for comments. Please identify schedule and line number
and identifying information (e.g., plant code, boiler id, generator id) for each comment and use
additional pages, if necessary.

Table 1. Energy Source Codes and Heat Content
28

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Fuel Type

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS
Higher Heating
Value Range
MMBtu
MMBtu
Lower
Upper
Fossil Fuels
22
28
20
29
14.5
10
15
20

Energy
Source
Code

Unit
Label

ANT
BIT
LIG
SUB

tons
tons
tons
tons

WC

tons

6.5

16

RC

tons

20

29

DFO

barrels

5.5

6.2

JF
KER
PC

barrels
barrels
tons

5
5.6
24

6
6.1
30

RFO

barrels

5.8

6.8

WO

barrels

3.0

5.8

BFG
NG

Mcf
Mcf

0.07
0.8

0.12
1.1

OG

Mcf

0.32

3.3

PG
SG
SGC

Mcf
Mcf
Mcf

AB
MSW

tons
tons

OBS

tons

8

25

WDS

tons

7

18

Coal

Petroleum
Products

Natural
Gas and
Other
Gases

Solid
Renewable
Fuels

2.5
2.75
0.2
1.1
0.2
0.3
Renewable Fuels
7
18
9
12

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Energy Source Description

Anthracite Coal
Bituminous Coal
Lignite Coal
Subbituminous Coal
Waste/Other Coal (including
anthracite culm, bituminous gob,
fine coal, lignite waste, waste
coal)
Refined Coal
Distillate Fuel Oil (including
diesel, No. 1, No. 2, and No. 4
fuel oils.
Jet Fuel
Kerosene
Petroleum Coke
Residual Fuel Oil (including No.
5, and No. 6 fuel oils, and
bunker C fuel oil)
Waste/Other Oil (including crude
oil, liquid butane, liquid propane,
oil waste, re-refined motor oil,
sludge oil, tar oil, or other
petroleum-based liquid wastes)
Blast Furnace Gas
Natural Gas
Other Gas (specify in
SCHEDULE 7. COMMENTS)
Gaseous Propane
Synthetic Gas
Coal-Derived Synthetic Gas

Agricultural By-Products
Municipal Solid Waste
Other Biomass Solids (specify in
SCHEDULE 7. COMMENTS)
Wood/Wood Waste Solids
(including paper pellets, railroad
ties, utility poles, wood chips,
bark, and wood waste solids)

Table 1. Energy Source Codes and Heat Content (continued)
Fuel Type

Energy
Source

Unit
Label

Higher Heating
Value Range
29

Energy Source Description

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Code

Liquid
Renewable
(Biomass)
Fuels

Gaseous
Renewable
(Biomass)
Fuels

All Other
Renewable
Fuels

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

MMBtu
MMBtu
Lower
Upper
Renewable Fuels

OBL

barrels

3.5

4

SLW
BLQ

tons
tons

10
10

16
14

WDL

barrels

8

14

LFG

Mcf

0.3

0.6

OBG

Mcf

0.36

1.6

SUN
WND
GEO

N/A
N/A
N/A

0
0
0

0
0
0

WV

N/A

0

0

CUR

N/A

0

0

TID

N/A

0

0

WAT

N/A

0

0

Other Biomass Liquids (specify
in SCHEDULE 7. COMMENTS)
Sludge Waste
Black Liquor
Wood Waste Liquids excluding
Black Liquor (including red
liquor, sludge wood, spent
sulfite liquor, and other woodbased liquids)
Landfill gas
Other Biomass Gas (including
digestor gas, methane, and
other biomass gases; specify in
SCHEDULE 7. COMMENTS)
Solar
Wind
Geothermal
Water used in Wave Buoy
Hydrokinetic Technology
Water used in Current
Hydrokinetic Technology
Water used in Tidal Hydrokinetic
Technology
Water at a Conventional
Hydroelectric Turbine

All Other Fuels

All Other
Energy
Sources

WAT

MWh

0

0

NUC

N/A

0

0

PUR

N/A

0

0

WH

N/A

0

0

TDF
OTH

Tons
N/A

16
0

32
0

Electric power (MWh) consumed
by Pumped Storage
Hydroelectric plants for
pumping energy, Compressed
Air Energy Storage for air
compression, and energy stored
into Battery Energy Storage
Nuclear including Uranium,
Plutonium, Thorium
Purchased Steam
Waste heat not directly
attributed to a fuel source (WH
should only be reported where
the fuel source for the waste
heat is undetermined, and for
combined cycle steam turbines
that do not have supplemental
firing.)
Tire-derived Fuels
Specify in SCHEDULE 7.
COMMENTS

Table 2. Commonly Used North American Industry Classification System (NAICS)
Codes
30

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)
Code
111
112
113
114
115
211
2121
2122
2123
23
311
3122
314
315
316
321
322
322122
32213
323
324
32411
325
32512
325188
325211
325311
326
327
32731
331
331111
331312
332
333
3345
335
336
337
339

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

Description
AGRICULTURE, FORESTRY, AND FISHING
Agriculture production - crops
Agriculture production, livestock and animal specialties
Forestry
Fishing, hunting, and trapping
Agricultural services
MINING
Oil and gas extraction
Coal mining
Metal mining
Mining and quarrying of nonmetallic minerals except fuels
CONSTRUCTION
MANUFACTURING
Food and kindred products
Tobacco products
Textile and mill products
Apparel and other finished products made from fabrics and similar materials
Leather and leather products
Lumber and wood products, except furniture
Paper and allied products (other than 322122 or 32213)
Paper mills, except building paper
Paperboard mills
Printing and publishing
Petroleum refining and related industries (other than 32411)
Petroleum refining
Chemicals and allied products (other than 325188, 325211, 32512, or 325311)
Industrial organic chemicals
Industrial inorganic chemicals
Plastic materials and resins
Nitrogenous fertilizers
Rubber and miscellaneous plastic products
Stone, clay, glass, and concrete products (other than 32731)
Cement, hydraulic
Primary metal industries (other than 331111 or 331312)
Blast furnaces and steel mills
Primary aluminum
Fabricated metal products, except machinery and transportation equipment
Industrial and commercial equipment and components except computer
equipment
Measuring, analyzing, and controlling instruments, photographic, medical, and
optical goods, watches and clocks
Electronic and other electrical equipment and components except computer
equipment
Transportation equipment
Furniture and fixtures
Miscellaneous manufacturing industries

31

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

482
485
484
22
2212
2213
22131
22132
481
482
483
484
485
486
487
513
562212
421 to 422
441 to 454
521 to 533
512
514
514199
541
561
611
622
624
712
713
721
811
8111
812
813
814
92

ANNUAL ELECTRIC GENERATOR
REPORT INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

TRANSPORTATION AND PUBLIC UTILITIES
Railroad transportation
Local and suburban transit and interurban highway passenger transport
Motor freight transportation and warehousing
Electric, gas, and sanitary services
Natural gas transmission
Water supply
Irrigation systems
Sewerage systems
Transportation by air
Railroad Transportation
Water transportation
Motor freight transportation and warehousing
Local and suburban transit and interurban highway passenger transport
Pipelines, except natural gas
Transportation services
Communications
Refuse systems
WHOLESALE TRADE
RETAIL TRADE
FINANCE, INSURANCE, AND REAL ESTATE SERVICES
Motion pictures
Business services
Miscellaneous services
Legal services
Engineering, accounting, research, management, and related services
Education services
Health services
Social services
Museums, art galleries, and botanical and zoological gardens
Amusement and recreation services
Hotels
Miscellaneous repair services
Automotive repair, services, and parking
Personal services
Membership organizations
Private Households
PUBLIC ADMINISTRATION

32

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC
GENERATOR REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013

Burden: 9.4 hours
GLOSSARY

SANCTIONS

REPORTING
BURDEN

The glossary for this form is available online at the following URL:
http://www.eia.gov/glossary/index.html
The timely submission of Form EIA-860 by those required to report is mandatory under Section
13(b) of the Federal Energy Administration Act of 1974 (FEAA) (Public Law 93-275), as amended.
Failure to respond may result in a penalty of not more than $2,750 per day for each civil violation, or
a fine of not more than $5,000 per day for each criminal violation. The government may bring a civil
action to prohibit reporting violations, which may result in a temporary restraining order or a
preliminary or permanent injunction without bond. In such civil action, the court may also issue
mandatory injunctions commanding any person to comply with these reporting requirements. Title
18 U.S.C. 1001 makes it a criminal offense for any person knowingly and willingly to make to
any Agency or Department of the United States any false, fictitious, or fraudulent statements
as to any matter within its jurisdiction.
Public reporting burden for this collection of information is estimated to average 6.75 hours per
response for respondents without environmental information and 12.5 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. The weighted average burden for the Form EIA-860 is 9.4 hours per
response. Send comments regarding this burden estimate or any other aspect of this collection of
information, including suggestions for reducing this burden, to the U.S. 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
Information reported on Form EIA-860 will be treated as non-sensitive and may be publicly released
REGARDING
in identifiable form except as noted below.
CONFIDENTIALITY
The information reported for the data element “Tested Heat Rate” contained on SCHEDULE 3,
OF INFORMATION
PART B. GENERATOR INFORMATION – EXISTING GENERATORS 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. GENERATOR INFORMATION – EXISTING GENERATORS, Tested Heat
Rate, on Form EIA-860 to ensure that the risk of disclosure of identifiable information is very small.

33

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours

ANNUAL ELECTRIC
GENERATOR REPORT

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 disclosure information, see the provisions stated on the last page of 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:_________________________________________

Phone (include extension):__________________________

Fax:____________________________________________

Email:_____________________________________________________________________________________________
Supervisor of Contact Person for Survey
First Name:______________________________________

Last Name:_______________________________________

Title:____________________________________________

Address:_________________________________________

Phone (include extension):__________________________

Fax:____________________________________________

Email:_____________________________________________________________________________________________
Report For
Operator Name:_____________________________________________________________________________________
Operator ID:________________________________________________________________________________________
Reporting as of December 31 of 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 staff:
Patricia Hutchins
Telephone Number: (202) 586-1029
Fax Number: (202) 287-1960
Email: [email protected]

Vlad Dorjets
Telephone Number: (202) 586-3141
Fax Number: (202) 287-1960
Email: [email protected]

34

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________
U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC
GENERATOR REPORT

Operator ID:__________

Reporting as of December 31 of Year:____________

SCHEDULE 2. POWER PLANT DATA
(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 10 YEARS)
LINE

PLANT 1
EIA Plant
Code

1

Plant Name

2

Street
Address

3

County Name

4

State

5

Zip Code

6

Latitude (Degrees, Minutes,
Seconds)

7

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

8a

NERC Region

8b

Does this Plant Belong to a RTO or ISO?

City Name

[
[
[
[

Longitude (Degrees, Minutes,
Seconds)

[ ] Yes

] California ISO
] Southwest Power Pool
] PJM Interconnection
] ISO New England

[
[
[
[

[ ] No

] Electric Reliability Council of Texas
] Midwest ISO
] New York ISO
] Other

8c

Name of RTO or ISO

9

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

10

Steam Plant Status

11

Steam Plant Type

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

16a

Owner of Transmission and/or Distribution Facilities

16b

Grid Voltage (in kilovolts)

[ ] existing
[
[
[

[ ] planned

[

] retired

[ ] NA

] Combustible 100 MW or more generator nameplate capacity
] Combustible 10 MW or Greater to Under 100 MW generator nameplate capacity
] NA

35

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________
U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC
GENERATOR REPORT

Operator ID:__________

Reporting as of December 31 of Year:____________

SCHEDULE 2. POWER PLANT DATA
(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 10 YEARS)
LINE

PLANT 2
EIA Plant
Code

1

Plant Name

2

Street
Address

3

County Name

4

State

5

Zip Code

6

Latitude (Degrees, Minutes,
Seconds)

7

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

8a

NERC Region

8b

Does this Plant Belong to a RTO or ISO?

City Name

[
[
[
[

Longitude (Degrees, Minutes,
Seconds)

[ ] Yes

] California ISO
] Southwest Power Pool
] PJM Interconnection
] ISO New England

[
[
[
[

[ ] No

] Electric Reliability Council of Texas
] Midwest ISO
] New York ISO
] Other

8c

Name of RTO or ISO

9

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

10

Steam Plant Status

11

Steam Plant Type

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

16a

Owner of Transmission and/or Distribution Facilities

16b

Grid Voltage (in kilovolts)

[ ] existing
[
[
[

[ ] planned

[

] retired

[ ] NA

] Combustible 100 MW or more generator nameplate capacity
] Combustible 10 MW or Greater to Under 100 MW generator nameplate capacity
] NA

36

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________
U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC
GENERATOR REPORT

Operator ID:__________

Reporting as of December 31 of Year:____________

SCHEDULE 2. POWER PLANT DATA
(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 10 YEARS)
LINE

PLANT 3
EIA Plant
Code

1

Plant Name

2

Street
Address

3

County Name

4

State

5

Zip Code

6

Latitude (Degrees, Minutes,
Seconds)

7

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

8a

NERC Region

8b

Does this Plant Belong to a RTO or ISO?

City Name

[
[
[
[

Longitude (Degrees, Minutes,
Seconds)

[ ] Yes

] California ISO
] Southwest Power Pool
] PJM Interconnection
] ISO New England

[
[
[
[

[ ] No

] Electric Reliability Council of Texas
] Midwest ISO
] New York ISO
] Other

8c

Name of RTO or ISO

9

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

10

Steam Plant Status

11

Steam Plant Type

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

16a

Owner of Transmission and/or Distribution Facilities

16b

Grid Voltage (in kilovolts)

[ ] existing
[
[
[

[ ] planned

[

] retired

[ ] NA

] Combustible 100 MW or more generator nameplate capacity
] Combustible 10 MW or Greater to Under 100 MW generator nameplate capacity
] NA

37

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________
U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC
GENERATOR REPORT

Operator ID:__________

Reporting as of December 31 of Year:____________

SCHEDULE 2. POWER PLANT DATA
(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 10 YEARS)
LINE

PLANT 4
EIA Plant
Code

1

Plant Name

2

Street
Address

3

County Name

4

State

5

Zip Code

6

Latitude (Degrees, Minutes,
Seconds)

7

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

8a

NERC Region

8b

Does this Plant Belong to a RTO or ISO?

City Name

[
[
[
[

Longitude (Degrees, Minutes,
Seconds)

[ ] Yes

] California ISO
] Southwest Power Pool
] PJM Interconnection
] ISO New England

[
[
[
[

] Electric Reliability Council of Texas
] Midwest ISO
] New York ISO
] Other

8c

Name of RTO or ISO

9

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

10

Steam Plant Status

[ ] existing
[
[
[

[ ] planned

[ ] No

[

] retired

[ ] NA

] Combustible 100 MW or more generator nameplate capacity
] Combustible 10 MW or Greater to Under 100 MW generator nameplate capacity
] NA

11

Steam Plant Type

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

16a

Owner of Transmission and/or Distribution Facilities

16b

Grid Voltage (in kilovolts)
38

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________
U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC
GENERATOR REPORT

Operator ID:__________

Reporting as of December 31 of Year:____________

SCHEDULE 2. POWER PLANT DATA
(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 10 YEARS)
LINE

PLANT 5
EIA Plant
Code

1

Plant Name

2

Street
Address

3

County Name

4

State

5

Zip Code

6

Latitude (Degrees, Minutes,
Seconds)

7

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

8a

NERC Region

8b

Does this Plant Belong to a RTO or ISO?

City Name

[
[
[
[

Longitude (Degrees, Minutes,
Seconds)

[ ] Yes

] California ISO
] Southwest Power Pool
] PJM Interconnection
] ISO New England

[
[
[
[

] Electric Reliability Council of Texas
] Midwest ISO
] New York ISO
] Other

8c

Name of RTO or ISO

9

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

10

Steam Plant Status

[ ] existing
[
[
[

[ ] planned

[ ] No

[

] retired

[ ] NA

] Combustible 100 MW or more generator nameplate capacity
] Combustible 10 MW or Greater to Under 100 MW generator nameplate capacity
] NA

11

Steam Plant Type

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

16a

Owner of Transmission and/or Distribution Facilities

16b

Grid Voltage (in kilovolts)
39

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________
U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC
GENERATOR REPORT

Operator ID:__________

Reporting as of December 31 of Year:____________

SCHEDULE 2. POWER PLANT DATA
(EXISTING POWER PLANTS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 10 YEARS)
LINE

PLANT 6
EIA Plant
Code

1

Plant Name

2

Street
Address

3

County Name

4

State

5

Zip Code

6

Latitude (Degrees, Minutes,
Seconds)

7

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

8a

NERC Region

8b

Does this Plant Belong to a RTO or ISO?

City Name

[
[
[
[

Longitude (Degrees, Minutes,
Seconds)

[ ] Yes

] California ISO
] Southwest Power Pool
] PJM Interconnection
] ISO New England

[
[
[
[

] Electric Reliability Council of Texas
] Midwest ISO
] New York ISO
] Other

8c

Name of RTO or ISO

9

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

10

Steam Plant Status

[ ] existing
[
[
[

[ ] planned

[ ] No

[

] retired

[ ] NA

] Combustible 100 MW or more generator nameplate capacity
] Combustible 10 MW or Greater to Under 100 MW generator nameplate capacity
] NA

11

Steam Plant Type

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

16a

Owner of Transmission and/or Distribution Facilities

16b

Grid Voltage (in kilovolts)
40

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________
ANNUAL ELECTRIC
GENERATOR REPORT

Operator ID:__________

Reporting as of December 31 of Year:____________

SCHEDULE 3. GENERATOR INFORMATION
(EXISTING GENERATORS AND THOSE PLANNED FOR INITIAL COMMERCIAL OPERATION WITHIN 10 YEARS)
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)
Operator’s Generator
3
Identification
1 ____
5 ____
1 ____
5 ____
1 ____
5 ____
Associated Boiler
2 ____
6 ____
2 ____
6 ____
2 ____
6 ____
4
3 ____
7 ____
3 ____
7 ____
3 ____
7 ____
Identifications
4 ____
8 ____
4 ____
8 ____
4 ____
8 ____
5

Prime Mover

6

Unit Code (Multi-Generator
Code)

7

Ownership

8

Is This Generator an Electric
Utility Generator?

9

Date of Sale If Sold (MM-YYYY)

10

11

Can This Generator Deliver
Power to the Transmission Grid?
For Combined-Cycle Steam
Turbines (i.e. Prime Mover = CA,
CS or CC) Does this Generator
Have Duct-Burners?

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[ ] Yes

[ ] No

41

[ ] Yes

[ ] No

[ ] Yes

[ ] No

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Operator Name:____________________________________

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator ID:___________

Plant Name:_______________________________________

Plant Code:___________

ANNUAL ELECTRIC GENERATOR
REPORT

Reporting as of December 31 of Year:___________________
SCHEDULE 3, PART B. GENERATOR INFORMATION – EXISTING GENERATORS
(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT)
Generator (a)
Generator (b)
Generator (c)
Generator Nameplate
1
Capacity (Megawatts)
2

3a
3b
4
5
6
7
8a

8b

9a

9b

Summer:

Summer:

Summer:

Winter:

Winter:

Winter:

Net Capacity (Megawatts)
Maximum Expected
Reactive Power Output
(MVAR)
Maximum Reactive Power
Absorption (MVAR)
Status Code
If Status Code is Standby,
Can the Generator be
Synchronized to the Grid?
Initial Date of Operation
(MM-YYYY)
Retirement Date (MM-YYYY)
Is This Generator
Associated with a
Combined Heat and Power
System?
If Yes, Is This Generator
Part of a Topping or
Bottoming Cycle?
ENERGY SOURCES
Predominant Energy Source
If coal-fired or petroleum
coke fired, check all
combustion technologies
that apply to the associated
boiler(s) and steam
conditions

10

Start-Up and Flame
Stabilization Energy
Sources

11

Second Most Predominant
Energy Source

12

Other Energy Sources

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[ ] Topping
[ ] Bottoming

[
[
[
[
[
[

]
]
]
]
]
]

[ ] Topping
[ ] Bottoming

Pulverized coal
Fluidized Bed
Sub-critical
Super-critical
Ultra super-critical
Carbon-capture

[
[
[
[
[
[

]
]
]
]
]
]

[ ] Topping
[ ] Bottoming

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

a

b

c

d

a

b

c

d

a

b

c

d

a

b

c

d

a

b

c

d

a

b

c

d

42

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Operator Name:____________________________________

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator ID:___________

Plant Name:_______________________________________

Plant Code:___________

ANNUAL ELECTRIC GENERATOR
REPORT

Reporting as of December 31 of Year:___________________
SCHEDULE 3, PART B. GENERATOR INFORMATION – EXISTING GENERATORS
(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT)
Generator (a)
Generator (b)
Generator (c)
Is This Generator Part of a
Solid Fuel Gasification
System?
Number of Turbines, Buoys,
14
or Inverters
15a Tested Heat Rate
13

15b

16

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

Fuel Used For Heat Rate
Test
Annual Average Operating
Efficiency for Solar
Photovoltaic, Wind and
Hydroelectric Generators
PROPOSED CHANGES TO EXISTING GENERATORS (WITHIN THE NEXT 10 YEARS)

Are There Any Planned
Modifications to This
17a
Generator, Including
Retirement?
Planned Uprates:

[ ] Yes

[ ] No

[ ] Yes

[ ] No

[ ] Yes

[ ] No

[ ] Yes

[ ] No

[ ] Yes

[ ] No

[ ] Yes

[ ] No

1. Incremental Net Summer
capacity (MW)
17b 2. Incremental Net Winter
capacity (MW)
3. Planned Effective Date
(MM-YYYY)
Planned Uprates:
1. Incremental Net Summer
capacity (MW)
17c 2. Incremental Net Winter
capacity (MW)
3. Planned Effective Date
(MM-YYYY)
Planned Repowering:
1. New Prime Mover
17d

2. New Energy Source
3. New Nameplate Capacity

4. Planned Effective Date
(MM-YYYY)
Other Modifications?
(explain in Notes)
17e
Planned Effective Date (MMYYYY)

43

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Operator Name:____________________________________

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator ID:___________

Plant Name:_______________________________________

Plant Code:___________

ANNUAL ELECTRIC GENERATOR
REPORT

Reporting as of December 31 of Year:___________________
SCHEDULE 3, PART B. GENERATOR INFORMATION – EXISTING GENERATORS
(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT)
Generator (a)
Generator (b)
Generator (c)
Planned Generator
17f
Retirement Date (MM-YYYY)
FUEL SWITCHING AND CO-FIRING CAPABILITY

18

Can This Generator be
Powered by Multiple Fuels?

19

Can This Unit Co-Fire
Fuels?

20

Fuel Options for Co-Firing

21

Can This Generator be
Powered by Co-Fired Fuel
Oil and Natural Gas?

Can This Generator be Run
on 100% Oil?

22

If No, What is the Maximum
Oil Heat Input When CoFiring with Natural Gas?
What is the Maximum
Output Achievable (Net
Summer Capacity in MW)
When Making the Maximum
Use of Oil and Co-Firing
Natural Gas?

[ ] Yes

Can This Unit Fuel Switch?

24

Can This Unit Switch
Between Oil and Natural
Gas?
If Yes, Can the Unit Switch
Fuels While Operating?

[ ] Yes

If No, Skip to SCHEDULE
3, PART C.
[ ] Yes

[ ] No

[ ] No

[ ] Yes

If No, Skip to SCHEDULE
3, PART C.
[ ] Yes

[ ] No

[ ] No

If No, Skip to SCHEDULE
3, PART C.
[ ] Yes

[ ] No

If No, Skip to Line 23.

If No, Skip to Line 23.

If No, Skip to Line 23.

a

b

c

a

b

c

a

b

c

d

e

f

d

e

f

d

e

f

[ ] Yes

[ ] No

If Yes, Skip to Line 23.
[ ] Yes

[ ] No

[ ] Yes

[ ] No

If Yes, Skip to Line 23.
[ ] Yes

[ ] No

[ ] Yes

[ ] No

If Yes, Skip to Line 23.
[ ] Yes

[ ] No

If Yes, Skip to Line 23.

If Yes, Skip to Line 23.

If Yes, Skip to Line 23.

________ %

________ %

________ %

________ MW

________ MW

________ MW

[ ] Yes
23

[ ] No

[ ] No

If No, Skip to Schedule 3,
Part C.
[ ] Yes

[ ] No

If No, Skip to Line 26.
[ ] Yes

[ ] No
44

[ ] Yes

[ ] No

If No, Skip to Schedule 3,
Part C.
[ ] Yes

[ ] No

If No, Skip to Line 26.
[ ] Yes

[ ] No

[ ] Yes

[ ] No

If No, Skip to Schedule 3,
Part C.
[ ] Yes

[ ] No

If No, Skip to Line 26.
[ ] Yes

[ ] No

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Operator Name:____________________________________

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator ID:___________

Plant Name:_______________________________________

Plant Code:___________

ANNUAL ELECTRIC GENERATOR
REPORT

Reporting as of December 31 of Year:___________________
SCHEDULE 3, PART B. GENERATOR INFORMATION – EXISTING GENERATORS
(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT)
Generator (a)
Generator (b)
Generator (c)
What is the Maximum Net
Summer Output Achievable
________ MW
________ MW
________ MW
(MW) When Running on
Natural Gas?
What is the Maximum Net
Summer Output Achievable
________ MW
________ MW
________ MW
(MW) When Running on
Fuel Oil?

25

26

[ ] 0 to 6 hours
How Much Time is Required [ ] over 6 to 24 hours
to Switch This Unit From
[ ] over 24 to 72 hours
Using 100% Natural Gas to
[ ] over 72 hours.
Using 100% Oil?
[ ] Unknown or uncertain
Are There Factors That
[ ] Yes [ ] No
Limit the Unit’s Ability to
Switch From Natural Gas to
If No, Skip to Line 26.
Oil?
[ ] Limited on site fuel
storage.
[ ] Air Permit limits
If Yes, Check All Factors
[ ] Other (specify in
That Apply
SCHEDULE 7.
COMMENTS)

Fuel Switching Options

[
[
[
[
[

] 0 to 6 hours
] over 6 to 24 hours
] over 24 to 72 hours
] over 72 hours.
] Unknown or uncertain
[ ] Yes

[ ] No

[
[
[
[
[

] 0 to 6 hours
] over 6 to 24 hours
] over 24 to 72 hours
] over 72 hours.
] Unknown or uncertain
[ ] Yes

If No, Skip to Line 26.
[ ] Limited on site fuel
storage.
[ ] Air Permit limits
[ ] Other (specify in
SCHEDULE 7.
COMMENTS)

[ ] No

If No, Skip to Line 26.
[ ] Limited on site fuel
storage.
[ ] Air Permit limits
[ ] Other (specify in
SCHEDULE 7.
COMMENTS)

a

b

c

a

b

c

a

b

C

d

e

f

d

e

f

d

e

f

45

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Operator Name:____________________________________

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator ID:___________

Plant Name:_______________________________________

Plant Code:___________

ANNUAL ELECTRIC GENERATOR
REPORT

Reporting as of December 31 of Year:___________________
SCHEDULE 3, PART C. GENERATOR INFORMATION – PROPOSED GENERATORS
(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT)
Generator (a)
Generator (b)
Generator (c)
Generator Nameplate
1
Capacity (Megawatts)
2

3a
3b
4
5
6

7

8

9

10

11

Summer:

Summer:

Summer:

Winter:

Winter:

Winter:

Net Capacity (Megawatts)
Maximum Expected
Reactive Power Output
(MVAR)
Maximum Reactive Power
Absorption (MVAR)
Status Code
Planned Original Effective
Date (MM-YYYY)
Planned Current Effective
Date (MM-YYYY)
Will This Generator be
Associated with a
Combined Heat and Power
System?
Will This Generator be Part
of a Solid Fuel Gasification
System?
Is This Generator Part of a
Site That Was Previously
Reported as Indefinitely
Postponed or Cancelled?
PLANNED ENERGY SOURCES
Expected Predominant
Energy Source
If coal-fired or petroleum
[
coke fired, check all
[
combustion technologies
[
that apply to the associated [
boiler(s) and steam
[
conditions
[

12

Expected Second Most
Predominant Energy Source

13

Other Energy Sources

14

Number of Turbines, Buoys,
or Inverters

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

[

] Yes

[

] No

]
]
]
]
]
]

a

Pulverized coal
Fluidized Bed
Sub-critical
Super-critical
Ultra super-critical
Carbon-capture

b

c

d

46

[
[
[
[
[
[

]
]
]
]
]
]

a

Pulverized coal
Fluidized Bed
Sub-critical
Super-critical
Ultra super-critical
Carbon-capture

b

c

d

[
[
[
[
[
[

]
]
]
]
]
]

a

Pulverized coal
Fluidized Bed
Sub-critical
Super-critical
Ultra super-critical
Carbon-capture

b

c

d

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Operator Name:____________________________________

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator ID:___________

Plant Name:_______________________________________

Plant Code:___________

ANNUAL ELECTRIC GENERATOR
REPORT

Reporting as of December 31 of Year:___________________
SCHEDULE 3, PART C. GENERATOR INFORMATION – PROPOSED GENERATORS
(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT)
Generator (a)
Generator (b)
Generator (c)
FUEL SWITCHING AND CO-FIRING CAPABILITY

15

[ ] Yes [ ] No
[ ] Yes [ ] No
[ ] Yes [ ] No
Will This Generator be Able
[ ] Undetermined
[ ] Undetermined
[ ] Undetermined
to be Powered by Multiple
If No or Undetermined, Skip If No or Undetermined, Skip If No or Undetermined, Skip
Fuels?
to SCHEDULE 4.
to SCHEDULE 4.
to SCHEDULE 4.

16

Will this Unit be Able to CoFire Fuels?

17

Fuel Options for Co-Firing

18

Will This Generator be Able
to be Powered by Co-Fired
Fuel Oil and Natural Gas?

Will This Generator be able
to Run on 100% Oil?

19

20

21

If No, What is the Expected
Maximum Oil Heat Input
When Co-Firing with Natural
Gas?
What is the Expected
Maximum Output
Achievable (Net Summer
Capacity in MW) When
Making the Maximum Use of
Oil and Co-Firing Natural
Gas?
Will This Unit be Able to
Fuel Switch?
Will This Unit be Able to
Switch Between Oil and
Natural Gas?

[ ] Yes

[ ] No

[ ] Yes

[ ] No

[ ] Yes

[ ] No

If No, Skip to Line 20.

If No, Skip to Line 20.

If No, Skip to Line 20.

a

b

c

a

b

c

a

b

c

d

e

f

d

e

f

d

e

f

[ ] Yes

[ ] No

If No, Skip to Line 20.
[ ] Yes

[ ] No

[ ] Yes

[ ] No

If No, Skip to Line 20.
[ ] Yes

[ ] No

[ ] Yes

[ ] No

If No, Skip to Line 20.
[ ] Yes

[ ] No

If Yes, Skip to Line 20.

If Yes, Skip to Line 20.

If Yes, Skip to Line 20.

________ %

________ %

________ %

________ MW

________ MW

________ MW

[ ] Yes

[ ] No

If No, Skip to Schedule 4.
[ ] Yes

[ ] No

If No, Skip to Line 23.

47

[ ] Yes

[ ] No

If No, Skip to Schedule 4.
[ ] Yes

[ ] No

If No, Skip to Line 23.

[ ] Yes

[ ] No

If No, Skip to Schedule 4.
[ ] Yes

[ ] No

If No, Skip to Line 23.

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Operator Name:____________________________________

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator ID:___________

Plant Name:_______________________________________

Plant Code:___________

ANNUAL ELECTRIC GENERATOR
REPORT

Reporting as of December 31 of Year:___________________
SCHEDULE 3, PART C. GENERATOR INFORMATION – PROPOSED GENERATORS
(COMPLETE ONE COLUMN FOR EACH GENERATOR, BY PLANT)
Generator (a)
Generator (b)
Generator (c)
If Yes, Will this Unit be Able
to Switch Fuels While
[ ] Yes [ ] No
[ ] Yes [ ] No
[ ] Yes [ ] No
Operating?
What is the Expected
Maximum Net Summer
________ MW
________ MW
________ MW
Output Achievable (MW)
When Running on Natural
Gas?
What is the Expected
Maximum Net Summer
________ MW
________ MW
________ MW
Output Achievable (MW)
When Running on Fuel Oil?
[ ] 0 to 6 hours
[ ] 0 to 6 hours
How Much Time is Expected [ ] 0 to 6 hours
[ ] over 6 to 24 hours
[ ] over 6 to 24 hours
[ ] over 6 to 24 hours
to be Required to Switch
This Unit From Using 100% [ ] over 24 to 72 hours
[ ] over 24 to 72 hours
[ ] over 24 to 72 hours
Natural Gas to Using 100% [ ] over 72 hours.
[ ] over 72 hours.
[ ] over 72 hours.
Oil?
[ ] Unknown or uncertain [ ] Unknown or uncertain [ ] Unknown or uncertain
Are There Factors That Will
[ ] Yes [ ] No
[ ] Yes [ ] No
[ ] Yes [ ] No
Limit the Unit’s Ability to
Switch From Natural Gas to
If No, Skip to Line 26.
If No, Skip to Line 26.
If No, Skip to Line 26.
Oil?
[ ] Limited on site fuel
[ ] Limited on site fuel
[ ] Limited on site fuel
22
storage.
storage.
storage.
[
]
Air
Permit
limits
[
]
Air
Permit
limits
[ ] Air Permit limits
If Yes, Check All Factors
[ ] Other (specify in
[ ] Other (specify in
[ ] Other (specify in
That Apply
SCHEDULE 7.
SCHEDULE 7.
SCHEDULE 7.
COMMENTS)
COMMENTS)
COMMENTS)

23

Fuel Switching Options

a

b

c

a

b

c

a

b

C

d

e

f

d

e

f

d

e

f

48

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

ANNUAL ELECTRIC GENERATOR
REPORT

Operator ID:__________

Reporting as of December 31 of Year:____________

SCHEDULE 4. OWNERSHIP OF GENERATORS OWNED JOINTLY OR BY OTHERS
PLANT NAME (a)
EIA PLANT CODE (b)
OPERATOR’S GENERATOR IDENTIFICATION (c)
IF JOINTLY OWNED – OWNER NAME AND CONTACT INFORMATION (d)
Owner/Joint Owner 1: Name
Street Address
City, State and Zip Code

% OWNED (e):

Joint Owner 2: Name

% OWNED (e):

EIA CODE:

Street Address
City, State and Zip Code

EIA CODE:

Joint Owner 3: Name
Street Address
City, State and Zip Code

% OWNED (e):

Joint Owner 4: Name
Street Address
City, State and Zip Code

% OWNED (e):

Joint Owner 5: Name
Street Address
City, State and Zip Code

% OWNED (e):

Joint Owner 6: Name
Street Address
City, State and Zip Code

% OWNED (e):

Joint Owner 7: Name
Street Address
City, State and Zip Code

% OWNED (e):

Joint Owner 8: Name
Street Address
City, State and Zip Code

% OWNED (e):

EIA CODE:

EIA CODE:

EIA CODE:

EIA CODE:

EIA CODE:

EIA CODE:

Joint Owner 9: Name
Street Address
City, State and Zip Code

% OWNED (e):

Joint Owner 10: Name
Street Address
City, State and Zip Code

% OWNED (e):

EIA CODE:

EIA CODE:
Total

49

100%

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________
ANNUAL ELECTRIC GENERATOR
REPORT

Operator ID:__________
Reporting as of December 31 of Year:____________
SCHEDULE 5. NEW GENERATOR INTERCONNECTION INFORMATION
(COMPLETE FOR EACH GENERATOR ENTERING SERVICE DURING CALENDAR YEAR 2010)
LINE
Name:
Name:
Name:
1
Plant Name and EIA Plant Code
Code:
Code:
Code:
2

Generator ID

3

Date of Actual Generator
Interconnection (MM-YYYY)

4

Date of Initial Interconnection
Request (MM-YYYY)

5

City:

City:

City:

State:

State:

State:

Interconnection Site Location

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:)

9

10

11

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

e. Other Equipment (specify in
SCHEDULE 7. COMMENTS)

[ ] Yes

[ ] No

[ ] Yes

[ ] No

[ ] Yes

[ ] No

b. Will This Cost Be Repaid?

[ ] Yes

[ ] No

[ ] Yes

[ ] No

[ ] Yes

[ ] No

Were Specific Transmission Use
Rights Secured as a Result of the
Interconnection Costs Incurred?

[ ] Yes

[ ] No

[ ] Yes

[ ] No

[ ] Yes

[ ] No

a. Total Cost for Other Grid
Enhancements/ Reinforcements
Needed to Accommodate Power
Deliveries From the Generator
(Thousand $)

50

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours
Operator Name:_____________________________________
Operator ID:_________
Plant Name:_________________________________________

Plant Code: _________

Reporting as of December 31 of 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)
EQUIPMENT
EQUIPMENT
EQUIPMENT
EQUIPMENT
EQUIPMENT
LINE EQUIPMENT TYPE IDENTIFICATION IDENTIFICATION IDENTIFICATION IDENTIFICATION IDENTIFICATION
(a)
(b)
(c)
(d)
(e)
1

Boiler ID

2

Associated
Generator(s) ID

3

Generator
Associations with
Boiler as Actual or
Theoretical

4

Associated Cooling
System(s) ID

5

Associated Flue Gas
Particulate
Collector(s) ID

6

Associated Flue Gas
Desulfurization
Unit(s) ID

7

Associated Flue(s) ID

8

Associated Stack(s)
ID

51

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours
Operator Name:_____________________________________
Operator ID:_________
Plant Name:_________________________________________

Plant Code: _________

Reporting as of December 31 of 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

2a

Type Of Boiler Standards Under Which The Boiler Is
Operating (use codes)

2b

3

Is Boiler Operating Under a New Source Review (NSR)
Permit?
If Yes, list date (MM-YYYY) and identification number
of the issued permit
PARTICULATE
CATEGORY
MATTER
(a)
FD [ ]
ST [ ]
Type of Statute or Regulation
(use codes)
LO [ ]
NA [ ]

D[

] Da [
Dc [ ]
[ ] Yes

Date

] Db [
N[ ]

]

[ ] No
Permit Number

SULFUR DIOXIDE
(b)
FD [ ]
ST [ ]

NITROGEN OXIDES
(c)
FD [ ]
ST [ ]

LO [

LO [

]

NA [

]

]

NA [

Emission Standard Specified
4a
4b
5
6

7

8

9

10

Emission Rate
Percent Scrubbed
Unit of Measurement
Specified (use codes)
Time Period Specified (use
codes)
Year Boiler Was or is
Expected to Be in
Compliance With Federal,
State and/or Local Regulation
If Not in Compliance,
Strategy for Compliance (use
codes)
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)
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)

N/A

N/A

N/A

N/A

N/A

N/A

52

]

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours
Operator Name:_____________________________________
Operator ID:_________
Plant Name:_________________________________________

Plant Code: _________

Reporting as of December 31 of Year:___________________
SCHEDULE 6, PART C. BOILER INFORMATION – DESIGN PARAMETERS
(Except for Lines 1 and 2, DATA NOT REQUIRED FOR PLANTS LESS THAN 100 MW)
(COMPLETE A SEPARATE PAGE FOR EACH BOILER)
LINE
1
Boiler ID
2

Boiler Status (use codes)

3

Boiler Actual or Projected Date of Commercial Operation (MM-YYYY)

4

Boiler Actual or Projected Retirement Date (MM-YYYY)

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 in SCHEDULE 7. COMMENTS)

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)

53

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours
Operator Name:_____________________________________
Operator ID:_________
Plant Name:_________________________________________

Plant Code: _________

Reporting as of December 31 of Year:___________________
SCHEDULE 6, PART D. BOILER INFORMATION – NITROGEN OXIDE EMISSION CONTROLS
(COMPLETE A SEPARATE PAGE FOR EACH BOILER)
1
Boiler ID
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?

2

If “Yes,” Select Up To Three Mercury
Emission Controls (use codes)

Yes [

54

]

No [

]

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours
Operator Name:_____________________________________
Operator ID:_________
Plant Name:_________________________________________

Plant Code: _________

Reporting as of December 31 of 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
(MM-YYYY)

4a

Type of Cooling System (use codes)

4b

For Hybrid Cooling Systems, Indicate Percent of Cooling Load Served by Dry Cooling
Components.

5a

Source (Name) of Cooling Water Including Makeup Water (if discharge is into different
water body, specify in SCHEDULE 7. COMMENTS)

5b

Type of Cooling Water Source (use codes)

5c

Type of Cooling Water (use codes)

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 (MM-YYYY)
COOLING PONDS

8

Actual or Projected In-Service Date (month and year of commercial operation, e.g. 121982)

9

Total Surface Area (acres)

10

Total Volume (acre-feet)
COOLING TOWERS

11

Actual or Projected In-service Date (MM-YYYY)

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)
55

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours

17

Towers (if applicable)

18

Chlorine Discharge Control Structures and Equipment (if applicable)
COOLING WATER INTAKE AND OUTLET LOCATIONS
ITEM
INTAKE (a)

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”

56

OUTLET (b)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours
Operator Name:_____________________________________
Operator ID:_________
Plant Name:_________________________________________
Plant Code: _________
Reporting as of December 31 of 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)

57

U.S. Department of Energy
Form Approved
U.S. Energy Information Administration ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Form EIA-860 (2011)
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours
Operator Name:_____________________________________
Operator ID:_________
Plant Name:_________________________________________

Plant Code: _________

Reporting as of December 31 of 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 (MM-YYYY)

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

58

U.S. Department of Energy
Form Approved
U.S. Energy Information Administration ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Form EIA-860 (2011)
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours
22

Other (installed cost of flue gas desulfurization unit)

23

Total (sum of lines 20, 21, 22)

59

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
ANNUAL ELECTRIC GENERATOR OMB No. 1905-0129
Approval Expires: 12/31/2013
REPORT
Burden: 9.4 hours
Operator Name:_____________________________________
Operator ID:_________
Plant Name:_________________________________________

Plant Code: _________

Reporting as of December 31 of 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., 122001)

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
U.S. Energy Information Administration
Form EIA-860 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.4 hours
Operator Name:_____________________________________________________________________________________
ANNUAL ELECTRIC
GENERATOR REPORT

Operator ID:__________

Reporting as of December 31 of Year:____________
SCHEDULE 7. COMMENTS
(USE ADDITIONAL PAGES IF NECESSARY)

SCHEDULE
NUMBER

PART

LINE
NUMBER

COMMENTS
(Including all identifying codes such as plant code, generator ID,
or boiler ID to which the comment applies)

61

Subject: United States Department of Energy – EIA Monthly Data Collection, Form EIA-860M

Dear Respondent:
Note: The EIA 860M data collection for this reporting month will take into account both January and February 2010
updates to the 860M form.
Entities: [ENITITYNUMBER, ENTITYNAMES]
Facilities: [PLANTNAMES]
This message was sent to notify you that the February 2010 EIA-860M, Monthly Update to the Annual Electric
Generator Report, is now available for e-filing. Before you submit your form, please consider the following:
If there is no change in the data shown for a generator, click in the “Check if no change” box; otherwise
update (e.g., status code and/or planned current effective date/planned retirement date) the data in all
applicable schedules and include any applicable notes in Schedule 4.
If a proposed retirement has occurred, remove the “Planned Modification or Retirement” indicator
(Schedule 3, Line 1) by selecting null from the drop down list and enter the actual month and year of
retirement in line 19.
If the “Planned Current Effective Date” (Schedule 2, Line 8) or the “Planned Retirement Month/Year”
(Schedule 3, Line 19) is January or February 2010 or earlier the "Check if no change" box is not applicable.
In this case, updates to status code/indicator and/or effective date(s) are required.
Please contact me if you are encountering difficulties with the form. I can be reached at (202) 586-1029 or [email protected]. The February 2010 EIA-860M is due February 15, 2010.
The website for accessing the EIA-860M is https://signon.eia.doe.gov/ssoserver/login .
Thank you for your time and cooperation in submitting timely, accurate data to the Energy Information
Administration.

Sincerely,
Patricia Hutchins
Survey Analyst, Form EIA-860M
Electric Power Division
Office of Coal, Nuclear, Electric and Alternate Fuels
Energy Information Administration

6

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)
PURPOSE

MONTHLY UPDATE TO THE
ANNUAL ELECTRIC
GENERATOR REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs

Form EIA-860M collects data on the status of:
a) Proposed new generators scheduled to begin commercial operation within the next 12
months,
b) Existing generators scheduled to retire from service within the next 12 months,
c) Existing generators that have proposed modifications that are scheduled for completion
within one month.
The data collected on this form appear in the EIA publication Electric Power Monthly. They are
also used to monitor the current status and trends of the electric power industry and to evaluate
the future of the industry.

REQUIRED
RESPONDENTS

RESPONSE DUE
DATE

Respondents to the Form EIA-860M who are required to complete this form are all Form EIA-860,
ANNUAL ELECTRIC GENERATOR REPORT, respondents who have indicated in a previous
filing to EIA that they have either one of the following: (1) a proposed new generator scheduled
to start commercial operation within the next 12 months, (2) an existing generator scheduled to
retire from service within the next 12 months or (3) an existing generator with a proposed
modification scheduled for completion within one month, of the report period (month).
Reporting on the EIA-860M must begin when either a new generator is within 12 months of
entering commercial operation, an existing generator proposed for retirement is within 12 months
of being retired from service, or a proposed modification to an existing generator is within one
month of completion.
The status information provided on the EIA-860M should be the status of the generator as of the
end of the data reporting period. The report is due by the 15th day of the month following the data
reporting period.

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 email requesting
assistance to: [email protected]

•

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

•

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

• If you need an alternate means of filing your response, contact the Help Desk.
Please retain a completed copy of this form for your files.
CONTACTS

Internet System Questions: For questions related to the Internet Data Collection system, see
the help contact information immediately above.
Data Questions: For questions about the data requested on Form EIA-860M, contact the Survey
Manager:
Patricia Hutchins
Telephone Number: (202) 586-2402
FAX Number: (202) 287-1960
Email: [email protected]

1

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)
ITEM-BY-ITEM
INSTRUCTIONS

MONTHLY UPDATE TO THE
ANNUAL ELECTRIC
GENERATOR REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs

SCHEDULE 1. IDENTIFICATION
1. Survey Contact: Verify contact name, title, address, telephone number, fax number, and
email address.
2. Supervisor of Contact Person for Survey: Verify the contact’s supervisor’s name, title,
address, telephone number, fax number and email address.
3. Report For: Verify the Legal Name of the Entity, Entity Identification Number, address, city,
state, zip code and reporting month and year. If incorrect, provide the correct information.
Provide changes to Legal Name of the Entity in SCHEDULE 4. COMMENTS. Note that the
Entity ID is assigned by EIA and cannot be altered.
If any of the above information is incorrect, revise the incorrect entry and provide the correct
information. Provide any missing information.
SCHEDULE 2. UPDATES TO PROPOSED NEW GENERATORS
Changes to the generator data: If there is no change to the preprinted data, check “no
change.”
1. Identification Information (applicable in all Schedules):
•

Plant Name: Provide an explanation of name changes in SCHEDULE 4.
COMMENTS.

•

Plant Code: If the information is incorrect, contact EIA.

•

Plant State: If the State listed is the incorrect location for the plant, provide correct
State. Use the two-letter U.S. Postal abbreviation to show the State in which the
plant is physically located.

If data are incorrect, provide revisions or updates in columns for updates. If data are
missing, provide data.
2. For line 1, verify Status Code. Use the status codes from the following table:
Status Code
IP
TS
P
L
T
U
V
OP
OT

Status Code Description
Planned new generator canceled, indefinitely postponed, or no
longer in resource plan
Construction complete, but not yet in commercial operation (including
low power testing of nuclear units)
Planned for installation but regulatory approvals not initiated; not
under construction
Regulatory approvals pending; not under construction, but site
preparation could be underway
Regulatory approvals received; not under construction but site
preparation could be underway
Under construction, less than or equal to 50 percent complete (based
on construction time to date of operation)
Under construction, more than 50 percent complete (based on
construction time to date of operation)
Operating (in commercial operation)
Other (Explain in SCHEDULE 4. COMMENTS)

2

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)

MONTHLY UPDATE TO THE
ANNUAL ELECTRIC
GENERATOR REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs

3. For line 2, verify Prime Mover Type. If re-powering is completed, update prime mover
type, as appropriate.
•

For combined cycle units, enter a prime mover code for each generator.

•

Use the prime mover codes from the following table:

Prime
Mover
BA
CP
ES
FW
ST
GT
IC
CA
CT
CS
CC
HA
HB
HY
HK
PS
BT
PV
WT
CE
FC
OT

Description
Energy Storage, Battery
Energy Storage, Concentrated Solar Power
Energy Storage, Other (Describe in Schedule 4, COMMENTS)
Energy Storage, Flywheel
Steam Turbine, including nuclear, geothermal and solar steam (does not
include combined cycle).
Combustion (Gas) Turbine – Simple Cycle (includes jet engine design)
Internal Combustion Engine (diesel, piston, reciprocating)
Combined Cycle Steam Part
Combined Cycle Combustion Turbine Part (type of coal or solid must be
reported as energy source for integrated coal gasification).
Combined Cycle Single Shaft (combustion turbine and steam turbine share a
single generator)
Combined Cycle Total Unit (use only for plants/generators that are in planning
stage, for which specific generator details cannot be provided).
Hydrokinetic, Axial Flow Turbine
Hydrokinetic, Wave Buoy
Hydraulic Turbine (includes turbines associated with delivery of water by
pipeline)
Hydrokinetic, Other (Describe in SCHEDULE 4, COMMENTS)
Hydraulic Turbine – Reversible (pumped storage)
Turbines Used in a Binary Cycle (such as used for geothermal applications)
Photovoltaic
Wind Turbine
Compressed Air Energy Storage
Fuel Cell
Other (Describe in SCHEDULE 4, COMMENTS)

4. For line 3, verify Nameplate Capacity. If the nameplate capacity is expressed in kilovolt
amperes (kVA), convert to kilowatts by multiplying the power factor by the kVA, divide by
1,000 to express in megawatts to the nearest tenth.
5. For lines 4 and 5, verify Net Summer Capacity and Net Winter Capacity, respectively.
6. For line 6, verify Energy Source 1, the energy source that is expected to be used in the
largest quantity (Btus) to power the generator. Select appropriate energy source codes
from the table of energy source codes 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).
7. For line 7, verify Energy Source 2, the energy source that is expected to be used in the
second largest quantity (Btus) to power the generator. Select appropriate energy source
codes from the table of energy source codes 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).
3

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs
8. For line 8, verify the Planned Current Effective Date that the generator is scheduled to
start commercial operation, or enter the date the generator started commercial operation
if reported status is “OP”.
MONTHLY UPDATE TO THE
ANNUAL ELECTRIC
GENERATOR REPORT

9. For line 9, enter Reason for Change in status or change in scheduled date. Check all of
the reasons that apply; if “Other,” explain in SCHEDULE 4, COMMENTS.

SCHEDULE 3. UPDATES TO PROPOSED CHANGES TO EXISTING GENERATORS
1. For line 1, verify Status Code. Use the status codes from the following table:
Status Code
RP
A
D
RT
RE
CN
OP
OT

Status Code Description
Proposed for life extension or repowering
Proposed generator net capacity increase (rerating or relicensing)
Proposed generator net capacity decrease (rerating or relicensing)
Existing generator scheduled for retirement
Retired - no longer in service and not expected to be returned to
service
Proposed change has been cancelled or indefinitely postponed
Proposed change completed, generator available for commercial
operation
Other modification (Explain in SCHEDULE 4. COMMENTS)

2. For line 2, verify Existing Prime Mover, use codes from the table in these instructions.
3. For line 3, verify 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 power factor by the kVA,
divide by 1,000 to express in megawatts to the nearest tenth.
4. For line 4, verify Existing Net Summer Capacity.
5. For line 5, verify the Incremental Net Summer Capacity.
6. For line 6, verify New Net Summer Capacity, (sum of lines 4 and 5).
7. For line 7, verify Existing Net Winter Capacity.
8. For line 8, verify the Incremental Net Winter Capacity.
9. For line 9, verify New Net Winter Capacity, (sum of lines 7 and 8).
10. For line 10, verify Energy Source 1. (Predominant Energy Source). Update, as
appropriate, based on the completion of any modification resulting in a change in energy
source. Enter the appropriate energy source code from the table in these instructions.
11. For line 11, verify Energy Source 2, (Second Most Predominant Energy Source).
Update, as appropriate, based on the completion of any modification resulting in a
change in energy source. Enter the appropriate energy source code from the table in
these instructions.
12. For line 12, verify New Prime Mover. For existing generators with a status code of “RP”,
enter the prime mover code that is applicable once the modification is complete if it will
be different from the current prime mover. Use the codes for prime mover provided in
these instructions.
13. For line 13, verify the Planned Current Effective Date. Enter the month and year that
the modification is expected to be completed or the month and year that the generator is
scheduled for retirement, as applicable . If the proposed modification is completed, enter
4

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs
the actual date of completion and state “Completed’ in SCHEDULE 4. COMMENTS and
update status code to “OP”.
MONTHLY UPDATE TO THE
ANNUAL ELECTRIC
GENERATOR REPORT

14. For line 14, enter Reason for Change in the planned current effective date. Check all of
the reasons that apply, if “Other,” explain in SCHEDULE 4. COMMENTS.

Energy Source
Code

ENERGY SOURCE
CODES

Fossil Fuels
Anthracite Coal and Bituminous Coal

BIT
LIG
Coal and
Syncoal

Lignite Coal
Coal-based 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.

SC
SUB

Subbituminous Coal
Waste/Other Coal. Including anthracite culm, bituminous
gob, fine coal, lignite waste, waste coal.
Distillate Fuel Oil. Including Diesel, No. 1, No. 2, and No. 4
Fuel Oils.
Jet Fuel

WC
DFO
JF
KER
Petroleum
Products

Kerosene

PC

Petroleum Coke
Residual Fuel Oil. Including No. 5, No. 6 Fuel Oils, and
Bunker C Fuel Oil.
Waste/Other Oil. Including Crude Oil, Liquid Butane, Liquid
Propane, Oil Waste, Re-Refined Motor Oil, Sludge Oil, Tar
Oil, or other petroleum-based liquid wastes.
Blast Furnace Gas
Natural Gas
Other Gas
Specify in SCHEDULE 4. COMMENTS
Gaseous Propane
Synthetic Gas, other than coal-derived
Synthetic Gas, derived from coal
Renewable Energy Sources
Agricultural Crop Byproducts/Straw/Energy Crops
Municipal Solid Waste
Other Biomass Solids
Specify in SCHEDULE 4. COMMENTS.
Wood/Wood Waste Solids. Including paper pellets, railroad
ties, utility poles, wood chips, bark, & wood waste solids
Other Biomass Liquids. Specify in SCHEDULE 4.
COMMENTS
Sludge Waste
Black Liquor
Wood Waste Liquids, excluding Black Liquor. Includes
red liquor, sludge wood, spent sulfite liquor, and other
wood-based liquids.

RFO
WO
BFG
NG
Natural Gas
and Other
Gases

Solid
Renewable
(Biomass)
Fuels

OG
PG
SG
SGC
AB
MSW
OBS
WDS
OBL

Liquid
Renewable
(Biomass)
Fuels

Description

SLW
BLQ
WDL

5

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)
Gaseous
Renewable
(Biomass)
Fuels
Other
Renewable
Energy Sources

MONTHLY UPDATE TO THE
ANNUAL ELECTRIC
GENERATOR REPORT
LFG

Landfill Gas
Other Biomass Gas. Includes digester gas, methane, and
other biomass gases. Specify in SCHEDULE 4.
COMMENTS
Solar
Wind
Geothermal
Water at a Conventional Hydroelectric Turbine
All Other Energy Sources
Purchased Steam
Waste heat not directly attributed to a fuel source. WH
should only be reported where the fuel source for the
waste heat is undetermined.
Tire-derived Fuels
Nuclear including Uranium, Plutonium, Thorium
Specify in SCHEDULE 4. COMMENTS.

OBG
SUN
WND
GEO
WAT
PUR

All Other
Energy
Sources

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs

WH
TDF
NUC
OTH

GLOSSARY

The glossary for this form is available online at the following URL:
http://www.eia.gov/glossary/index.html

SANCTIONS

The timely submission of Form EIA-860M 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 0.3 hours per
response, including the time of 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 U.S. Energy Information Administration,
Statistics and Methods Group, EI-70, 1000 Independence Avenue S.W., Forrestal Building,
Washington, D.C. 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 THE
CONFIDENTIALITY
OF INFORMATION

Information reported on Form EIA-860M will be treated as non-sensitive and may be publicly
released in identifiable form. In addition to the use of the information by EIA for statistical purposes,
the information may be used for any nonstatistical purposes such as administrative, regulatory, law
enforcement, or adjudicatory purposes.

6

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs

MONTHLY UPDATE TO THE
ANNUAL ELECTRIC
GENERATOR REPORT

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
Last Name:_________________

First Name:________________
Title:______________________________
Telephone (include extension):______________
Email:_______________________________

Fax:__________________

Supervisor of Contact Person for Survey
First Name:____________________
Last Name:_____________________
Title:___________________________
Telephone (include extension):______________
Fax:__________________
Email:________________________________
Report For
Legal Name of Entity: ________________________________
Entity ID:______________
Address:________________________________________________________________________
City:_______________
State:_______________
Zip Code:________________
Reporting Month/Year:________________
For questions or additional information about the Form EIA-860M contact the Survey Managers:
Patricia Hutchins
Telephone Number: (202) 586-2402
FAX Number: (202) 287-1960
Email: [email protected]

1

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)

MONTHLY UPDATE TO THE
ANNUAL ELECTRIC
GENERATOR REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs

Legal Name of Entity:_________________________________________
Entity ID:_______
State:______
Reporting Month/Year:________________
SCHEDULE 2. UPDATES TO PROPOSED NEW GENERATORS
Identification Information:

Line
No.
1
2
3
4
5
6
7
8

9

Plant Name ____________________
Plant Code__________

Plant State ______________

Check if no change
Generator
Data Element
Last Data Reported
This Month’s
to EIA
Updates
Pre-printed
Status Code
Pre-printed
Prime Mover Code
Nameplate Capacity (MW) Pre-printed
Pre-printed
Net Summer Capacity
(MW)
Net Winter Capacity (MW) Pre-printed
Pre-printed
Energy Source 1
Pre-printed
Energy Source 2
Planned Current Effective Pre-printed
Date: MM/YYYY
[ ] Equipment
[ ]
Reason for Change
Financial
(check all that apply; if
“Other” explain in
[ ]
[ ]
Permitting
Other
SCHEDULE 4)

2

Check if no change
Generator
Last Data Reported
This Month’s
to EIA
Updates
Pre-printed
Pre-printed
Pre-printed
Pre-printed
Pre-printed
Pre-printed
Pre-printed
Pre-printed
Financial

[ ]

Equipment

[ ]

Permitting

[ ]

Other

[ ]

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)

MONTHLY UPDATE TO THE
ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs

Legal Name of Entity:________________________________
Entity ID:______________
Plant Name:_______________________________________
Plant ID:______________
State:______
Reporting Month/Year:___________
SCHEDULE 3. UPDATES TO PROPOSED CHANGES TO EXISTING GENERATORS
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13

14

Data Element
Status Code
Prime Mover (existing)
Nameplate Capacity
(MW)
Existing Net Summer
Capacity (MW)
Incremental Net
Summer Capacity (MW)
New Net Summer
Capacity (MW) (lines 4
+5)
Existing Net Winter
Capacity (MW)
Incremental Net Winter
Capacity (MW)
New Net Winter
Capacity (MW) (lines 7
+ 8)
Energy Source 1
Energy Source 2
New Prime Mover Code
Planned Current
Effective Date: MM/YY
Reason for Change
(check all that apply; if
“Other” explain in
SCHEDULE 4.
COMMENTS)

Check if no change
Generator
Last Data
This Month’s
Reported to EIA
Updates
Pre-printed
Pre-printed
Pre-printed

Check if no change
Generator
Last Data
This Month’s
Reported to EIA
Updates
Pre-printed
Pre-printed
Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed

Pre-printed
Pre-printed
Pre-printed
Pre-printed

Pre-printed
Pre-printed
Pre-printed

Financial

[ ]

Permitting

[ ]

Equipment
Other

3

[ ]

Financial

[ ]

Equipment

[ ]

[ ]

Permitting

[ ]

Other

[ ]

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-860M (2011)

MONTHLY UPDATE TO THE
ANNUAL ELECTRIC GENERATOR
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 0.3 hrs

Legal Name of Entity:_________________________________________
Entity ID:_______
Reporting Month/Year:________________
SCHEDULE 4. COMMENTS
SCHEDULE
NUMBER
(a)

LINE
NUMBER
(b)

NOTES
(c)

4

Subject: United States Department of Energy – EIA Annual Data Collection, Form EIA-861
Dear Respondent:
The Energy Information Administration’s (EIA), electronic filing system (e-file) is now ready for you to report your annual electric
data for the year 2010. You are required to file Form EIA-861, “Annual Electric Power Industry Report.” The survey is due no
later than April 30, 2011. The EIA electric surveys are a mandatory collection under the authority of the Federal Energy
Administration Act of 1974 (P.L. 93-275). Non-respondents and late filers are subject to financial penalties. The EIA encourages you
to file your data using our IDC system.
If you are currently registered in the e-file system for secure electronic access with a Single Sign-On (SSO) account, you can login to
the e-file system at: https://signon.eia.doe.gov/ssoserver/login and enter your User ID and Password to access your EIA surveys. If
you are registered and have forgotten your password, but know the User ID, you can reset your password. Log on to the e-file system
at the website listed above. Type your User ID and click on Forgot Your Password. Follow the prompts and you will be allowed to
reset your password.
Please pay special attention to the password rules and be sure to record your new password. If you need assistance resetting your
password, please call the Help Center at (202) 586-9595 or contact us via email at: [email protected].
If you are not registered, please contact the CNEAF Help Center at (202) 586-9595 or via email. Please choose only one method of
contact for the CNEAF Help Center, either telephone or email. Please do not do both.
Edits have been built into the e-file system to assist you in providing accurate data. In order to successfully submit your forms, you
must run the edits and address the warning messages for all flagged data by either correcting and/or commenting on each of the
flagged data elements. Please go to the Error Log and click on the “Run EIA-861 Edits” button. Once you have corrected and/or
commented on the appropriate edit flags, you should be able to submit your data by pressing the “Submit” button. If your data are
accepted you should receive a message stating that your data have been successfully sent with the current date.
The timely submission of Form EIA-861 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.
Your cooperation is greatly appreciated.
Sincerely,
XXXXXXXXXXX
Survey Manager
Electric Power Division
Office of Coal, Nuclear, Electric and Alternate Fuels
Energy Information Administration

7

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

PURPOSE

Form EIA-861 collects information on the status of electric power industry participants involved
in the generation, transmission, and distribution of electric energy in the United States, its
territories, and Puerto Rico. The data from this form are used to accurately maintain the EIA list
of electric utilities, to draw samples for other electric power surveys, and to provide input for the
following EIA reports: Electric Power Monthly, Monthly Energy Review, Electric Power Annual,
Annual Energy Outlook, and 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

The Form EIA-861 is to be completed by electric power industry entities including: electric
utilities, all DSM Program Managers (entities responsible for conducting or administering a
DSM program), wholesale power marketers (registered with the Federal Energy Regulatory
Commission), energy service providers (registered with the States), and electric power
producers. Responses are collected at the business level (not at the holding company level).

RESPONSE DUE
DATE

Submit the completed Form EIA-861 to the EIA by April 30, following the end of the calendar
year.

METHODS OF
FILING RESPONSE

Submit your data electronically using EIA’s secure internet data collection system (e-file). 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 email requesting
assistance to: [email protected].

•

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

•

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

•

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

Please retain a completed copy of this form for your files.
CONTACTS

Internet System Questions: For questions related to e-file, see the help contact information
immediately above.
Data Questions: For questions about the data requested on Form EIA-861, contact the Survey
Manager:
Karen McDaniel
(202) 586-4280

Stephen Scott
(202) 586-5140
FAX Number: (202) 287-1938
Email: [email protected]

1

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)
GENERAL
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs
Submit the completed Form EIA-861 to the EIA by April 30, following the end of the
calendar year.
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

1. Respondents, who also submit the Form EIA-826, “Monthly Electric Sales and Revenue
Report with State Distributions," should coordinate the information submitted on the Form
EIA-861, and Form EIA-826 to ensure consistency.
2. Complete the information at the top portion of the form with the name, telephone and FAX
number, and address, of the current contact person, and the contact person’s supervisor.
3. Report peak demand in megawatts and energy values (e.g., generation and sales) in
megawatthours, except where noted. One megawatthour equals 1,000 kilowatthours. To
convert kilowatthours to megawatthours, divide by 1,000 and round to the nearest whole
number. For example, sales of 5,245,790 kilowatthours should be reported as 5,246
megawatthours.
4. Report in whole numbers (i.e., no decimal points), except where explicitly instructed to
report otherwise. For example: revenue of $8,459,688.42 should be reported as 8,460
(thousand dollars). There is one decimal place on the revenue on Schedule 3 and 4. Lines
4, 6 and 7 on Schedule 6A and line 3 on schedule 2C also contain one decimal point.
5. A state code can only be removed by highlighting the state and clicking on the Remove
Record icon (Schedule 2C, 2D, 4A-D and 6D). The Remove Record icon is the last one in
the icon row at the top (same row as the save and print button).
6. For number of customers, enter the average of the 12 close-of-month customer accounts.
•

All respondents having end-use customers, including retail power marketers selling
power in deregulated, competitive State programs must use the average of the 12
close-of-month customer counts when reporting on Schedule 4, even if your company
began business after the beginning of the reporting year, or ended business before the
close of the year.

•

Count each meter as a separate customer in cases where commercial franchise or
residential customer-buying groups have been aggregated under one buyer
representative. The customer counts for public-street and highway lighting should be
one customer per community.

•

Please do not count each pole as a separate customer even if billing is by a flat rate per
pole per month.

7. Use a minus sign for reporting negative numbers. Line 9 on schedule 2B must be a
negative number. On schedule 2B, line 1 and schedule 3, line 4 and 5, the number may
either positive or negative.
8. Where exact data are unavailable, report estimated data.
9. See the Glossary for terms used in this survey. The financial and accounting terms are
consistent as outlined in the Uniform System of Accounts for Public Utilities and Licensees
(U.S. of A.) (18 CFR Part 101).

2

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs
SCHEDULE 1. IDENTIFICATION

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

ITEM-BY-ITEM
INSTRUCTIONS

1. Survey Contact: Verify contact name, title, address, telephone number, fax number, and
address.
2. Supervisor of Contact Person for Survey: Verify the contact’s supervisor’s name, title,
address, telephone number, Fax number and address. Supervisor contact must be
different than the survey contact.
3. Report For: Verify all information, including entity name, entity identification number, and
reporting 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.
Entity and Preparer Information
4. Legal Name of Entity: Enter the legal name of the entity for which this form is being
prepared.
5. Current Address of Entity’s Principal Business Office: Enter the complete address,
excluding the legal name, of the entity’s principal business office (i.e., headquarters, main
office, etc.).
6. Preparer’s Legal Name: Enter the legal name of the company, which prepares this form, if
different from the Legal Name of Entity.
7. Current Address of Preparer’s Office: Enter the address to which this form should be
mailed, if different from the Current Address of Entity’s Principal Business Office.
Include an attention line, room number, building designation, etc. to facilitate the future
handling and processing of the Form EIA-861.
SCHEDULE 2. PART A. GENERAL INFORMATION
1. For line 1, please check all of the Regional Entities within the North American Electric
Reliability Corporation (NERC), in which your organization conducts operations.
The Regional Entities are:
TRE .................... Texas Regional Entity
FRCC ................. Florida Reliability Coordinating Council
MRO ................... Midwest Reliability Organization
NPCC ................. Northeast Power Coordinating Council
RFC…………..… ReliabilityFirst Corporation
SERC ................. Southeastern Electric Reliability Council
SPP .................... Southwest Power Pool
WECC ................ Western Electric Coordinating Council
For line 1a, select the RTO or ISO from the list:










California ISO
Electric Reliability Council of Texas
Southwest Power Pool
Midwest ISO
PJM Interconnection
New York ISO
ISO New England
Other
3

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

If your RTO or ISO does not appear on the list, select “Other” and explain in SCHEDULE 9.
COMMENTS
2. For line 3, Balancing Authority(s), enter the name of the balancing authority(s)
responsible for your oversight. If your balancing authority is not on the list, use “Other” and
list the authority in the Comments (Schedule 9).
3. For line 4, Operate Generating Plant(s), Check Yes to indicate that organization operated
a generating plant(s) during the reporting period. Otherwise, Check No.
4. For line 5, Activities, Check the appropriate activities the electric entity was engaged in
during the reporting year. You must check at least one.
Generation from company owned plant. Owned power generation only.
Transmission. Owned or leased transmission lines.
Buying transmission services on other electrical systems. Types of services include
borderline customers, transmission line rental, transmission capacity, transmission
wheeling, and system operational services.
Distribution using owned/leased electrical wires. Power delivery to your own end-use
customers over distribution facilities.
Buying distribution on other electrical systems. Types of support include customer
billing, distribution system support charges for energy delivered, line maintenance, and/or
equipment charges.
Wholesale power marketing. Wholesale transactions with other electric utilities,
purchases from power producers, and transactions to export and/or import electricity to, or
from, Canada or Mexico. Also includes electrical sales and purchases among Federal
Energy Regulatory Commission registered power marketers and similar participation in
transactions with electric utilities.
Retail power marketing. Provision of electrical energy to end-use customers in areas
where the customer has been given the legal right to select a power supplier other than
the “traditional electric utility.”
Bundled services. Provision of electricity in combination with gas, water, cable, Internet,
and/or telephone for a single price.
5. For line 6, Highest Hourly Electrical Peak System Demand, electric utility companies
should enter the maximum hourly summer load (for months of June through September)
based on net energy for the system during the reporting year. Net energy for the system is
the sum of energy an electric utility needs to satisfy their service area and includes full and
partial wholesale requirements customers, and the losses experienced in delivery. The
maximum hourly load is determined by the interval in which the 60-minute integrated
demand is the greatest. If such data are unavailable, adjust available data to approximate
a 60-minute demand interval and explain the adjustment on Schedule 9, Comments. If
adjustments cannot be made, furnish data as available and explain on Schedule 9,
Comments. For winter enter the maximum hourly winter load (for months of January
through March, and the previous December) based on the net energy for the system during
the reporting year. Please note: These data elements should be provided in megawatts, to
the nearest tenth.
6. For line 7, Alternative Fueled Vehicles, Check Yes to indicate that your company
owns/operates, or plans to own and operate, alternative fueled vehicles; otherwise Check
No. If “Yes,” provide the name, title, FAX number, telephone number and address of a
contact person. Note: For the purpose of this question, an “alternative-fueled vehicle” is
either designed or manufactured by an original equipment manufacturer or is a converted
vehicle designed to operate in either dual-fuel, flexible-fuel, or dedicated modes on fuels
other than gasoline or diesel. This does not include a conventional vehicle that is limited to
operation on blended or reformulated gasoline fuels.

4

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs
SCHEDULE 2. PART B. ENERGY SOURCES AND DISPOSITION
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

1. Enter the annual megawatthours (MWh) for all sources of electricity and disposition of
electricity listed.
2. For line 1, Net Generation, enter the net generation (gross generation minus station use)
from all respondent-owned plants. If a plant is jointly owned, enter only the reporting
party’s share of generation. Include generation used to replace system losses arising from
wheeling transactions. Include net generation supplied as part of a tolling arrangement.
3. For line 2, Purchases from Electricity Suppliers, enter the total amount of energy
purchased from electricity suppliers including: nonutility power producers and power
marketers (reported separately in previous years), municipal departments and power
agencies, cooperatives, investor-owned utilities, political subdivisions, State agencies and
power pools, and marketing agencies of the United States Government and Canada; these
agencies include Bonneville Power Administration (BPA), Southeastern Power
Administration (SEPA), Southwestern Power Administration (SWPA), Western Area Power
Administration (WAPA), Tennessee Valley Authority (TVA), United States Army Corps of
Engineers, the United States Bureau of Reclamation, United States Bureau of Indian
Affairs, International Boundary and Water Commission, Hydro-Quebec, etc. This entry
includes requirements power, firm power and all other nonfirm service. Note: Please
identify on Schedule 9, Comments, the portion of purchased power obtained through
tolling arrangements, and any international purchases.
4. For line 3, Exchanges Received (In), enter the amount of exchange energy received. Do
not include power received through tolling arrangements.
5. For line 4, Exchanges Delivered (Out), enter the amount of exchange energy delivered.
Do not include power delivered as part of a tolling arrangement.
6. For line 5, Exchanges (Net), enter the net amount of energy exchanged. Net exchange is
the difference between the amount of exchange received and the amount of exchange
delivered (lines 3-4). This entry should not include wholesale energy purchased from or
sold to regulated companies or unregulated companies for other systems.
7. For line 6, Wheeled Received (In), enter the total amount of energy entering your system
from other systems for transmission through your system (wheeling) for delivery to other
systems. Do not report as Wheeled Received, energy purchased or exchanged for
consumption within your system, which was wheeled to you by others.
8. For line 7, Wheeled Delivered (Out), enter the total amount of energy leaving your system
that was transmitted through your system for delivery to other systems. If Wheeling
Delivered is not precisely known, please estimate based on your system's known
percentage of losses for wheeling transactions.
9. For line 8, Wheeled (Net), enter the difference between the amount of energy entering your
system for transmission through your system and the amount of energy leaving your
system (line 6 minus line 7). Wheeled net represents the energy losses on your system
associated with the wheeling of energy for other systems.
10. For line 9, Transmission by Others, Losses, enter the amount of energy losses
associated with the wheeling of electricity provided to your system by other utilities.
Transmission by Others Losses should always be expressed as a negative value.
11. For line 11, Sales to Ultimate Customers, enter the amount of electricity sold to
customers purchasing electricity for their own use and not for resale. This entry should
correspond to the revenue from sales to ultimate customers reported on Schedule 3, line
1, and should be equal to the total megawatthours reported on Schedule 4, Parts A, B and
D, when summed for all reported States.
5

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

12. For line 12, Sales for Resale, enter the amount of electricity sold for resale purposes.
This entry should include sales for resale to power marketers (reported separately in
previous years), full and partial requirements customers, firm power customers and
nonfirm customers. This entry should also correspond to the revenue from sales for
resale reported in Schedule 3, line 3. Note: Please identify on Schedule 9, Comments,
the portion of sales for resale power sold through tolling arrangements, and any
international sales.
13. For line 13, Energy Furnished Without Charge, enter the amount of electricity furnished
by the electric utility without charge, such as to a municipality under a franchise agreement
or for public street and highway lighting. This entry does not include data entered in line
14.
14. For line 14, Energy Consumed by Respondent Without Charge, enter the amount of
electricity used by the electric utility in its electric and other departments without charge.
This entry does not include data entered in line 13.
15. For line 15, Total Energy Losses, enter the total amount of electricity lost from
transmission, distribution, and/or unaccounted for. This is the difference between line 10,
"Total Sources," and the sum of lines 11, 12, 13, and 14. Total Energy Losses should
always be expressed as a positive value.

SCHEDULE 2. PART C. GREEN PRICING
Green Pricing programs allow electricity customers the opportunity to purchase electricity
generated from renewable resources and to pay for renewable energy development.
Renewable resources include solar, wind, geothermal, hydroelectric power, and wood.
These programs are voluntary. Retail Customers pay an additional fee to purchase
electricity generated from renewable sources. In addition, Renewable Energy Certificates
(RECs), also known as green certificates, green tags, or tradable renewable certificates
representing the environmental attributes of power produced from renewable energy
projects may be purchased and incorporated into Green Pricing Programs when available
renewable generation is insufficient to cover the requirements of the program for energy
delivered in the reporting year.
Line1: Report the Total Green Pricing Revenue for customers in each customer class.
Revenue should be reported in thousands of dollars to the nearest tenth (for example,
$1,299 would be reported as 1.3 thousand dollars). Revenue should include revenue from
the green pricing program plus the price of the electricity purchased.
Example: For 1000 kWh of electricity sales, if the normal price for electricity is $0.10 per
kWh:
a) An entity sells Green Energy in blocks of $5.50 per 100 kWh block:
Total cost = (1,000kWh x $0.10/kWh) + (($5.50/100kWh block) x (10 blocks of
100 kWh))
= $100.00 + $55.00
= $155.00
b) Alternatively, an Entity which sells Green Energy for a premium of $0.02 per
kWh:
Total cost = (1,000kWh x $0.10/kWh) + (($0.02/kWh) x (1,000kWh))
= $100.00 + $20.00
= $120.00
Line 2: Report the Total Green Pricing Sales, the total amount of megawatthours
purchased by customers for each green pricing customer class (for example, 1,299 kWh
would be reported as 1 MWh).
6

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Line 3: Report the Total Green Pricing Customers, the number of customers who
purchased green power for each customer class. The sales volumes and the number of
customers should not exceed the values reported in Schedule 4, Parts A, B, or D.
Line 4: Report the revenue from RECs for each customer class in thousand of dollars to
the nearest tenth. Enter only the amount associated with RECs as part of a Retail Green
Pricing Program. This revenue must not exceed the Total Green Power Revenue reported
in line 1 above.
Line 5: Report the sales from RECs in megawatthours for each customer class. This
amount should not exceed the Total Green Pricing Sales reported in line 2 above,
The Total for each customer class will automatically sum for the electronic online
e-file system.

SCHEDULE 2. PART D. NET METERING

Net Metering tariff arrangements permit a facility, typically generating electricity from a
renewable resource, (using a meter that reads inflows and outflows of electricity) to sell
any excess power it generates over its load requirement back to the electrical grid,
typically at a rate equivalent to the retail price of electricity.
For net metering applications of 2 MW nameplate capacity or less, report the installed net
metering capacity by State, customer class and technology. Report net metering data by
sector and technology type for each state. Capacity should be reported in MW as AC load
capable. Example: 8 kW should be 0.008 MW. Capacities should not exceed limits set up
by each state. Please provide this capacity in MW, to the nearest 0.001 MW by
technology. Do not report for net metering applications larger than 2 MW.
Report the number of net metering customers by customer class. They should not exceed
the values in Schedule 4 Parts A and C. If you are unable to utilize the e-file system which
creates the totals automatically; then provide the Totals for net metering megawatt hours,
installed net metering capacity and customers by State, customer class and technology.
Complete all lines for Schedule 2, Part D.
If the data is available, enter the amount of electric energy sold back to the utility (MWh)
through the net metering application.

SCHEDULE 3. ELECTRIC OPERATING REVENUE
1. All electric operating revenue data should be rounded to the nearest tenth and reported in
thousand dollars (for example, revenue of $8,461,688.42 should be reported as 8,461.7
(thousand dollars).
2. For line 1, Electric Operating Revenue from Sales to Ultimate Customers, enter the
amount of revenue from sales of electricity to those customers purchasing electricity for
their own use and not for resale. Revenue reported on Schedule 4, Part C, for delivery
service (and all other charges) should not be reported on Schedule 3, line 1, but should
be reported in Schedule 3, line 2, Revenue from Unbundled (Delivery) Customers. This
entry is gross revenue and includes the revenue from State and local income taxes,
energy or demand charges, customer service charges, environmental surcharges,
franchise fees, fuel adjustments and other miscellaneous charges applied to end-use
customers during normal billing operations. This entry should not include deferred
7

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs
charges, credits, or other adjustments, such as fuel or revenue from purchased power,
from previous reporting periods which are included in Schedule 3, line 4, Electric Credits/
Other Adjustments. This entry should correspond to electricity sales reported in
Schedule 2, Part B, line 11. (This entry should also be the same total revenue reported on
Schedule 4, column e, Parts A and B, when summed for all reported States). This entry
should include all unbilled revenue resulting from power sold during the reporting period.
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

3. For line 2, Revenue from Unbundled (Delivery) Customers, enter the amount of
revenue from unbundled customers who purchase their electricity from a supplier other
than the electric utility that distributes power to their premises. This electric operating
revenue does not include the charges for electric energy but does include the revenue
required to cover power delivery.
4. For line 3, Electric Operating Revenue from Sales for Resale, enter the amount of
revenue from sales of electricity sold for resale purposes. This entry should include
revenue from sales for resale to wholesale or retail power marketers, full and partial
requirements customers (firm) and to nonrequirements (nonfirm) customers. This entry
should also correspond to the sales for resale reported in Schedule 2, Part B, line 12.
5. For line 4, Electric Credits/Other Adjustments, enter the amount of deferred revenue,
which corresponds to Account 449.1 of the Uniform System of Accounts including revenue
not applied to end-use or resale customers during the normal billing cycle. Funds included
in this entry consist of refunds to customers resulting from rate commission rulings
delayed beyond the reporting year in which the funds were originally collected. Also,
include revenue distributions to customers from rate stabilization funds where the
distribution occurred during the current reporting year but the funds were collected during
previous reporting years.
6. For line 5, Revenue from Transmission, enter the amount of revenue derived from the
transmission of electricity for others (wheeling).
7. For line 6, Other Electric Operating Revenue, enter the amount of revenue received
from electric activities other than selling electricity. This may include revenue from selling
or servicing electric appliances, revenue from the sale of water and water power for
irrigation, domestic, industrial or hydroelectric operations, revenue from electric plants
leased to others, revenue from the sale of steam, but not including sales made by a steam
heating department or transfers of steam under joint facility operations, revenue from
interdepartmental rents or sale of electric property, revenue from late fees, penalties or
reconnections, and revenue from interest.

SCHEDULE 4. PART A. SALES TO ULTIMATE CUSTOMERS.
FULL SERVICE – ENERGY AND DELIVERY SERVICE (BUNDLED)
Please note that data for the Transportation Sector (see definitions) has replaced the
“Other” Sector on all parts of Schedule 4. Non-Transportation customers previously
reported under “Other,” including street and highway lighting, should now be
included in the Commercial Sector. Irrigation customers should be reported in the
Industrial Sector.
Enter the reporting year revenue (thousand dollars, to the nearest tenth), megawatthours,
and number of customers for sales of electricity to ultimate customers by State and customer
class category for whom your company provides both energy and delivery service. Power
marketers providing both energy and delivery service should report on Part D. Note: For
sales to customer groups using brokers or aggregators, continue to count each customer
separately. For instance, count a group of franchised commercial establishments aggregated
through a single broker as separate customers (as reported in prior years). Enter the 2-letter
U.S. Postal Service abbreviation for the State in which the electric sales occurred.
8

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

SCHEDULE 4. PART B. SALES TO ULTIMATE CUSTOMERS.
ENERGY – ONLY SERVICE (WITHOUT DELIVERY SERVICE)
Enter the reporting year revenue (thousand dollars, to the nearest tenth), megawatthours,
and number of customers for sales of electricity to ultimate customers by State and customer
class category for whom your company provides only the energy consumed, where another
electric utility provides delivery services, including, for example, billing, administrative
support, and line maintenance.

SCHEDULE 4. PART C. SALES TO ULTIMATE CUSTOMERS.
DELIVERY – ONLY SERVICE (AND ALL OTHER CHARGES)
Enter the reporting year revenue (thousand dollars, to the nearest tenth), megawatthours
delivered, and number of customers for sales of electricity to ultimate customers in your
service territory by State and customer class category for whom your company provides only
billing and related energy delivery services, where another company supplies the energy.

SCHEDULE 4. PART D. SALES TO ULTIMATE CUSTOMERS. BUNDLED SERVICE BY
RETAIL ENERGY PROVIDERS, OR ANY POWER MARKETER THAT PROVIDES
“BUNDLED SERVICE”

Note: typically, the only entities that report on Schedule D are Texas Retail Energy
Providers. Any other entity that believes it should report on Schedule D should first contact
EIA.
Enter the reporting period revenue (thousand dollars, to the nearest tenth), megawatthours,
and number of customers for sales of electricity to ultimate customers by State and customer
class category for whom your company provided both energy and delivery service. For public
street and highway lighting, count all poles in a community as one customer. Note: For sales
to customer groups using brokers or aggregators, continue to count each customer
separately. For instance, count a group of franchised commercial establishments aggregated
through a single broker as separate customers (as reported in prior years). Enter the twoletter U.S. Postal Service abbreviation (if not preprinted) for the State in which the electric
sales occur. (Note: Texas Retail Energy Providers (REPs) should include delivery revenues.)
Common Instructions: SCHEDULE 4. PARTS A, B, C, AND D
1. For column a, Residential, enter the revenue, megawatthours, and number of customers
for electric energy supplied for residential (household) purposes. For the residential class,
do not duplicate the customer accounts due to multiple metering for special services
(e.g., water heating, etc.).
2. For column b, Commercial, enter the revenue, megawatthours, and number of
customers for electric energy supplied for commercial purposes.
3. For column c, Industrial, enter the revenue, megawatthours, and number of customers
for electric energy supplied for industrial purposes.
9

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

4. For column d, Transportation, enter the revenue, megawatthours, and number of
customers for electric energy supplied for transportation purposes.
SCHEDULE 5. MERGERS AND/OR ACQUISITIONS
If a merger or acquisition has occurred during the reporting period, report those newlyacquired corporate entities whose operations are now included in this report.

SCHEDULE 6. DEMAND-SIDE MANAGEMENT INFORMATION
Demand-side management (DSM) programs are designed to modify patterns of electricity
usage, including the timing and level of electricity demand. SCHEDULE 6 is divided into four
parts: Part A, Actual Effects, Part B, Annual Costs, Part C, Supplemental Information
and Part D, Advanced Metering. SCHEDULE 6 is to be completed by DSM program
managers (entities responsible for conducting or administering a DSM program). In previous
years, companies with sales to ultimate customers or sales for resale which were less than
150,000 megawatthours were required to complete only the INCREMENTAL EFFECTS
portion of Part A and annual cost to achieve in Part B, line 13, Total Cost. For this
reporting year and forward, all companies including those non-utility DSM Program
Managers are required to complete the entire schedule.
The DSM information provided should: 1) reflect only activities that are undertaken
specifically in response to company-administered programs, including activities implemented
by third parties under contract to the company; 2) account for the complete range of DSM
programs, including energy efficiency and load management; and 3) represent the energy
and load effects at the customer meter (i.e., transmission and distribution or reserve
requirement savings should be excluded). The DSM information should exclude, to the
extent possible, energy and load effects that are not attributable to DSM program activities.
Non-program related effects include changes in energy and load attributable to: 1) nonparticipants (e.g., customers known as free-riders, who would adopt program-recommended
actions even without the program); 2) government-mandated energy-efficiency standards
that legislate improvements in building and appliance energy usage; 3) natural operations of
the marketplace (e.g., reductions in customer energy usage due to higher prices); and 4)
weather and business-cycle fluctuations.
Power supply cooperatives, municipal joint action agencies, and Federal Power Marketing
Administrations should coordinate the reporting of DSM information with their power
purchasing utilities to avoid double counting the effects and costs of DSM programs. Utilities
that have their DSM activities reported on Schedule 6 of another company should name that
company in the space provided on line 2 of the schedule and proceed to Schedule 6, Part D.

SCHEDULE 6. PART A. ACTUAL EFFECTS
This part of the Schedule collects information on the energy and load effects of DSM programs
implemented, and measures installed, for each program category by major customer sector
within a State. It is divided into two subparts, Incremental Effects and Annual Effects.
1. Incremental Effects: The changes in energy use (measured in megawatthours) and peak
load (measured in megawatts) caused in the current reporting year by new participants in
existing DSM programs and all participants in your new DSM programs (that is programs
begun during the current reporting year). Reported Incremental Effects should be
annualized.

10

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Please leave blanks, not zeros, if the questions do not apply. For example, your company
operates industrial programs but does not expect any incremental effects in the current
reporting year, the field would have a value of zero. However, if your company does not
operate any industrial programs, then the field should be left blank.
2. Annual Effects: The total changes in energy use (measured in megawatthours) and peak
load (measured in megawatts) caused in the current reporting year by all participants in all
of your DSM programs. This includes new and existing participants in existing programs
(those implemented prior to the current reporting year that were in place during prior
reporting year), all participants in new programs (those implemented during current
reporting year), and participants in programs terminated since 1992 (those effects continue
even though the programs have been discontinued). DSM programs have a useful life, and
the net effects of these programs will diminish over time. To the extent possible, the
Annual Effects should consider the useful life of efficiency and load control measures by
accounting for building demolition, equipment degradation, and program attrition. The
effects of new participants in existing programs and all participants in new programs should
be based on their start-up dates (i.e., if participants enter a program in July, only the effects
from July to December are to be reported). If start-up dates are unknown and cannot be
reasonably estimated, the effects can be annualized (i.e., assume the participants were
initiated into the program on January 1). Please note that Annual Effects are not a
summation of 12 monthly peaks, but are the total DSM program effects of all
programs and all participants for the current reporting year.
3. For Part A, under the appropriate customer sector: Residential, Commercial, Industrial, and
Transportation, enter the aggregate Energy Effects (megawatthours, to one decimal point,
if possible) and Actual Peak Reduction (megawatts to one decimal point, if possible)
attributable to Energy Efficiency and Load Management programs. For Load Management
also enter the Potential Peak Reduction (megawatts to one decimal point, if possible)
attributable to each customer sector. Please leave blanks, not zeros, if the questions do
not apply. For example, your company operates industrial programs but does not expect
any incremental effects in the current reporting year, the field would have a value of zero.
However, if your company does not operate any industrial programs, then the field should
be left blank.
SCHEDULE 6. PART B. ANNUAL COSTS
This part of the schedule collects information on actual DSM program costs in the current
reporting year. Program costs consist of the cash expenditures, reported in thousands of
dollars, incurred by the company. Costs should reflect the total cash expenditures for the
year, reported in thousands of dollars that flow out to support DSM programs. They should
be reported in the year they are incurred, regardless of when the actual effects occurred. For
example, the cash expenditures to purchase 1,000 load control devices for installation in
customers' homes could be incurred a year in advance of the actual load savings that result
from operation of the devices.

Annual Costs: For each State enter for each sector your actual Direct Costs, Incentive
Payments, and Indirect Costs, incurred in the current reporting year.
Direct Costs are those costs that are directly attributable to a particular DSM program (e.g.,
Energy Efficiency or Load Management).
Incentives are the total financial value provided to a customer for program participation,
whether cash payment, in-kind services (e.g. design work), or other benefits directly provided
customer for their program participation.
Indirect Costs may include other costs that have not been included in any program category,
but could be meaningfully identified with operating the company’s DSM programs (e.g.,
Administrative, Marketing, Monitoring & Evaluation, Company-Earned Incentives, Other).
11

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Report Energy Efficiency and Load Management Costs separately. The Total Cost row,
line 13 and the Total column (e) will be summed automatically for respondents that file
electronically through the e-file system. Provide the actual costs breakdown in thousand
dollars.

SCHEDULE 6. PART C. SUPPLEMENTAL INFORMATION
1. Please indicate, by checking “Yes” or “No” on line 14, whether DSM program changes,
tracking procedures, evaluations, or reporting methods have affected the data reported on
this schedule (since 1992).
2. Please indicate, by checking “Yes” or “No” on line 15, whether your company currently
operates any incentive-based demand response programs, i.e., direct load control,
interruptible programs, demand bidding/buyback, emergency demand response, capacity
market programs, and ancillary service market programs. If the answer is “Yes,” enter the
number of participating customers, by state and class, on line 16.
3. Please indicate, by checking “Yes” or “No” on line 17, whether your company currently
operates any time-based rate programs, e.g., real-time pricing, critical peak pricing, variable
peak pricing and time-of-use rates administered through a tariff. If the answer is “Yes,”
enter the number of participating customers, by state and class, on line 18.

SCHEDULE 6. PART D. ADVANCED METERING

This schedule should only include customers from Schedule 4 Part A or Part C.
Standard (Electric) Meters are electromechanical or solid state meters measuring
aggregated kWh where data are manually retrieved over monthly billing cycles for billing
purposes only. Standard meters may also include functions to measure time-of-use and/or
demand with data manually retrieved over monthly billing cycles.
Automated Meter Reading (AMR): Meters that collect data for billing purposes only and
transmit this data one way, usually from the customer to the distribution utility. Aggregated
monthly kWh data captured on these meters may be retrieved by a variety of methods
including drive-by vans with short-distance remote reading capabilities and communication
over a fixed network such as a cellular network.
Enter the state and report the total number of AMR meters by sector. The number of AMR
meters may be equal to but not exceed the number of customers on Schedule 4.
Advanced Metering Infrastructure (AMI): Meters that measure and record usage data at a
minimum, in hourly intervals, and provide usage data to both consumers and energy
companies at least once daily. Data are used for billing and other purposes. Advanced
meters include basic hourly interval meters and extend to real-time meters with built-in twoway communication capable of recording and transmitting instantaneous data.
Enter the state and report the total number of AMI meters by sector.
For AMI meters that are only being used as AMR, report meters as AMR.
Energy Served Through AMI (MWh) should be entered in megawatthours for customers
served.
SCHEDULE 7. DISTRIBUTED AND DISPERSED GENERATION
This schedule collects information from distribution companies on industrial and commercial
12

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs
generators of less than 1 megawatt (1000 kilowatts) installed at or near a customer’s site, or
other sites within the system. Provide all of the requested information for grid
connected/synchronized distributed generators in column a, and for dispersed generators that
are not grid connected/synchronized in column b. Also provide the data on all industrial and
commercial dispersed generators in the Total column. Provide actual data if available,
otherwise provide best estimates, and indicate the nature of the data by checking the
appropriate box on the form.
ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Schedule 7 is intended to collect information about generators on the systems that are
NOT reported on Form EIA-860, “Annual Electric Generator Report.” Plants with capacity
of 1 MW or greater which ARE grid-connected, meet the threshold criteria for reporting on the
860 and as such, need not be reported on Schedule 7 of the EIA-861. Residential applications
should not be reported.
SCHEDULE 7. PART A. NUMBER AND CAPACITY
1. For line 1, Number of generators, provide in column (a), the number of distributed generators
in the area served by your distribution system. (Less than 1 megawatt) In column (b),
provide the number of dispersed generators. (Total and less than 1 megawatt) If you are
unable to provide the breakout, please explain in Schedule 9, Comments. The total number
of dispersed generators must be greater than or equal to the number of dispersed
generators less than 1 MW.
2. For line 2, Total combined capacity, columns (a) and (b), provide the nameplate capacity (to
the nearest tenth) for all generators with less than 1 megawatt that reported on line 1.
For column (b), also provide the sum of the capacity for all generators. The total capacity
must be greater than or equal to the capacity less than 1 MW.
3. For line 3, columns (a) and (b), capacity that consists of backup-only units, provide the total
nameplate capacity of generators that are used only for emergency backup service.
4. For Line 4, columns (a) and (b), capacity owned by respondent, provide the total nameplate
capacity listed in line 2 that the respondent owns.
5. For Line 5, columns (a) and (b), Nature of data reported, provide actual data if available,
otherwise provide best estimates, and indicate the nature of the data by checking the
appropriate box on the form.
6. For Line 6, columns (a) and (b), State, provide the 2-letter U.S. Postal Service abbreviation
for the State in which the generators are located.
SCHEDULE 7. PART B, CAPACITY BY GENERATING TYPE AND TECHNOLOGY
For each of the technologies listed in columns (a) and (b), lines 1 through 8, provide the
capacity. The total of lines 1 through 8 (line 9) should equal the total combined capacity in line
2 in each column, (a, < 1MW) and (b - Total).
SCHEDULE 8. DISTRIBUTION SYSTEM INFORMATION
Please verify the EIA provided names of the counties, parishes, etc. (dropdown menu), by
State, where your utility-owned distribution system’s electrical equipment are located. The
information may have been reported by the respondent last year or the result of independent
research by the EIA staff processing the Form EIA-861. If the information is incorrect, please
provide the correct information in Schedule 9.
SCHEDULE 9. COMMENTS
This schedule provides additional space for comments. For clarification purposes, identify
schedule, part, line number and column (if applicable) for each comment.
13

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT
INSTRUCTIONS

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

GLOSSARY

The glossary for this form is available online at the following URL:
http://www.eia.gov/glossary/index.html

SANCTIONS

The timely submission of Form EIA-861 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 9.0 hours per
response, 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 U.S. Energy
Information Administration, Statistics and Methods Group, EI-70, 1000 Independence Avenue
S.W., Forrestal Building, Washington, D.C. 20585-0670; and to the Office of Information and
Regulatory Affairs, Office of Management and Budget, Washington, D.C. 20503. A person is
not required to respond to the collection of information unless the form displays a valid OMB
number.
Information reported on Form EIA-861 will be treated as non-sensitive and may be publicly
released in identifiable form. In addition to the use of the information by EIA for statistical
purposes, the information may be used for any nonstatistical purposes such as administrative,
regulatory, law enforcement, or adjudicatory purposes.

PROVISIONS
REGARDING
CONFIDENTIALITY
OF INFORMATION

14

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

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 provisions on sanctions and the provisions concerning the confidentiality
of information in the instructions. 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.

SCHEDULE 1. IDENTIFICATION
Survey Contact
First Name:________________
Last Name:_________________
Title:______________________________
Telephone (include extension):______________
Fax:__________________
Email:_______________________________
Supervisor of Contact Person for Survey
First Name:____________________
Last Name:_____________________
Title:___________________________
Telephone (include extension):______________
Fax:__________________
Email:________________________________
Report For
Entity Name: _____________________________________________
Entity ID:_________________

Reporting Year:________________
Entity and Preparer Information

Legal Name of Entity:

_________________________________________________

Current Address of Entity’s Principal
Business Office:

_________________________________________________

Preparer's Legal Name (If Different
From Entity’s Legal Name):

_________________________________________________

Current Address of Preparer's Office
(If Different From Current Address of
_________________________________________________
Entity’s Principal Business Office):
[ ] Federal
[ ] State
Respondent
Type
[ ] Political Subdivision
[ ] Municipal
(check one)
[ ] Municipal Marketing Authority
[ ] Investor-Owned
[ ] Cooperative
[ ] Retail Power Marketer (or Energy
Service Provider)
[ ] Independent Power Producer or
Qualifying Facility
[ ] Wholesale Power Marketer
[ ] Transmission
For questions or additional information about the Form EIA-861 contact the Survey Managers:
Karen McDaniel
Phone: (202) 586-4280
Email: [email protected]
FAX Number: (202) 287-1938
Email: [email protected]
15

Stephen Scott
Phone: (202) 586-5140
Email: [email protected]

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 2, PART A. GENERAL INFORMATION
LINE
NO.
1

1a

Regional North American Electric
Reliability Corporation Region
(not applicable for power marketers) (mark
all that apply)

Name of RTO or ISO

2

(For EIA Use Only) Identify the North
American Electric Reliability Corporation
where you are physically located

3

Enter Balancing Authority(s) Responsible
for Your Oversight

4

Did Your Company Operate Generating
Plant(s)? (check one)

5

6

7

Identify the Activities Your Company Was
Engaged in During the Year (check
appropriate activities)

Highest Hourly Electrical Peak System
Demand
Did Your Company Operate AlternativeFueled Vehicles During the Year?
Does Your Company Plan to Operate Such
Vehicles During the Coming Year?

[

] TRE (ERCOT)

[

] NPCC

[

] SPP

[

] FRCC

[

] RFC

[

] WECC

[

] MRO

[

] SERC

[ ] California ISO

[ ] New York ISO

[ ] ISO New England

[ ] Electric Reliability Council of Texas

[ ] Southwest Power Pool

[ ] Other

[ ] PJM Interconnection

[ ] Midwest ISO

[

] Yes

[

] No

[

] Generation from company owned plant

[
[

] Transmission
] Buying transmission services on other
electrical systems

[

] Distribution using owned/leased
electrical wires

[
[

] Buying distribution on other electrical
systems
] Wholesale power marketing

[

] Retail power marketing

[

] Combined Utility Services (electricity plus
other services such as gas, water, etc.
in addition to electric service)

Summer (MW)
Winter (MW)
[

] Yes

[

] No

[

] Yes

[

] No

Name:
If "Yes", Please Provide Additional
Contact Information.

Title:
Telephone: (

)

Fax: (

16

)

Email address:

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 2. PART B. ENERGY SOURCES AND DISPOSITION
LINE
NO.
1
2
3
4
5
6
7
8
9
10

SOURCE OF ELECTRICITY
(MWh)

LINE
NO.

Net Generation
Purchases from Electricity Suppliers
Exchanges Received (In)
Exchanges Delivered (Out)
Exchanges (Net)
Wheeled Received (In)
Wheeled Delivered (Out)
Wheeled (Net)
Transmission by Others, Losses (negative
number)
Total Sources (sum of lines 1, 2, 5, 8, and 9)

11
12
13
14
15

16

DISPOSITION OF ELECTRICITY
(MWh)
Sales to Ultimate Customers
Sales for Resale
Energy Furnished Without Charge
Energy Consumed By Respondent Without Charge
Total Energy Losses (positive number)

Total Disposition (sum of lines 11, 12, 13, 14, and, 15)

SCHEDULE 2, PART C. GREEN PRICING
Green Pricing programs are voluntary programs where customers pay an extra fee to purchase electricity generated from renewable sources. Renewable Energy Certificates
(RECs) are a category of Green Pricing that involves the sale of the renewable attribute created with renewable electricity generation.

LINE
NO.

STATE/TERRITORY:

1

Total Green Pricing Revenue
(Thousand Dollars)

2

Total Green Pricing Sales (MWh)

3

Total Green Pricing Customers

4

Revenue from RECs
(Thousand Dollars)

5

REC Sales
(MWhs)

RESIDENTIAL
(a)

COMMERCIAL
(b)

17

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 2, PART D. NET METERING
Net Metering programs allow customers to sell excess power they generate back to the electrical grid to offset consumption. For net metering applications of 2 MW
nameplate capacity and less, provide the information about programs by State and customer class.

STATE/TERRITORY:

RESIDENTIAL
(a)

If Available, Enter the Electric Energy Sold Back
to the Utility (MWh)
Photovoltaic

Installed Net Metering Capacity (MW)
Number of Net Metering Customers

If Available, Enter the Electric Energy Sold Back
to the Utility (MWh)
Wind

Installed Net Metering Capacity (MW)
Number of Net Metering Customers

If Available, Enter the Electric Energy Sold Back
to the Utility (MWh)
CHP/Cogen

Installed Net Metering Capacity (MW)
Number of Net Metering Customers

If Available, Enter the Electric Energy Sold Back
to the Utility (MWh)
Other

Installed Net Metering Capacity (MW)
Number of Net Metering Customers
Total Energy Sold Back to the Utility (MWh)

Total

Installed Net Metering Capacity (MW)
Number of Net Metering Customers

18

COMMERCIAL
(b)

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 3. ELECTRIC OPERATING REVENUE
LINE
NO.

TYPE OF OPERATING REVENUE

1

Electric Operating Revenue From Sales to Ultimate Customers
(Schedule 4, Parts A and B)

2

Revenue From Unbundled (Delivery) Customers (Schedule 4, Part C)

3

REVENUE (THOUSAND DOLLARS)

Electric Operating Revenue from Sales for Resale

4

Electric Credits/Other Adjustments

5

Revenue from Transmission

6

Other Electric Operating Revenue

7

Total Electric Operating Revenue (sum of lines 1, 2, 3, 4, 5 and 6)

19

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 4. PART A. SALES TO ULTIMATE CUSTOMERS. FULL SERVICE – ENERGY AND DELIVERY SERVICE (BUNDLED)
RESIDENTIAL
(a)

COMMERCIAL
(b)

STATE /
TERRITORY
Revenue (thousand dollars)
Megawatthours Sold and
Delivered
Number of Customers
STATE /
TERRITORY
Revenue (thousand dollars)
Megawatthours Sold and
Delivered
Number of Customers
STATE /
TERRITORY
Revenue (thousand dollars)
Megawatthours Sold and
Delivered
Number of Customers
STATE /
TERRITORY
Revenue (thousand dollars)
Megawatthours Sold and
Delivered
Number of Customers

20

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 4. PART B. SALES TO ULTIMATE CUSTOMERS. ENERGY – ONLY SERVICE (WITHOUT DELIVERY SERVICE)
RESIDENTIAL
(a)

COMMERCIAL
(b)

STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Sold
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Sold
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Sold
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Sold
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Sold
Number of Customers

21

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 4. PART C. SALES TO ULTIMATE CUSTOMERS. DELIVERY – ONLY SERVICE (AND ALL OTHER CHARGES)
RESIDENTIAL
(a)

COMMERCIAL
(b)

STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Delivered
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Delivered
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Delivered
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Delivered
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Delivered
Number of Customers

22

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 4. PART D. BUNDLED SERVICE BY RETAIL ENERGY PROVIDERS, OR ANY POWER MARKETER THAT PROVIDES
“BUNDLED SERVICE”
RESIDENTIAL
(a)

COMMERCIAL
(b)

INDUSTRIAL
(c)

STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Sold and
Delivered
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Sold and
Delivered
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Sold and
Delivered
Number of Customers
STATE/TERRITORY
Revenue (thousand dollars)
Megawatthours Sold and
Delivered
Number of Customers

23

TRANSPORTATION
(d)

TOTAL
(e)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 5. MERGERS AND/OR ACQUISITIONS
Mergers and/or acquisitions during the reporting period:
If Yes, Provide:
Date of merger or acquisition ___________________________________
Company merged with or acquired ______________________________
Name of new parent company __________________________________

Yes
No (If no, skip to Schedule 6)
Address_______________________________________________________
New contact name _____________________ Telephone No. ___________
Email address _________________________________________________

24

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 6. DEMAND-SIDE MANAGEMENT INFORMATION
LINE
NO.

1

Do you have company administered Demand-Side Management Programs? (check Yes or No)

2

If your Demand-Side Management activities are reported on Schedule 6 of another company’s
form, identify the company.

[

] Yes

[

] No

NOTE: If you answered "No," to Line 1 or another Company Reports your Demand-Side Management Activities on their Schedule 6, proceed to
Schedule 6, Part D.

SCHEDULE 6. PART A. ACTUAL EFFECTS
ANNUALIZED INCREMENTAL EFFECTS

3
4

5
6
7
7b
7c

ACTUAL ANNUAL EFFECTS

RESIDENTIAL

COMMERCIAL

INDUSTRIAL

TRANSPORTATION

Total

RESIDENTIAL

COMMERCIAL

INDUSTRIAL

TRANSPORTATION

Total

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

STATE /
TERRITORY
ENERGY
EFFICIENCY
Energy Effects
(MWh)
Actual Peak
Reduction (MW)
LOAD
MANAGEMENT
Energy Effects
(MWh)
Potential Peak
Reduction (MW)
Actual Peak
Reduction (MW)
[ ] Yes
[ ] No
Were these savings verified through an independent evaluation?
Are these savings estimates based on a forecast or on the report of one or more Independent evaluators?

25

[

] Yes

[

] No

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER
INDUSTRY REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 6. PART B. ANNUAL COSTS (THOUSAND DOLLARS)
RESIDENTIAL
(a)

COMMERCIAL
(b)

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

STATE /
TERRITORY
Direct Costs, excluding incentive
payments - Energy Efficiency
8
9

Direct Costs, excluding incentive
payments - Load Management

11
12

Incentive Payments – Energy
Efficiency
Incentive Payments – Load
Management
Indirect Costs

13

Total Cost (sum of all of the above)

10

SCHEDULE 6. PART C. SUPPLEMENTAL INFORMATION
[ ] Yes

14

Have there been any major changes to your Demand-Side Management programs (e.g., terminated programs, new information or financing
programs, or a shift to programs with dual load building objectives and energy efficiency objectives), program tracking procedures, or
reporting methods that affect the comparison of demand-side management data reported on this schedule to data from previous years?
(check Yes or No)

[
] No

[ ] Yes

15

Does your company currently operate any incentive-based demand response programs (e.g., market incentives, financial incentives, direct
load control, interruptible programs, demand bidding/buyback, emergency demand response, capacity market programs, and ancillary
service market programs)? (check Yes or No)

16

If the answer to line 15 is “Yes”, please disclose the number of
participating customers by state & class.

17
18

Residential

Commercial

Industrial

] No

Transportation

State:

Does your company currently operate any time-based rate programs (e.g., real-time pricing, critical peak pricing, variable peak pricing and
time-of-use rates administered through a tariff)? (check Yes or No)
If the answer to line 17 is “Yes”, please disclose the number of
participating customers by state & class.

[

Residential
State:

26

Commercial

Industrial

[ ] Yes
] No
Transportation

[

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 6. PART D. ADVANCED METERING
Only customers from Schedule 4A and 4C need to be reported on this schedule. AMR – data transmitted one-way, from the customer to the utility.
AMI – data can be transmitted in both directions, between the delivery entity and the customer.
State/ Territory
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
TRANSPORTATION
TOTAL
(a)
(b)
(c)
(d)
(e)
Number of AMR Meters
Number of AMI Meters
Energy Served Through AMI Meters (MWh)
State/ Territory

RESIDENTIAL
(a)

COMMERCIAL
(b)

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

RESIDENTIAL
(a)

COMMERCIAL
(b)

INDUSTRIAL
(c)

TRANSPORTATION
(d)

TOTAL
(e)

Number of AMR Meters
Number of AMI Meters
Energy Served Through AMI Meters (MWh)
State/ Territory
Number of AMR Meters
Number of AMI Meters
Energy Served Through AMI Meters (MWh)

27

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 7. DISTRIBUTED AND DISPERSED GENERATION
If your company owns and/or operates a distribution system, please report information on known distributed generation capacity on the system. Such
capacity may be utility or customer-owned.

SCHEDULE 7. PART A. NUMBER AND CAPACITY

1

DISTRIBUTED GENERATORS
(COMMERCIAL AND INDUSTRIAL GRID
CONNECTED/SYNCHRONIZED GENERATORS)
(a)
Total
(<1MW)
Number of generators (N)

2
3

LINE
NO.

DISPERSED GENERATORS
(COMMERCIAL AND INDUSTRIAL GENERATORS NOT
CONNECTED/SYNCHRONIZED TO THE GRID)
(b)

LINE
NO.

Total (<1MW)
1

Number of generators (N)

Total combined capacity (MW)

2

Capacity that consists of backup-only units

3

Total combined capacity (MW)
Capacity that consists of backup-only units

4

Capacity owned by respondent

4

Capacity owned by respondent

5

Nature of data reported

5

Nature of data reported

6

State/Territory

6

State/Territory

Actual
Estimated

[ ]
[ ]

Actual
Estimated

[ ]
[ ]

SCHEDULE 7. PART B. CAPACITY by TECHNOLOGY (MW)
Total
(<1MW)

Total (<1MW)

1

Internal combustion/reciprocating engines

1

Internal combustion/reciprocating engines

2

Combustion turbine(s)

2

Combustion turbine(s)

3

Steam turbine(s)

3

Steam turbine(s)

4

Hydroelectric

4

Hydroelectric

5

Wind turbine(s)

5

Wind turbine(s)

6

Photovoltaic

6

Photovoltaic

7

Storage

7

Storage

8

Other

8

Other

9

Total

9

Total

10

Nature of data reported

10

Nature of data reported

Actual
Estimated

[ ]
[ ]

28

Actual
Estimated

[ ]
[ ]

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 8. DISTRIBUTION SYSTEM INFORMATION
If your company owns a distribution system, please identify the names of the counties (parish, etc.) by State in which the electric wire/equipment are
located.
LINE
NO.

STATE/TERRITORY
(U.S. POSTAL
ABBREVIATION)
(a)

COUNTY
(PARISH, ETC.)
(b)

LINE
NO.

1

20

2

21

3

22

4

23

5

24

6

25

7

26

8

27

9

28

10

29

11

30

12

31

13

32

14

33

15

34

16

35

17

36

18

37

19

38
29

STATE/TERRITORY
(U.S. POSTAL
ABBREVIATION)
(a)

COUNTY
(PARISH, ETC.)
(b)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-861 (2011)

ANNUAL ELECTRIC POWER INDUSTRY
REPORT

Form Approved
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 9.0 hrs

Entity Name:_________________________________________
Entity ID:_______

Reporting Year:________________

SCHEDULE 9. COMMENTS
SCHEDULE
(a)

PART LINE NO. COLUMN
(b)
(c)
(d)

NOTE(S)
(e)

30

Subject: United States Department of Energy – EIA Annual Data Collection, Form EIA-923 (Annual)

Dear Respondent:

The Annual Form EIA-923, "Power Plant Operations Report," is now open for 2009 data collection. Your filing is due by
April 5, 2010. The Form EIA-923 can be accessed through EIA's Single Sign On (SSO) website at:
https://signon.eia.doe.gov/ssoserver/login
Choose "EIA-923 Power Plant Operations Report - Annual" on the SSO screen.
Please verify the accuracy of the information we have on file for you.
Primary contact name:
Email:
SSO User ID:
Telephone:
Please send us a return email at [email protected] to acknowledge receipt of this email and, if needed, to update the
information in our records.
Our records show you are the primary contact to file the report for the plants listed below. Contact EIA immediately if this
list is not complete and accurate.
For questions about the Form EIA-923, instructions, a copy of the form, and a list of contact people, please see:
http://www.eia.doe.gov/cneaf/electricity/2008forms/consolidate_923.html

Sincerely,
Channele Wirman
Project Manager, EIA-923
Energy Information Administration
United States Department of Energy

List of Plants:
---------------

8

Subject: United States Department of Energy – EIA Monthly Data Collection, Form EIA-923 (Monthly)

Dear Respondent:

The monthly Form EIA-923, "Power Plant Operations Report," is now open for January 2010 data collection. Your filing of
the Form EIA-923 for January 2010 is due by March 1, 2010.
Please note the data entry process for coal mine information on Schedule 2 Page 3 has been changed. For all coal purchases,
a State or country of origin must be chosen first, and then a choice must be made for a mine by double clicking on the MSHA
ID field. With your choice of mine, all fields will automatically be populated with the MSHA ID, Mine Name, Mine County
and Mine Type.
The report can be accessed through EIA's Single Sign On website at:
https://signon.eia.doe.gov/ssoserver/login
For questions about using or accessing the Single Sign On system, please contact our Help Center at 202-586-9595 or
[email protected]. For questions about the Form EIA-923 and a list of contact people, please see:
http://www.eia.doe.gov/cneaf/electricity/2008forms/consolidate_923.html

Sincerely,

Channele Wirman
Project Manager, EIA-923
Energy Information Administration
United States Department of Energy

9

Subject: United States Department of Energy – EIA Annual Data Collection, Form EIA-923 (Supplemental)

Dear Respondent:

The Supplemental Form EIA-923, "Power Plant Operations Report," is now open for 2009 data collection. The Supplemental
Form EIA-923 is required for plants that reported Schedules 2 through 5 on the Monthly Form EIA-923 in 2009. The
Supplemental form is comprised of the annual Schedules 6, 7 and 8, and completes the filing requirements for the 2009 data
year for your power plant.
Your filing is due by April 5, 2010. The Form EIA-923 can be accessed through EIA's Single Sign-On website at:
https://signon.eia.doe.gov/ssoserver/login
Choose "EIA-923 Power Plant Operations Report - Supplementary" on the SSO screen.
Please verify the accuracy of the information we have on file for you:
Primary contact name:
Email:
SSO User ID:
Telephone:
Please send us a return email at [email protected] to acknowledge receipt of this email and, if needed, to update the
information in our records.
Our records show you are the primary contact to file the report for the plants listed below. Contact EIA immediately if this
list is not complete and accurate.
For questions about the Form EIA-923, instructions, a copy of the form, and a list of contact people, please see:
http://www.eia.doe.gov/cneaf/electricity/2008forms/consolidate_923.html

Sincerely,
Channele Wirman
Project Manager, EIA-923
Energy Information Administration
United States Department of Energy

List of Plants:
---------------

10

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

PURPOSE

Form EIA-923 collects information from electric power plants and combined heat and power (CHP) plants
in the United States (see Required Respondents immediately below). Data collected on this form include
electric power generation, fuel consumption, fossil fuel stocks, delivered fossil fuel cost, combustion
byproducts, operational cooling water data, and operational data for NOx, SO2, and particulate matter
control equipment. These data are used to monitor the status and trends of the electric power industry and
appear in many U.S. Energy Information Administration (EIA) publications including: Electric Power
Monthly, Electric Power Annual, Monthly Energy Review, Annual Energy Review, Natural Gas Monthly,
Natural Gas Annual, Cost and Quality of Fuels, Quarterly Coal Report, and the Renewable Energy Annual.
Further information can be found at http://www.eia.gov/fuelelectric.html. The “Stocks at End of Reporting
Period” information (SCHEDULE 4), Nonutility “Total Delivered Cost” information (SCHEDULE 2), and
“Commodity Cost” information (SCHEDULE 2) reported on this form are protected information.

REQUIRED
RESPONDENTS

The Form EIA-923 is a mandatory report for all electric power plants and CHP plants that meet the
following criteria: 1) have a total generator nameplate capacity (sum for generators at a single site) of 1
megawatt (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. To lessen the reporting burden, a sample of plants is collected on a monthly
basis. Plants that are not selected to respond monthly must respond annually for the calendar year.
Facilities that do not generate electricity but serve either as a transfer terminal or offsite storage facility for
fossil fuel stocks for generating stations may be required to report on the Form EIA-923.
See instructions for each schedule for more specific filing requirements.

RESPONSE DUE
DATE

Monthly respondents are required to file SCHEDULE 1 through SCHEDULE 5 and SCHEDULE 9 of this form
with EIA by the last day of the month following the reporting period. For example, if reporting for July, survey
data are due on August 31.
Supplemental responses (monthly respondent’s filings of Schedule 6 through Schedule 8) must be filed no
later than 45 days after the form opens for data entry – typically around March 31 following the end of the
reporting year.
Annual respondents are required to file the form approximately 45 calendar days after the form opens for data
entry – typically around March 31 following the end of the reporting year. (Schedules 3A, 5A, and 8D require
monthly level data for the calendar year. All other schedules collect aggregated annual data for the calendar
year.)
See instructions for each schedule for more specific filing requirements.

METHODS OF
FILING RESPONSE

Submit your data electronically using EIA’s secure e-file system. This system uses security protocols to
protect information against unauthorized access during transmission.
If you have not registered with the e-file Single Sign-On (SSO) system, send an email requesting
assistance to: [email protected].
If you have registered with SSO, log on at: https://signon.eia.gov/ssoserver/login
If you are having a technical problem with logging into or using the e-file system, contact the Help Desk at:
Email: [email protected] or 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.

1

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

CONTACTS

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

E-file System Questions: For questions related to the e-file system, see the help contact information
immediately above.
Data Questions: For questions about the data requested on the Form EIA-923, contact:
Schedules 1 & 4:
Chris Cassar
[email protected]
202-586-5448
Schedule 2:

Rebecca Peterson

[email protected]

202-586-4509

Schedules 3 & 5:

Ron Hankey

[email protected]

202-586-2630

[email protected]

202-586-5356

Schedules 6, 7, & 8: Channele Wirman
EIA-923 Fax:
EIA-923 Mailbox:
GENERAL
INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

202-287-1959 or 202-287-1960
[email protected]

Revision Policy: Submit revisions to data previously reported as soon as possible after the error or
omission is discovered. Do not wait to revise data until the next reporting month's form is due.
Revisions or adjustments to data should be made only to the survey month(s) to which they pertain. (Do
not adjust the current month to reflect a revision or adjustment to a prior month submission.)

•

Log on to the e-file system, re-key revised data, indicate in SCHEDULE 9 the nature and
date of the revision, and resubmit the data.

•

Remember to save and RESUBMIT (click on the SUBMIT button).

If you are unable to make a revision through the e-file system because the monthly data file has been
closed, please email your changes to [email protected], and indicate ‘Revision’ in subject line. Be sure to
include your Plant ID, the specific revision, and the month that is being revised.
Correcting prepopulated information: For e-file users, much of the information on the form is
prepopulated by EIA. Verify the administrative information and make corrections to the contact name,
phone numbers, addresses, or email addresses. Please note that PLANT NAME, PLANT CODE, and
COMPANY NAME cannot be changed. Contact the survey manager if these items are incorrect.
Correcting errors: For e-file users, data that fail our edits will be amassed into an edit log. Upon hitting
the “Submit” button, the system will notify you if there are failed edits in the log. You will be directed to the
log and given the opportunity to either revise the data in question or override it. When an edit is
overridden, the system will ask for a comment/explanation. Each explanation is reviewed by EIA and, if it
does not sufficiently explain the anomaly, you will be contacted for a more detailed clarification.
Revising data: If you report via facsimile or email, you may send a corrected copy of the form, but be
sure to indicate in SCHEDULE 9: (1) that it is a revision, (2) the month that is being revised, (3) what has
been revised, and (4) the date of the revision. If you report via the e-file system, send an email to the
survey manager indicating the 4 items listed above.
Schedule 9 is provided for respondents to provide comments. Use it to explain anomalies with data or to
provide any further details that are pertinent to the data and plant.

2

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

ITEM-BY-ITEM
INSTRUCTIONS

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

SCHEDULE 1. IDENTIFICATION
1.

Survey Contact: Verify contact name, title, address, telephone number, fax number, and email
address.

2.

Supervisor of Contact Person for Survey: Verify the contact’s supervisor’s name, title, address
telephone number, Fax number and email address. The Survey Contact and Supervisor cannot be
the same person.

If any of the above information is incorrect, revise the incorrect entry and provide the correct information.
Provide any missing information.

3.

Report For: Verify all information, including company name, plant name, plant identification number,
plant State and county, and month or year for which data are being reported. State codes are twocharacter U.S. Postal Service abbreviations. These fields cannot be revised online. Contact the EIA923 survey manager if corrections are needed.

4.

Regulatory Status: Verify that the check correctly identifies your plant as either regulated or
unregulated. Contact the EIA-923 survey manager if a correction is needed.

5.

CHP Checkbox: Verify that the check correctly indicates whether or not this facility is a combined
heat and power plant, regardless of its utility/nonutility status. Contact the EIA-923 survey manager if
a correction is needed.

6.

CHP Plant Efficiency: If the CHP checkbox is “YES”, enter the efficiency of the combined heat and
power plant. To calculate the total plant efficiency, divide the sum of the energy outputs (in British
thermal units (Btu)), including net generation and useful thermal output by the sum of the energy
inputs (fuels converted to Btu). Report the annual average total CHP plant efficiency.
SCHEDULE 2. COST AND QUALITY OF FUEL PURCHASES – PLANT-LEVEL

REQUIRED RESPONDENTS: Plants with a total nameplate capacity of 50 MW and above that use fossil
fuels (coal, petroleum products, petroleum coke, natural gas, and other gases, including blast furnace gas)
for the generation of electric power or the combined production of electric power and useful thermal output
must complete the appropriate data on Schedule 2, Cost and Quality of Fuel Receipts.
All fuel purchases should be reported at the plant level. However, for fuel received at transfer terminals or
storage facilities that CANNOT be allocated to individual plants or vendor information for cost and quality of
the fuel at a terminal is not available to the plant, the terminal or storage facility must report the fuel
purchases, including cost and quality data. Terminals and storage facilities must list the plants where the fuel
will be utilized on Schedule 9, Comments.
In order to avoid duplicate data, report purchases at either the storage site or at the plant, but not both.
Purchases reported by a storage site and then transferred to the plant should not be reported at the plant
level. Instead, designate such transfers in Schedule 4 as a negative adjustment to stocks at the storage
site and a positive adjustment to stocks at the plant, including appropriate comments.
ANNUAL RESPONDENTS: Report Schedule 2 by aggregating receipts for the entire year in the manner
specified in the instructions for Schedule 2, Page 1 below.
Plant Name, Plant ID, State, Reporting Month and Year: For e-file users, verify the prepopulated
information for these items at the top of this (and all) page(s).
If no fuel was purchased during the reporting period, place a check in the “No Receipts” box, and go to
Schedule 3.

3

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

If this plant has a tolling agreement and the toller will not divulge the cost of the fuel, you may leave both
the commodity and delivered prices blank. Report all other data. Be sure to indicate that there is a tolling
agreement currently in place by entering a check in the box at the center of the page. For e-file users, this
check will carry over into subsequent months. If the agreement expires, contact the survey manager to
have the check removed.
SCHEDULE 2. PAGE 1. CONTRACT INFORMATION, RECEIPTS, AND COSTS.
1. Fuel Supplier Name:
Coal Purchases: Report data by supplier and mine source. (Purchased coal or petroleum coke
which will be converted to synthesis gas should be reported as it is received, i.e. as coal or petroleum
coke.)
Monthly Respondents: Coal received from spot-market purchases and from contract purchases must
be reported separately. Data on coal received under each purchase order or contract from the same
supplier must be reported separately. Coal purchases can be aggregated when supplier, purchase
type, contract date, coal rank, transportation mode, costs, fuel quality, and all mine information are
identical. If coal received under a purchase order or contract originates in more than one
State/county/mine and the mines are known as well as the amount received from each mine, split the
amount received accordingly between the number of different mines and report identical quality and
prices (unless the actual quality and prices are known). Mine information is reported on Page 3 of
Schedule 2. If the mine or group of mines is not available on the list of mines provided for data entry on
the e-filing system, contact EIA immediately (see contacts on Page 1 of the form or instructions). EIA will
add appropriate choices for purchases from multiple sources to the drop down list.
Annual Respondents: Coal received from spot market purchases and from contract purchases must
be reported separately. Aggregation of coal shipments is allowed ONLY IF shipments are identical in
purchase type, coal rank, mine name, mine type, Mine Safety and Health Administration (MSHA) ID,
State of origin, county of origin, and supplier. For aggregated purchases, report the weighted average
cost and quality of the fuel. If the mine or group of mines is not available on the list of mines provided for
data entry on the e-filing system, contact EIA immediately (see contacts on Page 1 of the form or
instructions).
Petroleum Purchases: Report data by fuel type, supplier or broker, or refinery and, if applicable, port
of entry.
Monthly Respondents: Oil received from spot-market purchases and from contract purchases must be
reported separately. Report individual shipments as separate line items.
Annual Respondents: Oil received from spot-market purchases and from contract purchases must be
reported separately. Aggregation for the entire year is allowed by fuel type and supplier. If
aggregated, report the weighted average cost and quality of the fuel.
Gas Purchases (monthly and annual respondents): Report data by fuel type and supplier.
Aggregation of gas deliveries from various suppliers is allowed only if 1) the deliveries are spot
purchases, 2) the type of gas is the same (either NG, OG, or PG), and 3) the transportation contracts
are identical (either firm or interruptible). For aggregated deliveries, report the pipeline or distributor in
the supplier column and the weighted average cost and quality of the fuel. Contract purchases must
be reported as separate line items and should never be aggregated. For gas produced by the plant
(e.g., BFG), list the suppler as “self-produced,” which is one of the choices in the drop-down list of
suppliers. Do not report land fill gas (LFG) in the category of other gases (OG) on Schedule 2
because LFG is not a fossil fuel. Do not report gas injected into storage. Report it when it is delivered
to the plant. Do not report any costs associated with storage.
2.

Contract Type: Use the following codes for coal, petroleum and natural gas purchases:
C – Contract Purchase – Fuel received under a purchase order or contract with a term of one year
or longer. Contracts with a shorter term are considered spot purchases. (See below.)

4

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

NC – New Contract or Renegotiated Contract Purchase – Fuel received under a purchase order or
contract with duration of one year or longer, under which deliveries were first made during the
reporting month.
S – Spot-Market Purchase – Fuel received under a purchase order or contract with duration of less
than one year.
3.

Contract Expiration Date: Enter the month and the year the purchase order or contract expires. For
example, report “1112” for a November “2012” expiration date. This column should be left blank if
Contract Type contains an “S” for spot-market purchase.
Purchases

4.

Energy Source: Identify purchased fossil fuels (including start-up and flame stabilization fuel) using
the energy source codes listed in Table 8 for coal, petroleum products, petroleum coke, and natural
gas and other gases.

5.

Quantity Received: Enter quantities in tons for coal and other solid fuels, barrels for oil and other
liquid fuels, and thousands of cubic feet for gas. Fuel purchases reported should pertain to the fuel
that will ultimately be used only in the electric power plant for the generation of electricity and at
combined heat and power plants for useful thermal output (process steam, district heating/cooling,
space heating, or steam delivered to other end users). As far as possible, do not include fuel that will
be used in boilers with no connection to an electric power generator and are not part of the electric
power station. If these fuels cannot be separated, please provide a comment on Schedule 9,
Comments. Start-up and flame-stabilization fuels should be reported. When fuel is purchased by and
received at the plant and is resold, report the total receipts minus the amount sold. See the below
instruction regarding how to report the costs.
Cost of Fuel

6.

Total Delivered Cost (all fuels): Enter the delivered cost of the fuel in cents per million Btu to the
nearest 0.1 cent. This cost should include all costs incurred in the purchase and delivery of the fuel to
the plant. It should not include unloading costs. Do not include adjustments associated with prior
months’ fuel costs. The delivered price for fuel shipped under contract should include any
penalties/premiums paid or expected to be paid on the fuel delivered during the month. These
adjustments should be made only by revising the appropriate prior months’ submissions. The current
month fuel costs should reflect only costs associated with the current month fuel deliveries. If fuel
received at the plant is resold, report the commodity cost and the total delivered cost as the cents per
MMBtu paid for the original receipt. Do not discount the costs by the revenue received for the sale of
the fuel.

7.

For natural gas, include the following pipeline charges: fuel losses, transportation reservation
charges, balancing costs, and distribution system costs outside of the plant. Because these types of
fees can skew the cost of the fuel per MMBtu, please provide an explanation in an edit log override
comment, e.g. “This price includes a reservation fee of x dollars.”

8.

Commodity Cost (Coal, Petroleum Coke, and Natural Gas Only): The commodity cost is the price
of that fuel (in cents per million Btu) at the point of first loading (free on board mine/transportation
pipeline (FOB)) including taxes and any quality-related charges or credits. The commodity cost does
not include: loading and unloading charges, dust proofing, freeze conditioning, switching charges,
diesel fuel surcharges, pipeline charges, or any other charges relating to the movement of the fuel to
the point of use. In the case of natural gas this is typically the price of the gas FOB the transmission
pipeline.

9.

For fuel purchased via a hedging contract, report the actual fuel supplier, not the hedge contract.
Report the cost net of gains/losses as a result of the contract.

5

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

SCHEDULE 2. PAGE 2. QUALITY OF FUEL AND TRANSPORTATION INFORMATION
Quality of Fuel
Fuel Supplier Name, Contract Type, Quantity Purchased, and Energy Source is prepopulated for efile users based on the data entered on page 1 of SCHEDULE 2.
1.

Heat Content: Enter the actual (not contractual) average Btu content for each fuel purchase in terms
of million (MMBtu) per ton for solid fuel, MMBtu per barrel for liquid fuel, and MMBtu per thousand
cubic feet for gas. Show to the nearest 0.001 MMBtu. Refer to Table 8 for approximate ranges.

2.

Sulfur Content: For all coal types, petroleum coke, residual fuel oil, and waste oil, enter the sulfur
content of the fuel in terms of percent sulfur by weight. Show to the nearest 0.01 percent. Refer to
Table 1 for approximate ranges.

3.

Ash Content: For coal and petroleum coke, enter the ash content of the fuel in terms of percent ash
by weight. Show to the nearest 0.1 percent. Enter a comment in Schedule 9 if the reported ash
content for coal is an estimate. Refer to Table 1 for approximate ranges.

4.

Mercury Content: For coal only, enter the mercury content in parts per million (ppm). Show to the
nearest 0.001 parts per million (ppm). If lab tests of the coal receipts do not include the mercury
content, enter the amount specified in the contract with the supplier. Refer to Table 1 for approximate
ranges. If mercury content is unknown, enter 9.
Table 1
Fuel
BIT

% Sulfur
0.4 – 6.0

% Ash
4.0 – 30.0

Mercury
(ppm)
0.020 -- 0.500

LIG

0.4 – 3.0

5.0 – 35.0

0.020 -- 0.500

SUB

0.2 – 1.5

3.0 – 15.0

0.020 -- 0.200

ANT

0.4 – 6.0

4.0 – 30.0

0.020 -- 0.500

RC

0.2 – 6.0

3.0 – 30.0

0.020 -- 0.500

WC

0.3 – 6.0

5.0 – 50.0

0.020 -- 1.200

PC

1.0 – 7.0

0.1 -- 1.2

RFO

0.2 – 4.5

WO

0.0 – 4.5
Fuel Transportation

5.

Natural Gas: Use the following codes for natural gas transportation service:
F – Firm – Gas transportation service provided on a firm basis, i.e. the contract with the gas
transportation company anticipates no interruption of gas transportation service. Firm transportation
service takes priority over interruptible service.
I – Interruptible – Gas transportation service provided under schedules or contracts which anticipate
and permit interruption on short notice, such as in peak-load seasons, by reason of the claim of firm
service customers and higher priority users.
(Note: Natural Gas received under firm contracts must be reported separately from interruptible
contracts.)

6

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

6.

Predominant Mode: The method used to transport the fuel over the longest distance from point of
origin to consumer. If the shipment involves only one mode of transportation, that is the Predominant
Mode. If the shipment involves more than one mode of transportation, see Secondary Mode below.

7.

Secondary Mode: If more than one method of transportation is used in a single shipment, the
Secondary Mode of transportation is the second longest method used to transport the fuel to
consumer. If more than two methods are used in a single shipment, only the Predominant and
Secondary Modes should be reported.
Do not report “truck” as a transportation mode if trucks are used to transport coal exclusively on
private roads between the mine and rail load-out or barge terminal.
Do not report the transportation modes used entirely within a mine, terminal, or power plant (e.g.,
trucks used to move coal from a mine pit to the mine load-out; conveyors at a power plant used to
move coal from the plant storage pile to the plant).
For minemouth coal plants, report “Conveyor” as the Predominant Mode if the conveyor feeding coal
to the plant site originates at the mine. Otherwise report the Predominant Mode (typically truck or rail)
used to move the coal to the plant site.

Report Transportation Modes using the following codes:
RR – Rail: Shipments of fuel moved to consumers by rail (private or public/commercial). Included is coal
hauled to or away from a railroad siding by truck if the truck did not use public roads.
RV – River: Shipments of fuel moved to consumers via river by barge. Not included are shipments to
Great Lakes coal loading docks, tidewater piers, or coastal ports.
GL – Great Lakes: Shipments of coal moved to consumers via the Great Lakes. These shipments are
moved via the Great Lakes coal loading docks, which are identified by name and location as follows:
Conneaut Coal Storage & Transfer, Conneaut, Ohio
NS Coal Dock (Ashtabula Coal Dock), Ashtabula, Ohio
Sandusky Coal Pier, Sandusky, Ohio
Toledo Docks, Toledo, Ohio
KCBX Terminals Inc., Chicago, Illinois
Superior Midwest Energy Terminal, Superior, Wisconsin
TP – Tidewater Piers and Coastal Ports: Shipments of coal moved to Tidewater Piers and Coastal Ports
for further shipments to consumers via coastal water or ocean. The Tidewater Piers and Coastal Ports
are identified by name and location as follows:
Dominion Terminal Associates, Newport News, Virginia
McDuffie Coal Terminal, Mobile, Alabama
IC Railmarine Terminal, Convent, Louisiana
International Marine Terminals, Myrtle Grove, Louisiana
Cooper/T. Smith Stevedoring Co. Inc., Darrow, Louisiana
Seward Terminal Inc., Seward, Alaska
Los Angeles Export Terminal, Inc., Los Angeles, California
Levin-Richmond Terminal Corp., Richmond, California
Baltimore Terminal, Baltimore, Maryland
Norfolk Southern Lamberts Point P-6, Norfolk, Virginia
Chesapeake Bay Piers, Baltimore, Maryland
Pier IX Terminal Company, Newport News, Virginia
Electro-Coal Transport Corp., Davant, Louisiana
WT – Water: Shipments of fuel moved to consumers by other waterways.
TR – Truck: Shipments of fuel moved to consumers by truck. Not included is fuel hauled to or away from
7

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

a railroad siding by truck on non-public roads.
TC – Tramway/Conveyor: Shipments of fuel moved to consumers by tramway or conveyor.
SP – Slurry Pipeline: Shipments of coal moved to consumers by slurry pipeline.
PL – Pipeline: Shipments of fuel moved to consumers by pipeline.
SCHEDULE 2. PAGE 3. COAL MINE INFORMATION
Fuel Supplier Name, Contract Type, Quantity Purchased, and Energy Source will be prepopulated for
e-file users based on the data entered on page 1 of SCHEDULE 2.
1.

State or Country of Origin: Choose the two-letter U.S. Postal Service abbreviation or country code
from the drop down list of coal producing states (countries). For imported coal, insert the two-letter
country code shown here.
AS – Australia; CN – Canada; CL – Colombia; IS – Indonesia; PL – Poland;
RS – Russia; VZ – Venezuela; OT – Other (specify the country in Schedule 9).
The State of Origin is mandatory. If purchases originate from a broker, barge site or other third party,
you must contact the broker, barge site or other party and find out the State(s) where the coal
originates. If the broker or supplier is not forthcoming with State of Origin information or Mine Information,
provide the name and telephone number of the supplier on Schedule 9, Comments.
If coal purchased under a purchase order or contract originates in more than one State, determine from
the supplier the most dominant or probable State(s) of origin for the coal. Contact EIA to have the
supplier and State(s) added to the drop down list of choices for State of Origin and Mine Information on
Schedule 2 Page 3. If the amount of coal from each State/Mine is known, allocate the purchase among
multiple States, or report the State where the majority of the coal originates and report identical quality
and cost data (unless the actual quality and costs are known).
Contact EIA immediately (see contacts on Page 1 of the form or instructions) for assistance in reporting
coal State of Origin or Mine Information. EIA will add appropriate choices for purchases from multiple
sources to the drop down list.

2.

Mine Information: Choose from the drop down list the mine of origin. The list will display only those
mines located in the State/country of origin. The displayed information includes the mine operating
company for informational purposes to aid in identifying the mine of origin. Upon choosing a mine, the
MSHA ID, Mine Name, Mine Type and Mine County will automatically be populated.
Mine Information is mandatory. Determine from the supplier the most dominant or probable mine(s) of
origin for the coal. List the mines on Schedule 9, Comments. If the broker or supplier is not forthcoming
with State of Origin information or Mine Information, provide the name and telephone number of the
supplier on Schedule 9, Comments.
In cases where coal originates from multiple mines or the specific mine information cannot be
determined, list the tipple/loading point or dock on Schedule 9, Comments. EIA will add appropriate
choices to the drop down list of Mine Information to accommodate multiple mines or undetermined mine
sources. Use Schedule 9, Comments, to provide detailed explanations of mine origin data, including
names of multiple mines for a specific supplier/broker or dock, or the most probable origin of the coal
(county/State) if not specifically known.
Contact EIA immediately (see contacts on Page 1 of the form or instructions) for assistance in reporting
coal State of Origin or Mine Information. EIA will add appropriate choices for purchases from multiple
sources to the drop down list.

8

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

SCHEDULE 3. PART A. BOILER-LEVEL INFORMATION
FOR STEAM-ELECTRIC ORGANIC-FUELED PLANTS – FUEL CONSUMPTION
Required Respondents: Complete this schedule for fuels consumed in the boilers at plants with steam
turbines that have a total nameplate capacity of 10 MW and above and burn organic fuels. This does not
include steam turbines where the energy source is nuclear, geothermal, or solar, or plants that have less
than 10 MW total steam turbine nameplate capacity. Also report on this schedule fuels consumed at
combined-cycle plants for supplementary firing of heat recovery steam generator (HRSG) units that have a
total steam turbine nameplate capacity of 10 MW and above. If no fuel is consumed, for example in
combined cycle steam units (HRSG) without supplementary firing, report zero. Do not leave the field
blank. Report fuels consumed in gas turbines, including the gas turbines at combined-cycle plants, and IC
engines on SCHEDULE 3 PART B.
For combined heat and power plants, if steam was produced for purposes other than electric power
generation during this reporting period, please place a check in the box on the form.
For those plants that report annually, Schedules 3A and 5A must be reported for each month.
Prime movers are devices that convert one energy form (such as heat from fuels or the motion of water or
wind) into mechanical energy. Examples include steam turbines, combustion turbines, reciprocating
engines, and water turbines. For a complete list of prime mover codes, please refer to Table 7.
Prime Mover Code: Prime mover codes are shown in Table 7. Only CA and ST can be used in Schedule
3. Part A. For e-file users, the code will be prepopulated. If the prepopulated code is incorrect, delete the
code and choose the correct prime mover code from the drop-down list.
Boiler ID: The boiler ID is prepopulated. For an ID not prepopulated, choose the ID from the drop down list
of boiler IDs that were reported for your plant on the Form EIA-860. If the boiler ID is not on the list, contact
EIA immediately to have the ID added to your form. Boiler IDs must match those reported on the Form
EIA-860.
Boiler Status: Enter one of the codes listed below:
Table 2

Code

Boiler Status

OP

Operating (in commercial service or out of service less than 365 days)

OS

Out of service (365 days or longer)

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)

Energy Source: Use the fuel codes in Table 8. For bituminous and subbituminous coal that is blended,
where possible report each coal rank consumed separately. If no allocation can be determined, report the
fuel that is predominant in quantity. An estimated allocation between coal ranks is acceptable.
Quantity Consumed: For each month, report the amount of fuel consumed for electric power generation
and, at combined heat and power stations, for useful thermal output. Combined-cycle units should
report only the auxiliary firing fuel associated with the HRSG. Do not report the fuel consumed in the
combustion turbine portion of the combined-cycle unit on Schedule 3A. CT consumption must be reported
on Schedule 3B.

9

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Type of Physical Units: Fuel consumption must be reported in the following units:
Solids – Tons
Liquids – Barrels (one barrel equals 42 U.S. gallons)
Gases – Thousands of cubic feet (Mcf)
Average Heat Content: For each month, report the heat content of the fuels burned to the nearest 0.001
million Btu (MMBtu) per physical unit. The heat content of the fuel should be reported as the gross or
“higher heating value” (rather than the net or lower heating value). The higher heating value exceeds the
lower heating value by the latent heat of vaporization of the water. The heating value of fuels generally
used and reported in a fuel analysis, unless otherwise specified, is the higher heating value. If the fuel
heat content cannot be reported “as burned,” data may be obtained from the fuel supplier on an “as
received” basis. If this is the case, indicate on SCHEDULE 9 that the fuel heat content data are “as
received.” Report the value in the following units: solids in million Btu (MMBtu) per ton; liquids in MMBtu
per barrel; and gases in MMBtu per thousand cubic feet (Mcf). Refer to Table 8 for approximate ranges of
heat content of specific energy sources.
Sulfur Content (petroleum, petroleum coke, and coal): For each month, enter sulfur content to nearest
0.01 percent. Sulfur content should be reported for the following fuel codes: ANT, BIT, LIG, RC, SUB,
WC, PC, RFO, and WO. Refer to Table 1 for approximate ranges.
Ash Content (coal and petroleum coke only): For each month, enter ash content to the nearest 0.1
percent. Ash content should be reported for the following fuel codes: ANT, BIT, LIG, SUB, WC, RC, and
PC. Refer to Table 1 for approximate ranges.
Report actual values. If necessary, report estimated values and state that the value is an estimate on
SCHEDULE 9.
ENTER ZERO when an energy source was not consumed for the reporting period. Do not leave blank.
SCHEDULE 3. PART B. FUEL CONSUMPTION – PRIME MOVER-LEVEL
Required Respondents: Report fuel consumed in all gas turbines, including the combustion turbine part
of combined-cycle plants, internal combustion engines, steam-electric plants under 10 megawatts, fuel
cells, and electric power input to pumped-storage hydroelectric plants, compressed air units, and other
miscellaneous energy storage technologies. Excluded from this schedule are conventional hydroelectric
plants and all other plants that are not required to report energy consumed (e.g., wind, solar, geothermal,
and nuclear). Do not report for each individual unit. For example, report natural gas consumed in all
combustion turbines at the plant as one value and report distillate fuel oil consumed by all IC engines as one
value. Combined-cycle plants should report the fuel consumed by the combustion turbines on this
schedule. Report supplementary fuel consumed by the HRSG on this schedule only if the total steamelectric capacity is less than 10 MW. All steam-electric plants and supplementary-fired HRSGs at combined
cycle plants with a total steam electric nameplate of 10 MW and above must report fuel consumption at the
boiler level on Schedule 3A.
Prime movers are devices that convert one energy form (such as heat from fuels or the motion of water or
wind) into mechanical energy. Examples include steam turbines, combustion turbines, reciprocating
engines, and water turbines.
For combined heat and power plants, if steam was produced for purposes other than electric power
generation during this reporting period, please place a check in the box on the form.
Prime Mover Code: Prime mover codes are shown in Table 7. Only CA, CE, CS, CT, FC, GT, IC, PS,
ST, and OT can be used in Schedule 3. Part B. For e-file users, the code is prepopulated. If the
prepopulated code is incorrect, choose the correct code from the drop-down list. Each prime mover type on
Schedule 3B must have a corresponding entry on Schedule 5B for electric power generation.

10

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Report actual values. If necessary, report estimated values and state that the value is an estimate on
SCHEDULE 9.
Energy Source: Use the fuel codes in Table 8. For bituminous and subbituminous coal that is blended,
where possible report each coal rank consumed separately. If no allocation can be determined, report the
fuel that is predominant in quantity. An estimated allocation between coal ranks is acceptable.
Quantity Consumed: For each month, report the amount of fuel consumed for electric power generation
and, at combined heat and power stations, for useful thermal output. Include start-up and flamestabilization fuels. Pumped storage hydroelectric plants and compressed air plants report the megawatthours
of energy input for pumping water or compressing air for energy storage. Combined cycle plants with no
supplementary firing must report the CA unit on Schedule 3B with ZERO for fuel consumed. Each prime
mover type on Schedule 3B must have a corresponding entry on Schedule 5B for electric power generation.
Type of Physical Units: Fuel consumption must be reported in the following units:
Solids – Tons
Liquids – Barrels (one barrel equals 42 U.S. gallons)
Gases – Thousands of cubic feet (Mcf)
Pumped storage hydro and compressed air -- Megawatthours
Average Heat Content: For each month, report the heat content of the fuels burned to the nearest
.001 MMBtu (million Btu) per physical unit (MMBtu per ton/barrel/thousand cubit feet). The heat content
of the fuel should be reported as the gross or “higher heating value” (rather than the net or lower heating
value). The higher heating value exceeds the lower heating value by the latent heat of vaporization of the
water. The heating value of fuels generally used and reported in a fuel analysis, unless otherwise specified,
is the higher heating value. If the fuel heat content cannot be reported “as burned,” data may be obtained
from the fuel supplier on an “as received” basis. If this is the case, indicate on SCHEDULE 9 that the fuel
heat content data are “as received.” Report the value in the following units: solids in MMBtu per ton; liquids
in MMBtu per barrel; and gases in MMBtu per thousand cubic feet (Mcf). Refer to Table 8 for approximate
ranges of heat content for specific fuels. Heat content can be blank if fuel consumed is zero and for
pumped storage and compressed air plants.

SCHEDULE 4. FOSSIL FUEL STOCKS AT THE END OF THE REPORTING PERIOD
AND DATA BALANCE
Required Respondents: Schedule 4 regarding stocks must be completed by all plants that burn fossil
fuels: COAL, DISTILLATE FUEL OILS (NO. 2, 4), RESIDUAL FUEL OIL (NO. 6), JET FUEL, KEROSENE,
PETROLEUM COKE, and for plants 50 MW and above, NATURAL GAS. Although there are no stocks for
natural gas, the energy balance (between receipts and consumed fuel) and comments should be
completed for natural gas plants that have a total nameplate capacity of 50 MW and more (and have
completed Schedule 2).
Report fuel stocks ONLY for the following fuels:
−

Coal: Report all stocks of coal for use by this power plant. Include both stocks held on site and
stocks held off site whether owned by your plant or by an affiliated company. If the stocks are
held for the plant by an affiliated company and the amount is unknown, please provide EIA the
name of the company. EIA will contact them to obtain the stocks number. Do not report waste
coal stocks.

−

Residual oil (No. 5 and No. 6 fuel oils)

−

Distillate-type oils (including diesel oil, No. 2 oil, jet fuel, and kerosene)

−

Petroleum coke
11

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Include back-up fuels and start-up and flame-stabilization fuels. Do not report stocks for waste coal,
natural gas, or wood and wood waste or other biomass fuels. All fuel stocks should be reported at the
plant level where possible. Stocks data should be reported by a transfer terminal or storage facility only if
inventory cannot be attributed to individual plants.
To avoid duplication, do not report receipts in Schedule 2 at the plant level that have already been reported by
a transfer terminal or storage facility and then transferred to a plant(s). Designate such transfers in Schedule
4 as negative adjustments to stocks at the transfer terminal or storage facility and positive adjustments to
stocks at the plant, including appropriate comments. Depending on the required data at transfer terminals or
storage sites and associated plants, the energy balance may require an explanatory comment. ENTER ZERO
in the Ending Stocks column if a plant has no stocks. Do not leave the field blank.
Energy Source: Add the energy source code from Table 8. For e-file users the code is prepopulated. If
the code is incorrect, choose the correct code from the drop-down list.
Type of Physical Units: Report coal and petroleum coke in tons and distillate and residual oils in barrels.
1.

Previous Month’s Ending Stocks: This is automatically populated into the schedule from the
previous reporting period.

2.

Current Month’s Purchases: These data have been reported (above in SCHEDULE 2) and the
sum by energy source is automatically populated.

3.

Current Month’s Consumption: These data have been reported (in SCHEDULE 3A and 3B) and
the sum by energy source is automatically populated.

4.

Ending Stocks: Report this month’s ending stocks. Include all on-site stocks held for eventual use
in the electric power plant regardless of actual ownership of the fuel.

5.

Adjustment to Stocks: Report adjustments to end-of-month stocks. Adjustments may include
stocks transferred or sold offsite and revisions to account for adjustments to previous months’ stocks.
Adjustments can be positive or negative. Enter an explanation for the adjustment in the section
provided on Schedule 4.

6.

Balance: The data balance verifies the quality of the data. The balance is the difference between
Reported Ending Stocks (4) and an expected value for ending stocks calculated by the following
equation: Previous Month’s Ending Stocks plus Current Month’s Purchases minus Current Month’s
Consumption plus (or minus) Adjustment to Stocks [(4) = (1) + (2) - (3) + (5)]. If the balance is a nonzero value, please review the data entered for stocks, receipts, consumption, and adjustments. Enter
a comment in the box on Schedule 4 for Balance comments to explain any discrepancy. Fuel receipts
that are not used for the production of electricity but for other purposes at the plant (e.g. as a feed
material to produce chemical byproducts such as fertilizers, etc.) may cause an imbalance in the
equation. Likewise, fuel that is sold during the month may cause an imbalance. Enter an
adjustment to balance the equation and enter an explanation for the adjustment or other situation
that result in an imbalance. Note that there are separate areas on Schedule 4 for adjustment
explanations and explanations for balances not equal to zero.

12

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

SCHEDULE 5. PART A. GENERATOR INFORMATION FOR STEAM-ELECTRIC
ORGANIC-FUELED PLANTS
Required Respondents: This schedule will be completed ONLY for generators at steam-electric organicfueled plants with a total steam turbine capacity of 10 megawatts and above, including the steam turbine
generation from combined cycle units. Report generation for all other types of prime movers (combustion
turbines, IC engines, wind, and hydraulic turbines), and steam turbine capacity of less than 10 megawatts
and all plants fueled by nuclear, solar, geothermal, or other energy sources on SCHEDULE 5. PARTS B or
C. Generation reported on Schedule 5. Part A. corresponds to the fuel consumption reported on Schedule
3. Part A.
For those plants that report annually, Schedules 3.A. and 5.A. must be reported for each month.
Prime Mover Code: Prime mover codes are shown in Table 7. Only CA and ST can be used in Schedule
5. Part A. For e-file users, the code is prepopulated. If the prepopulated code is incorrect, choose the
correct prime mover code from the drop-down list.
Generator ID: The generator ID is prepopulated. For an ID not prepopulated, choose the ID from the drop
down list of generator IDs that were reported for your plant on the Form EIA-860. If the generator ID is not
on the list, contact EIA immediately to have the ID added to your form. Generator IDs must match those
reported on the Form EIA-860.
Data must be reported in megawatthours (MWh), rounded to whole numbers, no decimals.
If no generation occurred, report ZERO. Please do not leave fields blank.
Generator Status: Enter one of the codes listed in Table 3 for generator status.
Table 3

Status Status Code Description
Code
OP

Operating - in service (commercial operation) and producing some electricity. Includes
peaking units that are run on an as needed (intermittent or seasonal) basis.

SB

Standby/Backup - available for service but not normally used (has little or no generation
during the year) for this reporting period

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.

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

Gross Generation: Enter the total amount of electric energy produced by generating units and measured
at the generating terminal. For each month, enter that amount in MWh.
Net Generation: Enter the net generation (gross generation minus the parasitic station load, i.e. station
use). If the monthly station service load exceeded the monthly gross electrical generation, report negative
net generation with a minus sign. Do not use parentheses. For each month, enter that amount in MWh.
Combined heat and power plants in the industrial and commercial sectors may choose to leave net
generation blank in cases where net generation cannot be determined. Please note that net generation is
not defined as electric power sold to the grid (net of direct use), but as gross minus station use. If station
use is not separable from direct use at combined heat and power plants, report only gross generation and
leave net generation blank.

13

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

SCHEDULE 5. PART B. PRIME MOVER LEVEL GENERATION
Required Respondents: This schedule will be completed by: 1) steam-electric organic-fueled plants with
a total steam turbine capacity less than 10 megawatts, 2) combined-cycle plants whose steam portion of
the operation is under 10 MW and 3) all IC engines, combustion turbines, compressed air units, pumpedstorage hydroelectric turbines, and other miscellaneous energy storage technologies. Generation reported
on this schedule corresponds to the fuel consumption reported on Schedule 3. Part B.
Prime Mover Code: Prime mover codes are shown in Table 7. Only CA, CE, CS, CT, FC, GT, IC, PS,
ST, and OT can be used in Schedule 5. Part B. For e-file users, the code is prepopulated. If the
prepopulated code is incorrect, choose the correct prime mover code from the drop-down list. Each prime
mover type on Schedule 5B must have a corresponding entry on Schedule 3B for fuel consumption. Note
that for prime mover type CA, the entry on Schedule 3B (fuel consumed) is ZERO.
If no generation occurred, report zero. Do not leave fields blank.
Data must be reported in MWh, rounded to whole numbers, with no decimals.
Gross Generation: Enter the total amount of electric energy produced by generating units and measured
at the generating terminal. For each month, enter in the MWh generated.
Net Generation: Enter the net generation (gross generation minus the parasitic station load, i.e. station
use). If the monthly station service load exceeded the monthly gross electrical generation, report negative
net generation with a minus sign. Do not use parentheses. For each month, enter that amount in MWh.
Combined heat and power plants in the industrial and commercial sectors may choose to leave net
generation blank in cases where net generation cannot be determined. Please note that net generation is
not defined as electric power sold to the grid (net of direct use), but as gross minus station use. If station
use is not separable from direct use at combined heat and power plants, report only gross generation and
leave net generation blank.
SCHEDULE 5. PART C. GENERATION FROM NUCLEAR AND
OTHER NONCOMBUSTIBLE ENERGY SOURCES
Required Respondents: This schedule will be completed by all nuclear plants and by all wind, solar,
geothermal, conventional hydroelectric or other plants where the energy source is not required to be
reported on Schedules 3A or 3B, such as purchased steam or waste heat. No fuel consumption data is
required for these types of plants. Report generation by energy source for nuclear, wind, solar, geothermal,
conventional hydroelectric and miscellaneous sources such as purchased steam or waste heat. Report
nuclear data by generating unit. For all other plant types, ignore the unit column. Do not report generation
at a combined-cycle plant. All combined-cycle generation is reported on SCHEDULE 5. PARTS A or B,
even though the fuel consumption for non-supplementary fired HRSG units is zero (reported on Schedule
3A or 3B with a zero for fuel).
Prime Mover Code: Prime mover codes are shown in Table 7. Only HY, HA, HB, HK, BT, PV, ST, WT,
and OT can be used in Schedule 5. Part C. For e-file users, the code is prepopulated. If the prepopulated
code is incorrect, choose the correct prime mover code from the drop-down list.
Energy Source: Enter one of the fuel codes listed in Table 8.
Unit Code: The nuclear unit code is prepopulated. Contact EIA if it is incorrect. All other plants ignore this
field.
Gross Generation: Enter the total amount of electric energy produced by generating units and measured
at the generating terminal. For each month, enter that amount in MWh.
Net Generation: Enter the net generation (gross generation minus the parasitic station load, i.e. station
use). If the monthly station service load exceeded the monthly gross electrical generation, report negative
net generation with a minus sign. Do not use parentheses. For each month, enter that amount in MWh.
Combined heat and power plants in the industrial and commercial sectors may choose to leave net
14

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

generation blank in cases where net generation cannot be determined. Please note that net generation is
not defined as electric power sold to the grid (net of direct use), but as gross minus station use. If station
use is not separable from direct use at combined heat and power plants, report only gross generation and
leave net generation blank.

SCHEDULE 6. NONUTILITY ANNUAL SOURCE AND DISPOSITION OF ELECTRICITY
Required Respondents: Nonutility plants report annual calendar year data for the source and disposition
of electricity.

•

If you file the EIA-923 monthly,, this schedule is completed on the Form EIA-923 Supplemental Form
and is filed annually.

•

If you file the EIA-923 annually, this schedule is completed on the Form EIA-923 Annual.

Report all generation in MWh rounded to a whole number.
Source of Electricity
1.

Gross Generation (Annual): Report the total gross generation from all prime movers at the plant.
Note that for monthly respondents this should equal the sum of the gross generation reported each
month on Schedules 5A, 5B, and 5C.

2.

Other Incoming Electricity: Report all incoming electricity to the facility, whether from purchases,
tolling agreements, transfers, exchanges, or other arrangements.

3.

Total Sources: Enter the sum of the total gross electricity generated plus the total incoming
electricity. This entry must equal Total Disposition (see below).

Disposition of Electricity
4.

Station Use: Station Use is electricity that is used to operate an electric generating plant, which is the
electricity used in the operation and maintenance of the facility (e.g., parasitic loads from auxiliary
equipment and onsite heating and lighting loads), regardless of whether the electricity is produced at
the plant or comes from another source. Station use does not include any electricity converted and
stored at an energy storage plant (such as electricity used for pumping at a hydroelectric pumpedstorage plant), nor direct use (see below) of electricity by an industrial or commercial CHP plant.

5.

Direct Use (Industrial and Commercial Sector Plants, both CHP and non-CHP): Report the
amount of electricity generated by the plant and consumed onsite for processes such as
manufacturing, district heating/cooling, and uses other than power plant station use. (Plants that
cannot separate Station Use and Direct Use may enter zero in Station Use and the sum of Station
Use and Direct Use in the Direct Use field. Provide a comment on SCHEDULE 9. )

6.

Total Facility Use: Report the total sum of station use and direct use.

7.

Retail Sales to Ultimate Customers: Report the amount of electricity sold directly to retail (end-use)
customers (power that is not re-sold or distributed by another entity). Include unbilled electricity
provided to affiliated and non-affiliated entities, excluding power provided as part of a tolling
agreement. By entering a value in this cell, you will be required to file the Form EIA-861 “Annual
Electric Power Industry Report,” for more detailed information on the nature of the retail sales.

8.

Sales for Resale: Report the amount of electricity sold for resale (wholesale sales in MWh). If data
are entered for this item, you must complete SCHEDULE 7.

9.

Other Outgoing Electricity: Report all other outgoing electricity from the facility, such as tolling
agreements, transfers, and exchanges.

10. Total Disposition: Report the sum of station use, direct use, retail sales, sales for resale, and other
outgoing electricity. This entry must equal Total Sources (see above).
15

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

SCHEDULE 7. ANNUAL REVENUES FROM SALES FOR RESALE
Required Respondents: To be completed by respondents who report a positive value on SCHEDULE 6,
Disposition of Electricity, Item 8, Sales for Resale.
“Sales for Resale” is energy supplied to other electric utilities, cooperatives, municipalities, Federal and
State electric agencies, power marketers, or other entities for resale to end-use consumers. This excludes
energy supplied under tolling agreements that is intended for resale to end use customers. Report energy
supplied under tolling agreements in “Other Outgoing Electricity.” Report all revenue from Sales for
Resale in thousand dollars to the nearest whole number.
SCHEDULE 8. ANNUAL ENVIRONMENTAL INFORMATION
Required Respondents: SCHEDULE 8 is filed annually and must be reported by steam-electric organicfueled power plants and combined cycle plants with a total steam turbine capacity of 10 megawatts and
above (that is the set of plants that reported boiler-level consumption on SCHEDULE 3. Part A.). Parts A
through F are required for plants 100 MW and above, and only Parts C, E and F are required for plants from
10 megawatts to less than 100 MW.

•

If you file the EIA-923 monthly, this schedule is completed on the Form EIA-923 Supplemental and is
filed annually.

•

If you file the EIA-923 annually, this schedule is completed on the Form EIA-923 Annual.
SCHEDULE 8. PART A. ANNUAL BYPRODUCT DISPOSITION

1.

If no byproduct was produced, place a check in the checkbox labeled NO BYPRODUCTS.

2.

If a byproduct is disposed of at no cost, enter the quantity of the byproduct under the appropriate
column and make a footnote entry on SCHEDULE 9 stating that no money was exchanged for the
quantity indicated. If there was a cost for disposal, make sure there is a corresponding entry on
SCHEDULE 8, PART B, for collection and/or disposal costs. Costs for gypsum disposal should be
reported on SCHEDULE 8, PART B, column 5, under “Disposal,” with a footnote entry on SCHEDULE
9. Entries on SCHEDULE 8, PART A, in the Sold column, must be compatible with entries on
SCHEDULE 8, PART B, columns 11 through 16, Byproduct Sales Revenue. If the byproduct was
distributed in several different ways (for example, the byproduct was placed in a landfill and then later
sold), report the end disposition of the byproduct and provide a comment on SCHEDULE 9 explaining
all previous dispositions.

3.

Do not include byproducts sold under “Used On-Site.”

4.

Fly ash from standard boiler/primary particulate collection device (PCD) units includes those
with no flue gas desulfurization (FGD) system or with FGD systems located downstream of the PCD.

5.

Fly ash from units with dry FGD includes spray dryer or duct injection systems where Fly Ash and
FGD byproducts are collected in the same PCD. It does not include Fluidized Bed Combustion (FBC)
units.

6.

Fly ash from FBC units includes fly ash from fluidized bed combustion (FBC) units.

7.

Bottom ash from standard boiler units includes boiler slag from slagging combustors. It does not
include Bottom (Bed) Ash from FBC units or slag from coal gasification units.

8.

Bottom (bed) ash from FBC units includes bottom (bed) ash from fluidized bed combustion (FBC) units.

9.

FGD Gypsum is defined as byproducts that are greater than 75 percent CaS04●2H20 by weight.

10. Other FGD byproducts includes all FGD byproducts not reported in Fly ash from units with dry
FGD units; Fly ash from FBC units; Bottom ash from standard boiler units; Bottom (bed) ash
from FBC units; and FGD gypsum along with additives used to stabilize the FGD byproducts.
11. Ash from coal gasification (IGCC) units includes slag or solids extracted from the bottom of the
gasifier as well as fly ash removed downstream of the gasifier.
12. Other: Enter amount of other by-products. Specify the by-product on Schedule 9, Comments.
16

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

13. Steam sales must be reported in million Btu (MMBtu).
SCHEDULE 8. PART B. FINANCIAL INFORMATION RELATED TO COMBUSTION BYPRODUCTS
1.

All entries should be reported in thousand dollars to the nearest whole number.

2.

For all Operation and Maintenance (O&M) Expenditures During Year, costs should be provided for
both collection and disposal of the indicated byproducts. If the collection and disposal costs cannot be
separated, place the total cost under Collection, and provide a comment on SCHEDULE 9 indicating
that the costs cannot be separated. All operation and maintenance expenditures should exclude
depreciation expense, cost of electricity consumed, and fuel differential expense (i.e., extra costs of
cleaner, thus more expensive fuel). Include all contract and self-service pollution abatement operation
and maintenance expenditures for each line item.

3.

For column 1, Fly Ash, and column 2, Bottom Ash, expenditures cover all material and labor costs
including equipment operation and maintenance costs (such as particulate collectors, conveyors,
hoppers, etc.) associated with the collection and disposal of the byproducts. Record expenditures for
IGCC slag or fly ash collection/disposal in Column (1) or Column (2), respectively.

4.

For column 3, Flue Gas Desulfurization, expenditures cover all material and labor costs including
equipment operation and maintenance costs associated with the collection and disposal of the sulfur
byproduct.

5.

For column 4, Water Pollution Abatement, expenditures cover all operation and maintenance costs
for material and/or supplies and labor costs including equipment operation and maintenance (pumps,
pipes, settling ponds, monitoring equipment, etc.), chemicals, and contracted disposal costs.
Collection costs include any expenditure incurred once the water that is used at the plant is drawn
from its source. Begin calculating expenditures at the point of the water intake. Disposal costs
include any expenditure incurred once the water that is used at the plant is discharged. Begin
calculating disposal expenditures at the water outlet (i.e., cooling costs).

6.

For column 5, Other Pollution Abatement, operation and maintenance expenditures are those not
allocated to one particular expenditure (e.g., expenditures to operate an environmental protection
office or lab). Include expenses for conducting environmental studies for expansion or reduction of
operation. Exclude all expenses for health, safety, employee comfort (OSHA), environmental
aesthetics, research and development, taxes, fines, permits, legal fees, Superfund taxes, and
contributions. Define other pollution abatement(s) in a comment on SCHEDULE 9.

7.

For Capital Expenditures for New Structures and Equipment during Year, Excluding Land and
Interest Expense, report all pollution abatement capital expenditures for new structures and/or
equipment made during the reporting year regardless of the date they may become operational.
Columns 7, 8, 9, and 10 should not be left blank. ENTER ZERO if the item is not applicable or an
estimate is not available, and enter a comment in SCHEDULE 9. Specify the nature of the
expenditures for these items in a comment on SCHEDULE 9.

8.

For column 7, Air Pollution Abatement, report new structures and/or equipment purchased to
reduce, monitor, or eliminate airborne pollutants, including particulate matter (dust, smoke, fly ash,
dirt, etc.), sulfur dioxides, nitrogen oxides, carbon monoxide, hydrocarbons, odors, and other
pollutants. Examples of air pollution abatement structures/equipment include flue gas particulate
collectors, FGD units, continuous emissions monitoring equipment (CEMs), and nitrogen oxide control
devices. Specify new structures/equipment in a comment on SCHEDULE 9.

9.

For column 8, Water Pollution Abatement, report new structures and/or equipment purchased to
reduce, monitor, or eliminate waterborne pollutants, including chlorine, phosphates, acids, bases,
hydrocarbons, sewage, and other pollutants. Examples include structures/equipment used to treat
thermal pollution; cooling, boiler, and cooling tower blowdown water; coal pile runoff; and fly ash waste
water. Water pollution abatement excludes expenditures for treatment of water prior to use at the
plant. Specify new structures/equipment in a comment on SCHEDULE 9.

17

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

10. For column 9, Solid/Contained Waste, report new structures/equipment purchased to collect and
dispose of objectionable solids or contained liquids. Examples include purchases of storage facilities,
trucks, etc., to collect, store, and dispose of solid/contained waste. Include equipment used for
handling solid/contained waste generated as a result of air and water pollution abatement. Specify
new structures/equipment in a comment on SCHEDULE 9.
11. For column 10, Other Pollution Abatement, report amortizable expenses and purchases of new
structures and or equipment when such purchases are not allocated to a particular unit or item.
Examples include charges for the purchases of facilities to control hazardous waste, radiation, and
noise pollution. Exclude all equipment purchased for aesthetics purposes. Specify new
structures/equipment in a comment on SCHEDULE 9.
12. If Byproduct Sales Revenue During Year items are not applicable, ENTER ZERO in Total, column
16, only. Report the revenue, if any, for each listed byproduct. Specify “other” revenue in a comment
on SCHEDULE 9. Entries must be compatible with the entries on SCHEDULE 8, PART A, “Sold”
column. If the revenue for a byproduct is less than $500, but more than zero dollars, enter a zero and
enter a comment on SCHEDULE 9 with the actual dollar amount. Revenue for gypsum should be
reported on SCHEDULE 8, PART B, column 14, with a comment on SCHEDULE 9. Report the total
revenue for the sale of byproducts in column 16. If the revenue reported was for the sale of stockpiled
byproducts from previous years, make a comment on SCHEDULE 9.
SCHEDULE 8. PART C. BOILER INFORMATION
NITROGEN OXIDE EMISSION CONTROLS
1.

No NOx Controls: Place a check in this box if the plant has no NOx control equipment or processes.

2.

Boiler ID: The boiler ID must match and correspond to the boiler ID and associated information
reported on the EIA-860. The boiler ID is prepopulated for e-file users. If it is not prepopulated, choose
the boiler ID from the drop down list. If the boiler ID is not on the list, contact EIA.

3.

NOx Control In-Service (hours): Enter the total hours the nitrogen oxide control was in service during
the reporting period (to the nearest hour).

4.

For Entire Year, enter the controlled nitrogen oxide emission rate, in pounds per million Btu of the
fuel, based on data from the continuous emission monitoring system (CEMS) where possible. Where
CEMS data are not available, report the controlled nitrogen oxide emission rate based on the method
used to report emissions data to environmental authorities.

5.

For May through September Only, enter the controlled nitrogen oxide emission rate, in pounds per
million Btu of the fuel, based on data from CEMS where possible. Where CEMS data are not
available, report controlled nitrogen oxide rates based on the method used to report emissions data to
environmental authorities. The summer emission rate may be assumed to be equivalent to the annual
emission rate where identical nitrogen oxide controls are used year round.

SCHEDULE 8. PART D. MONTHLY COOLING SYSTEM OPERATIONS
NOTE: All steam-electric plants of 100 MW nameplate capacity or greater, including combined cycle and
nuclear energy plants, must respond to this schedule. A separate page must be completed for each
month.
1.

If actual data are not available, provide an estimated value.

2.

If the source of cooling water is a well or municipal water system, do not complete the Cooling Water
Temperature sections.

3.

Cooling System ID or PLANT: The cooling system ID must match and correspond to the data
reported on the EIA-860. The ID is prepopulated for e-file users. If the ID is not prepopulated, choose
the ID from the drop down list. If the cooling system ID is not on the list, contact EIA to have new IDs
added. If the data to be reported are for the entire plant (because the data cannot be broken down by
separate cooling systems), choose “PLANT” from the drop-down list.

4.

Cooling System Status: Select from the equipment status codes on Table 4.

18

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

PRIME MOVER
CODES AND
DESCRIPTION

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Table 4

Code

5.

System Status

OP

Operating (in commercial service or out of service less than 365 days)

OS

Out of service (365 days or longer)

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)

Hours in Service: Enter the hours each cooling system was in service for the reporting

period..
6.

Monthly Amount of Chlorine Added to Cooling Water pertains solely to elemental chlorine. If a
compound is used, determine the amount of chlorine in the compound. Report amount of chlorine to
the nearest whole number in thousand pounds.

7.

Average Monthly Rate of Cooling Water data should be the rate of flow reported in cubic feet per
second (to the nearest 0.1 ft3 ). Diversion is the water moved from a watercourse without immediate
beneficial use, for purposes such as filling a cooling pond or adding water to a lake from which
thermoelectric power water withdrawals can occur. Withdrawal is the water removed from a water
body for beneficial use such as cooling water, boiler make-up water, ash sluicing, and dust
suppression. Discharge is the water returned to a water body, not necessarily the same water body
as the withdrawal. (Do not include water discharged to a recirculation pond that will be re-used at this
power plant.) Consumption is the water that is withdrawn from a water body and not returned
(discharged), because of evaporation losses and onsite consumption such as for dust control and flue
gas desulfurization.

8.

For Measured or Estimated, if all data reported under either the Average Monthly Rate of Cooling
Water section or the Intake or Discharge Temperature section have been measured, choose one of
the choices for “Measured” from the drop-down list. If one or more entries have been estimated in a
particular section choose one of the estimation methodologies given in the drop-down list for that
section. If “Other” is chosen, provide details of the estimation method on Schedule 9.

9.

For the Cooling Water Temperature sections, report the Average Monthly Temperature and the
Maximum Temperature for the Month in degrees Fahrenheit to the nearest whole number, measured
at the withdrawal point from the natural body of water or cooling pond in the case where water s first
divertedand discharge into the natural body of water.
SCHEDULE 8. PART E. FLUE GAS PARTICULATE COLLECTOR INFORMATION

1.

Flue Gas Particulate Collector ID: The flue gas particulate collector ID must match and correspond
to the data reported on the Form EIA-860. The ID is prepopulated for e-file users. For an ID not
prepopulated, choose the ID from the drop down list. If the ID is not on the list, contact EIA.

2.

FGP Collector Status: Select from the equipment status codes in Table 5.

19

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

ENERGY SOURCE
CODES AND HEAT
CONTENT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Table 5
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)

SC

Cold Standby (Reserve); deactivated (usually requires 3 – 6 months to reactivate)

TS

Operating under test conditions (not in commercial service)

3.

Hours in Service: Enter the hours each collector was in service for the reporting period.

4.

For Typical Particulate Emissions Rate, enter the particulate emission rate based on the annual
operating factor (to nearest 0.01 pound per million Btu).

5.

For Removal Efficiency of Particulate Matter at Annual Operating Factor and At 100-Percent
Load or Tested Efficiency, if the collector has a combination of components (i.e., a baghouse and an
electrostatic precipitator) enter both components as one unit in one column. If the particulate collector
also removes sulfur dioxide, enter the particulate scrubbing process in this section and the
desulfurization process on SCHEDULE 8, PART F, FLUE GAS DESULFURIZATION UNIT
INFORMATION ANNUAL OPERATIONS.

6.

For Removal Efficiency of Particulate Matter at Annual Operating Factor, enter removal efficiency
based on the annual operating factor. Annual operating factor is defined as annual fuel consumption
divided by the product of design firing rate and hours of operation per year. If actual data are
unavailable, provide estimates based on equipment design performance specifications.

7.

For At 100-Percent Load or Tested Efficiency, if the test was conducted, but not at 100-percent
load, enter the efficiency and provide the load at which the test was conducted in a comment on
SCHEDULE 9. If no test has been conducted, ENTER ZERO in the column and leave the test date
blank. Test results should not be reported if there was no test date.

8.

For Date of Most Recent Efficiency Test, enter test date. If an efficiency test has never been
performed, enter “NA” and enter a comment on SCHEDULE 9.
SCHEDULE 8. PART F. FLUE GAS DESULFURIZATION UNIT INFORMATION
ANNUAL OPERATIONS

1.

Flue Gas Desulfurization Unit ID: The flue gas desulfurization unit ID must match and correspond to
the data reported on the Form EIA-860. The ID is prepopulated for e-file users. For an ID not
prepopulated, choose the ID from the drop down list. If the ID is not on the list, contact EIA.

2.

Flue Gas Desulfurization Unit Status, as of January 1 following the end of the reporting year. Select
from the equipment status codes listed in Table 6.

20

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Table 6
Code

Status

CN

Cancelled (previously reported as “planned”)

CO

New unit under construction
Operating (in commercial service or out of service less than
365 days)
Out of service (365 days or longer)

OP
OS

Planned (on order and expected to go into commercial service
within 5 years)
Retired (no longer in service and not expected to be returned
to service)
Standby (or inactive service); i.e. not normally used, but
available for service
Cold Standby (Reserve); deactivated (usually requires 3 – 6
months to reactivate
Operating under test conditions (not in commercial service)

PL
RE
SB
SC
TS

3.

For Hours in Service, enter the total number of hours one or more trains (or modules) were in
operation; do not report for individual trains.

4.

Quantity of FGD Sorbent Used: Enter the quantity of FGD sorbent used during the reporting period
(to the nearest 0.1 thousand tons).

5.

Electrical Energy Consumption: Enter the Electrical Energy Consumed by this Unit during the
reporting period (in megawatthours).

6.

For Estimated Removal Efficiency for Sulfur Dioxide at Annual Operating Factor and At 100
Percent Load or Tested Efficiency, if the FGD unit also removes particulate matter, enter the
desulfurization process in this section and the particulate scrubbing process on SCHEDULE 8. PART
E, FLUE GAS PARTICULATE COLLECTOR INFORMATION.

7.

For Estimated Removal Efficiency for Sulfur Dioxide at Annual Operating Factor, enter removal
efficiency based on the annual operating factor. Annual operating factor is defined as annual fuel
consumption divided by the product of design firing rate and hours of operation per year. If actual
data are unavailable, provide estimates based on equipment design performance specifications.

8.

For Estimated Removal Efficiency for Sulfur Dioxide at 100-Percent Load or Tested Efficiency, if
the test was conducted, but not at 100-percent load, enter the efficiency, and provide the load at which
the test was conducted in a comment on SCHEDULE 9. If no test was conducted, enter zero for the
efficiency and leave the test data blank. Test results should not be given without a test date.

9.

Report the Operation and Maintenance Expenditures during the Year, excluding electricity, in
thousand dollars.
SCHEDULE 9. COMMENTS

This schedule provides additional space for comments. Please identify schedule, item, and identifying
information (e.g., plant code, boiler ID, generator ID, prime mover) for each comment. If plant is sold,
provide purchaser’s name, a telephone number (if available), and date of sale.

21

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Table 7
Prime Mover Code

Prime Mover Description

BT

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

CA

Combined-Cycle – Steam Part

CE

Compressed Air Energy Storage

CP

Energy Storage, Concentrated Solar Power

CS

Combined-Cycle Single-Shaft Combustion turbine and steam turbine
share a single generator

CT

Combined-Cycle Combustion Turbine Part

FC

Fuel Cell

GT

Combustion (Gas) Turbine (including jet engine design)

HA

Hydrokinetic, Axial Flow Turbine

HB

Hydrokinetic, Wave Buoy

HK

Hydrokinetic, Other

HY

Hydraulic Turbine (including turbines associated with delivery of water by
pipeline)

IC

Internal Combustion (diesel, piston) Engine

OT

Other – Specify on SCHEDULE 9.

PS

Hydraulic Turbine – Reversible (pumped storage)

PV

Photovoltaic

ST

Steam Turbine (including nuclear, geothermal and solar steam, excluding
combined-cycle)

WT

Wind Turbine

22

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Table 8
“Higher Heating Value”
Range
Energy
Source
Code

Unit
Label

MMBtu
Lower

Energy Source Description

MMBtu
Upper
Fossil Fuels

Coal

Petroleum
Products

Natural Gas
and Other
Gases

ANT

tons

22

28

Anthracite Coal

BIT

tons

20

29

Bituminous Coal

LIG

tons

10

14.5

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)

RC

tons

20

29

Refined 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

KER

barrels

5.6

6.1

Kerosene

PC

tons

24

30

Petroleum Coke

RFO

barrels

5.8

6.8

WO

barrels

3.0

5.8

BFG

Mcf

0.07

0.12

Blast Furnace Gas

NG

Mcf

0.8

1.1

Natural Gas

OG

Mcf

0.32

3.3

Other Gas (specify in Comment Section of
SCHEDULE 9)

PG

Mcf

2.5

2.75

Gaseous Propane

SG

Mcf

0.2

1.1

Synthetic Gas

SGC

Mcf

0.2

0.3

Coal-Derived Synthetic Gas

Lignite Coal

Jet Fuel

Residual Fuel Oil (including No. 5 and No. 6 fuel
oils, and bunker C fuel oil.
Waste/Other Oil (including crude oil, liquid butane,
liquid propane, oil waste, re-refined motor oil, sludge
oil, tar oil, or other petroleum-based liquid wastes)

Renewable Fuels

Solid
Renewable
Fuels

AB

tons

7

18

MSW

tons

9

12

OBS

tons

8

25

WDS

tons

7

18

23

Agricultural By-Products
Municipal Solid Waste
Other Biomass Solids (specify
in Comment Section of
SCHEDULE 9)
Wood/Wood Waste Solids (including paper
pellets, railroad ties, utility poles, wood chips,
bark, and wood waste solids)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Table 8 Continued

Energy
Source
Code

“Higher Heating
Value” Range
Unit
Label

Energy Source Description
MMBtu
Lower

MMBtu
Upper

Renewable Fuels (cont.)
OBL
Liquid
Renewable
(Biomass)
Fuels

Gaseous
Renewable
(Biomass)
Fuels

All Other
Renewable
Fuels

barrels

3.5

4

Other Biomass Liquids (specify in Comment
Section of SCHEDULE 9)

SLW

tons

10

16

Sludge Waste

BLQ

tons

10

14

Black Liquor

WDL

barrels

8

14

Wood Waste Liquids excluding Black Liquor
(includes red liquor, sludge wood, spent sulfite
liquor, and other wood-based liquids)

LFG

Mcf

0.3

0.6

Landfill Gas

OBG

Mcf

0.36

1.6

Other Biomass Gas (includes digester gas,
methane, and other biomass gasses)
(specify in Comment Section of SCHEDULE 9)

SUN
WND
GEO

N/A
N/A
N/A

0
0
0

0
0
0

WV

N/A

0

0

CUR
TID

N/A
N/A

0
0

0
0

WAT

N/A

0

0

Solar
Wind
Geothermal
Water used in Wave Buoy Hydrokinetic
Technology
Water used in Current Hydrokinetic Technology
Water used in Tidal Hydrokinetic Technology
Water at a Conventional
Hydroelectric Turbine

All Other Fuels
Pumping Energy for Reversible (Pumped
Storage) Hydroelectric Turbine

WAT

MWh

0

0

N/A

MWh

0

0

NUC

N/A

0

0

PUR

N/A

0

0

Purchased Steam
Waste heat not directly attributed to a fuel
source (WH should only be reported where the
fuel source for the waste heat is undetermined,
and for combined cycle steam turbines that do
not have supplemental firing.)

All Other
Fuels

Compressed Air
Nuclear Uranium, Plutonium, Thorium

WH

N/A

0

0

TDF

tons

16

32

Tire-derived Fuels

OTH

N/A

0

0

Specify in Comment Section of SCHEDULE 9.

24

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT INSTRUCTIONS

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

GLOSSARY
The glossary for this form is available online at the following URL: http://www.eia.gov/glossary/index.html

SANCTIONS
The timely submission of Form EIA-923 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

DISCLOSURE
OF INFORMATION

Public reporting burden for this collection of information is estimated to average 2.7 hours per response for
monthly respondents, 3.2 hours per response for annual respondents, and 3.4 hours per response for
annual respondents with boiler level data, including the time for reviewing instructions, searching existing
data sources, gathering and maintaining the data needed, and completing and reviewing the collection of
information. The weighted average burden for the Form EIA-923 is 2.8 hours per response. Send
comments regarding this burden estimate or any other aspect of this collection of information, including
suggestions for reducing this burden, to the EIA, Statistics and Methods Group, EI-70, 1000 Independence
Avenue S.W., Forrestal Building, Washington, D.C. 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.

The “Total Delivered Cost” of coal, natural gas, and petroleum received at nonutility power plants and
“Commodity Cost” information for all plants in SCHEDULE 2 and “Previous Month’s Ending Stocks” and
“Stocks at End of Reporting Period” information reported on SCHEDULE 4 will be protected and not
disclosed to the extent that it satisfies the criteria for exemption under the Freedom of Information Act
(FOIA), 5 U.S.C. §552, the Department of Energy (DOE) regulations, 10 C.F.R. §1004.11, implementing
the FOIA, and the Trade Secrets Act, 18 U.S.C. §1905. All other information reported on Form EIA-923 is
considered public information and may be publicly released in company identifiable form.
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 non-statistical purposes such as administrative, regulatory, law
enforcement, or adjudicatory purposes.
Disclosure limitation procedures are applied to the protected statistical data published from SCHEDULES
2 and 4 on Form EIA-923 to ensure that the risk of disclosure of identifiable information is very small.

25

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

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 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: ___________________________________________
Telephone (include extension): _______________________

Fax: __________________________________________

Email: __________________________________________
Address: ________________________________________

City: __________________________________________

State: ___________________________________________

Zip: ___________________________________________

Supervisor of Contact Person for Survey
First Name: ______________________________________

Last Name: ____________________________________

Title: ___________________________________________
Telephone (include extension): _______________________

Fax: __________________________________________

Email: __________________________________________
Address: ________________________________________

City: __________________________________________

State: ___________________________________________

Zip: ___________________________________________

Report For
Company Name: ___________________________________________
Plant Name: _______________________________________________

Regulated

□ Yes □ No

Plant ID: ___________ Plant County: ___________________________

CHP

□ Yes □ No

Address: __________________________________________________

CHP Efficiency

City: ___________________________

Zip Code: ____________

State: __________________

%

Reporting Month/Year: _______________________________________

Contacts
For questions related to E-filing:

[email protected]

202-586-9595

For questions about the data requested on this form:
Schedules 1 & 4:

Chris Cassar

[email protected]

202-586-5448

Schedule 2:

Rebecca Peterson

[email protected]

202-586-4509

Schedules 3 & 5:

Ron Hankey

[email protected]

202-586-2630

Schedules 6, 7, & 8:

Channele Wirman

[email protected]

202-586-5356

EIA-923 Fax:

202-287-1959 or 202-287-1960

EIA-923 Mailbox:

[email protected]

1

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 2. PAGE 1. COST AND QUALITY OF FUEL PURCHASES – PLANT LEVEL
CONTRACT INFORMATION, RECEIPTS, AND COSTS
For fossil-fueled plants 50 megawatts and above

□ Is there a fuel tolling agreement in place for this plant? (If

□ No Receipts (If applicable, please check.)

applicable, please check.)

Contract Information

Fuel Supplier Name

Receipts

Contract
Contract
Type
Expiration Date

2

Energy
Source

Cost per Unit

Quantity
Total Delivered
Commodity Cost
Purchased
Cost
(Coal, Natural Gas)
(solids in tons, (cents per MMBtu, (cents per MMBtu,
to the nearest
to the nearest
liquids in barrels,
gases in Mcf)
0.1)
0.1)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 2. PAGE 2. COST AND QUALITY OF FUEL PURCHASES – PLANT LEVEL
QUALITY OF FUEL AND TRANSPORTATION
For fossil-fueled plants 50 megawatts and above

Purchases

Quality of Fuel as Received

All Fuels

Carried Forward from Schedule 2. Page 1.

Fuel Supplier
Name

Contract
Type

Energy
Source

50

4

8

Coal, Pet
Coke,
RFO, and
WO

Sulfur
Heat
Content
Quantity
Content
(percent
Purchased (MMBtus to
weight to
nearest
nearest
0.001)
0.01)

3

13

6

3

Fuel Transportation

Coal and
Pet Coke

Coal Only Natural Gas

Ash
Content
(percent
weight to
nearest
0.1)

Predomin
Mercury
ant Mode
Content
(Mode
(ppm to
used to
nearest
Firm or
transport
0.001 or
Interruptible fuel over
enter 9 if
the
not
longest
available)
distance)

6

6

1

Coal, Pet Coke,
and Oil

2

Secondary
Mode
(Mode used
to transport
fuel over the
secondlongest
distance)

2

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 2. PAGE 3. COST AND QUALITY OF FUEL PURCHASES – PLANT LEVEL
COAL MINE INFORMATION
For fossil-fueled plants 50 megawatts and above

Purchases Information

Coal Mine Information

Carried Forward from Schedule 2. Page 1.

Fuel Supplier Name

Contract Type

Energy Source

Quantity
Purchased

50

4

8

3

4

Coal Mine State

Coal Mine
MSHA ID

Coal
Mine
Type

8

40

3

Coal
Mine
Name

Coal Mine
County
(for imported
coal, enter
IMP)

2

5

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 3. PART A. BOILER INFORMATION FOR STEAM-ELECTRIC ORGANIC-FUELED
PLANTS — FUEL CONSUMPTION

This schedule will be completed by plants with a total steam turbine capacity of 10 megawatts and above that burn organic fuels.
Report only fuels consumed in the boilers, or for HRSGs in duct burners. If no fuel is consumed for the HRSG at combined cycle
plants, report zero. Do not leave blank. Report consumption in combustion turbines or IC engines on SCHEDULE 3. PART B.
If this does not apply, go to SCHEDULE 3. PART B.
Complete a separate row for each Boiler ID.

□

Did any boiler produce steam for purposes other than electric power generation during this reporting period?
(If applicable, please check.)

Energy Source

Prime
Mover Boiler ID
Code

Boiler
Status

(See Table 8
on pages
22 through
23 in the
Instructions.)

Quantity
Consumed
(Enter zero when
a fuel has no
consumption for
this
reporting period)

Type of
Physical
Units
(tons,
barrels,
or Mcf)

Average
Heat Content
(as burned, to
nearest 0.001
MMBtu per
ton, barrel, or
Mcf)

Sulfur
Content

Ash
Content

(coal, pet coke,
RFO, and WO,
to nearest
0.01%)

(coal and
PC only, to
nearest
0.1%)

If you reported the category of OTH, OBS, OBG, OBL, or OG in the Energy Source column, please identify the category and
specific fuel name below. For example, “The OBG gas is methane.”
_ ___________________________________________________________________________________.

5

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 3. PART B. FUEL CONSUMPTION – PRIME MOVER LEVEL

Report fuel consumed by plants with organic-fueled steam and combined cycle steam capacity under 10 MW, and all combustion
turbines, IC engines, fuel cells, pumped storage hydroelectric units and compressed air units. Aggregate quantity consumed for
prime movers of a single type. In other words, all natural gas consumed by all combustion gas turbines should be reported as one
number. Report pumping energy in megawatthours for pumped-storage plants and compressed air units.
Complete a separate row for each Prime Mover Type. (See Table 7 of the instructions.).

□

Was steam produced for purposes other than electric power generation during this reporting period?
(If applicable, please check.)

Prime Mover Code

Energy Source

(See Table 8 on pages 22
through 23 in the
Instr
ctions.)

Quantity Consumed
(Enter zero when a fuel has
no consumption for this
reporting period.)

Type of
Physical Units

Average Heat
Content

(tons, barrels,
or Mcf)

(MMBtu
per ton, barrel,
or Mcf)

If you reported the category of OTH, OBS, OBG, OBL, or OG in the Energy Source column, please identify the category and
specific fuel name below. For example, “The OBG gas is methane.”

_________________________________________________________________________________________________

6

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 4. FOSSIL FUEL STOCKS AT THE END OF THE REPORTING PERIOD AND DATA BALANCE
For Coal, Oil, and Natural Gas Plants
Report stocks for the following fuels:
Coal (tons)
Residual oil (No. 5 and No. 6 fuel oils) (barrels)
Distillate-type oils (including diesel oil, No. 2 oil, jet fuel and kerosene) (barrels)
Petroleum coke (tons)
Include back-up fuels.
Include start-up and flame-stabilization fuels.
Do not report stocks for waste coal, natural gas, or wood waste. Do enter a comment if the natural gas balance does not equal zero.
Stocks held off-site that cannot be assigned to an individual plant are to be reported as stocks held at a central storage site. Each
central storage site must be reported separately. New sites should be indicated in the Comment Section, located in SCHEDULE
9 of this form.
Enter zero if the plant has no stocks. Do not leave blank.
Enter adjustments to stocks. An adjustment can be positive or negative. See instructions for additional information. Provide a
comment to explain adjustments in the adjustments grid.
Enter a comment if the balance does not equal zero in the balance grid.
Energy Source
(See Table 8 in
the Instructions.)

Type of Physical
Units
(tons, barrels, or
Mcf)

Previous
Month’s Ending
Stocks
(1)

Current Month’s
Receipts (2)

Current Month’s
Consumption
(3)

Ending Stocks
(4)

Adjustment to
Stocks* (5)

Balance** (6)
4=(1+2-3+5)

*Explain any adjustments below.
Adjustment
(from Column 5 above)

Energy Source

Explanation

**Previous Month’s Stocks plus Receipts minus Consumption plus (or minus) Adjustment should equal Ending Stocks. The balance
will appear in column (6). If the balance is not zero, provide an explanation below.
Balance
(from Column 6 above)

Energy Source

Explanation

7

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 5. PART A. GENERATOR INFORMATION FOR STEAM-ELECTRIC
ORGANIC-FUELED PLANTS

This schedule will be completed ONLY for generators at steam-electric organic-fueled plants with a total steam turbine capacity of
10 megawatts and above. Report generation for all other types of prime movers (combustion turbines, IC engines, wind, or hydroelectric turbines, and compressed air units.), and steam turbine plants with less than 10 megawatts total capacity or fueled by
nuclear, solar, geothermal, or other energy sources on SCHEDULE 5. PARTS B or C. Generation reported on SCHEDULE 5,
Part A corresponds to the fuel consumption reported on SCHEDULE 3. Part A.
Industrial or Commercial Sector plants may report gross generation ONLY if net generation is not measured (see instructions for
definition of net generation).
Complete a separate row for each Generator ID. See Generator ID information in the instructions for Schedule 5. Part A.

Prime
Mover
Code

Generator
ID

Generator
Status

Gross Generation
(MWh)

8

Net Generation
(MWh)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 5. PART B. PRIME MOVER LEVEL GENERATION

This schedule will be completed ONLY by steam-electric organic-fueled plants with a total steam turbine capacity less than 10
megawatts, by combined-cycle plants whose steam portion of the operation is under 10 MW, and all IC engines, fuel cells,
combustion turbines, pumped-storage hydroelectric turbines, and compressed air units. Generation reported on this schedule
corresponds to the fuel consumption reported on SCHEDULE 3. Part B.
In the applicable Gross Generation or Net Generation cell, enter the aggregate generation for prime movers of a single type. For
example, enter the total generation from all combustion turbines. Industrial or Commercial Sector plants may report gross
generation ONLY if net generation is not measured (see instructions for definition of net generation).
Complete a separate row for each Prime Mover Type. (See Table 7 of the instructions.)

Prime Mover Code

Gross Generation
(MWh)

9

Net Generation
(MWh)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 5. PART C. GENERATION FROM NUCLEAR AND OTHER NONCOMBUSTIBLE ENERGY SOURCES

This schedule will be completed by all nuclear plants and by all wind, solar, geothermal, hydroelectric, or other plants where the
energy source is noncombustible, such as purchased steam or waste heat. No fuel consumption is required for these types of
plants. Report generation by energy source for nuclear, wind, solar, geothermal, conventional hydroelectric and miscellaneous
sources such as purchased steam or waste heat. Do not report generation at a combined-cycle plant. All combined-cycle
generation is reported on SCHEDULE 5. PART A or B. Report nuclear data by generating unit.
In the applicable Gross Generation or Net Generation cell, enter the aggregate generation for prime movers of a single type. For
example, enter the total generation from all combustion turbines. Industrial or Commercial Sector plants may report gross
generation only if net generation is not measured (see instructions for definition of net generation).
Complete a separate row for each Prime Mover Type. (See Table 7 of the instructions.)

Prime
Mover
Code

Energy
Source

Unit Code
(nuclear)

Gross Generation
(MWh)

10

Net Generation
(MWh)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

POWER PLANT OPERATIONS
REPORT

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 6. NONUTILITY ANNUAL SOURCE AND DISPOSITION OF ELECTRICITY

SCHEDULE 6 collects calendar year data (no monthly detail).
Report all generation in megawatthours (MWh) rounded to a whole number.

Source of Electricity

Disposition of Electricity

(1) Gross Generation (Annual)

(4) Station Use

(2) Other Incoming Electricity

(5) Direct Use (Industrial and Commercial
Sector Plants, both CHP and non-CHP)
(6) Total Facility Use (4 + 5)
(7) Retail Sales to Ultimate Customers
(8) Sales for Resale
(9) Other Outgoing Electricity

(3) Total Sources (1 + 2)

(10) Total Disposition (6 + 7 + 8 + 9)
Total Sources must equal Total Disposition (3 = 10)

11

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 7. ANNUAL REVENUES FROM SALES FOR RESALE

SCHEDULE 7 is to be completed by respondents who entered a positive amount on SCHEDULE 6, Disposition of Electricity, Item 8,
Sales for Resale.
Sales for Resale is energy supplied to other electric utilities, cooperatives, municipalities, Federal and State electric agencies, power
marketers, or other entities for resale to end-use consumers.

Annual Revenues from Sales for Resale (in thousand dollars): ____________________

12

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 8. ANNUAL ENVIRONMENTAL INFORMATION
SCHEDULE 8. PARTS A through F are filed annually by thermoelectric power plants (organic fueled, nuclear, and combined cycle)
with a total steam turbine capacity of 10 megawatts and above (plants that reported on SCHEDULE 3. Part A and SCHEDULE 5 Part
A.). Plants with a total steam turbine capacity of 10 megawatts to less than 100 MW file only Parts C, E, and F.

SCHEDULE 8. PART A. ANNUAL BYPRODUCT DISPOSITION

Enter the quantity of combustion byproducts for the year by type of disposal (to nearest 0.1 thousand tons). Report sales of steam
in million Btu (MMBtu). If actual data are not available, provide an estimated value.

□

NO BYPRODUCTS

Disposal

Sale or Beneficial Use

Storage

Byproduct

Total
On-Site
Landfill

On-Site
Ponds

Disposal
Off-site

Fly ash from standard boiler/PCD
units
Fly ash from un
ts with dry FGD
Fly ash from FBC units
Bottom ash from standard boiler
units
Bottom (bed) ash from FBC units
FGD Gypsum
Other FGD byproducts
Ash from coal gasification (IGCC)
units
Other (specify via footnote on
SCHEDULE 9)
Steam Sales (MMBtu)

13

Sold

Used
On-site

Used
Off-site

Stored
O
-site

Stored
Off-site

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 8. PART B. FINANCIAL INFORMATION RELATED TO COMBUSTION BYPRODUCTS

If actual data are not available, provide an estimated value.

Operation and Maintenance (O&M) Expenditures During Year (Thousand Dollars)

Type

(1)
Fly Ash

(2)
Bottom Ash

(3)
Flue Gas
Desulfurization

(4)
Water
Pollution
Abatement

(5)
Other Pollution
Abatement

(6)
Total
(1 + 2 + 3 + 4 + 5)

Collection
Disposal
Other
Capital Expenditures for New Structures and Equipment During Year, Excluding Land and Interest Expense
(Thousand Dollars)

Type

(7)
Air Pollution
Abatement

(8)
Water Pollution
Abatement

(9)
Solid/Contained Waste

(10)
Other Pollution Abatement

Amount
Byproduct Sales Revenue During Year
(Thousand Dollars)

Type

(11)
Fly Ash

(12)
Bottom Ash

(13)
Fly and Bottom
Ash Sold
Intermingled

Amount

14

(14)
Flue Gas
Desulfurization
Byproducts

(15)
Other
Byproduct
Revenue

(16)
Total
(11+12+13+14+15)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 8. PART C. BOILER INFORMATION NITROGEN OXIDE EMISSION CONTROLS

Complete a separate row for each boiler.
Note: The Boiler ID must match the Boiler ID as reported on Form EIA-860, "Annual Electric Generator Report."

□

No NOx Controls

NOx Emission Rate (lbs/MMBtu)
Boiler ID

NOx Control In-Service
(hours)
Entire Year

15

May through September

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: _____________________________________________________________________________________________________________________
Plant ID: ________________________________________

State: __________________________

Reporting Year: _______________________

SCHEDULE 8. PART D. MONTHLY COOLING SYSTEM INFORMATION
Reporting Month:__________________
Note: All steam-electric plants of 100 MW nameplate capacity or greater, including combined cycle plants and nuclear power plants, must respond to this schedule. Cooling System ID must
match the ID as reported on Form EIA-860, "Annual Electric Generator Report.” Complete a separate page for each month. Complete a separate row for each cooling system.

Cooling
System
ID or
Plant

Cooling
System
Status

Monthly
Amount
of
Chlorine
Added to
Cooling
Water
(1000 lbs)

Average Monthly Rate of Cooling Water
3
(in cubic feet per second, to the nearest 0.1 ft )
Hours in
Service
Diversion

Withdrawal

Discharge

Cooling Water
Temperature at Intake
(degrees Fahrenheit)

Measured or
Estimated? (If any
Average
Maximum
Consumption flow rate data was
Monthly
Temperature
estimated, select
Temperature for the Month
methodology.)

16

Cooling Water Temperature
at Discharge Outlet
(degrees Fahrenheit)

Average
Monthly
Temperature

Maximum
Temperature
for the Month

Measured or
Estimated? (If
any temperature
data was
estimated, select
methodology.)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ___________________________________________________________________________________________________________________
Plant ID: ________________________________________

State: __________________________

Reporting Year: _____________________________

SCHEDULE 8. PART E. FLUE GAS PARTICULATE COLLECTION INFORMATION

□ Does not apply.
Complete a separate row for each flue gas particulate collector.

Flue Gas
Particulate
Collector ID

FGP Collector
Status

Hours in
Service

Typical Particulate
Emissions Rate
(to the nearest 0.01
lb/MMBtu)

Removal Efficiency of Particulate Matter (nearest 0.1% by weight)

At Annual Operating
Factor

17

At 100% Load or
Tested Efficiency

Date of Most Recent
Efficiency Test (e.g., 12-2005)

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: _____________________________________________________________________________________________________________________
Plant ID: __________________________________

State: __________________________

Reporting Year: ___________________________________

SCHEDULE 8. PART F. FLUE GAS DESULFURIZATION UNIT INFORMATION – ANNUAL OPERATIONS
Note: Flue Gas Desulfurization ID must match the ID as reported on Form EIA-860, "Annual Electric Generator Report.”

□ Does not apply.

Complete a separate row for each Flue Gas Desulfurization Unit.
ANNUAL OPERATIONS

Flue Gas
Desulfurization Unit
ID

FGD Unit
Status

Hours InService

Quantity of FGD
Sorbent Used
(to the nearest 0.1
thousand tons)

Electrical Energy
Consumption
(MWh)

Removal Efficiency of Sulfur Dioxide (nearest 0.1% by wt)
At Annual Operating
Factor

At 100% Load or
Tested Efficiency

Date of Most Recent Efficiency
Test (e.g., 12-2005)

OPERATION AND MAINTENANCE EXPENDITURES DURING YEAR, EXCLUDING ELECTRICITY (THOUSAND DOLLARS)

Flue Gas
Desulfurization Unit
ID

Feed Materials
and Chemicals

Labor and
Supervision

Waste Disposal

18

Maintenance, Materials,
and All Other Costs

Total

U.S. Department of Energy
U.S. Energy Information Administration
Form EIA-923 (2011)

POWER PLANT OPERATIONS
REPORT

Form Approval
OMB No. 1905-0129
Approval Expires: 12/31/2013
Burden: 2.8 Hours

Plant Name: ____________________________________________________________________
Plant ID: _________________________________

State: ______

Reporting Month/Year: ____________________

SCHEDULE 9. COMMENTS

Comment Section: Explain any unusual values, occurrences, or changes in ownership.

Schedule

Part

Item

Comment

Changes in Ownership
(Provide name of purchaser and date sold.)

19