Electric Power Surveys

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
8

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
(+/-) 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
Burden: 17 hours

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

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
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.

11

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.

13

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

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

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.
17

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
• 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