FERC-714 (Annual Electric Balancing Authority Area and Planning Area Report)

Form 714 - Annual Electric Balancing Authority Area
and Planning Area Report Instructions
Table of Contents
I. General Information ...................................................................................... 1
A. Purpose ................................................................................................... 1
B. Who Must Submit ..................................................................................... 2
C. How to Submit ......................................................................................... 3
D. When to Submit ....................................................................................... 3
E. Sanctions and Confidentiality Statements .................................................... 3
II. General Instructions ..................................................................................... 3
III. Definitions ................................................................................................. 4
IV. Specific Instructions .................................................................................... 6
A. Part I Schedule 1: Identification and Certification ......................................... 6
B. Part II: Balancing Authority Areas ............................................................... 7
i. Schedule 1. Generating Plants Included in Reporting Balancing Authority Area
.............................................................................................................. 7
ii. Schedule 2. Balancing Authority Area Monthly Capabilities at Time of Monthly
Peak Demand ........................................................................................... 8
iii. Schedule 3. Balancing Authority Area Net Energy for Load and Peak Demand
Sources by Month ................................................................................... 11
iv. Schedule 4 Instructions: Adjacent Balancing Authority Area Interconnections
............................................................................................................ 12
v. Schedule 5 Instructions: Balancing Authority Area Scheduled and Actual
Interchange ........................................................................................... 13
vi. Schedule 6 Instructions: Balancing Authority Area Hourly System Lambda 13
C. PART III: Planning Areas ......................................................................... 15
i. Schedule 1. Electric Utilities that Compose the Planning Area..................... 15
ii. Schedule 2. Planning Area Hourly Demand and Forecast Summer and Winter
Peak Demands and Annual Net Energy for Load .......................................... 15
D. Part IV. Footnotes. ................................................................................ 15

I. General Information
A. Purpose
The FERC Form 714 (Form 714) collects information for the
Federal Energy Regulatory Commission (FERC, Commission)
from electric utility balancing authority and planning areas in
the United States. The Form 714 is authorized by the Federal
Power Act and is a regulatory support requirement as provided
by 18 CFR § 141.51. The data will be used to obtain a broad
picture of interconnected balancing authority area operations
including comprehensive information of balancing authority
area generation, actual and scheduled inter-balancing authority
area power transfers, and load; and to prepare status reports
on the electric utility industry including review of interbalancing authority area bulk power trade information. Planning
area data will be used to monitor forecasted demands by

electric utility entities with fundamental demand responsibility,
and to develop hourly demand characteristics.
B. Who Must Submit
The schedules in this report shall be completed as follows:
i. Each balancing authority area must file Parts I,
II and IV.
These parts shall be completed by each electric
utility that operates a balancing authority area
and each group of electric utilities, which are
bound together through pooling contracts,
holding company operations or other contractual
arrangements that operate a balancing authority
area. In each balancing authority area there is
generally one electric utility charged with
operating the balancing authority area and its
associated automatic generation balancing
authority equipment. It is this utility that should
complete Part I, II and IV. In some large power
pools, the balancing authority area may be
operated by an agency designated by the
members, or by a holding company subsidiary. In
these cases, these parts should be completed by
the organization responsible for operating the
balancing authority area. Electric utilities owning
one or more generating plants located outside
their balancing authority area, where the output
is received and controlled by some other electric
utility, should exclude such plants from
consideration on Part II. The information
pertaining to the excluded plant must be reported
by the electric utility in whose area the plant is
controlled.
ii. Each electric utility with its planning area
annual peak demand greater than 200 megawatts
(MW) must file Parts I, III and IV.
Respondents should be those electric utilities
charged with carrying out the resource planning
and demand forecasts for the planning area. A
typical respondent is an electric utility that is the
principal resource planning and forecasting entity
with an obligation to serve the planning area
demands. The respondent could be supplying full
and partial requirements wholesale power to
other electric utilities.
In many instances, the information to be
reported in Form 714 will have been reported to
the respondent's regional reliability council.
However, only utilities subject to the reporting
requirements may submit a Form 714. Entities
that are neither balancing authority area
operators nor planning area operators, but who

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are authorized by their members to compile Form
714 data on their behalf, are required to make
the data available to their balancing authority
area operators and planning area operators in
order that those area operators may file the data
with the Commission.
C. How to Submit
Submit this form electronically through the Form 714
Submission Software. Retain one copy of the report for your
files. For any resubmissions, submit the filing using the Form
714 Submission Software.
D. When to Submit
Submit this form on or before June 1 of the year following the
calendar reporting year. Note: A one-time extension was
given to July 16, 2007, to file the 2006 calendar year report.
E. Sanctions and Confidentiality Statements
This report is mandatory under the Federal Power Act. Late
filing or failure to file, keep records, or comply with these
instructions may result in criminal fines, civil penalties, and
other sanctions as provided by law. Data reported on the Form
714 are not confidential.
II. General Instructions
Conducting a valid survey requires that all respondents provide data
using the same frame of reference. Therefore, we need your help.
Please thoroughly familiarize yourself with all of the data requested on
this form and their applicable definitions and instructions BEFORE you
begin to provide any of the data.
Report in whole numbers (no decimal values); the only exception is
reporting system lambda data in Part II – schedule 6 where 2 decimal
places are required.
Use a minus sign when reporting negative numbers.
Furnish information for the balancing authority area or planning area
as it existed at the end of the calendar year (December 31). If part of
the system was acquired during the year, report for that part of the
system for the entire year, obtaining the information from the previous
owner. If part of the system was disposed of during the year, and the
respondent was not operating that part of the system at the end of the
year, do not report on that part of the system.
Some utilities, particularly municipal and other government-operated
utilities, maintain records on other than a calendar year basis.
Whenever this form requests annual data, please provide such data on
a calendar year basis. If monthly data are requested, please provide
such data for the month and year indicated, not for the corresponding
month within the fiscal year.

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III. Definitions
A. Actual Interchange
Metered electricity that flows from one balancing authority area
to another.
B. Available Capability
The maximum load-carrying ability exclusive of station use and
planned, unplanned or other outage or derating.
C. Coincident Peak Demand
Sum of two or more demands on individual systems that occur
in the same demand interval.
D. Balancing Authority Area
The area operator that is responsible for matching generation
and load, responsible for maintaining scheduled interchange
with other balancing authority areas, and that is responsible for
maintaining the frequency in real-time, of the electric power
systems.
E. Demand
The rate at which electric energy is delivered to or by a system,
part of a system, or piece of equipment, at a given instant or
averaged over any designated period of time.
F. Dynamically-Scheduled Plant
An electric generating plant in another balancing authority area
whose output matches a continuously adjusted schedule in real
time effectively making the plant a part of the respondent's
balancing authority area.
G. Electric System
The physically connected generation, transmission, distribution
and auxiliary facilities that are operated as an integrated unit
under single balancing authority, management, or operating
supervision. For purposes of this report, electric system may
consist of one or more electric utilities. An "electric utility"
means a corporation, person, agency, authority, or other legal
entity or instrumentality that owns and/or operates facilities
within the United States for the generation, transmission,
distribution, or sale of electric energy primarily for use by the
public.
H. Firm Capability (Unit/System)
The commitment of generation service to a customer under a
contractual agreement to which the parties to the service
anticipate no planned interruption. The allocation of the utility's
resources may be system wide, or only for a named unit; the
time of availability is usually prescribed as well.
I. Firm Power (Sales/Purchases)

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Electric power intended to meet the demand requirement of a
utility's customers; there is no planned interruption of service
with this type of sale/purchase. Utilities may sell/buy capacity
for a limited duration and time to other utilities.
J. Full Requirements Customer
A wholesale customer without other generating resources
whose electric energy supplier is the sole source of long-term
firm power for the customer's service area. The terms and
conditions of sale are equivalent to the supplier's obligations to
its own retail service, if any.
K. Interchange
Electricity that flows from one balancing authority area to
another.
L. Load
The amount of electrical power delivered or required at any
specified point or points on a system. The requirement
originates at the energy-consuming equipment of the customer.
M. Net Capability
The maximum load-carrying ability, exclusive of station use,
under specified conditions for a given time interval independent
of the characteristics of the demand. (Capability is determined
by design characteristics, physical condition, adequacy of prime
mover, energy supply, and operating limitations such as cooling
and circulating water supply and temperature, headwater and
tailwater elevations, and electrical use.)
N. Net Energy for Load (Generic)
This is the electric energy requirements of the system, which is
defined as the system net generation plus energy received from
others less energy delivered to others. It includes system losses
but excludes energy required for the filling of reservoirs at
pumped-storage plants.
O. Net Energy for Load (Balancing Authority Area)
The net generation plus actual interchange received minus
actual interchange delivered within the boundaries of the
balancing authority area.
P. Net Energy for Load (Planning Area)
The amount of energy required by the reported utility or group
of utilities' retail customers in the system's service area plus
the amount of energy supplied to full and partial requirements
utilities (wholesale requirements customers) plus the amount of
energy losses incurred in the transmission and distribution.
Q. Net Generation
Gross generation less plant use, measured at the high-voltage
terminals of the station's step-up transformer. The energy
required for pumping at pumped-storage plants is regarded as

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plant use and must be deducted from the gross generation.
Generation from auxiliary and start-up generators should not
be reported.
R. Other Outage and Derating
Refers to generators that are normally in an operating or
stand-by status, but are unavailable for all reasons other than
planned and unplanned outages, including transmission
limitations at the generating plant, disruptions in fuel supplies
of energy sources, environmental considerations etc.
S. Partial Requirements Customer
A wholesale customer with generating resources insufficient to
carry all its demand and whose energy seller is a long-term
firm power source supplemental to the customer's own
generation or energy received from others. The terms and
conditions of sale are similar to those for a full requirements
customer.
T. Peak Demand
The largest electric power requirement (based on net energy
for load) during a specific period of time, usually integrated
over one clock hour and expressed in megawatts (MW).
U. Planned Outage and Derating
Refers to generators that are normally in an operating or standby status, but are derated or unavailable due to routine service
or planned maintenance.
V. Planning Area
The electric system wherein an electric utility is responsible for
the forecasting of system demands and has the obligation to
provide the resources to serve those demands.
W. Scheduled Interchange
Electricity scheduled to flow between balancing authority areas,
usually the net of all sales, purchases, and wheeling
transactions between those parties at a given time.
X. Unplanned Outage and Derating
Refers to generators that were derated or out-of-service for
unplanned reasons, due to mechanical failures.
IV. Specific Instructions
A. Part I Schedule 1: Identification and Certification
i. Respondent Identification.
FERC utility code and name.
ii. Respondent Type.

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Check the appropriate categories.
iii. Balancing Authority Area.
Enter/verify the name of the balancing authority area reporting.
Use names as provided in the NERC Operating Manual, for
example.
iv. Planning Area.
Enter/verify the name of the planning area reporting. If the
planning area and balancing authority area are identical, then
these names may be identical.
v. Respondent Address.
Enter the respondent’s address. Include an attention line, room
number, building designation, etc. to facilitate the future
handling and processing of this form.
vi. Contact person.
Enter/verify the name, title, E-mail address and telephone
number of the individual to be contacted concerning the
information provided on this form.
vii. Certifying official.
Enter/verify the name and title of the certifying official. The
certifying official must date the form.
B. Part II: Balancing Authority Areas
i. Schedule 1. Generating Plants Included in Reporting
Balancing Authority Area
This schedule identifies each power plant whose output is
telemetered and monitored by the respondent (balancing
authority area operator). This would include all generation,
located within the respondent's balancing authority area, under
automatic generation balancing authority either directly or
indirectly through satellite balancing authority facilities, all
dispatchable generation by the balancing authority area
operator either directly or indirectly, and all other balancing
authority area generation resources whose output is
presumably significant enough to be continuously monitored for
balancing authority area operations. Also, include any
generation outside your balancing authority area which is
dynamically scheduled. Do not list generation located outside
your balancing authority area which you jointly own, but is not
dynamically scheduled. Energy received from this generation
should be reported as interchange.
The total output of such generation plus the net of transfers
would then be the balancing authority area net load. Other
generation within the balancing authority area not reported
here and thus not included within the total reported output

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would then presumably be reflected in the demand as "negative
demand."
Column b. List the name of each electric utility
operating power plant within the respondent's balancing
authority area whose output is telemetered and
monitored by the respondent (balancing authority area
operator) and outside the respondent's balancing
authority area which is dynamically scheduled.
Column c. List for each electric utility identified in
column b, the name of each such generating plant (or
unit if units at a plant are dispatched separately) that is
internal to your balancing authority area or dynamically
scheduled as part of your balancing authority area. The
monthly and annual output of these plants when
summed in your balancing authority area should be
identical to the monthly and annual net generation
reported in Schedule 3, column c.
Column d. Enter the available capability at the time of
the annual peak demand of each plant identified in
column c. The available capability requested is at the
time of balancing authority area annual peak demand for
whatever fuel is then being used. This total should equal
the value reported in Schedule 2, column c, "Available
Capacity," for the month with the annual peak demand.
Any differences must be explained in a footnote.
Column e. Enter the net demand on each plant at the
time of the Balancing Authority Area's annual peak
demand. The respondent should report by plant, the
aggregate of the demands placed upon the generators
located in the power plant identified in column c. If no
generators in a plant were operating at the time of the
annual peak demand, then report the integrated
demand as zero (0) for that plant. If a non-operating
plant was drawing power from the grid, report the
amount as a negative number. Provide a total as a last
line. This total should equal the value reported in
Schedule 3, column f, "Output of Generating Plants," for
the month with the annual peak demand. Any
differences must be explained in a footnote.
ii. Schedule 2. Balancing Authority Area Monthly Capabilities
at Time of Monthly Peak Demand
Schedule 2 collects the net generating capability available to
the respondent to meet the balancing authority area demand
and composition of internal and external resources available
and on reserve. The capability data are requested at the time of
the monthly hourly peak demands, where the peak demand is
defined to be that 60-minute integrated time period when the
net energy for load (NEL) as computed in Schedule 3, column

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(e), was the greatest. Available and unavailable capability are
requested as well as available or unavailable unit or firm
capability commitments.
Net capability is the steady hourly output which a generating
unit is expected to supply to demand, exclusive of station use,
under specified conditions, without exceeding limits of
temperature and stress. Net capability should be based on
average water conditions for thermal-electric plants and on
average or median flow conditions for hydroelectric plants.
Capability should be differentiated from nameplate rating which
defines the output that the manufacturer guarantees the
generator will produce under a defined set of conditions and
remains fixed. Capability measures the amount of power that
the generating unit can actually produce. This will likely be
more or less than its rating due to atmospheric conditions, the
characteristics of the fuel consumed, etc.
A generating unit may operate at reduced capability. In these
cases, the respondent should split the capability between
"available" (column c) and "unavailable" (columns d, e and f).
The capability data reported should reflect the respondent's
best estimate of the capability that was available at that time
given the then current operating conditions, not a fixed value
based on extensive testing. If a generator was not operating at
the time of the monthly peak demand, the respondent should
estimate the capability that the generator would have been
assigned if it had been operating. Further, if a portion of a
generator's total estimated capability was unavailable due to a
temporarily reduced rating, estimate the available and
unavailable portions of the generator's capability as of the time
of the monthly peak demand.
a. Column c. Report, in megawatts, by month, the
aggregated available capability of those generators
within the respondent's balancing authority area or
dynamically scheduled as part of your balancing
authority area as identified by plant in Schedule 1.
Available capability refers to operating generators and
those on stand-by that could have been made
operational if needed. Available capability does not
include generators in a test status, even if they were
producing power at the time of the peak demand.
Include any appropriate non-utility power producer
capabilities.
b. Columns d, e, and f. Report, in megawatts, by
month, the aggregated capability of those generators
within the respondent's balancing authority area or
dynamically scheduled as part of your balancing
authority area as identified by plant in Schedule 1, but
were unavailable to satisfy the demand at the time of
the balancing authority area's peak demand. Report

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separately the capability that was unavailable for
"planned or scheduled" reasons from that unavailable for
"unplanned or forced outage" and "other" reasons.
Derating of units also should be separated into planned
maintenance conditions, unplanned events and other
reasons.
1. Column d. Planned outage refers to
generators that are normally in an operating or
stand-by status, but were unavailable for service
due to routine and planned maintenance. Planned
derating refers to removal of a generator
component for repairs which were scheduled well
in advance and are of a predetermined duration.
These represent capability that the balancing
authority area did not expect to have available to
satisfy its demand at the time of the monthly
peak demand.
2. Column e. Unplanned outage refers to
generators that were out-of-service for
unplanned reasons, due to mechanical failures.
Unplanned derating refers to an unplanned
generator component failure which required that
the load on the unit be reduced.
3. Column f. Other outage refers to generators
that were out-of-service for reasons other than
planned or unplanned outages, including
transmission limitation at the generating plant,
disruptions in fuel supplies or energy sources,
environmental considerations, etc. Other derating
refers to other conditions which required that the
load on the unit be reduced.
c. Column g. This column is the automatically
calculated sum of Columns c, d, e, and f to arrive at the
balancing authority area's internal total net generation
capability.
d. Columns h and i.
1. Column h. If the respondent had capacity
available that could be scheduled into its
balancing authority area that could be traced to a
particular generator operated within another
balancing authority area or firm power
commitment, and the respondent did not treat it
as part of its balancing authority area's internal
capability, then the capability from that generator
or firm power commitment should be reported
here. Generating capacity within the respondent's
balancing authority area or firm power
commitments to other balancing authority areas

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at the time of the respondents monthly peak
demand are to be reported as a negative. If there
are commitments into and out of the
respondent's balancing authority area, provide a
net figure. However, if that capacity or any
portion of it was not available for any reason,
then the corresponding capability should NOT be
included in this column, rather it should be
reported in column i.
2. Column i. This column reports the firm power
capability not available to the respondent from
sources external to the balancing authority area,
at the time of the monthly peak demand based
on NEL. Conversely, if the respondent sold firm
capacity that was not taken because it was
unavailable, and it was included as a part of the
balancing authority area's internal capability,
then the capability from that un-taken firm power
sale should be reported here as a negative value.
e. Column j. This column is the automatically
calculated respondent's total capability in megawatts,
whether or not totally available, that is committed to
meet the monthly balancing authority area peak demand
(the total of column g+h+i)
iii. Schedule 3. Balancing Authority Area Net Energy for Load
and Peak Demand Sources by Month
This schedule covers all generation assigned to your balancing
authority area, and actual interchange with other balancing
authority areas, to determine the net energy for load in your
balancing authority area.
a. Column c. Enter the monthly net generation, internal
to the balancing authority area from those plants as
identified in Schedule 1, including any external
generation which is dynamically scheduled as part of
your balancing authority area, less any generation in
your balancing authority area dynamically scheduled as
part of another balancing authority area. Indicate in a
footnote if there are substantial amounts of internal
generation whose output is not telemetered to the
balancing authority area’s control center and thus not
included in net generation.
b. Column d. Enter the monthly net actual interchange
received by members of your balancing authority area
from suppliers (utilities or non-utility generators) in
other balancing authority areas. The amounts should
reflect actual interchange (see definition) rather than
scheduled interchange. Receipts should not include the

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physical transfer into the balancing authority area of
dynamically scheduled generation owned by utilities in
the balancing authority area and deliveries should not
include generation in your balancing authority area
dynamically scheduled as part of other balancing
authority areas. Total actual interchange should equal
the difference between the totals for columns (e) and (f)
on Schedule 5. Any difference must be explained in a
footnote.
c. Column e. Automatically generated sum of columns c
& d.
d. Column f. This column reports the megawatts of
output for the generating plant's energy reported in
column c. The value for the month of the annual peak
should equal the total of all plant integrated net loads
reported on Schedule 1, column (e). Any difference
must be explained in a footnote.
e. Column g. If unit or firm purchase transactions were
made from utilities external to the balancing authority
area during the hour of the balancing authority area's
monthly peak demand, then report the amount in
megawatts.
f. Column h. If unit or firm sales transactions were
made to utilities external to the balancing authority area
during the hour of the balancing authority area's
monthly peak demand, then report the amount in
megawatts.
g. Column i. Report the megawatts of net of non-firm
transactions and inadvertent interchange with utilities
external to the balancing authority area during the time
of the balancing authority area's monthly peak demand.
The amount will be positive for an in-flow and negative
for an outflow.
h. Column j. Automatically generated respondent's
monthly peak demand in megawatts which is defined to
be that 60-minute integrated time period when the
balancing authority area's NEL is the greatest.
i. Column k. Report, in megawatts, the respondent's
monthly minimum demand based on net energy for load
under normal operating conditions.
iv. Schedule 4 Instructions: Adjacent Balancing Authority
Area Interconnections
a. Column b. Enter/verify the name of the adjacent
interconnected balancing authority area. Use proper

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names to identify these balancing authority areas, as
provided in the NERC Operating Manual, for example. Do
not use the name of a transmission line owner if it is
different from the balancing authority area name.
b. Column c. Enter/verify each individual line or bus
name interconnecting each balancing authority area
identified in Column b. Use common industry naming for
lines, e.g., Bakerton - Bolivar No. 1 & 2, and naming for
a bus, e.g. Potomac Bus. Note that the example line is a
double circuit line.
c. Column d. Enter/verify the line or bus operating
voltage.
v. Schedule 5 Instructions: Balancing Authority Area
Scheduled and Actual Interchange
a. Column b. Enter/verify the names of all
interconnected balancing authority areas and balancing
authority areas with which interchanges were scheduled.
Use balancing authority area names as provided in the
NERC Operating Manual, for example. Do not list utilities
or non-utilities which are not balancing authority areas.
If these entities are located within the respondent's
balancing authority area they should either be treated as
generation, load or negative load.
b. Columns c and d. Enter in Column c the total annual
energy that was scheduled into the respondent's
balancing authority area from the balancing authority
area identified in column b, and, similarly for the annual
energy that was scheduled to that balancing authority
area in column d. Note: Scheduled interchange may
occur with non-adjacent balancing authority areas.
c. Columns e and f. Enter in column e the actual
metered electricity that flowed from the adjacent
balancing authority area reported in column b into your
balancing authority area. Enter in column f the actual
metered electricity that flowed from your balancing
authority area to the adjacent balancing authority area
listed in column b. The difference between the totals
should equal the total of column (d) on Schedule 3. Any
difference must be explained in a footnote.
vi. Schedule 6 Instructions: Balancing Authority Area Hourly
System Lambda

Enter in columns (c) to (z) the balancing authority area's
system lambda, in dollars per megawatthour, calculated for

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each hour of the day starting with 1 a.m. on January 1. This
schedule will have 365 records (or 366 for a leap year) with 24
hourly lambda values reported per day for each day of the
year. The hourly lambda data calculations for each day is
based on the respondent observing “standard time” for its
respective time zone for the entire year even though it may
have observed “daylight savings time” for part of the year.
Respondents must denote in column (b) the actual time zone
observed for each day (e.g., EST, EDT, CST, CDT, etc.).
a. Balancing Authority Area Hourly System
Lambda. For balancing authority areas where demand
following is primarily performed by thermal generating
units, the system lambda is derived from the economic
dispatch function associated with automatic generation
control performed at the balancing authority area’s
controlling utility or pool control center. Excluding
transmission losses, the fuel cost ($/hr) for a set of online and loaded thermal generating units (steam and gas
turbines) is minimum (1) when each unit is loaded and
operating at the same incremental fuel cost ($/MWh) (2)
with the sum of the unit loadings (MW) equal to the
system demand plus the net of interchange with other
balancing authority areas. This single incremental cost of
energy is the system lambda. System lambdas are likely
recalculated many times in one clock hour. However, the
indicated system lambda occurring on each clock hour
would be sufficient for reporting purposes.
Provide, as a footnote to the first lambda data cell in
Part II Schedule 6, an explanation describing the reason
for the unavailability of system lambda information. The
Commission expects that all Energy Management
Systems, with proper instructions, can record the
system lambda being used for economic dispatch of the
balancing authority area's thermal units.
Respondents should be able to report system lambda,
along with the other information reported on a balancing
authority area basis that describe the operation of such
areas from information that should be readily available.
The Commission is not requesting Respondents to
develop incremental or marginal cost (either short or
long term) according to any formula. Nor is the
Commission requesting "avoided cost rates" that electric
utilities file with state commissions or otherwise make
available for prospective qualified facilities.
b. Description of Economic Dispatch. Provide a
detailed description of how the Respondent calculates
system lambda. For those systems that do not use an
economic dispatch algorithm and do not have a system

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lambda, provide in writing a detailed description of how
balancing authority area resources are efficiently
dispatched.
C. PART III: Planning Areas
i. Schedule 1. Electric Utilities that Compose the Planning Area
Part III respondents should be those electric utilities charged
with carrying out the resource planning and demand forecasts
for the electric system consisting of the electric utilities
identified on this schedule. This should include all full
requirements customers and any partial requirements
customers which rely on their supplier to plan for incremental
demand requirements.
a. Column b. Identify all the electric utilities, including
the respondent that the respondent includes in its
planning area.
b. Columns c and d. Based on the planning area's
seasonal peak demands, enter in columns c and d the
annual summer and winter coincident peak demands,
respectively, for each utility identified in column b.
ii. Schedule 2. Planning Area Hourly Demand and Forecast
Summer and Winter Peak Demands and Annual Net Energy for
Load
a. Planning Area Hourly Demand. Respondents must submit
hourly demand data.
Enter in columns (c) to (z) the planning area's actual hourly
demand, in megawatts, for each hour of the day starting with 1
a.m. on January 1. This schedule will have 365 records (or 366
for a leap year) with 24 hourly demand values reported per
day. The time basis of the hourly data for each day of the year
will be based on “standard time” for the respondent’s respective
time zone (even though it may have been observing “daylight
savings time” for some days of the year). Respondents must
denote in column (b) the actual time zone observed for each
day (e.g., EST, EDT, CST, CDT, etc.).
b.Planning Area Forecast Summer and Winter Peak
Demand. Provide the planning area's forecast summer and
winter peak demand, in megawatts, and annual net energy for
load, in megawatthours, for the next ten years.
D. Part IV. Footnotes.
Include a footnote for any data item by right-clicking on the cell,
choosing Footnote from the drop-down list and typing your comment
provided on the pop-up page.

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Endnotes
1

Some utilities may also include variable operation and maintenance costs
that they consider "dispatchable." Therefore the costs to be minimized could
include a variable O&M component as well as the fuel costs.
2

Because unit heat rates and fuel costs vary, some units may not be able to
operate at the same incremental fuel cost as the other units and, thus, those
units may be loaded differently.

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