**Form 714 - Annual Electric Balancing Authority Area**

**and Planning Area Report Instructions**

Table of Contents

[I. General Information 1](#i.-general-information)

[A. Purpose 1](#__RefHeading___Toc166488434)

[B. Who Must Submit 2](#__RefHeading___Toc166488435)

[C. How to Submit 3](#__RefHeading___Toc166488436)

[D. When to Submit 3](#__RefHeading___Toc166488437)

[E. Sanctions and Confidentiality Statements
3](#__RefHeading___Toc166488438)

[II. General Instructions 3](#__RefHeading___Toc166488439)

[III. Definitions 4](#__RefHeading___Toc166488440)

[IV. Specific Instructions 6](#__RefHeading___Toc166488441)

[A. Part I Schedule 1: Identification and Certification
6](#__RefHeading___Toc166488442)

[B. Part II: Balancing Authority Areas 7](#__RefHeading___Toc166488443)

[*i. Schedule 1.* Generating Plants Included in Reporting Balancing
Authority Area 7](#__RefHeading___Toc166488444)

[*ii. Schedule 2.* Balancing Authority Area Monthly Capabilities at Time
of Monthly Peak Demand 8](#__RefHeading___Toc166488445)

[*iii. Schedule 3.* Balancing Authority Area Net Energy for Load and
Peak Demand Sources by Month 11](#__RefHeading___Toc166488446)

[*iv. Schedule 4 Instructions:* Adjacent Balancing Authority Area
Interconnections 12](#__RefHeading___Toc166488447)

[*v. Schedule 5 Instructions:* Balancing Authority Area Scheduled and
Actual Interchange 13](#__RefHeading___Toc166488448)

[*vi. Schedule 6 Instructions:* Balancing Authority Area Hourly System
Lambda 13](#__RefHeading___Toc166488449)

[C. PART III: Planning Areas 15](#__RefHeading___Toc166488450)

[*i. Schedule 1.* Electric Utilities that Compose the Planning Area
15](#__RefHeading___Toc166488451)

[*ii. Schedule 2.* Planning Area Hourly Demand and Forecast Summer and
Winter Peak Demands and Annual Net Energy for Load
15](#__RefHeading___Toc166488452)

[D. Part IV. Footnotes. 15](#__RefHeading___Toc166488453)

#  I. General Information 

[]{#__RefHeading___Toc166488434 .anchor}**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 inter-balancing
> 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.

[]{#__RefHeading___Toc166488435 .anchor}**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 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.

[]{#__RefHeading___Toc166488436 .anchor}**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.

[]{#__RefHeading___Toc166488437 .anchor}**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.

[]{#__RefHeading___Toc166488438 .anchor}**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.

[]{#__RefHeading___Toc166488439 .anchor}**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.

[]{#__RefHeading___Toc166488440 .anchor}**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)***
>
> 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 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 stand-by
> 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.

[]{#__RefHeading___Toc166488441 .anchor}**IV.** **Specific
Instructions**

[]{#__RefHeading___Toc166488442 .anchor}**A. Part I Schedule 1:**
**Identification and Certification**

> ***i. Respondent Identification.***
>
> FERC utility code and name.\
> \
> ***ii. Respondent Type.***
>
> 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.

[]{#__RefHeading___Toc166488443 .anchor}**B. Part II: Balancing
Authority Areas**

[]{#__RefHeading___Toc166488444 .anchor}***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 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.

[]{#__RefHeading___Toc166488445 .anchor}***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 (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 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 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)

[]{#__RefHeading___Toc166488446 .anchor}***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 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.

[]{#__RefHeading___Toc166488447 .anchor}***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 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.

[]{#__RefHeading___Toc166488448 .anchor}***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.

[]{#__RefHeading___Toc166488449 .anchor}***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 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 on-line and loaded thermal generating
> units (steam and gas turbines) is minimum
> [^[(1)]{.underline}^](http://www.ferc.gov/docs-filing/eforms/form-714/instructions.asp#N_1_%23N_1_)
> when each unit is loaded and operating at the same incremental fuel
> cost (\$/MWh)
> [^[(2)]{.underline}^](http://www.ferc.gov/docs-filing/eforms/form-714/instructions.asp#N_2_%23N_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 lambda, provide in writing a detailed description of how
> balancing authority area resources are efficiently dispatched.

[]{#__RefHeading___Toc166488450 .anchor}**C. PART III: Planning Areas**

[]{#__RefHeading___Toc166488451 .anchor}***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.

[]{#__RefHeading___Toc166488452 .anchor}***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.

[]{#__RefHeading___Toc166488453 .anchor}**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.
>
> **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.