ITEM-BY-ITEM
INSTRUCTIONS
|
SCHEDULE 1: IDENTIFICATION
Survey
Contact: Verify
contact name, title, telephone number, fax number, and email
address.
Supervisor
of Contact Person for Survey: Verify
the contact’s supervisor’s name, title, telephone
number, fax number and email address.
Report
For: Verify
the NERC Regional Entity and reporting party, whether it is a
Regional Entity or subregion.
SCHEDULE
2. HISTORICAL AND PROJECTED PEAK DEMAND AND ENERGY
GENERAL
INSTRUCTIONS
The reported peak
demand for each
assessment area should be:
Coincident,
treating all load serving entities within the assessment area
(region/subregion) as a single system. For a given assessment
area, the reported coincident peak demand will be for all the
member entities in combination.
If non-coincident, please explain why coincident is not used.
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 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). Actual peak hour
demand should be provided on a coincident basis (the sum of two
or more demands on individual systems that occur during the same
demand interval).
The
term “Net
Energy for Load”
is defined as:
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
may
not
be feasible
given
the
number
of
entities
reporting
and
the
time
available
to
build
hourly
models.
Therefore,
it is possible that peak
demand
forecasts
may not
be
aggregated
at
peak.
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% probability 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.
SCHEDULE
2.
PART
A. HISTORICAL
AND PROJECTED PEAK DEMAND AND ENERGY
-- MONTHLY
For
lines
1-12,
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.
SCHEDULE
2.
PART
B. HISTORICAL
AND PROJECTED PEAK DEMAND AND ENERGY -- ANNUAL
All
forecasts and projections should represent a ten‑year
outlook.
For
line 1, enter Summer Peak Hour Demand 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.
For
line 2, enter Winter Peak Hour Demand for designated years as
defined above.
The
winter peak demands will be the values entered on SCHEDULE 3,
Part B, line 2, for the corresponding year
For
line 3, enter Net Energy for Load for designated years as
defined above.
SCHEDULE
3. PART A. AND PART B. HISTORICAL
AND PROJECTED DEMAND, CAPACITY, TRANSACTIONS, AND RESERVE MARGINS
GENERAL
INSTRUCTIONS
PART
A should be filled out for the summer
seasonal peak.
PART
B should be filled out for the winter
seasonal peak.
All
forecasts and projections should represent a ten-year
outlook.
Enter
demand and capacity for the summer and winter 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.
Where
capacity values are entered, values should accumulate through the
ten‑year projection period.
The
example below would be correct for data submitted during 2014 --
the Report Year (RY). Following the table, in the Actual column
“0 MW” was added; in Year 1 “100 MW”
was added; in Year 2 “0 MW” was added; in Year 3 “100
MW” was added; in Year 4 “100 MW” was added,
and, in Year 5 “0 MW” was added. Hence, for the 2013
base-case, by Year 5 a capacity of 300 MW is planned to be
added.
-
YEAR
|
Actual
(2013)
|
Year
1 (RY 2014)
|
Year
2 (2015)
|
Year
3 (2016)
|
Year
4 (2017)
|
Year
5 (2018)
|
Actual
or Planned Capacity (MW)
|
0
|
100
|
100
|
200
|
300
|
300
|
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).
For
hydroelectric capacity, explain in SCHEDULE 10, COMMENTS whether
the projected year’s data are for an adverse water year, an
average water year, or other.
For
line
1,
Unrestricted Non-coincident Peak Demand
is the gross load of the assessment
area,
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),
provide the
estimated impact of Energy Efficiency during the summer and
winter peak for each year. The values submitted should include
only Energy Efficiency that was embedded in the submitted load
forecast, resulting in reduced Total Internal Demand
projections.
Note:
This Demand-Side Management category represents the amount of
consumer load reduction at the time of peak for the assessment
area, due to utility programs that reduce consumer load
throughout the year, also includes programs aimed at reducing the
energy used by specific end-use devices and systems, typically
without affecting the services provided and without any explicit
consideration for the timing of program-induced savings. Examples
include utility rebate and shared savings activities for the
installation of energy efficient appliances, lighting and
electrical machinery, and weatherization materials. Other
examples include high-efficiency appliances, efficient lighting
programs, high-efficiency heating, ventilating and air
conditioning (HVAC) systems or control modifications, efficient
building design, and heat recovery systems.
For
line
1b,
Estimated
Diversity
enter
the
difference
between
the
assessment
area
peak
and
the
sum
of
the
peaks
of
the
individual loads of reporting
entities
(Load‑Serving
Entities,
balancing
area,
zones,
etc.).
Note:
Electric
utility system load consists of many individual loads that vary
depending on the time of day. Individual loads within the
customer classes follow similar usage patterns, but these classes
of service 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 served by one or multiple
non-registered Load-Serving Entities located in an assessment
area. These values should equal the total adjustments to account
for load of non-members, so 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 demand that is normally served by behind the meter
generation, which has a contract to receive electric power from
a utility if, the generator becomes unavailable. The summer and
winter value for each year should represent the total amount of
load (at time of assessment area peak) projected to be served
through contracts with respective customer(s). This value should
not be reported if projected Stand-By Load Under Contract is
already integrated into the Total Internal Demand projections.
For
line
1e,
Non-Controllable
Demand Response,
enter the value of Demand Response programs that are not
controllable and non-dispatchable by the balancing authority (or
authorities) within an assessment area, but are considered or
otherwise integrated into the Total Internal Demand projections.
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
Values should also reflect
adjustments for transmission line losses. 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 (DCLM),
enter Demand Response under the direct control of the system
operator, with capability to control the electric supply to
appliances or equipment operated by smaller (residential)
customers. Values submitted should represent the amount of
demand that can be interrupted during the summer and winter
peaks for all years. The value provided for the actual year
should represent that amount of Direcrt Control Load Management
realized during the peak.
For
line
2b,
Interruptible
Load,
enter Demand Response that, in accordance with contractual
arrangements, can be interrupted by direct control of the system
operator (remote tripping) or by action of the customer at the
direct request of the system operator and in accordance with
contractual provisions. Load that can be interrupted to fulfill
planning or operating reserve requirements should be reported as
Interruptible Demand. Values submitted should represent the
amount of demand that can be interrupted during the summer and
winter peaks for all years. The value provided for the actual
year should represent that amount of Interruptible Load realized
during the peak
For
line
2c,
Critical
Peak Pricing (CPP) with Control,
enter Demand Response that, in accordance with contractual
arrangements, can be interrupted by direct control of the system
operator (remote tripping), or by action of the customer by
responding to high prices of energy triggered by system
contingencies or high wholesale market prices. Values submitted
should represent the amount of demand that can be interrupted
during the summer and winter peaks for all years. The value
provided for the actual year should represent that amount of
Crititical Peak Pricing with Control realized during the peak
For
line
2d, Load as a Capacity Resource,
enter Demand Response that, in accordance with contractual
arrangements, is committed to pre-specified load reductions when
called upon by the system operator. This program is typically an
aggregation of a variety of demand resources that must meet
specific requirements associated 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 the
system operator. These resources may also be used to meet
resource adequacy obligations when determining planning reserve
margins. The values submitted should represent the total amount
of program participation during the summer and winter peaks for
all years. The value provided for the actual year should
represent that amount of Load as a Capacity Resource realized
during the peak
For line 3, Net
Internal Demand, enter the Total Internal Demand (line 2),
reduced by the total Dispatchable, Controllable Capacity Demand
Response.
For
line
4,
Total
Demand Response,
enter the aggregate of Demand Response that is available
to serve during the peak.
(Line 2a + Line 2b + Line 2c + Line 2d).
Lines
5 through 20, Relating to Capacity:
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
are 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.
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 8a).
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).
For line 6a, Existing,
Certain Capacity, include capacity from existing generator
units or portions of existing generator units that are
physically located within the assessment area that meet at least
one of the following requirements when examining the projected
peak for the summer and winter of each year:
Unit must have firm capability,
a Power Purchase Agreement (PPA), and firm transmission.
Unit must be classified as a
Designated Network Resource
Where energy-only markets exist,
unit must be a designated market resource eligible to bid into
the market.
When reporting Existing, Certain
Capacity include the portion of capacity expected to be
available during the summer and winter peak of each year.
For line 6b, Existing,
Other Capacity, include capacity from existing generator
units or portions of existing generator units that are
physically located within the assessment area that do not
qualify as Existing, Certain (line 6a) when examining the
projected peak for the summer and winter peak of each year.
Accordingly, these are the units or portions of units that may
not be available to serve peak demand for each season/year.
For line 6c, Existing,
Unavailable Capacity, include existing capacity physically
located within the assessment area that is projected to be
unavailable to operate and deliver power within the area
during the peak. Include:
Inoperable or mothballed capacity
Derated capacity
Capacity on a scheduled outage
Transmission Limited Resources:
The total amount of capacity that is transmission-limited with
known physical deliverability limitations to serve load that the
resource is obligated to serve.
Capacity projected to be
unavailable due to other reasons
For line 7, Peak Hour
Demand Plus Available Reserves, provide an aggregation of
all capacity used to serve peak load, plus the available
reserves (spinning, non-spinnning, and other reserves) that ware
deliverable during the peak hour for the summer / winter season
for the prior year.
For line 8, Future
Capacity Additions, include the portion of future capacity
resources that are projected to be available to operate and
deliver power within the assessment area during the period of
peak demand. The requirements of each tier will be determined in
the LTRA instructions posted by NERC
Line 8a, Tier 1 (Most certain):
Line 8b, Tier 2
Line 8c, Tier 3 (Least certain)
Line 9, Anticipated
Capacity: This value is the summation of Existing, Certain
Capacity (Line 6a) and Tier 1 Future Capacity Additions (Line
8a)
NOTES FOR CAPACITY TRANSFERS:
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 assessment area to the
reporting Region or assessment area. Sales contracts refer to
exported capacity that is transmitted from the reporting Region
or assessment area to an outside Region or assessment area. 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
TranFERS.
DO
NOT INCLUDE TRANSMISSION SYSTEM LOSSES WHEN REPORTING IMPORTS AND
EXPORTS TRANSFERS.
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:
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. All derating accounted
for in Region or Province B.
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.
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.
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.
For
line
10,
Capacity Transfers – Imports,
for prior year enter actual imports, otherwise the sum of firm
and expected import transfers.
For
line
10a, Prior Year Actual Imports,
enter
the amount of capacity (both firm and non-firm) imported into
the assessment area during the summer and winter peaks for the
prior year.
For
line
10b,
Firm,
enter the amount of capacity purchases for which a firm contract
has been signed. Firm contracts for import transfers are the
highest quality (priority) service offered to customer(s) under
a fixed rate schedule that anticipates no planned interruption.
Values should reflect firm transfers for the assessment area
summer and winter peaks of all years that have confirmed
purchases from another area backed by signed firm contracts.
These transactions include the following subcategories:
Full
Responsibility Purchases
- Enter the total of all firm contracts for which the seller(s)
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. The purchaser(s)
and seller(s) must coordinate and agree on how transactions are
reported under this heading. Values should reflect transfers
for the summer and winter of all years that have confirmed
purchases from another assessment area backed by signed, firm
contracts. Values reported on this line represent a portion of
Line 10b – Firm.
Externally
Owned Capacity/Entitlement –
Enter the amount of externally owned capacity transfer in which
owned capacity is physically located outside the assessment
area footprint. Values should reflect externally owned
capacity or capacity entitlements that will be available for
the assessment area summer and winter peaks of all years.
Values reported on this line represent a portion of Line 10b –
Firm.
Modeled
Transfers,
for regions or assessment areas that model potential feasible
transfers, enter the amount of projected imported capacity
transfers. Value should reflect the amount of energy that could
be transferred, for the summer and winter seasons, with
consideration for available generation and transfer capability.
For
line
10c,
Expected,
enter the amount of capacity for which a firm import transfer
contract has not been executed, but has a reasonable expectation
to be implemented. Values should reflect any potential transfers
absent a firm contract, but with reasonable expectations for
available purchase during the summer and winter peaks for all
years. These transactions will be counted towards the
Prospective Resources and Reserve Margin
For
line
11,
Capacity
Transfers – Exports,
for prior year enter actual exports, otherwise the sum of firm
and expected export transfers.
For
line
11a, Prior Year Actual Exports,
enter
the amount of capacity (both firm and non-firm) exported out of
the assessment area during the summer and winter peaks for the
prior year.
For
line
11b,
Firm,
enter the amount of capacity purchases for which a firm contract
has been signed. Firm contracts for export transfers are the
highest quality (priority) service offered from the seller(s)
under a filed rate schedule that anticipates no planned
interruption. Values should reflect firm transfers for the
assessment area summer and winter peaks of all years that have
confirmed purchases by another area backed by signed firm
contracts. These transactions include the following
subcategories:
Full
Responsibility Sales
- Enter the total of all firm contracts for which the seller(s)
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. The purchaser(s)
and seller(s) must coordinate and agree on how transactions are
reported under this heading. Values should reflect transfers
for the summer and winter of all years that have confirmed
purchases from another assessment area backed by signed, firm
contracts. Values reported on this line represent a portion of
Line 11b – Firm.
Externally
Owned Capacity/Entitlement –
Enter the amount of externally owned capacity transfer in which
owned capacity is physically located outside the assessment
area footprint. Values should reflect externally owned
capacity or capacity entitlements that will be available for
the assessment area summer and winter peaks of all years.
Values reported on this line represent a portion of Line 11b –
Firm.
Modeled
Transfers,
for regions or assessment areas that model potential feasible
transfers, enter the amount of projected exported capacity
transfers. Value should reflect the amount of energy that could
be transferred, for the summer and winter seasons, with
consideration for available generation and transfer capability.
For
line
11c,
Expected,
enter the amount of capacity for which a firm export transfer
contract has not been executed, but has a reasonable expectation
to be implemented. Values should reflect any potential transfers
absent a firm contract, but with reasonable expectations for
available purchase during the summer and winter peaks for all
years. These transactions will be counted towards the
Prospective Resources and Reserve Margin.
NOTES
FOR CAPACITY RESOURCES:
Lines
12-16
are calculations for capacity resources with varying degrees of
certainty. They are calculated from capacity sources (generating
supply) and transfers for current and future years, and will be
used in margin calculations.
Line
12,
Existing
Certain and Net Firm Transfers,
includes the summation of:
Line
13,
Anticipated
Capacity Resources,
includes the summation of:
Existing
Certain and Net Firm Transfers (line
12 above)
Future
Capacity Resources, Tier 1 (line 8a above)
Line
14,
Prospective
Capacity Resources, includes
the summation of:
Anticipated
Capacity Resources (line 13 above)
Existing-Other
Capacity (line 6b)
Net
of Expected Capacity Transfers (Imports – Exports) (line
10c – line 11c)
Future
Capacity Resources, Tier 2 weighted in accordance with the
LTRA instructions posted by NERC (line
8b above * Weighting Factor).
Line
15,
Adjusted
Potential Capacity Resources
includes the summation of:
Prospective
Capacity Resources (line 14 above)
Future
Capacity Resources, Tier 3 weighted in accordance with the
LTRA instructions posted by NERC (line
8c above
* Weighting Factor).
For
line
16,
Target
Reserve Margin,
enter a value between 0 and 100 that represents the expected
target reserve margin (%) set by the Region/Assessment Area. 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.
NOTES
FOR MARGIN CALCULATIONS:
Reserve
Margin and Capacity Margin calculations are computed by NERC and
submitted on behalf of the Region or assessment area.
The
reserve margin is calculated by subtracting Net Internal Demand
from the appropriate capacity resource term. The resulting
difference is then divided by Net Internal Demand. In
calculating the capacity margin, the resulting difference divided
by the appropriate capacity resource term.
For
line
17, 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.
For
line
18,
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.
For
line
19,
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.
For
line
20,
Adjusted
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.
SCHEDULE
4. BULK
TRANSMISSION FACILITY POWER FLOW CASES
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.
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 submitted
which represents a period of at least two years into the future
and complete SCHEDULE 4 (see Instructions 4 through 9).
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.
For
each power flow case that is provided in response to Items 2 and
3 above, please identify on SCHEDULE 4 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.
EIA
expects that in nearly all cases the power flow format will be
one of the following:
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.
Line 4, Prospective
Facilities and Connections:
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.
Note: Repeat Instruction 9 for
each prospective facility.
SCHEDULE
5. BULK ELECTRIC TRANSMISSION SYSTEM MAPS
Each
Regional Entity is to submit a map(s), in electronic format,
showing the existing bulk electric transmission system, 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.
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.
The
map requirement may be satisfied by either:
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
Separate
maps for a set of subregions that comprise the whole region.
For
line
1,
enter the number of maps provided.
For
line
2,
enter the requested map information in columns (a) through (c).
SCHEDULE 6. EXISTING AND PROJECTED
TRANSMISSION CIRCUIT MILES AND CHARACTERISTICS OF PROJECTED
TRANSMISSION ADDITIONS
SCHEDULE 6.
PART A.
EXISTING AND PROJECTED TRANSMISSION CIRCUIT MILES
For
existing and projected transmission lines that are part of the
NERC BES, report circuit miles for the specified voltage
categories below. For the “Less than 100” range,
reporting will start with Report Year 2016. Report transmission
line circuit miles in WHOLE numbers.
Operative
Voltage Range (kV)
|
Voltage
Type
|
Less
than 100
|
AC
|
--
|
100-199
|
AC
|
--
|
100-299
|
--
|
DC
|
200-299
|
AC
|
--
|
300-399
|
AC
|
DC
|
400-599
|
AC
|
DC
|
600+
|
AC
|
DC
|
All
transmission lines must be classified into one of the following
categories:
Existing:
Energized
line available for transmitting power
Under
Construction: Construction
of the line has begun
Planned
(any of the following):
Permits
have been approved to proceed
Design
is complete
Needed
in order to meet a regulatory requirement
A
line projected in the transmission plan
A
line that is required to meet a NERC TPL Standard or powerflow
model and cannot be categorized as “Under Construction”
or “Planned”
Projected
transmission lines that are not “Under Construction”
or “Planned”
For
line
1,
report Existing transmission lines as of the last day in the
prior reporting year. (For example, the 2014 Report Year, enter
the amount of circuit miles existing as of 12/31/2013.)
For
line
2,
report Under Construction transmission lines as of the first
day in the current reporting year. (For example, the 2014
Report Year, enter the amount of circuit miles under
construction as of 1/1/2014.)
For
line
3,
report Planned transmission lines to be completed within the
first 5 years starting the first day in the current reporting
year.
For
line
4,
report Conceptual transmission lines to be completed within the
first 5 years starting the first day in the current reporting
year.
For
line
5,
report Planned transmission lines to be completed within the
second 5 years starting the first day of the 6th
projection year.
For
line
6,
report Conceptual transmission lines to be completed within the
second 5 years starting the first day of the 6th
projection year.
For
line
7,
report the sum of all Existing, Under Construction, and Planned
transmission line circuit miles for the ten year projection
period.
For
line
8,
report the sum of all Existing, Under Construction, Planned,
and Conceptual transmission line circuit miles for the ten year
projection period.
SCHEDULE 6.
PART B.
CHARACTERISTICS OF PROJECTED TRANSMISSION LINE ADDITIONS
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.
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.
For
line
1,
Project Name, enter the project name
For
line
2,
Project Status, enter the level of certainty defined by the
following criteria:
Permits
have been approved to proceed
Design
is complete
Needed
in order to meet a regulatory requirement
A
line projected in the transmission plan
A
line that is required to meet a NERC TPL Standard or powerflow
model and cannot be categorized as “Under Construction”
or “Planned”
Projected
transmission lines that are not “Under Construction”
or “Planned”
For
line
3,
Tie
line,
specify whether this addition interconnects Balancing
Authorities (YES/NO).
For
line
4a & 4b,
Primary
and
Secondary Driver,
specify drivers from the following list:
Reliability
Variable/Renewable
(identify by source or combination of sources)
Nuclear
Integration
Fossil-Fired
Integration (identify by source or combination of sources)
Hydro
Integration
Economics
/ Congestion
Other
(please specify in Schedule 10, Comments)
For
line
5,
Terminal
Location (From),
enter the name of the beginning terminal point of the line.
For
line
6,
Terminal
Location (To),
enter the name of the ending terminal point of the line.
For
line
7,
Company
Name,
enter the company name.
For
line
8,
EIA
Company Code,
identify each organization by the six-character code assigned by
EIA.
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).
For
line
10,
Percent
Ownership,
if the transmission line will be jointly-owned, enter the
percentages owned by each transmission owner.
For
line
11,
Circuit Line
Length,
enter the number of circuit line miles between the beginning and
ending terminal points of the line.
For
line
12,
Line
Type,
select physical location of the line conductor – overhead
(OH), underground (UG), or submarine (SM).
For
line
13,
Voltage
Type,
select voltage as alternating current (AC) or direct current
(DC).
For
line 14, Voltage
Operating,
enter the voltage at which the line will be normally operated in
kilovolts (kV).
For
line
15,
Voltage
Design,
enter the voltage at which the line is designed to operate in
kilovolts (kV).
For
line
16,
Circuits
per Structure Present, enter
the current number of three-phase circuits on the structures of
the line.
For
line
17,
Circuits
per Structure Ultimate,
enter the ultimate number of three-phase circuits that the
structures of the line are designed to accommodate.
For
line
18,
Capacity
Rating,
enter the normal load-carrying capacity of the line in millions
of volt-amperes (MVA).
For
line
19,
Original
In-Service Date,
enter the originally projected date the line was to be energized
under the control of the system operator.
For
line
20,
Expected
In-Service Date,
enter the currently projected date the line will be energized
under the control of the system operator.
For
line
21,
Line
Delayed,
enter “Y” if the line has been delayed and “N”
if it has not.
For
line
22,
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
FERC has published a Final Rule on
December 20, 2012, approving a new definition of the “Bulk
Electric System” (BES), but postponed its implementation
until July 1, 2014.
In Report Year 2014 and Report
Year 2015 report EIA-411 transmission outage data for circuits
200 kV and above, and transformers with a low side 200 kV and
above. From Report Year 2016 forward report outage data for
transmission elements that are part of the new BES definition.
All data in section 7 are to be
aggregated by each Regional Entity and reported on this schedule.
DEFINITIONS
Transmission line 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 10
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.
A
Single
Mode Outage
is an Automatic Outage of a single Element which occurred
independent of any other outages.
A
Dependent
Mode Outage
is an Automatic Outage of an Element which occurred as a result
of an initiating outage, whether the initiating outage was an
Elements outage or a non-Element outage.
A
Common
Mode Outage
is one of two or more Automatic Outages with the same Initiating
Cause Code and where the outages are not consequences of each
other and occur nearly simultaneously (i.e., within cycles or
seconds of one another).
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 10
Comments.
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.
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. There is no
requirement to report Non-Automatic, Planned Outages.
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 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.
SCHEDULE 7. PART A. ANNUAL
DATA ON AC TRANSMISSION LINE OUTAGES
For
the appropriate outage type (Automatic; or Non-Automatic,
Operational), enter the following:
Number
of Outages (lines
1 and 4),
report the total number of outages that occurred in the
reporting period for each voltage class.
For
line 1, automatic
sustained outages,
also provide :
Line
1a, total number of Single Mode outages
Line
1b, total number of Dependent Mode outages
Line
1c, total number of Common Mode outages
Number
of Circuit-Hours Out of Service (lines
2 and 5),
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
3 and 6),
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.
SCHEDULE 7. PART B. ANNUAL
DATA ON DC TRANSMISSION LINE OUTAGES
For
the appropriate outage type (Automatic; or Non-Automatic,
Operational), enter the following:
Number
of Outages (lines
1 and 4),
report the total number of outages that occurred in the
reporting period for each voltage class.
Number
of Circuit-Hours Out of Service (lines
2 and 5),
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
3 and 6),
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.
SCHEDULE 7. PART C. ANNUAL
DATA ON TRANSFORMER OUTAGES
For
the appropriate outage type (Automatic; or Non-Automatic,
Operational), enter the following:
Number
of Outages (lines
1 and 4),
report the total number of outages that occurred in the
reporting period for each voltage class based on the high-side
voltage
of the transformer.
Number
of Transformer-Hours Out of Service (lines
2 and 5),
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
3 and 6),
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.
SCHEDULE 7. 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.
Report
in accordance with the applicable AC/DC circuit voltage class
indicated.
For
line
1,
an AC Circuit is a set of overhead or underground three-phase
conductors that are bound by AC substations. Radial circuits
are AC Circuits.
For
line
1a,
enter the Number
of Overhead AC Circuits
in each voltage class.
For
line
1b,
enter the Number
of Underground AC Circuits
in each voltage class.
For
line
2,
an AC Circuit Mile is one mile of a set of three-phase AC
conductors in an Overhead or Underground AC Circuit
For
line
2a,
enter the Number
of Overhead AC Circuit Miles
in each voltage class.
For
line
2b,
enter the Number
of Underground AC Circuit Miles
in each voltage class.
For
line
3,
enter the Number
of Multi-Circuit Structure Miles
in each voltage class. A Multi-Circuit 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.)
For
line
4,
a DC circuit is one pole of an overhead or underground line
which is bound by an AC/DC Terminal on each end.
For
line
4a,
enter the Number
of Overhead DC Circuits
in each voltage class.
For
line
4b,
enter the Number
of Underground DC Circuits
in each voltage class.
For
line
5,
a DC Circuit Mile is one mile of one pole of a DC Circuit.
For
line
5a,
enter the Number
of Overhead DC Circuit Miles
in each voltage class.
For
line
5b,
enter the Number
of Underground DC Circuit Miles
in each voltage class.
For
line
6,
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.
For
line
7,
enter the total annual number
of events
associated with the outages reported on Schedules 7A, 7B, and
7C.
SCHEDULE
8. ANNUAL DATA ON GENERATING UNIT OUTAGES, DERATINGS AND
PERFORMANCE INDEXES FOR CONVENTIONAL UNITS
Schedule
8 collects annual data on generating unit outages, deratings and
performance indexes for conventional
generating units in active state,
available from the NERC Generating Availability Data System
(GADS).
Generating
unit outages, deratings, and required performance indexes are
defined below for purposes of reporting on this schedule and are
intended to be consistent with the instructions and definitions
provided in the GADS Data
Reporting Instructions
manual, found at http://www.nerc.com/page.php?cid=4|43|45,
Appendix
F - Performance Indices and Equations.
All data in section 8 are to be
aggregated by each Regional Entity and reported on this schedule.
Outages
A
generating unit outage exists whenever a unit is not synchronized
to the grid system and not in a Reserve Shutdown state.
Forced
Outages
A
Forced Outage (FO)
is an unplanned, unscheduled outage that requires removal of a
unit from the in-service state. There are three types of defined
Forced Outages – immediate, delayed and postponed.
Immediate
Forced
Outage (U1)
is an outage that requires immediate removal of a unit from
service, another Outage State, or a Reserve Shutdown state. This
type of outage usually results from immediate
mechanical/electrical/hydraulic control systems trips and
operator-initiated trips in response to unit alarms.
Delayed
Forced Outage (U2)
is an outage that does not require immediate removal of a unit
from the in-service state but requires removal within six hours.
Postponed
Forced
Outage (U3)
is an outage that can be postponed beyond six hours but requires
that a unit be removed from the in-service state before the end
of the next weekend.
Planned
and Maintenance Outages
Planned
Outage
(PO)
is an outage that is scheduled well in advance and is of a
predetermined duration, lasts for several weeks, and occurs only
once or twice a year.
Maintenance
Outages
(MO)
is an outage that can be deferred beyond the end of the next
weekend, but requires that the unit be removed from service,
another outage state, or Reserve Shutdown state before the next
Planned Outage.
Planned
Outage Extension (PE)
is an extension beyond the estimated completion date of a
Planned Outage.
Maintenance
Outage Extension (ME)
is an extension beyond the estimated completion date of a
Maintenance Outage.
Outage
Counts
Forced
Outage Count
is the number of all forced outage incidents (U1, U2, U3),
including Startup Failures (SF).
Maintenance
Outage Count
is the number of all maintenance outage incidents (MO). Since
Maintenance Extensions are part of the Maintenance Outages, they
should not be included in this count.
Planned
Outage Count
is the number of all planned outage incidents (PO). Since
Planning Extensions are part of the Planning Outages, they
should not be included in this count.
Outage
Hours
Planned
Outage Hours
(POH)
is the sum of all hours experienced during Planned Outages (PO)
and Planned Outage Extensions (PE) of any Planned Outages.
Maintenance
Outage Hours
(MOH)
is the sum of all hours experienced during Maintenance Outages
(MO) and Maintenance Outage Extensions (ME) of any Maintenance
Outages.
Deratings
A
unit derating exists whenever a unit is limited to some power
level less than the unit’s Net
Maximum Capacity (NMC),
defined below.
Seasonal
Deratings
Seasonal
Deratings are ambient-related deratings. GADS calculates
Seasonal Deratings as the difference in Maximum Capacity and
Dependable Capacity.
Net
Maximum Capacity
(NMC)
is the power level that the unit can sustain over a specified
period of time when not restricted by ambient conditions or
deratings, net of capacity (MW) utilized for that unit’s
station service or auxiliary load. Net
Dependable Capacity (NDC)
is the power level that the unit can sustain during a given
period if there are no equipment, operating, or regulatory
restrictions, net of capacity (MW) utilized for that unit’s
station service or auxiliary load.
Forced
Deratings
There
are three types of defined Forced Deratings – immediate,
delayed and postponed.
Immediate
Forced
Derating (D1)
is a derating that requires an immediate reduction in capacity.
Delayed
Forced Derating (D2)
is a derating that does not require an immediate reduction in
capacity but requires a reduction within six hours.
Postponed
Forced
Derating (D3)
is a derating that can be postponed beyond six hours but
requires a reduction in capacity before the end of the next
weekend.
Planned
and Maintenance Deratings
Planned
Derating
(PD)
is a derating that is scheduled well in advance and is of a
predetermined duration.
Maintenance
Derating (D4)
is a derating that can be deferred beyond the end of the next
weekend but requires a reduction in capacity before the next
Planned Outage.
Planned
Derating Extension (DP)
is an extension of a Planned Derate (PD) beyond its estimated
completion date.
Maintenance
Derating Extension (DM)
is an
extension of a maintenance derate (D4) beyond its estimated
completion date.
Derating
Counts
Forced
Derating Count
(FD)
is the number of all unique forced derating incidents (D1, D2,
D3), including Startup Failures (SF).
Maintenance
Derating Count
(D4)
is the number of all maintenance derating incidents. Since
Maintenance Derating Extensions (DM) are part of the Maintenance
Deratings, they should not be included in this count.
Planned
Derating Count
(PD)
is the number of all planned derating incidents. Since Planned
Derating Extensions (DP) are part of the Planned Deratings, they
should not be included in this count.
Derated
Hours
A
derated unit operates below its potential power level. For GADS
reporting purposes, derating hours are transformed into
equivalent full outage hours, by weighing each derating with the
size of capacity reduction in effect during the derated period of
the unit.
Equivalent
Seasonal Derating Hours
(ESEDH):
Seasonal derating due to ambient conditions is a continuous
state, affecting units throughout their available state.
Therefore, ESEDH is the transformation of Available Hours
multiplied by the MW size of power reduction (NMC-NDC) divided
by the Net Maximum Capacity (NMC). Unit Available
Hours
(AH)
are the in-service and reserve shutdown hours, plus additional
hours for used for operations, such as pumping hours and
synchronous condensing hours.
Equivalent
Forced Derated Hours
(EFDH)
is the duration of in-service and reserve shutdown forced (D1,
D2, D3) deratings multiplied by the MW size of power reduction
during derating, divided by the Net Maximum Capacity.
Equivalent
Planned Derated Hours
(EMDH)
is the duration of in-service and reserve shutdown planned
deratings (PD), including associated Planned
Derating Extensions
(DP),
multiplied by the MW size of power reduction, during the
derating, divided by the Net Maximum Capacity.
Equivalent
Maintenance Derated Hours
(EMDH)
is the duration of in-service and reserve shutdown maintenance
deratings (D4), including associated Maintenance
Derating Extensions
(DM),
multiplied by the MW size of power reduction, during derating,
divided by the Net Maximum Capacity.
Generating
Unit Performance Indexes
The
explicit formulas of the performance indexes can be found in
Appendix
F - Performance Indices and Equations
of the NERC Generating Availability Data System (GADS) Data
Reporting Instructions manual.
Net
Capacity Factor (NCF) is
the ratio of Net Actual Generation of the unit to maximum
possible generation during period hours, calculated by
multiplying the Period Hour (PH) with Net Maximum Capacity,
expressed in percents.
Net
Output Factor (NOF) is
the ratio of Net Actual Generation of the unit to maximum
possible generation during service hours, calculated by
multiplying the Service Hours (SH) with Net Maximum Capacity,
expressed in percents.
Service
Factor (SF) is
the ratio of Service Hours to Period Hours, expressed in
percents.
Availability
Factor (AF) is
the ratio of Available Hours to Period Hours, expressed in
percents.
Unavailability
Factor (UAF) is
the ratio of all unit outage hours (FOH+MOH+POH) to Period
Hours, expressed in percents.
Unit
Derating Factor (UDF) is
the ratio of equivalent unit derating hours (EFDH+EMDH+EPDH) to
Period Hours, expressed in percents.
Equivalent
Availability Factor (EAF) is
the ratio of Available Hours, adjusted for all unit derating
hours (including seasonal derating hours) to Period Hours,
expressed in percents.
Equivalent
Forced Outage Rate (FOR) is
the ratio of Forced Outage Hours and Equivalent Forced Derating
Hours to the sum of Forced Outage Hours, Service Hours, Pumping
Hours and Synchronous Hours, expressed in percents.
Equivalent
Maintenance Outage Rate (MOR) is
the ratio of Maintenance Outage Hours and Equivalent Maintenance
Derating Hours to the sum of Forced Outage Hours, Service Hours,
Pumping Hours and Synchronous Hours, expressed in percents.
Equivalent
Planned Outage Rate (POR) is
the ratio of Planned Outage Hours and Equivalent Planned
Derating Hours to the sum of Forced Outage Hours, Service Hours,
Pumping Hours and Synchronous Hours, expressed in percents.
Forced
Outage Rate Demand (FORd) is
the ratio of Forced Outage Hours during service demand time to
the sum of Service Hours and Forced Outage Rate during service
demand time, expressed in percents.
Equivalent
Forced Outage Rate Demand (EFORd) is
the ratio of Forced Outage Hours and Equivalent Forced Derating
Hours during service demand time to the sum of Service Hours and
Forced Outage Rate during service demand time, expressed in
percents. GADS calculates special factors to convert the Forced
Outage Hours and Forced Derating Hours to their equivalent
during service demand time.
SCHEDULE
8. PART A. ANNUAL DATA ON GENERATING UNIT OUTAGE HOURS AND
COUNTS
For
line
1-8,
enter the respective outage counts and durations for Forced,
Maintenance and Planned Outages, for the different generating
unit types.
For
line
9,
enter the respective total
outage counts and durations for Forced, Maintenance and Planned
Outages, for all generating unit types.
For
lines
10-13,
enter the respective outage counts and durations for Forced,
Maintenance and Planned Outages, for the different generating
unit capacity categories.
For
line
14,
enter the respective total
outage counts and durations for Forced, Maintenance and Planned
Outages, for all generating unit capacity categories.
For
lines
15-18,
enter the respective outage counts and durations for Forced,
Maintenance and Planned Outages, for coal units, by generating
unit vintage – for units that entered commercial
operations in or before 1972, and in or after 1973.
For
lines
19 and 20,
enter the respective outage counts and durations for Forced,
Maintenance and Planned Outages, for combined cycle units, by
generating unit vintage – for units that entered
commercial operations in or before 2002, and in or after 2003.
SCHEDULE
8. PART B. ANNUAL DATA ON GENERATING UNIT DERATING HOURS AND
COUNTS
For
line
1-8,
enter the respective derating counts and equivalent derated
durations for Forced, Maintenance and Planned Outages, for the
different generating unit types.
For
line
9,
enter the respective total
derating counts and equivalent derated durations for Forced,
Maintenance and Planned Outages, for all generating unit types.
For
lines
10-13,
enter the respective derating counts and equivalent derated
durations for Forced, Maintenance and Planned Outages, for the
different generating unit capacity categories.
For
line
14,
enter the respective total
derating counts and equivalent derated durations for Forced,
Maintenance and Planned Outages, for all generating unit
capacity categories.
For
lines
15-18,
enter the respective derating counts and equivalent derated
durations for Forced, Maintenance and Planned Outages, for coal
units, by generating unit vintage – for units that entered
commercial operations in or before 1972, and in or after 1973.
For
lines
19 and 20,
enter the respective derating counts and equivalent derated
durations for Forced, Maintenance and Planned Outages, for
combined cycle units, by generating unit vintage – for
units that entered commercial operations in or before 2002, and
in or after 2003.
SCHEDULE
8. PART C.1. AND C.2. ANNUAL DATA ON GENERATING UNIT PERFORMANCE
INDEXES
For
line
1-8,
enter the respective index values for Net Capacity Factor, Net
Output Factor, Service Factor, Availability Factor,
Unavailability Factor, Unit Derating Factor, Equivalent
Availability Factor, Equivalent Forced Outage Rate, Equivalent
Maintenance Outage Rate, Equivalent Planned Outage Rate, Forced
Outage Rate Demand, Equivalent Forced Outage Rate Demand, for
the different generating unit types.
For
line
9,
enter the respective total
index values for Net Capacity Factor, Net Output Factor, Service
Factor, Availability Factor, Unavailability Factor, Unit
Derating Factor, Equivalent Availability Factor, Equivalent
Forced Outage Rate, Equivalent Maintenance Outage Rate,
Equivalent Planned Outage Rate, Forced Outage Rate Demand,
Equivalent Forced Outage Rate Demand, for all generating unit
types.
For
lines
10-13,
enter the index values for Net Capacity Factor, Net Output
Factor, Service Factor, Availability Factor, Unavailability
Factor, Unit Derating Factor, Equivalent Availability Factor,
Equivalent Forced Outage Rate, Equivalent Maintenance Outage
Rate, Equivalent Planned Outage Rate, Forced Outage Rate Demand,
Equivalent Forced Outage Rate Demand, for the different
generating unit capacity categories.
For
line
14,
enter the respective total
index values for Net Capacity Factor, Net Output Factor, Service
Factor, Availability Factor, Unavailability Factor, Unit
Derating Factor, Equivalent Availability Factor, Equivalent
Forced Outage Rate, Equivalent Maintenance Outage Rate,
Equivalent Planned Outage Rate, Forced Outage Rate Demand,
Equivalent Forced Outage Rate Demand, for all generating unit
capacity categories.
For
lines
15-18,
enter the respective index values for Net Capacity Factor, Net
Output Factor, Service Factor, Availability Factor,
Unavailability Factor, Unit Derating Factor, Equivalent
Availability Factor, Equivalent Forced Outage Rate, Equivalent
Maintenance Outage Rate, Equivalent Planned Outage Rate, Forced
Outage Rate Demand, Equivalent Forced Outage Rate Demand, for
coal units, by generating unit vintage – for units that
entered commercial operations in or before 1972, and in or after
1973.
For
lines
19 and 20,
enter the respective index values for Net Capacity Factor, Net
Output Factor, Service Factor, Availability Factor,
Unavailability Factor, Unit Derating Factor, Equivalent
Availability Factor, Equivalent Forced Outage Rate, Equivalent
Maintenance Outage Rate, Equivalent Planned Outage Rate, Forced
Outage Rate Demand, Equivalent Forced Outage Rate Demand, for
combined cycle units, by generating unit vintage – for
units that entered commercial operations in or before 2002, and
in or after 2003.
SCHEDULE
8. PART D. ANNUAL DATA ON GENERATING UNIT PRIMARY CAUSE OF
ACTIVE STATE FORCED OUTAGES
In
this section submit system/component failure cause codes for
forced outages of conventional generating units in active state.
The cause codes listed below are high level categories listed in
Appendix B of the GADS Reporting Instructions.
For
each generating unit type column, report counts for the listed
cause codes. Cause code ranges are those provided in the GADS
Reporting Instructions.
For
line
1
give the forced outage counts for the major generating unit
components :
1.a
Boiler
related components (cause code range 0010-1999)
1.b
Reactor
related components for nuclear units
1.c
Engine
related components for internal combustion units
1.d
Steam
turbine
related components for all units (cause code range 4000-4499)
1.e
Generator
related
components (cause code range 4500-4899)
For
line
2
give the forced outage counts for components of systems grouped
under Balance
of Plant:
2.a
Water
Systems
related components (cause code range 3110-3549)
2.b
Electrical
Systems
related components (cause code range 3600-3690)
2.c
Power
Station Switchyard
related components (cause code range 3700-3730)
2.d
Auxiliary
Systems
related components (cause code range 3800-3899)
2.e
All
Other
Balance
of Plant
components (cause code range 3950-3999)
For
line
3
give the forced outage counts for the components of Pollution
Control Equipment
(cause code range 8000-8845)
For
line
4
give the forced outage counts caused by factors external to the
generating unit plant operations:
4.a
Severe
Weather
related factors (cause codes 9000, 9020, 9035, 9036)
4.b
Other
Catastrophes
not related to weather events (cause codes 9010, 9025, 9030,
9040)
4.c
Economic
factors
(cause code range 9130-9199, and cause code 0000)
4.d
Fuel
Quality
related factors (cause code range 9200-9291)
4.e
Transmission
System
related factors other than catastrophes (cause code 9300)
4.f
All Other
External
factors (cause code range 9300-9340)
For
line
5
give the forced outage counts not directly attributable to
equipment failures and are caused by Regulatory,
Safety and Environmental
restrictions:
5.a
Regulatory
factors (cause code range 9504-9590)
5.b
Stack
Emissions,
including exhaust emissions, restrictions (cause code range
9600-9656)
5.c
Other
Operating Environmental Limitations
(cause code range 9660-9690)
5.d
Safety
related regulations and factors (cause codes 9700, 9720)
For
line
6
give the forced outage counts caused by factors related to
Personnel
or Procedure errors:
6.a
Personnel
Errors
(cause code range 9900-9920)
6.b
Procedural
Errors
(cause code range 9930-9950)
6.c
Staff
Shortage
(cause code 9960)
For
line
7
give the forced outage counts caused by Performance
related factors (cause code range 9997-9999)
For
line
8
give the forced outage counts for units in active state that are
not accounted for by the cause codes listed above, in lines 1
through 7.
For
line
9,
provide the Total
outage counts for all causes in lines 1 through 8.
SCHEDULE
9. SMART GRID TRANSMISSION SYSTEM DEVICES AND APPLICATIONS
All data in section 9 are to be
aggregated by each region / assessment area and reported on this
schedule.
SCHEDULE
9. PART A. DYNAMIC CAPABILITY RATING SYSTEMS
Dynamic
capability rating systems on transmission
circuits
continuously monitor ambient conditions, such as line tension,
temperature or wind speed, and allow lines to be reliably loaded
closer to their true operational capacity. Often this means they
can carry electricity at higher levels than nominal limits;
however, in some conditions, they can warn operators of
situations where the capacity of the line is reduced. These
systems include, but are not limited to, cable tension
monitoring, line thermal or direct temperature monitoring, and
thermal monitoring of conductor replicas. Equipment can be
installed at substations or on transmission lines themselves,
depending on the kinds of measurements being taken. Information
collected by the monitors is transmitted back to the control
center and made available to operators or integrated into energy
management systems. If you have integrated equipment monitoring,
such as Integrated Substation Condition Monitoring, that monitors
transmission lines as well as other equipment, report it here.
For
line
1
enter the number of transmission circuits utilizing a dynamic
capability rating system.
For
line
2
enter the miles of AC transmission lines utilizing
a dynamic capability rating system.
For
line
3
enter the number of station transformers utilizing
a dynamic capability rating system.
SCHEDULE
9. PART B. PHASOR MEASUREMENT UNITS
A
phasor
measurement unit
(PMU) is equipment that can monitor the precise grid synchro
phasor measurements
(magnitude and phase angle) of both voltage and current at high
frequency (e.g., 30 times per second) and associated with an
accurate
time-stamp.
PMUs are typically installed at substations or at power plants,
at a variety of voltage levels. Depending on location and
surrounding network configuration, a PMU can be used to monitor
transmission lines, transformers and/or generators.
For
line
1, enter
the number
of non-networked PMUs installed
in your region. A non-networked PMU is a device that measures
and stores phasor data at high frequency with a time-stamp, but
these data are not transmitted automatically to any other device
(e.g., control room equipment, phasor data concentrator). These
data are available for later retrieval and analysis, for
instance for event analysis after a reliability event.
For
line
2,
enter the number
of networked PMUs installed
in your region. A networked PMU measures and stores phasor data
at high frequency with a time-stamp, and communicates these data
at regular intervals (at least 30 samples per second) to remote
locations. Typically the data are shared with a Phasor Data
Concentrator
(PDC),
which then shares this information with other PMUs, operating or
reliability organizations. These data are also stored in a data
storage system. Communication between the PMU and PDC, and then
between the PDC and the users or storage system, is done via a
private wide-area network or any other secure and reliable
digital transport system. The data collected by a networked PMU
can be used along with data collected by other networked PMUs in
order to get a precise and comprehensive view of large areas of
the grid.
For
line
3
enter the total number
of substations with at least one networked PMU installed.
A substation is defined as any network node in the system where
two or more transmission lines, or a transmission line and power
plant, are connected directly or via step-up/step-down
transformers.
For
line
4
enter the total
number of
substations
in your region.
SCHEDULE
9. PART C. SMART GRID PMU APPLICATIONS
In
this section respondents are asked to indicate whether the PMUs
installed by entities in their regions are being used for either
real-time operations applications, planning and off-line
applications, by checking the appropriate box.
Real-time
operations applications
include, but are not limited to:
Wide-area
situational awareness
Frequency
stability monitoring and trending
Power
oscillation monitoring
Voltage
monitoring and trending
Alarming
and setting system operating limits, event detection and
avoidance
Resource
integration
State
estimation
Dynamic
line ratings and congestion management
Outage
restoration
Operations
planning
Planning
and off-line applications
include, but are not limited to:
Baselining
power system performance
Event
analysis
Static
system model calibration and validation
Dynamic
system model calibration and validation
Power
plant model validation
Load
characterization
Special
protection schemes and islanding
Primary
frequency (governing) response
Applications
can be at any stage of deployment within the control room, from
research and development to full production.
SCHEDULE
10. 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.)
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