AD19-16, 30-day Notice, Attachment A

922_AD19-16_30day_20200124-3070.pdf

FERC-922, [AD19-16] Performance Metrics for ISOs, RTOs, and Utilities in Regions Outside ISOs and RTOs

AD19-16, 30-day Notice, Attachment A

OMB: 1902-0262

Document [pdf]

Download: pdf | pdf

Federal Energy Regulatory Commission STAFF DRAFT

FERC-922 (OMB Control No. 1902-0262)

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Expiration Date: to be determined

The views expressed in this Information Collection Request do not represent the views of the Commission, the Chairman, or any Commissioner.

Structure of the Information Collection Request
There are three groups of Metrics in this Information Collection Request
Group 1: Administrative and Descriptive Metrics
All reporting entities should answer these metrics
These metrics are identified by yellow shading in the title row of the worksheet and on the worksheet tabs
Group 2: Energy Market Metrics
All RTOs/ISOs should answer these metrics
These metrics are identified by green shading in the title row of the worksheet and on the worksheet tabs
Group 3: Capacity Market Metrics
The four RTOs/ISOs with forward capacity markets should answer these metrics
These metrics are identified by blue shading in the title row of the worksheet and on the worksheet tabs

Contact Information
Please complete the following text fields before entering any data in subsequent worksheets.
Balancing Authority Area Name:
Example: PJM, ISO-NE, etc.
Name of the Contact Person
John Doe
Phone Number of the Contact Person
202-111-1234
Email address of the Contact Person
[email protected]

Data Reporting Period
Respondents (utilities and RTOs/ISOs) without centralized capacity markets should enter the first calendar year of the five reporting periods.
RTOs/ISOs with centralized capacity markets should enter the four-digit year of the first delivery period of the five reporting periods.
For example, if June 2014 is the start of the first delivery period, enter 2014

Enter first reporting period (enter a 4 digit year in YYYY format)

YEAR

2014

Expiration Date
To be Determined
Where to Send Comments on Public Reporting Burden
The burden for the FERC-922 is estimated to average 402 hours per response, including the time for reviewing instructions,
searching existing data sources, gathering and maintaining the data, and completing and reviewing the collection of information.
Send comments regarding the burden estimate or any aspect of the collection of information, including suggestions for reducing
burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer);
and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer
for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display
a valid control number (44 U.S.C. § 3512 (a)).

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 1: Metric #1 Reserve Margins
1.00

1.01

1.02

1.03

1.04

1.05

Reporting Period
2014
Forecasted Peak Demand (MW). Enter the value of the forecasted
net coincident peak load (actual peak, not normalized) integrated over
the peak hour; net of behind-the-meter photovoltaic and energy
efficiency for the entire Balancing Authority Area for the given
reporting period. For some RTOs/ISOs, this number may have been
determined prior to an initial capacity auction.
Publication Date of the Forecasted Peak Demand. Enter the date in
MM/YYYY format of the last binding capacity auction or the date of
00/0000
the forecast from the most recent planning process at which time the
peak demand was forecasted.
Total Anticipated Installed Capacity (MW). Enter the amount of
capacity expected to be available for the entire Balancing Authority
Area at the time the Forecasted Peak Demand was calculated for the
reporting period. This is the cleared capacity in the binding auction for
ISOs/RTOs with a capacity market. For IOUs and RTOs/ISOs without
capacity markets use the generation estimate used for the planning
process (e.g., Resource Adequacy, etc.)
Publication Date of the Estimate of the Total Anticipated Installed
Capacity. Enter the date in MM/YYYY format. (This may be the same 00/0000
date as the Date of Forecasted Peak Demand)
Anticipated Reserve (MW). The value for Anticipated Reserves for the
entire Balancing Authority Area for the given reporting period is
calculated as [Total Anticipated Installed Capacity – Forecasted Peak
Demand]. (Automatically calculated)
Anticipated Reserve Margin (%). The Anticipated Reserve Margin is
the ratio of the amount of anticipated reserves in relation to the
forecasted demand, calculated as [(Total Anticipated Installed
Capacity – Forecasted Peak Demand) / Forecasted Peak Demand].
(Automatically calculated)

2015

2016

00/0000

2018

2017

00/0000

0/0000

00/0000

0/0000

#DIV/0!

Federal Energy Regulatory Commission STAFF DRAFT

1.06

1.07

1.08
1.09

1.10

1.11

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Actual Peak Demand (MW). Enter the value of the net coincident
peak load (actual peak, not normalized) integrated over the peak
hour; net of behind-the-meter photovoltaic and energy efficiency for
the entire Balancing Authority Area for the given reporting period.
Total Available Installed Capacity (MW). Enter the amount of
capacity that was available for the entire Balancing Authority Area at
the time the Actual Peak Demand was realized during the reporting
period. This is the available capacity at the time of the Actual Peak
Demand.
Date of the Actual Peak Demand. Enter the date in DD/MM/YYYY
00/00/0000
format.
Actual Reserve (MW). The value for the actual reserves for the entire
Balancing Authority Area for the given reporting period calculated as
[Total Actual Installed Capacity – Actual Peak Demand].
(Automatically calculated)
Actual Reserve Margin (%). The actual reserve margin is the ratio of
the amount of reserves procured for a specific reporting period,
#DIV/0!
calculated as [(Total Actual Installed Capacity – Actual Peak Demand) /
Actual Peak Demand]. (Automatically calculated)
Adjustment methodology. Describe your adjustment methodology by
technology.

00/00/0000

#DIV/0!

text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 1: Metric #2 Average Heat Rates

MWhi - Total Production of Resource i

𝐻𝐻𝐻𝐻𝑇𝑇 =
2.00
2.01
2.02
2.03
2.04
2.05

∑𝑛𝑛𝑖𝑖=1 𝐻𝐻𝐻𝐻𝑖𝑖 ∗ 𝑀𝑀𝑀𝑀𝑀𝑖𝑖
∑𝑛𝑛𝑖𝑖=1 𝑀𝑀𝑀𝑀𝑀𝑖𝑖

Reporting Period
Average Heat Rate of Oil-fired Steam Generation (Btu/kWh).
Average Heat Rate of Natural Gas-fired Steam Generation (Btu/kWh).
Average Heat Rate of Coal-fired Generation (Btu/kWh).
Average Heat Rate of Combustion Turbine Generation (Btu/kWh).
Average Heat Rate of Combined Cycle Generation (Btu/kWh).
Explanatory Text. Explanations, for example, if you haven't used the
primary fuel for dual-fuel units, please explain.

2014

0
0
0
0
0

2015

0
0
0
0
0

2016

0
0
0
0
0

2017

0
0
0
0
0

2018

0
0
0
0
0

text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 1: Metric #3 Fuel Diversity

Reporting Period

Summer Capacity Rating by Fuel Type (MW)
3.00 Biomass
3.01 Coal
3.02 Geothermal
3.03 Natural Gas
3.04 Other Fuel
3.05 Petroleum Products
3.06 Solar
3.07 Nuclear (All Fuel Types)
3.08 Water (Hydro)
3.09 Pumped / Hydro Storage
3.10 Wind
3.11 Battery
Total Energy Generated by Fuel Type (MWh)
3.12 Biomass
3.13 Coal
3.14 Geothermal
3.15 Natural Gas
3.16 Other Fuel
3.17 Petroleum Products
3.18 Solar
3.19 Nuclear (All Fuel Types)
3.20 Water (Hydro)
3.21 Wind
3.22 Explanatory Text. Add any explanatory text if necessary

2014

2015

2018

2017

2016

Text

"Summer Capacity" means the Net Summer Capacity rating as defined by the Energy Information Administration (EIA)
Note: There is no row for Energy Generated (MWh) by Fuel Type for the Pumped Storage and Battery Categories

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 1: Metric #4 Capacity Factor by Technology Type

4.00
4.01
4.02
4.03
4.04
4.05
4.06
4.07
4.08
4.09

Technology / Fuel Type
Units
Coal (All types)
All sizes
Oil (Steam)
All sizes
Natural Gas (Steam)
All sizes
Gas / Oil Turbine
All sizes
Combined Cycle
All sizes
Nuclear (All Fuel Types)
All sizes
Hydro
All sizes
Wind
All sizes
Solar
All sizes
Explanatory Text. Add any explanatory text if necessary

Reporting Period

2014
Capacity Factor*
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

2015
2016
Capacity Factor* Capacity Factor*
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Text

2017
Capacity Factor*
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

2018
Capacity Factor*
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

* Note: The capacity factor will range between 0 and 1. For example, a value of 0.89 indicates a capacity factor of 89 percent

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 1: Metric #5 Emergency Energy Alerts (EEA Level 1 or Higher)
Reporting Period
5.00 Number of EEAs (Level 1 or higher) (Integer). Report the number of
recognized EEAs during the reporting period. If an alert escalates from a
lower level to a higher level (e.g., a Level 1 converts to a Level 2 or 3),
report as one event.
5.01 Number of EEA Hours (HH:MM). Report the sum of hours in which any
level of an EEA occurred during the reporting period. Report a number in
the form HH:MM where HH is the number of hours and MM is the
number of minutes.
5.02 Amount of Load Shed during EEA Alerts (MWh). Report the total MWh of
load that were shed during the EEAs in the reporting period. (Do not
report the amount of interruptible load terminated due to emergency
conditions).
5.03 Explanatory Text. Add any explanatory text if necessary.

2014

2015

2016

2017

2018

0.00

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 1: Metric #6 Performance by Technology Type during EEA Level 1 or Higher

𝑇𝑇𝑘𝑘 =

6.00
6.01
6.02
6.03
6.04
6.05
6.06
6.07
6.08
6.09

𝑁𝑁 𝑀𝑀𝑀𝑀
∑𝑖𝑖=1
𝑖𝑖𝑖𝑖
𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑖𝑖𝑖𝑖

𝑁𝑁

* 100

Reporting Period
Technology / Fuel Type
Units
Coal (All types)
All sizes
Oil (Steam)
All sizes
Natural Gas (Steam)
All sizes
Gas / Oil Turbine
All sizes
Combined Cycle
All sizes
Nuclear (All Fuel Types)
All sizes
Hydro
All sizes
All sizes
Wind
Solar
All sizes
Explanatory Text. Add any explanatory text if necessary

2014
Performance
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

2015
Performance
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

2016
Performance
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
Text

2017
Performance
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

2018
Performance
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 1: Metric #7 Resource Availability (EFORd)

7.00
7.01
7.02
7.03
7.04
7.05
7.06
7.07
7.08
7.09

Reporting Period

2014
EFORd
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

2015
EFORd
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

2016
EFORd
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Text

2017
EFORd
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

2018
EFORd
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #8 Number and Capacity of Reliability Must-Run Units
8.00

8.01
8.02
8.03

8.04

Reporting Period
Number of RMR Units (Integer). Number of generation units under reliability must-run
(RMR) or equivalent contracts in each reporting period. Please note that RTOs and ISOs
use various terms to refer to such arrangements, e.g., “System Support Resources” in
MISO. For the purposes of this report, such arrangements are collectively referred to as
RMR. (RMR refers to "out of market" contracts for specific generation units in the
organized markets.)
Total Capacity of RMR Units (MW). Sum of the Nameplate capacity of the generation
units under RMR or equivalent contracts for each reporting period.
Total Available Installed Capacity (MW). (Automatically copied from Metric 1)
RMR MW as Percent of Total Available Installed Capacity (%). The Total Capacity of RMR
units as a percentage of the Total Available Installed Capacity of the Balancing Authority
Area. (Automatically calculated)
Explanatory Text. Add any explanatory text if necessary

2014

2016

2015

2017

2018

#DIV/0!

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #9 Reliability Must-Run Contract Usage
9.00
9.01
9.02
9.03

Reporting Period
Hours RMR Units Were Used (Integer). Number of unit hours that generation units under reliability
must-run (RMR) or equivalent contracts were called upon.
Total MWh Provided by RMR Units (Integer). Sum of the MWh that all RMR units provided in each
reporting period.
Total Cost of RMR Units ($). Sum of the costs of all RMR contracts for each reporting period.
Explanatory Text. Add any explanatory text if necessary

2014

2015

2016

2017
0

- $

2018
0

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #10 Demand Response Capability
10.00

10.01
10.02

10.03
10.04

10.05

Reporting Period
Total MWh of Demand Response (MWh). MWh of Demand Response resources in each
reporting period. (Includes RTO/ISO-registered and controlled demand response. See
the User Guide for instructions.)
Total Available Installed Capacity (MW). (Automatically copied from Metric 1)
Demand Response Resources as a Percent of Total Available Installed Capacity (%). The
Total MW of Demand Response as a percentage of the Total Available Installed Capacity
of the Balancing Authority Area. (Automatically calculated)
Actual Peak Demand (MW). (Automatically copied from Metric 1)
Demand Response Resources as a Percent of Actual Peak Demand (%). The Total MW
of Demand Response as a percentage of the Actual Peak Demand in the Balancing
Authority Area. (Automatically calculated)
Explanatory Text. Provide any additional information if necessary.

2014

2016

2015

2017

2018

#DIV/0!

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #11 Unit Hours Mitigated

Reporting Period
11.00 Number of Unit Hours With Active Mitigation (Day-ahead) (Integer). Provide the
number of unit hours in each reporting period that any generation unit(s) offer was
mitigated in the day-ahead energy market.
11.01 Number of Unit Intervals With Active Mitigation (Real-time) (Integer). Provide the
number of unit intervals in each reporting period that any generation unit(s) was
mitigated in the real-time energy market.
11.02 Percent of Unit Hours With Active Mitigation (Day-ahead) (%). Calculate the fraction of
unit hours in each reporting period that any generation unit(s) offer cap in the day-ahead
energy market was set due to mitigation and report that as a percent of the number of all
unit hours. (Automatically calculated)
11.03 Percent of Unit Intervals With Active Mitigation (Real-time) (%). Calculate the fraction of
unit intervals in each reporting period that any generation unit(s) offer cap in the realtime market was set due to mitigation and report that as a percent of the number of all
unit hours. (Automatically calculated)
11.04 Explanatory Text. Provide any additional information if necessary.

2014

2016

2015

2017

2018

0.0%

text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #12 Wholesale Power Costs by Charge Type
Reporting Period
Net Energy (MWh)
12.00 Net Energy for Load. Total generation plus imports minus exports
minus losses. From FERC Form No. 714, Schedule 3, Balancing
Authority Net Energy for Load and Peak Demand Sources by Month,
Net Energy for Load, Column (e), sum the entries in column (e) for
the months in the reporting period (Lines 1-12). To compute the Net
Energy for Load for a Reporting Period which spans calendar years,
you will need to include months from another annual Form No. 714.
See User Guide.
Wholesale Power Cost Components ($)
12.01 Energy Component of Total Wholesale Power Cost ($). Report the
total energy component (including system marginal price,
congestion and losses) of wholesale power costs paid by load and
exports for each reporting period. This component is the real-time
load weighted average locational marginal price.
12.02 Capacity Component of Total Wholesale Power Cost ($). Report the
total capacity component of wholesale power costs paid by load for
each reporting period. If your RTO/ISO does not have a centralized
capacity market enter zero.
12.03 Transmission Component of Total Wholesale Power Cost ($).
Report the total FERC-approved Transmission Charges paid by load
for each reporting period.
12.04 Ancillary Service Component of Total Wholesale Power Cost ($).
Report the total ancillary service component of wholesale power
costs paid by load for each reporting period. Include the cost for all
ancillary services such as black start, reactive power etc. that are not
included in the Operating Reserve charge type.

2014

2015

2016

2018

2017

Federal Energy Regulatory Commission STAFF DRAFT
12.05

12.06

12.07

12.08

12.09

Common Metrics 2020

Operating Reserves Component of Total Wholesale Power Cost ($).
Report the total operating reserves component of wholesale power
costs paid by load for each reporting period. Include costs for
ancillary services, such as regulation, spinning and non-spinning
reserves, and ramp products.
RTO and Regulatory Fee Component of Total Wholesale Power Cost
($). Report the total RTO cost and regulatory fee component of
wholesale power costs paid by load for each reporting period.
Include charges to NERC/Reliability organizations (including
Reliability Entity fees), RTO startup and expansion fees, etc.
Other Cost Component of Total Wholesale Power Cost ($). If the
RTO accounts for cost categories that are not included in the above
list (i.e., uplift charges), please report those costs here and describe
the cost category in the Explanatory Text category below. Note, for
example, that the PJM Balancing Operating Reserve credit and Day
Ahead Operating Reserve credit are included in this line.
Total Wholesale Power Cost ($). The worksheet calculates the total
wholesale power cost paid by load for each reporting period in
dollars by summing the cost components in lines 12.01 through
12.07. (Automatically calculated)
Explanatory Text. Please report any unusual events that provide
context to this metric. For instance, the expansion of the RTO/ISO
footprint may explain changes in the capacity costs.

Reporting Period
Wholesale Power Cost Components ($/MWh)
12.10 Energy Component of Total Wholesale Power Cost (Automatically
calculated)
12.11 Capacity Component of Total Wholesale Power Cost
(Automatically calculated)
12.12 Transmission Component of Total Wholesale Power Cost
(Automatically calculated)
12.13 Ancillary Service Component of Total Wholesale Power Cost
(Automatically calculated)

Authorization: FERC-922 OMB Control No. 1902-0262

text

2014

2015

2016

2017

2018

#DIV/0!

#DIV/0!
15

Federal Energy Regulatory Commission STAFF DRAFT
12.14
12.15
12.16
12.17

Common Metrics 2020

Operating Reserves Component of Total Wholesale Power Cost
(Automatically calculated)
RTO/ISO and Regulatory Fee Component of Total Wholesale Power
Cost (Automatically calculated)
Other Cost Component of Total Wholesale Power Cost
(Automatically calculated)
Total Wholesale Power Cost (Automatically calculated)

Authorization: FERC-922 OMB Control No. 1902-0262

#DIV/0!

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #13 Price Cost Markup
t = hours in reporting period (e.g., 8,784 hours * 12 five-minute intervals in a leap year
or 8,760 hours * 12 five-minute intervalsin other years)
Pi = Real-Time price-based offer in hour i
Ci = Real-Time cost-based offer in hour i
PC = Price Cost Markup
𝑃𝑃𝑃𝑃 =

∑𝑁𝑁
𝑖𝑖=1(𝑃𝑃𝑖𝑖 − 𝐶𝐶𝑖𝑖 )
𝑡𝑡

Calculate two supply curves for each five-minute interval of the real-time market in the
reporting period. The first curve (price curve) is based on the offer used in the price
formation for that interval. The second curve (cost curve) is based on the default bid of
the unit for that interval. For each curve, starting at the lowest cost offers, aggregate the
MWs of the curves until the aggregated MW value equals the real-time demand for that
interval. The intersection of the demand curve with the supply curves provides two prices.

Reporting Period

13.00 Average of the Price Cost Margin ($). Report the average price cost markup of all of the
hours.
13.01 Top Ten Percent of the Price Cost Margin ($). Report the average price cost markup of
the highest price 10 percent of the hours.
13.02 Bottom Ten Percent of the Price Cost Margin ($). Report the average price cost markup
of the lowest price 10 percent of the hours.
13.03 Explanatory Text. Explain any variations from this formula, e.g., the RTO/ISO used the
difference of Pi and Ci for the marginal resource for each five minute interval.

2014

2015

2016

2017

2018

Text

Note: This calculation does not account for physical restrictions on units,
transmission constrains or ramping restrictions.

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #14 Fuel-Adjusted Wholesale Energy Price

14.00
14.01
14.02

14.03

14.04

14.05

14.06

14.07

𝑃𝑃𝑎𝑎𝑎𝑎𝑎𝑎 = 𝐿𝐿𝐿𝐿𝐿𝐿 𝐹𝐹𝑔𝑔𝑔𝑔𝑔𝑔 ∗ 𝐴𝐴𝐴𝐴𝐴𝐴𝑔𝑔𝑔𝑔𝑔𝑔 + 𝐹𝐹𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 ∗ 𝐴𝐴𝐴𝐴𝐴𝐴𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐

Reporting Period

System-wide LMP ($). Provide the average real-time LMP for the reporting
period.
Reference Year (YYYY). Report the reference year for the fuel price
adjustment.
Fraction of Hours that Natural Gas was the Marginal Fuel. For purposes of
this metric, estimate the fraction of hours in the reporting period that natural
gas was the marginal fuel. Report the fraction with two decimal places.

Fraction of Hours that Coal was the Marginal Fuel. For purposes of this
metric, estimate the fraction of hours in the reporting period that coal was the
marginal fuel. Report the fraction with two decimal places.
Fuel Adjustment Factor Natural Gas. Calculate the natural gas price
adjustment for each reporting period compared to the Reference Year.
Report the fraction with two decimal place.
Fuel Adjustment Factor Coal. Calculate the coal price adjustment for each
reporting period compared to the Reference Year. Report the fraction with
two decimal places.
Fuel-Adjusted Wholesale Price ($). The spreadsheet will automatically
calculate the adjustment based on the equation above. (Automatically
calculated)

Explanatory Text. Explain any variations from this formula, e.g., unable to
estimate the fraction of hours that a fuel was marginal.

2014
$

2015
-

2016
-

2017
-

2018
-

0.00

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.

Group 2: Metric #15 Energy Market Price Convergence
Compute this metric four different ways using these two values, the load-weighted average of real time prices and the load-weighted average of day-ahead prices.
𝑖𝑖 = ℎ𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜 𝑖𝑖𝑖𝑖 𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟 𝑦𝑦𝑦𝑦𝑦𝑦𝑦𝑦 (𝑒𝑒. 𝑔𝑔. , 8,784 ℎ𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜 𝑖𝑖𝑖𝑖 𝑙𝑙𝑙𝑙𝑙𝑙𝑙𝑙 𝑦𝑦𝑦𝑦𝑦𝑦𝑦𝑦𝑦𝑦 𝑎𝑎𝑎𝑎𝑎𝑎 8,760 ℎ𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜 𝑖𝑖𝑖𝑖 𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜𝑜 𝑦𝑦𝑦𝑦𝑦𝑦𝑦𝑦𝑦𝑦)

Equation 1:

Equation 2:

𝑛𝑛

𝑖𝑖=1

𝑘𝑘=1

𝑛𝑛

𝑖𝑖=1

𝑘𝑘=1

𝑀𝑀𝑀𝑀𝑖𝑖
𝑅𝑅𝑅𝑅𝑖𝑖𝑖𝑖 − 𝐷𝐷𝐷𝐷𝑖𝑖𝑖𝑖 𝑀𝑀𝑀𝑀𝑖𝑖𝑖𝑖
∗ �
�
∑𝑛𝑛𝑘𝑘=1 𝑀𝑀𝑀𝑀𝑖𝑖𝑖𝑖
𝑀𝑀𝑀𝑀

Equation 3:

𝑀𝑀𝑀𝑀𝑖𝑖
|𝑅𝑅𝑅𝑅𝑖𝑖𝑖𝑖 − 𝐷𝐷𝐷𝐷𝑖𝑖𝑖𝑖 | 𝑀𝑀𝑀𝑀𝑖𝑖𝑖𝑖
∗ �
�
∑𝑛𝑛𝑘𝑘=1 𝑀𝑀𝑀𝑀𝑖𝑖𝑖𝑖
𝑀𝑀𝑀𝑀

Reporting Period
15.00
Equation 1 ($/MWh). Load weighted average of price differences between DA
and RT market. See Equation 1.
15.01
Equation 2 ($/MWh). Load weighted average of absolute value of price
differences. See Equation 2.
15.02
Equation 3 ($/MWh). Load weighted average of quotient of price difference and
DA price. See Equation 3.
15.03
Equation 4 ($/MWh). Load weighted average of absolute value of quotient of
price difference and DA price. See Equation 4.
15.04
Explanatory Text. Provide any additional information if necessary.
Zonal Convergence (optional)
Reporting Period
Zone Name
15.05
15.06
Equation 1 ($/MWh). Load weighted average of price differences between DA
and RT market. See Equation 1.

Equation 4:
2014

𝑛𝑛

𝑖𝑖=1

𝑘𝑘=1

𝑛𝑛

𝑖𝑖=1

𝑘𝑘=1

𝑀𝑀𝑀𝑀𝑖𝑖
∗ �
�
𝑀𝑀𝑀𝑀
𝑀𝑀𝑀𝑀𝑖𝑖
∗ �
�
𝑀𝑀𝑀𝑀
2015

𝑅𝑅𝑅𝑅𝑖𝑖𝑖𝑖 − 𝐷𝐷𝐷𝐷𝑖𝑖𝑖𝑖
𝑀𝑀𝑀𝑀𝑖𝑖𝑖𝑖
𝐷𝐷𝐷𝐷𝑖𝑖𝑖𝑖
∑𝑛𝑛𝑘𝑘=1 𝑀𝑀𝑀𝑀𝑖𝑖𝑖𝑖

|𝑅𝑅𝑅𝑅𝑖𝑖𝑖𝑖 − 𝐷𝐷𝐷𝐷𝑖𝑖𝑖𝑖 |
𝑀𝑀𝑀𝑀𝑖𝑖𝑖𝑖
𝐷𝐷𝐷𝐷𝑖𝑖𝑖𝑖
∑𝑛𝑛𝑘𝑘=1 𝑀𝑀𝑀𝑀𝑖𝑖𝑖𝑖
2016

2017

2018

2014
$

2015
-

Text
2016

2017
-

2018
-

Federal Energy Regulatory Commission STAFF DRAFT
15.07
15.08
15.09

Common Metrics 2020

Equation 2 ($/MWh). Load weighted average of absolute value of price
differences. See Equation 2.
Equation 3 ($/MWh). Load weighted average of quotient of price difference and
DA price.
Equation 4 ($/MWh). Load weighted average of absolute value of quotient of
price difference and DA price.

Authorization: FERC-922 OMB Control No. 1902-0262

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #16 Congestion Management
16.00

16.01
16.02
16.03

16.04

Reporting Period
Total Day-Ahead Congestion Charges (RTO/ISO wide) ($). For each reporting period,
enter the sum of (Day-Ahead MWh*CLMP) where Day-Ahead MWh consists of MWh
settled at day-ahead market energy prices (which includes financial schedules and virtual $
transactions) and CLMP is the congestion component of the day-ahead energy market
price.
Net Payments to FTR Holders (RTO/ISO wide) ($). Enter the sum of reporting period
congestion charges distributed to holders of Financial Transmission Rights (FTRs) or their
$
equivalent such as Transmission Congestion Rights (TCR) or Congestion Revenue Rights
(CRRs), net of revenue received from counterflow FTR holders.
Net Energy for Load (RTO/ISO wide) (MWh). (Automatically copied from Metric 12)
Congestion Charges per MWh of Load Served (RTO/ISO wide) ($/MWh). The worksheet
will calculate the ratio of the Total Day-Ahead Congestion Charges divided by the Net
Energy for Load. (Automatically calculated)
Net Payments to FTR Holders as a percent of Total Congestion Charges (RTO/ISO wide)
(%). The worksheet will calculate the ratio of Net Payments to FTR Holders divided by the
Total Day-Ahead Congestion Charges. (Automatically calculated)

16.05 Net Payments to Load Serving Entities (LSEs) through FTRs, ARRs, etc. ($). Total revenue
received by LSEs through financial instruments such as auction revenue rights and financial
$
transmission rights, net of charges paid for counterflow ARRs or FTRs. If an ARR is "selfscheduled" (i.e. converted) into an FTR, please report only the revenue (or charge)
received from the FTR.
Net Payments to Load Serving Entities (LSEs) as a percent of Total Congestion Charges
(%) The worksheet will calculate the percentage of revenue received by LSEs through FTRs
and ARRs as a percent of Total Day-Ahead Congestion Charges for the reporting period
16.06 expressed as a percent. (Automatically Calculated)

2014

2015

2016

2017

2018

#DIV/0!

16.07 Explanatory Text. Provide any additional information if necessary.

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #17 Administrative Costs

Reporting Period
17.00 Administrative Costs ($). Sum the administrative costs (both capital and non-capital)
billed by the RTO/ISO for each reporting period. RTOs/ISOs with capacity markets
$
should see the User Guide for instructions.
17.01 Administrative Costs (FERC Form No. 1) ($). Report the TOTAL Administrative &
General Expenses (row 197), page 323 from the last quarter of the filing for the
reporting period. RTOs/ISOs with capacity markets should see the User Guide for
$
instructions.
17.02 Net Energy for Load (MWh). (Automatically copied from Metric 12)
17.03 Administrative Costs per MWh of Load Served (%). The worksheet will calculate
Administrative Costs divided by the Net Energy for Load for each reporting period .
(Automatically calculated)
17.04 Administrative Costs (FERC Form No. 1) per MWh of Load Served (%). The
worksheet will calculate Administrative Costs (FERC Form No. 1) divided by the Net
Energy for Load for each reporting period. (Automatically calculated)
17.05 Explanatory Text. Describe any significant changes to administrative charges that
influence the Administrative Costs reported above, such as prior-year collection trueups, expansion of RTO/ISO footprint, etc.

2014

2015

2016

2017

2018

#DIV/0!

text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #18 New Entrant Net Revenues

Reporting Period

Net Revenue for New Entrant (Combustion Turbine)
18.00 Prototypical New Entrant Variable Production Cost (Combustion Turbine) ($). Enter the
new entrant's estimated variable production cost for a combustion turbine for the
$
reporting period.
18.01 Prototypical New Entrant Energy Revenues Received (Combustion Turbine) ($). Enter the
new entrant's estimated revenue received from RTO/ISO energy and ancillary services (as
$
defined in the RTO/ISO Tariff) for a combustion turbine for the given reporting period.
18.02 Size in MW of Prototypical New Entrant (Combustion Turbine) (MW). Enter the
nameplate capacity of the unit used in the calculation.
18.03 Net Revenue for New Entrant (Combustion Turbine) ($). The difference between the
Prototypical New Entrant Energy Revenues Received less the Prototypical New Entrant's
Variable Production Cost. (Automatically calculated)
Net Revenue for New Entrant (Combined Cycle)
18.04 Prototypical New Entrant Variable Production Cost (Combined Cycle) ($). Enter the new
entrant's estimated variable production cost for a combustion cycle for the reporting
period.
18.05 Prototypical New Entrant Energy Revenues Received (Combined Cycle) ($). Enter the new
entrant's estimated revenue received from RTO/ISO energy and ancillary services (as
defined in the RTO/ISO Tariff) for a combined cycle for the given reporting period.
18.06 Size in MW of Prototypical New Entrant (Combined Cycle) (MW). Enter the nameplate
capacity of the unit used in the calculation.
18.07 Net Revenue for New Entrant (Combined Cycle) ($). The difference between the
Prototypical New Entrant Energy Revenues Received less the Prototypical New Entrant's
Variable Production Cost. (Automatically calculated)
18.08 Explanatory Text. Please provide a description on how the cost and revenue estimate
were derived for a hypothetical new entrant, including the assumed location (i.e., high cost
zone, etc.)

2014

2015

2016

2017

2018

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 2: Metric #19 Order No. 825 Shortage Intervals and Reserve Price Impacts
s = a shortage event
Ts = duration of event s
i = 5-minute interval before shortage in reporting period
k = 5-minute interval during shortage in reporting period
MW = reserves for 5-minute interval
RMCP = Reserve Market Clearing Price for highest quality product (i.e., spinning reserve)
for 5-minute interval

19.00

19.01
19.02

19.03

Reporting Period
Number of Shortage Events. Total number of distinct shortage events in reporting
period. An event is a contiguous set of shortage intervals defined by Order No. 825 that
occurred in the reporting period. Report an integer.
Total Duration of Shortage Events. Total minutes/hours where shortage occurred
during the reporting period. Report an integer.
Average Duration of Shortages. The worksheet will calculate the ratio of the Total
Duration of Shortage Events divided by the Number of Shortage Events. (Automatically
calculated)
Total Size of Shortage Events. Total MW shortage during the reporting period. This is a
multi-step calculation. First, for each shortage event calculate the difference between
the average MW available during the shortage and the average of the MWs required of
the highest quality reserve product (i.e., spinning reserve) in the three intervals before
the shortage began. Second, for each event create the product of this difference and the
event duration and sum these for the reporting period. Report an integer.
� 𝐴𝐴𝐴𝐴𝐴𝐴 𝑀𝑀𝑀𝑀𝑖𝑖 , 𝑀𝑀𝑀𝑀𝑖𝑖−1 , 𝑀𝑀𝑀𝑀𝑖𝑖−2 − 𝐴𝐴𝐴𝐴𝐴𝐴 𝑀𝑀𝑀𝑀𝑘𝑘
𝑖𝑖+𝑘𝑘

𝑖𝑖+𝑘𝑘

2015

2017

2018

#DIV/0!

2016

#DIV/0!

∗ 𝑇𝑇𝑠𝑠

19.04 Average Size of the Shortage Events. The average size of all of the shortage events in
the reporting period. Divide Total Size of Shortage Events by the Total Duration of
Shortage Events. (Automatically Calculated)
𝐴𝐴𝐴𝐴𝐴𝐴 𝑀𝑀𝑀𝑀𝑖𝑖 , 𝑀𝑀𝑀𝑀𝑖𝑖−1 , 𝑀𝑀𝑀𝑀𝑖𝑖−2 − 𝐴𝐴𝐴𝐴𝐴𝐴 𝑀𝑀𝑀𝑀𝑘𝑘
�
𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝑜𝑜𝑜𝑜 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸

2014

#DIV/0!

∗ 𝑇𝑇𝑠𝑠

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

19.05 Total Price Differential of the Shortage Events. The price differential of the shortage
event (the increase between 5-minute intervals) in the reporting period. This is a multistep calculation. First, for each shortage event calculate the difference between the
reserve market clearing price of the highest quality reserve product (i.e., spinning
reserve) in the three intervals before the shortage began and the average price of the
reserve product in the shortage, and multiply this difference by the duration of the
shortage. Sum for all events for the reporting period. Report in $/MWh.
� 𝐴𝐴𝐴𝐴𝐴𝐴 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖 , 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖−1 , 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖−2 − 𝐴𝐴𝐴𝐴𝐴𝐴 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑘𝑘
𝑖𝑖+𝑘𝑘

∗ 𝑇𝑇𝑠𝑠

19.06 Average Price Differential of the Shortage Events. The average size of the price
differential of the shortage events in the reporting period. Divide Total Price Differential
of the Shortage Events by the Total Duration of Shortage Events. (Automatically
Calculated)
�
𝑖𝑖+𝑘𝑘

𝐴𝐴𝐴𝐴𝐴𝐴 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖 , 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖−1 , 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖−2 − 𝐴𝐴𝐴𝐴𝐴𝐴 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑘𝑘
𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝑜𝑜𝑜𝑜 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸

#DIV/0!

∗ 𝑇𝑇𝑠𝑠

19.07 Total Price Impact of the Shortage Events. The total price impact of the shortage events
in the reporting period. For each event where shortage pricing occurred, multiply the
duration of the shortage event by the product of the average size of each shortage event
and the price differential of each shortage event.
�( 𝐴𝐴𝐴𝐴𝐴𝐴 𝑀𝑀𝑀𝑀𝑖𝑖 , 𝑀𝑀𝑀𝑀𝑖𝑖−1 , 𝑀𝑀𝑀𝑀𝑖𝑖−2 − 𝐴𝐴𝐴𝐴𝐴𝐴 𝑀𝑀𝑀𝑀𝑘𝑘
𝑖𝑖+𝑘𝑘

∗ [𝐴𝐴𝐴𝐴𝐴𝐴 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖 , 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖−1 , 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖−2 − 𝐴𝐴𝐴𝐴𝐴𝐴 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑘𝑘 ]) ∗ 𝑇𝑇𝑠𝑠

19.08 Average Price Impact of the Shortage Events. The average price impact of the shortage
events in the reporting period. Divide the Total Price Impact of the Shortage Events by
the Total Duration of Shortage Events. (Automatically Calculated)
𝐴𝐴𝐴𝐴𝐴𝐴 𝑀𝑀𝑀𝑀𝑖𝑖 , 𝑀𝑀𝑀𝑀𝑖𝑖−1 , 𝑀𝑀𝑀𝑀𝑖𝑖−2 − 𝐴𝐴𝐴𝐴𝐴𝐴 𝑀𝑀𝑀𝑀𝑘𝑘 ∗
[𝐴𝐴𝐴𝐴𝐴𝐴 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖 , 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖−1 , 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑖𝑖−2 − 𝐴𝐴𝐴𝐴𝐴𝐴 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑘𝑘 ]
∗ 𝑇𝑇𝑠𝑠
�
𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝑜𝑜𝑜𝑜 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸
𝑖𝑖+𝑘𝑘

19.09 Explanatory Text (if necessary). Report any relevant information about this metric that
is not captured above e.g. including the product the price change is associated with,
improvements to the methodology, etc.

text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #20 Net Cost of New Entry (Net CONE) value

Reporting Period

Net Cost of New Entry
Capacity Zone Name
20.00
20.01
Net CONE value Used at the Most Recent Update ($/MW-Year). Report the estimated Net
CONE value used in the most recent update to the Net CONE value for each reporting
$
period.
20.02
Date of the Most Recent Net CONE Update (MM/YYYY). Enter the date in MM/YYYY
format.
20.03
Actual Net CONE value in Reporting Period ($/MW-Year). Rerun the estimate for each
historical reporting period using the actual value of local marginal prices (LMP) realized in
$
that reporting period (e.g., if the estimate for 2014 was produced in 2011 for the initial
auction, use the 2014 LMPs and re-run the Net CONE for 2014).
Explanatory Text. Provide any additional information if necessary.
20.04

2014

2015

00/0000

2016

00/0000

2017

00/0000

2018

00/0000

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #21 Resource Deliverability

Reporting Period
Resource Deliverability - Maximum Importable External Capacity into a Capacity Zone
21.00 Capacity Zone Name
21.01 Import Limitation into a zone (MW). The amount of external capacity that can be
imported into this zone for purposes of the capacity auction. Determined at the time of
the initial auction. Report for all capacity zones that are separately modeled.
21.02 Locational Generation Requirement (or equivalent) in the zone (MW). The amount of
capacity located inside the zone necessary (or is it available) to meet the estimated
demand in the zone (calculated at the time of the initial auction). Report for all capacity
zones that are separately modeled.
21.03

21.04

Locational Generation Procured in the zone (MW). The amount of capacity that was
actually procured for the zone in the auction. An RTO/ISO with a downward sloping
demand curve may actually procure more capacity than the Locational Requirement.
Report the actual amount of capacity procured in the auction for this zone.
Explanatory Text. Report any relevant information about this zone during the reporting
period (e.g., changes in boundaries, significant changes in load).

2014

2015

2016

2017

2018

text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #22 New Capacity (Entry)

Reporting Period
New Capacity Added
22.00 Capacity Zone Name
22.01 Number of Generation Units Added (Integer). Total number of generation units added
during the reporting period.
22.02
Increase in Capacity with Supply Obligations (MW). Amount of generating capacity that
has cleared in an auction, that now has an obligation to offer into the capacity market
during the reporting period. Do not report existing capacity that has been uprated.
22.03 Explanatory Text. Provide any additional information if necessary.

2014

2015

2016

2017

2018

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #23 Capacity Retirement (Exit)

Reporting Period
Capacity Retirement (Exit)
23.00 Capacity Zone Name
23.01 Number of Generation Units Taken out of Service (Integer). Total number of
generation units taken out of service during the reporting period.
23.02

23.03

Decrease in Capacity with Supply Obligations (MW). Amount of generating capacity
that no longer has an obligation to offer into the capacity market during the reporting
period. Do not report generation capacity that has been de-rated.
Explanatory Text. Provide any additional information if necessary.

2014

2015

2016

2017

2018

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #24 Forecasted Demand

Reporting Period
Forecasted Demand
Capacity Zone Name
24.00
24.01
Demand in the Zone (time of initial auction) (MW). Total estimated coincident peak
demand integrated over the hour needed for this zone at the time of the initial auction
for the reporting period. Note that this load value is not weather-normalized and is the
peak value assigned to that zone from the estimated region peak at the time of the initial
auction.
24.02
24.03

Peak Demand Realized in the Zone (during actual reporting period) (MW). Peak
demand (not weather normalized) realized in this zone during the reporting period.
Explanatory Text. Provide any additional information if necessary.

2014

2015

2016

2017

2018

Text

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #25 Capacity Market Procurement and Prices

Reporting Period
Capacity Market Procurement & Prices (RTO-wide)
25.00 Date That the Capacity Auction took Place (MM-YYYY). Enter the date that the initial
capacity auction took place.
25.01 Start Date of the Reporting Period of capacity auction (MM-YYYY).
25.02 Total Capacity Offered into the Auction (RTO-wide) (MW). Enter the total capacity that
offered into the entire RTO for the relevant reporting period.
25.03 Total Capacity Cleared (RTO-wide) (MW). Enter the total capacity the cleared for the
entire RTO during the relevant reporting period.
25.04 Capacity Market Clearing Price (RTO-wide) ($/MW-day). Enter the RTO-wide clearing
price for the relevant reporting.
25.05 Explanatory Text. Provide any additional information if necessary.
Capacity Market Procurement & Prices (Zonal)

2014

2015

2016

2017

2018

00-0000

Text
Reporting Period

25.06 Capacity Zone Name
25.07 Total Capacity Offered into the Auction (Zonal) (MW). Enter the total capacity that
offered into each zone where price separation occurred for the relevant reporting
period.
25.08 Total Capacity Cleared (Zonal) (MW). Enter the total capacity that cleared in each zone
where price separation occurred during the relevant reporting period.
25.09 Capacity Market Clearing Prices (Zonal) ($/MW-day). Enter the clearing price for each
zone where price separation occurred for the relevant reporting period.
25.10 Amount of Capacity in this Zone in Bilateral Contracts, if Known (MW). Total capacity
of bilateral contracts in this zone during the relevant period.

2014

2015

2016

2017

2018

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #26 Capacity Obligations and Performance Assessment Events

Reporting Period
Capacity Obligations (RTO-wide)
26.00 Total Capacity with Capacity Obligation (RTO-wide) (MW). Enter the cleared capacity
eligible for bonus payments or subject to penalties for the entire RTO during the
reporting period.
26.01 Total Number of Performance Assessment Events (RTO-wide) (Integer).
26.02 Total Duration of Performance Assessment Events (RTO-wide) (Hours).
26.03 Explanatory Text. Provide any additional information if necessary.
Capacity Obligations (Zonal)

2014

Reporting Period

2014

26.04 Capacity Zone Name
26.05 Total Capacity with Capacity Obligations (Zonal) (MW). Enter the cleared capacity
eligible for bonus payments or subject to penalties for the zone during the reporting
period.
26.06 Total Number of Performance Assessment Events (Zonal) (Integer).
26.07 Total Duration of Performance Assessment Events (Zonal) (Hours).

2015

2016

2015

Text

2017

2016

2018

2017

2018

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #27 Capacity Over-Performance

Equation 1.

∑𝑛𝑛𝑠𝑠=1 𝐶𝐶𝑠𝑠 ∗ 𝑇𝑇𝑠𝑠
∑𝑛𝑛𝑠𝑠=1 𝑇𝑇𝑆𝑆

𝑇𝑇𝑠𝑠 = 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝑜𝑜𝑜𝑜 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑠𝑠

𝐶𝐶𝑆𝑆 = 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶 𝑂𝑂𝑂𝑂𝑂𝑂𝑂𝑂 − 𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑠𝑠

Reporting Period
Capacity Eligible for Bonus Payments for Over-Performance (RTO-wide)
27.00 Total Number of Units That Over-Performed During Assessment Events (RTO-wide) (Integer).
27.01 Weighted Average Capacity that Over-Performed During Assessment Events (RTO-wide) (MW).
See Equation 1.
27.02 Explanatory Text. Provide any additional information if necessary.
Capacity Eligible for Bonus Payments for Over-Performance (Zonal)
Reporting Period
27.03 Capacity Zone Name
27.04 Total Number of Units That Over-Performed During Assessment Events (Zonal) (Integer).
27.05 Weighted Average Capacity that Over-Performed During Assessment Events (Zonal) (MW).
See Equation 1.

2014

2015

2016

2017

2018

Text
2014

2015

2016

2017

2018

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #28 Capacity Under-Performance

Equation 1.

∑𝑛𝑛𝑠𝑠=1 𝐶𝐶𝑠𝑠 ∗ 𝑇𝑇𝑠𝑠
∑𝑛𝑛𝑠𝑠=1 𝑇𝑇𝑆𝑆

𝑇𝑇𝑠𝑠 = 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝑜𝑜𝑜𝑜 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑠𝑠

𝐶𝐶𝑆𝑆 = 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶 𝑈𝑈𝑈𝑈𝑈𝑈𝑈𝑈𝑈𝑈 − 𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑𝑑 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑠𝑠
Reporting Period
Capacity Facing Penalty Payments for Under-Performance (RTO-wide)
28.00 Total Number of Units That Under-Performed During Assessment Events (RTO-wide)
(Integer).
28.01 Weighted Average Capacity that Under-Performed During Assessment Events (RTOwide) (MW). See Equation 1.
28.02 Explanatory Text. Provide any additional information if necessary.
Capacity Facing Penalty Payments for Under-Performance (Zonal)
Reporting Period
28.03 Capacity Zone Name
28.04 Total Number of Units That Under-Performed During Assessment Events (RTO-wide)
(Integer).
28.05 Weighted Average Capacity that Under-Performed During Assessment Events (RTOwide) (MW). See Equation 1.

2014

2015
-

2016
-

2017
-

2018
-

Text
2014

2015

2016

2017

2018

Federal Energy Regulatory Commission STAFF DRAFT

Common Metrics 2020

Authorization: FERC-922 OMB Control No. 1902-0262

Balancing Authority Area Respondent Name: Example: PJM, ISO-NE, etc.
Group 3: Metric #29 Total Capacity Bonus Payments and Penalties

Total Capacity Bonus Payments and Penalties (RTO-wide)
29.00 Total Bonus Payments for Over-Performance (RTO-wide) ($).

Reporting Period

2014

2016

2015

2017

2018

29.01 Total Penalties Charged for Under-Performance (RTO-wide) ($).
$
29.02 Total Capacity that Under-Performed (RTO-wide) (Integer). (Automatically copied
from Metric #28.01)
29.03 Total Capacity with Supply Obligations (RTO-wide) (Integer). (Automatically copied
from Metric #26.00)
29.04 Fraction of Capacity That did not Meet its Obligation (%). The spreadsheet will
calculate the ratio by dividing the total capacity that did not meet its obligations by the
total obligation. (Automatically calculated)
29.05 Explanatory Text. Provide any additional information if necessary.
Total Capacity Bonus Payments and Penalties (Zonal)
Reporting Period
29.06 Capacity Zone Name
$
29.07 Total Bonus Payments for Over-Performance (Zonal) ($).
29.08 Total Penalties Charged for Under-Performance (Zonal) ($).
$

#DIV/0!

2017

2018

Text
2014

2015
-

$
$

2016
-

$
$

File Type	application/pdf
File Modified	2020-01-24
File Created	2020-01-24