COMMON METRICS

Commission Staff Report

Federal Energy Regulatory Commission

August 26, 2014

This report does not necessarily reflect the views of the Commission, its Chairman, 

or individual Commissioners, and it is not binding on the Commission

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Table of Contents

Section Page

I. Metrics Initiative Overview.................................................................................... - 4 -

II. Common Metrics Report Summary........................................................................ - 5 -

III. Background......................................................................................................... - 6 -

IV. Common Metrics ................................................................................................ - 8 -

A. Reliability Metrics .............................................................................................. - 8 -

1. NERC Reliability Standards Compliance ...................................................... - 8 -

a. Definition.................................................................................................... - 8 -

b. Data Review and Metrics Assessment ....................................................... - 9 -

2. Dispatch Reliability ...................................................................................... - 11 -

a. Definition.................................................................................................. - 11 -

b. Data Review and Metrics Assessment ..................................................... - 11 -

3. Load Forecast Accuracy ............................................................................... - 16 -

a. Definition.................................................................................................. - 16 -

b. Data Review and Metrics Assessment ..................................................... - 16 -

4. Wind Forecasting Accuracy ......................................................................... - 18 -

a. Definition.................................................................................................. - 18 -

b. Data Review and Metrics Assessment ..................................................... - 18 -

5. Unscheduled Flows Metric........................................................................... - 19 -

a. Definition.................................................................................................. - 19 -

b. Data Review and Metrics Assessment ..................................................... - 20 -

6. Transmission Outage Coordination.............................................................. - 22 -

a. Definition.................................................................................................. - 22 -

b. Data Review and Metrics Assessment ..................................................... - 22 -

7. Long-Term Reliability Planning – Transmission......................................... - 25 -

a. Definition.................................................................................................. - 25 -

b. Data Review and Metrics Assessment ..................................................... - 25 -

8. Long-Term Reliability Planning – Resources .............................................. - 28 -

a. Definition.................................................................................................. - 28 -

b. Data Review and Metrics Assessment ..................................................... - 29 -

9. Interconnection and Transmission Process Metrics ..................................... - 32 -

a. Definition.................................................................................................. - 32 -

b. Data Review and Metrics Assessment ..................................................... - 33 -

10. Special Protection Systems....................................................................... - 37 -

a. Definition.................................................................................................. - 37 -

b. Data Review and Metrics Assessment ..................................................... - 37 -

B. Systems Operations Performance Metrics........................................................ - 39 -

1. System Lambda ............................................................................................ - 39 -

a. Definition.................................................................................................. - 39 -

b. Data Review and Metrics Assessment ..................................................... - 39 -

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2. Resource Availability ................................................................................... - 41 -

a. Definition.................................................................................................. - 41 -

b. Data Review and Metrics Assessment ..................................................... - 41 -

3. Fuel Diversity ............................................................................................... - 43 -

a. Definition.................................................................................................. - 43 -

b. Data Review and Metrics Assessment ..................................................... - 43 -

V. Other Metrics........................................................................................................ - 46 -

A. Other Metrics Specific to ISO and RTO Performance..................................... - 46 -

1. Load Forecasting Accuracy Metrics............................................................. - 46 -

2. Transmission Outage Metrics....................................................................... - 48 -

3. Long-Term Reliability Planning – Resources .............................................. - 50 -

4. Price-Cost Mark-Up ..................................................................................... - 55 -

5. Generator Net Revenue ................................................................................ - 56 -

6. Percentage of Megawatt Hours Mitigated.................................................... - 58 -

7. Market Pricing Metrics................................................................................. - 58 -

8. Energy Market Price Convergence............................................................... - 61 -

9. Congestion Management Metrics................................................................. - 61 -

10. Resource Availability Metric ................................................................... - 63 -

11. Renewables Metrics.................................................................................. - 64 -

12. Administrative Costs Metrics................................................................... - 66 -

13. Customer Satisfaction Metric................................................................... - 69 -

14. Billing Controls Metric............................................................................. - 70 -

B. Other Metrics Specific To Regions Outside ISO and RTO Markets ............... - 71 -

1. Outages With Less Than Two Days’ Notice................................................ - 71 -

2. Dollar Amount of Facilities Approved To Be Constructed For Reliability 

Purposes and Stakeholder Process For Transmission Planning ........................... - 72 -

3. Transmission Access/Transmission Service Requests Denials.................... - 74 -

4. Demand Response and Renewables Integration Discussions ...................... - 75 -

5. Congestion Management .............................................................................. - 76 -

6. Transmission System Availability................................................................ - 77 -

7. Clean Energy ................................................................................................ - 77 -

8. Price Metric .................................................................................................. - 80 -

Appendix A: Common Metrics

Appendix B: List of Participants

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Federal Energy Regulatory Commission Staff Report

Common Metrics

I. Metrics Initiative Overview

The primary purpose of the Common Metrics Report is to provide a platform for

review of Independent System Operator (ISO), Regional Transmission Organization 

(RTO) and utility performance. The Common Metrics Report provides two components 

for a performance review, as follows: (1) an analysis of the metrics data to confirm that 

the data provided by ISOs, RTOs and utilities in regions outside ISO and RTO markets 

are consistent with the definitions of the common metrics; and (2) an evaluation and

confirmation that the common metrics are measuring the same activities and have the 

same meaning across the industry.

This report represents the culmination of five years of effort by ISOs, RTOs and 

utilities in regions outside ISO and RTO markets to develop performance metrics in a 

Commission Staff-led Metrics Initiative. These entities are to be commended for their 

contributions to the Metrics Initiative. Their contributions, ranging from submitting 

comprehensive performance assessments, to providing technical expertise in developing 

the common metrics and discussing issues of concern to stakeholders in informal 

discussions, have played a significant role in the evolution of these measures into best 

practices in the industry, to the benefit of consumers and other stakeholders.

The analysis framework discussed in this report consists of 31 common metrics 

that measure performance for the six ISOs and RTOs and five utilities in regions outside 

ISO and RTO markets for the 2006-2010 period. While this information is appropriate as 

a starting point for reviewing performance, further analysis is needed. For example, 

additional data will need to be collected to ensure that the performance review reflects the 

most recent information available and to provide additional data points to ensure that 

performance is not biased by one-time events. Ideally, additional utilities in regions 

outside ISO and RTO markets would provide data, thereby providing a more 

comprehensive basis for performance reviews.

In order to undertake further data collection, approval from the Office of

Management and Budget (OMB) is required. Therefore, the next steps will be as follows:

 The Commission will request approval for further data collection on performance 

metrics for the 2008-2012 and 2010-2014 periods from OMB.

 Upon approval by OMB for additional data collection, the Commission will issue 

a notice requesting that the ISOs, RTOs and participating utilities provide 

information on a schedule to be specified in the notice.

As discussed more fully in the Common Metrics Report Summary, data collection 

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will be requested on 30 of the 31 metrics discussed in this report. The transmission 

loading relief (TLR) and unscheduled flow metric will not be included in the data 

collection request. After the ISOs, RTOs and utilities provide their performance 

assessments for the 2008-2012 and 2010-2014 periods, the Commission will issue reports

reviewing performance.

II. Common Metrics Report Summary

This report assesses which of the 31 metrics identified as candidates to be 

common metrics would be suitable as common metrics for evaluating the performance of 

ISOs, RTOs and utilities in regions outside ISO and RTO markets and provides the first 

comprehensive review of performance metrics data.

ISOs, RTOs and utilities1 submitted extensive performance metrics data, thereby 

providing the basis for a comprehensive performance review over the 2006–2010 review 

period. A five-year review period was chosen to ensure that performance evaluations 

would be based on long-term trends and not on short-term aberrations.

Significant features of the report are as follows:

 Commission Staff identified 31 metrics as candidates to be common metrics. 

After reviewing the ISO, RTO and utility reports, all but one of these metrics were

determined to meet the criteria for common metrics.2

 

o The one metric that is not a suitable common metric is the metric for TLRs 

and unscheduled flow events. As discussed below, TLRs or unscheduled 

flow events are not used universally in the industry and the data might not 

be a reliable indicator of their role in managing reliability. As a possible 

alternative, a more suitable common metric might be a measure of the 

megawatts managed by all manual actions as a percentage of total 

megawatts subject to congestion management. Such a measure would 

encompass the full range of manual procedures used by ISOs, RTOs and 

utilities and it would not count TLRs that are not implemented.

 The other common metrics have a common definition across ISOs, RTOs and 

utilities that apply to the same activities.

 1 Throughout this report, staff uses the term “utilities” to mean utilities in regions 

outside ISO and RTO markets.

2 The final common metrics are listed in Appendix A.

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o For example, a number of the reliability metrics are based on North 

American Electric Reliability Corporation (NERC) reliability standards that 

apply to all transmission providers. Accordingly, these metrics are suitable 

as common metrics since they are based on common definitions that are 

well understood by all transmission providers and have been reported on by

these entities for a number of years.

o As another example, inasmuch as ISOs, RTOs and utilities all perform 

interconnection and transmission services, the transmission planning 

metrics apply to activities that are common to ISOs, RTOs and utilities in 

regions outside ISO and RTO markets.

III. Background

The common metrics discussed in this report represent the culmination of an effort 

spanning over five years to develop metrics that measure the performance of ISOs, RTOs 

and utilities in regions outside ISO and RTO markets with respect to reliability, 

operations and market performance. The common metrics and the metrics information 

provided in this report were developed in a voluntary and collaborative process led by 

Commission Staff. Participants in the process included ISOs, RTOs, utilities, state 

regulators, consumer advocates and various industry stakeholders, such as developers of 

renewable resources.3

As detailed in FERC’s FY 2009–2014 Strategic Plan, the objectives of the Metrics 

Initiative are as follows: (1) develop appropriate operational and financial metrics for 

ISOs/RTOs; (2) explore and develop appropriate operational and financial metrics for 

utilities outside ISO and RTO regions; (3) establish appropriate common metrics between 

ISOs and RTOs and utilities outside ISO and RTO regions; (4) monitor implementation 

and performance; and (5) evaluate performance and seek changes as necessary. The first 

objective was completed with the submission of a Report to Congress on performance 

metrics for ISOs and RTOs.4

 The second objective was completed with the issuance of a 

Commission Staff Report on performance metrics in regions outside ISOs and RTOs.5

 

 3 Participants in the Metrics Initiative are listed in Appendix B.

4 Performance Metrics For Independent System Operators and Regional 

Transmission Organizations, Docket No. AD10-5-000, at 5 (Apr. 2011); see also 2010 

ISO/RTO Performance Metrics Commission Report, Docket No. AD10-5-000 (Oct. 21, 

2010).

5 Performance Metrics In Regions Outside ISOs and RTOs Commission Staff 

Report, Docket No. AD12-8-000 (Oct. 15, 2012).

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This report satisfies the requirements of the third and fourth objectives and takes the first 

step in meeting the requirements of the fifth objective. 

The ISOs and RTOs have submitted two metrics reports. The first report,

submitted on December 6, 2010, provided information on performance metrics for the 

2005–2009 period. The second report, submitted on August 31, 2011, provided 

information on performance metrics for the 2006–2010 period. The ISOs and RTOs that 

submitted reports are as follows:6

 ISO New England Inc. (ISO-NE)

 New York Independent System Operator, Inc. (NYISO)

 PJM Interconnection, L.L.C. (PJM)

 Midcontinent Independent System Operator, Inc. (MISO)

 Southwest Power Pool, Inc. (SPP)

 California Independent System Operator Corporation (CAISO)

Utilities in regions outside ISO and RTO markets provided information on 

performance metrics for the 2006 – 2010 period in reports submitted in the first quarter of 

2013. The utilities that submitted reports are as follows:

 Duke Energy Corporation7 (Duke)

 Southern Company (Southern)

 Louisville Gas and Electric Company and Kentucky Utilities Company

(LG&E/KU)

 PacifiCorp8

 Arizona Public Service Company (APS)

 6 Although these reports were filed in one document, this Commission Staff report 

refers to each ISO’s or RTO’s separate section of that joint document (i.e., SPP Report at 

323).

7 Duke Energy Corporation provided metrics information for the following 

subsidiaries: Duke Energy Carolinas, LLC (Duke Energy Carolinas), Carolina Power & 

Light Company d/b/a Progress Energy Carolinas, Inc. (Progress Energy Carolinas) and 

Florida Power Corporation, d/b/a Progress Energy Florida, Inc. (Progress Energy 

Florida).

8 PacifiCorp provided metrics information for the following subsidiaries: 

PacifiCorp-West (serving California, Oregon and Washington) and PacifiCorp-East 

(serving Idaho, Utah and Wyoming).

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IV. Common Metrics

The process for developing common metrics started with the development of 

metrics for regions outside ISO and RTO markets. During this stage, Commission Staff, 

with the collaboration of utility participants and industry stakeholders, refined the list of 

57 ISO and RTO metrics to a list of metrics that were also applicable to regions outside 

ISO and RTO markets. This list of common metrics, applicable to ISOs, RTOs and 

utilities outside of ISO and RTO markets, are the metrics proposed to be common metrics 

and to be discussed in this report.

To determine if these common metrics are, in fact, appropriate as common 

metrics, this report first confirms that the definition of each common metric is the same 

for ISOs, RTOs and utilities in regions outside these markets, and then evaluates the 

metrics data for each metric to determine if it is measuring the same activities and has the 

same meaning across all entities. To the extent that a metric is determined not to be 

suitable as a common metric, recommendations are made to revise the metric so that it 

can be a common metric. Finally, the metrics data in this report provide the first 

comprehensive review of performance based on the metrics data submitted by ISOs, 

RTOs and utilities outside these markets for the 2006–2010 period.

The common metrics measure reliability and systems operations performance. 

The reliability metrics, evaluated first, were chosen to measure the reliability of day-today operations using metrics such as compliance with national and regional reliability 

standards, real-time balance of supply and demand, and forecasting and special protection 

schemes. Reliability metrics were also chosen to measure long-term reliability using 

metrics such as long-term transmission planning and resource planning. The systems 

operations metrics were chosen to measure resource availability performance, resource 

costs and diversity.

A. Reliability Metrics

1. NERC Reliability Standards Compliance

a. Definition

This metric measures the number of violations of NERC reliability standards,9

provides information on how these violations were reported (self-reported or reported in 

audits), and indicates the severity of the violations. The metric also details compliance 

with operating reserve standards and unserved energy (or load shedding) caused by 

 9 A full listing of the NERC Reliability Standards is provided at 

http://www.nerc.com/page.php?cid=2|20 (last visited Aug. 26, 2014).

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violations. 

b. Data Review and Metrics Assessment

The reliability standards metrics10 measure both the significance of the violations 

and the effectiveness of self-reporting procedures in identifying violations in a timely 

manner. Of the twenty-nine violations shown on the table below, seventeen (more than 

half) were self-reported. Per NERC’s Violation Security Level Matrix, three incidents 

were rated severe, one was rated high and three were rated medium. All ISOs, RTOs and 

utilities were in compliance with operating reserve standards. No ISO, RTO or utility 

outside these markets reported unserved energy resulting from violations.

 10 These metrics are numbered 1 – 6 on the metrics table in Appendix A.

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2006 – 2010 Reliability Standards Violations

Entity Violations 

Made 

Public By 

NERC or 

FERC

Violations 

Made 

Public By 

NERC

Audits

Violations 

Self 

Reported

Severity Level of Public and 

Reported Violations

CAISO 0 0 1 Severity information not 

provided

ISO-NE 1 0 0 Severity information not 

provided

MISO 0 0 1 Severity information not 

provided

NYISO 0 0 0

PJM 0 0 0

SPP 0 0 0

APS 5 4 1 1 severe

Duke 0 0 0

LG&E/KU 0 0 1 1 medium

PacifiCorp 0 2 13 2 severe; 1 high; 2 medium

Southern 0 0 0

Note

Information represents data provided by ISOs, RTOs and utilities. FERC made public

two additional violations in SPP in 2007 after these reports were submitted.

The reliability standards violations and operating reserve standards data submitted 

and discussion of the data by the ISOs, RTOs and utilities indicate that these metrics 

measure the same activities and have the same meaning for ISOs, RTOs and utilities in 

regions outside ISO and RTO markets, and therefore are suitable as common metrics. 

Such an outcome is expected for these metrics that are based on reliability standards 

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developed for the entire electric industry by NERC. The data submitted and discussion 

of the data by the ISOs, RTOs and utilities for the unserved energy metric indicate that it 

is measuring the same activity and has the same meaning for ISOs, RTOs and utilities in 

regions outside ISO and RTO markets, and therefore is suitable as a common metric. 

2. Dispatch Reliability

a. Definition

Dispatch reliability is measured by three metrics as follows: (1) Balancing 

Authority Area Control Error Limit or Control Performance Standard 1 and Control 

Performance Standard 2.11 These metrics measure the performance of dispatch 

operations in maintaining steady-state frequency within defined limits by balancing 

power demand and supply in real time; (2) the number of transmission load relief events 

(TLRs) of severity level 3 and higher called by the ISO, RTO or incumbent transmission 

provider or, for Western Electricity Coordinating Council (WECC) entities, unscheduled 

flow procedures equivalent to the TLR at a severity level 3 and higher, as measures of 

how often ISO, RTOs or transmission providers must resort to manual actions to redirect 

physical flows; and (3) Energy Management System Availability for performing realtime monitoring and security analysis functions, reported as a percentage of minutes of 

operational availability each year.

b. Data Review and Metrics Assessment

As shown on the Control Performance Standards charts below, all reporting ISOs, 

RTOs and utilities were in compliance with NERC reliability standards for managing 

supply and demand in real-time. Similar to the reliability standards metrics, the Control 

Performance Standard metrics are based on reliability standards developed for the entire 

electric industry by NERC. Therefore, the data submitted and discussion of the data by 

the ISOs, RTOs and utilities indicates that the Control Performance Standard metrics 

measure the same activities and have the same meaning across all entities, and therefore 

are suitable to be common metrics.

 11 Control Performance Standard 1 is a statistical measure of Area Control Error 

variability. This standard measures Area Control Error in combination with the 

Interconnection’s frequency error. It is based on an equation derived from frequencybased statistical theory. Control Performance Standard 2 is a statistical measure of Area 

Control Error magnitude. The standard is designed to limit a control area’s unscheduled 

power flows. 

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CPS 1 Performance Reliability Standard

Notes

CPS 1 is the 12 month rolling average limit for a Balancing Authority's impact of its

Area Control Error on system frequency. To be compliant with CPS 1, Balancing

Authorities must achieve a score of at least 100 percent to avoid an adverse

impact on system frequency.

MISO CPS 1 compliance commenced in 2009 with the start of the Ancillary Services Market. 

Duke, Southern and APS provided no data. Their reports state that 

their operations are in compliance with the reliability standard.

2006 - 2010 Dispatch Reliability: Control Performance Standard (CPS) 1

0%

40%

80%

120%

160%

200%

1 2 3 4 5

ISO-NE

0%

40%

80%

120%

160%

200%

1 2 3 4 5

NYISO

0%

40%

80%

120%

160%

200%

1 2 3 4 5

PJM

0%

40%

80%

120%

160%

200%

1 2 3 4 5

SPP

0%

40%

80%

120%

160%

200%

1 2 3 4 5

CAISO

0%

40%

80%

120%

160%

200%

1 2 3 4 5

LG&E/KU

0%

40%

80%

120%

160%

200%

1 2 3 4 5

PacifiCorp

West

0%

40%

80%

120%

160%

200%

1 2 3 4 5

PacifiCorp

East

0%

40%

80%

120%

160%

200%

1 2 3 4 5

MISO

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CPS 2 Performance Reliability Standard

Notes

CPS 2 compares the Balancing Authority's integrated

Area Control Error value for clock 10 minute periods 

(six non-overlapping periods per hour) during a calendar

month against a NERC-assigned limit. Compliance requires

being within this limit for greater than 90% of the clock 

10 minute periods in every month.

CAISO 2010 data represents January and February

results only. CAISO was in a field trial for the 

remainder of 2010.

PJM, MISO, Duke, Southern and APS did not provide

data because they were in field trials. All were in

compliance with the reliability standard.

2006 - 2010 Dispatch Reliability: Control Performance Standard (CPS) 2

80%

82%

84%

86%

88%

90%

92%

94%

96%

98%

100%

1 2 3 4 5

ISO-NE

80%

82%

84%

86%

88%

90%

92%

94%

96%

98%

100%

1 2 3 4 5

NYISO

80%

82%

84%

86%

88%

90%

92%

94%

96%

98%

100%

1 2 3 4 5

SPP

80%

82%

84%

86%

88%

90%

92%

94%

96%

98%

100%

1 2 3 4 5

CAISO

80%

82%

84%

86%

88%

90%

92%

94%

96%

98%

100%

1 2 3 4 5

LG&E/KU

80%

82%

84%

86%

88%

90%

92%

94%

96%

98%

100%

1 2 3 4 5

PacifiCorp

West

80%

82%

84%

86%

88%

90%

92%

94%

96%

98%

100%

1 2 3 4 5

PacifiCorp

East

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The data on the second metric, TLRs and unscheduled flow events, show a wide 

range of results as reflected in the table below, from a few events per year on certain 

utility systems to thousands of events per year on some of the ISO and RTO transmission 

systems. The meaning of this information should be interpreted with caution, particularly 

in interpreting the extent to which this data measures performance. For example, SPP’s 

operating protocols require that it issue TLRs in parallel with congestion management so 

that increases in TLRs reflect increased use of market redispatch.12 Accordingly, 

increases in TLRs in SPP are not necessarily an indication of increased use of manual 

redispatch. 

 TLR or Unscheduled Flow Events: Severity Level 3 or Higher

Entity 2006 2007 2008 2009 2010

CAISO No Data 0 200 30 50

ISO-NE No Data No Data No Data No Data No Data

MISO 750 750 550 300 200

NYISO 0 0 0 200 150

PJM 200 100 250 200 150

SPP 500 1700 1700 1900 2450

APS 16 15 10 8 9

Duke 0.5 19.8 0 1.3 2.6

LG&E/KU No Data 42 18 16 40

PacifiCorp 8 122 281 25 54

Southern No Data No Data No Data No Data No Data

Notes

Bold italics indicate TLR hours, as opposed to events, reported by Duke. ISO-NE and 

Southern did not report TLRs. LG&E/KU data includes events for all severity levels. 

LG&E/KU indicate that 75 percent of all events were severity level 3 and higher. 

LG&E/KU did not report information on severity level 3 and higher by year.

 12 SPP Report at 323.

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The data submitted on TLR and unscheduled flow events indicate that this metric 

is not suitable as a common metric because TLRs or unscheduled flow events are not 

used universally in the industry and the data are not reliable indicators of their role in 

managing reliability, as noted in the SPP discussion above. 

A more suitable common metric might be a measure of the megawatts managed by 

all manual actions as a percentage of total megawatts subject to congestion management. 

Such a measure would encompass the full range of manual procedures used by ISOs, 

RTOs and utilities and it would not count TLRs that are not implemented. While we are 

not recommending that this metric be revised in this report, we encourage ISOs, RTOs, 

participating utilities and stakeholders to consider refinements to the metric or alternative 

metrics. 

With respect to the Energy Management System availability metric, ISOs, RTOs 

and utilities in regions outside these markets provided the following information for the 

2006–2010 period:

 NYISO reported availability of greater than 99 percent, which is equivalent 

to Energy Management System unavailability of less than 87 hours and 36 

minutes in a year.

 PJM reported availability equal to 99.5 percent, which is equivalent to 

Energy Management System unavailability of 43 hours and 48 minutes in a 

year. 

 SPP reported availability since 2007 of greater than 99.5 percent.

 PacifiCorp reported availability between 99.869 percent, which is

equivalent to 11 hours and 29 minutes of unavailability in a year, and 99.9

percent, which is equivalent to 8 hours and 46 minutes of unavailability in a 

year.

 ISO-NE, MISO, LG&E/KU and Southern reported availability of greater 

than 99.9 percent, which is equivalent to unavailability of less than 8 hours 

and 46 minutes in a year.

 APS reported availability or greater than or equal to 99.94 percent, which is

equivalent to unavailability of 5 hours and 15 minutes or less in a year.

 Duke reported availability between 99.986 percent, which is equivalent to 1 

hour and 14 minutes of unavailability in a year, and 100 percent for 

Progress Energy Carolinas and Progress Energy Florida. Duke did not 

report information for Duke Energy Carolinas.

 CAISO’s report did not provide numerical data. Based on the graphical 

depiction in its report, availability ranges between 99.9 percent (equivalent 

to 8 hours and 46 minutes in a year) and 100 percent. 

The data submitted and the discussion of the data by the ISOs, RTOs and utilities 

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indicate that the Energy Management System Availability metric measures the same 

activities and has the same meaning across all entities, and therefore is a suitable 

common metric. 

3. Load Forecast Accuracy

a. Definition

The percentage variance of actual peak load compared to day-ahead forecasted 

peak load measures the effectiveness of the load forecasting function. Since load 

forecasting provides the basis for resource commitment, this metric impacts the 

incurrence of resource costs. The more accurate an ISO, RTO or utility is in forecasting 

load, the greater the likelihood that it can commit sufficient resources in a cost-effective 

manner that avoids over-commitment of resources, inefficient commitment of short leadtime resources or under-utilization of available resources. 

b. Data Review and Metrics Assessment

Day-ahead load forecasting by ISOs, RTOs and utilities is typically highly 

accurate, as shown by the forecast accuracy data on the following charts. While a dayahead forecast metric is designed to ensure that it does not measure the ability to forecast 

long-term weather variability that is beyond the control of ISOs, RTOs and utilities, 

nonetheless, weather still played a role in forecast results. For example, Progress Energy 

Florida notes that significant weather shifts from AM to PM hours influenced its forecast 

results. Progress Energy Florida also explains that it forecasts higher to account for 

potential load volatility.13

The data submitted indicates that all ISOs and RTOs and three of the five utilities 

outside ISO and RTO markets use the same metric to measure load forecast accuracy. 

For these entities, the load forecast accuracy metric is measuring the same activity and 

has the same meaning. On this basis, we therefore conclude that the proposed load 

forecasting metric is a suitable common metric. 

 13 Duke Report at 8.

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Duke Key

Duke Energy Carolinas

Progress Energy Carolinas

Progress Energy Florida

Notes

MISO, SPP, LG&E/KU, APS and Progress Energy Florida did not report forecast data in 2006.

CAISO did not report forecast data prior to 2009. 2009 data represents April through December.

PacifiCorp did not submit data on day-ahead forecast accuracy.

2006 - 2010 Load Forecasting Accuracy

(Actual peak load as a percentage variance from forecasted peak load)

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

ISO-NE

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

NYISO

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

PJM

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

MISO

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

SPP

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

CAISO

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

Southern

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

LG&E/KU

80%

82%

84%

86%

88%

90%

92%

94%

96%

98%

100%

1 2 3 4 5

Duke

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

APS

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 18 -

4. Wind Forecasting Accuracy

a. Definition

This metric measures the percentage accuracy of actual wind availability 

compared to day-ahead forecasted wind availability. Improving the accuracy of the wind 

forecast facilitates the timely commitment and dispatch of sufficient supplemental, nonwind resources.

b. Data Review and Metrics Assessment

During the 2006–2010 period, forecasting wind availability was a new activity for 

ISOs, RTOs and utilities, as shown by the lack of data for the early years of the analysis 

period in the charts below and in the discussion of improvements in forecasting 

techniques in the reports.14 Several transmission providers did not forecast wind 

availability because they had no or few wind resources interconnected to their 

transmission systems during the analysis period.

The entities forecasting wind availability used the common definition detailed 

above, comparing actual wind availability to day-ahead forecasted wind availability. The 

data submitted and discussion of the data by the ISOs, RTOs and utilities indicates that 

the wind forecast accuracy metric is measuring the same activity and has the same 

meaning across the entities forecasting wind availability, and therefore is a suitable 

common metric. 

 14 See, e.g., ISO-NE Report at 80; APS Report at 8.

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 19 -

5. Unscheduled Flows Metric

a. Definition

Unscheduled flows are defined as the difference between scheduled flows and 

actual flows on a particular interconnection between two Balancing Authorities and the 

difference between scheduled and actual flows on a contract path, either between 

Balancing Authorities or within Balancing Authorities. The two components of 

unscheduled flows are inadvertent energy, defined as the difference between actual and 

Notes

NYISO started wind forecasting mid-2008.

PJM started wind forecasting in December 2009.

MISO started wind forecasting in 2009.

CAISO started wind forecasting in 2007.

PacifiCorp started wind forecasting for owned resources in March 2010.

APS started wind forecasting in 2009.

ISO-NE, SPP, Duke, Southern and LG&E/KU did not forecast wind availability.

2006 - 2010 Wind Forecasting Accuracy

(Percentage accuracy of actual wind availability compared to forecast wind availability)

0%

20%

40%

60%

80%

100%

1 2 3 4 5

NYISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

PJM

0%

20%

40%

60%

80%

100%

1 2 3 4 5

MISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

PacifiCorp

0%

20%

40%

60%

80%

100%

1 2 3 4 5

CAISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

APS

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 20 -

scheduled interchange for all interties, and parallel flow (or loop flow), defined as the 

difference between scheduled and actual flows on a contract path. Parallel flows are a 

function of the interconnection’s operating configuration, line resistance, and physics. 

This metric measures the difference between net actual interchange (actual measured 

power flow in real time) and the net scheduled interchange in megawatt hours, as 

reported in FERC Form No. 714, “Annual Electric Balancing Authority Area and 

Planning Area Report.” When unscheduled flows exceed system operating limits, 

curtailments could occur and efficient scheduling of the grid could be hindered. 

Accordingly, unscheduled flows provide information relevant to operational planning that 

is part of a comprehensive reliability assessment for an ISO, RTO or utility.

b. Data Review and Metrics Assessment

Unscheduled flows and their percentage of total flows vary significantly among 

the reporting entities, as shown on the charts below. The fact that certain of the reporting 

entities, such as NYISO, are in regions with more significant parallel flows15 than other 

regions would be an explanation for this variation. It should be noted that ISO-NE did 

not report unscheduled flows and explained that its system does not experience parallel 

flows because of its radial interconnection with the Eastern Interconnection.16

Unscheduled flows are based on a FERC Form No. 714 definition applicable to 

the entire electric industry and, therefore, this metric measures the same activities and has 

the same meaning across all entities; accordingly, it is a suitable common metric. 

 15 NYISO Report at 212-13. NYISO has undertaken a regional initiative to 

address Lake Erie loop flows. 

16 ISO-NE Report at 81.

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 21 -

Absoute Value of Unscheduled Flows (TWh) Unscheduled % of Total Flows

Notes

Left Axis: Absolute Value of Unscheduled Flows in terawatt hours (TWh).

Right Axis: Unscheduled Percentage of Total Flows.

ISO-NE and SPP did not report unscheduled flows. PacifiCorp did not report the absolute value of unscheduled flows.

Southern, APS and Duke did not report information on the percentage of total flows that are unscheduled.

Duke Key:

Duke Energy Carolinas

Progress Energy Carolinas

Progress Energy Florida

2006 - 2010 Unscheduled Flows

0%

2%

4%

6%

8%

10%

12%

0

10

20

30

40

50

60

70

80

90

1 2 3 4 5

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

0

2

4

6

8

10

12

1 2 3 4 5

0%

1%

2%

3%

4%

5%

6%

7%

8%

0

5

10

15

20

25

30

35

40

45

1 2 3 4 5

0.00%

0.02%

0.04%

0.06%

0.08%

0.10%

0

10

20

30

40

50

60

1 2 3 4 5

0

2

4

6

8

10

12

14

16

18

1 2 3 4 5

APS

0%

5%

10%

15%

20%

0

1

2

3

4

5

6

7

8

9

10

1 2 3 4 5

0

10

20

30

40

50

1 2 3 4 5

Southern

NYISO PJM MISO

CAISO LG&E/KU

0

2

4

6

8

10

12

14

16

1 2 3 4 5

Duke

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 22 -

6. Transmission Outage Coordination

a. Definition

Commission Staff has defined the common metrics for effective transmission 

outage coordination as follows: (1) early notification of planned outages of five days or 

longer on major transmission lines (200 kV and above) – i.e., notification at least one 

month prior to the outage commencement date; and (2) cancellations of outages due to 

conflicting planned outages as well as forced outages that could cause reliability issues 

and additional congestion costs. All metrics are measured as a percentage of all outages. 

Effective transmission outage coordination will result in early notification of outages, and 

therefore will be indicated in the metrics as a low percentage of short notice outages. 

Effective transmission outage coordination ensures that outages do not threaten system 

reliability and that additional, and potentially more expensive, resources do not need to 

be committed.

b. Data Review and Metrics Assessment

The charts below show a range of results for the metric measuring early 

notification of planned outages on major transmission lines. These results require 

interpretation. Whereas the one-month notification requirement before planned outages 

is a metric that has been used by some ISOs and RTOs, such as PJM,17 for certain outage 

durations, other ISOs, RTOs and utilities do not have a one-month notification standard. 

For example, LG&E/KU coordinate their outage notifications with the Tennessee Valley 

Authority system, which uses a seven-day notice requirement.18 The chart for the second 

metric, cancellations of planned outages, shows low levels for all entities, with the 

exception of LG&E/KU.

The data submitted and discussion of the data by the ISOs, RTOs and utilities 

indicate that the transmission coordination metrics measure the same activities and have 

the same meaning across all entities, and therefore are suitable common metrics. 

 17 See PJM Report at 272.

18 LG&E/KU Report at 7-8.

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Docket No. AD14-15-000 

- 23 -

On 200 kV lines and higher, the percentage

of planned outages of more than five days 

with at least one month notification prior to

the outage.

Notes

NYISO data available for 2009-2010 only.

CAISO data available for April 2009-2010 only.

Duke data represents results for Duke Energy Carolinas

for March 2009-2010. Progress Energy Carolinas

and Progress Energy Florida did not submit data.

LG&E/KU data available for May 2008-2010 only

Southern and APS did not submit data.

2006 - 2010 Transmission Outage Coordination: Early Notification Metric

0%

20%

40%

60%

80%

100%

1 2 3 4 5

ISO-NE

0%

20%

40%

60%

80%

100%

1 2 3 4 5

NYISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

MISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

SPP

0%

20%

40%

60%

80%

100%

1 2 3 4 5

CAISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

Duke

0%

20%

40%

60%

80%

100%

1 2 3 4 5

LG&E/KU

0%

20%

40%

60%

80%

100%

1 2 3 4 5

PacifiCorp

0%

20%

40%

60%

80%

100%

1 2 3 4 5

PJM

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 24 -

On 200 kV lines and higher, the percentage of 

previously approved outages that the

transmission provider cancels.

Notes

NYISO did not report data for 2006-2008.

CAISO did not report data for 2006 through March 2009.

Duke data represents results for Duke Energy Carolinas 

for March 2009-2010. 

LG&E/KU did not report data for 2006 through April 2008.

SPP, Southern and APS did not submit data.

2006 - 2010 Transmission Outage Coordination: Cancellation Metric

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

1 2 3 4 5

ISO-NE

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

1 2 3 4 5

NYISO

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

1 2 3 4 5

PJM

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

1 2 3 4 5

MISO

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

1 2 3 4 5

CAISO

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

1 2 3 4 5

Duke

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

1 2 3 4 5

PacifiCorp

0%

10%

20%

30%

40%

1 2 3 4 5

LG&E/KU

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 25 -

7. Long-Term Reliability Planning – Transmission

a. Definition

This metric tracks the effectiveness of a transmission provider’s planning process 

in facilitating development of the transmission system. Measures of transmission 

planning performance are as follows: (1) the number of transmission facilities approved 

to be constructed for reliability purposes; (2) the percentage of approved construction 

projects completed and on schedule; and (3) measures of the performance of the planning 

study process in completing reliability and economic studies. This information measures 

the ability of each ISO’s, RTO’s or utility’s expansion planning process to identify 

reliability and economic needs in advance. 

With respect to the first metric, the number of transmission facilities approved to 

be constructed for reliability purposes, Commission Staff did not consider it appropriate 

to measure ISO and RTO performance based on construction spending and construction 

project completion information since ISOs and RTOs do not construct transmission 

facilities. Instead, a project approval measure was considered an appropriate common 

metric since all entities approve transmission projects – ISOs and RTOs in their 

reliability planning processes and utilities in their own transmission planning, which is 

undertaken typically as part of regional power pool planning processes.

b. Data Review and Metrics Assessment

Data submitted on transmission project approvals is shown on the chart below.

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 26 -

Transmission Projects Approved For Construction

 Entity 2006 2007 2008 2009 2010

 CAISO 48 45 50 49 48

 ISO-NE 149 147 245 200 185

 NYISO 10 20 35 47 40

 MISO 450 100 540 355 235

 PJM 250 280 355 420 455

 SPP 10 140 210 185

No 

Data

 APS 0 1 2 2 1

 Duke 157 176 217 222 192

 LG&E/KU 9 14 9 21 18

 PacifiCorp 9 14 35 26 14

 Southern 16 28 35 25 39

Note

Bold italics indicate projects completed.

The data submitted and discussion of the project approval metric by the ISOs, 

RTOs and utilities indicates that this metric measures the same activity and has the same 

meaning across all types of entities, and therefore is a suitable common metric. While 

Duke and Southern submitted data on the number of projects completed, the other 

utilities outside ISO and RTO markets reported the number of projects approved, thereby 

indicating that this metric can be a common metric for all ISOs, RTOs and utilities 

outside ISO and RTO markets. 

Commission Staff intends the second metric, the percentage of approved projects 

completed, to track progress in completing projects. The metric on the chart below 

shows the percentage of projects approved in each year that were completed as of 

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 27 -

December 31, 2010. Only the ISOs and RTOs provided this information. Utilities 

outside ISO and RTO markets did not use this measure, and instead tracked their 

performance based on the percentage of projects that were on schedule each year. On 

this measure, Duke, Southern and APS reported 100 percent of transmission projects on 

schedule, PacifiCorp reported 90 percent on schedule for most years, and LG&E/KU 

reported, respectively, between 50 percent and 80 percent of transmission projects on 

schedule.

Inasmuch as utilities outside ISO and RTO markets are tracking information on 

project completion, it is expected that they could provide the same information provided 

by the ISOs and RTOs and, therefore, this metric would be suitable as a common metric.

Notes

Data shows the percentage of projects approved in each year that were completed as of 

December 31, 2010.

NYISO and SPP did not provide data for 2010.

2006 - 2010 Transmission Projects Completed

(Percentage of Approved Projects Completed as of December 31, 2010)

0%

20%

40%

60%

80%

100%

1 2 3 4 5

ISO-NE

0%

20%

40%

60%

80%

100%

1 2 3 4 5

NYISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

PJM

0%

20%

40%

60%

80%

100%

1 2 3 4 5

MISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

SPP

0%

20%

40%

60%

80%

100%

1 2 3 4 5

CAISO

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 28 -

With respect to measures of the planning study process, all reporting entities 

conduct annual reliability studies as part of their regional expansion planning processes. 

Such assessments typically encompass sensitivity analyses based on stakeholder requests. 

Southern indicated that it performed 191 reliability studies in addition to its annual 

reliability analysis, and that it evaluated 30 sensitivity analyses.19 PacifiCorp and 

LG&E/KU did not receive any requests for additional reliability studies. 

As for economic studies, ISOs, RTOs and utilities provided the following specific 

study information:

 ISO-NE completed five economic studies over the 2006–2010 period.

 MISO completed four economic studies in 2009 and 2010.

 NYISO initiated a biennial economic planning process in 2009.

 Duke Energy Carolinas and Progress Energy Carolinas evaluated 10 

economic assessment sensitivities over the 2006–2010 period. 

 Progress Energy Florida received no requests.

 LG&E/KU completed five economic studies annually as part of its 

expansion planning process.

 APS completed three economic studies over the 2006–2010 period.

 PacifiCorp completed one economic study over the 2006–2010 period.

The data submitted and discussion of the data by the ISOs, RTOs and utilities 

indicates that the planning study metrics measure the same activities and have the same 

meaning across all entities, and therefore are suitable common metrics. 

8. Long-Term Reliability Planning – Resources

a. Definition

Two metrics are employed to measure the effectiveness of long-term reliability 

planning for resources. The first metric, processing time for generation interconnection 

requests, measures the effectiveness of processes in achieving timely interconnection of 

new resources. The second metric compares the actual reserve margin to the planned 

reserve margin to measure the extent to which ISO, RTO and utility generation resource 

 19 Southern Report at 25.

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 29 -

planning processes are ensuring long-term resource adequacy and reliability.

b. Data Review and Metrics Assessment

The results of the first metric, the time required to process generator 

interconnection requests, show that ISO-NE and MISO experienced significant increases 

– a four-fold increase for ISO-NE and a doubling for MISO – in the time required to 

process generator interconnection requests. ISO-NE and MISO cited several factors as 

explanations for the processing time increases, including:

 wind manufacturers have been slow to provide accurate models needed for 

study completion;

 dependence of later-queued projects on earlier-queued projects;

 tariff requirements allowing customers to waive or combine phases of the 

interconnection process;

 requests to not proceed by resource developers; and

 increasing complexity and congestion impact of interconnection requests.20

The processing time for generator interconnection requests metric should be 

evaluated primarily in terms of the trends for each respondent. Each ISO, RTO or utility 

interconnects generators under widely different operating conditions. Some entities, such 

as ISO-NE and MISO, were required to process hundreds of new requests each year as 

new resources were developed in response to renewable energy programs. Others, such 

as LG&E/KU and Southern, had few requests each year and therefore the time-required 

data reflects the time required to process fewer applications. Also, inasmuch as 

processing time can include time during which the developer chooses not to 

interconnect,21 this metric is not entirely within the control of ISOs, RTOs or utilities.

The second metric, actual versus planned reserve margins, shows a wide range of 

results, ranging from resources in excess of planning requirements on a consistent basis 

(ISO-NE) to actual reserve margins both above and below the planned reserve margin 

(Southern, Duke, LG&E/KU, and APS). Actual reserve margins in SPP were 

consistently below planned margins.

 20 ISO-NE Report at 90; MISO Report at 162.

21 This practice is referred to as “parking” in the industry.

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 30 -

The data submitted and discussion of the data by ISOs, RTOs and utilities 

indicates that the long-term reliability resource planning metrics measure the same 

activities and have the same meaning across all entities and, therefore, are suitable 

common metrics. 

Notes

NYISO - 2010 no data.

CAISO - 2006 no data.

Southern - no data 2006-2008.

APS - no requests for 2006,

2007 and 2010.

LG&E/KU - no data since

generators withdrew requests.

Duke:

Progress Energy Carolinas

Progress Energy Florida

Duke Energy Carolinas - 197 day average

for 2007-2010.

2006 - 2010 Generator Interconnection Processing Time

(Days)

0

200

400

600

800

1000

1200

1 2 3 4 5

ISO-NE

0

200

400

600

800

1000

1200

1 2 3 4 5

NYISO

0

200

400

600

800

1000

1200

1 2 3 4 5

PJM

0

200

400

600

800

1000

1200

1 2 3 4 5

MISO

0

200

400

600

800

1000

1200

1 2 3 4 5

SPP

0

200

400

600

800

1000

1200

1 2 3 4 5

CAISO

0

200

400

600

800

1000

1200

1 2 3 4 5

Duke

0

200

400

600

800

1000

1200

1 2 3 4 5

PacifiCorp

0

200

400

600

800

1000

1200

1 2 3 4 5

Southern

0

200

400

600

800

1000

1200

1 2 3 4 5

APS

20140826-4006 FERC PDF (Unofficial) 08/26/2014
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- 31 -

Actual Reserve Margin Planned Reserve Margin

2006 - 2010 Actual and Planned Reserve Margins

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

ISO-NE

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

NYISO

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

PJM

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

MISO

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

SPP

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

CAISO

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 32 -

9. Interconnection and Transmission Process Metrics 

a. Definition

These metrics track the progress that ISOs, RTOs and utilities have made in 

Actual Reserve Margin Planned Reserve Margin

2006 - 2010 Actual and Planned Reserve Margins

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

Southern

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

LG&E/KU

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

PacifiCorp

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

APS

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

Duke

Carolinas

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

Progress

Carolinas

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

Progress

Florida

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Docket No. AD14-15-000 

- 33 -

completing their reliability reviews (feasibility, system impact and facility studies) of 

interconnection and transmission service requests in a timely and efficient manner. The 

metrics track the number of study requests, the time required to complete the reliability 

reviews – including the age of incomplete studies – and the costs of completing each of 

the three types of studies.

b. Data Review and Metrics Assessment

With respect to the first metric on the number of study requests and completed 

studies, the data provided by the ISOs and RTOs shows a wide range of study requests in 

the accompanying charts – from 250 for SPP to 1445 for PJM over the 2006 – 2010 

period. Data for utilities in regions outside ISO and RTO markets likewise show a wide 

range of study requests – ranging from 139 for Southern to 1211 for PacifiCorp over the 

2006 - 2010 period.22 In light of the significant differences in interconnection and 

transmission development among the ISOs, RTOs and utilities, this metric should be 

evaluated primarily in terms of the trends for each respondent over time.

The second metric on the average age of incomplete studies metric provides a 

measure of the efficiency of the study process for interconnections and transmission 

service requests. The annual data on the age of incomplete studies shown on the charts 

below is for ISOs and RTOs only. Utilities outside ISO and RTO markets did not 

provide annual information on studies. Duke indicated that, as of January 1, 2011, the 

average age for incomplete interconnection studies was 108 days and 58 days for 

transmission service requests. Southern indicated that, as of January 1, 2011, the average 

age for incomplete interconnection studies was 14 days and 23 days for transmission 

service requests. LG&E/KU and PacifiCorp indicated that no studies were incomplete. 

APS indicated that, as of January 1, 2011, the average age for incomplete interconnection 

studies was 119 days.

 22 LG&E/KU had 111 requests. However, these requests were only for system 

impact and facilities studies resulting from transmission service requests. See LG&E/KU 

Report at 13-14.

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 34 -

Study Requests Completed Studies

Notes

Data for CAISO are interconnection studies only. 

Data for all other ISOs and RTOs, Duke, PacifiCorp, Southern

and APS are interconnection and transmission service studies.

Data for LG&E/KU are transmission services studies only.

Duke 2006 data does not include Duke Carolinas.

Southern and LG&E/KU have no data for 2006. Southern 2007 data is for 3rd and

4th Qtr only.

2006 - 2010 Interconnection and Transmission Service Request Process

0

20

40

60

80

1 2 3 4 5

ISO-NE

0

20

40

60

80

1 2 3 4 5

NYISO

0

100

200

300

400

500

600

1 2 3 4 5

PJM

0

50

100

150

200

250

300

1 2 3 4 5

MISO

0

20

40

60

80

100

1 2 3 4 5

SPP

0

10

20

30

40

50

1 2 3 4 5

Southern

0

50

100

150

200

250

1 2 3 4 5

Duke

0

50

100

150

200

250

1 2 3 4 5

CAISO

0

50

100

150

200

250

300

350

400

1 2 3 4 5

PacifiCorp

0

20

40

60

80

100

120

1 2 3 4 5

APS

0

10

20

30

40

50

1 2 3 4 5

LG&E/KU

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 35 -

The table below compares the costs of studies. The range of costs shown depicts 

the lowest and highest average costs reported over the 2006–2010 period. 

Notes

CAISO data represents age of interconnection studies only.

Data for all other ISOs and RTOs represent age of interconnection and transmission service studies.

Utilities outside ISO and RTO markets did not provide annual study information.

2006 - 2010 Average Age of Incomplete Studies

(Days)

0

50

100

150

200

250

300

350

400

1 2 3 4 5

ISO-NE

0

50

100

150

200

250

300

350

400

1 2 3 4 5

NYISO

0

50

100

150

200

250

300

350

400

1 2 3 4 5

PJM

0

50

100

150

200

250

300

350

400

1 2 3 4 5

MISO

0

50

100

150

200

250

300

350

400

1 2 3 4 5

SPP

0

100

200

300

400

500

1 2 3 4 5

CAISO

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 36 -

 2006 – 2010 Range of Average Costs of Studies

Entity Feasibility Study 

Costs

System Impact

Study Costs

Facility Impact 

Study Costs

ISO-NE $62,824 - $94,960 $83,370 - $121,363 $4,479 - $146,685

NYISO $24,217 - $45,805 $38,990 - $58,337 $113,090 - $125,119

PJM $3,514 - $4,538 $10,263 - $14,406 $28,635 - $66,648

SPP $2,491 - $6,495 $14,050 - $17,694 $7,290 - $16,960

APS $13,983 - $17,512 $37,127 - $43,662 $29,890 - $47,059

Duke $2,775 - $14,376 $371 - $43,601 $1,078

LG&E/KU No data $2,925 - $4,237 $2,636 - $3,256

Southern No data $5,688 - $10,683 $5,329 - $6,912

Notes

▪ Duke costs do not include Duke Energy Carolinas. Total study costs for Duke Energy 

Carolinas ranged from $31,084 to $70,483.

▪ LG&E/KU and Southern data based on transmission service study costs only.

▪ MISO reported average annual total costs (feasibility, system impact and facility 

impact studies) that ranged between approximately $90,000 to $175,000.

▪ PacifiCorp only reported total (aggregate) annual costs.

▪ CAISO did not provide data.

The data submitted and discussion of the data by ISOs, RTOs and utilities 

indicates that the interconnection and transmission process metrics measure the same 

activities and have the same meaning across all entities, and therefore are suitable 

common metrics.

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 37 -

10. Special Protection Systems

a. Definition

Special Protection Systems23 are automatic protection systems designed to detect 

abnormal or predetermined system conditions and take corrective actions, such as 

changing demand, generation, or system configurations in order to maintain system 

stability, acceptable voltage levels, or power flows. These metrics measure the number 

of Special Protection Systems, as well as the performance of such Special Protection 

Systems, based on the definition of Special Protection Systems used by the reporting 

entity’s Regional Entity. These performance metrics measure both the frequency with 

which the region relies on these systems and their effectiveness, as measured by 

successful activations and the number of unintended activations.

b. Data Review and Metrics Assessment

The table below compares the number of special protection systems used by ISOs, 

RTOs and utilities in 2010.

 23 Special Protection Systems are also referred to as Special Protection Schemes, 

Remedial Action Schemes or System Integrity Protection Schemes. 

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 38 -

Entity Special Protection Systems

CAISO 65

ISO-NE 9

NYISO 12

MISO 50

PJM 45

SPP 5

APS 6

Duke 2

LG&E/KU 0

PacifiCorp 8

Southern 5

Note

Duke data represents Progress Energy Florida information. Duke Energy Carolinas and 

Progress Energy Carolinas did not have Special Protection Systems.

With respect to the performance of Special Protection Systems, the ISOs, RTOs 

and utilities provided the following information for 2010:

 ISO-NE had one misoperation in which a Special Protection System did not 

perform as designed.

 PacifiCorp had four unintended activations of Special Protection Systems.

 MISO, PJM, SPP, Progress Energy Florida, Southern and APS had no 

unintended activations or misoperations.

 CAISO, NYISO, LG&E/KU, Duke Energy Carolinas and Progress Energy 

Carolinas did not provide performance information.

The data submitted and discussion of the data by ISOs, RTOs and utilities indicate 

that the Special Protection System metrics measure the same activities and have the same 

meaning across all entities and, therefore, are suitable common metrics. 

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 39 -

B. Systems Operations Performance Metrics

1. System Lambda

a. Definition

System lambda is the incremental cost of energy of the marginal unit assuming no 

system constraints. This metric tracks the trend in marginal fuel costs and is an important 

metric because fuel costs represent the largest component of wholesale energy costs. The 

system lambda metric does not apply to utilities where the marginal price is typically set 

by hydro units. Also, system lambda data is based on information contained in FERC 

Form No. 714.

b. Data Review and Metrics Assessment

The data on the accompanying charts shows a range of incremental costs, 

reflecting differences among regions in the costs of fuels used by the marginal unit for 

ISOs, RTOs and utilities. The data submitted and discussion of the data by ISOs, RTOs 

and utilities indicate that the system lambda metric has the same meaning across all 

entities and, therefore, is a suitable common metric. 

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 40 -

Incremental cost of energy 

of the marginal unit on the 

system ($/MWh)

Notes

Duke key: 

Duke Energy Carolinas

Progress Energy Carolinas

Progress Energy Florida

SPP did not provide 2006 data.

CAISO did not provide 2006-2008 data; 2009 data is based on April-December results.

PacifiCorp did not report a system marginal cost

since the marginal resource is hydro power.

2006 - 2010 System Lambda

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

ISO-NE

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

NYISO

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

PJM

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

MISO

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

SPP

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

CAISO

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

LG&E/KU

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

APS

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

Duke

$0

$10

$20

$30

$40

$50

$60

$70

$80

1 2 3 4 5

Southern

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 41 -

2. Resource Availability

a. Definition

This metric measures the percentage of time that system resources are available 

after accounting for unplanned outages, as measured by the system forced outage rate. 

Resource availability is calculated as one minus the forced outage rate.24 Resource 

availability is a measure of efficiency and cost management. Higher generator 

availability can result in the commitment of fewer potentially higher cost peak generators 

(or the importation of potentially higher cost peak supplies), thereby resulting in reduced 

costs.

b. Data Review and Metrics Assessment 

Resource availability for ISOs, RTOs and utilities ranged between 98 percent and 

92 percent, as shown on the charts below. The data submitted and discussion of the data 

by the ISOs, RTOs and utilities indicates that the resource availability metric has the 

same meaning across all entities, and therefore is a suitable common metric. 

 24 Since resource availability is calculated as a percentage, the calculation is 100 

percent minus the forced outage rate, expressed as a percentage.

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 42 -

Duke Key:

Duke Energy Carolinas Progess Energy Carolinas

Progress Energy Florida

2006 - 2010 Resource Availability

(1 - forced outage rate over 12 months)

90%

92%

94%

96%

98%

100%

1 2 3 4 5

ISO-NE

90%

92%

94%

96%

98%

100%

1 2 3 4 5

NYISO

90%

92%

94%

96%

98%

100%

1 2 3 4 5

PJM

90%

92%

94%

96%

98%

100%

1 2 3 4 5

MISO

90%

92%

94%

96%

98%

100%

1 2 3 4 5

SPP

90%

92%

94%

96%

98%

100%

1 2 3 4 5

CAISO

90%

92%

94%

96%

98%

100%

1 2 3 4 5

Southern

90%

92%

94%

96%

98%

100%

1 2 3 4 5

LG&E/KU

90%

92%

94%

96%

98%

100%

1 2 3 4 5

PacifiCorp

90%

92%

94%

96%

98%

100%

1 2 3 4 5

APS

90%

92%

94%

96%

98%

100%

1 2 3 4 5

Duke

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 43 -

3. Fuel Diversity

a. Definition

This metric is defined as the percentage mix of fuel types installed and available 

(capacity fuel diversity) and produced (generation fuel diversity). Fuel diversity provides 

an indication of the capability of ISOs, RTOs and utilities to integrate fuels with different 

characteristics, such as lower costs or lower environmental impacts, and how this 

capability compares to the fuel mix of energy consumed.

b. Data Review and Metrics Assessment

With respect to the first metric, the diversity of resources as measured as a 

percentage of capacity, the capacity of ISOs, RTOs and utilities is predominantly 

comprised of coal, natural gas and nuclear power resources. The exception is the 

significant hydro and renewable capacity in CAISO and PacifiCorp (between 15 and 27 

percent of total capacity). It should also be noted that ISO-NE and NYISO have 

meaningful capacity contributions (between 13 and 16 percent) from hydro and 

renewable resources. The second metric, which measures the diversity of resources used

in providing energy, shows a greater reliance on coal, natural gas and nuclear power 

resources for meeting the daily energy needs in ISO and RTO markets and in utilities 

outside ISO and RTO markets. For example, coal provided nearly all the energy 

generated for LG&E/KU load. MISO, Southern, and PacifiCorp also relied heavily on 

coal resources for energy requirements.

The data submitted and discussion of the data by the ISOs, RTOs and utilities 

indicates that the fuel diversity metrics have the same meaning across all entities, and 

therefore are suitable common metrics. 

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 44 -

Key and Note

Other resources

Oil

Gas/Oil

Hydro & Renewables

Nuclear

Gas

Coal

SPP - no data for 2006

2006 - 2010 Capacity Diversity

(Percentage of Total Capacity)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

PJM

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

MISO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

ISO-NE

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

NYISO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

SPP

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

CAISO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

Duke 

Carolinas

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

Progress

Carolinas

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

Progress

Florida

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

Southern

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

LG&E/KU

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

PacifiCorp

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

APS

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 45 -

Key and Note

Other resources

Oil

Gas/Oil

Hydro & Renewables

Nuclear

Gas

Coal

SPP - no data for 2006

2006 - 2010 Energy Diversity

(Percentage of Total Generation)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

PJM

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

MISO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

ISO-NE

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

NYISO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

SPP

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

CAISO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

Duke 

Carolinas

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

Progress

Carolinas

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

Progress

Florida

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

Southern

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

LG&E/KU

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

PacifiCorp

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5

APS

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 46 -

V. Other Metrics

A number of performance metrics were developed that are not on the list of 

common metrics because they are not applicable to the entire industry. For example, 

metrics were developed that measure the performance of ISO and RTO markets. Since 

regions outside ISO and RTO markets by definition do not have energy, ancillary 

services or capacity markets, such measures are not universally applicable and, therefore,

are not suitable common metrics. Similarly, metrics for utilities in regions outside ISO 

and RTO markets measure certain aspects of transmission provider performance that are 

not relevant to ISOs and RTOs. For example, metrics were developed for utilities in 

regions outside ISO and RTO markets that evaluate the extent to which transmission 

service is open-access and non-discriminatory. These metrics appropriately apply to 

utilities in regions outside ISO and RTO markets that have an incentive to discriminate 

among users of their transmission services in their role as transmission providers for 

transmission service on transmission facilities that they own. However, they are not 

relevant to ISOs and RTOs, since ISOs and RTOs are independent entities that do not 

own transmission facilities and, therefore, they do not have an incentive to discriminate 

among users of their transmission service.

Other metrics specific to ISOs and RTOs are evaluated first, followed by other 

metrics specific to utilities in regions outside ISO and RTO markets.

A. Other Metrics Specific to ISO and RTO Performance

1. Load Forecasting Accuracy Metrics

In addition to the common load forecasting accuracy metrics discussed above, ISO 

and RTO average year and valley (off-peak) forecasting accuracy performance was also 

evaluated. Also, load forecasting accuracy was measured using a mean absolute 

percentage error metric. This information is illustrated in the charts below.

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 47 -

Actual % Variance From Forecast Mean Absolute % Error

Notes

Left Axis: Actual % Variance From Forecast.

Right Axis: Mean Absolute % Error.

MISO and SPP did not report forecast data in 2006.

CAISO did not report data prior to 2009. 2009 data represents

accuracy for April through December.

2006 - 2010 Average Load Forecasting Accuracy

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

ISO - NE

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

NYISO

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

PJM

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

MISO

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

SPP

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

CAISO

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 48 -

2. Transmission Outage Metrics

In addition to the common transmission outage metrics discussed above, ISO and 

RTO performance was also evaluated according to the following metrics: (1) percentage 

of planned outages studied within prescribed tariff and business manual timeframes; and 

(2) percentage of unplanned outages compared to all outages on transmission facilities 

greater than 200 kV. ISO and RTO performance data is presented on the charts below.

Actual % Variance From Forecast Mean Absolute % Error

Notes

Left Axis: Actual % Variance From Forecast.

Right Axis: Mean Absolute % Error.

MISO and SPP did not report forecast data in 2006.

CAISO did not report load forecast data prior to 2009.

2006 - 2010 Valley Forecasting Accuracy

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

ISO - NE

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

NYISO

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

PJM

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

MISO

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

SPP

0%

1%

2%

3%

4%

5%

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

1 2 3 4 5

CAISO

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 49 -

Note

CAISO did not provide data for 2006.

NYISO and SPP did not have tariff or manual-established timeframes for outage studies.

2006 - 2010 Transmission Outage Study Metric

(Percentage of Outage Studies Completed Within Tariff/Manual Timeframes)

0%

20%

40%

60%

80%

100%

1 2 3 4 5

ISO-NE

0%

20%

40%

60%

80%

100%

1 2 3 4 5

PJM

0%

20%

40%

60%

80%

100%

1 2 3 4 5

MISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

CAISO

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 50 -

3. Long-Term Reliability Planning – Resources

In addition to the common long-term reliability planning for resource metrics 

discussed above, ISO and RTO performance was also evaluated according to the 

following metrics: (1) demand response megawatts as a percentage of total capacity; 

(2) percentage of generation outages cancelled by ISOs/RTOs; (3) number and capacity 

of generation reliability-must run contracts; and (4) demand response megawatts as a 

percentage of total ancillary services. The demand response metrics provide an 

indication of the role played by demand response resources in maintaining short-term and 

long-term reliability in ISOs and RTOs. The generation outage cancellation metric 

provides an indication of the effectiveness of ISOs and RTOs in administering generation 

outage schedules. A low cancellation percentage indicates that generation owners were 

Notes

Data not available prior to 2009 for NYISO and CAISO.

NYISO classified any outage with less than two days' notice as unplanned.

2006 - 2010 Unplanned Outage Metric

(Unplanned Outages as a Percentage of All Outages on > 200 kV Transmission Lines)

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

ISO-NE

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

NYISO

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

PJM

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

MISO

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

CAISO

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

SPP

20140826-4006 FERC PDF (Unofficial) 08/26/2014
Docket No. AD14-15-000 

- 51 -

allowed to complete nearly all the maintenance they had planned without incurring 

rescheduling costs or delays. The reliability-must-run metric provides a measure of the 

degree to which an ISO or RTO must depend on critical facilities to maintain reliability 

and the flexibility of an ISO or RTO system to respond to emergencies and other 

contingencies. ISO and RTO performance data is presented on the charts below.

Note

SPP did not provide data.

2006 - 2010 Demand Response Percentage of Installed Capacity

(Demand Response Capacity MW as a Percentage of Total Capacity MW)

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

1 2 3 4 5

ISO-NE

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

1 2 3 4 5

NYISO

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

1 2 3 4 5

PJM

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

1 2 3 4 5

MISO

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

1 2 3 4 5

CAISO

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Notes

No outages were cancelled in 2006 and 2007 in MISO.

NYISO did not provide data for the period prior to 2010.

NYISO cancelled two outages in 2010.

SPP did not provide data.

2006 - 2010 Generation Outages Cancelled by ISO/RTO

(Percentage of Total Outages)

0.00%

0.25%

0.50%

0.75%

1.00%

1 2 3 4 5

ISO-NE

0.00%

0.25%

0.50%

0.75%

1.00%

1 2 3 4 5

PJM

0.00%

0.25%

0.50%

0.75%

1.00%

1 2 3 4 5

MISO

0.00%

0.25%

0.50%

0.75%

1.00%

1 2 3 4 5

CAISO

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Number of RMR Units RMR Capacity in MW

Notes

Left Axis: Number of RMR Units.

Right Axis: RMR Capacity in MW.

In June 2010 ISO-NE RMR units were reduced to 1 and RMR capacity was reduced

to 162 MW.

NYISO and MISO had no RMR units during this period.

SPP did not report data.

2006 - 2010 Reliability-Must-Run (RMR) Metric

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0

10

20

30

40

50

60

70

80

90

100

1 2 3 4 5

ISO - NE

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0

10

20

30

40

50

60

70

80

90

100

1 2 3 4 5

PJM

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0

10

20

30

40

50

60

70

80

90

100

1 2 3 4 5

CAISO

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2006 - 2010 Demand Response Percentage of Ancillary Services

(Percentage Share of MWh of Ancillary Services Provided By Demand Response)

MISO Key

Synchronized reserve market

Regulation Market

Note

ISO-NE data represents share of hourly total 30-minute reserve requirement.

PJM data repesents share of synchronized reserve market. Demand response

did not provide any regulation service.

MISO did not provide data for the period prior to 2009. 2009 data represents

January 6, 2009 (when Ancillary Services Market commenced) through year end.

NYISO, SPP and CAISO did not provide data.

0%

1%

2%

3%

4%

5%

6%

1 2 3 4 5

ISO-NE

0%

1%

2%

3%

4%

5%

6%

1 2 3 4 5

PJM

0%

1%

2%

3%

4%

5%

6%

7%

8%

1 2 3 4 5

MISO

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4. Price-Cost Mark-Up

The price-cost mark-up metric compares the system marginal price to the system 

marginal cost, assuming no system constraints.25 The ratio between the marginal price 

and marginal cost indicates the degree of competition and efficiency in ISO and RTO 

markets. ISO and RTO markets are more competitive the closer prices are to marginal 

costs. This metric is measured as the percentage mark-up for each year. 

The results in the chart below show that system marginal costs and system 

marginal prices are nearly identical in all ISO and RTO markets, indicating efficient and 

competitive conditions in these markets.

 25 The definition of the price-cost mark-up is the load-weighted average mark-up 

on the cost-based offer divided by the load-weighted price offer, expressed as a 

percentage.

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5. Generator Net Revenue

Generator net revenue measures the revenue that a new generator would earn 

above its variable production costs if it were to operate only when its variable production 

costs were less than the energy price. This metric can be an indicator of whether 

generator net revenues are sufficient to ensure new investment, if needed, and are 

consistent with competitive markets. This metric is measured on an annual basis and 

comes from analysis conducted by each entity’s market monitor.

The data in the accompanying charts reflect the estimated generator revenues per 

megawatt year for a new combustion turbine unit fueled by natural gas and for a new 

Notes

Price/Cost Mark-Up definition: Load-weighted average mark up on cost-based offer divided by load-weighted

price offer, expressed as a percentage.

SPP did not provide data. MISO and NYISO did not provide data for 2006 and 2006-2008, respectively.

CAISO NYISO

2006-2010 Price/Cost Mark Up

ISO - NE MISO PJM

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

50%

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

50%

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

50%

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

50%

-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

50%

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entrant combined-cycle unit fueled by natural gas. Several of the ISO and RTO reports 

indicate that revenues are below the levels needed for new investment.26

Key

Gas-Fired Combustion Turbine

Gas-Fired Combined Cycle

Note

SPP did not provide information for 2006.

2006 - 2010 Net Generation Revenues

($ Per Installed Megawatt Year)

 $-

 $20,000

 $40,000

 $60,000

 $80,000

 $100,000

 $120,000

1 2 3 4 5

ISO - NE

 $-

 $20,000

 $40,000

 $60,000

 $80,000

 $100,000

 $120,000

1 2 3 4 5

MISO

 $-

 $20,000

 $40,000

 $60,000

 $80,000

 $100,000

 $120,000

1 2 3 4 5

PJM

 $-

 $20,000

 $40,000

 $60,000

 $80,000

 $100,000

 $120,000

1 2 3 4 5

CAISO

 $-

 $20,000

 $40,000

 $60,000

 $80,000

 $100,000

 $120,000

1 2 3 4 5

SPP

 $-

 $20,000

 $40,000

 $60,000

 $80,000

 $100,000

 $120,000

1 2 3 4 5

NYISO

 26 See, e.g., CAISO Report at 50; MISO Report at 175; SPP Report at 337.

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6. Percentage of Megawatt Hours Mitigated

This metric provides an indication of the magnitude of mitigation occurring in ISO

and RTO markets, as measured by the percentage of unit hours that prices were set at the 

mitigated price on an annual basis. The accompanying chart shows a low percentage of 

mitigated hours for all ISOs and RTOs, again indicating competitive conditions across

these markets.

7. Market Pricing Metrics

The four market pricing metrics measure the customer cost impact of ISO and 

RTO markets. The first measure, the load-weighted locational marginal price (LMP) 

metric, measures the cost to load of energy purchased in ISO and RTO markets. The 

Notes

MISO reported less than 0.1% in all years.

CAISO did not report data for 2006-2008. CAISO 2009 data for April-December.

2006 - 2010 Real-Time Energy Market Percentage of Unit Hours 

Mitigated

0%

1%

2%

3%

4%

5%

1 2 3 4 5

ISO - NE

0%

1%

2%

3%

4%

5%

1 2 3 4 5

MISO

0%

1%

2%

3%

4%

5%

1 2 3 4 5

PJM

0%

1%

2%

3%

4%

5%

1 2 3 4 5

CAISO

0%

1%

2%

3%

4%

5%

1 2 3 4 5

SPP

0%

1%

2%

3%

4%

5%

1 2 3 4 5

NYISO

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second metric, components of total power costs, breaks out each element of all costs paid 

by load, thereby providing a comprehensive assessment of all ISO and RTO market 

costs.27 The third measure, the load-weighted, fuel-adjusted locational marginal price, is 

derived by holding fuel costs constant over a defined time period to show the trend of 

non-fuel customer costs over this period. This metric isolates the customer cost impact of 

cost elements such as transmission costs, congestion and losses, thereby providing a 

measure of the effectiveness of ISO and RTO market management. This metric also 

reflects the impact of load growth, investments in resources and the retirement of 

uneconomic facilities, and therefore it measures factors that are not entirely within the 

control of ISOs and RTOs. The fourth metric measures the impact of demand response 

on market prices, including impacts associated with voluntary curtailments by demand 

response during heat waves and other emergency conditions. All four metrics are 

measured on an annual basis. 

The first three metrics on market pricing and costs are summarized on a single 

chart below. The purple and green lines in the chart, the energy cost and total power cost 

metrics, closely follow fuel price trends. As detailed in the ISO and RTO performance 

reports, the nation-wide increase in fuel costs in 2008 and the decrease in 2009 were 

closely tracked in wholesale energy prices. More relevant to an assessment of ISO or 

RTO performance is the red line in the chart, the market price adjusted for fuel costs. 

This metric, when compared to unadjusted market prices, shows the impact of security 

constrained economic dispatch, incentives for improved generator availability, 

investment in more efficient generating units, and other factors on prices. Therefore, this 

metric provides a measure of the efficiency of ISO and RTO markets, and how that 

efficiency provides a benefit to consumers in their cost of energy. It should be noted that 

each ISO or RTO uses a different base year for its fuel adjustments and different fuel 

mixes and, therefore, direct comparisons between ISOs and RTOs are not meaningful. 

 27 The cost break-down includes the following cost categories: ISO or RTO costs 

and regulatory fees, operating reserve costs, ancillary services costs, transmission costs, 

capacity costs, and energy costs. 

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With regard to the fourth metric, the impact of demand response on prices, ISOs 

and RTOs provided the following information:

 MISO indicated that clearing prices declined by $100 - $200 per megawatthour during hours in which demand response participated in the August 1, 

2006 emergency event.28

 ISO-NE estimated that its demand response programs reduced average realtime LMPs between $0.04 (April-June 2009) and $1.72 (June-September 

2010) per megawatt-hour over the 2008-2010 period.29

 28 MISO Report at 181.

29 ISO-NE Report at 114.

 Load Weighted LMP ($/MWh)

 Fuel Adjusted LMP ($/MWh)

 Total Power Cost ($/MWh)

Notes

CAISO did not provide Total Power Cost data for 2006-2008. CAISO Total Power Cost and load-weighted LMP are identical in 2010.

SPP did not provide Total Power Cost data. LMP data for SPP is only available since 2007. 

CAISO SPP NYISO

2006 - 2010 Market Prices and Costs 

ISO - NE MISO PJM

$0

$20

$40

$60

$80

$100

$120

$0

$20

$40

$60

$80

$100

$120

$0

$20

$40

$60

$80

$100

$120

$0

$20

$40

$60

$80

$100

$120

$0

$20

$40

$60

$80

$100

$120

$0

$20

$40

$60

$80

$100

$120

2006 2007 2008 2009 2010 

2006 2007 2008 2009 2010 

2006 2007 2008 2009 2010 

2007 2008 2009 2010 

2006 2007 2008 2009 2010 

2006 2007 2008 2009 2010 

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 NYISO calculated that demand response reduced locational marginal prices 

between $0.04 (2007) and $2.05 (2008) per megawatt-hour.30

 PJM estimated that voluntary curtailments through its demand response 

program reduced wholesale energy prices by approximately $12 per 

megawatt-hour in the summer of 2010 and by more than $300 per 

megawatt-hour during August 2006.31

8. Energy Market Price Convergence

Convergence of day-ahead and real-time energy prices provides an indication of 

the efficiency of ISO and RTO markets. Since the large majority of energy settlements 

and generator commitments occur in the day-ahead market, day-ahead price convergence 

with the real-time market ensures efficient day-ahead commitments that reflect real-time 

operating needs. Energy market price convergence is measured by the absolute value and 

percentage of the annual difference between real-time energy market prices and dayahead market prices. Prices in ISO-NE, MISO and PJM showed a difference of less than 

two percent between day-ahead and real-time prices. NYISO reported a difference of 

between four and one percent. In CAISO, day-ahead and real-time prices had a 

difference of between eight and nine percent in 200932 and 2010. SPP did not report 

convergence information since it did not operate a day-ahead market.33

9. Congestion Management Metrics

Congestion represents the cost to customers of paying for more expensive energy 

because physical transmission line limits do not allow full delivery of least-cost energy.

The first congestion management metric, annual congestion costs divided by the 

megawatt hours of load served, tracks congestion cost trends relative to load growth,

thereby providing an indication of the efficiency of the overall ISO or RTO system as 

well as the effectiveness of ISO or RTO efforts to manage congestion costs through 

transmission expansion planning and other efficiency measures. This metric is also 

influenced by other factors, such as load trends, and therefore it is not entirely within the 

control of the ISO or RTO. The second metric, congestion revenues paid divided by 

 30 NYISO Report at 234.

31 PJM Report at 295.

32 Specifically, April 1, 2009 through December 31, 2009.

33 CAISO Report at 56; ISO-NE Report at 117-18; MISO Report at 183; NYISO 

Report at 238; PJM Report at 299-300; SPP Report at 344.

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congestion charges expressed as a percentage, tracks the ability of market participants to 

hedge these congestion costs, and thereby manage their costs. These metrics are shown 

on the charts below.

Notes

CAISO did not report data prior to 2009. CAISO 2009 data covers April through December. 

SPP did not report congestion data.

2006 - 2010 Congestion Costs

(Annual Congestion Costs per Megawatt Hour of Load Served)

$0

$2

$4

$6

$8

1 2 3 4 5

ISO-NE

$0

$2

$4

$6

$8

1 2 3 4 5

NYISO

$0

$2

$4

$6

$8

1 2 3 4 5

PJM

$0

$2

$4

$6

$8

1 2 3 4 5

MISO

$0

$2

$4

$6

$8

1 2 3 4 5

CAISO

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10. Resource Availability Metric

In addition to the generator outage metric, discussed above in the common 

metrics, ISOs and RTOs tracked demand resource availability. Demand resource 

availability measures the availability of demand response when called on to perform and 

when tested for its capability to meet capacity requirements. PJM reported that demand 

response performed at 121 percent of capacity values when called on in 2006, and 118 

percent in 2009 and 99 percent in 2010 when tested. Demand resources provided a 

cumulative load reduction in 2010 of 4,652 megawatts. NYISO reported that demand 

response was called on for five events in 2006 and two events in 2010. During the 2006 

events in NYISO, demand response provided between 314 and 865 megawatts per hour. 

During the 2010 events in NYISO, demand response provided between 387 and 409 

Notes

CAISO 2009 data covers April through December. 

SPP did not report congestion hedge data since it did not provide a

congestion hedge in the 2006-2010 period.

2006 - 2010 Congestion Hedge

(Percentage of Congestion Costs Hedged)

0%

20%

40%

60%

80%

100%

1 2 3 4 5

ISO-NE

0%

20%

40%

60%

80%

100%

1 2 3 4 5

NYISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

PJM

0%

20%

40%

60%

80%

100%

1 2 3 4 5

MISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

CAISO

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megawatts per hour. ISO-NE estimated availability of 966 megawatts for on-peak 

demand resources based on events from August 1, 2006 through August 25, 2009. MISO 

reported that it did not call on its load modifying resources during this period. CAISO 

and SPP did not report on this metric.

11. Renewables Metrics 

Renewable resource34 penetration in ISO and RTO markets is measured as the 

renewable share of total capacity and the renewable share of total energy. The 

renewables metrics indicate the diversity of an ISO or RTO resource mix to meet demand 

and capacity requirements. The renewable diversity profiles of the ISOs and RTOs are 

shown on the charts below.

 34 Renewable resources are defined as solar, wind, hydro, geothermal, and biomass 

resources. 

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Key and Note

Hydro

Other renewables (wind, solar, geothermal and biomass)

SPP did not provide data for 2006.

2006 - 2010 Renewable Capacity Metric

(Percentage of Total Capacity)

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

ISO-NE

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

NYISO

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

PJM

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

MISO

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

SPP

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

CAISO

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12. Administrative Costs Metrics 

Administrative cost metrics measure the ability of ISOs and RTOs to manage the 

growth rate of administrative costs commensurate with the growth rate of system load 

(administrative charges cents per megawatt-hour of load served metric) and to keep costs 

within budgeted levels (actual versus budgeted administrative charges metric). The 

components of ISO and RTO administrative costs are capital costs – capital charges, debt 

service, interest expense and depreciation expense – and operating and maintenance costs 

net of miscellaneous income. By managing administrative costs, ISOs and RTOs can 

reduce customer costs.

The pertinent analysis of the data shown on the accompanying chart is the trend in 

costs over the 2006–2010 for each ISO or RTO. Direct comparisons between the ISOs 

Key and Note

Hydro

Other renewables (wind, solar, geothermal and biomass)

SPP did not provide data for 2006.

2006 - 2010 Renewable Energy Metric

(Percentage of Total Energy Produced)

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

ISO-NE

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

NYISO

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

PJM

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

MISO

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

SPP

0%

5%

10%

15%

20%

25%

30%

1 2 3 4 5

CAISO

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and RTOs are not meaningful. While administrative costs vary widely across the ISOs 

and RTOs, from 20 cents per megawatt-hour for SPP up to over $1 dollar per megawatthour for ISO-NE, these cost differences are primarily attributable to the differences in the 

responsibilities of the various ISOs and RTOs. For example, during the 2006–2010 

period, eastern ISOs and RTOs managed day-two energy and reserve markets as well as 

capacity markets, thereby increasing their administrative costs, compared to an RTO such 

as SPP that only managed a day-one energy market and did not manage a capacity 

market. With respect to the second metric, which compares actual costs to budgeted 

amounts, this comparison is shown for noncapital (operations and maintenance costs) and 

capital costs (capital charges, debt service, interest expense and depreciation expense) on 

the charts below. 

CAISO SPP NYISO

2006 - 2010 Administrative Costs (Per Megawatt Hour of Load)

ISO-NE MISO PJM

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

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Actual Spending (in millions) % of Budget

Notes

Left Axis: Actual Spending

Right Axis: Spending Percent of Budget

2006 - 2010 Noncapital Costs and Budget Comparison

80%

90%

100%

110%

120%

130%

140%

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

1 2 3 4 5

ISO - NE

80%

90%

100%

110%

120%

130%

140%

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

1 2 3 4 5

NYISO

80%

90%

100%

110%

120%

130%

140%

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

1 2 3 4 5

PJM

80%

90%

100%

110%

120%

130%

140%

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

1 2 3 4 5

MISO

80%

90%

100%

110%

120%

130%

140%

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

1 2 3 4 5

SPP

80%

90%

100%

110%

120%

130%

140%

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

1 2 3 4 5

CAISO

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Actual Spending (in millions) % of Budget

Notes

Left Axis: Actual Spending

Right Axis: Spending Percent of Budget

2006 - 2010 Capital Costs and Budget Comparison

40%

60%

80%

100%

120%

140%

160%

180%

200%

$0

$20

$40

$60

$80

$100

$120

$140

$160

1 2 3 4 5

ISO - NE

40%

60%

80%

100%

120%

140%

160%

180%

200%

$0

$20

$40

$60

$80

$100

$120

$140

$160

1 2 3 4 5

NYISO

40%

60%

80%

100%

120%

140%

160%

180%

200%

$0

$20

$40

$60

$80

$100

$120

$140

$160

1 2 3 4 5

PJM

40%

60%

80%

100%

120%

140%

160%

180%

200%

$0

$20

$40

$60

$80

$100

$120

$140

$160

1 2 3 4 5

MISO

40%

60%

80%

100%

120%

140%

160%

180%

200%

$0

$20

$40

$60

$80

$100

$120

$140

$160

1 2 3 4 5

SPP

40%

60%

80%

100%

120%

140%

160%

180%

200%

$0

$20

$40

$60

$80

$100

$120

$140

$160

1 2 3 4 5

CAISO

13. Customer Satisfaction Metric 

The percentage of satisfied members metric, based on an independent assessment 

of customer satisfaction, provides an indication of the extent to which ISOs and RTOs 

provide value to their customers. The independent assessments of customer satisfaction 

are based on surveys undertaken by independent, third-party entities. These surveys 

analyze customer perspectives on a wide range of ISO and RTO activities. Results of the 

customer satisfaction surveys are shown on the charts below.

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Notes

SPP 2009 survey did not measure customer satisfaction.

CAISO did not provide data for 2006.

2006 - 2010 Customer Satisfaction

(Percentage of Satisfied Customers)

0%

20%

40%

60%

80%

100%

1 2 3 4 5

ISO-NE

0%

20%

40%

60%

80%

100%

1 2 3 4 5

NYISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

PJM

0%

20%

40%

60%

80%

100%

1 2 3 4 5

MISO

0%

20%

40%

60%

80%

100%

1 2 3 4 5

SPP

0%

20%

40%

60%

80%

100%

1 2 3 4 5

CAISO

14. Billing Controls Metric

This metric indicates the accuracy and integrity of the ISO and RTO billing 

processes, based on audits conducted according to the Statement on Auditing Standards 

No. 70 (SAS 70) guidelines set by the American Institute of Certified Public 

Accountants. The audits describe the controls, the results of testing of the ISO and RTO 

controls, whether the controls were designed to achieve the control objectives, the 

auditor’s opinions on the audit and whether the controls that were tested operated with 

sufficient effectiveness to provide reasonable assurance that the control objectives were 

achieved.

There are two types of SAS 70 audits: Type 1 audits, which assess the adequacy of 

the control design, and Type 2 audits, which review both the adequacy of the control 

design and whether the controls are being followed. An unqualified opinion indicates 

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that the independent auditor found the control objectives for each of the areas covered by 

the audit to be adequately designed and operated for the audit period. A qualified opinion 

means the independent auditor found the design and/or the operation of one or more of 

the control objectives inadequate. In this case, specific inadequate control objective(s) 

are identified and the remaining control objectives covered by the audit are deemed 

adequate. Audit results are shown in the table below.

2006 – 2010 Billing Control Audits

ISO/RTO 2006 2007 2008 2009 2010

CAISO Unqualified

(Type 2)

Qualified

(Type 2)

Qualified

(Type 2)

Unqualified

(Type 1 and 

Type 2)

Unqualified

(Type 2)

ISO-NE Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

NYISO Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

MISO Unqualified

(Type 2)

Qualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

PJM Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

Unqualified

(Type 2)

SPP Qualified

(Type 2)

Qualified

(Type 2)

Qualified

(Type 2)

Qualified

(Type 2)

Unqualified

(Type 2)

B. Other Metrics Specific To Regions Outside ISO and RTO Markets 

1. Outages With Less Than Two Days’ Notice

In addition to the common metrics for transmission outages discussed above, 

utilities outside of ISO and RTO markets measure the performance of their outage 

coordination in terms of the percentage of outages, planned and unplanned, with less than 

two days’ notice. A low percentage of short-notice outages indicates effective 

transmission coordination. Data on this metric is provided on the charts below.

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2. Dollar Amount of Facilities Approved To Be Constructed For 

Reliability Purposes and Stakeholder Process For Transmission 

Planning

As part of the performance metrics for long-term reliability transmission planning, 

utilities outside of ISO and RTO markets provided information on the dollar amount of 

facilities approved to be constructed for reliability purposes and discussions of their 

stakeholder processes. With regard to the dollar amount metric, the utilities submitted 

the following information.

 Transmission Capital Investment ($Millions)

Entity 2006 2007 2008 2009 2010

Duke $264 $286 $399 $404 $401

Southern $514 $447 $375 $334 $500

Notes

LG&E/KU - no data for 2006-2007.

Duke:

 Duke Energy Carolinas: 18% for late February 2009-2010.

 Progress Energy Carolinas: 3.5% for May 2009-2010.

 Progress Energy Florida: no data provided.

APS and Southern did not provide data.

2006 - 2010 Short Notice Outages

Percentage of Outages (Planned and and Unplanned)

With Less Than Two Days' Notice

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

LG&E/KU

0%

5%

10%

15%

20%

25%

30%

35%

40%

1 2 3 4 5

PacifiCorp

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 Net Cost of Approved Reliability Projects ($Millions)

Entity 2006 2007 2008 2009 2010

PacifiCorp $1 $6 $50 $102 $133

APS reported an estimated cost of $639 million over the 2006-2010 period for 

projects that had been granted Certificates of Environmental Compatibility by the 

Arizona Corporation Commission. LG&E/KU did not provide data.

With regard to the stakeholder process, the purpose of this evaluation is to provide 

insights into the efficacy of each transmission provider’s planning process. Highlights 

from the discussions include the following:

 Subsidiaries of Duke participate in the North Carolina Transmission 

Planning Collaborative, the Florida Reliability Coordinating Council, Inc.

Regional Transmission Planning Process and various SERC Reliability 

Corporation groups associated with reliability assessments. Stakeholders 

have the opportunity to propose alternatives to projects included in the 

expansion plans as well as sensitivity analyses. Stakeholders in these 

processes include transmission-dependent utilities, public service 

commission staff, federal and state regulatory representatives and nongovernmental organizations.

 Southern participates in the SERC transmission planning process. In this 

process, stakeholders (transmission owners/operators, transmission service 

customers, cooperatives, municipals, power marketers, generator 

owners/developers, ISOs/RTOs, and demand response resources) establish 

and participate in a regional planning stakeholder group. Additional 

stakeholders in the process may include transmission-dependent utilities, 

public service commission staff, federal and state regulatory representatives 

and non-governmental organizations. The purpose of the regional planning 

stakeholder proceedings is to solicit stakeholder feedback and represent 

multiple stakeholder groups in focused interactions and dialogue with 

project sponsors.

 LG&E/KU coordinates transmission planning with a Stakeholder Planning 

Committee. Membership in the Stakeholder Planning Committee is open to 

all interested parties and is comprised of transmission customers, loadserving entities and municipal organizations.

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 PacifiCorp participates in the regional planning process of the Northern 

Tier Transmission Group. PacifiCorp’s description of its transmission 

planning process outlines a process for stakeholders to provide input and 

bring forth those transmission needs driven by public policy requirements 

and commits PacifiCorp to participate in a regional transmission planning 

process. Stakeholders in this planning process include network customers 

(Bonneville Power Administration, Deseret Generation and Transmission 

Cooperative, Utah Municipal Power Agency, and Utah Associated 

Municipal Power Systems), generation developers, state public utility 

commissioners, and public interest groups.

 APS participates in regional planning organizations and the WestConnect 

organization. APS is also a member of WECC and Southwest Area 

Transmission Planning group. APS provides an opportunity for other 

entities to participate in future planned projects through the annual planning 

process. These entities include FERC-jurisdictional and non-jurisdictional 

utilities, state utility regulatory bodies, generator developers, transmission 

line project developers, consumer advocates, and individual customers.

3. Transmission Access/Transmission Service Requests Denials

The interconnection and transmission service request metric measures the number 

of transmission access or transmission service denials. The purpose of this metric is to 

provide information on the magnitude and reasons for transmission service denials and 

whether additional infrastructure investment is needed to avoid transmission service 

denials. Results are shown on the table below.

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2006 – 2010 Transmission Service Requests Denied

Entity 2006 2007 2008 2009 2010

APS 6 6 0 3 1

Duke 3 9 12 28 26

LG&E/KU 1208 985 704 237 1574

PacifiCorp 2 0 1 2 0

Southern 6 19 13 1 0

Notes

Duke, Southern and APS count refused requests only. LG&E/KU denials were due to 

insufficient flowgate capacity. PacifiCorp denials were due to incomplete applications.

4. Demand Response and Renewables Integration Discussions

These metrics require the following discussions: (1) a comprehensive explanation 

of the nature of utility demand response programs implemented to manage load and to 

comply with state requirements; and (2) a discussion of programs to facilitate the 

integration of renewable resources and to mitigate any issues and uncertainty associated 

with scheduling renewable resources.

Each responding utility had several demand response programs in operation during 

the 2006–2010 period. Highlights of the demand response discussions are as follows:

 PacifiCorp’s demand response programs35 provided a maximum curtailment 

capability of 738 megawatts.

 LG&E/KU demand response programs provided 180 megawatts of curtailment 

capability.

 APS demand response programs reduced summer peak loads by over 100 

megawatts.

 35 These are irrigation load control, energy exchange load shaving, air conditioner 

direct load control, and industrial agreements.

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 Duke and Southern discussed their demand response programs and provided 

links to these programs on their respective corporate websites.

Utility programs to integrate renewable resources include the following:

 PacifiCorp used automatic generation control on its resources to facilitate the 

integration of renewable resources and it participated in the joint initiative that 

developed tools such as the intra-hour transaction accelerator platform and 

dynamic scheduling system to assist in the integration of renewable resources. 

 APS required its generation to follow ramping events of wind generators and 

anticipates adding gas-fired peak generators to compensate for the 

intermittency of multiple types of renewable energy generation.

5. Congestion Management

Congestion represents the cost to customers of paying for more expensive energy 

because physical transmission line limits do not allow full delivery of least-cost energy. 

Entities responding to this metric were required to provide a congestion analysis 

consistent with Order No. 890.36 In Order No. 890, the Commission adopted a planning 

principle requiring transmission providers to prepare studies identifying “significant and 

recurring” congestion and to post such studies on their Open Access Same-Time 

Information Systems (OASIS). The Commission explained that these studies should 

analyze and report on the following items: (1) location and magnitude of the congestion; 

(2) possible remedies for the elimination of the congestion, in whole or in part; (3) 

associated costs of congestion; and (4) costs associated with relieving congestion through 

system enhancements (or other means).37

All responding utilities cited information provided in their tariff descriptions of 

their transmission planning processes and some of them provided explanations of their 

programs to address congestion issues, including planning processes, stakeholder 

processes and studies undertaken in their regions to minimize congestion, as follows:

 36 Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERC 

Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 

(2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, 

Order No. 890-D, 129 FERC ¶ 61,126 (2009). 

37 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at PP 529, 542.

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 PacifiCorp discussed the congestion analysis done by the WECC Transmission 

Expansion Planning Policy Committee and the role played by PacifiCorp’s 

Energy Gateway Project in alleviating congestion.38

 LG&E/KU explained that the primary causes of congestion on its system are 

non-firm transfers and generating unit commitments. LG&E/KU also

described the components of its planning process.39

 Duke and Southern explained how their transmission planning processes are 

designed to minimize congestion and the role of congestion studies in regional 

planning processes.40

6. Transmission System Availability

This metric measures interrupted load megawatt hours as a percentage of 

megawatt hours of load served. Duke, Southern and APS reported zero interruptions 

over the 2006–2010 period. LG&E/KU and PacifiCorp did not have information on 

interruptions. PacifiCorp, however, reported system availability between 99.9108 

percent and 99.9532 percent for the 2006–2010 period based on Form OE-417 data.

7. Clean Energy

The clean energy41 metrics track the megawatt capacity of clean energy, by 

resource type, as a percentage of total capacity, and the megawatt-hours of clean energy, 

by resource type, as a percentage of total energy. This information is provided on the 

accompanying charts. 

 38 PacifiCorp Report at 50-52.

39 LG&E/KU Report at 17-18.

40 Duke Report at 40-41; Southern Report at 32-33.

41 Clean energy is defined to include nuclear energy, solar, wind, hydro, 

geothermal, landfill, and biomass resources. 

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Key

Unspecified clean energy

Hydro

Nuclear

Renewables (wind, solar, geothermal

 and biomass)

2006 - 2010 Clean Capacity

(Percentage of Total Capacity)

0%

10%

20%

30%

40%

50%

1 2 3 4 5

Duke Carolinas

0%

10%

20%

30%

40%

50%

1 2 3 4 5

Progress 

Carolinas

0%

10%

20%

30%

40%

50%

1 2 3 4 5

Progress Florida

0%

10%

20%

30%

40%

50%

1 2 3 4 5

Southern

0%

10%

20%

30%

40%

50%

1 2 3 4 5

LG&E/KU

0%

10%

20%

30%

40%

50%

1 2 3 4 5

PacifiCorp

0%

10%

20%

30%

40%

50%

1 2 3 4 5

APS

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Key

Unspecified clean energy

Hydro

Nuclear

Renewables (wind, solar, geothermal, biomass)

2006 - 2010 Clean Energy 

(Percentage of Total Energy Produced)

0%

10%

20%

30%

40%

50%

60%

70%

1 2 3 4 5

Duke Carolinas

0%

10%

20%

30%

40%

50%

60%

70%

1 2 3 4 5

Progress 

Carolinas

0%

10%

20%

30%

40%

50%

60%

70%

1 2 3 4 5

Progress Florida

0%

10%

20%

30%

40%

50%

60%

70%

1 2 3 4 5

Southern

0%

10%

20%

30%

40%

50%

60%

70%

1 2 3 4

LG&E/KU

0%

10%

20%

30%

40%

50%

60%

70%

1 2 3 4 5

PacifiCorp

0%

10%

20%

30%

40%

50%

60%

70%

1 2 3 4 5

APS

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8. Price Metric

In the Commission Staff Report on performance metrics in regions outside ISOs 

and RTOs, Commission Staff proposed that utilities provide a price metric on their 

wholesale power sales based on a single, average price for energy and capacity, in 

addition to reporting peak and off-peak prices. Commission Staff requested that 

participating utilities discuss their perspectives on a wholesale price metric.42 Several of 

the utilities (APS, Duke, Southern) responded that a single, annualized average price 

metric would not provide useful performance information and PacifiCorp noted that the 

averaging of data may mask pertinent information. PacifiCorp also questions whether the 

Commission’s proposal to obtain and collect data concerning wholesale prices is intended 

to measure the health of wholesale markets, or intended to identify instances of bad 

behavior by market participants. Southern and APS disagreed with the premise that a 

single price metric, applicable to all wholesale market models, can be developed. APS 

stated that a single, annualized price will not be useful without a detailed and timeconsuming analysis of individual transaction data. Duke indicated that the challenges of 

comparing wholesale market prices in the Southeast with organized ISO/RTO market 

prices preclude the ability to construct a meaningful common metric.43 

We continue to believe that a price metric for utilities outside RTO regions would 

provide a basis for comparing cost trends between RTOs and areas outside RTOs. In 

response to PacifiCorp regarding the intended purpose of a price metric, we emphasize 

that such a metric would be useful in measuring the health of wholesale markets. As 

discussed in the Commission Staff Report, information on a price metric would be useful 

in assessing the performance of utilities in pricing their products competitively. We 

encourage participating utilities to develop price metrics that are meaningful. For 

example, price metrics could be developed for comparable products, such as peak, offpeak and year-round capacity and energy and these product prices could then be volumeweighted into an average price. Accordingly, we repeat our request for data, even if the 

information is not directly comparable to RTOs.

 42 Performance Metrics In Regions Outside ISOs and RTOs Commission Staff 

Report, Docket No. AD12-8-000 at 14 (Oct. 15, 2012).

43 See APS Report at 28; Duke Report at 46-47; Southern Report at 13; PacifiCorp 

Report at 63.

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Appendix A

Common Metrics
Docket No. AD14-15-000 

- 2 -

Performance Metric Specific Metric(s)

Reliability

A.

NERC Reliability 

Standards Compliance

1. References to which NERC standards are applicable

2. Number of violations self-reported and made public by NERC/FERC

3. Number of violations identified and made public as NERC audit findings

4. Total number of violations made public by NERC/FERC

5. Severity level of each violation made public by NERC/FERC

6. Compliance with operating reserve standards

7. Unserved energy (or load shedding) caused by violations. Additional detail will be provided on 

(1) number of events; (2) duration of the events; (3) whether the events occurred during on/offpeak hours; (4) additional information on equipment types affected and kV of lines affected; and 

(5) number of events (and severity and duration of events) resulting in load shedding based on the 

utilization of TPL-002 Footnote b criteria. 

Utilities outside ISO and RTO regions should limit reporting to the same eight functional areas 

used by the ISOs and RTOs:

1. Balancing Authority 7. Transmission Planner

2. Interchange Authority 8. Transmission Service Provider

3. Planning Authority

4. Reliability Coordinator

5. Resource Planner

6. Transmission Operator
Docket No. AD14-15-000 

- 3 -

Performance Metric Specific Metric(s)

B. Dispatch Reliability 1. Balancing Authority ACE Limit (BAAL) or CPS1 and CPS2

2. Energy Management System (EMS) availability 

C. Load Forecast Accuracy Actual peak load as a percentage variance from forecasted peak load 

D. Wind Forecasting 

Accuracy

Actual wind availability compared to forecasted wind availability

E. Unscheduled Flows Difference between net actual interchange (actual measured power flow in real time) and the net 

scheduled interchange in megawatt hours

 Reported in FERC Form No. 714

F. Transmission Outage 

Coordination

1. Percentage of ≥ 200 kV planned outages of 5 days or more for which ISO, RTO or utility 

notified customers at least 1 month prior to the outage commencement date.

2. Percentage of ≥ 200kV outages cancelled by utility after being approved previously.

G. Long-Term Reliability 

Planning – Transmission

1. Number of facilities approved for construction due to reliability purposes

2. Percentage of approved construction projects on schedule and completed

3. Performance of planning process related to:

 a. Completion of reliability studies

 b. Completion of economic studies 
Docket No. AD14-15-000 

- 4 -

Performance Metric Specific Metric(s)

H. Long-Term Reliability 

Planning – Resources

1. Processing time for generation interconnection requests

2. Actual reserve margins compared with planned reserve margins

 

I. Interconnection and 

Transmission Process 

Metrics

1. Number of requests

2. Number of studies completed

3. Average age of incomplete studies

4. Average time for completed studies 

5. Total cost and types of studies completed (e.g., feasibility study, system impact study and 

facility study)

J. Special Protection 

Systems

1. Number of special protection systems

2. Percentage of special protection systems that responded as designed when activated

 Applicable pool of special protection systems should be based on how the reporting entity’s 

Regional Entity defines “special protection systems”

3. Number of unintended activations
Docket No. AD14-15-000 

- 5 -

Performance Metric Specific Metric(s)

System Operations Measures

A. System Lambda System Lambda (on marginal unit)

 System Lambda metric does not apply to ISOs, RTOs or utilities where the marginal price is 

set by hydro units

 System lambda data will be based on FERC Form No. 714 information.

B. Resource Availability 1 - System forced outage rate as measured over 12 months

C. Fuel Diversity Fuel diversity in terms of energy produced and installed capacity
Appendix B

List of Participants

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List of Participants In The Metrics Initiative

Allegheny Power and Allegheny Energy Supply Company, LLC 

American Public Power Association

American Wind Energy Association

Arizona Public Service Company 

California Department of Water Resources State Water Project

California Independent System Operator Corporation

California Public Utilities Commission

City of Redding, City of Santa Clara and M-S-R Public Power Agency

COMPETE Coalition

Consumer Commenters1

DC Energy, LLC

Delaware Municipal Electric Corporation, Inc.

Dominion Resources Services, Inc.

Duke Energy Corporation

Edison Electric Institute

Eastern Massachusetts Consumer-Owned Systems2

Electric Power Supply Association

Electricity Consumers Resource Council

Federal Trade Commission

FirstEnergy Service Company

 1 AARP, American Forest & Paper Association, American Municipal Power, Inc., 

American Public Power Association, Blue Ridge Power Agency, Citizen Power, Citizens 

Utility Board, Coalition of Midwest Transmission Customers, Connecticut Office of 

Consumer Counsel, Electricity Consumers Resource Council, Illinois Attorney General, 

Industrial Energy Consumers of America, Kennebunk Light & Power District, Maryland 

Office of People’s Counsel, Modesto Irrigation District, Municipal Electric Utilities 

Association of New York, National Consumer Law Center, NEPOOL Industrial 

Customer Coalition, Northeast Public Power Association, New York Association of 

Public Power, Office of the People’s Counsel for the District of Columbia, Ohio Partners 

for Affordable Energy, Pennsylvania Office of Consumer Advocate, PJM Industrial 

Customer Coalition, Public Citizen, Public Power Association of New Jersey, Public 

Utility Law Project of New York, Inc., and Virginia Citizens Consumer Council. 

2 Belmont Municipal Light Department, Braintree Electric Light Department, 

Hingham Municipal Lighting Plant, Reading Municipal Light Department, Taunton 

Municipal Lighting Plant, and Wellesley Municipal Lighting Plant.

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Internal Market Monitor of ISO New England Inc.

ISO/RTO Council 

Independent Power Producers of New York, Inc.

Indicated New York Transmission Owners3

International Transmission Company

Kentucky Utilities Company

Louisville Gas and Electric Company

Maine Public Utilities Commission

Maryland Public Service Commission

Attorney General of the Commonwealth of Massachusetts

MidAmerican Energy Company

Midcontinent Independent System Operator, Inc.

Midwest ISO Transmission Owners4

Missouri Public Service Commission

Multiple Transmission-Dependent Public Power Systems5

 3 Central Hudson Gas & Electric Corporation, Consolidated Edison Company of 

New York, Inc., Long Island Power Authority, New York Power Authority, New York 

State Electric & Gas Corporation, Orange and Rockland Utilities, Inc., and Rochester Gas 

and Electric Corporation.

4 Ameren Services Company, as agent for Union Electric Company d/b/a 

AmerenUE, Central Illinois Public Service Company d/b/a AmerenCIPS, Central Illinois 

Light Co. d/b/a AmerenCILCO, and Illinois Power Company d/b/a AmerenIP; American 

Transmission Company LLC; City of Columbia Water and Light Department (Columbia, 

MO); City Water, Light & Power (Springfield, IL); Duke Energy Corporation for Duke 

Energy Ohio, Inc., Duke Energy Indiana, Inc., and Duke Energy Kentucky, Inc.; Great 

River Energy; Hoosier Energy Rural Electric Cooperative, Inc.; Indiana Municipal Power 

Agency; Indianapolis Power & Light Company; International Transmission Company 

d/b/a ITCTransmission; ITC Midwest LLC; Michigan Electric Transmission Company, 

LLC; Michigan Public Power Agency; MidAmerican Energy Company; Minnesota 

Power (and its subsidiary Superior Water, L&P); Montana-Dakota Utilities Co.; Northern 

Indiana Public Service Company; Northern States Power Company, a Minnesota

corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries 

of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power 

Company; Southern Illinois Power Cooperative; Southern Indiana Gas & Electric 

Company (d/b/a Vectren Energy Delivery of Indiana); Southern Minnesota Municipal 

Power Agency; Wabash Valley Power Association, Inc.; and Wolverine Power Supply 

Cooperative, Inc.

5 Public Works Commission of the City of Fayetteville, North Carolina, Lafayette 

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- 4 -

National Association of Regulatory Utility Commissioners

National Association of State Utility Consumer Advocates

National Grid USA

National Rural Electric Cooperative Association

New England Conference of Public Utility Commissioners

ISO New England Inc.

New England Power Generators Association, Inc.

New England Power Pool Participants Committee

New England States Committee on Electricity

New Jersey Department of the Public Advocate, Division of Rate Counsel

New Hampshire Public Utilities Commission

New York Independent System Operator, Inc.

New York State Public Service Commission 

Northwest & Intermountain Power Producers Coalition 

Public Utilities Commission of Ohio

Office of the Ohio Consumers’ Counsel

Old Dominion Electric Cooperative

Organization of MISO States

Pacific Gas and Electric Company

PacifiCorp

Pennsylvania Public Utility Commission

Pepco Holdings, Inc.

PJM Interconnection, L.L.C.

PJM Power Providers Group

Public Systems6

Retail Energy Supply Association

Southern Company

Southern California Edison Company

Southwest Power Pool, Inc.

Steel Producers Association7

Transmission Agency of Northern California

Transmission Access Policy Study Group

Tyrone J. Christy, Vice Chairman, Pennsylvania Public Utility Commission 

 

Utilities System, and City of Orangeburg, South Carolina.

6 Connecticut Municipal Electric Energy Cooperative, Massachusetts Municipal 

Wholesale Electric Company and New Hampshire Electric Cooperative, Inc.

7 Steel Dynamics and Nucor Steel.

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United Illuminating Company

Viridity Energy, Inc.

Westar Energy, Inc.

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Document Content(s)

Common Metrics Commission Staff Report (clean).DOCX...................1-90

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