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pdfPERFORMANCE METRICS IN REGIONS
OUTSIDE ISOs AND RTOs
Commission Staff Report
Federal Energy Regulatory Commission
October 15, 2012
This report does not necessarily reflect the views of the Commission, its
Chairman, or individual Commissioners, and it is not binding on the Commission
Docket No. AD12-8-000
Table of Contents
Section
Page
I. Background………………………………………………………………… 4
II. Notice of Filing and Responsive Pleadings.……………………………...... 5
III. Discussion..……………………………………………………………...... 6
A. Procedural Issues..…………………………………………………... 6
B. Metrics Issues………………………………………………………...7
1. General Issues…………………………………………………7
2. Additional Metrics……………………………………………9
3. Discussion of Individual Metrics.……………………………15
a. National and Regional Reliability Standards………..15
b. Dispatch Reliability…………………………………18
c. Load Forecasting Accuracy.………………………...20
d. Wind Forecasting Accuracy….………………….….20
e. Unscheduled Flows………………………………….22
f. Transmission Outage Coordination..………………..23
g. Long-Term Reliability Planning – Transmission…..24
h. Long-Term Reliability Planning – Resources..……..27
i. Infrastructure Investment..………………………….27
j. Special Protection Systems…………………………30
k. Demand Response...…………………………………31
l. System Lambda……………………………………...31
m. Congestion Management.……………………………31
n. Resource Availability………………………………..32
o. Transmission System Availability.…………………..32
p. Fuel Diversity………………..……………………...32
q. Clean Energy....……………………………………...33
C. Burden Estimate……………………………………………………33
D. Information Collection Statement..…………………………………34
Appendix: Performance Metrics in Regions Outside ISOs and RTOs
2
Docket No. AD12-8-000
Federal Energy Regulatory Commission Staff Report on Performance Metrics for
Regions Outside of ISOs and RTOs 1
The purpose of this Federal Energy Regulatory Commission (Commission) Staff
report is to describe the final metrics that have been developed to track performance and
operations of utilities in regions outside of Independent System Operators (ISO) and
Regional Transmission Organizations (RTO). While these metrics are based on the
metrics previously developed to track the performance of ISOs and RTOs in Docket No.
AD10-5, they have been tailored to fit markets outside of ISOs and RTOs. Consistent
with the approach used to create performance metrics for ISOs and RTOs and also with
the Commission’s FY2009-2014 Strategic Plan, Commission Staff worked with the
Edison Electric Institute (EEI), its members, and other interested stakeholders to design
this set of performance metrics. Commission Staff appreciates the public comments filed
in this proceeding, which we have taken into account in developing the final metrics for
tracking performance and operations of utilities in regions outside of ISOs and RTOs. 2
As for next steps, Commission Staff requests participating utilities to submit
reports providing data and explanatory information for the 2006-2010 period that
responds to the final list of performance metrics contained in the Appendix. 3 The
information included in these reports will cover the same time period that ISOs and RTOs
covered in their second performance report to the Commission. We ask participating
utilities to submit their reports by January 25, 2013.
The next performance report, which is expected to issue in 2013, will be based on
2008-2012 data. Having developed metrics for ISOs/RTOs, and then tailored these
metrics to suit non-ISOs/RTOs, Commission Staff has established appropriate common
metrics between ISOs/RTOs and non-ISOs/RTOs. 4 We will, however, continue to assess
the metrics and evaluate the responses received in response to both the ISO/RTO metrics
1
This report does not necessarily reflect the views of the Commission, its
Chairman, or individual Commissioners, and it is not binding on the Commission.
2
The final list of metrics is provided in the Appendix.
3
We expect entities to provide data and explain performance trends in a manner
consistent with the responses provided by ISOs and RTOs in Docket No. AD10-5-000.
See, e.g., The Six ISOs and RTOs 2011 ISO/RTO Metrics Report, Docket No. AD10-5000 (Aug. 31, 2011) (2011 ISO/RTO Metrics Report).
4
See Commission Staff Report on ISO/RTO Metrics, Docket No. AD10-5-000, at
6 (October 21, 2010) (Staff Report).
3
Docket No. AD12-8-000
and the non-ISO/RTO metrics to ensure there are no inconsistencies, and we will further
modify the metrics as necessary.
I.
Background
Responding to a request for an investigation into ISO/RTO costs, structure,
processes, and operations, 5 the Government Accountability Office, in a September 2008
Report to the U.S. Senate Committee on Homeland Security and Governmental Affairs, 6
recommended that the Chairman of the Commission take action to accomplish the
following: (1) work with RTOs, stakeholders, and other experts to develop standardized
measures that track the performance of RTO operations and markets; and (2) report the
performance results to Congress and the public, while also providing the following
interpretation: (a) what the measures and reported performance communicate about the
benefits of RTOs; and, where appropriate (b) changes that need to be made to address any
performance concerns. The Government Accountability Office Report also suggested
that the Commission explore performance metrics for non-ISOs/RTOs. 7
The Performance Metrics effort is also part of the Commission’s Strategic Plan,
which includes a Metrics Initiative. The first step of the Performance Metrics effort was
to develop appropriate operational and financial metrics for ISOs/RTOs. This step was
completed with the submission of a Report to Congress. 8 The next steps in the Metrics
Initiative are as follows: (1) explore and develop appropriate operational and financial
5
This request was made on May 21, 2007, by Senator Joseph I. Lieberman,
Chairman, and Senator Susan M. Collins, Ranking Minority Member, of the U.S. Senate
Committee on Homeland Security and Governmental Affairs, in a letter to the U.S.
Government Accountability Office. The letter expressed the Senators’ concern that
ISOs/RTOs may not be living up to their full potential with respect to improving
efficiencies and reducing costs, and that they might not have adequate incentives to
minimize costs.
6
U.S. Government Accountability Office, Electricity Restructuring: FERC Could
Take Additional Steps to Analyze Regional Transmission Organizations’ Benefits and
Performance (2008) (Government Accountability Office Report). A copy of the
Government Accountability Office Report, GAO-08-987, can be found at
http://www.gao.gov/new.items/d08987.pdf.
7
Government Accountability Office Report at 57.
8
Performance Metrics For Independent System Operators and Regional
Transmission Organizations, Docket No. AD10-5-000, at 5 (October 21, 2010). See also
2010 ISO/RTO Metrics Report, Docket No. AD10-5-000 (Dec. 6, 2010).
4
Docket No. AD12-8-000
metrics for utilities in non-ISO/RTO regions; (2) establish appropriate common metrics
between ISOs/RTOs and non-ISO/RTO regions; (3) monitor implementation and
performance; and (4) evaluate performance and seek changes as necessary.
Consistent with FERC’s FY 2009 – 2014 Strategic Plan, with the issuance of this
report, Commission Staff has now completed the first and second of the “next steps” of
the Metrics Initiative, and in the coming months will evaluate the performance of utilities
in non-ISO/RTO regions. Starting with the list of metrics developed for ISOs/RTOs,
Commission Staff met with a team of representatives of utilities that operate outside of
ISOs and RTOs to develop performance metrics for utilities in non-ISO/RTO regions.
These discussions resulted in a list of 31 proposed performance metrics. Commission
Staff then held focused outreach meetings with a variety of industry, consumer, and state
regulatory associations to discuss the proposed metrics. 9 As a follow-up to that outreach,
Commission Staff’s proposed performance metrics were noticed for public comment and
reply comment in Docket No. AD12-8-000 on February 23, 2012.
II.
Notice of Filing and Responsive Pleadings
Notice of Commission Staff’s request for comments on draft metrics for regions
outside of ISOs and RTOs was published in the Federal Register, 77 Fed. Reg. 12,832
(2012), with comments due on or before May 1, 2012 and reply comments due on or
before May 16, 2012. Comments were filed by Edison Electric Institute (EEI), Electric
Power Supply Association (EPSA), Joint Commenters, 10 Multiple TDUs, 11 and
Northwest & Intermountain Power Producers Coalition (NIPPC). EEI filed reply
comments.
9
Commission Staff, Edison Electric Institute (EEI) and utility representatives met
with the Compete Coalition, ISO/RTO Council, Electric Power Supply Association
(EPSA), National Association of Regulatory Utility Commissioners (NARUC), National
Association of State Utility Consumer Advocates (NASUCA), and National Rural
Electric Cooperative Association (NRECA).
10
Joint Protesters are: AARP, American Public Power Association, Citizen
Power, Electricity Consumers Research Council, and Virginia Citizens Consumer
Council.
11
Multiple TDUs are: Public Works Commission of the City of Fayetteville,
North Carolina, Lafayette Utilities System, and the City of Orangeburg, South Carolina.
5
Docket No. AD12-8-000
III.
Discussion
A.
Procedural Issues
1.
Comments
Joint Commenters argue that the process used for developing performance metrics
outside of ISOs and RTOs is fundamentally flawed. They claim that the metrics
developed for ISOs and RTOs do not adequately measure performance because the
Commission relied on the regulated ISOs and RTOs themselves to develop measures of
their own performance. Thus, they maintain that any attempt to develop comparable
metrics for public utilities outside of RTOs and ISOs is a fruitless endeavor. Moreover,
they state that the Commission is making the same mistake here by allowing those
entities that will eventually report under the metrics to drive their development. While
they acknowledge that regulated entities have expertise that can inform the development
of the metrics, they object to having regulated entities develop the metrics without the
benefit of what Joint Commenters consider to be a transparent and open public process. 12
In reply, EEI argues that the Joint Commenters overlook the fact that the metrics
are the product of a collaborative process. In this regard, EEI notes that it and its
members participated in Commission-led outreach sessions to discuss the proposed
metrics and solicit feedback from stakeholders, which was taken into account before the
metrics were issued for public comment. EEI notes that the Joint Commenters fail to
provide reasons why the metrics will not be useful and cautions the Commission against
ignoring the benefits of the metrics in favor of accepting the Joint Commenters’
unsupported claims. 13
2.
Response
Commission Staff disagrees with Joint Commenters’ characterization of the
process used to develop the metrics for regions outside of ISOs and RTOs as
“fundamentally flawed.” Commission Staff used a process similar to the process that was
used to develop metrics for ISOs/RTOs. Commission Staff invited broad stakeholder
participation and engaged in a process with EEI, its members, and other interested
stakeholders to develop performance metrics tailored to regions outside of ISOs and
RTOs. Since the goal is to develop metrics that are comparable for ISOs/RTOs and non12
Joint Commenters Comments at 2-3.
13
EEI Reply Comments at 2-3.
6
Docket No. AD12-8-000
ISOs/RTOs, Commission Staff began by assessing which ISO/RTO metrics should apply
to non-ISOs/RTOs, and tailored these metrics to the non-ISO/RTO context. Commission
Staff met with representatives from various stakeholder groups and solicited comments
prior to issuing the metrics for public comment. Commission Staff then provided an
opportunity for public comment and, as further discussed below, Commission Staff has
taken these comments into account when crafting a final list of metrics. Thus,
Commission Staff concludes that the process was sufficiently interactive and transparent.
Moreover, Commission Staff concludes that any benefits to be gained from restarting the
process would not justify the attendant delay in using the draft metrics to gather
performance data. Therefore, just as similar procedural criticisms were considered in the
ISO/RTO metrics report, we also dismiss them here.
B.
Metrics Issues
As noted when the draft metrics were issued for public comment, the list of
metrics for regions outside of ISOs and RTOs was based on the list of metrics adopted in
Docket No. AD10-5-000 and was tailored to markets in these regions. 14 Based on the
comments discussed below and certain adjustments by Commission Staff, 39
performance metrics have been selected for participating utilities in regions outside of
ISOs and RTOs. As noted above, these metrics are listed in the Appendix.
1.
General Issues
a.
Comments
Several commenters express general support for the proposed metrics for regions
outside of ISOs and RTOs. EPSA explains that it supports the proposed metrics and
expects that the metrics will address the factors necessary to evaluate the performance of
non-ISO/RTO markets. EPSA states that the proposed metrics appear to appropriately
reflect the unique differences in the markets that exist outside of an ISO or RTO. EPSA
states that the development of performance metrics for non-ISO/RTO markets will assist
the Commission by providing a solid basis for comparing markets within an ISO and
RTO and those outside of such regions. 15
14
See Commission Staff Request Comments on Performance Metrics for Regions
Outside of RTOs and ISOs, Non-ISO/RTO Performance Metrics, Docket No. AD12-8000, at 2 (Feb. 23, 2012).
15
EPSA Comments at 2-3.
7
Docket No. AD12-8-000
Similarly, EEI states that the metrics are sufficient to provide meaningful data
without being overly burdensome on members that choose to respond. 16 EEI cautions,
however, that use of the data should be limited to the purposes contemplated in the
notice. EEI states that given the differences in the entities that voluntarily choose to
respond, it may be difficult to draw comparisons among them. Moreover, EEI states that
data reported in response to the metrics should not be used as record evidence in any
contested proceeding or serve as a basis for any enforcement action against an entity
voluntarily providing data in response to these metrics. 17
A number of commenters claim that there will be gaps in the information available
without the participation of non-jurisdictional entities. NIPPC explains that nonjurisdictional transmission providers play a significant role in the “Hybrid West market”
(the area of the Western Interconnection outside of the organized markets in Alberta and
California) and, as a result, the Commission will only have limited insight into market
performance in this region without the participation of non-jurisdictional transmission
providers. Likewise, EEI notes that several stand-alone utilities coordinate their
operations with non-jurisdictional entities to maintain reliability, and, since these entities
will not be reporting data, there will be significant gaps for some of the metrics. 18
b.
Response
Commission Staff agrees with commenters that the proposed performance metrics
for non-ISO/RTO regions should provide a suitable basis for comparing the performance
of ISOs, RTOs and utilities in regions outside ISO/RTO markets. Commission Staff will
monitor implementation and performance under both the ISO/RTO metrics and the nonISO/RTO metrics, and, if necessary, make modifications to improve the comparability of
metrics for these two sets of entities.
While Commission Staff recognizes that an analysis of performance metrics in
non-ISO/RTO regions would be enhanced by the inclusion of information from nonjurisdictional entities, as NIPPC and EEI note, the performance metrics are being
developed and analyzed in a voluntary and collaborative process. Commission Staff
encourages and welcomes information that these entities are willing to provide
voluntarily.
16
Id. at 3.
17
Id. at 3, 4-5.
18
Id. at 4.
8
Docket No. AD12-8-000
2.
Additional Metrics and Information
a.
Comments
A number of commenters recommend that the Commission adopt additional
metrics. For instance, EPSA states that the metrics should include a metric measuring
and monitoring the transfer capability of a utility or transmission system, as the ability to
import or export megawatts (MW) into or out of a utility’s transmission system is a solid
indicator of that utility’s or transmission system’s performance. EPSA explains that a
metric monitoring transfer capability would assist both the Commission and the public in
determining which balancing authority areas have available power to transfer, which, in
turn, could provide competitive suppliers with greater access to wholesale customers and
enhance competition. 19
NIPPC argues that the Commission should require transmission providers to report
the extent of their participation in initiatives facilitating virtual consolidation of
operations among transmission providers, such as the Joint Initiative project. NIPPC
explains that the Joint Initiative project refers to an effort to promote market efficiency
through greater cooperation among the Northern Tier Transmission Group, Columbia
Grid, and WestConnect. 20
NIPPC also states that the Commission should include a metric concerning
whether the transmission provider is participating in the Area Control Error Diversity
Interchange Program, which involves the pooling of individual Area Control Errors 21 to
take advantage of control error diversity. 22 NIPPC further maintains that the
Commission should require transmission providers to indicate whether they are
participating in the Joint Initiative Dynamic Scheduling System, which allows dynamic
19
Id. at 6.
20
NIPPC Comments at 7.
21
Area Control Error refers to the instantaneous difference between a balancing
authority’s net actual and scheduled interchange, taking into account the effects of
Frequency Bias and correction for meter error. See North American Electric Reliability
Council (NERC), Glossary of Terms Used in NERC Reliability Standards (NERC
Glossary), available at http://www.nerc.com/files/Glossary_of_Terms_2012May25.pdf.
It is a measure of the power balance on the interties between balancing authority areas.
22
NIPPC Comments at 7.
9
Docket No. AD12-8-000
schedules to be implemented quickly while requiring minimal changes to existing
processes and procedures. 23
NIPPC argues that, as parts of the western United States move to intra-hour
markets and/or energy imbalance markets, the Commission would benefit from
information concerning which transmission providers are actively participating in those
markets. Similarly, noting that the Commission has observed that intra-hour scheduling
can reduce the cost of providing reserves to integrate variable energy resources, 24 NIPPC
argues that the Commission should obtain information from transmission providers on
whether they allow intra-hour scheduling. Accordingly, NIPPC urges the Commission to
collect metrics describing: (1) whether the transmission provider allows intra-hourly
scheduling and facilitates customer participation in an intra-hour energy market; (2) what
products are traded in that intra-hour market (e.g., scheduling increments); and (3) the
total number of intra-hour scheduling requests; and (4) for each of the products identified,
the total number of transactions and the total megawatt hour (MWh) quantity of
transactions. 25 Additionally, NIPPC notes that transmission providers in the Hybrid West
market 26 are seeking to impose integration charges on variable energy resource
generators and argues that the Commission should require transmission providers who
impose such charges to report the specific charge and the specific service associated with
the charge. 27
NIPPC also argues that the Commission should obtain information on whether the
transmission provider has adopted the Joint Initiative standards – standardized business
practices and procedures to facilitate the intra-hour schedule developed by the Joint
Initiative project. 28 Further, NIPPC claims that the Commission should obtain
information from transmission providers on whether they participate in the ITAP/webExchange and, if so, the number and nature of transactions using the tool. 29
23
Id at 8.
24
Id. (citing Integration of Variable Energy Resources, Notice of Proposed
Rulemaking, 133 FERC ¶ 61,149 (2011) (VERS NOPR)).
25
NIPPC Comments at 9-10.
26
NIPPC defines the “Hybrid West” [market] as the area of the Western
Interconnection outside the organized markets in Alberta and California. Id. at 2.
27
Id. at 10.
28
Id.
29
NIPPC explains that the Joint Initiative project developed I-TAP, which reduces
the number of keystrokes necessary to complete a transaction and thereby reduces the
10
Docket No. AD12-8-000
EPSA expresses concern that there are insufficient metrics for evaluating a
utility’s cost to serve native load, which is important for comparing the performance of
utilities within an ISO or RTO with those outside. 30 EPSA argues that the Commission
should evaluate price metrics for entities in regions outside of ISOs and RTOs. EPSA
asserts that establishing a price metric for these regions is consistent with the metrics
established to evaluate performance in an ISO or RTO. EPSA acknowledges the
difficulties in comparing prices between a utility in a region outside of an RTO or ISO
and one that participates in such a market. Nevertheless, EPSA maintains that it is
important to establish some method to compare prices if the metrics are to provide a
realistic method to compare ISOs and RTOs with regions outside of such markets. 31
EEI points out that it is the state’s responsibility to monitor and evaluate a utility’s
cost of service to native load. EEI argues that this is outside the Commission’s
jurisdiction and could further complicate state efforts to ensure that native load receives
reliable, cost-effective service. 32
b.
Response
With respect to EPSA’s interest in transfer capability metrics, we note that transfer
capability is measured by Available Transfer Capacity (ATC), 33 which is a function of
system topology and the transmission capacity reserved by firm transmission customers
to meet their load requirements. Since many aspects of system topology are beyond the
control of utilities, such as system capabilities on neighboring systems, and they must
reserve firm capacity to meet load requirements, Commission Staff does not consider
ATC to be a good indication of a utility’s performance.
potential for errors. Id. at 8-9. I-TAP will not be a centralized market, but instead is
expected to operate as a highly-efficient bilateral market that will enable energy and
capacity products to be traded in as short a term as intra-hour. All participation will be
voluntary, with completed transactions being bilateral deals between the individual
parties.
30
EPSA Comments at 9.
31
Id. at 8 n.6.
32
EEI Reply Comments at 3-4.
33
ATC is a measure of the flow capacity remaining on a flowgate for further
commercial activity over and above already committed uses. See NERC Glossary.
11
Docket No. AD12-8-000
While Commission Staff does not think that ATC would be an appropriate
measure of a utility’s performance, we share EPSA’s concern about the under-utilization
of capacity. It appears that EPSA is concerned that utilities are reserving capacity that
they do not utilize, thereby leaving available capacity unused. This can harm competition
and reduce the efficiency of the electric system by limiting the ability to deliver low cost
energy where it is needed. Such a practice could be especially problematic where utilities
do not schedule transmission until just prior to the operating hour. For these reasons,
Commission Staff recommends that participating utilities provide a narrative discussion
addressing interconnection-wide and seams issues consistent with the Commission Staff
report addressing ISO and RTO markets. 34
As NIPPC points out, initiatives such as the Joint Initiative project involving the
Northern Tier Transmission Group, Columbia Grid and WestConnect can be the basis for
improving the efficiency of the regional transmission system through joint planning and
transmission access programs. For this reason, Commission Staff recommends that
transmission providers include narrative discussions of their participation in joint regional
initiatives and progress made on improving the efficiency of regional transmission
systems in their reports on interconnection-wide and seams-wide issues. Also, regarding
NIPPC’s interest in tracking progress toward the development of energy imbalance
markets, in particular, Commission Staff agrees that discussions of a transmission
provider’s participation in such markets and the progress made in the development of
these markets would be useful. Imbalance markets can reduce the cost of supply and
foster competition among suppliers. Therefore, utility participation in these programs
can ultimately result in reducing the cost of power. Consequently, Commission Staff
recommends that participating utilities include information on the development of energy
imbalance markets in the narrative discussions in their performance reports. However,
Commission Staff does not recommend adding metrics measuring the number of
transactions or MW traded at this time. 35 In light of the early stage of development of
these markets and the impact of factors beyond the control of utilities in the development
of these markets, it is premature to designate this information as a measure of the
performance of utilities.
Commission Staff agrees with NIPPC that information on utility participation in
programs to facilitate the integration of variable energy resources and to mitigate any
issues and uncertainty associated with scheduling variable energy resources would
provide information relevant to the performance of utilities. Such information would
allow for an assessment of how utilities are ensuring the efficiency of their operations
34
Staff Report at 15.
35
We note that this information is included in the Electric Quarterly Reports that
must be filed with the Commission. See 18 C.F.R. § 35.10b (2012).
12
Docket No. AD12-8-000
while integrating renewable resources. While we do not think a standard metric is
necessary at this time, Commission Staff nevertheless recommends that utilities include
in their reports narrative discussions of their progress in implementing such programs,
including area control error diversity interchange, dynamic scheduling systems, intrahour transmission scheduling 36 and intra-hour transaction accelerator platforms.
Regarding NIPPC’s request for information on transmission grid integration charges for
variable energy resources, the Commission recently addressed the design of generator
regulation service charges in its final rule in Docket No. RM10-11-000. 37 Any such
charges would be subject to Commission review under section 205 of the Federal Power
Act 38 and, as a result, subject to public review.
With respect to EPSA’s interest in price metrics for entities in regions outside of
ISOs and RTOs, Commission Staff agrees with EPSA that it is difficult to compare prices
outside of ISO and RTO markets with prices in these markets. ISO and RTO market
prices are locational marginal prices (LMPs) that are based on resource offers and load
bids. LMP pricing does not exist outside these markets. This lack of comparability was
the primary reason that Commission Staff did not propose a price metric for utilities
outside ISO and RTO markets. Commission Staff also considered utility cost-of-service
rates that include retail costs to be unsuitable price metrics. These rates include
distribution and other functions that are not encompassed by the wholesale service
provided by ISOs and RTOs and, as noted by EEI, utility cost-of-service rates are outside
the Commission’s jurisdiction.
Notwithstanding the difficulties inherent in comparing wholesale prices between
ISO/RTO markets and regions outside ISO/RTO markets, wholesale prices are pertinent
to the performance of utilities in pricing their products competitively. Accordingly,
Commission Staff proposes that utilities provide price metrics on their wholesale power
sales derived from the transaction information and price data utilities report on wholesale
power sales in the Electric Quarterly Report. 39 To ensure comparability with the load36
In the final rule in Integration of Variable Energy Resources, the Commission
amended the pro forma OATT to provide all transmission customers the option of using
more frequent transmission scheduling intervals within each operating hour, at 15-minute
intervals. See Integration of Variable Energy Resources, Order No. 764, 139 FERC ¶
61,246, at P 91 (2012).
37
Id. P 271.
38
16 U.S.C. § 824e (2006).
39
Revised Public Utility Filing Requirements, Order No. 2001, 67 Fed. Reg.
31,043 (May 8, 2002), FERC Stats. & Regs. ¶ 31,127, reh’g denied, Order No. 2001-A,
100 FERC ¶ 61,074, reh’g denied, Order No. 2001-B, 100 FERC ¶ 61,342, order
13
Docket No. AD12-8-000
weighted data provided by ISOs and RTOs, Commission Staff proposes that participating
utilities submit a single volume-weighted average annual price for energy and for
capacity.
Commission Staff recognizes that in the regions outside of ISO/RTO markets, as
in the ISO/RTO markets, some of the wholesale prices that are reported in the Electronic
Quarterly Reports include cost-based transactions that reflect cost allocation decisions of
regulators as well as market-based transactions. Also, wholesale power prices reflect fuel
prices that are a function of global and nationwide price trends that are beyond the
control of utilities. To address these matters, the metric could be developed to include
market-based transactions only and to hold fuel prices constant in a fuel-adjusted price
metric. 40
Commission Staff further recognizes that utilities provide a series of peak, offpeak and year-round wholesale power products, and therefore utilities will need to
volume-weight each of these products into a single average annual price for energy and
for capacity, in addition to reporting peak and off-peak prices. Commission Staff also
requests comments on whether seasonal prices provide useful information on utility
performance.
In light of the fact that Commission Staff is now proposing a price metric for the
first time, and therefore there has not been an opportunity for a full and complete
discussion among stakeholders of the pros and cons of various price metric options,
Commission Staff is not including a price metric on the list of recommended metrics in
Appendix A. Rather, Commission Staff recommends that participating utilities discuss in
their 2012 reports their perspectives on a wholesale price metric. Based on these
perspectives and further discussions with interested stakeholders, Commission Staff
intends to recommend a price metric that participating utilities will submit in their next
report following the report that is requested in this Commission Staff Report.
directing filing, Order No. 2001-C, 101 FERC ¶ 61,314 (2002), order directing filing,
Order No. 2001-D, 102 FERC ¶ 61,334, order refining filing requirements, Order No.
2001-E, 105 FERC ¶ 61,352 (2003), order on clarification, Order No. 2001-F, 106 FERC
¶ 61,060 (2004), order revising filing requirements, Order No. 2001-G, 72 Fed. Reg.
56,735 (Oct. 4, 2007), 120 FERC ¶ 61,270, order on reh’g and clarification, Order No.
2001-H, 73 Fed. Reg. 1,876 (Jan. 10, 2008), 121 FERC ¶ 61,289 (2007), order revising
filing requirements, Order No. 2001-I, 73 Fed. Reg. 65,526 (Nov. 4, 2008), 125 FERC ¶
61,103 (2008).
40
The RTO price metrics include a fuel-adjusted LMP price metric.
14
Docket No. AD12-8-000
3.
Discussion of Individual Metrics
The two major categories of performance metrics are reliability and systems
operations measures. The reliability metrics were chosen to measure the reliability of
day-to-day operations using metrics such as compliance with national and regional
reliability standards, the real-time balance of supply and demand, forecasting and Special
Protection Schemes, and to measure long-term reliability using metrics such as long-term
transmission and resource planning. The systems operations measures were chosen to
measure the operating performance of utilities in non-ISO/RTO regions using metrics
such as system resource and transmission availability and system lambda.
a.
National and Regional Reliability Standards
Compliance Metrics
i.
Performance Metric
This metric measures the number of violations of national and regional reliability
standards, provides information on how these violations were reported, and indicates the
severity of the violations. 41 The metric also details unserved energy (or load shedding)
caused by violations and requires a utility to provide additional details on the number of
events, the duration of the events, whether the events occurred during on/off peak hours,
and information on the equipment types affected and the kilovolts of lines affected.
Consistent with the 2010 ISO/RTO Metrics Report, the text of the metric has been
revised to reflect the fact that this metric is a quantification of all NERC and Regional
Reliability Organization standard violations that have been identified during an audit or
as a result of a self-report and have been published as part of that process. 42
Additionally, the text of the metric has been revised to clarify that utilities located in
regions outside of ISOs and RTOs should limit reporting to the same eight functional
areas used by the ISOs and RTOs. 43
41
A full listing of the reliability standards is provided at
http://www.nerc.com/page.php?cid=2|20.
42
2011 ISO/RTO Metrics Report, Docket No. AD10-5-00, at 12 (August 31,
2011).
43
The eight functional areas are as follows: 1) Balancing Authority; 2)
Interchange Authority; 3) Planning Authority; 4) Reliability Coordinator; 5) Resource
Planner; 6) Transmission Operator; 7) Transmission Planner; and 8) Transmission
Service Provider.
15
Docket No. AD12-8-000
ii.
Comments
Multiple TDUs assert that the Commission and NERC would benefit from the
collection of data regarding events when Footnote b 44 is invoked and utilities interrupt
non-consequential Firm Demand. Multiple TDUs state that there should not be any
dispute about the utility of this information and note that the Commission has directed
NERC to collect information regarding the specific circumstances and frequency with
which Firm Demand is planned to be interrupted as part of the Footnote b remand
process. 45 Multiple TDUs explain that since it is not a violation of any reliability
standard to interrupt non-consequential Firm Demand if Footnote b is applicable,
National or Regional Reliability Standards Compliance metrics will not encompass
events where Footnote b is involved. Multiple TDUs believe that the collection of the
following categories of data would facilitate further discussion at the Commission and
NERC: (1) the number of incidents in which the utility relies on Footnote b in order to
interrupt non-consequential Firm Demand; (2) information concerning the severity of
these incidents and whether there are systemic problems with the transmission system
and transmission plan;46 and (3) information concerning whether interrupted wholesale
44
Footnote b refers to a petition filed by the North American Electric Reliability
Corporation (NERC) seeking approval of Table 1, Footnote b of four Reliability
Standards: Transmission Planning: TPL-001-1– System Performance Under Normal
(No Contingency) Conditions (Category A), TPL-002-1b – System Performance
Following Loss of a Single Bulk Electric System Element (Category B), TPL-003-1a –
System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C), and TPL-004-1– System Performance Following Extreme Events Resulting
in the Loss of Two or More Bulk Electric System Elements (Category D). While
Footnote b appears in all four of the above referenced TPL Reliability Standards, its
relevance and practical applicability is limited to TPL-002-0a. See Transmission
Planning Reliability Standards, Order No. 762, 139 FERC ¶ 61,060, at P 1 & n.2 (2012).
Footnote b states:
Planned or controlled interruption of electric supply to radial customers or some
local Network customers, connected to or supplied by the Faulted element or by
the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next
contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.
Id. P 3.
45
Multiple TDUs Comments at 9 (citing Order No. 762, 139 FERC ¶ 61,060 at P
20).
16
Docket No. AD12-8-000
transmission customers of the reporting transmission provider have notice and
understanding before the interruption. Multiple TDUs recognize that Footnote b is in
flux, and, as a result, urge the Commission to revisit the metrics associated with Footnote
b after Footnote b is revised.47
In reply to Multiple TDUs, EEI argues that situations in which Footnote b is
invoked are clearly contemplated under section A.7 of the Reliability metrics proposed in
the Commission notice. 48
NIPPC argues that the Commission should consider expanding the reliability
standards metrics to include the number of dispatch orders issued to generators to curtail
output and the specific reasons for each of those dispatch orders, as a dispatch order made
to a generator to avoid or mitigate a reliability violation will have the same impact on a
market as a reliability violation. NIPPC also argues that the metrics should include the
number of, and justification for, schedule curtailments (or e-tag curtailments). NIPPC
further maintains that the metrics should compare the percentage of the dispatch orders or
schedule curtailments issued to independent power producers to the percentage of
independently owned generation capacity interconnected to the transmission provider’s
system. 49
iii.
Response
While Reliability metric A.7 captures situations where Footnote b is invoked,
Commission Staff concludes that for purposes of clarity it would be beneficial to have a
separate metric to address the planned Firm Demand interruptions that planners use to
meet the system performance requirements of TPL-002-2b, Table 1 for Category B single
contingency events (i.e., Footnote b interruptions as discussed in Order No. 762), and that
the metric should track the number, severity and duration of these incidents. This
information is a good performance measure because it could expose an area of weakness
in the Bulk Electric System that may need to be addressed with a capital project or an
appropriate operating procedure. Commission Staff recommends that in the narrative that
accompanies the metrics report, participating utilities discuss the actions taken to address
the interruptions and the notice utilities provide customers before interruptions are made.
46
We note that this request is discussed in our response, infra, at pp. 19-20.
47
Multiple TDUs Comments at 10-11.
48
EEI Reply Comments at 4.
49
NIPPC Comments at 4.
17
Docket No. AD12-8-000
Responding to NIPPC, the reliability standards metrics are limited to providing
information on reliability violations. Actions taken by transmission providers to curtail
the dispatch of generators or adjust transmission schedules (or e-tags) are relevant to the
dispatch reliability metrics, discussed below. As discussed in that section, Commission
Staff is recommending that participating utilities include narratives on all actions they
take to manage dispatch reliability. Commission Staff is not recommending that this
information be incorporated into metrics because not all participating utilities take these
actions and there are no standardized measures for these activities. With respect to
NIPPC’s request that a metric be developed to measure transmission schedule
adjustments, or e-tag revisions, we note that these actions are the result of transmission
loading reliefs (TLR) or Unscheduled Flow Relief events that are being reported in the
Dispatch Reliability measure below, and are already covered by the metrics. For this
reason, Commission Staff does not recommend adding this metric.
b.
Dispatch Reliability
i.
Performance Metrics
Dispatch reliability is measured by three metrics. The proposed metrics listed in
the notice retained two of the metrics used to measure dispatch reliability in ISOs and
RTOs: (1) Balancing Authority Area Control Error Limit or Control Performance
Standard 1 and Control Performance Standard 2; and (2) Energy Management System
Availability. The proposed metric relating to TLR or Unscheduled Flow Relief Events
would measure the number of events – rather than the hours as is reported in the
performance metrics for ISOs and RTOs – of TLRs (of severity level 3 or higher) or
unscheduled flows called by the incumbent transmission provider. Utilities that are part
of the Western Electricity Coordinating Council (WECC) will report events under the
WECC Unscheduled Flow Mitigation Procedure that are equivalent to the NERC TLR
Level 3.
ii.
Comments
EPSA contends that, in order to properly identify problem areas, the Commission
should require each transmission provider to identify the length and magnitude of each
TLR event. EPSA states that, at a minimum, each transmission owner should provide the
following information: (1) how long each constrained element is subject to a continuous
Level 3 or higher TLR, in hours; (2) the number of MW of network transmission service
curtailed for each continuous TLR event, and for all continuous TLR events in total; (3)
the number of MW of firm point-to-point transmission service curtailed for each
continuous TLR event, and in aggregate; and (4) the number of MW of non-firm
transmission service curtailed per continuous TLR event, and in aggregate.50 EPSA
50
EPSA Comments at 3-4.
18
Docket No. AD12-8-000
further states that monitoring and tracking TLR events on a system that are categorized at
level 1 or 2 can provide additional insights into system dynamics, as those events can be
prevented by nodal market designs that dispatch around binding constraints using
congestion prices. Additionally, EPSA states that all TLR events at level 5 or higher
should be tracked and reported separately from all other TLR events, as TLR events at
this level indicate a severely constrained system.
EPSA recommends that the metrics include a metric for reporting all congestion
management events – not only those categorized as a TLR – because some areas rely on a
variety of other congestion management techniques. EPSA further recommends
including an evaluation of the number and severity level of all congestion management
events of a utility or transmission system with the changes discussed above. 51
iii.
Response
Commission Staff agrees with EPSA that the metric concerning TLR should
measure the duration of such events. Accordingly, Commission Staff recommends that
the TLR metric be revised to measure the hours of TLR called by the incumbent
transmission provider. Commission Staff notes that this revision will result in a metric
that is consistent with the metrics for ISO and RTO markets.
Commission Staff does not consider information on severity level 1 and 2 events
to be measures of utility reliability performance. Such events, by definition, only impact
local area operations and, as a result, will not impact system reliability. For this reason,
TLR events of level 3 and above are systemic events and are the appropriate basis for a
performance metric for system reliability. For TLR events of severity level 3 and above,
Commission Staff agrees with EPSA that the TLR/Unscheduled Flow Relief metric
should be supplemented with information on TLR (or Unscheduled Flow Relief) events
for each severity level, energy curtailment data on the number of MW curtailed, and
duration of curtailment information. Such information, along with a discussion by the
participating utility of the impact of curtailments on customers and the various resource
types, will allow for a better informed evaluation of performance. 52 For this reason we
51
Id. at 5.
52
We note that, in Order No. 890, the Commission concluded that requiring
transmission providers to post additional information on curtailments was necessary to
provide transparency and enable customers to assess whether they have been treated
without undue discrimination. See Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 1626, 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 (2009), order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009). For
19
Docket No. AD12-8-000
recommend that this information be included in the narrative discussions that accompany
the (TLR/Unscheduled Flow Relief) metric, to the extent the information is available.
With respect to EPSA’s request for metrics on all congestion management
activities, such as Local Area Protocols, Commission Staff recommends that participating
utilities provide narratives on the use of Local Area Protocols, out-of-merit dispatches
and other techniques to resolve system dispatch reliability problems. Such information
will provide a context for the role played by TLRs or Unscheduled Flow Reliefs, thereby
providing the basis for a more comprehensive assessment of constraint management by
the participating utility. Since not all participating utilities use these techniques and the
definitions of these techniques may differ among utilities, Commission Staff does not
consider this information to be appropriate for standardized metrics.
c.
Load Forecasting Accuracy
Actual peak load as a percentage variance from forecasted peak load, as reported
in a transmission provider’s OASIS, measures the effectiveness of the load forecasting
function of utilities in non-ISO/RTO regions. Since load forecasting provides the basis
for resource commitment, this metric impacts the incurrence of resource costs. The more
accurate a 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 lead-time resources or under-utilization of available
resources. This metric measures the percentage difference between actual peak load and
forecasted peak load. No comments were submitted on this metric.
d.
Wind Forecasting Accuracy
i.
Performance Metric
This metric measures the percentage accuracy of actual wind availability
compared to forecasted wind availability. Improving the accuracy of the wind forecast
will facilitate the timely commitment and dispatch of sufficient supplemental resources.
ii.
Comments
NIPPC maintains that the Commission should clarify whether this metric applies
to the wind generation assets controlled by the merchant function of the transmission
provider or to the independently owned and operated wind generation interconnection to
TLR events of severity level 3 and above, Commission Staff recommends including a
narrative explanation of why transactions could not be continued or completed, similar to
what is required by Order No. 890. Id. P 1627.
20
Docket No. AD12-8-000
the transmission provider’s system. NIPPC argues that the metric should not extend to
generators not owned or controlled by the merchant function of the transmission provider
in light of the market-sensitive nature of a generator’s wind forecasting accuracy and
scheduling practices. 53 NIPPC also urges the Commission to consider expanding this
metric to require a transmission provider to report whether it has implemented a
centralized wind forecast system for use in its operations and, if so, to collect additional
metrics on the accuracy of that centralized forecast. 54
NIPPC contends that a single metric comparing actual wind output to forecast
output over the reporting period is not a useful metric, as inaccuracies in the forecast may
cancel out over a long reporting period. NIPPC argues that a more relevant measure of
accuracy would be the number of hours during the reporting period that the forecast is
accurate (where the forecast is within five percent of actual output). NIPPC also suggests
that the following additional metrics would be useful: (1) the MW of wind/solar capacity
subject to the forecast; (2) granularity of the forecast (monthly, weekly, daily, hourly,
sub-hourly); (3) whether the forecast is integrated into the transmission provider’s
operations; (4) whether the transmission provider shares the forecast with market
participants (or generation owners); and (5) an equivalent metric for forecasts associated
with solar energy and hydroelectric energy.55
iii.
Response
The wind accuracy metric was intended to apply to all wind resources – owned
and non-owned – on the transmission providers’ systems. Commission Staff does not
recommend excluding wind generators not owned or controlled by transmission providers
from the wind accuracy metric. To be an effective tool to ensure system reliability, this
metric must measure the accuracy of forecasts that account for all wind resources in a
utility’s footprint. This requirement is increasingly important as wind resources become
a more significant portion of total resource output. When wind generators – including
those not owned or controlled by the utility – provide wind availability forecasts, they are
performing a reliability function that has implications for system reliability management
and planning. Accordingly, Commission Staff considers this information to be an
important element in an assessment of a utility’s reliability performance. We encourage
participating utilities to work with wind generators not owned or controlled by the utility
to ensure that the data gathered and reported protects market-sensitive information from
53
NIPPC Comments at 5.
54
Id.
55
Id. at 5-6.
21
Docket No. AD12-8-000
being reported in public reports or released to utility subsidiaries that compete with these
wind generators.
Commission Staff agrees with NIPPC that to the extent that centralized forecasting
can minimize integration costs, this information is an indication of utility performance.
Therefore, Commission Staff recommends that participating utilities discuss their
forecasting process in their reports.
With respect to NIPPC’s concern that inaccuracies in the forecast may cancel out,
Commission Staff notes that the wind accuracy forecast will be based on the mean
absolute error of the forecast compared to actual wind availability. Therefore, all errors –
positive and negative – will be measured and will not cancel out. Since the proposed
metric will measure the magnitude of forecast inaccuracies, Commission Staff considers
the proposed metric to be superior to the alternative proposed by NIPPC that only
indicates the number of hours in which a forecast is outside a five percent threshold.
Further responding to NIPPC, Commission Staff notes that forecast accuracy will be
based on a comparison of the day-ahead forecast to actual availability. Commission Staff
also notes that the capacity of wind and solar subject to the forecast, which NIPPC
requests be an additional performance metric, is included in the Clean Energy metric
discussed below.
Commission Staff is not recommending the inclusion of a metric measuring the
accuracy of forecasts for other variable energy resources because many utilities do not
perform these forecasts or they are not performed according to a standardized process.
Nevertheless, Commission Staff considers it appropriate that participating utilities
provide narrative descriptions of their solar and hydro forecasts, to the extent these
resources are significant sources of energy, to allow for a more complete assessment of
forecasting performance.
e.
Unscheduled Flows Metric
Unscheduled flows are defined as the difference between net actual interchange
(actual power flow measured in real time) and net scheduled interchange. The two
components of unscheduled flows are inadvertent energy, defined to be the difference
between actual and scheduled interchange for all interties, and parallel flow (or loop
flow), defined to be the actual power flow on a contract path within an interconnection
from one Balancing Authority Area to a second Balancing Authority Area through
“parallel” transmission lines through a third Balancing Authority Area. Parallel flows are
a function of the interconnection’s operating configuration, line resistance, and physics.
Unscheduled flows provide information relevant to operation planning because
curtailments may occur when unscheduled flows exceed system operating limits. This
metric is measured by the difference between net actual interchange (actual measured
power flow in real time) and the net scheduled interchange in MWh as reported in a
22
Docket No. AD12-8-000
utility’s FERC Form No. 714, “Annual Electric Balancing Authority Area and Planning
Area Report.” No comments were received on this metric.
f.
Transmission Outage Coordination
i.
Performance Metric
The transmission outage coordination metric measures the percentage of outages,
planned and unplanned, that occur with less than two days notice. 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. 56 Effective
transmission outage coordination by utilities in non-ISO/RTO regions ensures that
outages do not threaten system reliability and that additional and potentially more
expensive resources do not need to be committed.
ii.
Comments
ESPA recommends that the performance metrics track a utility’s transmission
outage performance. EPSA states that the information posted on OASIS is valuable
information and requests that the Commission include information regarding any
transmission outages known ahead of time, including the time and date of the planned
outage and the planned duration of the outage. 57 EPSA maintains that providing this
information would allow market participants to evaluate the information concerning the
proposed outage and make other arrangements, if necessary, or otherwise take proactive
steps to reduce the impact of any such planned outage. EPSA states that outage
performance information would also give the Commission and other observers the
opportunity to evaluate how well the utility or transmission owner can schedule outages
and execute that schedule. 58
iii.
Response
Commission Staff agrees with EPSA that the transmission outage metrics should
include information to measure the utilities’ ability to plan for outages and successfully
execute their outage plan. As stated in the Commission Staff Report on ISO/RTO
Performance Metrics, effective transmission outage coordination is defined as early
56
The proposed metrics will measure outages for major transmission facilities,
which are defined for purposes of the metrics as 200kV and higher.
57
EPSA Comments at 7-8.
58
Id. at 8.
23
Docket No. AD12-8-000
notification of planned outages of five days or longer – i.e., notification at least one
month prior to the outage commencement date – and timely review of outage impacts. 59
Also, effective transmission outage coordination is measured by the percentage of
planned outages that are canceled due to conflicting planned outages as well as forced
(unscheduled) outages that could cause reliability issues and additional congestion costs.
Commission Staff recommends adding these metrics for outages on major transmission
lines of 200kV and higher, to be consistent with the metrics for ISOs and RTOs. 60
g.
Long-Term Reliability Planning – Transmission
i.
Performance Metric
The proposed metric tracks the dollar amount of transmission facilities approved
to be constructed for reliability purposes, the percentage of approved construction
completed, the number of requests for and completed reliability studies, and a narrative
detailing a utility’s economic study process. This information measures the ability of
each utility’s expansion planning process to identify reliability and economic needs in
advance, which is essential to ensuring that market participants have sufficient time to
develop either transmission or resource solutions to system reliability and economic
requirements. The metric also includes a narrative discussion of the transmission
planning stakeholder process.
ii.
Comments
Multiple TDUs state that a metric related to planning and completion of economic
transmission is needed for multiple reasons. First, vertically-integrated transmission
59
Staff Report at 25.
60
See Staff Report at Appendix B, Peformance Metric F.1 (Oct. 21, 2010)
(Percentage of > 200kV planned outages of 5 days or more that are submitted to
ISO/RTO at least 1 month prior to the outage commencement date). We note that in
Revisions to Electric Reliability Organization Definition of Bulk Electric System and
Rules of Procedure, Notice of Proposed Rulemaking, 77 Fed. Reg. 39,846, 139 FERC ¶
61,247 (2012), the Commission proposed to approve a modification to the currentlyeffective definition of “bulk electric” system” that would establish a bright-line threshold
that includes all facilities at or above 100 kV. Commission Staff still considers it
reasonable to require a 200 kV minimum for reporting information related to outages for
performance metrics purposes, particularly since this 200 kV minimum is consistent with
the threshold ISOs/RTOs used in their prior metric reports. Nevertheless, Commission
Staff will monitor responses under this metric and continue to evaluate whether this is the
appropriate threshold.
24
Docket No. AD12-8-000
providers have inherent incentives to discriminate and underperform when performing
this function. Multiple TDUs state that the Commission has recognized as much and that
such a metric would help measure the efficacy of the remedies that the Commission
adopted in Order No. 890 to address this concern. 61 Second, the economic costs of
transmission constraints are not transparent in areas without centralized markets, like
those found in ISOs and RTOs, with congestion pricing. Third, more specificity is
needed because a vertically-integrated transmission owner reporting on transmission
construction and identifying shortfalls would be identifying its own unsuccessful
outcomes. 62 Multiple TDUs argue that merely requiring vertically-integrated
transmission providers to provide a narrative detailing their economic studies process, as
is proposed, will elicit little more than a repetition of the planning process descriptions
that were filed in compliance with Order No. 890.
For these reasons, Multiple TDUs argue that the transmission planning and
construction metric should be expanded to include the dollar amount of facilities
constructed for purposes whose predominant purpose was not reliability, broken down
between (a) economic; (b) public policy; (c) facilities to support the planned generation
resources of the transmission provider or its affiliates; (d) transmission or interconnection
requests made by the transmission provider or its affiliates; and (e) in response to
requests from others. Multiple TDUs state that the metrics should also include the
number of transmission construction projects that were added to the transmission
provider construction plans between the issuance of Order No. 890 and the submission of
the report, broken down into categories (a) through (e) and into their current status (i.e.,
completed, incomplete and on schedule, incomplete and behind schedule, and removed
from plan).
EEI argues that the Multiple TDUs’ request is unwarranted. EEI maintains that,
due to the low incidence of economic study requests, requiring such additional reporting
will create an added and unnecessary burden to reporting utilities. 63
Multiple TDUs also state that the metric should include a narrative assessment,
supported by quantitative information, of the transmission provider’s planning process
efficacy. 64 Similarly, EPSA argues that the performance metrics should include a metric
61
Multiple TDUs Comments at 6 (citing Order No. 890, FERC Stats. & Regs. ¶
31,241).
62
Id. at 6-7.
63
EEI Reply Comments at 4.
64
Multiple TDUs Comments at 7-8.
25
Docket No. AD12-8-000
detailing how well a utility executes its transmission development plans. EPSA explains
that a utility’s failure to follow its transmission plan can adversely impact customers and
merchant generators. Thus, EPSA maintains that a metric assessing how well a utility
executes its transmission plan would provide valuable information, including a
demonstration of how prepared a utility is to meet any future reliability needs on its
system. 65
iii.
Response
Commission Staff does not recommend adding the metrics proposed by Multiple
TDUs on non-reliability transmission and interconnection projects. The purpose of this
metric is to assess the extent to which transmission solutions are analyzed, planned, and
deployed to meet reliability requirements. Thus, additional information to examine
discrimination by utilities or to obtain information on all project spending, including
projects to meet public policy objectives, would go beyond the scope of the metric. The
congestion issues of concern to Multiple TDUs, including the impact of transmission
planning on congestion, are discussed further below in the Congestion Management
metric.
Commission Staff agrees with commenters that additional information is needed,
however, in the transmission planning metrics to provide a more comprehensive
assessment of transmission planning performance and to allow for comparisons between
ISOs and RTOs and participating utilities in regions outside of ISOs and RTOs.
Accordingly, Commission Staff recommends additional information be included in the
metrics, as follows: (1) the proposed dollar amount of facilities approved to be
constructed for reliability purposes should be revised to also include the number of
facilities, so that this metric is comparable to the relevant ISO/RTO performance metric;
(2) the proposed percentage of approved construction completed metric should be revised
to the percentage of approved construction on schedule and completed; and (3) the
proposed narrative detailing the economic studies process should be revised to a metric
that measures the percentage completion of economic projects.
Responding to EEI, Commission Staff does not find that it would be unduly
burdensome to incorporate both the number of economic study requests and the number
of economic studies accomplished into a narrative explanation of the status of planning
for economic expansions. Economic projects can reduce congestion, which, in turn, can
reduce costs to customers and decrease the likelihood that reliability issues will occur.
Therefore, this information provides an important indicator on the progress made by
utilities in improving the efficiency of their transmission systems.
65
EPSA Comments at 7.
26
Docket No. AD12-8-000
Commission Staff agrees with EPSA that the reports provided by participating
utilities should also include a discussion of the status of their transmission plans. Such
information will allow participating utilities to explain their progress in meeting planning
goals, and explain the issues that may be delaying the completion of reliability and
economic projects. Commission Staff expects that this discussion will also address the
desire of Multiple TDUs to have a narrative assessment of the efficacy of the
transmission provider’s planning process 66 and to address how utilities provide an
opportunity to consider transmission needs driven by Public Policy Requirements in their
planning process. 67
h.
Long-Term Reliability Transmission Planning – Resources
Three 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 that are needed to ensure reliability. The second metric, the planned
reserve margin, is the planned number of MW of resources available as system reserves
divided by the number of MW of peak load. The third metric is a narrative discussion of
demand response programs and how they are used in system planning. No comments
were received on this metric.
Commission Staff recommends that the proposed planned reserve margin metric
be revised to compare the actual reserve margin to the planned reserve margin. This
comparison will allow for an evaluation of utility performance in achieving the planned
reserve margin.
i.
Infrastructure Investment – Interconnection and
Transmission Process Metrics
i.
Performance Metric
These metrics track the progress that utilities have made in regions outside of ISOs
and RTOs in completing their reliability reviews – namely, feasibility, system impact and
66
We note that this narrative assessment is in keeping with the Commission’s
requirement that public utility transmission providers make available information
regarding the status of transmission upgrades identified in their transmission plans. See
Transmission Planning and Cost Allocation by Transmission Owning and Operating
Public Utilities, Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 159 & n.154
(2011)), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132 (2012).
67
Order No. 1000, FERC Stats. & Regs. ¶ 31,323 at P 203.
27
Docket No. AD12-8-000
facility studies – of interconnection and transmission service requests in a timely and
efficient manner. The metrics track the number of requests, the time required to complete
the reliability reviews and the costs of completing each of the three types of studies.
There is also a metric that measures the number of transmission access denials and
transmission service request 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.
ii.
Comments
Multiple TDUs state that the Commission should collect additional information on
the completion of transmission studies. Multiple TDUs state that while the metrics for
ISOs and RTOs require the reporting of information on studies, such measures are
omitted from the draft metrics for regions outside of ISOs and RTOs without explanation.
Multiple TDUs argue that such metrics are even more important than in the ISO and RTO
context and that it would be worth obtaining from vertically-integrated transmission
providers all of the study completion metrics that ISOs and RTOs are required to
produce. Multiple TDUs explain that the cost of collecting and providing this
information should not be inordinate and that transmission providers should already have
expense tracking mechanisms in place to estimate and bill study costs.
Multiple TDUs state that the following additional metrics would be worth
collecting from vertically-integrated transmission providers: (1) percentages of longterm transmission service requests and interconnection requests that triggered study
requirements; (2) percentages of the studies undertaken that led to the identification of
upgrade costs; (3) the average estimated upgrade cost; (4) the percent of transmission
service requests withdrawn and the percent approved; and (5) the average processing time
through each process milestone identified in the transmission provider’s Order No. 890
compliance tariff provisions, such as completion of a feasibility study, system impact
study and facilities study. Multiple TDUs claims that such information would help the
Commission identify situations in which impediments to obtaining transmission or
interconnection service warrant further investigation. 68
Multiple TDUs state that the addition of a metric concerning the number of
transmission access denials or transmission service requests denied is less meaningful
than it first appears. Multiple TDUs explain that, under the pro forma Open Access
Transmission Tariff, long-term transmission service requests cannot be legitimately
denied; instead, if there is no existing transmission capability available to accommodate
the request, the requester is supposed to be informed that meeting the request would
require additional facilities and offered the opportunity to fund studies to determine what
68
Multiple TDUs Comments at 5.
28
Docket No. AD12-8-000
upgrades are needed. Multiple TDUs state that a metric tracking how often entities
requesting service withdraw their request for service in the face of these requirements
would be worthwhile, but that the proposed metric might not elicit such information. 69
Accordingly, Multiple TDUs suggest revising the metric to require entities to report the
number of long-term transmission service requests for which ATC was initially found to
be unavailable and the disposition of each request, with each of these points broken down
between requests made by third-party transmission customers and requests made by
affiliates or divisions of the transmission provider. 70
NIPPC contends that the Commission should require transmission operators to
report information concerning the pace of large generator interconnections, including the
total number of pending interconnection requests, the number of pending requests in each
phase of the LGIA process, and the number of requests in each phase that have
experienced delays in completing that phase of the interconnection process, along with a
narrative describing the causes of those delays. 71
iii.
Response
Commission Staff agrees with Multiple TDUs that the proposed metrics should
include information on how long it takes participating utilities to complete
interconnection and transmission studies, as a measure of the efficiency of the utility’s
infrastructure development process. Accordingly, Commission Staff recommends that
the performance metrics be revised to include metrics concerning the average age of
incomplete studies and the average time to complete studies. Commission Staff
considers the time to complete all studies to be an appropriate metric to measure the
efficiency of utility interconnection and transmission study processes. It is expected that
the narrative discussions that accompany the metrics will address issues with the various
study stages, and that the discussions will address the issues of concern to Multiple
TDUs. Commission Staff does not consider that information on the percentage of
requests that trigger studies or are withdrawn will reflect utility performance. The
percentage of requests that trigger studies is a function of available transmission capacity,
not utility performance. The percentage of requests withdrawn is caused by the actions
of market participants – not utilities – and therefore does not measure utility performance.
Therefore, we are not recommending the addition of this information to the metrics
reports.
69
Id. at 8.
70
Id.
71
NIPPC Comments at 4-5.
29
Docket No. AD12-8-000
With regard to Multiple TDUs’ interest in additional metrics on transmission
service denials, Commission Staff expects that the narrative discussions provided by
participating utilities will address issues of concern to the Multiple TDUs, such as the
disposition of requests for service. Commission Staff notes, however, that this metric is
not intended to measure ATC or transmission capacity in general. Rather, the purpose of
tracking transmission service denials is to provide an additional measure of the efficiency
of utilities in processing requests for transmission service, and therefore is intended to be
evaluated in the context of the other infrastructure investment processing metrics. This
information, combined with explanations provided by the utilities in their narrative
discussion, will provide the basis for a comprehensive assessment of how utilities are
managing their infrastructure development process.
Commission Staff does not recommend adding a metric concerning the number of
pending generation interconnection requests as requested by NIPPC. By measuring the
time it takes utilities to complete their studies for interconnection and transmission
service, the proposed metric appropriately focuses on the efficiency of a utility’s
processing of service requests – irrespective of the total number of requests. Also, since
many interconnection requests in a utility’s interconnection queue may not be ready to
proceed because of commercial issues and other factors beyond the control of utilities,
the number of pending interconnection requests is not an appropriate measure of utility
performance. As has been the case in the ISO/RTO performance metrics reports,
Commission Staff expects that the narrative discussion that accompanies the utility
metrics on interconnections and transmission service will explain the status of their
request queues and reasons for delays.
j.
Special Protection Systems
Special Protection Systems 72 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 maintain power flows. These metrics measure the
performance of such Special Protection Systems based on the definition of Special
Protection Systems utilized by the reporting entity’s Regional Entity. These 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. No comments were submitted on this metric.
\
72
Special Protection Systems are also referred to as Special Protection Schemes,
Remedial Action Schemes (RAS), or System Integrity Protection Schemes (SIPS).
30
Docket No. AD12-8-000
k.
Demand Response
Entities responding to this metric will be required to provide a comprehensive
explanation of the nature of utility demand response programs implemented for load
management as well as in compliance with state requirements. There were no comments
on this metric.
l.
System Lambda
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 since fuel costs represent the largest component of wholesale energy costs. The
system lambda metric would not apply to utilities where the marginal price is typically
set by hydro units. Also, system lambda data will be based on information contained in
FERC Form No. 714. There were no comments on this metric.
m.
Congestion Management
i.
Performance Metric
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 would be required to provide a congestion analysis
consistent with Order No. 890. In Order No. 890, the Commission adopted a planning
principle requiring transmission providers to prepare studies identifying “significant and
recurring” congestion and post such studies on their OASIS. The Commission explained
that the studies should analyze and report on the following items: (1) the location and
magnitude of the congestion; (2) possible remedies for the elimination of the congestion,
in whole or in part; (3) the associated costs of congestion; and (4) the cost associated with
relieving congestion through system enhancements (or other means). 73
ii.
Comments
Multiple TDUs argue that merely requiring vertically-integrated transmission
providers to provide a narrative detailing their economic study processes, as is proposed,
will elicit little more than a repetition of the planning process descriptions that were filed
in compliance with Order No. 890.
73
Order No. 890, FERC Stats. & Regs. ¶ 31,241 at PP 529, 542.
31
Docket No. AD12-8-000
iii.
Response
Commission Staff recommends that utilities discuss the status of their transmission
plans, as explained in the Long-Term Transmission Planning Metrics discussed above.
Commission Staff expects that these discussions will address expansion plans to resolve
congestion issues on their systems. Therefore, Commission Staff expects that the
performance reports submitted by utilities will provide substantive information on
congestion management.
n.
Resource Availability
i.
Performance Metric
The proposed metric measures the percentage of time that system resources are not
available because of unplanned outages, as measured by the system forced outage rate.
No comments were submitted on the metric.
ii.
Response
Commission Staff recommends that this metric be revised to be 1 minus the
system forced outage rate. Revising the metric as recommended will measure unforced
capacity availability and, therefore, resource availability. This revision will also make
this metric comparable to the performance metric adopted for ISOs and RTOs. Resource
availability is an indication of system efficiency and cost management by utilities in
regions outside of ISOs and RTOs. Higher resource availability can result in the
commitment of fewer peak resources (or the importation of peak supplies) that potentially
have high costs, thereby resulting in reduced costs.
o.
Transmission System Availability
This metric measures interrupted load MWh as a percentage of load served. In
light of the many factors that can result in load interruptions, some of which are beyond
the control of utilities, the narrative detailing the reasons for load interruptions will be
essential in assessing performance. No comments were submitted on this metric.
p.
Fuel Diversity
This metric is defined to be the percentage mix of fuel types installed and
available (capacity fuel diversity) and produced (generation fuel diversity). Fuel
diversity provides an indication of a utility’s capability to integrate fuels with different
characteristics, such as lower costs or lower environmental impacts. No comments were
submitted on this metric.
32
Docket No. AD12-8-000
q.
Clean Energy
i.
Performance Metric
These metrics measure the use of “clean energy.” 74 The metrics track number of
MWh of clean energy, by resource type, as a percentage of total energy, and the number
of MW of clean energy, by resource type, as a percentage of total capacity.
ii.
Comments
NIPPC states that the Commission should expand the clean energy metric to
include information related to curtailments of clean energy resources, as frequent
curtailments of these resources by a transmission operator may reflect a dysfunction in
the generation market since these resources have no fuel costs. NIPPC explains that the
metric should include the number of curtailments, the duration of each curtailment, the
number of MW hours curtailed, and the justification for the curtailment. 75
iii.
Response
Commission Staff does not consider curtailments of clean energy to be a measure
of the diversity of a utility’s resource mix. Rather, curtailments of resources – or, more
accurately, schedule adjustments or manual redispatch instructions by transmission
providers – are used to maintain system reliability. We note that the diversity metrics, in
conjunction with the narratives regarding actions taken to manage dispatch reliability and
TLR (see pages 18-19 infra), will provide a basis for a comprehensive view of the issue
of clean energy.
D.
Burden Estimate
1.
Information Collection Statement
In its solicitation for comments, Commission Staff estimated the public reporting
burden for participating utilities to be approximately 140 hours per respondent for each
report.
74
Clean Energy is defined to include nuclear energy and variable energy
resources, including solar, wind, hydro, geothermal and biomass resources.
75
NIPPC Comments at 6.
33
Docket No. AD12-8-000
2.
Comment
EEI asserts that the response time could be as high as 300-400 hours.
3.
Response
Commission Staff will adjust the burden estimate based on EEI’s high estimate of
300-400 hours. Commission Staff considers EEI’s estimate to be reflective of the most
time that it would take an entity to respond to the metrics. While Commission Staff
recognizes that this report requires additional metrics and narrative discussions,
Commission Staff nevertheless continues to conclude that 140 hours still represents a
reasonable estimate of the burden, since much of the data required should be readily
available to the responding utilities. However, in recognition of the fact that the burden
will vary from entity to entity, we will revise our estimate to 245 hours per respondent,
which is the mid-point between these estimates.
E.
Information Collection Statement
Information Collection Statement:
The following collection of information contained in these metrics is subject to
review by the Office of Management and Budget (OMB) under section 3507 of the
Paperwork Reduction Act of 1995. 76 OMB’s regulations require approval of certain
information collection requirements imposed by agency actions. 77 The Commission
cannot conduct this information collection unless it displays a valid OMB control
number. 78
The collection of information requires those public utilities outside of ISOs and
RTOs that choose to participate to provide information responding to the attached metrics
on a periodic basis. This includes the submission of price data and information relating
to reliability, transmission planning, requests for service, and system capacity. The
76
44 U.S.C. § 3507 (2006). The Paperwork Reduction Act requires OMB
approval of certain information collection activities when these activities apply to 10 or
more persons. Because it is estimated that 11 entities will respond to this collection, the
Chairman is requesting approval from OMB.
77
5 C.F.R. § 1320 (2012).
78
The Commission is issuing a separate notice regarding the collection of
information that will be published in the Federal Register to comply with the OMB
requirements at 5 C.F.R. § 1320.5(a)(iv).
34
Docket No. AD12-8-000
information submitted by participating utilities would be used to help develop a common
set of metrics for both ISO/RTO markets and non-RTO/ISO markets, and for evaluating
market performance thereafter.
35
Docket No. AD12-8-000
Burden Estimate: The estimated public reporting burdens for the reporting
requirements have been adjusted as described above.
FERC-922
Requirements
Metrics Data
Collection
Write
Performance
Analysis
Management
Review
Total
Number of
Respondents
Annually
(1)
11
Number of
Responses per
Respondent
(2)
Average
Burden Hours
per Response
(3)
Total Annual
Burden Hours
(1)x(2)x(3)
140
1,540
85
935
20
220
245
2,695
1
Cost to Comply: The Chairman has projected the cost of compliance to be
$184,460.
Technical Expertise = $168,300 (1,540 hours data collection + 935 hours report
completion @ $68 per hour)
Management Review = $17,160 (220 hours report review @ $78 per hour)
Cost per hour figures are calculated using BLS data. 79 The technical expertise category
factors in the median wage for an engineer, analyst, attorney and economist. The
management category factors in the median wage for general and operations managers.
Based on BLS data, 80 both cost figures have been adjusted to include benefits (benefits
represent 29.5 percent of the total hourly figure).
Title: FERC-922, Non-RTO/ISO Performance Metrics
Action: Proposed Collection.
OMB Control No.: TBD
79
See http://bls.gov/oes/current/naics3_221000.htm
80
See http://www.bls.gov/news.release/ecec.nr0.htm
36
Docket No. AD12-8-000
Internal Review: The Chairman has reviewed the proposed metrics and has
determined that the metrics and data gathered thereunder are necessary. These
requirements conform to the Commission’s need for efficient information collection,
communication, and management within the energy industry. The Chairman is assured,
by means of internal review, that there is specific, objective support for the burden
estimates associated with the information collection requirements.
Interested persons may obtain information on the reporting requirements by
contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE,
Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], email: DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. Any
further comments on the collections of information and the associated burden estimates in
this proceeding should be sent to the Commission in this docket and may also be sent to
the Office of Information and Regulatory Affairs, Office of Management and Budget,
Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory
Commission]. For security reasons, comments to OMB should be submitted by e-mail
to: oira_submission@omb.eop.gov. Comments submitted to OMB should include
Docket Number AD12-8-000 and FERC-922.
37
Docket No. AD12-8-000
IV.
Appendix
38
Docket No. AD12-8-000
Performance Metric
Reliability
A. National or Regional
Reliability Standards
Compliance
39
Specific Metric(s)
1. References to which Electricity Reliability Organization (ERO) and Regional Reliability
Organization (RRO) standards are applicable
2. Number of violations self-reported and made public by NERC/FERC
3. Number of violations identified and made public as RRO or ERO 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/off-peak
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.
Items 2-7: Track the ISO/RTO definition: “This metric is a quantification of all NERC and RRO
Reliability Standards violations that have been identified during an audit or as a result of an
ISO/RTO self-report and have been published as part of that process.”
Non –ISO/RTO utilities should limit reporting to the same eight functional areas used by the
ISO/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. AD12-8-000
B. Dispatch Reliability
40
1. Balance Authority Ace Limit (BAAL) OR// CPS1 and CPS2
2. Number of hours of transmission load reliefs (of severity level 3 or higher) called by the
incumbent transmission provider or unscheduled flows
WECC entities will report events under the WECC Unscheduled Flow Mitigation Procedure
(equivalent to the NERC TLR Level three).
C. Operational Planning –
Load Forecast Accuracy
D. Wind Forecasting
Accuracy
E. Unscheduled Flows
3. Energy Management System (EMS) availability
Actual peak load as a percentage variance from forecasted peak load as reported in OASIS.
Actual wind availability compared to forecasted wind availability
Difference between net actual interchange (actual measured power flow in real time) and the net
scheduled interchange in megawatt hours
Reported in Form 714
F. Transmission Outage
Coordination
1. Percentage of ≥ 200 kV planned outages of 5 days or more for which utility notified customers at
least 1 month prior to the outage commencement date.
2. Percentage of ≥ 200kV outages cancelled by utility after having been previously approved.
3. Report information posted on OASIS (percentage of outages, planned and unplanned, with less
than 2 days notice).
Docket No. AD12-8-000
G. Long-Term Reliability
Planning – Transmission
41
Dollar amount and number of facilities approved to be constructed for reliability purposes
2. Percentage of approved construction on schedule and completed
3. Performance of planning process related to:
a. Requests for and number of completed reliability studies
b. Requests and number of completed economic studies
Discussion of stakeholder process and identification of stakeholder groups participating
H. Long-Term Reliability
Planning – Resources
1. Processing time for generation interconnection requests
2. Actual reserve margins compared with planned reserve margins
3. Explanation of the nature and characteristics of demand response programs and how they are
used in system planning.
Discussion of programs to facilitate the integration of renewable resources and to mitigate any
issues and uncertainty associated with scheduling renewable resources
Docket No. AD12-8-000
I.
Infrastructure Investment
– Interconnection and
Transmission Process
Metrics
42
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)
6. Number of transmission access denials/transmission service requests (TSRs) denied
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. AD12-8-000
System Operations Measures
A. Demand Response
B. System Lambda
43
Comprehensive explanation of the nature of utility demand response programs
implemented for load management as well as in compliance with state requirements.
System Lambda (on marginal unit)
Proposed System Lambda metric would not apply to utilities where the
marginal price is typically set by hydro units
C. Congestion Management
D. Resource Availability
E. Transmission System
Availability
F. Fuel Diversity
G. Clean Energy
Organizational Effectiveness
Not applicable to non-RTO
entities
System lambda data will be based on Form 714 information.
Congestion analysis per Order No. 890
1 - System forced outage rate as measured over 12 months
Interrupted load megawatt hours as a percentage of load served
Fuel diversity in terms of energy, installed capacity and actual production
1. Clean Energy megawatt hours, by resource type, as a percentage of total energy
2. Clean Energy megawatts, by resource type, as a percentage of total capacity
| File Type | application/pdf |
| File Title | Federal Energy Regulatory Commission Staff Report on Performance Metrics for Regions Outside of ISOs and RTOs |
| Author | snhgc10 |
| File Modified | 2012-10-15 |
| File Created | 2012-10-15 |