Comments for RM13-11 Final Rule

Comments
28.

NERC, IRC and Trade Associations disagree with the NOPR proposal, and

support use of the median statistical measure. NERC states that the Commission’s
proposed directive to develop a modification to the methodology for determining the
Frequency Response Measure is premature. NERC asserts that the standard drafting
team evaluated different approaches for averaging individual event observations to
compute a technically sound estimate of Frequency Response Measure, including the
median and linear regression analysis. NERC also notes that, in the NOPR, the
Commission indicated that NERC provided adequate rationale for using the median to
determine the required Frequency Response Measure, and that use of the median is
supported by the analyses performed to date.1
29.

Trade Associations and IRC also disagree with the Commission’s proposal to

direct NERC to develop a modification to the proposed standard and assert that the
standard drafting team selected the most appropriate methodology. Trade Associations
assert that the standard drafting team’s reasoning was “well thought out and balanced
considering the advantages and disadvantages of both approaches (i.e., ‘median’ and
‘linear regression’).”2 Trade Associations understand that the standard drafting team
evaluated both methods and found that the median approach consistently produced a
more conservative Frequency Response Measure value, and was significantly less likely

1

NERC Comments at 5.

2

Trade Associations Comments at 5; see also IRC Comments at 4.

to result in calculation errors. Thus, Trade Associations support the median methodology
because “it is far better to err on the side of having slightly more available reserves than
not having enough.”3 Finally, Trade Associations and IRC comment that that the median
methodology is less complicated and will minimize the compliance risks and resource
burdens of applicable entities. IRC notes that the frequency response measurement
process is easily susceptible to distortion due to a very large noise to signal ratio, and that
use of the median discards such “outliers,” while results from linear regression may be
skewed by such “noise.”
30.

BPA raises a concern that use of the median method for determining the

Frequency Response Measure “gives equal weight to large and small disturbances.”4 In
particular, BPA expresses concern with NERC’s proposal to use 20 to 30 events per year
for calculating the Frequency Response Measure because targeting a fixed number of
events per year may lead to using relatively small (less than 400 MW) events in
frequency response calculations. BPA asserts that extrapolating from these small events
to large events could lead to misleading indications of the Interconnection and balancing
authority’s performance during large events and “undermine the intent” of the Reliability
Standard.5 BPA recommends the following specific revisions to the frequency response
measurement proposal: (1) use resource loss events equal to or greater than 1,000 MW or
events with frequency deviations below 59.9 Hz for calculating frequency response,
3

Trade Associations Comments at 5.

4

BPA Comments at 2.

5

Id.

rather than a fixed number of events per year; and (2) use the smallest of actual maximum
design frequency or the maximum design delta from NERC Table 1 Interconnection
Frequency Response Obligation.
31.

In reply comments, NERC responds to BPA’s proposed revisions, stating that the

values in Table 1 are not static and are revised on an annual basis pursuant to a written
process for identifying candidate frequency events and an annual review of the
calculations. Further, NERC explains that the methodology set forth in Table 1 of
Attachment A to Reliability Standard BAL-003-1 is based on frequency and not the size
of events, as suggested by BPA.
Commission Determination
32.

The Commission does not adopt the NOPR proposal that NERC develop a

modification to replace the use of the median with a more appropriate methodology and,
instead, approves the use of the median methodology to determine the required
Frequency Response Measure as set forth in Reliability Standard BAL-003-1. As
indicated by NERC, the standard drafting team considered various approaches for
averaging individual event observations to compute a technically sound estimate of
Frequency Response Measure and determined that “the median’s superior resiliency to
this type of data quality problem [i.e., a data set with outliers] makes it the best
aggregation technique at the time.”6 We also see merit at this time in IRC’s explanation
that the frequency response measurement process is susceptible to distortion due to a

6

NERC Petition at 17-18.

large noise to signal ratio, and that use of the median discards such “outliers.”
Accordingly, we are persuaded that, based on this record, there is sufficient justification
for NERC’s use of the median method for determining the required Frequency Response
Measure in the initial implementation of Reliability Standard BAL-003-1.
33.

Further, with respect to BPA’s concerns regarding NERC’s process for

determining the appropriate Frequency Response Measure, we agree with NERC’s
explanation that NERC has developed an acceptable methodology for identifying
candidate frequency events and an annual review of the calculations.7 The methodology
developed by NERC is based on frequency and not the size of events. Therefore, if any
revisions are necessary, as BPA suggests, they can be implemented via this established
review process.8
34.

In addition, while the use of the median provides an adequate initial means to

achieve the objectives of Reliability Standard BAL-003-1, we continue to believe that
over the long term the Reliability Standard can be improved by adopting the linear
method.9 However, we are persuaded by the comments of NERC and others that
adopting the linear regression method will insert an additional level of complexity to the
process, and a directive to that effect would be premature. Accordingly, as stated above,
7

NERC Reply Comments at 3-4.

8

Id.

9

See NOPR, 144 FERC ¶ 61,057 at P 27. One of the recommendations contained
in NERC’s Frequency Response Initiative Report states that “[l]inear regression is the
method that should be used for calculating Balancing Authority Frequency Response
Measure (FRM) for compliance with Standard BAL-003-1-Frequency Response.”

we do not adopt our NOPR proposal to direct that NERC immediately develop a
modification to Reliability Standard BAL-003-1 to calculate the Frequency Response
Measure using linear regression. Rather, the Commission acknowledges NERC’s
commitment to studying the use of linear regression10 and the analysis contained in the
Frequency Response Initiative Report,11 and directs NERC to continue its evaluation of
the use of the linear regression methodology based upon experience and data collected
following the implementation of BAL-003-1 and to submit a report to the Commission
within three months after two years of operating experience once Requirement R1 of
BAL-003-1 becomes effective (i.e., 27 months from the effective date of Requirement
R1). The report should assess the accuracy of the linear regression methodology
compared to the median methodology for purposes of determining Frequency Response
Measure. Based on this report and actual experience, the Commission may revisit this
issue.
B.

Determination of Interconnection Frequency Response

Obligation
NERC Petition
35.

Reliability Standard BAL-003-1 establishes an Interconnection Frequency

Response Obligation designed to require sufficient frequency response for each
Interconnection to arrest frequency decline even for severe, but possible, contingencies.
10

NERC Comments at 6 and NERC Petition at 18, fn. 35.

11

See NERC Petition at 17-18; see also id., Exh. F at 72-78.

The methodology for determining each Interconnection’s obligation for obtaining the
necessary amount of frequency response is set forth in Attachment A of the Reliability
Standard. The Interconnection Frequency Response Obligation is based on the “resource
contingency criteria,” which is the largest “Category C” event for the Interconnection,12
except for the Eastern Interconnection, which uses the largest event and maximum actual
change in frequency in the last ten years.13 The maximum change in frequency is
calculated by adjusting the starting frequency for each Interconnection by the “prevailing
UFLS first step,” i.e., under-frequency load shedding for the Interconnection as adjusted
by specific information on the frequency deviations for the observed events which make
up the data-set used to calculate the Frequency Response Measure.14 For multiple
balancing authority Interconnections, the Frequency Response Obligation is allocated to
balancing authorities based on the formula set forth in Attachment A. FRS Form 1 and
the underlying data retained by the balancing authorities are used for measuring whether
frequency response was provided.
12

See Reliability Standard BAL-003-1, Attachment A at 1. Category C events are
defined in Reliability Standard TPL-003-0 (System Performance Following Loss of Two
or More Bulk Electric System Elements), Table 1.
13

For the Eastern Interconnection, the largest event in the last ten years is the loss
of 4,500 MW of generation, which occurred on August 4, 2007. See Reliability Standard
BAL-003-1, Attachment A at 1; Frequency Response Initiative Report at 34-37, 54.
14

Id. Under-frequency load shedding is intended to be a safety net to prevent
against system collapse from severe contingencies. The resource contingency criterion is
selected to avoid violating the under-frequency load shedding settings. See NERC
Petition, Exh. D at 36 (“in general, the goal is to avoid triggering the first step of
under‐frequency load shedding (UFLS) in the given Interconnection for reasonable
contingencies expected”).

NOPR
36.

In the NOPR, with respect to the determination of the Interconnection Frequency

Response Obligation, the Commission discussed two matters: (1) Eastern
Interconnection – prevailing first step of under-frequency load shedding and (2) Western
Interconnection – identifying the largest N-2 contingency.
1.
37.

Eastern Interconnection – Prevailing UFLS First Step

For the Eastern Interconnection, Attachment A to the Reliability Standard

identifies 59.5 Hz as the “first step” of under-frequency load shedding in the calculation
of the default Interconnection Frequency Response Obligation. Attachment A notes that
this set point is “a compromise value set midway between the stable frequency minimum
established in Reliability Standard PRC-006-1 (59.3 Hz) and the local protection under
frequency load shedding setting of 59.7 Hz used in Florida and Manitoba.”15 The NERC
Frequency Response Initiative Report notes that the Florida Reliability Coordinating
Council (FRCC) concluded that the Interconnection Frequency Response Obligation
starting frequency of the prevalent 59.5 Hz for the Eastern Interconnection is acceptable
because it imposes no greater risk of triggering under-frequency load shedding operation
for contingencies internal to FRCC than for contingencies external to FRCC.16
38.

Noting that the actual first-step of under-frequency load shedding for the Eastern

Interconnection is 59.7 Hz, the NOPR sought comment on the technical source or support
15

Reliability Standard BAL-003-1, Attachment A at 2.

16

See Frequency Response Initiative Report at 4, n.3.

for NERC’s statement that the first-step value of 59.5 Hz in the calculation of the
Interconnection Frequency Response Obligation imposes no greater risk of underfrequency load shedding operation in FRCC for an external resource loss than for an
internal FRCC event. Also, the NOPR sought clarification of whether the intent of the
proposal is that FRCC will start shedding load automatically before an event meets the
value of 59.5 Hz used in the Reliability Standard to determine the Interconnection
Frequency Response Obligation.
Comments
39.

NERC, Trade Associations, and MISO submitted comments in support of using

the prevailing under-frequency load shedding first step for the Eastern Interconnection of
59.5 Hz. Trade Associations state that they understand that FRCC has evaluated the
impact of the proposed standard and has determined that the probability of a load
shedding event caused by a generation loss within the Eastern Interconnection is
comparable with an event internal to the FRCC region.17
40.

NERC comments that FRCC’s 59.7 Hz under-frequency load shedding setting is

designed to arrest dynamic transients for system events occurring on the Florida
peninsula to avoid separation from the rest of the Eastern Interconnection. NERC states
that further analysis by NERC showed that the under-frequency load shedding settings on
the Florida peninsula are not susceptible to activation even by very large resource losses
within the main body of the Eastern Interconnection. NERC explains that “[u]sing the

17

Trade Association Comments at 6.

‘generic’ dynamics case available, a follow-on analysis was performed by NERC staff to
determine the general order of magnitude of a frequency event that could be sustained by
the Eastern Interconnection without violating the 59.7 Hz first step under-frequency load
shedding in FRCC. A simulation was run that tripped about 8,500 MW of generation in
the southeast United States (north of Florida).”18 NERC further states that the simulation
showed that the lowest frequency resulting from that event would be about 59.76 Hz in
southern Florida.
41.

NERC further states that the initial nadir of 59.78 Hz in southern Florida from the

simulation is lower than the nadir in northern Florida due to the wave properties of the
disturbance.19 Finally, NERC asserts that because the simulation was conducted with
nearly twice the 4,500 MW resource loss used to determine the Interconnection
Frequency Response Obligation for the Eastern Interconnection, it is prudent to conclude
that the smaller resource loss could not generate a transient or momentary system
disturbance that would trip the FRCC 59.7 Hz under-frequency load shedding. For these
reasons, NERC concludes that the proposed first-step value of 59.5 Hz is adequately
supported by technical considerations.20
42.

MISO also supports the proposed first-step value of 59.5 Hz for the Eastern

Interconnection and asserts that NERC has provided sufficient support for using the
18

NERC Comments at 13.

19

The “nadir” is the lowest point at which frequency excursion is arrested.
Frequency Response Initiative Report at 13.
20

NERC Comments at 14.

59.5 Hz value. According to MISO, the FRCC 59.7 Hz frequency value reflects local
concerns specific to Florida, based on the observation that an event in Florida causes a
wider frequency swing locally than what propagates out to the rest of the Eastern
Interconnection. MISO asserts that there has been no recorded case of frequency in the
Eastern Interconnection declining to 59.7 Hz.21 MISO further submits that, given the
localized nature of the concerns supporting the first-step value in Florida, and the extreme
nature of the event that would be required to drive Interconnection-wide impact, NERC
has sufficient justification for establishing 59.5 Hz as the first-step value for the Eastern
Interconnection.
Commission Determination
43.

The Commission accepts NERC’s and MISO’s explanation of the technical

support for using 59.5 Hz as the “first step” of under-frequency load shedding in the
calculation of the default Interconnection Frequency Response Obligation. The
Commission also agrees with Trade Associations’ assertion that FRCC has evaluated the
impact of the proposed standard and has determined that the probability of a load
shedding event caused by a generation loss within the Eastern Interconnection is
comparable with an event within the FRCC region. Accordingly, the Commission is
satisfied with the NOPR responses and takes no further action on this matter.
2.

Western Interconnection – Largest N-2 Event

NERC Petition
21

MISO Comments at 5.

44.

The Interconnection Frequency Response Obligation is based on the largest

Category C event, or N-2 (loss of two or more bulk electric system elements) for the
Interconnection. The default Interconnection Frequency Response Obligation for the
Western Interconnection is based on the loss of two Palo Verde generating station units,
which results in a resource contingency criterion of 2,740 MW.22 NERC indicated in its
petition that the default Interconnection Frequency Response Obligation calculation
scenarios and the calculation of the Frequency Response Measure for the Western
Interconnection do not take into account the intentional tripping of generation that will
occur during the operation of specific remedial action schemes. According to the
Frequency Response Initiative Report, operation of the Pacific Northwest Remedial
Action Scheme trips up to 3,200 MW of generation in the Pacific Northwest due to the
loss of the Pacific DC Intertie.23 The Frequency Response Initiative Report recommends
that NERC and the Western Interconnection analyze the Frequency Response Obligation
allocation implications of the activation of the Pacific Northwest Remedial Action
Scheme that trips 3,200 MW of generation for a single contingency.24
NOPR

22

See Frequency Response Initiative Report at 53.

23

The Pacific Northwest Remedial Action Scheme, among other things, blocks
frequency response from a number of generators and Balancing authorities to avoid
overloading the Pacific AC ties. See Frequency Response Initiative Report at 62.
24

See id. NERC noted that the maximum value of the Pacific Northwest Remedial
Action Scheme has been updated to be 2,850 MW. See NERC Petition, Exh. G (Status of
Recommendations of the Frequency Response Initiative Report).

45.

In the NOPR, the Commission expressed concern regarding whether the N-2

contingency identified as an input to the Attachment A methodology for calculating the
Interconnection Frequency Response Obligation accurately identifies the largest N-2
event in the Western Interconnection. The NOPR referenced the Frequency Response
Initiative Report, which indicates that the Pacific Northwest Remedial Action Scheme
could result in a larger contingency that, if included as an input to the Attachment A
calculation, would produce more accurate results.25 Accordingly, the Commission
proposed in the NOPR to direct NERC to submit a report that analyzes, with supporting
documentation, the implications of the Pacific Northwest Remedial Action Scheme or
any other Remedial Action Scheme which involves intentional tripping of greater than
2,400 MW of generation, and whether such a contingency would provide a more accurate
basis for the determination of the Western Interconnection default Interconnection
Frequency Response Obligation.
Comments
46.

Trade Associations comment that they recognize the Commission’s issue and have

no concerns with a directive mandating the ERO to study the implications of the Pacific
Northwest Remedial Action Scheme and other similar arrangements that intentionally
involve the tripping of greater than 2,400 MW of generation.
47.

BPA comments that “[Remedial Action Scheme] events should not determine the

Resource Contingency Criteria in the Western Interconnection” because, inter alia,

25

See NOPR, 144 FERC ¶ 61,057 at P 32.

simulation of Remedial Action Scheme events and two Palo Verde events show similar
system frequency performance and “RAS events off-load the system stress … while an
unplanned 2 Palo Verde unit outage would increase the system stress.”26
Commission Determination
48.

In light of NERC’s December 30, 2013 annual analysis informational filing, we

will not adopt our NOPR proposal. In its 2013 annual analysis NERC explains that
“[Remedial Action Schemes] in the Western Interconnection that trip generation
resources in excess of 2,400 MW for transmission system contingencies should not be
used for the resource contingency protection criteria for the Western Interconnection.
Because of the location of the resources tripped and the fact that [Remedial Action
Schemes] would not be armed to trip those levels of generation under peak conditions,
the loss of two Palo Verde units is a larger hazard to the interconnection.”27
Accordingly, the Commission will not direct NERC to submit a report concerning the
implications of the Pacific Northwest Remedial Action Scheme or any other Remedial
Action Scheme which involves intentional tripping of greater than 2,400 MW of
generation, and whether such a contingency would provide a more accurate basis for
determining the Western Interconnection default Interconnection Frequency Response
Obligation. We expect, however, that NERC will continue to study any modified or new
Remedial Action Schemes that may have an impact greater than the tripping of 2,400

26

See BPA Comments at 7 (providing additional rationale for not considering
Remedial Action Scheme events).

MW in its annual frequency response analysis, including an assessment of the adequacy
of the resource contingency protection criteria for the Western Interconnection.
49.

While BPA advocates that Remedial Action Schemes should not be considered in

determining the Interconnection Frequency Response Obligation, BPA did not provide
support in the record for its claim that activation of Remedial Action Schemes will reduce
system stress while the loss of two Palo Verde units will increase it. Contrary to BPA’s
argument, we believe that it is appropriate to study this matter, as NERC has done, and
take possible future action depending on study results because if the obligation is set too
low, the Western Interconnection may not have sufficient frequency response to arrest
frequency decline.
C.
50.

Method of Obtaining Frequency Response

In Order No. 693, the Commission directed NERC to develop a modification to

BAL-003-0 that includes methods for obtaining frequency response.28 While the
Reliability Standard establishes an Interconnection Frequency Response Obligation and
allocates this obligation to the balancing authorities within the Interconnection, the
Reliability Standard imposes no obligation on resources that are capable of providing
frequency response.
27
28

NERC’s 2013 Annual Analysis at 2.

Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 375. The Commission
directed NERC to develop a modification to BAL-003-0 that “defines the necessary
amount of Frequency Response needed for Reliable Operation for each balancing
authority with methods of obtaining and measuring that the frequency response is
achieved.” Id. (emphasis added).

NOPR
51.

In the NOPR, the Commission stated that Reliability Standard BAL-003-1

imposes an obligation, subject to compliance and enforcement, on each balancing
authority to obtain frequency response. The Commission recognized, however, that
balancing authorities must obtain frequency response from other entities with available
resources, and Reliability Standard BAL-003-1 imposes no obligation on those entities to
provide frequency response.
52.

In the NOPR, the Commission proposed to direct NERC to submit a report

15 months after implementation of BAL-003-1 that provides an analysis of the
availability of resources for each balancing authority to meet its Frequency Response
Obligation during the first year of implementation.29 The Commission also proposed that
the report provide data indicating whether actual frequency response was sufficient to
meet each balancing authority’s Frequency Response Obligation. Further, the NOPR
proposed that, if NERC’s findings indicate that the Frequency Response Obligation was
not met, NERC should provide appropriate recommendations to ensure that frequency
response can be maintained at all times within each balancing authority’s footprint.
Comments
53.

NERC, Trade Associations, IRC, APS, and ELCON generally support the

Commission’s proposal that NERC submit a report regarding the availability of resources
for frequency response. Trade Associations comment that they “recognize the potential

29

NOPR, 144 FERC ¶ 61,057 at P 34.

benefit of such a study,” but suggest that 20 to 24 months is a more reasonable time
frame for a directive. Trade Associations also ask the Commission to exercise care when
directing NERC to conduct studies to ensure that scarce resources are not expended
unnecessarily.
54.

NERC commits to submitting an analysis of resource availability as proposed in

the NOPR. However, NERC provides a detailed timeline for implementation and
indicates that it will not receive the necessary information from responsible entities until
March 24 of the year following the implementation of Requirement R1 of BAL-003-1,
beyond the 15 month time frame proposed in the NOPR. Thus, NERC proposes to
submit the report “within six months of the validation by the ERO of the Frequency Bias
Setting values and computation of the sum of all Frequency Bias Setting values for each
Interconnection and determination of the L 10 values for the CPS 2 criterion for each
Balancing Authority or, if applicable, confirmation of the Frequency Bias Setting to be
used for the calculation of the Balancing Authority ACE limit.”30 NERC also seeks
clarification that the study should analyze the availability of resources for both balancing
authorities and Frequency Response Sharing Groups, since the latter was not specifically
mentioned in the NOPR proposal. NERC states that, upon completion of the analysis,
“should the findings indicate that the Frequency Response Obligation was not met,
NERC will provide appropriate recommendations.”31

30

NERC Comments at 16 (footnote omitted).

31

Id. at 17.

55.

Several commenters, including IRC, APS and BPA, raise concerns regarding the

compliance responsibilities of balancing authorities to meet a Frequency Response
Obligation. IRC asserts that BAL-003-1 creates an inequitable alignment of compliance
responsibility and generator performance capability. IRC states that while the obligation
to meet the frequency response requirements lies with the balancing authority, the ability
to provide the resources necessary to meet those obligations lies primarily with
generators. Therefore, while IRC supports the analysis proposed in the NOPR, IRC also
requests that the Commission direct prospective revisions to the Reliability Standard to
assign responsibilities based on performance capability. IRC contends that this approach
is appropriate because balancing authorities have no control over generators’
performance in supporting the Frequency Response Obligation assigned to balancing
authorities.
56.

BPA agrees with the Commission that Reliability Standard BAL-003-1 does not

address the ability of each balancing authority to ensure adequacy of resources to meet its
frequency response obligations. According to BPA, there is a proposal in WECC to
develop a regional Reliability Standard complementary to NERC BAL‐003‐1 to address
this gap. BPA comments that, until such a standard is developed, each balancing
authority must determine how to meet its own frequency response obligation. BPA states
that this frequency response, measured by balancing authority interchange, includes not
only the response of balancing authority generation but also incremental transmission

losses and natural load response to voltage and frequency.32 Finally, BPA asserts that
balancing authorities that have to acquire resources will also need to develop monitoring
capabilities to ensure that the contracted resources provide frequency response and that
such monitoring will further increase the cost of compliance with Reliability Standard
BAL-003-1.
57.

APS believes it is appropriate for NERC to study and report on the availability

of resources. However, APS asserts it is neither just nor reasonable for a balancing
authority to be held to this requirement when frequency response services are simply not
available. APS states that until such time that NERC has completed the studies, the
results are reviewed, and appropriate solutions are developed to assure that affected
entities have the resources available to comply under all conditions, either the
implementation of the requirements should be delayed, or in the alternative, those
balancing authorities who cannot obtain the required frequency response should be
exempt from the proposed requirements.
58.

APS also proposes that the Commission take a phased-in approach to compliance

obligations to allow adequate time for necessary activities such as testing generation units
for ramp-up capability, tuning generation and retesting, as well as time to allow a
frequency response market to develop. APS comments that the types of resources a
balancing authority has in its portfolio may significantly impact its ability to comply with
BAL-003-1 because some resources, such as hydroelectric generation, are more effective

32

BPA Comments at 20.

in responding to frequency declines. APS asserts that it does not have sufficient fastramping resources to provide the required frequency response should the Western
Interconnection experience an event that results in significant frequency response
deviation. To address its concern, APS suggests a revision to the definition of a
Balancing Authority’s “annual generation” to exclude non-responsive units and apply a
higher weighting factor for responsive units. According to APS, this revision would
align the allocation of Frequency Response Obligation with a generator’s physical ability
to provide it.
59.

In its reply comments, NERC responds to APS, stating that the standard drafting

team determined technical evidence indicates that sufficient frequency response resources
would be available for balancing authorities to comply with the requirements of
Reliability Standard BAL-003-1.33 Therefore, NERC contends that there is no need to
adjust the implementation plan for Reliability Standard BAL-003-1 on the basis of
availability.34 Further, NERC disagrees with APS’s suggestion to revise the definition of
balancing authority “annual generation,” contending that such a change would create a
“perverse incentive” for entities to install generating units that are not capable of
providing Frequency Response. Further, NERC explains in response to APS that the
Reliability Standard is appropriately technology- neutral, does not require every
generator to respond and provide Frequency Response, and allows for flexibility since
33

NERC Reply Comments at 4 (citing NERC Report: State of Reliability 2013
Report (May 2013), Key Finding 3, Page 12).
34

NERC Reply Comments at 4.

Frequency Response is measured on a balancing authority and an Interconnection-wide
basis and permits the formation of Frequency Response Sharing Groups.
Commission Determination
60.

The Commission adopts the NOPR proposal and directs NERC to submit a report

that provides an analysis of the availability of resources for each balancing authority and
Frequency Response Sharing Group to meet its Frequency Response Obligation during
the first year of implementation. However, NERC indicates in its comments that it needs
more than the proposed 15 months to prepare the report based on the time frame for
NERC to receive relevant data from applicable entities.35 Accordingly, we direct NERC
to submit this report within 27 months of implementation of Requirement R1. The
Commission believes that the need for the report is well justified based on the record in
the proceeding, including the support of most commenters. While we conclude that
BAL-003-1 is reasonable and should be approved, it includes a new methodology for
determining the Frequency Response Obligation and the results when applied are not yet
known. Further, as discussed above, the ability of balancing authorities and Frequency
Response Sharing Groups to meet the obligation is untested. Thus, we believe the
required report is an appropriate means to inform us as to whether additional steps are
needed on the Frequency Response Obligation and what those might be. The required
report should provide data indicating whether actual frequency response was sufficient to
meet each balancing authority’s Frequency Response Obligation. Further, consistent

35

See NERC Comments at 16.

with NERC’s representation in its comments, the Commission directs that, upon
completion of the required analysis, should the findings indicate that the Frequency
Response Obligation was not met, NERC shall provide appropriate recommendations to
ensure that frequency response can be maintained at all times within each balancing
authority’s footprint.36
61.

In response to the concerns expressed by the IRC, BPA and APS that balancing

authorities may not have control over adequate resources necessary to support the
Frequency Response Obligations assigned to the balancing authorities, we will not forego
compliance or delay implementation. Certainly, a balancing authority’s ability or
inability to draw on the necessary resources to meet the compliance obligations of BAL003-1 might be a potential mitigating factor in a compliance action, depending on the
efforts made to obtain resource commitments. Moreover, NERC and its stakeholders
had, and still have, the option to propose a Reliability Standard imposing obligations
directly on resources, if they find it appropriate. (Similarly, we may consider a directive
for such a Standard or other options such as market or tariff mechanisms, if appropriate.)
However, we are not persuaded that a blanket waiver or delay in compliance is
warranted.
62.

While we share concerns regarding the ability of balancing authorities and

Frequency Response Sharing Groups to meet the Frequency Response Obligation
pursuant to BAL-003-1, we do not believe that such changes are warranted based on the

36

See NERC Comments at 17.

current record in the proceeding. Rather, a recent NERC study indicates that sufficient
frequency response resources would be available for balancing authorities to comply with
the requirements of Reliability Standard BAL-003-1.37 Further, as noted by NERC,
Reliability Standard BAL-003-1 provides flexibility, for example by allowing entities to
form Frequency Response Sharing Groups to meet the Frequency Response Obligation.
Likewise, we are not persuaded by APS that a change to the definition of balancing
authority annual generation is warranted at this time, and we are concerned that APS’s
suggestion would change the resource-neutral approach of the standard.
63.

We do not discount the concerns of APS and others regarding resource

availability. However, we believe that the prudent course is to have NERC complete the
directed report. The Commission will review NERC’s report, any related
recommendations from NERC, and the record developed in Docket No. AD13-8
regarding the market implications of frequency response requirements,38 to determine
whether additional action is warranted. However, if prior to the deadline for the report
NERC learns that a lack of resource availability could prevent achieving the purpose of
Reliability Standard BAL-003-1, (e.g., balancing authorities are experiencing problems
procuring sufficient resources to satisfy their frequency response obligations), NERC
37

See NERC Reply Comments at 4 (citing NERC Report: State of Reliability
2013 Report (May 2013), Key Finding 3, Page 12). See also APS Comments at 8 (“[a]s
NERC Reported in its recent State of Reliability 2013 Report, from 2009 to 2012
interconnection frequency response performance, and expected frequency response …
has been higher than the recommended interconnection frequency response obligation”).
38

See Market Implications of Frequency Response and Frequency Bias Setting
Requirements, 144 FERC ¶ 61,058 (2013).

should immediately report that to the Commission together with appropriate
recommendations for mitigation.39
Premature Withdrawal of Primary Frequency Response
NERC Petition
64.

In its petition, NERC indicated that, while the standards drafting team addressed

the early withdrawal of primary frequency response, there are no requirements that
address this issue and it remains a concern.40 Specifically, during the initial recovery
from the loss of a generator, a gap can occur if a significant amount of primary frequency
response is withdrawn before the secondary response is fully activated. As previously
noted, the Interconnection Frequency Response Obligation for each Interconnection is a
function of the resource contingency criteria and the maximum change in frequency.41

39

For example, in such circumstances, NERC could look to regional Reliability
Standard BAL-001-TRE-01, approved concurrently with this Final Rule, which contains
provisions for assuring frequency response in the ERCOT Interconnection.
40

See NERC Petition, Exh. D (Frequency Response Standard Background
Document) at 19 (“the intentional withdrawal of response before frequency has been
restored to schedule can cause a decline in frequency beyond that which would be
otherwise expected. This intentional withdrawal of response is highly detrimental to

reliability. Therefore, it can be concluded in general that sustained response has a higher
reliability value than un‐sustained response.”).
41

The maximum change in frequency is an amount of frequency deviation based
on the loss of the identified resource contingency that will not trigger under-frequency
load shedding.

65.

NERC’s Frequency Response Initiative Report states that “[w]ithdrawal of

primary frequency response is an undesirable characteristic associated most often with
digital turbine-generator control systems using set point output targets for generator
output. These are typically outer-loop control systems that defeat the primary frequency
response of the governors after a short time to return the unit to operating at a requested
MW output.”42 The Frequency Response Initiative Report recommends measuring and
tracking frequency response sustainability trends.43 The Frequency Response Initiative
Report also recommends that “NERC should include guidance on methods to reduce or
eliminate the effects of primary frequency response withdrawal by outer-loop unit or
plant control systems.”44
NOPR
66.

In the NOPR, the Commission explained that “following the sudden loss of

generation, the automatic and immediate increase in power output by resources providing
primary frequency control seeks to quickly arrest and stabilize the frequency of the
interconnection, usually within 30 seconds or less. After this rapid primary frequency
response, AGC provides secondary frequency response to return frequency to the
scheduled value in time frames of several minutes after the loss of generation.”45
42

NERC Petition, Exh. F (Frequency Response Initiative Report) at 31.

43

Id. at 35. The Frequency Response Initiative Report also recognizes unit
characteristics and operating philosophies as typical causes.
44

Id. at 41-42.

45

NOPR, 144 FERC ¶ 61,057 at P 35.

However, the withdrawal of a significant amount of primary frequency response before
the secondary frequency response is activated can cause a further drop in frequency
response. This drop in frequency is illustrated by the following diagram:46

1. Event
2. Primary Response

3. Early Withdrawal of
Primary Response

67.

In the NOPR, the Commission expressed concern that Reliability Standard BAL-

003-1 does not adequately address the reliability issue created by the withdrawal of
primary frequency response prior to activation of secondary frequency response. The
withdrawal of primary frequency response before the activation of resources providing
secondary frequency response may lead to under-frequency load shedding and possible
cascading outages. Accordingly, the Commission proposed to direct NERC to develop a
46

Id. P 35 (citing Frequency Response Initiative Report at 35, fig. 21).

modification to BAL-003-1 to address the concern of premature withdrawal of primary
frequency response prior to the activation of secondary frequency response.
Comments
68.

NERC disagrees with the need for the proposed directive. First, NERC asserts

that Form 1 of the Reliability Standard addresses premature withdrawal of frequency
response and suggests that experience with the actual implementation of the Reliability
Standard will better indicate whether premature withdrawal is an issue that requires
revisions to the Reliability Standard and, if necessary, definitions of the scope and
parameters of the potential issue. Second, NERC notes that the premature withdrawal
issue could be impacted by the Commission’s ongoing effort to determine whether action
is necessary to coordinate the requirements of the Reliability Standard with tariffs and
market rules.47 Third, NERC asserts the issue of premature withdrawal can be addressed
with other mechanisms rather than a revision to the Reliability Standard. Finally, NERC
states that it “commits to monitoring the issue of premature withdrawal on a goingforward basis and will submit an informational filing two years after Requirement R1 of
Reliability Standard BAL-003-1 becomes effective.”48
69.

NERC maintains that the standard drafting team accounted for the issue of

premature withdrawal of frequency response in the calculation of the B-value averaging
period within the Frequency Response Measure. NERC states that “[t]he team
47

See Market Implications of Frequency Response and Frequency Bias Setting
Requirements, 144 FERC ¶ 61,058 (2013).
48

NERC Comments at 7.

recognized that there would be more AGC response in the 20 to 52 second period, but the
team also recognized that the 20 to 52 second period would provide a better measure of
squelched response from outer loop control action. The 20 to 52 second period was
selected because it would indicate squelched response from outer‐loop control and
provide incentive to reduce response withdrawal.”49 NERC further explains that if there
is withdrawal of primary frequency response during the 20 to 52 second interval, the
metric will have a lower value, which will then lower an entity’s median score thereby
impacting compliance with Requirement R1 of Reliability Standard BAL-003-1.
70.

NERC also maintains that, while Reliability Standard BAL-003-1 applies to

balancing authorities and Frequency Response Sharing Groups, the premature withdrawal
issue applies to generators. Therefore, NERC asserts, the withdrawal issue could be
addressed with alternative mechanisms, including other Reliability Standards or
guidelines. NERC further asserts that there are emerging technologies that can and will
affect withdrawal, including energy storage devices. NERC notes that the premature
withdrawal issue could be affected by whatever tariff or market solutions the
Commission may adopt in related Docket AD13-8. For these reasons, NERC believes
the Commission’s proposed directive requiring a specific solution, i.e., a modification to
BAL-003-1 Reliability Standard, is premature. NERC states that, consistent with the
recommendations in the Frequency Response Initiative Report, it will evaluate whether a
modification to Reliability Standard BAL-003-1 is necessary to address premature

49

NERC Comments at 9 (citing NERC Petition, Exh. D at 13).

withdrawal and will submit an informational filing to the Commission two years after
Requirement R1 of Reliability Standard BAL-003-1 becomes effective.50
71.

Trade Associations disagree with the Commission’s concern over premature

withdrawal of frequency response. Trade Associations state that Reliability Standard
BAL-003-1, along with other Reliability Standards awaiting implementation, such as
BAL-001-2, sufficiently addresses this concern. Trade Associations assert that the
Eastern Interconnection has significant inertia which buffers the initial drop in frequency
in major events making premature primary frequency response withdrawal more
apparent. Trade Associations state that the exemplary post-contingent recovery of all
Interconnections’ frequency as demonstrated over time supports their view that premature
withdrawal is not a significant factor at this time. Finally, Trade Associations state that
the desired outcome of automatic generation control for a balancing authority should
result in a dispatch of resources to meet the secondary control requirements of NERC
BAL-001. Based upon the overall balance of resources and demand, Trade Associations
assert that automatic generation control may at times, guide individual regulating
resources within a balancing authority, where a positive ACE exists, to withdraw energy
(i.e., to reduce ACE) to meet the secondary control requirements of CPS2 under
Reliability Standard BAL-001-1. Trade Associations assert that the response of such a

50

Id. at 10.

unit would be to withdraw support, thereby resulting in an outcome contrary to the desire
to sustain frequency response.51
72.

IRC states that the Commission’s concern about premature withdrawal of

frequency response is unwarranted. IRC maintains that the Commission should adopt a
more comprehensive perspective, taking into account frequency response and withdrawal
patterns over an extended period of time and across Interconnections to understand the
potential impact of premature withdrawal. IRC states that data collected and analyzed
during the standard drafting team’s field trial indicated how quickly and steadily
frequency is, on average, brought back to a stable level over a five minute response
window in all three Interconnections. IRC explains that the standard drafting team
considered data regarding the mean frequency recovery rate (mHz/Sec) for all frequencyrelated events in each of the major Interconnections from 2010 to 2013. IRC states that
early withdrawal of primary frequency response has not been a significant problem
because “most responses are incomplete at the time that frequency has been initially
arrested and the additional response has generally been sufficient to make up for more
than these unpreventable reductions in response.”52
73.

ELCON states that secondary frequency response (Regulation) is primarily

delivered through automatic generation control, which is governed by Reliability
Standard BAL-005-0.2b. That Reliability Standard contains requirements applicable to

51

Trade Associations Comments at 8-9.

52

IRC Comments at 10.

balancing authorities which therefore, ELCON states, have “the responsibility to ensure
its operability.”53 ELCON further states that Reliability Standard TOP-003-1 calls for
generator operators to coordinate planned outages with transmission operators, who are
required to share that information with balancing authorities. Therefore, ELCON asserts
that “[t]his means that the [balancing authority] is aware of all AGC capacity that will be
unavailable due to planned maintenance well ahead of time—and can plan mitigating
actions accordingly.”54 ELCON also asserts that Reliability Standard PRC-024-1has
requirements intended to ensure that generator operators can ride through specifically
defined frequency deviations, “which can best assure their availability when needed for
secondary frequency response support.”55 ELCON suggests that generator concerns with
possible violations of Reliability Standard PRC-024-1, such as dropping off-line during a
frequency transient within the standard’s “no-trip zones,” could provide incentives
against premature withdrawal.
74.

BPA states that it shares the Commission’s concerns on early withdrawal of

frequency response and provides a recorded frequency response withdrawal by a
combined cycle plant.56 BPA states that the withdrawal was caused by load controllers
implemented at many power plants and suggests that load controllers include a frequency
bias term, similar to automatic generation control, to allow plants to sustain their
53

ELCON Comments at 8.

54

Id.

55

Id.

56

BPA Comments at 14-15.

frequency response. BPA asserts that the sustainability of frequency response is essential
not only for Interconnection system frequency support, but also for voltage stability when
the response withdrawal causes excessive loading on stability‐limited transmission
paths.57
Commission Determination
75.

The Commission is persuaded not to adopt the NOPR proposal to require NERC

to develop a modification to Reliability Standard BAL-003-1 to address premature
withdrawal of frequency response. The Commission believes that the nature and extent
of the problems that could result from the premature withdrawal of primary frequency
response, and how best to address it if necessary, will be better understood after NERC
and balancing authorities have more experience with Reliability Standard BAL-003-1.
Accordingly, in light of NERC’s December 30, 2013 annual analysis informational filing,
the Commission expects NERC to continue to evaluate the impact of the withdrawal of
primary frequency response before secondary frequency response is activated in its
annual analyses.
76.

The Commission recognizes BPA’s concerns about the early withdrawal of

frequency response, particularly the possibility that load controllers may prematurely
over-ride primary frequency response. However, we agree with NERC that the need to
take action, including requiring load controllers to include a frequency bias term similar

57

Id. at 15.

to AGC to sustain frequency response or otherwise modifying Reliability Standard BAL003-1, should be decided after we have actual experience with the Reliability Standard.
Light Load Case Study
NOPR
77.

In the NOPR, the Commission highlighted NERC’s conclusion in its Frequency

Response Initiative Report that “[s]ustainability of primary frequency response becomes
more important during light-load conditions when there are generally fewer frequencyresponsive generators online.”58 Light load conditions require special consideration
because inertia, i.e., the resistance to a change in the motion of an object, plays a crucial
role in how fast frequency declines following the sudden loss of generation.59 In the
NOPR, the Commission further explained that “[W]hen the inertia on the system is low
(i.e. fewer generators on line), the loss of generation creates a steeper frequency
excursion and thus the need for faster frequency response.”60
78.

In the NOPR, the Commission focused on the resource contingency criterion in

Reliability Standard BAL-003-1 for calculating the Interconnection Frequency Response
Obligation for the Eastern Interconnection, and the potential concerns with the use of an
58

NOPR, 144 FERC ¶ 61,057 at P 39 (quoting Frequency Response Initiative
Report at 32).
59

Id. Inertia is provided from the stored energy in the rotating mass of the
turbine-generators and synchronous motors on the Interconnection. See NERC Petition,
Exh. D at 16-17.
60

Id. (quoting Frequency Response Initiative Report at 40). The reduction in
inertia also drives a need for higher speed response to frequency excursions.

event that took place during heavy system load conditions. The use of a generic governor
stability case in the stability simulation testing for the Eastern Interconnection resource
contingency criteria used in the determination of the Interconnection Frequency Response
Obligation represented conditions far different than light-load conditions. This raises
questions regarding whether, and by what amount, light load conditions would lower
system inertia and load response. The Frequency Response Initiative Report
recommended the development of a new light-load case study, and the re-simulation of
the resource contingency criterion for the Eastern Interconnection Frequency Response
Obligation.61 According to NERC, the Eastern Interconnection Reliability Assessment
Group is preparing an updated generic governor 2013 summer light-load case (from the
2012 case series), and NERC will be evaluating the Eastern Interconnection Frequency
Response Obligation during the expected light-load conditions.62
79.

The Commission agreed with NERC that the study of light-load scenarios is useful

in determining an appropriate Interconnection Frequency Response Obligation, especially

61
62

NERC Petition, Exh. F, Frequency Response Initiative Report at 99.

NERC Petition, Exh. G. A study conducted by the National Renewable Energy
Laboratory explored the relationship between system disturbance and grid frequency
perturbation. See National Renewable Energy Laboratory, Eastern Frequency Response
Study (May 2013). A key finding is that the dynamic model of the Eastern
Interconnection can be adjusted to more closely capture the observed behavior. In
particular, the assumed amount of generation with governor controls activated was
increased to model the contingency used in calculating the Eastern Interconnection
Frequency Response Obligation. In addition, a light load power flow case was selected
with the expectation that it would represent one of the more challenging conditions for
the Eastern Interconnection with respect to frequency response. See
http://www.nrel.gov/docs/fy13osti/58077.pdf.

for the Eastern Interconnection.63 Accordingly, the Commission proposed to direct
NERC to submit the results of the light-load case, together with NERC’s
recommendations on whether further actions are warranted.
Comments
80.

BPA, Trade Associations, and IRC submitted comments agreeing with the

Commission that the study of light-load scenarios is useful in determining an appropriate
Interconnection Frequency Response Obligation, especially for the Eastern
Interconnection.
81.

IRC states that it does not oppose the development of a new light-load case study,

but believes that better modeling data needs to be collected before an accurate study can
be conducted. IRC states that “[i]n particular, inaccurate modeling of governor
deadbands and adjustments to model governor performance based on observed
performance for frequency excursions will lead to inaccurate assumptions of performance
for extreme events during light-load.”64 IRC encourages the Commission to direct that
NERC partner with industry to compile the appropriate information needed to ensure an
accurate case study, and to review that study through an industry stakeholder process.

63

According to NERC, “[m]odeling of frequency response characteristics has been
a known problem since at least 2008, when forensic modeling of the Eastern
Interconnection required a ‘de-tuning’ of the existing [Multiregional Modeling Working
Group] dynamics governor to 20% of modeled (80% error) to approach the measured
frequency response values from the [August 4, 2007] event.” See NERC Petition, Exh. F,
Frequency Response Initiative Report at 35.
64

IRC Comments at 11.

Finally, the IRC states that while it agrees that a new light-load case study would be
useful, the study should also look at tools to estimate frequency response in real time.
82.

BPA states that while frequency response is expected to be lower during off-peak

light load conditions, there have not been a sufficient number of events under light load
conditions to confirm the severity of the problem. BPA states that currently all WECC
regions are exceeding their frequency response obligations.
83.

The Trade Associations support the Commission’s proposal to direct NERC to

submit their light-load case study and recommendations.
Commission Determination
84.

The Commission adopts the proposal in the NOPR and directs NERC to submit

the results of the Eastern Interconnection Reliability Assessment Group’s light-load case,
using actual turbine governor response data. Additionally, the Commission directs
NERC to submit a recommendation on whether further actions are warranted no later
than 15 months after implementation of the Final Rule. Further, the report should discuss
any appropriate changes to the Interconnection Frequency Response Obligation
warranted by the study.
Assignment of Violation Risk Factors and Violation Severity Levels
Violation Risk Factor for Requirement R1
NOPR
85.

In the NOPR, the Commission proposed to approve each violation risk factor

assignment NERC proposed for a requirement of the proposed Reliability Standard, with

one exception. The Commission indicated that NERC did not adequately justify
assignment of a medium violation risk factor to Requirement R1, which establishes the
Frequency Response Measure that a balancing authority must achieve to arrest a decline
in system frequency. While NERC asserted that a violation of this requirement will not
cause bulk electric system instability, separation or cascading failures because “a
balancing authority’s previous year’s Frequency Bias setting is included within its ACE
equation and would provide support for the contingency,” the Commission indicated that
this explanation does not apply to Requirement R1. The Commission noted that the ACE
equation provides input to secondary frequency control, which differs from the primary
control needed to arrest a frequency decline, as established by Requirement R1. The
Commission proposed to direct NERC to assign a high violation risk factor to
Requirement R1 because (1) NERC described frequency response as a critical component
to the reliable operation of the Bulk-Power System, indicating that Requirement R1 does
not impose merely an administrative burden, and (2) the medium violation risk factor that
the Commission approved for each BAL-003-0.1b requirement does not apply to
Requirement R1 because it has no equivalent in that standard.65 The Commission sought
comments on this proposal.
Comments
86.

Trade Associations state that while Requirement R1 may merit a high violation

risk factor, responsible entities must achieve an annual Frequency Response Measure as

65

NOPR, 144 FERC ¶ 61,057 at P 42.

calculated in accordance with Attachment A to Reliability Standard BAL-003-1. The
Trade Associations therefore observe that it would be inappropriate to apply the violation
risk factor for Requirement R1 to a single event rather than to an annual Frequency
Response Measure.66
87.

Commenting that the standard drafting team took a rational approach to its

violation risk factor assignments, and that each such assignment appears appropriate and
well-reasoned to approximate the impact of a violation on reliability, IRC requests that
the Commission accept the medium violation risk factor for Requirement R1 as
developed by the standard drafting team and agreed to by industry. 67
88.

APS disagrees with the Commission’s proposal to assign a high violation risk

factor to Requirement R1. APS agrees with NERC that a violation of this requirement
will not cause Bulk Electric System instability, separation or cascading failures. APS
maintains that frequency response in the Western Interconnection is and has been stable.
APS states that there are almost forty balancing authorities in the Western
Interconnection, and even if individual balancing authorities should fall short of their
obligation, there is no measurable risk to the Interconnection.68
89.

APS also states that the worst case scenario from a violation of Requirement R1 is

some loss of load due to under-frequency load shedding. APS contends that over the last
fifteen years in the Western Interconnection, frequency has not declined below 59.7 Hertz
66

Trade Associations Comment at 10-11.

67

IRC Comments at 12.

68

APS Comments at 9.

for a generation loss of 3,000 megawatts or less. APS states that the first underfrequency load shedding in the Western Interconnection occurs at 59.5 Hertz, and hence,
there has not been a significant impact to the bulk electric system for loss of generation.
APS submits that a medium violation risk factor is appropriate.69
Commission Determination
90.

We direct NERC to change the violation risk factor for Requirement R1 to “high,”

as proposed in the NOPR. No commenter disagreed with the Commission’s observation
that Requirement R1 addresses primary frequency control that is necessary to arrest
frequency decline within seconds after it begins. Without sufficient primary frequency
control, a frequency decline may not be arrested in sufficient time to prevent instability,
uncontrolled separation or cascading failures. While APS maintains that frequency in the
Western Interconnection is and has been stable, that stability depends on compliance with
Requirement R1 by balancing authorities that have sufficient resources to meet
Requirement R1. The fact that one entity’s violation of Requirement R1 may be offset by
the efforts of others is not a basis for ignoring or downplaying the substantial risk posed
by inadequate frequency response. Accordingly, we conclude that a “high” violation risk
factor for Requirement R1 is appropriate. We agree with Trade Associations that
Requirement R1 mandates achievement of an annual Frequency Response Measure, and
that compliance with that requirement cannot be determined by a single event.
2.

69

Violation Severity Levels for Requirement R1

APS Comments at 9.

NOPR
91.

In the NOPR, the Commission proposed changes to NERC’s proposed violation

severity level assignments for Requirement R1. NERC proposed two violation severity
levels depending upon whether a balancing authority or a Frequency Response Sharing
Group has an annual Frequency Response Measure “less negative than its Frequency
Response Obligation by more than 1 percent but by at most 30 percent or 15 MW/0.1Hz,
whichever one is the greater deviation from its [Frequency Response Obligation].” This
violation would have a “lower” severity level if “[t]he summation of the Balancing
authorities’ [Frequency Response Measure] within an Interconnection was equal to or
more negative than the Interconnection’s [Interconnection Frequency Response
Obligation],” and a “high” severity level if this summation “did not meet its
[Interconnection Frequency Response Obligation].” Based on these two possibilities for
this summation, NERC proposed either a “medium” severity level and a “severe” severity
level for a balancing authority or Frequency Response Sharing Group with an Frequency
Response Measure that is “less negative than its [Frequency Response Obligation] by
more than 30% or by more than 15 MW/0.1 Hz, whichever is the greater deviation from
its [Frequency Response Obligation].”70
92.

The Commission proposed that NERC modify its severity level assignments for

Requirement R1 to remove references to performance by other entities or otherwise so as
to address a concern that NERC assigned these severity levels partly on performance of

70

NOPR, 144 FERC ¶ 61,057 at P 43.

Requirement R1 by all other responsible entities in the Interconnection in which a
violator is located. The Commission concluded that it would be unfair to base a penalty
on a responsible entity in part upon the collective compliance or lack of compliance by
independent entities, because: (1) NERC’s sanction guidelines focus violation severity
levels on a violator’s deviation from required performance, not the risk the violation is
expected to pose to reliability or performance by other entities; and (2) a balancing
authority or Frequency Response Sharing Group subject to Requirement R1 does not
control any other responsible entity’s compliance with this requirement.71 The
Commission sought comments on its proposal.
Comments
93.

APS agrees with the Commission's proposal that NERC change Requirement R1

violation severity level assignments that are in part based on the performance of other
entities in the Interconnection. However, APS contends that there is no justification for a
“severe” violation severity level applicable to this requirement. APS comments that the
violation severity level should be “low” for a responsible entity missing its annual
Frequency Response Obligation by small amounts (less than 20 percent) and “medium”
for missing by a larger amount (greater than 20 percent).72
94.

IRC states that the standard drafting team took an appropriate, rational approach to

its violation severity level proposal, taking into account that frequency response is an

71

Id. P 44.

72

APS Comments at 9-10.

interconnection-wide service, not balancing authority specific. IRC contends that a
single balancing authority should not be penalized for a 10 percent decrease in response,
where frequency response is otherwise sufficient amongst its surrounding balancing
authorities and the reliability of the Interconnection as a whole is not in jeopardy. IRC
asserts that, in contrast, a 10 percent decrease in frequency response within the
Interconnection as a whole clearly would signal a reliability issue. IRC contends that, by
suggesting that the VSLs for Requirement R1 be modified to remove references to
performance by other entities, the Commission essentially suggested that a small
deficiency within a single balancing authority is equivalent to deficient frequency
response within an Interconnection, and should be equivalently penalized as such.73

73

IRC Comments at 12-13.