COMMENTS OF THE INTERVENOR NEWFOUNDLAND AND LABRADOR
HYDRO REGARDING FOLLOW-UP OF DECISIONS D-2011-068 AND
D-2012-091 WITH RESPECT TO THE REQUEST BY HYDRO-QUÉBEC
CONTRÔLE DU MOUVEMENT DES ÉNERGIES TO ADOPT RELIABILITY
STANDARDS
FILE R-3699-2009 - PHASE 1
Presented to the Régie de l’énergie du Québec
Montréal, Québec
October 21, 2013
1
Introduction
Newfoundland and Labrador Hydro (“NLH”), in its function as a Purchasing and Selling Entity1,
submits to the Régie de l’énergie (“Régie”), its concluding remarks in hearing R-3699-2009
Phase I. NLH thanks the Régie for the opportunity to present its concerns and will limit its
comments to six related issues:
1. Definition and identification of the Bulk Power System (“BPS”);
2. Contingencies under Consideration;
3. The use of Northeast Power Coordinating Council Inc. (“NPCC”) Documentation;
4. New version of standards MOD-010-0, MOD-012-0, PRC-004-2A, PRC-007-0, PRC008-0, PRC-009-0, PRC-015-0 and PRC-016-0.1;
5. Transmission Service Providers (“TSPs”);
6. Comments on the document titled 'Application of Reliability Standards in Québec.
Collectively the first three topics associate the formation of the electrical systems in Québec
subject to reliability standards with the mapping of these systems to specific standards. The last
three topics were raised by the Regie just prior to the October 10 and 11, 2013 oral hearing.
1.
Definition and identification of the BPS
While NLH recognizes the HQ Reliability Coordinator’s (“HQRC”) discretion to identify the
elements which constitute the electric system subject to reliability standards, (RTP, BES, BPS)
and recognizes the oversight offered by the Régie during the development of the Québec specific
appendixes, NLH believes that the standards adoption process, has not required HQRC to:

Adequately demonstrate the need to establish both the RTP and BPS as alternatives to the
industry’s default system; that system being the BES.

Justify the choice of elements which constituent the systems applicable to particular
standards (scope).
1
‘Register of Entities subject to reliability standards’, June 2013, HQCMÉ-6, Document 7.1.
2
Generally speaking NLH believes the need to abandon the BES system, along with the
development and application of alternative system definitions for use with specific standards,
have not been validated through verifiable technical analyses nor conclusive evidence which
illustrate the planning and operating implications associated with the scope (BES, RTP, BPS)
chosen for each standard.
This lack of transparency is particularly evident in the list of elements which make up the BPS.
(a)
HQRC definition for BPS differs from that used by NPCC2
The HQRC's Glossary definition for BPS, while sourced from NPCC differs from that used by
the Regional Reliability Organization (‘’RRO’’).3
HQRC defines BPS to be:
The interconnected electrical systems within northeastern North America comprised of
system elements on which faults or disturbances can have a significant adverse impact
outside of the local area.4
In comparison, the original NPCC definition for BPS is defined to be:
The interconnected electrical systems within northeastern North America comprised of
system elements on which faults or disturbances can have a significant adverse impact
outside of the local area.5
While at a glance the definitions may look alike, they are not the same. In accordance with the
NPCC Glossary, the bold text within the NPCC definition signifies that these words/phrases are
2
3
4
5
The definition posed by HQRC also differs from that used by NERC. NERC Glossary dated July 15, 2013
contains the following definition for BPS approved by FERC on July 9, 2013; BPS - . A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or any
portion thereof); and (B) electric energy from generation facilities needed to maintain transmission system
reliability. The term does not include facilities used in the local distribution of electric energy
HQRC Glossary of Terms and Acronyms used in Reliability Standards, July 2013, HQCMÉ-6, Document
6, footnote to BPS definition – ‘ Source: Document A-07 (NPCC Glossary of Terms)’
HQRC Glossary of Terms and Acronyms used in Reliability Standards, July 2013.
The NPCC Glossary of Terms has replaced the A7 document and was approved by the Regional Standards
Committee (‘’RSC’’) on October 26, 2011, as stated in the ‘Reliability Assessment Program (NRAP) High
Light Report’ Prepared for the Reliability Coordinating Committee February 27, 2013.
3
themselves defined terms within the NPCC Glossary and as such their glossary definitions must
be incorporated into the reader’s interpretation of the term BPS.
In contrast to NPCC’s definition for the term BPS, the HQRC definition does not contain text
properties (bold, italicized, etc.) to signify those same words/ phrases are being used as defined
terms in the HQRC glossary, thus making the two definitions different.
To more fully understand the contributions made by the absent terms, the definitions for the
phrases ‘significant adverse impact’ and ‘local area’, as contained in NPCC Glossary of terms
dated Oct 26, 2011, are pasted below:
Local Area - An electrically confined or radial portion of the system. The geographic
size and number of system elements contained will vary based on system characteristics.
A local area may be relatively large geographically with relatively few buses in a sparse
system, or be relatively small geographically with a relatively large number of buses in a
densely networked system.
Significant Adverse Impact -With due regard for the maximum operating capability of
the affected systems, one or more of the following conditions arising from faults or
disturbances, shall be deemed as having significant adverse impact:
a. instability;
• any instability that cannot be demonstrably contained to a well-defined local
area.
• any loss of synchronism of generators that cannot be demonstrably contained to
a well-defined local area
b. unacceptable system dynamic response;
• an oscillatory response to a contingency that is not demonstrated to be clearly
positively damped within 30 seconds of the initiating event.
c. unacceptable equipment tripping
• tripping of an un-faulted bulk power system element (element that has already
been classified as bulk power system) under planned system configuration due
to operation of a protection system in response to a stable power swing
• operation of a Type I or Type II Special Protection System in response to a
condition for which its operation is not required
4
d. voltage levels in violation of applicable emergency limits;
e. loadings on transmission facilities in violation of applicable emergency limits.
The significance of the presence of these two NPCC defined terms, not referenced in the HQRC
definition, is illustrated in the final paragraph of the introduction to the NPCC Glossary.6 Section
1.0 of that document states:
The Classification of Bulk Power System Elements is based on three defined terms: bulk
power system, local area and significant adverse impact.
While NPCC indicates that three defined terms are required to classify elements as BPS, HQRC
proposes that classification decisions be based on the use of only one defined term.
HQRC's decision to not incorporate the complimentary definitions into its Glossary, in effect,
broadens the interpretation for the term BPS, and increases the likelihood that the term BPS will
not be interpreted in a manner consistent with that used by NPCC. As a result of this potential for
differing interpretations, HQRC's determination of BPS elements through the application of
document A-10 may not be contestant with NPCC's determination.
The absence of these two definitions within the HQRC Glossary presents a potential source of
ambiguity and disagreement between NPCC and HQRC. This potential ambiguity is in addition
to the ambiguity which inherently exists within NPCC’s BPS definition as commented on by
Federal Energy Regulatory Commission (“FERC”) in its examination of the definition and its
examination of NPCC document A-10. In its comments on NPCC’s use of the BPS, FERC
indicated that NPCC’s BPS definition is inferior to NERC's BES definition.7 FERC’s opinions
on the A-10 are discussed in the next section.
(b)
6
7
FERC's opinion on Impact based Methodologies
The NPCC Glossary of Terms approved by the RSC, October 26, 2011
Order 743, 133 FERC 61,150, Nov 18, 2010, paragraph 96 states: […] We further find that the existing
NPCC impact test is not a consistent, repeatable, and comprehensive alternative to the brightline, 100kV
definition we prefer […]’
5
FERC in its hearing process and final Order No 7438 provided its opinion on the use of impact
based methodologies for identifying system elements. From that hearing, the Commission
determined:
77. We disagree with commenters who assert that NPCC’s current material impact
assessment, referred to as NPCC Document A-10, ensures that the proper facilities are
included in the bulk electric system. Although the NPCC Document A-10 provides a test
methodology to identify elements of the bulk electric system, the tests prescribed are
subjective. In the test, a specific bus is subjected to a three-phase fault and the impacts
on other buses are determined. NPCC Document A-10 states that “a transient stability test
may be done first to identify buses at which faults may cause a significant adverse impact
outside of the ‘local area.” The term “local area” is broadly defined and is open to
interpretation. Thus, under NPCC Document A-10, if an entity chooses a large
geographical area for its “local area,” the impact resulting from a fault at a specific bus
could be considered a “significant adverse impact,” but since the impact falls within the
large “local area,” the bus may not be declared part of the bulk electric system. For
example, if one entity defines the “local area” as the boundary of the balancing authority,
while another entity defines the local area as adjacent buses, the outcome of the two tests
could vary significantly. In particular, this likely could result in an exclusion of a large
number of facilities from the purview of the bulk electric system for the first entity that
applies a broader view of “local area.”
[Emphases added by NLH]
The FERC’s opinion was unchanged in Order 743-A9 where it said:
11. We clarify that the specific issue the Commission directed the ERO to rectify is
the discretion the Regional Entities have under the current bulk electric system
definition to define the parameters of the bulk electric system in their regions
without any oversight from the Commission or NERC. As we explained in the Final
Rule, NPCC’s use of this discretion has resulted in an impact-based approach to defining
the bulk electric system that allows significant subjectivity in application and thus creates
anomalous results. While NPCC’s use of its discretion brought the problems with the
current definition to our immediate attention, the Commission’s concern is potentially
broader because any region could use its discretion to define the bulk electric system in a
way that leads to similar inconsistent and anomalous results.
[…]
44. Order No. 743 did not reject all material impact assessments but, instead, took issue
with particular tests and outlined general problems with the material impact tests used to
determine the extent of the bulk electric system that we have seen to date. The NYPSC
incorrectly states that the Commission rejected NPCC’s material impact assessment
8
9
Order 743, 133 FERC 61,150, Nov 18, 2010
Order 743-A, 134 FERC 61,210, March 17, 2011
6
based on one event. Rather, as discussed extensively in the Final Rule and elsewhere
herein, the Commission rejected NPCC’s material impact assessment due to its
subjective language and failure to identify facilities necessary to reliably operate the
interconnected transmission system. These flaws include use of the amorphous term
“local area,” which was not consistently applied throughout the NPCC region. The
NYPSC does not clarify application of this term in its request for rehearing, and instead
merely states that the local area is defined by “the Council members.” As Order No. 743
notes, the subjectivity of the “local area” definition, which ultimately determines
whether or not a facility is classified as part of the bulk electric system, has led to
varying results throughout the NPCC region.
[Emphases added by NLH]
Hence, from paragraph 11 above, FERC has determined that the BES definition contained in the
HQRC Glossary has previously afforded RROs an unacceptable discretion to permit them to
define the BES without FERC oversight.10 This discretion afforded to the RROs also permitted
them to author complimentary documents which were not subject to FERC approval.
The discretion afforded to the RROs was removed with FERC’s approval of a new BES
definition.11 The RRO’s discretion to establish new definitions, such as BPS, and documents
related to that definition, has been removed12, and FERC oversight re-established. As a
consequence of this new BES definition, which is contained in the January 2013 version of the
NERC Glossary, FERC will be required to approve any changes submitted by RROs before a
new BES definition, or related documents, can become effective.
HQRC have not included NERC’s new BES definition in its Glossary even though the NERC
Glossary dated February 11, 201313 contains the new BES definition. As a result of the new BES
definition, it is reasonable to assume that NPCC’s BPS definition will no longer be effective and
as a consequence, BPS supporting documentation, such as A-10, will be substantially modified
10
11
12
13
The RRO’s discretion to define the BES stems from the first sentence of HQRC’s BES definition, which
states ‘As defined by the Regional Reliability organization’.
Order No 773, 141 FERC 61,236 dated December 20th 2012, reaffirmed in Order No 773-A 143 FERC
61,053 dated April 18th, 2013.
Order No 773, dated December 20, 2012 at paragraph 51 states:‘We find that the “core” definition satisfies
the Order No. 743 directives to remove the subjectivity and regional variations that are possible under
the current definition by eliminating the language “as defined by the Regional Reliability Organization”
and “generally operated at,” in the revised definition’.
FERC Order 143 FERC 61,231 dated June 13th, 2013 establishes the effective date of this new BES
definition to be July 1, 2014.
7
or withdrawn. NLH believes the Régie should be mindful of the evolution of the BES definition,
and FERC’s rational for changing it.
As stated in paragraph 44 above, it is also FERC’s opinion that NPCC document A-10 provides
for a subjective determination of BPS elements.
This subjective determination of the ‘local area’ could prove to be a source of disagreement
between transmission customers and the transmission provider, particularly if the interpretation
is considered to be preferential.
Given that NPCC is acting as expert consultants to the Régie on reliability matters in Québec, it
will be informative to read in the Régie’s final decision, any comments solicited from NPCC on
how the new BES definition and FERC Orders 743 and 773 affect the use of NPCC’s BPS
definition in Quebec.14
(c)
A Methodology for identifying BPS Elements as required if the BPS
Definition is Maintained
The construction of Hydro-Québec’s (“HQT”) /NPCC’s BPS definition necessitates that system
analysis be undertaken to identify the elements on which faults or disturbances can have
significant adverse impact outside the local area. While FERC indicated that they are accepting
of Impact based methodologies, the required analytical methodology proposed by NPCC
(document A-10), did not meet with FERC approval. Thus if it is the case that HQRC wishes to
maintain the BPS definition, than a modified version of the A-10 document, or another objective
methodology for identifying BPS elements is required to establish the Registry listing of
Elements that ‘create an adverse effect’.
NLH believes such a methodology should be discussed with stakeholders if the BPS definition is
to be used for specifying the scope of reliability standards. The rational for discussion results
from the fact that the methodology establishes the BPS element list contained in the Registry of
entities which in turn identifies the elements subject to specific standards.
14
Agreement on the Development of Electric Power Transmission Reliabiltiy standards and of Procedures
and a Program for the Monitoring of the Application of these standards for Québec, signed May 8, 2009.
8
It is worth mentioning that the regulatory process adopted in Québec for establishing the scope
of reliability standards in Québec differs from that utilized during the development of the
standards within the US through the Notice of Proposed Rulemaking (“NOPR”)15 process. In
that process, FERC proposed a definition for the BES, and undertook a hearing and in doing so,
specified all the elements subject to Reliability standards (ie. the BES definition).
Contrary to this approach, in the Québec context, the determination of the elements subject to
specific reliability standards, those whose scope is the BPS, is being performed by HQT. HQT
will establish the element list by utilizing a methodology (NPCC document A-10, or similar).
That impact based methodology has not been approved by the Régie (or FERC).
Based on the existing process NLH is concerned with the fact that:
1) The tests and simulations conducted under the methodology are the property of the
Planning Coordinator (HQT) and not the Reliability Coordinator and as such are
considered confidential.16 HQT is the dominant transmission provider in Quebec
2) The TPL standards utilize the BPS element list for transmission planning and the
development and evolution of this list is not transparent and maybe preferential.
To ensure that the standards developed are transparent, and not preferential17, as agreed to by
the Regie with NERC, the methodology for determining the list of BPS elements should be
15
16
17
FERC, Notice of Proposed Rulemaking, Revision to Electric Reliability Organization Definition of Bulk
Electric System, 75 Fed. Reg. 14,097 (March 24, 2010).
During the hearing NLH counsel requested a copy of the simulations and models used to identify the BPS
elements however were informed by HQRC counsel that these were the property of HQT, not HQRC. See
page 123 of the transcript. NLH had hoped to independently verify the BPS element list.
Agreement on the Development of electric Power Transmission Reliability Standards and of Procedures
and a Program for the Monitoring of the application of these standards for Québec, dated May 8, 2009.
Section 4.2 states that NERC and NPCC undertake to ascertain that any electric power transmission
reliability standards specific to Québec, and/or any variant of such standards specific to Québec, which the
reliability coordinator deems necessary to ensure the reliability of electric power transmission in Québec,
is as stringent as the NERC reliability standards applicable in the rest of North America. NERC maintains a
requirement that Reliability standards be just, reasonable and not unduly discriminatory or preferential. See
FERC’s Criteria for Approving Reliability Standards (from Order 672) which states: ‘’ 320. We find
informative the recommendations of commenters on criteria for reviewing a proposed Reliability Standard,
particularly on how to apply the legal standard of review, “just, reasonable, not unduly discriminatory or
9
reviewed by the Régie during an open hearing process for comment by stakeholders. Through
such a process the methodology and the list of elements which result from its application can be
challenged and independently verified by stakeholders. Without submitting such methodology
for approval NLH believes it is difficult for the Régie to ensure that the standards which they
adopt and which depend on the methodology are just, reasonable, not preferential and not unduly
discriminatory.
2.
Contingencies under Consideration
NLH has previously indicated18, and still maintains, that it has issue with the fact that different
element classes are prescribed for establishing the contingencies used in specific Transmission
Planning (TPL) and Facilities Design, Connections and Maintenance (FAC) standards. Unlike in
the application of the NERC standards where contingent elements come from the BES, HQRC
proposes to utilize BPS contingencies for certain TPL standards, and proposes to utilize the RTP
contingencies for certain FAC standards. NLH already raised this issue in a January 2011
submission to the Régie..
NLH believes that the Régie has not required HQRC to adequately substantiated and
demonstrated the criteria utilized to associate particular contingencies to a particular standard.
This lack of transparency is particularly evident in the application of BPS contingencies within
the TPL standards particularly in light of the fact that other related standards utilize RTP
contingencies.
As stated and through the specifications contained in the scope sections of the HQRC Appendix
to standards TPL-001 through to TPL-004, the contingencies to be studied through the guidance
of these standards are derived from the BPS list of elements.19 Inconsistent with this identified
18
19
preferential, and in the public interest.” Although we will not adopt every test that commenters propose, we
do provide here general guidance regarding how the Commission will review a proposed Reliability
Standard.’
See correspondance from NLH on the remaining issues dated June 10, 2013 and July 22, 2013.
Both the MTS and BPS element list are contained in the HQRC document titled ‘Register of Entities
subject to reliability standards’, December 2012. Note, the English redacted version does not contain an
exhibit number.
10
contingency list are the contingencies to be studied during the application of standards FAC-010
and FAC-011; for these standards contingencies are derived from the RTP elements list.20
NLH’s concerns related to the use of different contingencies are consistant with those expressed
by FERC, when the US regulator spoke about the need for consistency amongst contingencies in
its Order No 705.21 In that order, the commission stated:
49. Because the TPL series of Reliability Standards sets the foundation for the types of
contingencies to be considered to meet requirements in the FAC Reliability Standards,
and the FAC Reliability Standards are intended to be consistent with the set of
contingencies identified in the TPL Reliability Standards, the Commission would be
concerned if the TPL Reliability Standards use one set of contingencies to plan the
system, while the FAC Reliability Standards generate another set to calculate SOLs in the
planning horizon. As NERC acknowledges, as the TPL series of Reliability Standards is
modified, conforming changes to the corresponding lists of contingencies in the FAC or
MOD series of Reliability Standards are expected to be necessary to ensure consistency
in the list of contingencies. Similarly, the Commission believes that as FAC or MOD
Reliability Standards are updated, the TPL series of Reliability Standards must be
updated to remain consistent. Therefore, we direct that any revised TPL Reliability
Standards must reflect consistency in the lists of contingencies between the two
Reliability Standards. Should NERC file such revised TPL Reliability Standards, the
Commission will review the resulting Reliability Standards for compliance with our
directives in Order Nos. 890 and 693 concerning consistency for SOLs, transfer
capability and TTC.
Hence, it is reasonable to assume that, as a basic premise, with respect to the list of elements
which make up the contingencies to be examined under study, the contingencies related to the
planning of the transmission system and those related to the system’s operating limit are to be the
same. If the element list differs, it seems appropriate that the onus to prove the need for the
difference rests with HQRC.
It is also worth noting that the HQRC proposed approach to the application of standards to the
BPS system differs from that utilized by NPCC. The NPCC approach to the analysis of the BPS
system is governed and described in NPCC Regional Reliability Reference Directory # 1 Design
and Operation of the Bulk Power System, copy attached. That NPCC criteria document states
that the BPS system, as identified through A-10, is to be planned and operated in accordance
20
21
Ibid.
Order No 705, 121 FERC 61,296, December 27th, 2007.
11
with that document. The HQRC have not submitted this criteria document to the Régie for
discussion.
NPCC are expert consultants to the Régie on the development of standards in Québec, and have
agreed to consider the opinions of transmission system users22. In that light NLH welcomes any
opinions solicited from NPCC on HQRC’s choice to depart from NPCC directory #123 and its
choice to establish different contingencies for different standards.
In addition to NPCC, NERC is as well familiar with the issue of consistency. Their familiarity
was referenced by FERC in Order No 70524:
47. Further, the Commission is persuaded by NERC’s comments that it will coordinate
the assumptions and conditions considered in system planning under the TPL Reliability
Standards, SOL determination under the FAC Reliability Standards and TTC calculation
under the MOD Reliability Standards.
NERC are as well familiar with the potential for a Reliability Standard to influence competiton,
as was discussed in page 332 of FERC’s Order 67225;
332. As directed by section 215 of the FPA, the Commission itself will give special
attention to the effect of a proposed Reliability Standard on competition. The ERO should
attempt to develop a proposed Reliability Standard that has no undue negative effect on
competition. Among other possible considerations, a proposed Reliability Standard
should not unreasonably restrict available transmission capability on the Bulk- Power
System beyond any restriction necessary for reliability and should not limit use of the
Bulk-Power System in an unduly preferential manner. It should not create an undue
advantage for one competitor over another.
22
23
24
25
Agreement on the Development of Electric Power Transmission Reliabiltiy standards and of Procedures
and a Program for the Monitoring of the Application of these standards for Québec, May 8, 2009. Section
4.1.
NPCC’s opinion on the future of its Glossary, A-10, and directory #1, as a result of recent FERC rulings on
NERC’s adoption of a new BES definition in orders 743 and 773 would as well be insightful.
Order No 705, 121 FERC 61,296, December 27th, 2007.
Order No 672, 114 FERC 61,104, February 3, 2006
12
Given NERC’s commitments to FERC and the fact that NERC are expert consultants to the
Régie during these proceedings, and that NERC has agreed to consider the opinions of
transmission users26, any opinions solicited from NERC on this issue, are welcome..
As stated in the introduction, NLH believes that HQRC's rational for establishing a scope for
specific FAC standards which is different from the scope for related TPL standards has not been
sufficiently demonstrated to the Régie and to NLH, and in this regard, any technical analysis or
application guidance for the standards, which has been provided to either NERC or NPCC on
this issue, should be available to other stakeholders for consideration. Such access will help
ensure that all stakeholders can assess whether the standards are equal or superior to that of
NERC and ensure that changes proposed by HQRC to the NERC standards are needed as a result
of the technical uniqueness of the HQT system and are not being recommended simply on the
basis of historical regional practices which maybe preferential.
NLH believes that the Régie should require HQRC to technically validate the use of BPS
contingencies in standards TPL-001 to TPL-004 while utilizing RTP contingencies in FAC-010
and FAC-011.
Such a request seems reasonable, particularly given that FERC gave consideration to the concept
of regional variations in Order number 74327. The following were taken from that order:
68. Hydro-Québec and Ontario Power state that application of the NERC Reliability
Standards should be limited to facilities with a material impact on reliability, based on
regional variances and expertise.
From that hearing, the commission determined the following:
81. […] Commenters state that regional variation allows regional entities to use their
technical expertise to adopt a tailored regional bulk electric system definition. NARUC
and Utah Municipal contend that a key part of the historical approach was the discretion
of the Regional Entities.
26
27
Development of Electric Power Transmission Reliability standards and of Procedures and a Program for
the Monitoring of the Application of these standards for Québec, May 8, 2009.
Order 743, 133 FERC 61,150, Nov 18, 2010
13
82. In response, as the Commission stated in Order No. 672, uniform Reliability
Standards, and uniform implementation, should be the goal and the practice, the rule
rather than the exception, absent a showing that a regional variation is superior or
necessary due to regional differences.
These concepts of superiority and necessity with regard to the development of reliability
standards, as referred to in paragraph 82 above, were agreed to by NERC, NPCC and the
Régie.28
4.2 NERC and NPCC undertake to ascertain that any electric power transmission
reliability standards specific to Québec, and/or any variant of such standards specific to
Québec, which the reliability coordinator deems necessary to ensure the reliability of
electric power transmission in Québec, is as stringent as the NERC reliability standards
applicable in the rest of North America.
[Emphasis added by NLH]
3.
The use of NPCC Documentation
It is NLH’s opinion that documents directly relied upon in the application of NERC reliability
standards in Québec, or documents referenced by any of the documents directly relied upon, are
themselves integral to the reliability standard applicable in Québec and should be submitted to
the Régie for comments by stakeholders prior to potential adoption.29 As mentioned earlier, and
as articulated by FERC in paragraph 11 of 743-A, presented earlier, FERC believes the lack of
regulatory oversight that resulted from the previous BES definition, the same definition proposed
by HQRC, was problematic. FERC resolved that problem by removing the RRO’s discretion to
independently define the BES. NLH believes the Régie should exercise the oversight sought with
the new BES definition and require that relevant NPCC documents be discussed and approved
before being relied upon by any of the standards.
As a consequence of the BPS being identified as the Québec specific scope for standards TPL001 to TPL-004, those NPCC documents which are employed to determine the BPS are
examples of documents worthy of approval.
28
29
Development of Electric Power Transmission Reliabiltiy standards and of Procedures and a Program for
the Monitoring of the Application of these standards for Québec, May 8, 2009. Section 4.2.
Section 85.2 of the Act states: The Régie shall ensure that electric power transmission in Québec is
carried out according to the reliability standards it adopts.
14
On May 9th, 2013 HQRC updated the Register of Entities, HQCMÉ-6 document 7.1. In that
exhibit, footnote #1, on the bottom of page 3 states:
"Elements of the Bulk Power System are determined using NPCC’s A-10 criteria revised on
December 1st, 2009."
Hence Standards TPL-001 through TPL-004 rely directly on NPCC document A-10 for proper
application.
Furthermore, as a result of the integrated nature of NPCC references, NPCC document A-10
relies on other NPCC companion documents for proper interpretation. Examples of such
documents are the NPCC Glossary30 (which used to be document A-7) and the NPCC Design
and Operating Criteria Directory31 (which used to be A-2 but is now Directory 1, referenced
earlier in this submission).32
To reduce the potential for future disagreements, NLH believes documents required for the
proper application of reliability standards, such as NPCC’s A-10, should also be adopted by the
Régie. Documents referenced by A-10 should as well be adopted.
4.
New version of standards MOD-010-0, MOD-012-0, PRC-004-2A, PRC-007-0, PRC008-0, PRC-009-0, PRC-015-0 and PRC-016-0.1
In previous submissions33, NLH expressed some concerns about the absence of the RRO34 within
the set of Reliability standards and expressed concern about the fact that an entity has not been
30
31
32
33
34
NPCC Reliability Assessment Program (NRAP) HIGHLIGHT REPORT Prepared for the Reliability
Coordinating Committee February 27, 2013. The NPCC Glossary of Terms has replaced the A7 document
Latest Version: October 26, 2011 and was approved by the RSC on October 26, 2011.
Reliability Assessment Program (NRAP) HIGHLIGHT REPORT Prepared for the Reliability
Coordinating Committee March 1, 2012. Status/ Comments: Directory No. 1 received Full Member
approval on December 1, 2009 and NPCC Document A-2 was retired on the same date.
See Referances, Page 9 of NPCC A-10.
Comments of the intervenor Newfoundland and Labrador Hydro regarding follow-up of decisions D-2011
068 and D-2012-091 with respect to the request by Hydro-Québec contrôle du mouvement des énergies to
adopt reliability standards File R-3699-2009 - Phase 1presented to the Régie on October 31, 2012 and
comments submitted on January 14, 2013.
Glossary of Terms and Acronyms used in Reliability Standards. That document in its definition of the
RRO specifies in footnote #4 that NPCC is the RRO for the Québec
system.
15
specified to perform the requirements of the RRO particularly given the fact that compliance
monitoring and enforcement agreements35 exist with NPCC.
Subsequent to our submission to the Régie on those concerns, HQRC have transferred to the
Planning Coordinator, activities which were once related to the RRO, particularly the submission
of system data as per standard MOD-010 and MOD-012. This is due to the fact that related MOD
standards applicable to only the RRO, such as MOD-011, were not submitted to the Régie for
approval.
The revisions to Requirements R1 and R2 of standards MOD-010 and MOD-012 are suggesting
that equipment characteristics, system data, dynamic system modeling and simulation data, etc,
be provided to the Planning Coordinator, and do not suggest that the data be provided to the
Reliability Coordinator as well. These revisions do not require the Planning Coordinator to
forward copies of the data to the Reliability Coordinator.
NLH believes that Requirements R1 and R2 of the Québec Specific Appendixes to standards
MOD-010 and MOD-012 are inadequate in that the modifications suggested by HQRC do not
include the requirements that this data be supplied, either directly or indirectly, to the Reliability
Coordinator as well.
The present reliability hearing process places obligations directly on the Reliability Coordinator
and places obligations on the Planning Coordinator through the written requirements within the
standards. In the event that data supplied by the TOs, GOs or GOPs is questionable, the activities
of the Planning Coordinator maybe considered outside the reach of the Reliability Standards if
the Planning Coordinator is not subject to some form of compliance by the Regie.
Without the ability to challenge the credibility of this fundamental data through the Reliability
Standard development process, a gap in the coverage of standards compliance and investigation
before the Régie may exist.
35
Québec Compliance Monitoring and Enforcement Program (QCMEP) for Implementation by Northeast
Power Coordinating Council, Inc. Dated July 28th, 2009.
16
In an effort to remove the potential for gaps in the oversight offered by the Régie and to maintain
transparency within the process, NLH requests that R1 and R2 in standards MOD-010 and
MOD-012 be modified to ensure that all the data specified in the requirements go to the
Reliability Coordinator as well as the Planning Coordinator.
Finally, with respect to the changes proposed by HQRC to these standards, entities, such as
NLH, have not been provided with the opportunity to discuss these changes with HQRC through
a technical session. Technical sessions were held during the initial adoption of standards. NLH
believes such technical discussions are warranted before the changes are accepted.
5.
Auxiliary Carriers as TSPs
Régie requested participants, if in their opinion, Auxiliary Carriers in Québec who do not
provide transportation service under the OATT, can be described within the meaning of the
functional model of the NERC as TSP considering the nature of the activities they perform.
NLH’s review Section 85.3 and 85.14 to 85.23 of the Act respecting the Régie (“Act”) and
section 2.1 of the Register of Entities indicate that all of them are silent on criteria for
establishing the classification of Auxiliary Carriers into the functional category of TSP. In the
absence of such criteria, NLH relies on basic Glossary terms and the requirements of the Act to
determine if Auxiliary Carriers should be subject to TSP standards.
The HQRC Glossary (July 2013 version) which accompanies the reliability standards uses the
following definition for TSP to identify an entities functional type:
The entity that administers the transmission tariff and provides Transmission Service to
Transmission Customers under applicable transmission service agreements.36
[NLH underline]
The definition establishes a number of requirements. With respect to the requirement that the
TSP administer a transmission tariff, the HQRC Glossary for Reliability Standards, document
36
HQRC Glossary of Terms and Acronyms.
17
HQCME-06-06, contains no definition for the word ‘tariff’ nor the phrase ‘transmission tariff’.
In fact, neither word/phrase are capitalized to link them to a glossary definition. Hence, the
phrase ‘transmission tariff’, as used in the definition for TSP is being used in the general sense.
In that light, the phrase is not making reference to a FERC or Régie compliant Open Access
Transmission Tariff (‘’OATT’’), a transmission tariff specific to the Auxiliary Carrier, or to the
HQT OATT specifically.
Section 85.14 of the Act and subsequent sections of Division II of chapter VI.I defines what an
Auxiliary Carrier is but does not use specific OATT wording or language.
Division III of this chapter with respect to access to electric power transmission facilities must
also be read to answer Régie’s question given that it is linked to division II.
Section 85.23 of the Act states:
‘If the connection authorized by the Régie involves a connection to the facilities of the
accessible carrier, that carrier must ensure open access to the facilities and negotiate an
agreement to that effect with the electric power carrier in compliance with Division II of
this chapter’.
[NLH underline]
The Act does not define ‘open access’ and is instead using the phrase in the general sense37. It is
also the case that the Act does not require the carrier to formalize the guiding principles for an
agreement through a formalized Régie approved OATT. Hence the terms and conditions (tariff)
under which service is being provided are general terms acceptable within the industry and those
acceptable to the Régie. These general principles are regulated by the Régie under Division II of
the Act, titled ‘’Electric Power Transmission Service Contracts’.
Given that the Act is silent on an Accessible Carrier's requirement to have a formally structured
tariff document to satisfy the 'open access' requirements of section 85.23, prior to offering
37
As Régie concluded on the interpreation of the division II and III of chapter VI.I of the Act in decision D2008-074, page 23 (in that file, Régie decided that Énergie La Lièvre is an Auxiliary Carrier).
18
transmission service under a contract as an Auxiliary Carrier, (Division II), we can conclude that
the creation of such a tariff document is voluntary. If it is the case that within the TSP definition
the phrase 'transmission tariff' is interpreted to mean a formal document then an entities
classification as a TSP is a voluntary act, conditioned on its desire to formalize a tariff document
which will satisfy the definitions requirements.
Hence the carrier, when forging a transmission service agreement, is administering the generally
accepted tariff term and condition principles consistent with open access, as established and
regulated by the Régie. As a result, the carrier is satisfying the tariff administration requirements
of the definition.
With respect to the requirement that the TSP provides ‘Transmission Service’ to Transmission
Customers under applicable transmission service agreements,
NLH believes that when an Auxiliary Carrier begins to provide a third party with a service for
the movement of energy, as per Division II of the Act, that Auxiliary Carrier is beginning to
satisfy the ‘Transmission Service’ requirements of the definition.
With respect to the requirement that the TSP provide Transmission Service to Transmission
Customers under ‘applicable transmission service agreements’, the phrase ‘transmission service
agreements’ is being used in the general sense.
As indicated earlier, Division II of the Act, sections 85.14 to 85.18, titled ‘Electric Power
Transmission Service Contracts’ specifies that contracts for service must be entered into and if
not a contract will be imposed. Hence Auxiliary Carriers when providing third party service will
do so under applicable transmission service contracts, thus satisfying this aspect of the over all
TSP definition.
In addition to satisfying the basic requirements of the TSP definition, NLH believes that the
materiality of either including or excluding an Auxiliary Carrier within / from the TSP
19
classification should be considered when determining if an Auxiliary Carrier should be classed
as a TSP Functional Entity.
With respect to the materiality of whether or not TSPs should be subject to reliability standards,
an examination of the HQRC Reliability Standards Set indicates that TSPs have responsibilities
which simultaneously are not responsibilities for TOs or TOPs when transmission service is
being provided. Hence there appears to exist the potential for a gap in the coverage of the
standards when an 'Auxiliary Carrier' is providing transmission service. An example of such a
gap and the manner by which the responsibilities of various entities are delineated can be found
in standard MOD-001. That standard deals with ATC calculations. ATC issues are important to
NLH.
Standard MOD-001, in requirements 1 specifies requirements specific to TOs, while requirement
2 specifies requirements specific to TSPs:
R1. Each Transmission Operator shall select one of the methodologies
The Area Interchange Methodology, as described in MOD-028 listed
below for
calculating Available Transfer Capability (ATC) or Available Flowgate Capability (AFC)
for each ATC Path per time period identified in R2 for those Facilities within its
Transmission operating area: [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
The Rated System Path Methodology, as described in MOD-029
The Flowgate Methodology, as described in MOD-030
R2. Each Transmission Service Provider shall calculate ATC or AFC values as listed
below using the methodology or methodologies selected by its Transmission Operator(s):
[Violation Risk Factor: Lower [Time Horizon: Operations Planning]
R2.1. Hourly values for at least the next 48 hours.
R2.2. Daily values for at least the next 31 calendar days.
R2.3. Monthly values for at least the next 12 months (months 2-13).
20
From the above, it can be seen that while it is the responsibility of the transmission operator to
choose the ATC methodology which will apply to the system he operates, it is up to the TSP to
calculate ATC. In addition, that same standard specifies that the responsibility for
communicating ATC lies with the TSP and does not impose that responsibility on either the TO
or TOP, as indicated below. From the same MOD standard:
R3. Each Transmission Service Provider shall prepare and keep current an Available
Transfer Capability Implementation Document (ATCID) that includes, at a minimum, the
following information: [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
R3.1. Information describing how the selected methodology (or methodologies) has been
implemented, in such detail that, given the same information used by the Transmission
Service Provider, the results of the ATC or AFC calculations can be validated.
The application of TSP responsibilities to all carriers that provide transmission service helps to
ensure that ATC is calculated in a method consistent with the intentions of the standards, that
these results are communicated properly and that a standard for compliance exists.
As a result of the analysis applied to the TSP definition and to the fact that the standards require
TSPs to perform tasks related to transmission service which are not requirements for TOs and
TOPs, NLH believes that Auxiliary Carriers should be classed as TSPs within the functional
model when providing transmission service to third parties.
6.
Document titled 'Application of Reliability Standards in Québec
NLH will pass comment on two aspects of the document titled ‘Application of Reliability
standards in Québec’.
Firstly, the contents of the document specify that the document ‘shall take precedence over any
other provision set forth in a reliability standard, the schedules thereto, the Glossary of Terms
and Acronyms used in reliability standards or the Register identifying the entities that are subject
to the reliability standards’.
21
It is NLH’s opinion that the statement’s scope is excessively broad in that the document
identifies all elements pertinent to the proper interpretation of a reliability standard and in doing
so, abolishes legal precedence and interpretations related to the standards, glossary, etc.
Secondly, the document states that ‘’ The default scope of all reliability standards adopted by the
Régie de l’énergie is the bulk electric system. This generic expression means all power
generating and transmission networks in Québec.’38 That expression encompasses a scope which
exceeds the criteria specified in 85.3 of the Act.
By default, the scope of application for these standards is the scope incorporated by the original
authors, in this case NERC. That scope is the Bulk Electric system (BES), as defined by NERC
in its glossary.
With respect to the scope of application in Québec, the process for the adoption of reliability
Standards within Québec provided for modifications to the standards through the creation of
‘Québec specific’ appendixes to each standard. These appendixes define the individual scope
(BES, RTP, BPS) of application for each standard in Québec.
Furthermore HQRC writes the phrase ‘bulk electric system’ in lower case, and in doing so does
not, through the conventions associated with the use of glossary terms, reference the Glossary
definition for the phrase. These conventions are stated in section 1.1 of the Glossary. HQRC
applied the conventions when it wrote the phrase ‘Registry of Entities’.
In fact, by writing the phrase ‘bulk electric system’ in lower case within the document, HQRC is
attempting to attribute a new definition to the phrase for use within the document. HQRC states
that ‘This generic expression means all power generating and transmission networks in Québec.’
Of course this BES definition differs from that contained in the approved Glossary. NLH
believes only the approved Glossary definition should be used.
38
The quote is an NLH translation; the original document was not circulated in English.
22
NLH requests that any use of the phrases Bulk Electric System, Bulk Power System, or Main
Transmission System, or their related acronyms (BES, BPS, RTP) be done so in a manner which
links the use of the phrase to their glossary definitions. That is to say the first letter in each word
should be capitalized, as specified in section 1.1 of the Glossary. Doing so will reduce ambiguity
in the use and interpretation of these phrases. This is particularly important given that NERC, at
the insistence of FERC, has issued new definitions for the phrases ‘Bulk Electric System’ and
‘Bulk Power System’. Those definitions are contained in the most recent NERC version of the
NERC Glossary but are not contained in HQRC’s Glossary. HQRC’s un-capitalized and newly
defined phrase ‘bulk electric system’ may cause unnecessary confusion during the evolution of
the standards.
7.
Conclusion
As a transmission service customer, NLH believes that in the absence of a process which permits
stakeholders to technically, and independently, validate the operating and planning implications
associated with the application of varying system scopes (BES vs RTP vs BPS) to a standard, the
selective choice of the BPS for specific standards may prove to be preferential. This potential for
preferential interpretation is compounded by the ambiguity associated with the BPS definition
and the fact that the analytical methodology required by the definition, such as document NPCC
A-10, has not been presented by HQRC nor approved by the Régie.
NLH believes that thorough technical analysis should be provided to the stakeholders prior to the
adoption of standards by the Régie to permit all stakeholders to fully understand and question the
necessity for abandoning the BES as the default system for reliability standards in Québec and
for determining the appropriateness of the systems eventually approved. NLH believes that this
information should be made available as a basic requirement within the adoption process without
the need for such a request. NLH also believes that it would be appropriate to permit each
stakeholder to independently replicate and validate the analysis supplied to ensure transparency
within the process.
23
NLH requests that the Régie, in its decision, thoroughly discuss the need and appropriateness of
the system scope specified for standards TPL-001 to TPL-004, FAC-010 and FAC-011. NLH
also asks that issues of transparency, potential ambiguity and preferentiality be considered and
commented on with respect to these standards to ensure that the interpretations which result from
the Québec specific appendixes produce reliability standards that are as stringent as those
employed by NERC.39
8.
Recommendation
With respect to the new reliability file of HQRC40 (file number not yet established). During the
technical sessions which will be planned for those 14 or so standards, NLH believes that all
stakeholders should be provided with the opportunity to speak to both NPCC and NERC during
those discussions. This opportunity should be established so as to provide the expert consultants
with varying perspectives on the issues under discussion.
39
40
Agreement on the Development of Electric Power Transmission Reliabiltiy standards and of Procedures
and a Program for the Monitoring of the Application of these standards for Québec, May 8, 2009. Section
4.2 States: NERC and NPCC undertake to ascertain that any electric power transmission reliability
standards specific to Québec, and/or any variant of such standards specific to Québec, which the reliability
coordinator deems necessary to ensure the reliability of electric power transmission in Québec, is as
stringent as the NERC reliability standards applicable in the rest of North America
See correspondance from the Régie dated December 6, 2012.
24