CANADA
PROVINCE OF QUÉBEC
RÉGIE DE L’ÉNERGIE
No: R-3699-2009
HYDRO-QUÉBEC TRANSÉNERGIE,
CONTRÔLE DES MOUVEMENTS D’ÉNERGIE
DIVISION, in its role as Reliability Coordinator
for the Province of Québec (“HQRC”)
Petitioner
v.
NEWFOUNDLAND AND LABRADOR HYDRO
(“NLH”)
Intervenor
FILE R-3699-2009
REQUEST BY THE HQRC TO ADOPT RELIABILITY STANDARDS
IN SUPPORT OF ITS INTERVENTION, NLH RESPECTFULLY SUBMITS THE
FOLLOWING:
A.
CONTEXT
1.
On June 2, 2009, HQRC made a request to the Régie de l’énergie (“Régie”) to adopt
reliability standards and to approve registry identifying the entities and facilities covered
by the reliability standards and sanction guide.
2.
On August 21, 2009, NLH filed a request to intervene in this matter. In support of its
request, NLH invoked that according to the evidence filed by HQRC (Exhibit HQCME-2,
Document 3) it was likely to be covered by the reliability standards.
3.
On September 22, 2009, the Régie, in Decision D-2009-121, granted intervenor status to
NLH.
4.
On January 8, 2010, NLH filed comments in which it raises four issues: (1) Dual status of
HQRC's and Hydro-Québec TransÉnergie (“HQT”) Counsel, (2) Reliability standards
not dealt with by Québec Compliance Monitoring and Enforcement Program
(“QCMEP”) and Québec Rules of Procedure (“QROP”), (3) Comments on the sanction
guide and (4) Comments regarding certain reliability standards.
5.
On October 1, 2010, NLH filed with the Régie amended comments in which the issues
added were:
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(a)
“Extended control” and “wide-area view” (IRO-003-2), which includes (1)
Jurisdictional issues, (2) Absence of explicit consent by the Province of
Newfoundland and Labrador, and (3) Interpretation of the CF(L)Co/HydroQuébec “reliability documents”;
(b)
Glossary of terms;
(c)
Coming into force of the reliability standards.
6.
On October 7 and 14, 2010, NLH participated to the Régie’s public hearings.
7.
On May 13, 2011, the Régie rendered a partial decision (D-2011-068) to adopt the
reliability standards and to approve the registry of the entities and facilities subject to
compliance to the reliability standards.
8.
In Decision D-2011-068, the Regie requested to HQRC, among other things, the
integration and justification, as attachment to each reliability standard, of some technical
Quebec specificities requested by HQRC and the submission of a single registry of
entities and facilities subject to compliance with the reliability standards, as well as a
glossary of terms and acronyms related to these standards applicable in Quebec.
9.
On December 20, 2011, the HQRC filed the revised documents with the Régie.
10.
In a letter dated December 15, 2011, the Régie advised the interveners of the opportunity
to file comments regarding the revised reliability standards filed by the HQRC by
January 27, 2012.
11.
Having reviewed the public and confidential material, NLH wishes to comment on the
reliability standards filed December 20, 2011 by HQRC.
12.
The comments relate to the manner by which the reliability standards effect the interests
of Nalcor or its subsidiaries, including NLH, as:
-
The operator and owner of a neighbouring system and facilities (in another
jurisdiction) not regulated by the Regie as per section 85.3 (1), 85.3 (2) and 85.3
(3) of the Act respecting the Regie de l’énergie, L.R.Q., chapter R-6.01.;
-
A holder of an electric power transmission service agreement who uses the
electric power transmission system in Quebec as per section 85.3 (5) of the Act
respecting the Regie de l’énergie, L.R.Q., chapter R-6.01.
B.
SCOPE OF THE RELIABILITY STANDARDS RELATING TO THE
GENERATION AND TRANSMISSION FACILITIES IN THE PROVINCE OF
NEWFOUNDLAND AND LABRADOR
13.
Paragraph 11 of Decision D-2011-068 provides as follows:
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« [11] Seules subsistent certaines interrogations sur la portée des normes
de fiabilité relativement aux installations de production et de transport de
Churchill Falls (Labrador) Corporation Limited (CF(L)Co) au Labrador
et sur la centrale de Chat Falls située en partie en territoire québécois et
propriété conjointe d’Hydro-Québec dans ses activités de production
d’électricité (HQP) et d’OPG. »
“Only certain questions remain about the scope of the reliability
standards relating to the production and transmission facilities of
Churchill Falls (Labrador) Corporation Limited (CF(L)Co), in Labrador,
and the Chat Falls generating station partially situated in Québec and
jointly owned by Hydro-Québec in its power generation activities (HQP)
and Ontario Power Generation (OPG).”
[Our translation][Our emphasis]
14.
The question of the scope of the reliability standards is dealt with by the Régie in
paragraphs 64 to 91 of Decision D-2011-068.
15.
As noted by the Régie in paragraph 65, HQRC determines the scope of the reliability
standards by its definition of the RTP, which was found in Exhibit HQCME-2, Document
10 (prior to revision in December 2011):
French (original)
[65] Le Coordonnateur propose, pour la
plupart des normes de fiabilité qu’il a
déposées, le champ d’application suivant
par sa définition du RTP:
« Réseau de transport composé des
appareils et des lignes transportant
généralement des quantités importantes
d’énergie et des installations de
production de 50 MVA ou plus assurant le
contrôle des paramètres de fiabilité:
• Maintien de l’équilibre offre/demande;
• Réglage de la fréquence;
• Maintien des réserves d’exploitation;
• Réglage de la tension du réseau et des
interconnexions;
• Maintien du transit dans les limites
d’exploitation;
• Coordination et supervision des
transactions d’échanges;
• Supervision des automatismes de réseau;
• Remise en charge du réseau.
English translation
[65] The Coordinator propose, for most of
the reliability standards filed, the
following scope on the basis of the RTP
definition:
“The transmission system comprised of
equipments and lines generally carrying
large quantities of energy and of
generating facilities of 50 MVA or more,
providing control over reliability
parameters:
• Generation/load balancing;
• Frequency control;
• Level of operating reserves;
• Voltage control of the system and tie
lines;
• Power flows within operating limits;
• Coordination and monitoring of
interchange transactions;
• Monitoring of special protection
systems;
• System restoration;
Le réseau de transport principal est sous la The main transmission system is under the
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supervision du coordonnateur de la
fiabilité du Québec (direction Contrôle
des mouvements d’énergie (CMÉ),
Hydro- Québec TransÉnergie).
(Main Transmission System) »
supervision of the HQRC for Québec
(direction – Contrôle des mouvements
d'énergie (CMÉ), Hydro-Québec
TransÉnergie).
(Main Transmission System)”
16.
In paragraph 84 of the Decision D-2011-068, the Régie asks HQRC to delete, as
requested by NLH in its evidence, the last paragraph of the RTP definition, which refers
to HQRC supervision on RTP.
17.
HQRC’s revised definition of the RTP can now be found at Exhibit HQCME-6,
Document-6 (English version):
French (original)
« Réseau de transport composé des
appareils et des lignes transportant
généralement des quantités importantes
d’énergie et des installations de
production de 50 MVA ou plus assurant le
contrôle des paramètres
de fiabilité :
• Maintien de l’équilibre offre/demande;
• Réglage de la fréquence;
• Maintien des réserves d’exploitation;
• Réglage de la tension du réseau et des
interconnexions;
• Maintien du transit dans les limites
d’exploitation;
•Coordination et supervision des
transactions d’échanges;
• Supervision des automatismes de réseau;
• Remise en charge du réseau.
Le réseau de transport principal est sous la
supervision du coordonnateur de la
fiabilité du Québec (direction Contrôle
des mouvements d’énergie (CMÉ),
Hydro- Québec TransÉnergie).
(Main Transmission System)»
18.
English
“The transmission system comprised of
equipments and lines generally carrying
large quantities of energy and of
generating facilities of 50 MVA or more,
providing control over reliability
parameters:
• Generation/load balancing;
• Frequency control;
• Level of operating reserves;
• Voltage control of the system and tie
lines;
• Power flows within operating limits;
• Coordination and monitoring of
interchange transactions;
• Monitoring of special protection
systems;
• System restoration;
The main transmission system is under the
supervision of the HQRC for Québec
(direction – Contrôle des mouvements
d'énergie (CMÉ), Hydro-Québec
TransÉnergie).
(Réseau de transport principal)”.
NLH believes that the issue of scope of the reliability standards remains unresolved, and
wishes to make additional comments on the topic to remove any potential
misunderstanding associated with the jurisdictional scope of these standards, and the
facilities to which the standards apply.
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Special Protection Systems
19.
NLH stated at the public hearing and reiterates that HQRC’s reliability standards, as per
sections 85.3 (1), 85.3 (2), 85.3 (3) of the Act respecting the Regie de l’énergie, are not
applicable to facilities (transmission or generation assets) in the province of
Newfoundland and Labrador;
(a)
either through direct application to CF(L)Co / Nalcor / or NLH or its assets;
(b)
through indirect application by any Hydro-Quebec division as the
purchaser/receiver of power delivered to the Labrador/Quebec border over
CF(L)Co transmission assets;
20.
NLH believes it is important to recognize this reality.
21.
The revised definition continues to complicate the proper determination of RTP facilities
and again neglects to identify the fact that the equipment and lines referenced in the
definition are only those, or portions of which, reside in Quebec.
22.
The revised definition continues to be troublesome in that it speaks to such activities as
Voltage control of the system and tie lines, Monitoring of Special Protection Systems
(“SPS”) and System restoration.
23.
These activities, and their association with CF(L)Co facilities are specifically dealt with
in the following confidential documents1. The relationship between the submitted
documents and bulleted aspects of the RTP definition are itemized below:
(a)
HQCME-3, Document 3.2.1, Directive d’exploitation GEN-D-040A, titled Power
System Stabilizers – Churchill Falls Generating Station;
This document discusses the need to report to CCR those Power system stabilizers
that are out of service at CF(L)Co (NLH believes this document could be used in
a false attempt to relate operations at CF(L)Co plant with the aspect of the
definition that deals with voltage control on a tie line thereby attempting to
validate its inclusion within the RTP definition);
(b)
HQCME-3, Document 3.2.2, Directive d’exploitation GEN-D-002A, titled
Generation Rejection and Remote Load Scheding;
This document deals with the operation of the RPTC Special Protection Scheme
at Churchill Falls. This protection scheme is listed as item #2 (Automation RPTC)
in Annexe E of HQCME-6, Document 7. (NLH believes that the document could
be used in a false attempt to relate the operations of RPTC Scheme at CF(L)Co
with aspects of the RTP definition that deal with the operating limits of power
1
It is worth mentioning that both documents titled GEN-D-002A and GEN-D-051-A are not, according to HQRC,
part of the reliability standards. See Transcript of the Regie’s hearing of October 14, 2010, pages 23-26.
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flows on Quebec’s RTP thereby attempting to validate its inclusion within the
RTP definition);
(c)
HQCME-3, Document 3.2.3, Instruction commune GEN-C-051, titled Operation
of the Churchill Falls – Arnaud Subsystem with a single link South of Arnaud
Substation or as an Island system;
This document deals with the operation of CF(L)Co during those periods when
the RTP is experiencing problems just inside the Quebec-Labrador
Interconnection and discusses the use of the URP SPS for generator rejection.
This SPS is listed as item #3 (Automation SPSR) in Annexe E of HQCME-6,
Document 7. (NLH believes that the document could be used in a false attempt to
relate the operations of the generation rejection scheme at CF(L)Co with aspects
of the RTP definition that deal with System Restoration thereby attempting to
validate its inclusion within the RTP definition;
24.
HQRC did not provide any specific information that would prove HQT ownership of the
devices as indicated in Annex E. NLH believes it is HQRC’s onus to demonstrate HQT
ownership of those devices particularly given that these devices reside in another
province. NLH could not make its own verification among CF(L)Co’s employees since
NLH’s representatives were under a Non-Disclosure Agreement.
25.
In addition not all the Directives submitted by HQRC have been signed by the company
that is expected to carry out the actions, that being CF(L)Co and its personnel. As a result
the documents do not demonstrate CF(L)Co’s concordance to cooperate with the
Directives, nor has HQRC proven that it has authority to direct a separate company in a
separate province, to undertake specific activities. Such cooperation or authority should
be demonstrated.
26.
Given the fact that the protection devices to which the Directives apply are not within
Quebec, and the fact that HQRC has not demonstrated HQT ownership of these devices,
the fact the HQRC has not demonstrated authority to direct personnel in another company
and the fact that CF(L)Co has not demonstrated concordance to comply with the
Directives, the Regie should not assume that that the protection offered by these devices
to the RTP or BES, are subject to the reliability standards of Quebec, or conversely the
Regie should not assume that these devices can be used by HQRC is satisfying its own
Reliability standards.
27.
In short, HQRC has not demonstrated that CF(L)Co, nor any of its assets, nor any assets
on its premises are subject to HQRC reliability standards, directly or indirectly,
regardless of the manner by which the Annex present the information. Nor has HQRC
established that CF(L)Co or its assets can be used to satisfy the reliability requirements of
HQ and its system.
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Transmission lines L7051, L7052, and L7053
28.
As suggested above, the issues remains unresolved as illustrated and further complicated,
by the Annex B of exhibit HQCME-6, Document 7 filed by HQRC December 20, 2011.
29.
Annex B of that document list the 735kV transmission lines L7051, L7052, and L7053 as
HQT line assets without any qualification to the fact that it is only the portion of those
lines located in Quebec which are covered by the reliability standards.
30.
This qualifier (“it is only the portion of those lines located in Quebec which are covered
by the reliability standards”) has been applied to other transmission lines which have a
portion of their total length located outside of Quebec.
31.
The qualifier should be applied to lines L7051, L7052, and L7053 as well since those
lines crosses the provincial/geographical border between the province of Québec and the
province of Newfoundland and Labrador.
32.
This lack of qualification in the exhibit HQCME-6, Document 7 (Annex B) may leave
the impression that the portions of lines L7051, L7052, and L7053, which are in the
province of Newfoundland and Labrador, and owned by CF(L)Co, are HQT assets under
its control making up part of Quebec's Main Transmission System (RTP) – which they
are not.
33.
The Régie’s partial decision of May 2011 (D-2011-068) and the revised exhibits filed by
HQRC on December 2011, HQRC have not clearly delineated the fact that the standards
can not be applied to assets in the province of Newfoundland and Labrador.
34.
To recap some history on this issue, first, let’s recall that in a letter dated September 28,
2010 addressed to the Régie, HQRC’s Counsel, Carolina Rinfret, indicated clearly that
the reliability standards do not apply to CF(L)Co:
« Bien que l’intervenante au dossier soit NLH et non Churchill Falls
(Labrador) Corporation (« CF(L)Co ») et que les normes de fiabilité
déposées au présent dossier pour approbation ne s’appliquent pas à
CF(L)Co, […] »
“Considering that the intervenor in this case is NLH, and not Churchill
Falls (Labrador) Corporation (« CF(L)Co ») and that the reliability
standards submitted for approval in this case do not apply to CF(L)Co,
[...]”
[Our translation][Emphasis added]
35.
Second, NLH stresses that at the hearing, the Régie made it clear that there can be no
supervision (e.g. control) by HQRC over any assets of CF(L)Co, or other of its current or
future assets situated in the province of Newfoundland and Labrador.
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36.
Régie’s commissioner, Mr. Michel Hardy, made the following statement during the
public hearing on this issue:
French
« M. MICHEL HARDY
English translation
“Mr. MICHEL HARDY
Maître [procureur de NLH], il n’y a
aucune supervision sur des actifs hors
Québec. Il me semble que ça a été
répondu plusieurs fois.»
Maître [NLH’s counsel], there is no
control over assets outside Quebec. I think
it's been answered many times.”
Référence : notes sténographiques de
l’audience de la Régie du 7 octobre 2010,
page 105 à 108
Reference: transcript of the hearing of the
Régie on October 7, 2010, page 105-108
Mr. MICHEL HARDY
« M. MICHEL HARDY
Vous employez le terme encore
supervision d’actifs hors Québec. Je pense
que la réponse était claire. C’est la
puissance qu’ils vont chercher ou la
quantité et non pas l’actif. »
Référence : notes sténographiques de
l’audience de la Régie du 7 octobre 2010,
page 108, 20e ligne
“You still use the term control of assets
outside Quebec. I think the answer was
clear. It is the quantity of power generated
or volume of electricity they are after, not
the assets.”
Reference: transcript of the Regie’s
hearing of October 7, 2010, page 108,
20th line
37.
HQRC counsel reiterated the same statement in its final pleading at the hearing2.
38.
This line of questions was necessary considering the fact that HQRC had indicated, prior
to the hearing in response to a request for information in file R-3699-2009 (September
22, 2010), that the assets located in Labrador and owned by CF(L)Co were part of the
Hydro-Québec RTP and met the definition of RTP.
39.
Moreover, HQRC included in the concept of RTP, certain assets located in Labrador
through the line drawing submitted as confidential under Exhibit HQCME-2, Document
8.
40.
Thereby, despite the statements made by HQRC and the Regie commissioner, the issues
of the scope of the reliability standards remains unresolved as evidenced by Annex B and
E of exhibit HQCME-6, Document 7 and by the Directives submitted to the hearing by
HQRC. That is the case because:
2
Transcript of the Regie’s hearing of October 14, 2010, pages 22-23.
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(a)
Annex B does not contain a qualifier for lines L7051, L7052 and L7053
indicating that only the portion in Quebec is covered;
(b)
Annex E contains confidential information related to the ownership by HQT of
SPS at CF(L)Co;
(c)
The Directives, both confidential and not, attempt to link SPS devices to the
definition of the RTP;
41.
There is no doubt that HQRC cannot have any control or supervisory authority over
assets located in the province of Newfoundland and Labrador.
42.
Adding also the fact that NLH evidence, supported by testimonies made by NLH and
CF(L)Co representatives, showed clearly that both NLH and CF(L)Co have 100% control
over all of the transmission and generation assets in Labrador from a reliability
standpoint3.
43.
This issue of boundary and scope of application is important to the Regie, as well as
NLH, in that the Regie should not have any misconceptions about the standards that
apply to the energy imported by Hydro-Quebec from Labrador.
44.
On January 19, 2012, a conference call between NLH and HQRC representatives
occurred with respect issues related to HQRC filing of December 20, 2011. Regarding
the application of the qualifier (“it is only the portion of those lines located in Quebec
which are covered by the reliability standards”) to transmission lines L7051, L7052 and
L7053, HQRC indicated that it was an “omission” and that it would be corrected in the
final version of Annex B of exhibit HQCME-6, Document 7.
The exclusion of Labrador from the NPCC
45.
The exclusion of Newfoundland and Labrador from the NPCC territory was presented by
NPCC and recognized by FERC in Order 119 FERC 61,0604. Paragraphs 288 and 289
from that Order state5:
“288. The geographic region in which NPCC will perform its duties and
functions under the NPCC Delegation Agreement will include, as noted
above, New York State, the six New England states, and Ontario,
Quebec, and the Maritime Provinces in Canada. The region covers
approximately one million square miles. NERC, in support of this
proposed regional boundary, states that the six Regional Entities within
the Eastern Interconnection, including NPCC, have worked together to
3
4
5
Transcript of the Regie’s hearing of October 7, 2010, pages 156-163 and 194-197 (Mr. Robert Henderson of
NLH) and pages 204-235 (Andrew MacNeill, Nalcor and Chad Wiseman, CF(L)Co).
FERC, Order accepting ERO Compliance Filing, accepting ERO/Regional Entity Delegation Agreements, and
accepting Regional Entity 2007 Business Plans, April 19, 2007.
Newfoundland and Labrador Hydro is part of the Atlantic Provinces but not of the Maritimes Provinces.
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develop their respective Exhibit A proposals. This is especially important
for a region that is less than interconnection-wide, where failure of one
of the region’s bulk-power system components may have an adverse
impact on the neighboring regions’ bulk-power systems. NERC asserts
that these Regional Entities are satisfied that they have properly
identified their boundaries so as to avoid both gaps and overlaps, and
know which owners, operators and users of the bulk-power system
located along the boundaries are in which regions.
289. We find that the NPCC region, as described in Exhibit A, represents
a sufficient size, scope and configuration. In the pro forma Exhibit A
accepted by the Commission in the ERO Certification Order, the regional
boundary is required to reflect coordination with neighboring Regional
Entities, as appropriate, to ensure that all relevant areas are either
included within the geographic boundary of a Regional Entity or
specifically identified as not being within that Regional Entity’s
geographic boundary. NERC, as noted above, asserts that it has
undertaken this review with NPCC and NPCC’s neighboring Regional
Entities and that each of these entities is satisfied that NPCC’s
boundaries have been properly identified.”
46.
6
These Boundaries are illustrated in the following diagram6;
http://www.nerc.com/docs/oc/rs/BubbleMap_2011-04-12.jpg
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47.
The diagram confirms that Newfoundland and Labrador is neither within NPCC nor
within the Balancing Area of Quebec.
48.
Neither NALCOR, CF(L)Co, nor NLH are “Full members” of NPCC and as per exhibit
HQCME-2, Document 5.3, section 3.2 (“Guide d’application des documents du NPCC
relatifs à la fiabilité”) and as a result are not required to comply with documents
implemented by NPCC:
“3.2
Particularités applicables aux entités membres du NPCC
Les entités qui sont membres à part entière du NPCC1 (Full Member)
doivent, de par leur convention d’adhérent (membership agreement) et
des autres obligations souscrites auprès du NPCC, respecter l’ensemble
des documents de type « A », « B », « C » et « D » mis en vigueur par le
NPCC.
Les non-conformités liées à l’application des documents visés à la
section 4 ne sont pas traitées dans le cadre prévu par la Loi sur la Régie
de l’énergie, mais administrées par le NPCC dans le cadre de
l’application de son programme de conformité et de vérification relatif
aux critères du NPCC (Criteria Compliance and Enforment Program
(CCEP)).”
49.
While NERC standards have not been formally adopted in the Province of Newfoundland
and Labrador or by the electrical utilities in the Province at this time, this matter is under
consideration in the context of planning for the Lower Churchill development.
50.
To illustrate the need for clearly identifying the facilities to which standards apply, the
following simple mis-application of reliability standard FAC-003-1 (Transmission
Vegetation Management Program – exhibit HQCME-6, Document 2), will be made.
51.
This misapplication could result from a belief that the full length of lines L7051 to L7053
are located in Quebec and subject to the reliability standards which have been submitted
by HQ for approval.
52.
In reality of the over 200 km of uninterrupted distance traversed by those lines between
CF(L)Co in Labrador and the Montagnais Substation in Quebec, 90% of the lines length
resides in Labrador – merely 10% in Quebec.
53.
Requirements R1 and R2 of the FAC-003-1 reliability standard require a Transmission
Owner (“TO”) to formalize and implement a Transmission Vegetation Management
Program (“TVMP”) for its transmission assets. The sections of lines L7051 to L7053
which are located in Quebec under the ownership of Hydro-Quebec are required, by the
reliability standard, to have such a program.
54.
However, those sections of the same continuous lines L7051 to L7053 lines which are
routed into Labrador, and under the full ownership of CF(L)Co are not subject and as a
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result CF(L)Co is not required to implement a TVMP in accordance with these reliability
standards.
55.
Hydro-Quebec, as a result of not having ownership over the portions of lines L7051 to
L7053 which are in Labrador and owned by CF(L)Co, does not have the authority to
enforce the FAC-003 reliability standard to those lines portions, nor the authority to
direct any corrective actions required to deal with perceived violations.
56.
The previous illustration demonstrates its worth in that:
57.
(a)
The Reliability Standards Application Matrix (exhibit HQCME-2, Document 6.1)
classifies the Violation Risk Factors associated with requirements 1 and 2 of the
standard as “High”. Similarly, NERC, in its Complete Violations Severity Levels
Matrix, dated December 20, 2011, associates a violation risk factor of ‘SEVERE”
for an Entity that does not have or implement an annual plan for vegetation
management;
(b)
While poor performance of these lines can have an Adverse Reliability Impact (as
per the Glossary of Terms and Acronyms used in Reliability Standards – exhibit
HQCME-6, Document 6) on the HQT system, the scope of the reliability
standards does not permit them to be applied in Labrador.
Again, to avoid misinterpretation related to the application of the reliability standards,
and to diminish any additional confusion that results from Annex B of exhibit HQCME6, Document-7, NLH wishes to recall here section 7.2 of the 1969 Power Contract7 to
demonstrate that CF(L)Co owns and operates the sections of lines L7051 to L7053 in
Labrador:
“7.2 Transmission Facilities
The construction, operation and maintenance of the necessary
transmission facilities up to the Delivery Point will be the exclusive
responsibility of, and at the sole cost of, CF(L)Co and onwards from the
Delivery Point will be the exclusive responsibility of, and at the sole cost
of, Hydro-Quebec.”
[Our emphasis]
58.
Where the Delivery Point is the Quebec/Labrador border or as defined in section 7.1 of
the 1969 Power Contract:
“[…] the Delivery Point for each circuit shall be at the height of land,
about opposite present mile 148.8 on the Quebec North Shore and
Labrador railway, […]”
7
Power Contrat between Quebec Hydro-electric Commission and Churchill Falls (Labrador) Corporation Limited,
May 12, 1969.
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59.
CF(L)Co, Nalcor or NLH have not delegated to HQT the right to conduct a TVMP within
Labrador, nor can Hydro-Quebec take responsibility for, nor direct corrective action, for
any vegetation management issues within Labrador.
Manual intervention by CF(L)Co staff
60.
A second example of the ambiguity surrounding requirements of the reliability standards
in Newfoundland and Labrador is contained in Annexe E of that exhibit HQCME-6,
Document 7.
61.
As specified earlier, that Annex lists the locations where SPS are installed. The protective
devices referenced in this Annex, which are automatically actuated in the event of an
anomaly on HQT’s Main Transmission System will require intervention from CF(L)Co
personnel to re-establish the delivery of energy to the HQT system during the period
when HQT is restoring its Main Transmission System in Quebec8, the steps for which are
itemized in the Directives.
62.
Issues associated with manual intervention by CF(L)Co staff, when re-establishing
energy deliveries to the HQT system are demonstrable in Reliability Standard PER-003
(R1, R1.1, R1.2), which HQ has not yet submitted.
63.
That reliability standard requires NERC certification for operators having real time
control over a transmission lines. While HQT owns or controls the facilities associated
with the termination of lines L7051 to L7053 at Montagnais in Quebec, the other ends of
the lines terminate at CF(L)Co facilities in Labrador, and are controlled by staff at
CF(L)Co. While staff at those stations are well trained, responsible, professional and
have provided reliable service for more than 40 years, they may not necessarily have
undergone NERC certification.
64.
This is the case for both day to day and emergency operations, which affect the BES and
RTP in Quebec.
65.
To once again demonstrate the need for a clear interpretation of the boundaries of the
“Main Transmission System”, so as to avoid a mis-understanding related to the scope of
application of the standards, exhibit HQCME-6, Document 4, associates a risk factor of
‘high’ with violations in standard PER-003.
66.
Similarly, NERC, in its Complete Violations Severity Levels Matrix, dated December 20,
2011, associates a violation risk factor of ‘SEVERE” to the actions of a responsible entity
that does not staff all of its operating positions with personnel that are NERC certified as
required by the criteria described in R1.1 and R1.2.
8
Transcript of the Regie’s hearing of October 7, 2010, pages 156-163 and 194-197 (Mr. Robert Henderson of
NLH) and pages 204-235 (Andrew MacNeill, Nalcor and Chad Wiseman, CF(L)Co).
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67.
If a qualifier for lines 7051 to 7053 has not already been added to appendix B of the
registry of entities by HQRC, to prevent misunderstanding related to the applicability of
the reliability standards in Labrador, NLH requests that the Regie direct HQRC to include
in Annex B of HQCME 6, document 7, a qualifier for lines L7051, L7052 and L7053
indicating that only the portion in Quebec is covered.
C.
RELIABILITY STANDARDS FAC-010-1 AND FAC-011-2
68.
As a PSE and holder of an electric power transmission service agreement, NLH’s
interests lay in the reliability standards which influence the quantity of transmission
capability which is made available to the market and in the transparency afforded the
determination of that capacity by the reliability standards. Proposed reliability standards
FAC-010-1 and FAC-011-2 (exhibits HQCME-6, Document-2) are examples of
standards which fall into this category and merit comment.
Exemption requested by HQRC
69.
NLH’s primary concern with the two above mentioned reliability standards is the
exemption requested by HQRC, to these NERC recognised, and FERC approved
standards.
70.
This exemption in Quebec is requested in the section titled “Regional Difference”,
section E of each of the two standards (Appendix QC – Provisions specific to the
Standard applicable in Québec).
71.
Within that section, HQRC has entered the phrase “Not Applicable in Quebec” as
opposed to the phrase “No Specific Provision” which is used in other standards. HQRC
did not provide any justification for such exemption.
72.
While reliability standards contain regional differences, FERC has taken the view that:
“93. In the NOPR, we noted that Order No. 672 explains that “uniformity
of Reliability Standards should be the goal and the practice, the rule
rather than the exception.” As a general matter, the Commission has
stated that regional differences are permissible if they are either more
stringent than the continent-wide Reliability Standard or if they are
necessitated by a physical difference in the Bulk-Power System.
Regional differences must still be just, reasonable, not unduly
discriminatory or preferential and in the public interest.”9
[Our emphasis]
73.
9
During the approval process for reliability standards FAC-010-1 and FAC-011-2 NLH
expects the Regie to apply both of the criteria mentioned in the above quote.
Paragraph 93, FERC Order No. 705, 121 FERC ¶ 61,296, Facilities Design, Connections and Maintenance
Reliability Standards, issued December 27, 2007.
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Application of the “Necessity” criteria
74.
NLH believes that the application of the FERC “Necessity” criteria mentioned in the
quote, to the exclusion requested by HQRC, based on a physical difference in the Main
Transmission System, is unreasonable as a necessity and if accepted would produce
reliability standards which could be applied in an unduly preferential manner.
75.
During the initial approval of these standards by FERC – FERC Order 705 – it was
reasoned that the determination of System Operating Limits (“SOLs”), as per the
Facilities Design, Connections and Maintenance (FAC) reliability standards, are inputs
required for the calculation Total Transmission Capability (“TTC”) and subsequently
Available Transmission Capability (“ATC”) values, as per the Modeling, Data and
Analysis (MOD) group of reliability standards, and as a result of this link, can affect the
quantity of transmission released to the market.
76.
This reasoning is contained in many sections of that ruling10. The following paragraphs
have been referenced:
“46. The Commission will not direct NERC to revise the FAC Reliability
Standards to address Order No. 890 consistency issues. Given that the
SOLs developed pursuant to the FAC Reliability Standards will be inputs
to the calculation of TTC and ATC under the MOD Reliability Standards
currently under development, the Commission agrees with commenters
that SOLs are not the same as TTC used for ATC calculation. However,
we note that SOLs are a significant component in TTC calculation.
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.
[…]
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
10
121 FERC ¶ 61,296 Order No. 705 Facilities Design, Connections and Maintenance Reliability Standards
Issued December 27, 2007.
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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. Our
determination here not to revise prior directives also addresses
Southern’s request, in response to FAC-011-1, that the Commission
clarify its policy of consistency between operations planning and system
expansion planning relative to TTC calculations. 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.
[…]
77. SOLs are also used by transmission providers to provide details to
system users concerning available capacity for transmission service and
to communicate justifications for denials of service requests, including
long-term ATC. Transmission owners are required to make long-term
TTC calculations in accordance with Order Nos. 890 and 693.”
[Our emphasis]
77.
Hence, as inputs to the MOD reliability standards which calculate ATC/TTC values, the
FAC reliability standards can affect the quantity of transmission capacity available in the
market.
78.
It bears noting that the references to FERC Order 890 relate to an Open Access
Transmission Tariff (“OATT”) containing an Attachment K (Regional System Planning
Process). That attachment provides for transparency in the basic criteria, assumptions and
data that underlie system plans11. HQT has yet to adopt an Order 890 compliant OATT.
79.
The importance of these FAC reliability standards and the influence that these standards
have on the MOD standards require that not only should the assumptions and criteria
used in the FAC standards be consistent with the criteria used in the MOD standards, but
in addition, the results from the FAC system studies and its methodology must be
demonstratable, as per paragraphs 163 and 164 of that same Order, to ensure that the
contingencies and results can be proven to be accurate:
“163. […] As the Commission states previously in this order, FAC-010-1
and FAC-011-1 do not merely establish documentation, methodologies,
and administrative tasks, as is the case for the Requirements that Ameren
points to as examples of inconsistencies. The FAC-010-1 and FAC-011-1
Requirements at issue require the Bulk-Power System to demonstrate
11
121 FERC ¶ 61,297, Order No. 890-A, Preventing Undue Discrimination and Preference in Transmission
Service, (Issued December 28, 2007, Paragraph 195.
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transient, dynamic, and voltage stability performance pre- and postcontingency. The Commission believes that, to demonstrate the pre- and
post-contingency performance metrics required by these Requirements,
an assessment or analysis would need to be performed. […] As such, the
Requirements at issue go beyond the establishment and documentation of
a methodology […]
164. The Commission agrees with NERC that the Requirements to
follow a methodology when determining SOLs are included in FAC-0141. However, as the Commission states above, FAC-010-1, Requirements
R2.1-R2.2 establish the performance metrics of the SOL methodology
used. Thus, if the planning authority’s methodology to develop SOLs
does not meet the demonstrated performance metrics of these
Requirements in a planning time horizon, then under emergency,
abnormal, or restorative conditions, the Bulk-Power System would be at
risk of instability, separation, or cascading failures.”
[Our emphasis]
80.
From the above it can be seen that the criteria used for the system studies and the results
from these system studies should be demonstratable. This demonstration can be used to
diminish preferential treatment by ensuring that both the contingencies used in the
ATC/TTC calculations are not only consistent with those used in the SOLs studies, but
are as well accurate.
81.
The requirement that standards not be preferential was articulated in paragraph 332 of
FERC Order No. 67212:
“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 BulkPower 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.”
[Our emphasis]
82.
12
To eliminate the potential for preferential treatment between the SOLs, as defined by the
FAC reliability standards, and the TTC/ATC as defined by the MOD reliability standards,
each standard in its methodology is required to identify the contingencies included in the
FERC Order 672, Docket No. RM05-30-000, Rules Concerning Certification of the Electric Reliability
Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, issued February 3, 2006.
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calculations. As stated during the development of the MOD standards in paragraph 200 of
FERC Order 729:
“200. With regard to Midwest ISO’s concern, while the terms
“assumptions” and “no more limiting” as used in Requirements R6 and
R7 could benefit from further granularity, we find these Requirements to
be sufficiently clear for purposes of compliance. Likewise, with regard to
Entegra’s concern, we agree that transmission service providers should
use data and assumptions for their available transfer capability or
available flowgate capability and total transfer capability or total
flowgate capability calculations that are consistent with those used in the
planning of operations and system expansion. Under Requirements R6
and R7, transmission service providers and transmission operators must
not overstate assumptions that are used in planning of operations […]”13
83.
Hence the assumptions used for ATC calculations and those used in the Planning process
should be consistent.
84.
Preferential treatment can occur when the contingencies identified for use in the MOD
(TTC/ATC) reliability standards while being consistent with those used in the FAC
(SOLs) reliability standards, do not, at the same time reflect the true limits of the system.
85.
HQCME-6, Document-6 defines the System Operating Limit (SOL) as:
“The value (such as MW, MVar, Amperes, Frequency or Volts) that
satisfies the most limiting of the prescribed operating criteria for a
specified system configuration to ensure operation within acceptable
reliability criteria. System Operating Limits are based upon certain
operating criteria. These include, but are not limited to:
13
-
Facility Ratings (Applicable
equipment or facility ratings)
pre-
and
post-Contingency
-
Transient Stability Rating (Applicable pre- and post-Contingency
Stability Limits)
-
Voltage Stability Ratings (Applicable pre- and post-Contingency
Voltage Stability)
-
System Voltage Limits (Applicable pre- and post-Contingency
Voltage Limits),”
FERC Order 729, Docket No. RM08-19-000, Mandatory Reliability Standards for the Calculation of Available
Transfer Capability, Capacity Benefit Margins, Transmission Reliability Margins, Total Transfer Capability, and
Existing Transmission Commitments and Mandatory Reliability Standards for the Bulk-Power System, issued
November 24, 2009.
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86.
Hence the most limiting criteria are employed when determining SOL to identify the
system’s full capability, less restrictive criteria will not identify the full capability of the
system.
87.
Similarly, if the same and most restrictive criteria are not applied to the TTC/ATC
calculations, as per the MOD standards, transmission capacity which is capable of
transmitting additional energy may not be released to the market.
88.
In such cases customers could be prevented from accessing the transmission system.
89.
This circumstance can be avoided by formalizing the methodology for calculating the
SOLs and demonstrating the results from the application of these reliability standards, as
required by the FERC approved versions of the FAC standards.
90.
As per HQME-6, Document 4 as well as Appendix QC-FAC-010-1 and Appendix QCFAC-011-2 of HQCME-6, Document 2, HQT wishes to have an exemption from this
requirement without any justification.
91.
The listing of the contingencies in the methodology of the FAC reliability standards and
the demonstration of the fact that these limits do actually reflect the system’s limits,
ensures that the system’s capability is not being understated before these same
(consistent) contingencies are applied to the MOD standards for the calculation of
ATC/TTC (i.e. consistent criteria, but inaccurate criteria).
92.
The documentation of the methodology for the FAC, MOD, and other standards, along
with the demonstration of the results, can be used to prove both consistency and accuracy
93.
When determining if the potential for discrimination should be considered in the
development of reliability standards, the FERC in Order No 672 spoke to the balance of
interests:
“39. The Final Rule determines that the ERO’s Reliability Standard
development process must provide for reasonable notice and opportunity
for public comment, due process, openness and balance of interests. The
Commission observes that an American National Standards Institute
(ANSI)-accredited process is one reasonable means of satisfying these
requirements.”
94.
In order to remove the potential for preferential treatment FAC-010-1 and FAC-011-2
should be a requirement in Quebec to demonstrate that the results from the SOLs analysis
do show the true limits of the HQT system and that the criteria/contingencies used in
these calculations be the most limiting and consistent with those used in the ATC/TTC
calculations.
95.
This requirement will help ensure that ATC calculations are not being used to limit
transmission access.
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Link between FAC-010-1, FAC-011-2 and FAC-014-1 reliability standards
96.
In addition to the above rational for maintaining the FAC-010 and FAC-011 standards in
Quebec, the proper application of Standard FAC-014, requires that standards FAC-010
and FAC-011 be approved.
97.
The manner by which the FAC-014-1 standard is linked to the previous standards is noted
below.
(a)
FAC-014-1, R1 requires HQRC to establish SOLs in a manner consistent with its
Methodology (as contained in FAC-011). If FAC-011is not applicable in Quebec
than FAC-014-1 can not be applied properly.
(b)
FAC-014-1, R3 requires the Planning Authority (“PA”) to establish SOLs in a
manner consistent with its Methodology (as contained in FAC-010). If FAC-010
is not applicable in Quebec than FAC-014 cannot be applied properly.
98.
NLH believes that an exemption for HQT from FAC-010 and FAC-011 cannot be
considered “necessary” as a result of the “uniqueness” of the Quebec system, particularly
given the fact that the application of this standard cannot “harm” the HQT system or
diminish its reliability.
99.
When considering the “balance of interests” in its evaluation, the Regie should recognise
that the absence of these standards can present the potential for preferential treatment if
removed. FERC considers that these three standards are mandatory in the rest of North
America14 and it’s not reasonable to exclude their application in Quebec.
100.
During the approval process of these standards15, NPCC as the cross border regional
entity delegated by NERC for the Quebec Interconnection16 did not request that this
regional difference be included when presented to FERC for approval.
101.
During the submission of the standards HQ did not provide any evidence on specific
reason why the exemptions were needed.
14
15
16
121 FERC ¶ 61,296 Order No. 705 Facilities Design, Connections and Maintenance Reliability Standards
Issued December 27, 2007.
121 FERC ¶ 61,296 Order No. 705 Facilities Design, Connections and Maintenance Reliability Standards Issued
December 27, 2007.
From 119 FERC 61,060: 289. We find that the NPCC region, as described in Exhibit A, represents a sufficient
size, scope and configuration. In the pro forma Exhibit A accepted by the Commission in the ERO Certification
Order, the regional boundary is required to reflect coordination with neighboring Regional Entities, as
appropriate, to ensure that all relevant areas are either included within the geographic boundary of a Regional
Entity or specifically identified as not being within that Regional Entity’s geographic boundary.165 NERC, as
noted above, asserts that it has undertaken this review with NPCC and NPCC’s neighboring Regional Entities
and that each of these entities is satisfied that NPCC’s boundaries have been properly identified. 165 ERO
Certification Order, 116 FERC ¶ 61,062 at P 534.
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102.
In the approval process HQ should not benefit from the application of rebuttable
presumption. In Order 67217, at paragraph 345, the commission stated;
“[345] We do not agree that giving due weight means a rebuttable
presumption that the Reliability Standard meets the statutory requirement
of being just, reasonable, not unduly discriminatory or preferential, and
in the public interest. Rather, we agree with the Oklahoma Commission
and SMA that the ERO must justify to the Commission its contention
that the proposed Reliability Standard or proposed modification to a
Reliability Standard is just, reasonable, not unduly discriminatory or
preferential, and in the public interest.”
103.
We expect the Regie to take the same approach.
104.
In its evaluation of the pertinence of the impacts of the submitted reliability standards, as
per 85.6 of the Act respecting the Régie de l’énergie, the Regie should request HQRC to
modify submitted standards FAC-010-1 and FAC-011-2, as per 85.7 of the Act, so that
these standards are applicable in Quebec.
105.
In accordance with HQRC’s removal of the obligation for the Planning Authority and the
Reliability Coordinator to establish methodologies for conducting their respective SOL
analysis, as per the request for a regional exclusion, HQRC in its Reliability Standards
Violation Risk Factor matrix contained in HQCME-6, Document 4, pages 4 and 5, has
provided a risk factor of ‘LOWER’ for violations associated with not having these
methodologies.
106.
NERC, in its Complete Violation Severity Levels Matrix, dated December 20,2011, in
association with requirement R1 of standards FAC-010 and FAC-011, have allocated a
violation level of ‘SEVERE’ to a Planning Authority or a Reliability Coordinator,
whichever the case, if that Entity does not have a documented SOL methodology.
107.
Such is the importance of the documented methodology.
FOR THESE REASONS, MAY IT PLEASE THE REGIE TO:
108.
DIRECT HQRC to include in Annex B of HQCME 6, document 7, a qualifier for lines
L7051, L7052 and L7053 indicating that only the portion in Quebec is covered.
109.
DIRECT HQRC to modify submitted reliability standards FAC-010-1 and FAC-011-2
(exhibit HQCME-6, Document 2) by removing the phrase “Not Applicable in Quebec” in
the “Regional Difference” section of Appendix QC – Provisions specific to the Standard
applicable in Québec so that these standards are applicable in Quebec.
17
114 FERC ¶ 61, 104 Order No. 672, Rules Concerning Certification of the Electric Reliability Organization; and
Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards, Issued February
3, 2006.
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110.
DIRECT HQRC to modify exhibit HQCME-6, Document 4 by removing the word
LOWER from requirement R1 of standard FAC-010 and FAC-011 and replacing it with
the word SEVERE.
111.
DIRECT HQRC, in its definition of RTP/MTS to indicate that it applied only to facilities
in the province of Quebec.
112.
DIRECT HQRC to demonstrate that the information provided in confidentiality is
accurate and can be effectively actioned by HQ or its divisions.
113.
DIRECT HQRC to provide a translation of the exhibit HQCME-6, Document 7, titled
“Registre des entités visées par les normes de fiabilité” (in English “Registry identifying
the entities and facilities covered by the reliability standards”) filed by HQRC December
20, 2011.
114.
DIRECT HQRC to resubmit the revised reliability standards and associated violation
risk matrix to the interveners for further review and to the Regie for approval.
Montréal, this January 27, 2012
(s) Fasken Martineau DuMoulin LLP
Fasken Martineau DuMoulin LLP
Attorneys for NLH
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