Joel deJesus
Assistant General Counsel, Federal Affairs
January 3, 2007
VIA ELECTRONIC FILING
The Honorable Magalie Roman Salas, Esq.
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
Re: Docket No. RM06-16-000
Dear Secretary Salas:
Please find enclosed for electronic filing in the above referenced docket, the “Comments
of National Grid USA.”
Please do not hesitate to contact me if you have any questions or concerns.
Respectfully submitted,
Joel deJesus
Attorney for
National Grid USA
633 Pennsylvania Avenue, NW, Sixth Floor, Washington, DC 20004-3600
T: 202-783-7959 n F: 202-783-1489 n joel.dejesus@us.ngrid.com n
www.nationalgrid.com
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
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Mandatory Reliability Standards
for the Bulk-Power System
Docket No. RM06-16-000
COMMENTS OF
NATIONAL GRID USA
Pursuant to the Commission’s October 20, 2006 Notice of Proposed Rulemaking in the
above referenced docket,1 National Grid USA (“National Grid”) respectfully submits these
Comments on the NOPR and the proposed mandatory reliability standards to be implemented by
the North American Electric Reliability Corporation and its affiliate, North American Electric
Reliability Council, (jointly “NERC”) as the electric reliability organization (“ERO”) under
Section 215 of the Federal Power Act (“FPA”).
In large part, National Grid agrees with the Commission’s desire to promulgate as
comprehensive a set of reliability standards as possible and as soon as possible. These
Comments, however, will address in detail particular areas that warrant further consideration in
this rulemaking. In particular, National Grid respectfully submits the following:
1. Despite the lack of uniformity among regional approaches to identifying the term “bulk
electric system,” the Commission should allow the continued application of those
traditional regional approaches to identifying the “bulk electric system” as an interim
measure and should not impose the Commission’s own novel interpretation of that term.
Rather, the Commission should require NERC to develop under appropriate timelines
1
Mandatory Reliability Standards for the Bulk-Power System, 117 FERC ¶61,084 (2006) (“NOPR”). See
also Notice Granting in Part Motions for Extension of Time to File Comments and Announcing Rulemaking
Proceeding, Docket Nos. RM06-16-000 and RM07-3-000 (November 11, 2006) (extending comment deadline to
January 3, 2007).
and guidelines a workable approach to identifying the facilities included under the term
“bulk-power system.”
2. Enforcement discretion should apply to any situation in which due process or fairness
require the exercise of such discretion, and it should not be restricted to a six month time
frame or to a limited class of entities who did not previously participate in NERC’s
voluntary reliability standards program.
3. While the Commission should encourage NERC to further refine its functional model, the
Commission should not require the filing or approval of the functional model or future
revisions to it.
4. While the Commission’s decision to exercise its authority under FPA § 215(d)(5) to
request modifications of reliability standards was appropriate in the present
circumstances as the industry transitions from voluntary to mandatory reliability
standards, the Commission should exercise that authority sparingly and in a manner that
allows the ERO and its stakeholders flexibility in how to rewrite reliability standards.
5. The Commission should recognize that there remain important regional requirements that
regional reliability organizations should continue to fulfill and that such requirements
should be embodied in binding commitments in the regional delegation agreements or
Commission order, if not in the reliability standards themselves.
6. The Commission should enter into a binding memorandum of understanding or other
formal mechanism with the Canadian provincial authorities to ensure proper coordination
of approvals, remands, and requests for modifications of reliability standards.
7. The Commission should affirmatively endorse event-based planning.
8. The Commission should continue to push for longer planning horizons, but should
recognize that obtaining accurate generation resource siting and retirement information
remains a concern.
9. N-2 planning should not be imposed as an across the board requirement for “major load
pockets” under TPL-003.
10. Planning for cyber-security incidents should be addressed in TPL-004.
11. The Commission should establish a uniform data retention requirement for data covered
by the reliability rules, but should coordinate that requirement with existing Commission
record retention rules.
2
BACKGROUND
National Grid has electric utility subsidiaries operating in Massachusetts, New
Hampshire, New York, Rhode Island, and Vermont. National Grid’s operating subsidiaries
serve approximately 3.3 million electric end-users. These utilities own and operate
approximately 84,000 miles of transmission and distribution lines.
On February 22, 2006, National Grid and KeySpan Corporation (“KeySpan”) jointly
announced plans for National Grid to acquire KeySpan. This acquisition was approved by the
Commission on October 20, 2006,2 but is subject to receipt of additional regulatory approvals.
Upon completion of this acquisition, the combined company will be the third-largest energy
delivery utility in the United States, with well balanced electricity and gas businesses serving
nearly eight million customers in the New York State and New England regions.
National Grid has been uniquely focused on energy delivery and, in particular, the
development and operation of a robust electric transmission grid that will support the efficient
and economic transfer of energy. As a company that is focused primarily on energy delivery,
National Grid has advanced a comprehensive set of transmission policies designed to promote
the development of transmission infrastructure that will improve reliability and reduce
congestion costs.3
2
117 FERC ¶ 61, 080 (2006).
3
See, National Grid’s white papers entitled “Transmission: The Critical Link” – available on National
Grid’s website at: http://www.nationalgridus.com/non_html/transmission_critical_link.pdf -- and “Transmission
and Wind Energy: Capturing the Prevailing Winds for the Benefit of Customers” – available on National Grid’s
Website at http://www.nationalgridus.com/non_html/c3-3_NG_wind_policy.pdf. See also Post Technical
Conference Comments of National Grid USA, filed in Docket No. AD04-13-000, http://elibrary.ferc.gov/idmws/
common/opennat.asp?fileID=10388841 (January 28, 2005) (“Comments on Wind Power; Motion to Intervene and
Comments of National Grid USA, filed in Docket No. EL05-80-000, http://elibrary.ferc.gov/idmws/common/
opennat.asp?fileID=10495377 (April 14, 2005) (“Comments in Response to SCE Petition”); Post-Technical
Conference Comments of National Grid USA, filed in Docket Nos. AD05-5-000 and PL03-1-000, http://elibrary.
ferc.gov/idmws/common/opennat.asp?fileID=10524165 (May 2, 2005) (“Comments on Transmission Independence
and Investment”); Post-Technical Conference Comments of National Grid USA, filed in Docket No. AD05-3-000,
3
National Grid has a significant interest in the development of reliability policy and the
establishment of NERC as the Electric Reliability Organization (“ERO”) under FPA § 215.
National Grid both will be subject to the new regulatory regime established in FPA § 215 and
will be dependent on that regime to safeguard its customers, business, and assets. In Docket No.
RM05-30-000, National Grid submitted substantial comments4 on the ERO NOPR5 leading up to
the Commission’s Order No. 672.6 National Grid has also submitted substantial comments on
http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=10582423 (May 27, 2005) (“Comments on
Transmission Planning and Expansion to Promote Fuel Diversity”); Comments of National Grid USA, filed in
Docket No. AD05-7-000, http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=10633884 (June 27, 2005)
(“Long-term Transmission Rights Whitepaper Comments”); Comments of National Grid, submitted to the Electric
Energy Market Competition Interagency Task Force, and filed in FERC Docket AD05-17-000, http://elibrary.
ferc.gov/idmws/common/OpenNat.asp?fileID=10887937 (November 18, 2005 with errata on November 22, 2005)
(“Competition Task Force Comments”); Comments of National Grid USA, filed in Docket No. RM05-25-000,
http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=10887032 (November 22, 2005) (“OATT Reform NOI
Comments”); Reply Comments of National Grid USA, filed in Docket No. RM05-25-000, http://elibrary.ferc.gov/
idmws/common/opennat.asp?fileID=10934223 (January 23, 2006) (“OATT Reform NOI Reply Comments”);
Comments of National Grid USA, filed in Docket No. RM06-4-000, http://elibrary.ferc.gov/idmws/
common/opennat.asp?fileID=10924906 (January 11, 2006) (“Initial Comments on Incentive and Rate Reform
NOPR”); Comments of National Grid, filed in Docket Nos. RM06-8-000 and AD05-7-000, http://elibrary.ferc.gov/
idmws/common/opennat.asp?fileID=10972532 (March 13, 2006) (“Initial Comments on Long-term Transmission
Rights NOPR”); Reply Comments of National Grid, filed in Docket Nos. RM06-8-000 and AD05-7-000,
http://elibrary. ferc.gov/idmws/common/opennat.asp?fileID=10990250 (March 13, 2006) (“Reply Comments on
Long-term Transmission Rights NOPR”); Comments of National Grid USA, filed in Docket No. RM06-4-000,
http://elibrary.ferc.gov/idmws/ common/opennat.asp?fileID=10991974 (April 5, 2006) (“Reply Comments on
Incentive and Rate Reform NOPR”); Prepared Technical Conference Remarks of Joel deJesus on behalf of National
Grid USA, Docket Nos. RM05-25-000 and RM05-17-000, http://elibrary.ferc.gov/idmws/common/opennat.asp?
fileID=11155870 (October 12, 2006) (“OATT Reform Prepared Remarks”).
4
Comments of National Grid USA, filed in Docket No. RM05-30-000, http://elibrary.ferc.gov/idmws
/common/opennat.asp?fileID=10836891 (October 7, 2005) (“Comments on the ERO NOPR”).
5
Rules Concerning Certification of the Electric Reliability Organization; Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, 112 FERC ¶ 61,329 (2005) (“ERO
NOPR”).
6
Rules Concerning Certification of the Electric Reliability Organization; Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, 114 FERC ¶ 61,104 (2005) (“Order
No. 672”).
4
NERC’s application to become the ERO, 7 and on NERC’s initial set of proposed mandatory
reliability standards.8
COMMENTS
I.
The Commission Should Refrain from Imposing an Arbitrary and Untested
Interpretation of Bulk Electric System, but Should Instead Allow for Traditional
Interpretations to Continue for a Transition Period.
In each of its many pleadings on reliability, National Grid has raised concerns about the
ambiguity of the definition of bulk-power system in FPA § 215 and has urged the Commission
and NERC to adopt an objective, yet functional interpretation of that term so that the industry
will have fair notice as to which particular facilities the mandatory reliability standards will
apply.9 In the NOPR at PP.60-71, while noting differences between the statutory term and
NERC’s traditional definition of “bulk electric system,” the Commission accepts NERC’s
proposal to continue to use the term bulk electric system for a transition period until NERC and
the industry can develop a more workable approach to interpreting the term bulk-power system
through the reliability standards development process. Although National Grid is very much
interested in locking down a workable approach to identifying the bulk-power system, National
Grid supports this transition period approach given the limited time before the reliability
standards will become effective. Developing a mechanism for identifying facilities that have an
7
Motion to Intervene and Comments of National Grid USA, filed in Docket No RR06-1-000,
http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=11019177 (May 4, 2006) (“Comments on ERO
Certification”).
8
Comments of National Grid USA, filed in Docket No. RM06-16-000, http://elibrary.ferc.gov/idmws/
common/opennat.asp?fileID=11072334 (June 26, 2006) (“Comments on Staff Assessment”).
9
See Comments on ERO NOPR at 4-7; Comments on ERO Certification at 6-9; Comments on Staff
Assessment at 5-8.
5
impact on reliability will require detailed study and investigation to carefully define the
parameters and what they mean to ensure that they work in each region. Accordingly, for a
limited period of time, NERC and the industry will need to work with the traditional definitions
of “bulk electric system” in order to define the scope of the mandatory reliability standards.
Nevertheless, in the NOPR at P.68, the Commission goes beyond the practical proposal
of continuing to use the traditional term bulk electric system for a limited transition period, and
offers a brand new and seemingly arbitrary interpretation of that term:
However, we interpret the term “bulk electric system” to apply to all of the > 100
kV transmission systems and any underlying transmission system (< 100 kV) that
could limit or supplement the operation of the higher voltage transmission
systems. It would also include transmission to all significant local distribution
systems (but not the distribution system itself), load centers, and transmission
connecting generation that supplies electric energy to the system.
The NOPR at P. 69 suggests that this uniform interpretation is needed because NERC’s
definition of bulk electric system is subject to multiple regional interpretations. While National
Grid shares the Commission’s concerns about the lack of standardization in the scope of
reliability standards caused by varying interpretations of what constitutes the bulk- electric
system, for various reasons outlined below, National Grid respectfully submits that the
Commission should not adopt this non-traditional interpretation of the traditional term bulk
electric system. Instead, the Commission should allow the multiple traditional interpretations of
that term to continue for the limited transition period until NERC and the industry can adopt a
standardized approach to implementing the term bulk-power system.
While relying on the traditional definition of bulk electric system for a limited period
makes sense to allow for regulatory stability as the reliability standards transition from voluntary
to mandatory, the addition of a new interpretive gloss to that definition undermines such
stability. While the various regions have all come to different interpretations of the term bulk
6
electric system (which in the long run need to be rationalized), those interpretations were
developed over time, reflect the unique designs and business/regulatory arrangements in those
regions, and are now well settled. The imposition of a new Commission-imposed interpretation
of the bulk electric system would be disruptive to the settled expectations as to the scope of
NERC’s reliability standards. This is a particular concern for regions of the country bordering
Canada because Canadian authorities may not share the Commission’s new interpretation, which
would leave interconnected systems that straddle the border with the possibility of having to
comply with different, if not inconsistent, standards on either side of the border.
The imposition of this new interpretation would also defeat the purpose of having a
transition period. The imposition of this new interpretation of bulk electric system during the
trial period would force NERC and the industry to take the extraordinary steps of conforming
business practices, system design, and other activities to that new interpretation for a temporary
period and then to undertake those steps again after a NERC and the stakeholders arrive at a
permanent approach to implementing the term bulk-power system. This would be inefficient and
would divert resources that would be better spent on developing a permanent solution as
expeditiously and comprehensively as possible.
On the merits, the Commission’s proposed interpretation of bulk electric system would
appear to expand dramatically the scope of facilities covered by that term without really
advancing the goals of reliability. The Northeast Power Coordinating Council (“NPCC”) has
interpreted bulk electric system for years based on an adverse impact test, much like the
Commission’s proposed interpretation, but rarely have the experts at NPCC ever concluded that
facilities below 100 kV would meet that test. Moreover, as reflected in National Grid’s prior
comments, the Commission’s effort to impose a national bright-line voltage test of 100 kV is
7
inappropriate because it fails to reflect the varying system designs that have developed in each
region over time or, therefore, the reliability needs of each region.10
To the extent consistency is the goal behind the Commission’s proposal to impose a
uniform interpretation of bulk electric system, that goal will not be met and may not even be
worthy if applied across the board on an arbitrary voltage basis. There are very legitimate
differences in the power systems between regions that would argue against the application of a
single bright-line voltage test for the continent. A region’s transmission system development
reflects location of load centers, generation facilities, and interactions between adjacent facilities.
It also reflects various market and regulatory structures that have evolved over time. It is not
appropriate and will be detrimental to reliability to ignore those differences in setting the scope
of the mandatory reliability standards through an ad hoc interpretation of the term bulk electric
system based on a brightline voltage distinction. Such an approach could only result in the
diversion of attention and resources away from those facilities that have a direct impact on the
reliability of the interconnected system. Consistency is best achieved by ensuring the process
used to define the scope and applicability of the reliability standards results in consistent and
uniform identification and treatment of system elements that function similarly without regard to
arbitrary distinctions such as voltage.
Also, while a brightline test may lead to ease of administration, the consistency imposed
by such a test does not necessary lead to better reliability. The Commission could strive for
consistency in the process of defining those elements that comprise the bulk-power system,
recognizing that different standards may be required for different classes of facilities within the
10
See Comments on ERO NOPR at 4-7; Comments on ERO Certification at 6-9; Comments on Staff
Assessment at 5-8.
8
definition. The desire for consistency should not result in an interpretation of bulk-power system
that overrides carefully defined (and refined) applicability provisions in various standards that
have been developed over the course of many years. Even if the Commission interprets the term
bulk electric system to apply to facilities at voltages of 100 kV or lower, some rules include
explicit voltage limits that were carefully identified in the standards setting process. For
example, the vegetation management standard FAC-003-1 has a 200 kV threshold. Expanding
the applicability of reliability standards beyond the specific thresholds they contain would not be
appropriate because it could dramatically change the meaning of the reliability standards and
would undermine the standard setting process which yielded the careful balances struck in
developing the standards.
While National Grid would strongly agree that NERC and the industry should work
expeditiously toward a permanent approach to determining the elements of the bulk-power
system, the Commission should not on its own impose a new untested interpretation of bulk
electric system to be applied in the interim. The imposition of such an interpretation would
create a dramatic and unwelcome change in the scope of the reliability standards and would
detract from efforts to achieve a permanent solution. Further refinement of the implementation
of the term bulk-power system should only come about through broad based stakeholder review
that ensures that the term is applied through a consistent process such that the results take into
account the many legitimate differences in the design, operation and use of the grid in each
region.
Given the relative importance of this issue in setting the overall scope of applicability of
the reliability standards, the Commission should provide the ERO substantial guidance for and
oversight over the development of a common approach to identifying the elements of the bulk-
9
power system. Because this task will determine the scope of the reliability standards, the
Commission should set reasonable and timely deadlines for completion of this task and should
ensure that it is given a high priority in NERC’s work plan. For the reasons stated above, the
Commission should also ensure that the end result of NERC’s process is a clear identification of
the elements of the bulk-power system in a manner that reflects their need for reliability. Rather
than an arbitrary brightline voltage test that ignores reliability needs and impacts, the approach
should be geared toward identifying facilities needed to avoid uncontrolled cascading outages
over large portions of the system. With such clear guidance as to the timing and substance of the
task, National Grid is hopeful that the ERO standard setting process will settle promptly on a
workable means of identifying the elements of the bulk-power system.
II.
Enforcement Discretion Should Not Be Limited in Scope or Duration But
Should Extend to Any Situation Where Due Process or Fairness Require the
Exercise of Such Discretion.
Despite numerous comments supporting a phase-in of reliability standards with a trial
period in which violations would not be subject to financial penalties, the Commission proposes
not to adopt any formal trial period. NOPR at P.92. Instead, the Commission proposes to allow
the ERO and Regional Entities to use their enforcement discretion when imposing penalties for
the first six months the reliability standards are in effect. NOPR at P.93.
The Commission
proposes that this enforcement discretion be limited to entities that “have not historically
participated in the voluntary system (including some relatively small entities).” Id. National
Grid respectfully suggests that such a limitation is unwarranted and that enforcement discretion
should apply to any entity that may be subject to novel application of a reliability standard.
The Commission’s stated rationale for limiting enforcement discretion to entities that
have not historically participated in the voluntary system is that such entities “may not be
10
familiar with the proposed mandatory Reliability Standards and what is required for
compliance.” Id. But this rationale applies equally in a number of other situations that may
involve entities that have historically participated in the voluntary system of reliability standards.
For example, if the Commission persists in imposing a new interpretation of the term bulk
electric system, then it is likely that reliability standards will be applied to facilities not
previously covered by current regional interpretations of that term. Moreover, despite concerns
that adoption of the standards that lack specific measures and/or levels of compliance may raise
due process issues,11 the Commission is proposing to make mandatory several proposed
reliability standards that lack such specific measures and levels of compliance (NOPR at P.106).
This means that the first time ERO or a Regional Entity enforces such a standard may be based
on a novel interpretation of the scope of that standard. Similarly, despite concerns raised with
NERC’s functional model not aligning properly with roles and responsibilities identified in
various regional operating agreements (see Part III of these Comments, infra), the Commission
proposes to use NERC’s functional model to identify the entities to which each reliability
standard applies. This means that reliability standards may be applied in a manner that is
inconsistent with existing operating arrangements and delegations of functions in each region. In
each of these examples, reliability standards may be applied to an entity in a manner in which
they had not previously been applied, and regardless of whether that entity had historically
participated in the voluntary system, such an entity “may not be familiar with the proposed
mandatory Reliability Standards and what is required for compliance” as such standards are
applied.
11
See Comments on Staff Assessment at 8 (“There would be no way to foster ex-ante compliance or expost due process if the reliability standards do not include criteria to determine whether an entity is in compliance or
the severity of any violation.”).
11
In short, enforcement discretion to waive penalties should extend to any situation in
which a reliability standard is applied in a novel manner. Such a situation may exist where the
entity had not historically participated in the voluntary program, or when a reliability standard is
applied to facilities or entities not previously subject to the standard under the voluntary
program, or in a “case of first impression,” in which the ERO or a regional entity is called upon
to interpret a reliability standard for the first time (particularly a reliability standard that lacks
specific measures and/or levels of compliance). Given that all users, owners and operators of the
bulk-power system can affect reliability regardless of their size, for-profit or non-profit status, or
past participation in the voluntary reliability standard regime, there is no basis to limit the
exercise of enforcement discretion to a small subset of entities. Rather, the Commission should
allow that discretion to apply in any situation in which an entity lacked sufficient experience
with a reliability standard (or the application of a reliability standard) to be familiar with “what is
required for compliance.”
Even where the enforcement of a reliability standard does not entail a “case of first
impression” or a novel interpretation, there may be instances in which the exercise of
enforcement discretion should be appropriate simply on the basis of due process or fundamental
fairness. For example, some reliability standards are written to require compliance over the
course of multiple years – such as requirements to maintain certain data for a period of years.
When those standards become mandatory upon the passage of a final rule in this proceeding, it
would not be appropriate to enforce such standards retroactively by penalizing entities for acts or
omissions that occurred prior to the effective date of the reliability standards. Another example
in which enforcement discretion is appropriate would be a situation in which compliance with a
new standard (or a new interpretation of a standard) requires a capital project or otherwise takes
12
several months or even years to implement. In these cases, consistent with the current practice
under NERC's voluntary enforcement program, an entity that has initiated a remedy should not
be penalized while the compliance plan or remedy is being implemented.
Finally, this enforcement discretion should not be restricted to “the first six months the
Reliability Standards are in effect” as identified in the NOPR at P.93. Although enforcement
discretion should be used sparingly, it is likely that many of these “cases of first impression”
may continue to arise long after the initial six month period following the effective date of any
new or revised reliability standard. The Commission should recognize that, as part of the ERO’s
ongoing enforcement responsibilities, it will need the flexibility to apply enforcement discretion
in any cases when fairness and due process merits such discretion and not for an arbitrarily
limited time period. Such ongoing enforcement discretion will facilitate settlements of
investigations of alleged violations of reliability standards, which, in turn, will facilitate efficient
administration of bulk-power system reliability, where the ultimate goal is not the assessment of
penalties but is compliance.12
12
In discussing the Commission’s own enforcement policies, Chairman Kelliher recently noted the public
benefits associated with settling enforcement actions:
With respect to Commission enforcement actions, I would expect that in many cases they would
result in settlements. Settlements allow us to stretch our enforcement resources, and conduct
investigations across a wider field. They also benefit consumers, by delivering benefits such as
disgorgement of profits sooner that would be possible under litigation.
Chairman Joseph T. Kelliher's Statement on Process for Assessing Civil Penalties, Docket No. AD07-4-000,
http://www.ferc.gov/press-room/statements-speeches/kelliher/2006/12-21-06-kelliher-M-1.asp (December 21,
2006).
13
III.
While the Commission Should Encourage NERC To Further Refine the
Functional Model, the Commission Should Not Require the Filing or Approval
of the Functional Model or Future Revisions.
National Grid has long raised concerns about the use of the current functional model in
establishing applicability of specific reliability standards. While the model may serve as a
starting point for identifying entities responsible for particular reliability requirements, the
functional categories, their descriptions, and how they are utilized in particular reliability
standards do not align with the allocation of roles and responsibilities adopted in each region,
particularly regions that have RTOs or ISOs. As noted by National Grid,
More fundamentally, the functional definitions offered by NERC appear to
conflict with the operating reality that exists in various regions. For example, the
transmission owners and RTOs/ISOs share various planning functions under
comprehensive operating agreements approved by the Commission. 13
Given these concerns, National Grid has urged the Commission and NERC to continue to
refine the functional model to include the flexibility to accommodate the varying
assignments of roles and responsibilities in each region:
Although National Grid does not have any specific comment arising out of the
Staff Assessment analysis of the TOP standards, National Grid would like to
reiterate concerns raised in its [Comments on ERO Certification] at 13-16 about
the lack of clarity about the responsibilities assigned to the “transmission
operator” function under NERC’s functional model and the TOP standards and
about how those responsibilities are mapped out to entities in the ISO/RTO
regions, in which National Grid owns and operates transmission. . . . To rectify
this concern, the Commission and NERC need to revisit its functional model to
allow for flexibility in assigning transmission owner and transmission operator
responsibilities, or alternatively, the Commission and NERC should carefully
review the TOP standards and other reliability standards to ensure that they
clearly distinguish requirements that are incident to transmission ownership from
those that are truly a part of transmission operations. 14
13
See Comments on ERO Certification at 13-16.
14
See Comments on Staff Assessment at 21-22.
14
In the NOPR at PP.44-48, the Commission found that the functional model “provides a
useful level of detail and appears to be more practical than simply identifying an applicable
entity as a user, owner, or operator,” and it proposes “to use” the functional model to identify the
applicable entities to which each reliability standard applies.
Notwithstanding this
endorsement, the Commission indicated that it was “mindful of the concerns of certain
commenters that the Functional Model may contain ambiguities or omit certain entities or
functions” and was “proposing to require NERC to specifically address these concerns.” The
Commission further proposed to require “the ERO to submit any future modifications to the
Functional Model that may affect the applicability of the Reliability Standards for Commission
approval.”
While National Grid supports the Commission’s resolve to have NERC continue to
further refine its functional model for the reasons stated above, the Commission should not take
the next step and mandate approval of the functional model itself or proposed changes to it
because such a step would hinder efforts to improve the functional model. The principle concern
with the functional model is that it currently is not flexible enough to reflect the varying roles
and responsibilities in each region. What constitutes TOP responsibilities in NERC’s functional
model does not match up with the responsibilities of actual transmission operating entities in any
given region, and, in fact, those responsibilities may vary from region to region. The same is
true for other functional categories (TP, TO, etc.) as well. While a particular reliability standard
should not vary significantly from region to region (except under approved regional differences),
the entities responsible for meeting such standard will vary from region to region. Aside from
the flexibility to reflect differences among regions, there is also a need for the functional model
to be flexible over time as operating arrangements change. As the industry works to refine the
15
functional model, that flexibility will be of paramount concern. Any requirement to file and
approve the functional model or proposed changes to the model will work against this flexibility
by hardwiring a specific model and requiring the Commission to endorse a single allocation of
roles and responsibilities across the country, even if the stakeholders in a particular region have
agreed to and adopted an alternate allocation of roles and responsibilities.
While the Commission will certainly need to understand the functional model in
interpreting specific reliability standards proposed by the ERO for approval, the Commission
need not approve the functional model independently of approving such proposed reliability
standards. While the functional model is an important guideline for drafting individual
reliability standards, ultimately the applicability of provisions of each such standard should be
the key determinant of whether that standard should be approved and how such standard should
be enforced. In fact, approving changes to the functional model in isolation could lead to
unintended consequences, because such approval could have the legal affect of “cascading”
changes throughout the applicability sections of each of reliability standards. Approval
“upfront” of the applicability of the reliability standards via the functional model may conflict
with the specific applicability provisions in each reliability standard. In other words, if the
Commission were assume the role of approving changes to the functional model, it would
require a reevaluation of all of the reliability standards at the same time and could ultimately
subvert the ERO standard setting process.
In short, the Commission should require NERC to further refine the functional model,
with an eye toward making it a flexible reference tool for drafting future standards, but the
Commission should not approve the functional model in its current form or require the approval
16
of future changes to the functional model. Rather the Commission should continue to evaluate
the applicability sections of individual reliability standards on their own merits.
IV.
The Commission Should Use Caution in Approving “Incomplete” Reliability
Standards and in Suggesting Revisions to Proposed Reliability Standards under
FPA § 215(d)(5).
As reflected in the NOPR at PP.7-8, the Commission proposes to accept most of
NERC’s proposed reliability standards, despite a recognized need for improvement of many of
those standards. To address deficiencies in such reliability standards, the Commission proposes
to exercise its authority to “direct” modifications, in lieu of remanding such standards to the
ERO’s standard setting process under FPA § 215(d)(4). The Commission justifies this approach
in part based on the fact that the industry is in “a period of transition from a voluntary to a
mandatory system of compliance” and based on the Commission’s desire to have mandatory
reliability standards in place by Summer 2007. See NOPR at P.8. Under these unique
circumstances, the approach taken by the Commission in this NOPR may be appropriate.
Nevertheless, as the Commission, the ERO, and the industry gain experience with the
mandatory reliability standards regime, National Grid would caution the Commission against
routinely approving reliability standards that are acknowledged by the Commission to be
incomplete. As noted above (see supra n.11), enforcement of standards that lack clear measures
and/or levels of compliance raises significant due process concerns, and the Commission should
allow for the ERO to exercise enforcement discretion in applying penalties for violations of
incomplete or unclear reliability standards. The lack of clear measures or levels of compliance
also makes it difficult for users, owners, and operators to tailor their businesses and practices
toward compliance or to track ongoing compliance. Moreover, the Commission could
undermine the discipline of the reliability standards setting process if the Commission were to
17
signal that its normal approach to addressing incomplete standards would be to accept them and
“direct” specific modifications. Such a signal may encourage stakeholders to avoid tough
decisions in the standard setting process and may further diminish the quality of reliability
standards proposed by the ERO.
While the Commission can and should provide welcome guidance to the ERO and the
industry in identifying improvements in proposed reliability standards, the Commission should
use caution in the exercise of its authority to order the submission of reliability standards and
modifications under FPA § 215(d)(5). The Commission should be mindful that FPA § 215 was
carefully written in a manner to ensure that the drafting of reliability standards remained the
province of the industry stakeholders and the ERO and relied substantially on the expertise of
those entities. If the Commission were to “direct” modifications under FPA § 215(d)(5) either
too prescriptively or too frequently, such a practice would not be consistent with the general
structure or intent of FPA § 215.
Moreover, from a policy perspective, the Commission would be best served by providing
general guidance on how to improve certain reliability standards with its exercise of FPA §
215(d)(5), while relying on the stakeholders in the standard setting process to determine how
best to incorporate that guidance into revised standards. Just as there are multiple ways to meet
the “just and reasonable” standard under FPA §205,15 there are multiple ways to meet the
statutory test for approving reliability standards under FPA § 213(d)(2) (which provides that
reliability standards must be just and reasonable, not unduly discriminatory and preferential, and
15
See Belco Petroleum Corp. v. FERC, 589 F.2d 680, 689 (D.C. Cir. 1979) (“[a] just and reasonable rate is
not a product of any single formula, but is instead a rate within a broad ambit of various rates which may be just and
reasonable.”), citing Permian Basin Area Rate Cases, 390 U.S. 747, 767 (1968); FPC v. Hope Natural Gas Co., 320
U.S. 591, 602 (1944); FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 585-86 (1942).
18
in the public interest). A less prescriptive approach by the Commission would allow the experts
at NERC and industry stakeholders to consider alternative approaches that may lead to better
standards. A more general (and less prescriptive) exercise of FPA § 215(d)(5) would allow for
freer stakeholder discussions and would facilitate better international coordination. A less
prescriptive approach will also allow stakeholders to take into account cost considerations in
choosing among alternatives to resolve issues identified by the Commission.16
In short, while the Commission’s proposal in the NOPR to accept admittedly incomplete
standards and to “direct” modifications under FPA § 215(d)(5) may be appropriate as an initial
transition manner, the Commission should not adopt either as a regular practice.
V.
The Commission Should Recognize that There Remain Important Regional
Requirements that Regional Reliability Organizations Should Continue Fulfill.
In the NOPR at P. 56, the Commission expresses doubts as to whether regional reliability
organizations are proper subjects of reliability standards because such entities are not technically
“users, owners or operators” of the bulk-power system. While there may be merit in that view,
National Grid would respectfully urge the Commission not to carve regional reliability
organizations out of the reliability compliance picture completely. Although the regional
reliability organizations are applying to become regional entities under FPA § 215(e)(4), the
compliance of such entities with requirements that are regional in scope is critical to achieving
and maintaining the region’s overall reliability and compliance with reliability standards.
16
As standards evolve and the industry has more experience, there will naturally be opportunities to
compare best practices and stakeholders will need to weigh more options in ensuring greater reliability. A process
needs to be put in place to ensure that the development of all new or modified standards adequately addresses both
the reliability improvement the standard purports to bring about and the resource requirement required to implement
the standard. This is critical to ensure that the statutory requirement of the standards to provide for reliable operation
as defined in the statute is satisfied while not squandering resources on supposed improvements with little
demonstrable impact on the reliability of the interconnected system.
19
Although the Commission is holding in abeyance 28 proposed reliability standards that
apply to regional reliability organizations based on the Commission’s assumption that such
entities technically would not be “users, owners, or operators,” the Commission should recognize
the historic and ongoing role that such entities fill in ensuring reliability at a regional level. As
noted by the Commission in the NOPR at P.57, such entities serve important “data gathering,
data maintenance, reliability assessments and other ‘process’-type functions.” With respect to
PRC-002-1, which requires regional reliability organizations to maintain regional databases
concerning special protection systems, the Commission specifically found that “we agree with
National Grid that the database should be maintained on a regional basis.” NOPR at P. 909.
Accordingly, while reliability standards can be rewritten to ensure that they are applicable to
specific “users, owners, and operators,” the Commission should not lose sight of the real need
for regional reliability organization administration of and compliance with regional
requirements.
Although regional reliability organizations may not be proper subjects of reliability
standards, the role of regional reliability organizations can be preserved in a variety of ways. For
example, obligations currently imposed upon regional reliability organizations could be included
in the regional delegation agreements entered into under FPA § 215(e)(4) in the proceedings in
which such organizations petition to become regional entities.17
17
See Notice of Filings, Docket Nos. RR06-1-004, RR07-2-000, RR07-3-000, RR07-4-000, RR07-5-000,
RR07-6-000, RR07-7-000, RR07-8-000 (December 4, 2006) (notice of regional delegation agreement filings).
20
VI.
The Commission Should Adopt a Formal Mechanism for Coordinating
Reliability Standards Approvals with Foreign Officials.
In the NOPR at PP. 94-95, the Commission recognizes the importance of international
coordination, but proposes to rely on NERC to coordinate approvals and existing informal lines
of communications, such as the US – Canada Bilateral Electric Reliability Oversight Group.
National Grid respectfully urges the Commission to undertake a more formal mechanism for
coordinating approvals of and modifications to reliability standards.
The grid in the Northeast part of the US is strongly interconnected with the adjacent
Canadian provinces and differences in reliability standards could have the effect of diluting the
effectiveness of a proposed standard to the detriment of reliability in the Northeast. In this
respect, lack of uniformity between a state and a province might actually be a worse situation for
reliability than lack of uniformity from state to state. National Grid has a strong interest in crossborder reliability issues because of its interconnections with Quebec and Ontario.
The problem is compounded as the Commission develops its own interpretations of longstanding terms, such as “bulk electric system” (as discussed above in Part I of these Comments),
and seeks to “direct” modifications of reliability standards under FPA § 215(d)(5) (as discussed
above in Part IV of these Comments). Where similar interpretations and modifications are not
adopted by the provincial authorities in Canada, there is potential for conflicting requirements
for interconnected facilities. For example, the problems associated with the Commission’s
proposal to impose its own interpretation of bulk electric system are exacerbated by the fact that
there likely will not be corresponding changes for the interconnected systems in Canada.
Although there may be legitimate bases for having different rules apply to different parts of the
grid, differences applied without careful and coordinated deliberation are not likely to enhance
reliability and may undermine reliability.
21
Reliance on NERC alone for coordination is not enough. Regardless of NERC’s efforts
to undertake shuttle diplomacy between and among this Commission and the provincial
authorities, the Commission and the provincial authorities have the ultimate say in approving
applicable reliability standards. As evidenced in the NOPR, this Commission and presumably
the provincial authorities will have significant authority to interpret standards and seek changes
to standards, which will beyond NERC’s control. In short, coordination will not be credible or
serve reliability unless the regulators themselves commit to coordination through a formal
mechanism, such as a multilateral memorandum of understanding that is binding on all
regulatory authorities.
VII.
Miscellaneous NOPR Issues
a. The Commission Should Affirmatively Endorse Event-Based Planning.
(NOPR at PP.1049-50)
As noted in National Grid’s Comments on Staff Assessment (cited more fully supra at
n.8), event-based planning is a more robust form of contingency analysis than element-based
planning because the former focuses on contingencies regardless of how many system elements
may be affected and the latter focuses on losses of specific elements which may not have a direct
relationship to the severity of the impact on or risks to reliability.
In the NOPR the
Commission appears to endorse event-based planning:
The Commission notes that entities with planning responsibility for
approximately half of the load in the nation analyze contingencies based on the
actual number of elements that would be removed from service in the actual
power system for an unanticipated failure of system elements, rather than
simulating only the outages identified in Table 1. Simply put, the Commission
believes that the simulations should faithfully duplicate what will happen in the
actual power system and not a generic listing of outages. In addition, the BulkPower System must be operated and planned to be operated within a number of
conditions after a contingency or cyber event. The Contingency can be a sudden
disturbance or unanticipated failure of any system element. If a specific portion of
22
the system has been designed such that the response to a failure results in multiple
lines, transformers, generators, circuit breakers, etc., being removed from service,
then the Commission proposes that this is what should be simulated.
NOPR at PP. 1049-50 (emphasis added).
Nevertheless, because the Commission does not
explicitly state its support for event-based planning, the Commission should make its position
clear in the final rule.
Notwithstanding the language in the NOPR that appears to endorse event-based planning,
the NOPR also includes language that appears to undercut that endorsement. For example, the
NOPR at P.1049 states: “To achieve this objective, planning standards should promote system
designs that result in the minimum set of elements being removed from service for ‘unanticipated
failures of system elements.’” This sentence could be construed to be an endorsement of
element-based planning. To eliminate this ambiguity, the Commission should clarify that this
sentence is not an endorsement of element-based planning, but rather a retelling of the principle
that “standards must influence system design and not the other way around.” As described in the
bulk of paragraphs 1049-50, event-based planning is better reflective of reality and the types of
contingencies (and various combinations of element faults) that may occur. The Commission
should state with clarity its support for event-based planning,
b. The Commission Should Continue To Push for Longer Planning Horizons,
but Should Recognize that Obtaining Accurate Generation Resource Siting
and Retirement Information Remains a Concern. (NOPR at P.1060)
In NOPR at P.1060, FERC asks whether transmission planners are able to obtain and
validate resource information on new generation and retirements for assessments over the ten
year planning horizon. National Grid respectfully submits that obtaining this resource data has
been a challenge, but would urge the Commission to support longer planning horizons.
23
In many respects, the ten-year planning horizon may be too short a timeframe for
assessing transmission needs, particularly with regard to long-distance high-voltage facilities that
pose considerable siting and permitting challenges. Establishing planning horizons that are
shorter than transmission lead times may create “gaps” where the identification of a reliability
need to which transmission may be the best solution occurs too late to head off the identified
reliability violation. This often requires the region to resort to stopgap measures, such as
reliability must run contracts, which can be expensive to customers, undermine markets, and act
as an incentive to delay difficult-to-site transmission upgrades even after they have been
identified in the planning process as the optimal solution. PJM is attempting to address this
problem by establishing a fifteen-year planning horizon that will accommodate large-scale
projects that are needed for reliability and to support regional transactions.18 National Grid,
therefore, respectfully urges the Commission to support longer planning horizons and to ensure
that reliability standards do not supersede planning horizons longer than ten years where such
practices are adopted by particular regions.
While sufficiently long planning horizons are critical to staying ahead of transmission
lead times, it is also vital that planners have sufficient information about the system for which
they are planning upgrades. Forward capacity markets, for instance, and the generation
interconnection queue provide some understanding relative to the location of new generation
18
See PJM Interconnection LLC, 115 FERC ¶ 61,079 at P.87 (2006) (“Lastly, we strongly encourage PJM
to continue its efforts in reforming its regional transmission planning process in order to better coordinate RPM with
RTEP, and to provide incentives for construction of bulk lines that serve as a backbone of the transmission system.
Although we believe that forward procurement provides a much better solution to RTEP integration than the current
generation interconnection procedures, which are subject to high levels of project withdrawals, generation and
transmission planning processes must be better coordinated. In its answer, PJM stated that the first component of
transmission reform, extending the planning horizon for reliability baseline additions from the current five years to
as much as fifteen years (depending on the project), has already been approved by the PJM Reliability Committee
and incorporated in the RTEP process beginning January 1, 2006.”).
24
entry, but such constructs generally only provide insight for five to seven years, even though
transmission planning horizons are (and should be) considerably longer. Though its is not
always clear precisely where new entry will occur, it may be reasonable in some instances to
conclude that certain areas are prime locations for new resources, particularly inexpensive or
renewable resources, that are dependent on “non-transportable” fuel supplies. Parts of West
Virginia, Kentucky, and Wyoming are just such areas where considerable interest has been
expressed by generators. There are other reasonably identifiable locations of generator sites,
such as areas of high wind potential or coal mine-mouth areas, which should be considered in the
transmission planning process even in the absence of specific interconnection requests. While
transmission planners should avoid “picking winners and losers,” they should not ignore the
reasonably calculated benefits to customers that increased access to these areas would provide. 19
It is also vitally important to acknowledge that generation retirements may pose a greater
threat to reliability in some areas of the country than the slow down in new entry. Indeed, this is
one of the principle reasons PJM proposed its reliability pricing model. 20 While such measures
are helpful, they have not proven to be adequate on their own to avoid threats to reliability posed
by large-scale generator retirements. As required notice periods for such retirements may be as
little as 90 days in some areas, it is imperative that transmission planners use robust statistical
approach to identifying sub-regions or localities where a significant portion of the generator
19
The “chicken and egg” problem produced by the inability of the initial generators in remote regions to
fund large transmission projects that would later attract more supply to area for the benefit of customers has been
widely discussed. Indeed, CAISO has written a white paper proposing to establish a third category of transmission
to remedy this market failure. See California ISO, “Proposal to Remove Barriers Efficient Transmission
Investment,” http://www.caiso.com/1879/18799b184b440.pdf (Revised September 21, 2006). The Commission
should embrace efforts of transmission planners to facilitate new entry when such initiatives are expected to increase
customer access to inexpensive, renewable and diverse sources of supply.
25
stock is aged or whose continued profitable operation is vulnerable to new environmental
legislation. Such modeling should be conducted as an integral part of the transmission planning
process in order to anticipate retirements over horizons that cover transmission lead times and to
promote the construction of needed upgrades when projected generator retirements are expected
to pose a threat to reliability.
c. N-2 Planning Should Not Be Imposed as an Across the Board Requirement
for All “Major Load Pockets” under TPL-003. (NOPR at P.1099).
In NOPR at P.1099, FERC asks whether there should be an explicit requirement in TPL003-1 that the portions of the bulk-power-system in major load pockets to be planned and
operated in such a way as to withstand two simultaneous contingencies for major load pockets.
We respectfully suggest that this type of “N-2 planning” is not necessary as an across the board
requirement.
Although the Commission cites two specific areas in which N-2 planning occurs (NOPR
at n.332), many other regions are planned and operated in accordance with the “N-1-1 planning”
provided for in Category C3 of TPL-003-1 – or as the Commission describes, “a situation in
which two single contingencies occur, with manual system adjustments permitted to prepare for
the next one.” NOPR at P.1099. In National Grid’s experience, N-2 planning may not be
necessary in regions designed to accommodate contingencies on an N-1-1 basis. N-2 planning
is usually relied upon when a particular area does not have the resources or flexibility to adopt
N-1-1 planning. In operations, the N-1-1 paradigm is more flexible and affords the operator
extra time, usually on the order of 30 minutes, to make system adjustments to withstand the next
20
See PJM Interconnection LLC, 115 FERC ¶ 61,079 at P.31 (2006) (“According to the affidavit of Steven
Herling on behalf of PJM, which no party has disputed, multiple reliability criteria violations in PJM, particularly in
New Jersey, have occurred recently due to generation retirements.”)
26
contingency rather than forcing an immediate remedial action, such as shedding load. The bulkpower system in every region is designed differently, and there is no need to impose N-2
planning where regions are satisfactorily implementing the N-1-1 paradigm.
Moreover, the imposition of a new N-2 requirement as proposed by the Commission may
be difficult to administer. There is no record in this proceeding as to how to define “major load
pockets.” As load pockets and their boundaries change with the dynamically changing system
and load patterns, it is difficult to establish or administer a rule that encompasses the particular
sub-regions to which such an N-2 requirement would be applicable.
d. Planning for Cyber-Security Incidents Is Most Appropriately Covered in
TPL-004. (NOPR at P.1051)
In NOPR at P.1051, the Commission asks whether planning for cyber-security incidents
should be addressed in the planning standards (TPL) or in the critical infrastructure (CIP)
standards. As planning for cyber-security incidents will require analysis of system impacts, the
standards for such planning are most appropriately addressed in the planning standards –
particularly TPL-004.
With that said, the inclusion of cyber-security planning in the planning standards should
not preclude the standard setting process from developing or NERC from adopting standards
related cyber-security in other sections of the reliability standards. For example, provisions
detailing specific cyber-security protections should be addressed in the CIP standards and
emergency procedures for response to cyber-security events should be addressed in the EOP
standards.
27
e. A Uniform Data Retention Requirement Should Be Established and
Coordinated with Other Records Retention Requirements Established by the
Commission. (NOPR at P.107)
In the NOPR at P.107, the Commission seeks comment on data retention requirements
specified in various reliability standards. National Grid respectfully suggests that a single data
retention period be established for all data required under the reliability standards. At this stage
no record has been established for varying the retention period on a standard-by-standard basis,
and there is no apparent technical reason for doing so. For ease of administration, a single
retention period tied to the five-year statute of limitations for civil penalties (see NOPR at n.83,
citing Order No. 672 at P.487) is appropriate.
In establishing this single retention period, the Commission should be mindful that a
number of record retention requirements may already apply to data covered under reliability
standards. Aside from the five-year requirement associated with market-based sales noted by the
Commission in the NOPR at n.83, the Commission recently established new record retention
requirements for holding companies and service companies, which requirements conform to the
requirements already in place for electric utilities.21 These more general record retention
requirements include transmission operator, facilities, and engineering information which may
also be covered by data retention requirements related to the reliability standards.
In cases of
conflicting record retention requirements, the Commission should make clear that the longest
21
See 18 C.F.R. § 368.3; Financial Accounting, Reporting and Records Retention Requirements Under
the Public Utility Holding Company Act of 2005, Order No. 684, 117 FERC ¶ 61,064 (2006); see also 18 C.F.R. §
125.3.
28
applicable record retention requirement governs the handling of any document or particular set
of data.22
CONCLUSION
National Grid respectfully requests that the Commission consider the foregoing
Comments in its deliberations in this proceeding.
Respectfully submitted,
/s/
_
Joel deJesus
Assistant General Counsel, Federal Affairs
National Grid USA Service Co., Inc.
633 Pennsylvania Avenue, NW
Washington, DC 20004
(202) 783-7959
Attorney for National Grid USA
January 3, 2007
22
See 18 C.F.R. § 368.2(a)(5) (“To the extent that any Commission regulations may provide for a different
record retention period, the records must be retained for the longer of the retention periods.”); 18 C.F.R. §125.2
(a)(3) (same).
29