UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
I/M/O Petition of the North American Electric Reliability Corporation for Approval of a Revised Definition of “Bulk Electric System” in the NERC Glossary of Terms Used in Reliability Standards
Docket No. RM12-6
I/M/O Petition of the North American Electric Reliability Corporation for Approval of Revisions to its Rules of Procedure to Adopt a Bulk Electric System Exception Procedure
Docket No. RM12-7
Comments of the New England States Committee on Electricity
Pursuant to the Commission’s June 22, 2012 Notice of Proposed Rulemaking (“NOPR”) in the above-captioned dockets, the New England States Committee on Electricity (“NESCOE”) submits these comments.
The names, titles, and offices of the persons to whom correspondence should be addressed are as follows:
New England States Committee on Electricity
655 Longmeadow Street
Longmeadow, MA 01106
Elizabeth A. Grisaru
Whiteman Osterman & Hanna
One Commerce Plaza
Albany, NY 12260
* Person designated for service
NESCOE is the Regional State Committee for the New England region. NESCOE is governed by a board of managers appointed by the Governors of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. It is funded through a regional tariff administered by ISO New England, Inc. (“ISO-NE”).1 NESCOE’s purpose is to represent the interests of the New England citizens by advancing policies that will provide electricity at the lowest possible price over the long term, consistent with maintaining reliable service and environmental quality.
On June 22, 2012 the Commission proposed to approve two filings made by the North American Electric Reliability Corporation (“NERC”) in response to Orders Nos. 743 and 743-A. The filings proposed changes to NERC’s definition of “bulk electric system,” which establishes the scope of the facilities subject to NERC reliability standards, and revisions to certain rules of procedure. NESCOE submitted comments to NERC in the course of the development and drafting of NERC’s proposals.2 NESCOE’s comments to the drafting team highlighted the New England states’ concern that the application of the revised definition and exceptions procedure could result in classifying facilities as BES that are not necessary for reliable operation, with a resulting adverse impact on New England ratepayer costs. The proposals that NERC has now submitted do not adequately address NESCOE’s concerns.
A. THE COMMISSION SHOULD NOT APPROVE THE REVISED BES DEFINITION ABSENT TECHNICAL JUSTIFICATION FOR THE THRESHOLD 100 KV BRIGHT-LINE LEVEL.
In the NOPR, the Commission sought comment on “how NERC’s proposal adequately differentiates between local distribution and transmission facilities in an objective, consistent, and transparent manner.”3 The Commission properly acknowledged in the NOPR the existence of limits on NERC’s authority and focused on the language and procedures in NERC’s proposals that are intended to avoid applying bulk electric system (“BES”) standards to distribution facilities.4 However, for the reasons described below, NERC’s approach is likely to result in the misclassification of facilities, at potentially significant costs in terms of both dollar investment and time.
In particular, NERC’s proposal provides no technical justification for relying on the brightline approach. NERC itself acknowledged in the drafting process that the time constraints imposed by Order No. 743 forced it to defer the development of technical support for the proposed revisions, including the justification for the 100 kV threshold.5 NESCOE recognizes the firm deadline set by the Commission for revising the BES definition and NERC’s need to meet the compliance date. However, deferring development of the technical justifications supporting the threshold values is a flawed approach, particularly in light of Congress’ direction that the Commission and NERC ensure the jurisdictional distinction between transmission and distribution facilities.6
Moreover, without a technical justification for the threshold, the Commission does not have sufficient information to determine that the proposal is “just, reasonable, not unduly discriminatory or preferential, and in the public interest” – the standard of review applicable to submissions by the Electric Reliability Organization.7 NERC’s approach does not allow the Commission to determine whether the costs imposed on ratepayers are justified by increased reliability benefits. The Commission should not approve the revised BES definition without the proper supporting technical justification.
B. THE PROPOSED “EXCEPTIONS PROCEDURE” DOES NOT ADEQUATELY GUARD AGAINST THE RISK OF OVER-INCLUSIVENESS AND FAILS TO ACCORD THE STATES A MEANINGFUL ROLE
NERC’s decision to delay developing technical justifications to another drafting process has the effect of heightening the importance of the exemption procedure, which provides the only mechanism to correct a misclassification. The Commission, in Order Nos. 743 and 743-A, recognized the need for a procedural mechanism to review potential cases where that threshold might be over or under-inclusive.8 The Commission has appropriately recognized that an effective and transparent process for carrying out such reviews is an essential corrective to the potential overreach of the bright-line rule, helping to resolve questions about the relationship of particular facilities to the bulk transmission system.9 While NERC’s proposed changes to its Rules of Procedure (“ROP”) are a good starting point, the proposed process is flawed in several areas. The ROP should be modified in the manner described below to ensure that it achieves the proper balance between efficiency and transparency. 10
1. The ROP should ensure that the States have a Meaningful Opportunity to Participate
NESCOE’s primary concern is that NERC’s proposal does not give States an opportunity to participate directly in the process, when they might choose to do so. The Commission should recognize that the potential for jurisdictional issues requires State participation in both the development and review of possible exceptions. Without state participation, NERC will not address the full range of substantive concerns that may arise in any given case, and, if the Commission is asked to review an exemption determination, the record presented will not reflect the States’ views.
In its comments to NERC on the ROP draft, NESCOE requested that States, at minimum, be provided (i) notice of an exception request, (ii) notice of the applicable Regional Entity’s recommendation regarding such request, and (iii) an opportunity to review the exception related information and to submit comments to the Regional Entity during its review and, later, to NERC following the Regional Entity’s recommendation. However, while NERC appropriately revised its rules to enhance the role of planning authorities and other entities, the procedure still does not provide for State input in the consideration of proposed exceptions. This gap arises because the proposed changes to the ROP do not require notice to the potentially interested States at the beginning of the process. Without timely notice of an exception request, State regulatory authorities will have less ability to react to the issue being raised, even simply to determine whether and to what extent to express concern or support a particular request. In a case where a State might have serious concerns, the State may not learn about the request until it is too late to provide a considered response.
The Commission should correct this failure by directing NERC to amend the ROP to ensure that relevant state regulatory authorities receive the same notice and access to information as Planning Authorities and other entities. States should also have the same right to provide comment and input to a Regional Entity as the ROP provides to other stakeholders. States should receive timely notice of a Regional Entity’s recommendation and an opportunity to submit comments to NERC. Finally, States should have the right to appeal a NERC determination to the Commission so that jurisdictional questions are addressed directly by the relevant parties.
NESCOE is also greatly concerned that the proposed ROP continues to lack a mechanism for a state regulatory authority to initiate review of the classification of an element. States have an undeniable interest in the proper classification of BES facilities. However, States will not always be in a position to submit an exception request because they lack the detailed information required for a submission under the proposed ROP. NESCOE suggests that this flaw can be remedied by allowing a State to request a review from the relevant Regional Entity and to require the Regional Entity to submit a formal Exception Request if it finds that the classification is inaccurate. A State should also have a right to seek review from NERC of the Regional Entity’s determination; as drafted, the procedure does not give States this opportunity.
Meaningful State participation in the exceptions process can reduce the risk of jurisdictional conflicts between the Commission and State regulators. Without the opportunity for active state participation, the exceptions process risks delegating to a technical panel what are essentially jurisdictional determinations, without input from the very parties whose jurisdiction Congress explicitly preserved. For these reasons, the Commission should require NERC to revise its proposed changes to its ROP to provide a greater opportunity for state involvement.
2. The Proposed ROP Changes Require Modifications to Increase Efficiency
NESCOE supports NERC’s efforts to develop an exceptions process that is as efficient as possible, while allowing decision-makers to reach well-supported resolutions in a reasonable amount of time. However, the NERC proposal does not fully meet this standard. Rather, the process it enshrines is, in some areas, unnecessarily burdensome and redundant and likely to consume excessive time and resources. For example, a Regional Entity is required to develop a recommendation on an Exception Request, including convening a technical review panel.11 In the second step, NERC convenes another group of technical experts and conducts its own review of the application. This two-level review does not distinguish between “easy” and “hard” cases and thus will likely result in unnecessary delays. Further, NESCOE does not see any need for lengthy reviews of exceptions at both levels unless there is a dispute as to the Regional Entity’s finding.12 If all parties (including the relevant state regulators) accept the Regional Entity’s recommendation, NERC’s only role should be to assess the consistency of that result with its prior determinations.13 The Commission should direct NERC to revise the exceptions process to allow for thorough consideration at the Regional Entity level and prompt disposition of objections and consistency determinations at NERC.14
The ROP changes, as proposed, could also lead to unnecessary costs being passed to consumers if asset owners are forced to incur significant compliance expenditures before objections to the inclusion of a facility in the BES are finally addressed.15 When a Regional Entity recommends keeping an element in the BES or adding a new element to the BES, it is reasonable to require an implementation schedule. If there is no objection to the recommendation, NERC may also reasonably require compliance with that schedule. However, barring an identified imminent reliability risk, when a party seeks NERC’s review of the Regional Entity’s action, the asset owner should not be faced with compliance expenditures and potential penalties until after NERC has made its final determination. Otherwise, owners and ratepayers will be exposed to investment costs that may not actually be necessary. The Commission should require NERC to revise the ROP to make clear that owners will not be required to implement the proposed schedule so long as an objection to the inclusion is pending.16 NESCOE understands that there may be unique circumstances in which a specific risk to reliability requires action before all reviews can be completed. NESCOE would support language in the ROP that would obligate an asset owner to take steps in such a case, upon a determination by NERC that action was necessary pending the outcome of the exception request.
C. Technical Comments.
In the NOPR, the Commission sought comments on aspects of the revised definition and proposed certain scenarios, raising questions about what lower-voltage configurations should be classified as part of the BES. NESCOE shares the Commission’s concern that the boundaries of what is included in the BES be delineated as clearly as possible, to avoid the expenses associated with over-inclusion. Consistent with this approach, rather than expand the scope of the BES, one solution to the Commission’s concern could be to ensure that regional planning standards require the modeling of certain lower-voltage facilities and networks in planning and operational studies. Modeling these facilities and networks will provide system operators with up-to-date information about their reliability impacts. This is already the case in New England, where facilities rated at 69kV and above are included in the “Pool Transmission Facilities” that the ISO models in its studies.17 With this approach, the Commission can enhance system reliability without imposing unnecessary compliance costs on ratepayers.
NESCOE offers the following additional comments responding to the Commission’s discussion at specific paragraphs of the NOPR.
NOPR at P 63: As the Commission notes, the proposed BES definition is accompanied by several “inclusions” intended to clarify the scope of the definition. Inclusion I1 would classify all transformers having a primary and at least one secondary winding operating at 100 kV or higher as part of the BES. NESCOE does not believe the Commission should expand the definition to include transformers that have a primary terminal at or above 100 kV with all secondary terminals operated below that level.
NESCOE observes that many of the transformers in New England fall into this category, most of which are used to supply local networks rated at voltages of 46kV and below. These local networks have no significant impact on the reliability of the bulk electric system, and therefore the generic inclusion of these transformers in the BES definition would risk imposing unnecessary and unjustified costs on ratepayers. At the same time, planners in the regional entities should model these types of transformers and the associated local networks. If a reliability issue affecting the BES emerges from those planning studies, then the transformers and local networks should be considered for inclusion under the “exceptions request” process. NESCOE encourages the Commission to view these transformers as appropriate for such a caseby-case evaluation.
NOPR at P 65: The Commission also sought comment on the potential inclusion of generators connected to the BES by two transformers in series where only the second transformer operates at 100 kV or above. The New England system includes many instances of 115 kV substations where step down transformers reduce the voltage to a “subtransmission” or local network level of 46 kV and lower. At some substations, generation is connected via transformers that step up the voltage to that of the local network level. The primary use of these generation resources is to serve local load connected at the local network level often only under heavy load conditions while the connection to the 115 kV level provides a source of economic power to the local network as well as stabilize the local network. These resources are connected to a local network that operates at voltages below 100 kV, and, thus, should be excluded, though subject to individual inclusion through the exception process. Furthermore, NESCOE believes that most of the 115 kV networks that these lower voltage networks are connected to qualify as local networks, as discussed below.
NOPR at P 68: The Commission asked whether the deletion of cranking paths from the BES resulted in a reliability gap, and further asked for comment on the role of the States in ensuring that blackstart power is delivered through cranking paths to restart the system. NESCOE does not agree that excluding cranking paths from the BES creates a general reliability gap. Furthermore, these facilities are generally part of the distribution system and fall within State jurisdiction. State regulators bear direct and immediate responsibility for ensuring the reliability of these lower voltage facilities and are acutely aware of the importance of effective blackstart capability. Finally, these facilities are required to operate only in restoration scenarios and are not needed for continuous operation. Imposing BES standards on these cranking paths adds significant cost with no commensurate reliability benefit to New England ratepayers.
NOPR at P 71: The Commission sought comment on the inclusion of facilities whose purpose is to aggregate power from dispersed resources. As a general matter of policy, NESCOE cautions against a blanket rule including dispersed power resources with an aggregate power of less than 300 MVA in the BES. As NESCOE explained in its comments to NERC filed in October 2011, extending the definition to include all such resources—absent a clear reliability risk—may have an adverse impact on State policies fostering the development of renewable generation by imposing additional costs.18 For these reasons, proposed Inclusion I4 must avoid imposing costs on facilities that do not have a significant impact on reliability. NERC’s proposal does not meet this standard.
The NERC proposal to exclude only an aggregate of less than 75MVA is not supported by technical analysis. These dispersed resources are intermittent sources of power and as such deliver only a fraction of their nameplate value to the transmission system. Industry planners rarely assume the full nameplate value of such resources in planning and operating studies relating to reliable operation of the BES. Thus, using the 75 MVA gross aggregate nameplate rating is not based on a realistic assumption of these resources’ impact. An appropriate and substantiated threshold value should be related to the largest contingency to which the applicable control area is designed to operate. Implementing I4 as proposed would impose compliance costs on these renewable sources that have not been justified by any corresponding reliability benefit.
Finally, in NESCOE’s view, unless the loss of the entire aggregated nameplate value of 300 MVA poses an adverse reliability impact to the BES, the loss of individual low voltage elements used to deliver fractions of the power would have no significance.
NOPR at P 80: The Commission further sought comment on NERC’s proposed exclusions, in particular Exclusion E1 relating to radial systems, and proposed potential scenarios to evaluate how the exclusion might be applied. NESCOE notes that the network configuration shown in Figure 2 of the NOPR is typical of network configurations that exist in New England and believes that this arrangement is more appropriately analyzed as a “local network” pursuant to exclusion E3.
NOPR at P 90: As noted above, the New England system includes many local networks that are not necessary to the reliable operation of the bulk power system. Exclusion E3 defines “local network” but imposes three restrictive conditions that would unnecessarily include some New England networks in the BES, without any clear reliability benefit. In particular, the limits on connected generation should be raised to 300 MVA instead of 75MVA. As NESCOE commented earlier in the drafting process, the Northeast portion of the Eastern Interconnection defines a 1200 MVA loss of source as the largest contingency to which the control area is designed to operate. A level of 300 MVA represents 25% of that contingency and falls well within typical loss of source expectations for the Northeast.19 Local networks to which this amount of generation is connected should not be included in the BES, as they are not necessary to its reliable operation.
Exclusion E3 also specifies that a local network is excluded from the BES when power flows only into the network. However, this attempt at a bright-line distinction is unworkable and will result in unjustified costs. Minimal transfers may and do occur, and local networks should not necessarily be ineligible for Exclusion E3 simply because some amount of power may transfer out of the network at times. The Commission should direct NERC to reevaluate Exclusion E3 to allow these minimal flows. As part of this reassessment, NERC should investigate the appropriateness of a 100 MVA limit, which represents 25% of the rated value of a typical 345/115 substation (typically on the order of 400 MVA). Rarely does more than a fraction of the rated MVA flow from the low voltage side to the high voltage side. An allowance of 100 MVA represents a flow level that typically will have no significant impact on the interconnected bulk power network.
For all the reasons stated above, NESCOE respectfully requests that the Commission reject the proposed BES definition and ROP and direct NERC to (1) provide a technical justification for the threshold voltage levels contained in the BES definition; (2) provide a role for the States in the initiation, development, and review of exceptions; (3) enhance the efficiency of the exceptions review process; (4) avoid the imposition of compliance costs when a party seeks review of a BES determination; and (5) revise the proposed Inclusions and Exclusions consistent with NESCOE’s comments.
/s/ Elizabeth A. Grisaru______
Elizabeth A. Grisaru
Whiteman Osterman & Hanna
One Commerce Plaza
Albany, New York 12260
Phone: (518) 487-7624
Mail to: email@example.com
1 ISO New England, Inc., 121 FERC ¶ 61,105 (2007).
2 NESCOE’s comments to the NERC drafting team, filed on May 27, 2011, October 10, 2011, and October 27, 2011, are available at www.nescoe.com/FERC_filings.html.
3 NOPR at P 60.
4 Id. at P 58, citing Order No. 743 at P 37 (“Congress has specifically exempted “facilities used in the local distribution of electric energy” from the Bulk Power System definition….”).
5 NERC Project 2010-17 Phase 2 – Definition of BES, Comment Form at 2, posted at www.nerc.com/filez/Standards/Project2010-17_BES.html.
6 NOPR at P 60.
7 16 U.S.C. § 824o(d)(2) (2006). See Order 743-A at P 14.
8 Order No. 743 at P 73; Order No. 743-A at PP 64-71.
9 Order No. 743 at P 16; NOPR at P 9.
10 NESCOE provided the substance of the comments discussed here to the standard drafting team, but NERC’s revisions to the ROP proposal largely failed to respond to the States’ concerns. See Comments of NESCOE on Proposed Amendments to NERC Rules of Procedure, submitted at wwww.nerc.com (October 27, 2011).
11 As proposed, this would occur only where the Regional Entity recommends disapproval of an exception request. The Commission in the NOPR sought comment on whether all proposed Regional Entity determinations should be submitted to a technical review panel. NOPR at P 113. NESCOE believes that there should always be technical review of a request at the Regional Entity level, and that NERC’s subsequent role could be narrower, as described above.
12 While the NERC procedure does not have to emulate a judicial process, NESCOE notes that it is a basic principle of the judicial system that an appellate tribunal does not conduct de novo review of the facts of a case. Efficiency, preservation of scarce decisional resources, and fairness to the parties dictate this approach.
13 This suggestion addresses the Commission’s concern for reducing the discretion exercised by the regional entities.
14 Excessive process delays do not only impact the review of exclusions; they are equally likely to create delays in resolving proposed inclusions to the BES, which could raise a reliability concern.
15 Section 10 of proposed Appendix 5C requires the development of implementation plans and schedules.
16 The same logic applies in the case of requests for exclusions. NERC should not enforce implementation requirements until those requests have been finally reviewed. See proposed NERC ROP Appendix 5C, at 10.2.
17 See definition of PTFs in the ISO’s Open Access Transmission Tariff (“OATT”) at Section III.H.49. The tariff requires the ISO to review the status of facilities as PTF or non-PTF annually. Id. Similarly, the ISO’s planning procedures establish a process for the evaluation of PTF system reliability needs and the development of solutions to any deficiencies. OATT, Attachment K, Section 4.1.
18 Comments of NESCOE, Response to Question 1, filed electronically on October 11, 2011, available at www.nescoe.com/FERC_filings.html.
19 NESCOE believes that exclusion E1 should use the same 300 MVA threshold