UNITED STATES OF AMERICA
`BEFORE THE
`FEDERAL ENERGY REGULATORY COMMISSION
`
`
`
`Managing Transmission Line Ratings
`
`
`
`Docket No. RM20-16-000
`
`)
`
`COMMENTS OF THE
`MISO TRANSMISSION OWNERS
`
`
`
`
`
`
`Pursuant to the Federal Energy Regulatory Commission’s (“Commission”)
`
`November 19, 2020 Notice of Proposed Rulemaking,1 the MISO Transmission Owners2
`
`submit these Comments addressing the Commission’s proposal to revise its pro forma
`
`Open Access Transmission Tariff (“OATT”) and regulations to require transmission
`
`
`1
`Managing Transmission Line Ratings, Notice of Proposed Rulemaking, 173 FERC
`¶ 61,165 (2020) (“NOPR”).
`
`2
`
`The MISO Transmission Owners for this filing consist of: Ameren Services
`Company, as agent for Union Electric Company d/b/a Ameren Missouri, Ameren
`Illinois Company d/b/a Ameren Illinois and Ameren Transmission Company of
`Illinois; American Transmission Company LLC; Big Rivers Electric Corporation;
`City Water, Light & Power (Springfield, IL); Cleco Power LLC; Cooperative
`Energy; Dairyland Power Cooperative; Duke Energy Business Services, LLC for
`Duke Energy Indiana, LLC; East Texas Electric Cooperative; Entergy Arkansas,
`LLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy New Orleans,
`LLC; Entergy Texas, Inc.; Great River Energy; GridLiance Heartland LLC;
`Hoosier Energy Rural Electric Cooperative, Inc.; Indiana Municipal Power
`Agency; Indianapolis Power & Light Company; International Transmission
`Company d/b/a ITCTransmission; ITC Midwest LLC; Lafayette Utilities System;
`Michigan Electric Transmission Company, LLC; MidAmerican Energy Company;
`Minnesota Power (and its subsidiary Superior Water, L&P); Missouri River Energy
`Services; Montana-Dakota Utilities Co.; Northern Indiana Public Service Company
`LLC; Northern States Power Company, a Minnesota corporation, and Northern
`States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.;
`Northwestern Wisconsin Electric Company; Otter Tail Power Company; Prairie
`Power, Inc.; Southern Illinois Power Cooperative; Southern Indiana Gas & Electric
`Company (d/b/a Vectren Energy Delivery of Indiana); Southern Minnesota
`Municipal Power Agency; Wabash Valley Power Association, Inc.; and Wolverine
`Power Supply Cooperative, Inc.
`
`

`

`providers to implement seasonal ratings and ambient adjusted ratings (“AAR”)3 on
`
`transmission facilities and related requirements. As explained below, developing
`
`appropriate transmission line ratings is important to reliable and efficient transmission
`
`system operations, and implementing AARs and seasonal ratings, where appropriate, can
`
`provide value in increased transfer capability and reduced congestion. While the MISO
`
`Transmission Owners support certain aspects of the NOPR and, indeed, have been working
`
`diligently to develop a cost-beneficial AAR construct within the Midcontinent Independent
`
`System Operator, Inc. (“MISO”) regional transmission organization (“RTO”)4 footprint,
`
`some aspects of the NOPR are overly broad and will not yield benefits that are sufficient
`
`to justify the increased cost and complexity of adopting the broad-based requirements
`
`proposed in the NOPR. Accordingly, the Commission should consider instead proposing
`
`broad guidelines for implementation of appropriate transmission line ratings and allow for
`
`regional flexibility in any requirements it adopts in this proceeding. In addition, consistent
`
`with its past practices in other rulemaking proceedings, the Commission should allow
`
`transmission providers to propose alternative compliance approaches that are consistent
`
`with or superior to the final rule.
`
`
`3
`The NOPR proposes to define an AAR “as a transmission line rating that: (1)
`applies to a time period of not greater than one hour; (2) reflects an up-to-date
`forecast of ambient air temperature across the time period to which the rating
`applies; and (3) is calculated at least each hour, if not more frequently.” NOPR at
`P 3 n.3.
`
`4
`
`
`
`Except whether otherwise noted, references in these comments to “RTO” also
`encompass independent system operators.
`
`2
`
`

`

`I.
`
`EXECUTIVE SUMMARY
`
`The NOPR correctly appears to recognize that deployment of seasonal ratings and
`
`AARs can provide benefits to transmission system and energy market operations, and that
`
`a widespread requirement to implement dynamic line ratings (“DLR”) will not result in
`
`benefits that exceed the cost and complexity of doing so. Notwithstanding the benefits of
`
`implementing AARs and seasonal ratings in certain circumstances for certain purposes, the
`
`proposal to require eventual implementation of AARs on at least an hourly basis on all
`
`transmission facilities for use in day-ahead and longer-term analysis is overly broad and
`
`will not yield benefits in MISO that are sufficient to justify the added cost, effort,
`
`complexity, and operational challenges associated with the proposal. Recognizing the
`
`benefits of AARs, the MISO Transmission Owners have launched an effort in coordination
`
`with MISO to identify candidate transmission facilities where the targeted development
`
`and use of AARs will provide significant economic and operational benefits to MISO and
`
`its market participants and customers. The Commission’s final rule in this proceeding
`
`should respect regional differences and promote such voluntary efforts rather than adopt
`
`prescriptive one-size-fits-all mandates that bear no relationship to the unique circumstances
`
`of each region, each transmission owner, and each transmission system.
`
`Additionally, while AAR implementation on targeted facilities should provide
`
`benefits to real-time operations and markets, broader deployment as proposed in the NOPR
`
`(including extending AARs to day-ahead and so-called “near-term” transmission service
`
`and requiring hourly or more frequent AAR updating) will not yield significantly greater
`
`benefit but instead will add costs and complexities and present operational challenges that
`
`will undermine the Commission’s goal of promoting economic and beneficial use of AARs.
`
`The Commission should focus its mandates, and the efforts and resources of transmission
`
`
`
`3
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`

`

`owners and transmission providers, on developing AAR programs that are focused on
`
`where AAR deployment will provide the most benefit. The Commission also should
`
`recognize in any final rule in this proceeding that, while AARs are a tool that market and
`
`transmission system operators can use to maximize transmission system capability at
`
`certain times, AARs and seasonal ratings are not a substitute for long-term transmission
`
`planning and investment.5 Implementing adjustable line ratings, whether in the more
`
`limited, targeted, and net-beneficial fashion advocated in these comments or in the broad
`
`scope proposed in the NOPR, will not address the long-term needs of the transmission
`
`system brought about by a changing resource mix and evolving demands.6
`
`As it has done often in the past, the Commission should acknowledge that regional
`
`differences exist and it should provide broad guidance to the industry to implement line
`
`ratings programs that are tailored to address regional needs and reflect regional preferences.
`
`II.
`
`BACKGROUND
`
`In September 2019, the Commission convened a Staff-led technical conference to
`
`“discuss issues related to transmission line ratings, with a focus on dynamic and ambient-
`
`adjusted line ratings . . . [and] explore what transmission line rating methodologies and
`
`
`5
`MISO’s Response to the Reliability Imperative, Midcontinent Independent System
`Operator, Inc. 3, 13-14 (Feb. 2020) (“MISO Reliability Imperative”) (discussing
`the need for long range transmission planning to assess the region’s future
`transmission needs
`amid
`a dramatic
`shift
`in
`the
`resource mix),
`https://www.misoenergy.org/about/miso-strategy-and-value-proposition/miso-
`reliability-imperative/.
`
`6
`
`
`
`See generally MISO’s Renewable Integration Impact Assessment (RIAA),
`Midcontinent Independent System Operator, Inc. (Feb. 2021) (discussing the MISO
`region’s significant
`resource portfolio changes and
`related challenges),
`https://cdn.misoenergy.org/RIIA%20Summary%20Report520051.pdf.
`
`4
`
`

`

`related practices might constitute best practices, and what, if any, Commission action in
`
`these areas might be appropriate.”7 Numerous industry and stakeholder representatives
`
`participated in that conference, including a representative on behalf of the MISO
`
`Transmission Owners.8 Commission Staff also issued a paper addressing transmission line
`
`rating issues that discussed the various types of transmission line ratings, potential benefits,
`
`disadvantages, and limitations of the different transmission line rating methods.9 The Staff
`
`Paper also indicated that adjusting a transmission line’s rating may provide a means to
`
`manage congestion.10
`
`On November 19, 2020, the Commission issued the NOPR, proposing to require:
`
`1. That transmission providers use AARs as the basis for evaluation of
`transmission service requests that will end within ten days of the request;
`and as the basis for the determination of the necessity of certain curtailment,
`interruption, or redispatch of transmission service that is anticipated to
`occur within those ten days;11
`
`2. That transmission providers use seasonal line ratings as the basis for
`evaluation of longer-term (beyond ten days) transmission service requests
`
`
`7
`Managing Transmission Line Ratings, Supplemental Notice of Technical
`Conference, Docket No. AD19-15-000, at 1 (Sept. 4, 2019).
`
`8
`
`9
`
`10
`
`11
`
`
`
`See Statement of Dennis D. Kramer, Senior Director of Transmission Policy and
`Stakeholder Relations, Ameren Services Company on Behalf of the MISO
`Transmission Owners, Panel 3: Discussion of Possible Requirement for
`Transmission Owners to Implement AARs (Sept. 10, 2019); Statement of Dennis D.
`Kramer, Senior Director of Transmission Policy and Stakeholder Relations,
`Ameren Services Company on Behalf of the MISO Transmission Owners, Panel 5:
`Discussion of Transparency of Transmission Line Rating Methodologies
`(Sept. 11, 2019).
`
`Managing Transmission Line Ratings, A Staff Paper by the Federal Energy
`Regulatory Commission Staff, Docket No. AD19-15-000, at 4-10 (Aug. 23, 2019)
`(“Staff Paper”).
`
`Id. at 12, 17-18.
`
`NOPR at PP 3, 84-87, 89, 95.
`
`5
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`

`

`(including network service) and as the basis for the determination of the
`necessity of curtailment, interruption, or redispatch that is anticipated to
`occur more than ten days in the future (which the Commission notes is
`currently standard practice);12
`
`3. RTOs to establish and implement the systems and procedures necessary to
`allow transmission providers to update their transmission line ratings
`electronically on at least an hourly basis;13 and
`
`4. Transmission owners to share their transmission line ratings and
`methodologies with their transmission provider(s), and in RTO regions,
`with the RTO’s market monitor.14
`
`The Commission proposed to require compliance filings within sixty days of the issuance
`
`of a final order,15 and proposed a staggered approach to implementation of the proposed
`
`AAR requirements that would focus first on implementation of AARs on “historically
`
`congested lines” (which the Commission proposed to define as any “transmission line that
`
`was congested at any time within the five years prior to the effective date of any final rule”)
`
`within one year from the date of compliance filing submission,16 and a “less aggressive”
`
`implementation on all other lines within two years from the date of submission of
`
`compliance filings.17
`
`
`12
`Id. at PP 4 & n.4, 84, 88-90.
`
`13
`
`14
`
`15
`
`16
`
`17
`
`
`
`Id. at PP 5, 82, 91, 108, 131. The Commission also requested comment on whether
`to impose this requirement on transmission providers outside of RTOs and on the
`additional costs that would need to be incurred for RTOs to comply with this
`requirement. Id. at PP 82, 109.
`
`Id. at PP 7, 125.
`
`Id. at P 131. The Commission specifically requested comment on whether sixty
`days is sufficient time for public utility transmission providers to develop new tariff
`language in response to the final rule. Id. at P 133.
`
`Id. at PP 81, 92, 131 (emphasis added).
`
`Id. at PP 81, 131.
`
`6
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`

`

`The Commission also requested comments on various issues including whether to
`
`require transmission providers to implement unique emergency ratings18 that would be
`
`used during post-contingency operations,19 and whether transmission line ratings and
`
`methodologies should be shared with other transmission providers upon request,20 or more
`
`broadly to other stakeholders.21 The Commission did not propose to require
`
`implementation of DLRs,22 but did request comments regarding whether to require RTOs
`
`to conduct a one-time study of the cost effectiveness of DLR implementation,23 and
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`whether to require transmission providers to implement DLRs across their systems or on
`
`certain transmission facilities that have the most potential to benefit from a dynamic
`
`rating.24
`
`
`18
`The NOPR defines the phrase “unique emergency ratings” to be “an emergency
`rating that is a different value from a facility’s normal rating” and “[t]ypically . . . a
`higher value than the normal rating unless there is specific [sic] constraint that
`prohibits a higher emergency rating.” Id. at P 6 n.7.
`
`19
`
`20
`
`21
`
`22
`
`23
`
`24
`
`
`
`Id. at PP 6, 83, 111.
`
`Id. at PP 7, 118.
`
`Id. at P 129.
`
`The NOPR defines a DLR as “a transmission line rating that: (1) applies to a time
`period of not greater than one hour; (2) reflects up-to-date forecasts of inputs such
`as (but not limited to) ambient air temperature, wind, solar irradiance intensity,
`transmission line tension, or transmission line sag; and (3) is calculated at least each
`hour, if not more frequently.” Id. at P 5 n.5.
`
`Id. at P 110.
`
`Id. at P 101.
`
`7
`
`

`

`III. COMMENTS
`
`The MISO Transmission Owners appreciate the opportunity to provide comments
`
`in response to the Commission’s proposal to require use of AARs and seasonal ratings in
`
`various circumstances and the Commission’s related NOPR proposals. Generally
`
`speaking, the MISO Transmission Owners agree that, in certain circumstances involving
`
`certain transmission facilities, utilizing AARs for certain real-time and near-term activities
`
`can provide reliability, operational, and economic benefits by maximizing the capacity of
`
`those assets. Likewise, the use of seasonal rather than static ratings for longer-term
`
`analyses and requests could yield benefits in certain circumstances.25 Indeed, the MISO
`
`Transmission Owners have voluntarily embarked on a data-driven effort to identify
`
`transmission facilities in MISO that would provide the most benefit from implementation
`
`of AARs, based on a thorough review of transmission facility congestion and establishment
`
`of appropriate benefit metrics. MISO has determined that only approximately 10 percent
`
`of the nearly 10,000 transmission lines26 under MISO’s functional control experienced any
`
`congestion during the last five years,27 and it is only these lines that currently may benefit
`
`
`25
`Many MISO Transmission Owners already use seasonal ratings, but that does not
`always mean that there will be a difference if the limiting element of the circuit is
`not temperature adjustable.
`
`26
`
`27
`
`
`
`Review of MISO’s Ratings Process – Transmission Line Ratings Workshop,
`Midcontinent
`Independent System Operator,
`Inc., 14
`(Jan. 15, 2021),
`https://cdn.misoenergy.org/20210115%20Transmission%20Line%20Ratings%20
`Workshop%20Item%2004%20of%20MISO%20Rating%20Processes%20and%20
`Statistics%20513174.pdf.
`
`MISO real-time binding history is available on the MISO website. See Market
`Reports,
`Midcontinent
`Independent
`System
`Operator,
`Inc.,
`https://www.misoenergy.org/markets-and-operations/real-time--market-
`data/market-reports/ (last visited Mar. 22, 2021).
`
`8
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`

`

`from implementation of AARs.28 The MISO Transmission Owners encourage the
`
`Commission to facilitate such voluntary regional efforts instead of adopting uniform,
`
`prescriptive AAR mandates broadly applicable across all transmission facilities in all
`
`regions of the country.
`
`The MISO Transmission Owners also support the Commission’s proposal not to
`
`require widespread implementation of DLRs at this time. The significant additional costs
`
`and technical concerns associated with widespread DLR implementation outweigh the
`
`benefits that would be achieved by such a mandate. The Commission should continue to
`
`allow flexibility for transmission owners to experiment with implementation of DLRs on
`
`a voluntary basis where the transmission owner determines it is cost-beneficial to do so.
`
`Based on the considerable differences in transmission system technology, topology,
`
`geography, and weather across regions, the Commission should not adopt a one-size-fits-
`
`all approach to encouraging broader implementation of AARs and seasonal ratings, but
`
`instead should let experience and efforts in each region guide the appropriate approach to
`
`implementation. The MISO Transmission Owners urge the Commission to allow
`
`flexibility for each RTO and its transmission owners, and transmission providers and
`
`transmission owners in non-RTO regions, to develop AAR and seasonal ratings
`
`implementation approaches that best work for their regions.
`
`
`28
`Part of the MISO Transmission Owners’ effort is a periodic reevaluation to
`determine which facilities present the best opportunity for application of AARs;
`through this process, the list of facilities will change to reflect changing conditions
`over time.
`
`
`
`9
`
`

`

`A.
`
`The MISO Transmission Owners Offer a Reasonable, Flexible
`Alternative to the Prescriptive Approach Proposed in the NOPR
`Utilizing Existing, Voluntary Regional Efforts Already Underway
`
`As was made clear at the technical conference,29 and recent experience in MISO
`
`indicates, rather than adopt a one-size-fits-all approach, the Commission should provide
`
`broad guidance on the implementation of AARs and seasonal ratings, and allow RTOs and
`
`transmission providers and their associated transmission owners to develop programs that
`
`best comport with unique regional circumstances.30
`
`
`29
`the technical conference representatives from PJM
`For example, during
`Interconnection, L.L.C. and the Electric Reliability Council of Texas and their
`respective members discussed the efforts that transmission owners in those regions
`have voluntarily undertaken to implement various line ratings methodologies that
`those regions deemed were net-beneficial. E.g., NOPR at P 29 (summarizing
`technical conference discussion and post-technical conference comments). A
`prescriptive Commission regulation was not required to encourage these efforts.
`
`30
`
`The Commission has frequently recognized regional differences and afforded
`regional flexibility in rulemaking proceedings, and should continue that sound
`tradition here. See, e.g., Transmission Planning and Cost Allocation by
`Transmission Owning and Operating Public Utilities, Order No. 1000, 136 FERC
`¶ 61,051, at P 61 (2011) (“Nevertheless, the Commission recognizes that each
`transmission planning region has unique characteristics and, therefore, this Final
`Rule accords transmission planning regions significant flexibility to tailor regional
`transmission planning and cost allocation processes to accommodate these regional
`differences. The Commission recognizes that many transmission planning regions
`have or are in the process of taking steps to address some of the concerns described
`in this Final Rule.”), order on reh’g & clarification, Order No. 1000-A, 139 FERC
`¶ 61,132, order on reh’g & clarification, Order No. 1000-B, 141 FERC ¶ 61,044
`(2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014);
`Frequency Regulation Compensation in the Organized Wholesale Power Markets,
`Order No. 755 137 FERC ¶ 61,064, at P 75 (2011) (declining to mandate
`standardized market rules, instead allowing RTOs “flexibility to design market
`rules that accommodate their markets”), reh’g denied, Order No. 755-A, 138 FERC
`¶ 61,123 (2012); Wholesale Competition in Regions with Organized Electric
`Markets, Order No. 719, 125 FERC ¶ 61,071, at PP 59, 86, 160 (2008) (declining
`to mandate that RTOs develop standardized procedures for demand response), as
`amended, 126 FERC ¶ 61,261, order on reh’g, Order No. 719-A, 128 FERC
`¶ 61,059, reh’g denied, Order No. 719-B, 129 FERC ¶ 61,252 (2009); Long-Term
`Firm Transmission Rights in Organized Electricity Markets, Order No. 681, 116
`
`
`
`10
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`

`

`The MISO Transmission Owners voluntarily launched such an effort in early 2020,
`
`in coordination with MISO and in consultation with the MISO Independent Market
`
`Monitor (“IMM”) and state regulators as represented by the Organization of MISO States
`
`(“OMS”), to identify a prioritized list of candidate transmission facilities for application of
`
`real-time AARs. This effort has focused on historical, real-time binding constraint costs31
`
`and associated real-time congestion hours for each facility that has bound in the past two
`
`years. Individual MISO Transmission Owners are in the process of reviewing the list to
`
`determine on which candidate facilities the implementation of AARs is technically feasible
`
`and where implementation of thermal ratings adjustments are expected to provide benefits.
`
`The analysis examines the following factors, including whether: (1) the limiting element
`
`on the facility is capable of adjustment based on ambient temperatures;32 (2) the historical
`
`congestion on the facility is likely to recur;33 and (3) an increased thermal rating would
`
`address at least some of the anticipated future congestion. From there, the MISO
`
`
`FERC ¶ 61,077, at PP 22, 84-85, order on clarification, Order No. 681-A, 117
`FERC ¶ 61,201 (2006), order on reh’g, Order No. 681-B, 126 FERC ¶ 61,254
`(2009).
`
`31
`
`32
`
`33
`
`
`
`This is defined as the summation of costs for 1 MW of relief on the binding
`constraint during each five-minute weighted market solution where binding was
`active on the constraint.
`
`Sometimes the limiting element is sufficiently isolated from impacts from ambient
`temperature changes, such that no benefit would result from implementing AARs
`on the other, ambient temperature reactive elements. Examples of such non-
`adjustable elements include, but are not limited to, underground cables, protective
`equipment limiting facilities, and terminal equipment limiting facilities.
`
`For short-term and transitory historical congestion that has since been resolved or
`where an upgrade has resolved congestion on a historically-congested facility,
`implementing AARs may not yield any benefits because any incremental capacity
`increases will not relieve congestion and therefore will not result in congestion cost
`savings.
`
`11
`
`

`

`Transmission Owners and MISO calculate the potential savings by quarter for congestion
`
`costs assuming a 1 MW increase in rating. The potential savings, which sets a floor on
`
`potential congestion savings to the market, are used to stack rank candidate facilities. The
`
`MISO Transmission Owners intend to complete the evaluation of the candidate facilities
`
`according to these guidelines by July 1, 2021, and to repeat the process quarterly, with the
`
`results being shared with the IMM and state regulators.
`
`After the evaluation is complete this summer, each transmission owner will be
`
`responsible for developing its own AAR program and methodologies for the facilities that
`
`have been identified as providing sufficient benefit based on the evaluation. Individual
`
`transmission owner AAR programs will need to: (1) determine the appropriate method for
`
`establishing AARs; (2) develop data to support the AAR calculations as required by North
`
`American Electric Reliability Corporation (“NERC”) Reliability Standard FAC-008;34 and
`
`(3) create repeatable processes and data systems to store, use, and communicate the AARs
`
`to the appropriate entities in real-time, per NERC Reliability Standards.35 This approach
`
`is designed to ensure compliance with applicable NERC Reliability Standards and to
`
`implement AARs for those facilities where AAR application is likely to yield the most
`
`benefit and net savings for near-term operations.
`
`To encourage such region-specific approaches to developing cost beneficial line
`
`ratings programs, the Commission should avoid one-size-fits-all mandates but instead
`
`
`34
`Reliability Standard FAC-008-3 – Facility Ratings, North American Electric
`Reliability Corporation (Dec. 12, 2013), https://www.nerc.com/files/FAC-008-
`3.pdf (“NERC Reliability Standard FAC-008”).
`
`35
`
`
`
`E.g., Reliability Standard FAC-014-2 – Establish and Communicate System
`Operating Limits, North American Electric Reliability Corporation (July 23, 2015),
`https://www.nerc.com/pa/Stand/Reliability%20Standards/FAC-014-2.pdf.
`
`12
`
`

`

`adopt broad guidelines that accommodate regional differences and preferences. To that
`
`end, the MISO Transmission Owners offer an alternative approach to the prescriptive
`
`proposed mandates in the NOPR that will allow transmission providers and transmission
`
`owners to build upon the voluntary efforts that they have already undertaken.
`
`First, the Commission should acknowledge that the purpose behind implementing
`
`AARs is to maximize the use of the transmission grid reasonably in a safe and reliable
`
`manner to reduce or minimize short term congestion costs, and should stress that reliability
`
`and safety concerns should be paramount at all times.36 The Commission should also
`
`acknowledge that AARs are not a substitute for building new transmission or upgrading
`
`existing facilities when the RTO determines though its planning process that such
`
`expansion is necessary.37 The focus of any Commission final rule should be on maintaining
`
`reliability and safety while maximizing value by balancing the cost of implementation
`
`against congestion cost savings, which means that AARs should only be used where there
`
`are congestion benefits and thus not on every possible transmission facility. Specifically,
`
`deployment of AARs should focus on the facilities expected to provide the most benefit by
`
`“freeing up” additional transmission capacity when: (1) the limiting element of a
`
`historically-congested facility is temperature sensitive; (2) there is reliable local weather
`
`data available; and (3) the transmission owner and RTO secure and deploy the necessary
`
`
`36
`The NOPR correctly observes that “[s]ystem safety and reliability are paramount
`to the proposed requirements for transmission line ratings” and that line ratings
`should be developed “consistent with good utility practice,” which “requires
`consistency with safety and reliability, among other things.” NOPR at P 98. The
`Commission should adopt these guiding principles in any final rule.
`
`37
`
`
`
`See supra notes 5-6 and accompanying text (discussing the need for long range
`transmission planning and the MISO Reliability Imperative).
`
`13
`
`

`

`reliable systems to calculate and implement AARs. Focusing on net benefits, AARs would
`
`be used on the most congested facilities where it is actually possible to achieve a market
`
`benefit, and AARs would not be required where there are no or insufficient market benefits
`
`to justify the added expense and complexity.
`
`Second, understanding that focus, the Commission should provide broad guidelines
`
`and allow regions flexibility to adopt approaches that are appropriate for their regions. In
`
`MISO, this would mean continuing to follow the existing conceptual framework outlined
`
`above, involving coordination and consultation among the MISO Transmission Owners,
`
`MISO, the IMM, and OMS, and, ultimately, other stakeholders as appropriate.
`
`Third, the Commission should allow flexibility for transmission owners and
`
`transmission providers to identify the most beneficial transmission facilities for which to
`
`implement AARs and seasonal ratings. Again, this approach would allow the ongoing
`
`AAR implementation efforts in MISO to proceed unimpeded. This approach should be
`
`based on historical congestion data as adjusted to reflect known and foreseeable changes,
`
`such as completion of upgrades that alleviate congestion, expected weather changes, and
`
`other relevant factors.
`
`Fourth, the Commission should allow more time for implementation. While the
`
`MISO Transmission Owners appreciate the Commission’s “staggered” approach to
`
`implementation, the Commission must also be aware that there are significant up-front
`
`efforts required to implement an effective AAR program, including developing or updating
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`ratings methodologies, analyzing historical weather conditions and procuring and
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`deploying weather forecasting services, identifying the applicable transmission facilities
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`and the limiting elements of those facilities, defining the specifications for, developing,
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`installing, testing, and implementing necessary software and hardware, and ensuring
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`proper communication of ratings information between the transmission owner and
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`appropriate parties as defined by agreements, applicable tariffs, and various NERC
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`Reliability Standards requirements. As explained in more detail below, the experience of
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`the MISO Transmission Owners that have implemented AARs methodologies is that the
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`up-front development and implementation efforts take multiple years. Also, given the
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`limited universe of vendors capable of developing the software and systems necessary to
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`implement AARs both on the transmission owner and transmission provider ends, more
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`time may be needed if all transmission owners and transmission providers attempt to
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`procure these services at the same time in response to a Commission final rule.
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`Fifth, the primary focus of AAR implementation should be in the real-time market
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`and real-time operations. The greatest benefit from implementing AARs is in real-time
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`markets and operations, where actual system operating conditions can be analyzed and
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`utilized in generation dispatch, market clearing, and operations. Applying AARs beyond
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`real-time to day-ahead or even further (e.g., ten days as discussed in the NOPR) requires
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`the use of forecasts to speculate as to future conditions, which leads to greater uncertainty
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`and error or more conservative ratings to account for such uncertainty. Beyond potential
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`market impacts caused by using one set of AARs in day-ahead and a different set in real-
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`time, using AARs in day-ahead markets and operations presents other concerns. For
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`example, the day-ahead processes establish the final reliability plan for the next operating
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`day. If real-time conditions on the next day occur that are less favorable than forecasted
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`(e.g., higher ambient temperatures), the reliability of the system may be jeopardized due to
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`insufficient scheduling of reactive resources, including generation, under planned system
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`topology. Though this risk exists today, AARs introduce additional complexity since the
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`increased system load and insufficient resources are further compounded by transmission
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`lines operating at lower ratings in real-time than forecasted day-ahead. The use of seasonal
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`or static ratings, as opposed to AARs, when establishing the reliability plan for the next
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`operating day provides more certainty that the system will be able to perform as intended,
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`including being able to proceed with planned transmission outages, which have their own
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`market impacts if they are unable to be implemented in real-time.38 Moreover, the MISO
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`Transmission Owners understand that MISO’s current systems can only incorporate line
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`ratings data in real-time. MISO is in the midst of a multi-year Market System Enhancement
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`project, but that project will not be