Implementation of Dynamic Line Ratings

Federal RegisterJul 15, 2024

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM24-6-000]

Implementation of Dynamic Line Ratings

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Advance notice of proposed rulemaking.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is issuing an advance notice of proposed rulemaking presenting potential reforms to implement dynamic line ratings and, thereby, improve the accuracy of transmission line ratings. These potential reforms would require transmission line ratings to reflect solar heating based on the sun's position and forecastable cloud cover and require transmission line ratings to reflect forecasts of wind conditions on certain transmission lines. The potential reforms would also ensure transparency in the development and implementation of dynamic line ratings and enhance data reporting practices related to congestion in non-regional transmission organization/independent system operator regions to identify candidate transmission lines for the requirement to reflect forecasts of wind conditions. The Commission invites all interested persons to submit comments on the potential reforms and in response to specific questions.

DATES:

Comments are due October 15, 2024 and Reply Comments are due November 12, 2024.

ADDRESSES:

Comments, identified by docket number, may be filed in the following ways. Electronic filing through

https://www.ferc.gov,

is preferred.

•

Electronic Filing:

Documents must be filed in acceptable native applications and print-to-PDF, but not in scanned or picture format.

• For those unable to file electronically, comments may be filed by USPS mail or by hand (including courier) delivery.

○

Mail via U.S. Postal Service Only:

Addressed to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426.

○

Hand (including courier) Delivery:

Deliver to: Federal Energy Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.

The Comment Procedures section of this document contains more detailed filing procedures.

FOR FURTHER INFORMATION CONTACT:

Daniel Kheloussi (Technical Information), Office of Energy Policy and Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-6391,

Daniel.Kheloussi@ferc.gov

Lisa Sosna (Technical Information), Office of Energy Policy and Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-6597,

Lisa.Sosna@ferc.gov

Ryan Stroschein (Legal Information), Office of the General Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8099,

Ryan.Stroschein@ferc.gov

SUPPLEMENTARY INFORMATION:

Table of Contents

Paragraph Nos.

I. Introduction

II. Background

A. Transmission Line Rating Proceedings

1. Order No. 881

2. Notice of Inquiry

3. Comments Supporting DLRs

B. Transmission Line Ratings Background

1. Different Types of Transmission Line Ratings: Based on Thermal, Voltage, and Stability Limits

2. Calculating Thermal Ratings

3. Variables That Impact Thermal Ratings of Transmission Lines

a. Ambient Air Temperature

b. Solar Heating

c. Wind Speed and Direction

C. Incorporating Weather Variables Into Thermal Ratings

1. Sensors and Their Use in DLRs

2. Incorporating Local Weather Forecasts Into DLRs

3. Current Use and Benefits of DLRs

Pro forma

Transmission Scheduling and Congestion Management Practices

1. How Transmission Service Is Procured

a. Transmission Service Under the

pro forma

OATT

b. Congestion Management Under the

pro forma

OATT

c. Transmission Scheduling and Congestion Management in the RTOs/ISOs

2. Existing Data Reporting on Congestion, or Proxies of Congestion

a. RTOs/ISOs

b. Non-RTO/ISO Regions

i. ATC and Constrained Posted-Paths

ii. Redispatch Costs

III. The Potential Need for Reform

A. Demonstrated DLR Benefits

1. U.S. Examples

2. International Examples

B. Consideration of Reforms

IV. Potential Reforms and Request for Comment

A. Potential Transmission Line Ratings Reforms and Request for Comment

1. Framework for a Potential Requirement

2. Potential Solar Requirement

a. Reflecting Solar Heating Based on the Sun's Position

b. Reflecting Solar Heating Based on Forecastable Cloud Cover

3. Potential Wind Requirement

a. Components of a Wind Requirement

i. Time Horizon and Forecasting Requirement

101

ii. Sensor Requirements

109

b. Proposed Criteria To Identify Transmission Lines Subject to a Wind Requirement

116

i. Number of Transmission Lines Subject to the Wind Requirement Annually

117

ii. Wind Speed Threshold

120

iii. Congestion Threshold

124

(a) RTO/ISO Regions

125

(1) Congestion Costs

125

(b) Non-RTO/ISO Regions

130

(1) Limiting Element Rate

130

(i) Overview

130

(ii) Triggering Events

131

(iii) Data To Be Collected and Reported

135

(iv) LER Threshold

137

(2) Potential Alternatives for Comment

138

(i) Non-RTO/ISO Congestion Costs

139

c. Self-Exceptions From the Wind Requirement

142

i. Self-Exception Categories

142

ii. Challenges to Self-Exceptions

151

d. Transmission Lines Formerly Subject to the Wind Requirement

152

e. Potential Transparency Reforms and Request for Comment

153

i. Potential Reforms to Congestion Data Collection

156

ii. Posting of Congestion Data

158

iii. Posting of Transmission Line Ratings Subject to a Wind Requirement

160

4. Requirements for Reflecting Solar and/or Wind in Transmission Line Ratings in RTOs/ISOs

162

5. Implications for Emergency Ratings

166

6. Confidence Levels

169

B. Compliance and Transition and Implementation Timelines

174

Pro forma

OATT Revisions and Implementation

174

2. Implementation Timeframe for the Solar Requirement

176

3. Phased-In Implementation Timeframe for the Wind Requirement

177

a. Annual Wind Requirement Implementation Cycles

177

b. Transmission Provider Compliance Requirement

180

c. Compliance for Transmission Providers That Are Subsidiaries of the Same Public Utility Holding Company

182

V. Comment Procedures

183

VI. Document Availability

186

I. Introduction

1. In this advance notice of proposed rulemaking (ANOPR), the Federal Energy Regulatory Commission (Commission), pursuant to its authority under section 206 of the Federal Power Act (FPA),

is considering the need to establish requirements for transmission providers to use dynamic line ratings to improve the accuracy of transmission line ratings. Dynamic line ratings, or DLRs, are transmission line ratings that reflect up-to-date forecasts of weather conditions, such as ambient air temperature, wind, cloud cover, solar heating, and precipitation, in addition to transmission line conditions such as tension or sag.

The Commission is also considering reforms to ensure transparency in the development and implementation of dynamic line ratings.

16 U.S.C. 824e.

See, e.g.,

18 CFR 35.28(b)(14).

2. In 2021, the Commission issued Order No. 881, to revise its

pro forma

Open Access Transmission Tariff (OATT) and the Commission's regulations to improve the accuracy and transparency of transmission line ratings.

Specifically, the Commission found that the use of only seasonal and static temperature assumptions in developing transmission line ratings would result in transmission line ratings that do not accurately represent the transfer capability of the transmission system.

The Commission found that inaccurate transmission line ratings result in unjust and unreasonable Commission-jurisdictional rates.

Managing Transmission Line Ratings,

Order No. 881, 87 FR 2244 (Jan. 13, 2022), 177 FERC ¶ 61,179 (2021),

order addressing arguments raised on reh'g,

Order No. 881-A, 87 FR 31712 (May 25, 2022), 179 FERC ¶ 61,125 (2022).

Id.

P 3.

Id.

PP 3, 29.

3. Building upon past Commission actions designed to improve the accuracy and transparency of transmission line ratings, this ANOPR raises questions and explores potential reforms to further enhance transmission line ratings and congestion reporting practices. We preliminarily propose and seek comment on a DLR framework for reforms to improve the accuracy of transmission line ratings and ensure transparency in the development and implementation of transmission line ratings. These potential DLR reforms would require transmission line ratings to reflect the impacts of solar heating by considering the sun's position and forecastable cloud cover. They would also require transmission line ratings to reflect forecasts of wind conditions—wind speed and wind direction—on certain transmission lines. The potential reforms also would enhance data reporting practices related to congestion in non-regional transmission organization (RTO)/independent system operator (ISO) regions to identify candidate transmission lines for any wind requirement. We seek comment on this framework and whether any reforms to alter the requirements for transmission line ratings are needed to ensure rates for Commission-jurisdictional service are just and

reasonable, and not unduly discriminatory or preferential.

II. Background

4. This ANOPR proposes a DLR framework for reforms that would build upon past Commission actions designed to improve the accuracy of transmission line ratings and ensure transparency in the development and implementation of transmission line ratings. This section describes those past actions, related Commission proceedings, how transmission line ratings are determined, including the incorporation of weather variables into thermal ratings and the use of sensors, and how transmission services are provided and procured in the bulk electric system to provide context for the reforms proposed herein.

A. Transmission Line Rating Proceedings

1. Order No. 881

5. In December 2021, the Commission issued Order No. 881, which reformed both the

pro forma

OATT and the Commission's regulations to improve the accuracy and transparency of transmission line ratings.

The Commission explained that seasonal or static transmission line ratings, which represent the maximum transfer capability of each transmission line and are typically based on conservative assumptions about long-term air temperature and other weather conditions, may not accurately reflect the near-term transfer capability of the transmission system and that more accurate transmission line ratings can be achieved through the use of ambient-adjusted ratings (AAR) and DLRs.

Therefore, the Commission adopted requirements for the use of AARs,

and the use of uniquely determined emergency ratings that include separate AAR calculations, for use in the operations horizon and in post-contingency simulations of constraints.

The Commission further required associated transparency requirements and certain discrete requirements related to removing barriers to DLRs, including requiring RTOs/ISOs to establish and implement the systems and procedures necessary to allow transmission providers to electronically update transmission line ratings at least hourly. The Commission also required the consideration of solar heating as part of AARs in the form of separate daytime and nighttime ratings. For this daytime/nighttime ratings requirement, transmission providers must assume solar heating during daylight hours, and nighttime ratings must reflect the absence of solar heating.

Although the Commission declined to require hourly forecasts of solar heating, it clarified that nothing in the final rule prohibited a transmission provider from voluntarily implementing hourly forecasts for solar heating.

177 FERC ¶ 61,179.

Unlike static thermal line ratings, which are calculated annually or seasonally based on constant values of line current and worst-case weather conditions, AARs are determined using near-term forecasted ambient air temperatures and updated daytime/nighttime solar heating values. As noted above, DLRs are calculated using up-to-date forecasts of ambient air temperature, plus other weather conditions such as wind, cloud cover, solar heating, and precipitation, in addition to transmission line conditions such as tension or sag.

AAR is defined as a transmission line rating that: (a) applies to a time period of not greater than one hour; (b) reflects an up-to-date forecast of ambient air temperature across the time period to which the rating applies; (c) reflects the absence of solar heating during nighttime periods, where the local sunrise/sunset times used to determine daytime and nighttime periods are updated at least monthly, if not more frequently; and (d) is calculated at least each hour, if not more frequently.

Pro forma

OATT, attach. M, Definitions;

see also

18 CFR 35.28(b)(12).

“Emergency Rating” is defined as a transmission line rating that reflects operation for a specified, finite period, rather than reflecting continuous operation. An emergency rating may assume an acceptable loss of equipment life or other physical or safety limitations for the equipment involved. 18 CFR 35.28(b)(13);

pro forma

OATT, attach. M, Definitions.

Order No. 881, 177 FERC ¶ 61,179 at P 149.

Id.

P 150.

6. With respect to DLRs, the Commission in Order No. 881 adopted as the definition of DLR: a transmission line rating that applies to a time period of not greater than one hour and reflects up-to-date forecasts of inputs such as (but not limited to) ambient air temperature, wind, solar heating intensity, transmission line tension, or transmission line sag.

Although organizationally Order No. 881 discussed the DLR requirement for RTOs/ISOs separately from the AAR requirement,

the Commission defined DLRs to include ambient air temperature and solar heating.

Consistent with that definition, in this ANOPR, references to DLR include AAR (which, as used in Order No. 881, includes ambient air temperatures and solar daytime/nighttime ratings) as well as the solar requirement and wind requirement proposed below.

18 CFR 35.28(b)(14);

see

Order No. 881, 177 FERC ¶ 61,179 at PP 7, 235, 238.

Compare

Order No. 881, 177 FERC ¶ 61,179 at PP 47-192 (section IV.B “Ambient-Adjusted Ratings”)

with id.

PP 235-266 (section IV.E “Dynamic Line Ratings”).

See supra

n.12.

This ANOPR does not propose any changes to the requirements of Order No. 881.

7. The Commission agreed with commenters that highlighted the benefits of DLR implementation. The Commission stated that, absent RTOs/ISOs having the capability to incorporate DLRs, voluntary implementation of DLRs by transmission owners in some RTOs/ISOs would be of limited value, as their more dynamic ratings and resulting benefits would not be incorporated into RTO/ISO markets.

For example, the Commission acknowledged that the use of DLRs generally allows for greater power flows than would otherwise be allowed, and that their use can detect situations when power flows should be reduced to maintain safe and reliable operation and avoid unnecessary wear on transmission equipment.

However, the Commission also recognized that implementing DLRs is more costly and challenging than implementing AARs, and found that the record in the proceeding was insufficient to evaluate the benefits, costs, and challenges of DLR implementation at that time.

As a result, the Commission declined to adopt any reforms that would mandate DLR implementation based on the record in that proceeding and instead incorporated that record into a new proceeding in Docket No. AD22-5-000 to further explore DLR implementation.

Order No. 881, 177 FERC ¶ 61,179 at P 255.

Id.

P 253.

Id.

P 254.

Id.

PP 7-9.

8. The Commission required implementation of the requirements adopted in Order No. 881 by July 12, 2025, three years after compliance filings were due.

We note, however, that certain transmission providers requested and were granted extensions by the Commission.

E.g., N.Y. Indep. Sys. Operator, Inc.,

186 FERC ¶ 61,237 (2024) (granting an extension until no later than December 31, 2028);

S. Co. Servs. Inc.,

187 FERC ¶ 61,055 (2024) (granting an extension up to and including December 31, 2026).

2. Notice of Inquiry

9. On February 17, 2022, the Commission issued a Notice of Inquiry

in which the Commission asked a series of questions about whether and how the use of DLRs might be needed to ensure just and reasonable Commission-jurisdictional rates; potential criteria for DLR requirements; the benefits, costs, and challenges of implementing DLRs; the nature of potential DLR requirements; and potential timeframes for implementing DLR requirements. The Commission received initial comments from 40 entities, reply comments from six

entities, and supplemental comments from four entities.

Implementation of Dynamic Line Ratings,

Notice of Inquiry, 178 FERC ¶ 61,110 (2022) (NOI).

A list of commenters in the NOI proceeding and their abbreviated names is located in the appendix.

3. Comments Supporting DLRs

10. Comments in response to the NOI suggest potential net benefits of implementing DLRs in certain circumstances. Various commenters state that DLRs would reduce congestion costs.

Other commenters highlight DLR benefits related to reduced renewable energy curtailment and reduced interconnection costs.

WATT/CEE Comments, Docket No. AD22-5, at 4 (filed Apr. 25, 2022); DOE Comments, Docket No. AD22-5, app A (Grid-Enhancing Technologies: A Case Study on Ratepayer Impact (Feb. 2022)) at 40-41, 52-53 (filed Apr. 25, 2022); R Street Institute Comments, Docket No. AD22-5, at 8 (filed Apr. 26, 2022); ELCON Comments, Docket No. AD22-5, at 5-6 (filed Apr. 25, 2022); Certain TDUs Comments, Docket No. AD22-5, at 7, 9 (filed Apr. 25, 2022).

WATT/CEE Comments, Docket No. AD22-5, at 4 (filed Apr. 25, 2022) (citing Consentec,

The Benefits of Innovative Grid Technologies

(Dec. 8, 2021) and T. Bruce Tsuchida, Stephanie Ross, and Adam Bigelow,

Unlocking the Queue with Grid-Enhancing Technologies

(Feb. 1, 2021)); DOE Comments, Docket No. AD22-5, attach. A at 44 (filed Apr. 25, 2022); ELCON Comments, Docket No. AD22-5, at 7 (filed Apr. 25, 2022).

11. Commenters assert that DLR implementation can help mitigate congestion associated with planned and/or unplanned long-term outages of generation or transmission.

Clean Energy Parties identify two examples in which sensors for transmission line sag and transmission line temperature can serve a reliability function, indicating that the cost-benefit analysis for installation of sensors to enable DLR is not limited to economic benefits. Clean Energy Parties assert that DLR sensors serve reliability by detecting potential fire danger during high wind periods and detecting real-time transmission line capacity.

PJM Comments, Docket No. AD22-5, at 5 (filed May 9, 2022); Clean Energy Parties Comments, Docket No. AD22-5, at 21 (filed Apr. 25, 2022); LineVision Comments, Docket No. AD22-5, at 5 (filed Apr. 22, 2022).

Clean Energy Parties Comments, Docket No. AD22-5, at 15 (filed Apr. 25, 2022).

12. Commenters also note that weather sensors (which measure,

e.g.,

wind speed, wind direction and/or cloud cover) and conductor sensors (which measure conductor properties such as temperature, sag or tension) can provide real-time operational awareness. Commenters explain that such operational awareness can be useful for a transmission provider to monitor specific events, such as ice on a transmission line or the response of a transmission line operating near its rating limit. Commenters also state that local sensors provide an additional way to verify weather conditions in real time, which may be especially useful along frequently limiting spans.

See

LineVision Comments, Docket No. AD22-5, at 8-10 (filed Apr. 25, 2022); TAPS Comments, Docket No. AD22-5, at 7 (filed Apr. 25, 2022); TS Conductor Comments, Docket No. AD22-5, at 9-10 (filed Mar. 13, 2022); WATT/CEE Comments, Docket No. AD22-5, at 14 (filed Apr. 25, 2022); Electricity Canada Comments, Docket No. AD22-5, at 6 (filed Apr. 25, 2022). A transmission span is the distance between specific transmission support towers.

13. Some commenters discuss different considerations and challenges with DLRs, which are described in more detail below.

B. Transmission Line Ratings Background

14. Transmission line ratings are determined by the most limiting element among the components that make up the transmission facility, which includes the conductors and the associated equipment necessary for the transfer or movement of electric energy across a transmission facility (

e.g.,

switches, breakers, busses, line traps, metering equipment, and relay equipment).

A transmission line rating is the maximum transfer capability of a transmission line taking into account the technical limitations on conductors, relevant transmission equipment, and the transmission system.

As the Commission explained, “Relevant transmission equipment may include, but is not limited to, circuit breakers, line traps, and transformers.”

For purposes of the discussion that follows, references to transmission “line” ratings encompass ratings for all transmission equipment that has a rating.

Order No. 881, 177 FERC ¶ 61,179 at P 44.

Id.

1. Different Types of Transmission Line Ratings: Based on Thermal, Voltage, and Stability Limits

15. Transmission line ratings are based on the most limiting of three types of limits: thermal limits; voltage limits; and stability limits. The thermal limit reflects the maximum amount of power that can safely flow on a transmission line without it overheating. Each transmission line may have several thermal limits depending on the duration of power flow considered, with a lower thermal limit for normal operations and higher thermal limits for long-term and short-term emergency operations. However, voltage and stability limits are typically fixed values that limit the power flow on a transmission line from exceeding the point above which there is an unacceptable risk of a voltage or stability problem.

2. Calculating Thermal Ratings

16. Thermal ratings are determined based on the physical characteristics of the conductor and assumptions about environmental conditions (

e.g.,

ambient air temperature, sun position, cloud cover, wind, or other weather conditions). Thermal ratings determine the maximum amount of power that can flow through a conductor while keeping the conductor under its “maximum operating temperature,” a limit designed to prevent wear on the conductor and comply with ground clearance and conductor sag requirements. Engineering standards, including those published by the Institute of Electrical and Electronics Engineers (IEEE) and the International Council on Large Electric Systems (CIGRE), establish methods for calculating transmission line ratings based on the conductor properties and weather conditions.

The National Electrical Safety Code (NESC) provides minimum clearance requirements between the transmission conductor and other facilities, including, but not limited to, minimum clearances to other electrical circuits, communications cables, structures below the transmission conductor, vegetation, railroads, roadways, waterways, and ground.

See, e.g.,

IEEE Standard 738-2023, “IEEE Standard for Calculating the Current-Temperature Relationship of Bare Overhead Conductors,” 2023 (IEEE 738); and CIGRÉ Technical Brochure 207, “Thermal Behavior of Overhead Conductors, Working Group 22.12,” 2002 (CIGRÉ 207).

See, e.g.,

IEEE Standard C2-2023, “2023 National Electric Safety Code,” 2023, at section 23.

17. Thermal ratings are calculated using formulas, which are based on forecast- or assumption-based inputs that require the use of confidence levels. Confidence levels represent the likelihood that the actual real-time value of that input is less than or equal to the assumption or forecast. For some inputs in thermal ratings formulas, forecast uncertainty may not be normally distributed. In other words, there may be more forecast uncertainty as the input approaches a historic limit or extreme level. For example, if an ambient air temperature forecast approaches an extreme level (

e.g.,

an unusually high temperature for a given location), the uncertainty about that forecast may become skewed such that the actual ambient air temperature value is more likely to be below the forecast temperature than above it.

Choosing

confidence levels requires a balance between realizing the benefits of incorporating weather forecasts and ensuring that the estimate does not overestimate the thermal capability of the transmission line, which could create system management challenges for transmission providers and/or jeopardize reliability.

Lisa Sosna, et al.,

Demonstration of Potential Data/Calculation Workflows Under FERC Order 881's Ambient-Adjusted Rating (AAR)

Requirements,

joint FERC/NOAA staff presentation at FERC's Software Conference at slide 24-25 (June 23, 2022),

https://www.ferc.gov/media/demonstration-potential-datacalculation-workflows-under-ferc-order-no-881s-ambient-adjusted.

3. Variables That Impact Thermal Ratings of Transmission Lines

18. Thermal ratings are affected by a variety of factors, including ambient air temperatures, solar heating, and wind speed.

a. Ambient Air Temperature

19. Transmission line thermal ratings generally decrease with warmer ambient air temperatures and generally increase with cooler ambient air temperatures, because the heat generated within the conductor due to resistive losses dissipates to the environment more quickly at lower ambient temperatures.

b. Solar Heating

20. Transmission line thermal ratings generally decrease when exposed to more intense solar heating conditions and generally increase when exposed to less intense solar heating conditions, because lower solar heating allows the conductor to carry more power without overheating. Solar heating is most intense when there are clear-sky conditions, and the sun is at its peak position in the sky.

c. Wind Speed and Direction

21. Wind cools a transmission line, which dissipates the heat generated from resistive losses more quickly and results in greater transmission transfer capability on that line. Transmission line thermal ratings generally increase when wind speed is higher and when wind direction is perpendicular to a line and generally decrease when wind speed is lower and when wind direction is parallel to a line. According to research presented by Idaho National Laboratory at the Commission's 2019 DLR Workshop, consideration of wind speed and direction could theoretically increase transmission line ratings by more than 100% in certain periods.

In practice, the typical increase in transmission line ratings may be smaller than 100%, but it would still be significant, because consideration of forecast uncertainty and confidence levels for both wind speed forecasts and wind direction forecasts would reduce the potential rating increases. A higher confidence level would proportionally discount the impact of reflecting wind speed and direction on a transmission line rating.

Jake Gentle, et al.,

Forecasting for Dynamic Line Ratings,

Idaho National Laboratory presentation at FERC DLR Workshop slide 13 (Sept. 10, 2019),

https://www.ferc.gov/sites/default/files/2020-09/Gentle-INL.pdf.

See

Order No. 881, 177 FERC ¶ 61,179 at P 128 (acknowledging concerns about temperature forecast margins being too low or too high).

C. Incorporating Weather Variables Into Thermal Ratings

22. Because a variety of weather variables affect thermal ratings, DLRs can incorporate weather variables that “reflect transfer capability even more accurately” than static line ratings.

In addition to ambient air temperature, DLRs can incorporate weather variables and other inputs into the calculation of thermal ratings “such as (but not limited to) wind, cloud cover, solar heating (beyond daytime/nighttime distinctions), precipitation, and transmission line conditions such as tension or sag.”

Moreover, the use of sensors installed on or near the transmission line can provide localized and potentially more accurate weather forecasts when compared to large-area weather forecasts, such as those provided by the National Weather Service, further improving DLR accuracy.

See id.

P 26.

See id.

P 7.

23. DLR implementation requires making reliable short-term forecasts

at very specific locations. In DLR implementation, weather measurements and, potentially, other data from sensors are combined with data from the recent past to create short-term weather forecasts for the specific location of the transmission line. These short-term weather forecasts are the basis of the DLRs themselves.

Although clear-sky solar heating calculations are generally referred to as forecasts, they may be better thought of as “determinations” because they carry no forecast uncertainty. Total solar power along a transmission line can be calculated based on the location and orientation of a transmission line, at any time and day of the year.

See

Conseil International des Grands Réseaux Électriques/International Council of Large Electric Systems (CIGRE), Guide for Thermal Rating Calculations of Overhead Lines, Technical Brochure 601, Dec. 2014 (CIGRE TB 601). Thus, our use of “forecast” here when referring to clear-sky solar heating is not intended to indicate any expected forecast uncertainty about the determination of clear-sky solar heating.

See, e.g.,

Jake Gentle, et al.,

Dynamic Line Ratings Forecast Time Frames,

Idaho National Lab (2023), Dynamic-Line-Rating-Forecasting-Time-Frames.pdf (inl.gov);

Managing Transmission Line Ratings,

Docket No. AD19-15-000, Technical Conference, Day 1 (Sept. 10, 2019), Tr. 29:1-3 (Joey Alexander, Ampacimon SA) (filed Oct. 8, 2019) (discussing a DLR project undertaken by Elia, Belgium's transmission system operator and noting that, “they wanted to make sure they could implement a two-day ahead forecast of the DLR because that's what that market traded on”);

see also Managing Transmission Line Ratings,

Staff Report, Docket No. AD19-15-000, at 10 (issued Aug. 23, 2019) (“As mentioned earlier, forecasting of the relevant weather conditions and line ratings over some operationally useful period . . . is necessary for DLR implementation.”).

24. DLRs are implemented through the following steps: identifying candidate transmission lines; installing any needed sensors and data communication systems; forecasting short-term weather conditions; revising thermal ratings formulas; and validating thermal ratings and integrating them in an energy management system (EMS).

See

Order No. 881, 177 FERC ¶ 61,179 at P 7.

1. Sensors and Their Use in DLRs

25. Generally, two types of sensors can be used to implement DLRs: (1) weather sensors that measure factors like wind speed, wind direction, and/or cloud cover; and (2) conductor sensors that measure the condition of the transmission line itself, such as conductor temperature, sag, or tension.

26. Sensors can be positioned either on the ground or on the transmission line. Each option has advantages and disadvantages.

For instance, sensors placed on a transmission line may require transmission line outages for installation and maintenance, while ground-based sensors can be easier to install and maintain. However, ground-based sensors are more vulnerable to physical tampering and could pose a security threat for safe operations.

Some DLR systems incorporate photo-spatial sensors (

e.g.,

light detection and ranging (LiDAR)) and/or line sensors installed on or close to the monitored transmission line.

The ideal placement of a sensor can depend upon the sensor technology and which variable the sensor is trying to measure. For example, optical fiber sensors that are placed inside a conductor can measure conductor properties but may not be capable of measuring ambient weather conditions.

Managing Transmission Line Ratings,

Staff Report, Docket No. AD19-15-000, at 9 (issued Aug. 23, 2019).

Id.

at 7-8.

27. The real-time data acquired from either type of sensor can provide many benefits to the DLR systems and the transmission providers using them. For example, data from sensors can provide real-time operational awareness to grid operators, helping to identify

unexpected changes in a transmission line's capacity. Data from sensors can also be used to verify the thermal rating calculated for the transmission line, a process known as “ratings validation.” Data from sensors can also help measure the accuracy of the local weather forecasts underlying DLRs and provide information with which to improve the forecasting methodology, a process known as “forecast training.” Both ratings validation and forecast training can improve thermal ratings over time. Moreover, forecast training can help transmission providers discover systemic patterns in local forecast errors and thus adjust their forecasting methods to improve local forecast accuracy. As a simplified example, a transmission provider may observe that actual wind speeds, as measured by a sensor, in a particular valley are consistently lower than the weather forecasts indicate for the broader area. In this case, the transmission provider could develop a “trained” forecast reflecting a lower localized wind speed forecast for that valley, which could be used to calculate the transmission line's thermal ratings more accurately.

Rating validation and forecast training do not necessarily have to use

weather

sensors;

conductor

sensors can also be used for these purposes. While conductor sensors do not measure weather variables directly, conductor sensor measurements nonetheless reflect the effects of real-time weather, and thus can be used to indirectly validate and train weather forecasts.

28. However, some weather elements can be incorporated into a transmission line rating without a sensor. For instance, in addition to ambient air temperature, initial outreach indicates that solar heating based on the sun's position and some forecasts of cloud cover can be incorporated into transmission line ratings without sensors.

29. The effective use of sensors to determine DLRs requires at least four key considerations: what type of sensors and where to place them; how many sensors are needed; how to configure them; and how to ensure physical security and cybersecurity. Sensor placement requires a careful assessment of the sensor type, the number of sensors needed, and the location for each of the sensors to be installed.

30. The appropriate quantity and configuration of sensors depends on the type of sensors used and the weather variables they measure. Weather-based DLR systems may incorporate real-time measurements and/or forecasts of wind conditions because wind conditions have the greatest effect on the thermal rating of a transmission line.

However, because wind speed and direction are highly variable and subject to local geographic differences,

real time measurements of wind conditions may require numerous sensors. As such, reflecting wind conditions in transmission line ratings can be costly because it requires installation and maintenance of sufficient local sensors and communications equipment.

WATT/CEE Comments, Docket No. AD22-5, at 14 (filed Apr. 25, 2022).

Clean Energy Parties Comments, Docket No. AD22-5, at 12 (filed Apr. 25, 2022).

31. Generally, placing more sensors at rating-limiting elements or spans ensures more granular data to calculate transmission line ratings.

Generally, placing fewer sensors can diminish the granularity and accuracy and may require transmission providers to interpolate the weather and transmission line data from sensors on other parts of the transmission line, which could be difficult or impractical, and factors such as varied terrain or turns in the transmission line could make this calculation potentially inaccurate. Varied terrain turns in the transmission line, and the length of the transmission line, each create the need for more sensors, but each sensor represents an additional cost. Thus, sensor placement can be more expensive for both transmission providers with longer transmission lines and those with transmission lines in hilly or mountainous areas.

For example, BPA explains that it paid $50,000 for each of its DLR sensors, and an additional $17,500 each for installation, in its DLR study with EPRI. BPA Comments, Docket No. AD22-5, at 9 (filed Apr. 25, 2022).

32. DLR implementation also involves physical security and cybersecurity risks. Therefore, as with other transmission systems, protections must be put in place to ensure the physical security and cybersecurity of the communications equipment, computer hardware, and computer software required to integrate and manage DLR systems, which can include sensors and/or alternative data sources, and associated data in the transmission provider's EMS. DLR systems may rely upon numerous routable devices, each of which may be vulnerable to cyberattack. Physical security and cybersecurity protections must be installed to protect and ensure that the new sensor system is not tampered with or compromised. Moreover, transmission providers implementing DLRs may not be able to use the off-the-shelf computer systems, cloud solutions, and/or services offered by vendors.

Instead, transmission providers may have to build their own secure, on-premises computer systems, rely on services that comply with applicable North American Electric Reliability Corporation (NERC) Reliability Standards, and quickly adopt developing best practices to ensure that the DLR system is secure.

See, e.g.,

PPL Comments, Docket No. AD22-5, at 17-18 (filed Apr. 25, 2022).

2. Incorporating Local Weather Forecasts Into DLRs

33. While DLRs that rely on weather forecasts may offer significant value, forecasting local weather may present several challenges, with related opportunities for solutions. First, because all transmission line ratings—including DLRs—depend upon the transmission line's most-limiting element, the location of the most-limiting element must be determined to identify which local weather forecast is needed. Further, changes in the local weather may change which of the weather-sensitive elements is most limiting.

However, while identifying limiting segments across a transmission line may appear conceptually challenging, a joint FERC/National Oceanic and Atmospheric Administration (NOAA) staff presentation concluded that determining the location of the most-limiting segment for purposes of AAR calculations can be relatively simple once the transmission line rating formula and weather data processing is established.

For example, if the wind were to stop blowing across one segment of a transmission line and were to start blowing across another segment, the former segment might become the most limiting element. Therefore, thermal ratings for each segment on a transmission line must be frequently redetermined based on up-to-date weather forecasts, and thus the most limiting element or transmission line span may vary.

See, e.g.,

Lisa Sosna,

et al., Demonstration of Potential Data/Calculation Workflows Under FERC Order 881's Ambient-Adjusted Rating (AAR) Requirements,

joint FERC/NOAA staff presentation at FERC's Software Conference slides 10, 14 and 26 (June 23, 2022),

https://www.ferc.gov/media/demonstration-potential-datacalculation-workflows-under-ferc-order-no-881s-ambient-adjusted

(FERC/NOAA staff evaluated ratings at numerous elements on each line they demonstrated AAR calculations for, adopting the rating at the most conservative element as the rating of the overall line; “Our approach proved to support very quick calculation of line ratings despite the large number of rating [elements].”). In theory, establishing such a process could be more complicated for DLR systems that consider additional weather variables.

34. Second, incorporating additional weather variables into transmission line ratings will require preparing forecasts for each variable, which may be more resource intensive. For example, due to increased variability and micro-geographic differences, forecasting wind speed and direction may require more

analysis from meteorologists than ambient air temperature forecasts.

35. Third, relying on weather forecasts for calculating transmission line ratings exposes transmission providers to forecasting uncertainty. In most instances, reductions in forecasted transmission line ratings can be identified hours or days ahead of the operating hour, giving transmission providers and market participants time to act to ensure flows do not exceed transmission line ratings. However, in some instances, when changes in forecasts happen at or close to the operating hour and cause potential reliability concerns, transmission system operators may need to issue curtailment or redispatch instructions to manage the shortage in transmission capability, which could be operationally similar to transmission line derates that do not involve DLRs. This challenge can be managed through specification of appropriate forecast confidence levels and related forecast margins.

Where weather conditions are particularly challenging to forecast, achieving the necessary confidence levels may require significant forecast margins that may make DLRs impractical, even on heavily congested transmission lines. We discuss this challenge further below in section IV.A.6. Confidence Levels.

A forecast margin is a margin by which a forecast of an expected parameter is adjusted (up or down, depending on the circumstance) to provide sufficient confidence that the actual parameter value will not be less favorable than the forecast.

See, e.g.,

Order No. 881, 177 FERC ¶ 61,179 at P 128.

3. Current Use and Benefits of DLRs

36. As discussed further in the Need for Reform section below, numerous DLRs have already been deployed domestically and internationally, with resulting benefits to the transmission system and customers, including increased transmission capacity, reduced congestion, and reduced costs.

D. Pro forma Transmission Scheduling and Congestion Management Practices

37. As relevant here, transmission line ratings are used by transmission providers

in determining: (1) whether a transmission service request is approved or denied; and (2) when and how transmission service must be curtailed or redispatched to protect reliability or interrupted to provide service to a higher-priority customer.

In this ANOPR, we use transmission provider to mean any public utility that owns, operates, or controls facilities used for the transmission of electric energy in interstate commerce. 18 CFR 37.3. Therefore, unless otherwise noted, “transmission provider” refers only to public utility transmission providers. The term “public utility” as defined in the FPA means “any person who owns or operates facilities subject to the jurisdiction of the Commission under this subchapter.” 16 U.S.C. 824(e).

Transmission line ratings are also used by transmission providers for other purposes, including as part of transmission planning.

1. How Transmission Service Is Procured

38. Because the preliminary proposals discussed herein—both for identifying the congested transmission lines that would be subject to a DLR requirement and the transmission services that would be impacted by such a DLR requirement—relate to the details of transmission service and congestion management practices under the

pro forma

OATT, we provide an overview of those services and practices.

a. Transmission Service Under the pro forma OATT

39. There are two types of transmission service provided under the

pro forma

OATT: (1) point-to-point transmission service; and (2) network integration transmission service.

40. Point-to-point transmission service is the reservation and transmission of capacity and energy from the point(s) of receipt to the point(s) of delivery.

Point-to-point transmission service is offered on a firm and non-firm basis.

When evaluating a point-to-point transmission service request, the transmission provider determines whether there is sufficient available transfer capability (ATC) from a specified point-of-receipt to a specified point-of-delivery. ATC can be calculated for any path on the transmission system to determine if the system has available capacity to reliably accommodate new transmission customers, using as inputs total transfer capability (TTC) and existing transmission commitments (ETC) on that path, as well as the amount of transfer capability reserved as part of the capacity benefit margin (CBM) and transmission reliability margin (TRM).

Specifically, ATC is calculated as: ATC = TTC − ETC − CBM − TRM.

Pro forma

OATT, section 1.37 (Point-To-Point Transmission Service).

Id.; id.

section 13.6 (Curtailment of Firm Transmission Service).

Section 37.6 of the Commission's regulations defines CBM as “the amount of TTC preserved by the transmission provider for load-serving entities, whose loads are located on that Transmission Provider's system, to enable access by the load-serving entities to generation from interconnected systems to meet generation reliability requirements, or such definition as contained in Commission-approved Reliability Standards.” 18 CFR 37.6(b)(1)(vii). Section 37.6 defines TRM as “the amount of TTC necessary to provide reasonable assurance that the interconnected transmission network will be secure, or such definition as contained in Commission-approved Reliability Standards.”

Id.

§ 37.6(b)(1)(viii).

Preventing Undue Discrimination & Preference in Transmission Serv.,

Order No. 890, 72 FR 12266 (Mar. 15, 2007), 118 FERC ¶ 61,119, at P 209,

order on reh'g,

Order No. 890-A, 72 FR 12266 (Mar. 15, 2007), 121 FERC ¶ 61,297 (2007),

order on reh'g,

Order No. 890-B, 123 FERC ¶ 61,299 (2008),

order on reh'g,

Order No. 890-C, 74 FR 12540 (Mar. 25, 2009), 126 FERC ¶ 61,228,

order on clarification,

Order No. 890-D, 74 FR 61511 (Nov. 25, 2009), 129 FERC ¶ 61,126 (2009).

41. The transmission line rating of a given transmission line is the primary input into determining its TTC and, thus, is a key determinant of the transmission line's ATC. ATC on a path is not a single, static value; rather, it has different values based on the requested point-to-point transmission service duration (hourly, daily, weekly, monthly, annual), time (when service is requested to start and end), and priority (firm or non-firm). For example, firm annual ATC starting January 1 of a given year might be zero because of high levels of ETC during the summer months, while firm monthly, weekly, and daily ATC on the same path may be higher during non-summer months.

42. In the event a transmission provider is unable to accommodate a request for long-term (

i.e.,

with a term of one year or more) firm point-to-point transmission service, the

pro forma

OATT establishes various obligations on the transmission provider, including obligations related to redispatch and conditional firm transmission service. First, such a transmission provider must (under certain conditions) use due diligence to provide redispatch from its own resources and not unreasonably deny self-provided redispatch or redispatch arranged by a transmission customer from a third party.

Second, such a transmission provider must offer to provide firm transmission service with the condition that it may curtail the service prior to the curtailment of other firm transmission service for a specified number of hours per year or during specified system condition(s) (

i.e.,

conditional firm transmission service).

Pro forma

OATT, section 15.4(b).

Id.

section 15.4(c);

id.

section 19.3 (System Impact Study Procedures).

43. Network integration transmission service or network service allows a network customer to use the transmission system in a manner comparable to how the transmission provider uses its own transmission system to serve its native load. Specifically, network service allows a network customer's network resources (generators, firm energy purchases, etc.) to be integrated and economically dispatched to serve its network load.

44. Network service is provided from a fleet of network resources to a set of network loads rather than from a single point-of-receipt to a single point-of-delivery.

As such, when evaluating network integration transmission service requests, a transmission provider performs load-flow modeling of various anticipated dispatches on its system and compares the modeled flows on each impacted transmission line to the transmission line's rating.

Pro forma

OATT, pt. III (Network Integration Transmission Service Preamble);

id.

section 28 (Nature of Network Integration Transmission Service).

Pro forma

OATT, section 32 Additional Study Procedures For Network Integration Transmission Service Requests, attach. C (Methodology To Assess Available Transfer Capability), and attach. D (Methodology for Completing A System Impact Study).

b. Congestion Management Under the pro forma OATT

45. Congestion is managed under the

pro forma

OATT according to service priority. While there are some exceptions, the typical order of service priority is: (1) network integration transmission service and long-term (one year or longer) firm point-to-point; (2) short-term (less than one year) firm point-to-point; (3) conditional firm transmission service and secondary service; and (4) non-firm point-to-point.

Under the

pro forma

OATT, network integration transmission service is subject to curtailment or redispatch, while point-to-point transmission service is subject to curtailment or interruption.

Under the

pro forma

OATT, curtailment and redispatch are typically done for reliability reasons, whereas interruption is typically conducted for economic reasons. Prior to curtailing network integration transmission service and/or long-term firm point-to-point service, transmission providers may, however, be required to redispatch network customers' resources and the transmission provider's own resources, on a least-cost and non-discriminatory basis and without respect to ownership of such resources, to relieve a transmission constraint or maintain reliability.

Id.

section 13.6 (Curtailment of Firm Transmission Service);

id.

section 14.7 (Curtailment or Interruption of Service);

id.

section 33 (Load Shedding and Curtailments).

The

pro forma

OATT defines curtailment as a reduction in firm or non-firm transmission service in response to a transfer capability shortage as a result of system reliability conditions.

Id.

section 1.8 (Curtailment). The

pro forma

OATT defines interruption as a reduction in non-firm transmission service due to economic reasons pursuant to section 14.7.

Id.

section 1.16 (Interruption).

Id.

section 33.2 (Transmission Constraints).

c. Transmission Scheduling and Congestion Management in the RTOs/ISOs

46. All RTO/ISO tariffs reflect Commission-approved variations from the

pro forma

OATT provisions. In RTOs/ISOs, transmission service is typically provided as part of the security-constrained economic dispatch (SCED) and security-constrained unit commitment (SCUC) processes performed by the market software. As part of SCED and SCUC, the market software performs a constrained optimization based on supply offers and demand that minimizes production costs and ensures (among other things) that flows on transmission lines do not exceed transmission line ratings. Therefore, transmission line ratings are a primary factor in the optimization process and efficient pricing.

While SCED and SCUC processes consider power flow over the interties, RTOs/ISOs do not typically optimize ATC in the same manner as internal locations.

2. Existing Data Reporting on Congestion, or Proxies of Congestion

47. The availability of data measuring the cost of congestion on the transmission system, or proxies that could be used to estimate the cost of congestion, varies between RTO/ISO and non-RTO/ISO regions.

a. RTOs/ISOs

48. In RTO/ISO markets, at least two types of congestion metrics are computed and publicly reported. First, as part of solving their real-time and day-ahead markets, RTOs/ISOs compute and publish locational marginal prices (LMP) that include a “congestion component,” indicating how much congestion has increased (or decreased) a locational price at a node compared to reference node(s).

The congestion component of an LMP for a node reflects the extent to which an additional increment of load at that node would, because of binding transmission constraints, need to be supplied by resources with different marginal costs than the resources available to serve additional increments of load at the reference node(s).

For example, if an RTO/ISO must ramp up a higher-cost peaking unit in lieu of a lower-cost baseload unit due to a transmission constraint, the additional incremental cost of the peaking unit would be reflected in the congestion component of LMP. Second, as part of solving their real-time and day-ahead markets, RTOs/ISOs compute and publish the marginal cost of each transmission flow constraint, sometimes called the “shadow prices” of those constraints. These shadow prices reflect the marginal production cost savings that would occur if the flow limit on a constraint were relaxed by one MW. Shadow prices are used to calculate the marginal congestion component of LMP.

LMPs and shadow prices reflect

marginal

rather than

total

costs.

See, e.g.,

ISO-NE,

FAQs: Locational Marginal Pricing,

(Feb. 2024),

https://www.iso-ne.com/participate/support/faq/lmp

; NYISO,

LBMP In-Depth Course: Congestion Price Component

4-15 (Nov. 2022),

https://www.nyiso.com/course-materials

; MISO,

MTEP18: Book 4 Regional Energy Information,

at 8 (2018).

See

NYISO,

LBMP In-Depth Course: Congestion Price Component

19-21 (Nov. 2022),

https://www.nyiso.com/course-materials

; FERC,

Energy Primer: A Handbook for Energy Market Basics

69-71 (2024),

https://www.ferc.gov/sites/default/files/2024-01/24_Energy-Markets-Primer_0117_DIGITAL_0.pdf

The MISO tariff and the CAISO Business Practice Manual for Definitions and Acronyms both define “shadow price” as “the marginal value of relieving a particular constraint.”

See

MISO, MISO Tariff, Module A—Common Tariff Provisions, Definitions—S (Shadow Price),

https://www.misoenergy.org/legal/rules-manuals-and-agreements/tariff/

; CAISO,

Business Practice Manual for Definitions & Acronyms

128, (Jan. 21, 2023),

https://bpmcm.caiso.com/BPM%20Document%20Library/Definitions%20and%20Acronyms/2023-Jan31_BPM_for_Defintions_and_Acronyms_V20_Redline.pdf

b. Non-RTO/ISO Regions

49. Non-RTO/ISO regions do not publish nodal prices in the same manner as RTOs/ISOs, which can result in less public information available on congestion costs outside of RTOs/ISOs. However, practices to manage congestion and redispatch of internal resources may be used to assess congestion costs in non-RTO/ISO regions.

i. ATC and Constrained Posted-Paths

50. Section 37.6 of the Commission's regulations requires transmission providers to calculate and post certain information, including ATC and TTC.

Such calculations and postings must be made for the following posted paths: (1) any control-area-to-control area interconnection; (2) any path for which service has been denied, curtailed, or interrupted for more than 24 hours in the past 12 months; and (3) any path for which a transmission customer has requested that ATC or TTC be posted.

For all posted paths, ATC, TTC, CBM, and TRM values must be automatically posted.

These postings allow potential transmission customers to: (1) make requests for transmission services offered by transmission providers, request the designation of a network resource, and request the termination of

the designation of a network resource; (2) view and download information regarding the transmission system necessary to enable prudent business decision making; (3) post, view, upload and download information regarding available products and desired services; (4) identify the degree to which transmission service requests or schedules were denied or interrupted; (5) obtain access to information to support ATC calculations and historical transmission service requests and schedules for various audit purposes; and (6) make file transfers and automate computer-to-computer file transfers and queries.

18 CFR 37.6.

Id.

§ 37.6(b)(1)(i).

Id.

§ 37.6(b)(3).

Id.

§ 37.6(a).

51. Section 37.6(b)(1)(ii) of the Commission's regulations defines constrained posted paths as any posted paths that have ATC less than or equal to 25 percent of TTC at any time during the preceding 168 hours or for which ATC has been calculated to be less than or equal to 25 percent of TTC for any period during the current hour or the next 168 hours.

For all constrained posted paths, additional detailed information must be made available upon request.

This includes “all data used to calculate ATC [and] TTC,” including relevant transmission line ratings, identification of limiting element(s), the cause of the limit (

e.g.,

thermal, voltage, stability), and load forecast assumptions.

Id.

§ 37.6(b)(1)(ii).

Id.

§ 37.6(b)(2)(ii).

Id.

52. Under these requirements, depending on whether the paths are constrained or unconstrained, transmission providers are required to post firm and non-firm ATC and related data for many different timeframes (

e.g.,

daily, monthly, seasonally, annually) for different durations into the future ranging from daily ATC for the next day to annual ATC as far out as 10 years (in certain circumstances for some constrained posted paths).

Other posting requirements (including posting of hourly ATC) apply to non-firm ATC. All such postings are typically made to the transmission providers' Open Access Same-Time Information System (OASIS) site.

Id.

§ 37.6(b)(3).

ii. Redispatch Costs

53. Under the

pro forma

OATT, transmission providers may redispatch resources due to the existence of transmission constraints in certain circumstances.

Because non-RTO/ISO regions do not publish nodal prices that reflect congestion costs, the cost of redispatching resources is less transparent.

Nonetheless, redispatching of resources in non-RTO/ISO regions to manage congestion may be comparable to the practices in RTOs/ISOs in that both are tasked with reliably serving wholesale transmission customers at least cost.

Section 33.2 of the

pro forma

OATT provides that during any period when the Transmission Provider determines that a transmission constraint exists on the Transmission System, and such constraint may impair the reliability of the Transmission Provider's system, the Transmission Provider will take whatever actions, consistent with Good Utility Practice, that are reasonably necessary to maintain the reliability of the Transmission Provider's system. Section 33.2 of the

pro forma

OATT provides that to the extent the Transmission Provider determines that the reliability of the Transmission System can be maintained by redispatching resources, the Transmission Provider will initiate procedures pursuant to the Network Operating Agreement to redispatch all Network Resources and the Transmission Provider's own resources on a least-cost basis without regard to the ownership of such resource. Section 33.2 of the

pro forma

OATT further provides that any redispatch under this section may not unduly discriminate between the Transmission Provider's use of the Transmission System on behalf of its Native Load Customers and any Network Customer's use of the Transmission System to serve its designated Network Load.

Any redispatch costs are allocated proportionately to the load ratio share of the transmission provider and network customers.

See pro forma

OATT, section 33.3 (Cost Responsibility for Relieving Transmission Constraints).

III. The Potential Need for Reform

54. As a result of the continued development of DLR technology, the record gathered in the NOI, and outreach conducted since the issuance of the NOI, we believe that it is appropriate to examine whether transmission line ratings that fail to reflect forecasts of solar heating and wind speed and direction result in sufficiently accurate transmission line ratings and whether reforms may be necessary to improve the accuracy of transmission line ratings and ensure transparency of their development and implementation. Without these reforms, we believe that transmission line ratings may be insufficiently accurate and may unjustly and unreasonably increase the cost to reliably serve wholesale electric customers by forgoing many potential benefits. As the Commission has previously found, inaccurate transmission line ratings result in Commission-jurisdictional rates that are unjust and unreasonable.

Accordingly, we preliminarily find that transmission line ratings that do not account for solar heating and wind conditions may result in rates and practices that are unjust, unreasonable, unduly discriminatory or preferential. We begin with a discussion about existing uses of DLRs and their associated benefits before discussing potential reforms.

Order No. 881, 177 FERC ¶ 61,179 at P 3.

A. Demonstrated DLR Benefits

55. DLRs have been deployed nationally and internationally, with resulting benefits to the transmission system and customers, including increased transmission capacity, reduced congestion, and reduced costs. Existing DLR projects and data demonstrating their benefits strengthen the potential need for reform.

1. U.S. Examples

56. In the United States, some transmission providers and system operators report using DLR systems to curb congestion, increase transmission capacity, and reduce costs. Below, we detail four specific examples of DLR use. These examples illustrate how DLRs can more accurately reflect the capability of a transmission facility and result in cost savings where congestion is decreased due to increased transmission capability.

57. First, PPL, which owns transmission facilities in PJM, has spent approximately $1 million implementing DLRs, using 18 sensors on more than 31 miles of three 230 kV transmission line segments, and has integrated DLRs for these transmission lines into PJM's real-time and day-ahead markets.

By contrast, PPL states that it internally estimated the cost to reconductor the Susquehanna-Harwood double-circuit line to be approximately $12 million.

PPL reports that, based on 2022 data, implementing DLR on these three transmission lines produced normal ratings gains above AARs of approximately 17% and emergency ratings gains above AARs ranging from 8.5% to 16.5%.

PPL further reports that deploying DLR on two Susquehanna-Harwood lines eliminated congestion, which was $12 million per year in the summer of 2022, and that, deploying DLR on the Juniata-Cumberland transmission line decreased congestion costs from approximately $66 million in the winter of 2021-22 to approximately $1.6 million in the winter of 2022-23. PPL explains that it aims to implement DLR

on five additional transmission lines by the end of 2024.

Idaho National Laboratory,

A Guide to Case Studies of Grid Enhancing Technologies

11 (Oct. 2021),

https://inl.gov/content/uploads/2023/03/A-Guide-to-Case-Studies-for-Grid-Enhancing-Technologies.pdf

; T&D World,

PPL Electric Utilities Wins 95th Annual Edison Award

(June 2023),

https://www.tdworld.com/electric-utility-operations/article/21267742/ppl-electric-utilities-wins-95th-annual-edison-award

PPL Comments, Docket No. AD22-5, at 14-15 (filed Apr. 25, 2022).

PPL Supplemental Comments, Docket No. AD22-5, at 2-4 (filed Feb. 9, 2024).

Id.

58. PJM notes that, during Winter Storm Elliott, DLRs on the previously mentioned PPL transmission lines proved higher than the AARs, and that, had PJM not had the higher DLRs, PJM would have had to redispatch the system to maintain reliability. PJM adds that such action would have been very difficult under the critical operating conditions caused by the winter storm.

PJM Supplemental Comments, Docket No. AD22-5, at 2 (filed Jan. 17, 2024).

59. In a DLR deployment study of a single 115 kV transmission line owned by National Grid in Massachusetts, DLRs were found to increase transmission capacity by approximately 16% above AARs (excluding periods when DLRs were lower than AARs). However, the project also recorded that DLRs were below AARs 22% of the time in the summer and 27% of the time in the winter (at times when wind speed was low and the AAR would have been overstated).

The DLR sensors were reported as “easy to install, reliable, and effective at reporting periods of either excess or limited capacity.”

K. Engel, J. Marmillo, M. Amini, H. Elyas, B. Enayati,

An Empirical Analysis of the Operational Efficiencies and Risks Associated with Static, Ambient Adjusted, and Dynamic Line Rating Methodologies

3, 8 (Jul. 2, 2021),

https://cigre-usnc.org/wp-content/uploads/2021/11/An-Empirical-Analysis-of-the-Operational-Efficiencies-and-Risks-Associated-with-Line-Rating-Methodologies.pdf

Idaho National Laboratory,

A Guide to Case Studies of Grid Enhancing Technologies

8 (Oct. 2022),

https://inl.gov/content/uploads/2023/03/A-Guide-to-Case-Studies-for-Grid-Enhancing-Technologies.pdf

60. A Department of Energy (DOE) report described implementation of DLRs using tension sensors along five 345 kV transmission lines and three 138 kV transmission lines by Oncor Electric Delivery Company's (Oncor), a transmission owner in ERCOT. The report noted that DLRs increased the available capacity of the lines by between 6% and 14% beyond the transmission lines' AARs, on average. As described in the report, Oncor determined that the cost of installing DLRs ranged from $16,000 to $56,000 per mile, depending on the type of transmission towers upon which DLR equipment was installed.

The report noted that installation costs in this instance totaled approximately $4.8 million and that DLR system costs are often only a fraction of the cost of reconductoring or rebuilding a transmission line.

Warren Wang and Sarah Pinter, U.S. Dept. of Energy,

Dynamic Line Rating Systems for Transmission Lines

at 33, U.S. Dept. of Energy (Apr. 2014),

https://www.energy.gov/sites/prod/files/2016/10/f34/SGDP_Transmission_DLR_Topical_Report_04-25-14.pdf

Id.

61. In August 2021, Duquesne Light Company (Duquesne), a transmission owner in PJM, partnered with LineVision on a DLR pilot project.

The pilot project installed DLRs on 345 kV lines in southwestern Pennsylvania and increased the lines' available capacity by 25%, on average. In 2022, Duquesne expanded the pilot program and installed sensors to also monitor 138 kV transmission lines, reporting an average transmission line rating increase of 25%, which, it asserts, has helped to make way for more renewable energy sources.

Duquesne,

Duquesne Light Company Investing in New Technology to Enhance Grid Capacity and Reliance,

NewsRoom (Aug. 2021),

https://newsroom.duquesnelight.com/duquesne-light-company-investing-in-new-technology-to-enhance-grid-capacity-and-reliance

LineVision, Inc,

Duquesne Light Company Further Enhances Transmission Capacity, Reliability with Grid-Enhancing Technology

(Aug. 2022),

https://www.linevisioninc.com/news/duquesne-light-company-further-enhances-transmission-capacity-reliability-with-grid-enhancing-technology

62. In addition, a recent report on an initial deployment of DLRs by subsidiaries of AES Corporation in Indiana and Ohio shows that estimated costs to implement DLRs on the studied transmission lines are generally lower than reconductoring alternatives and that DLRs can be implemented more quickly than reconductoring.

AES Corporation and LineVision, Inc.,

Lessons from First Deployment of Dynamic Line Ratings

(Apr. 2024),

https://www.aes.com/sites/aes.com/files/2024-04/AES-LineVision-Case-Study-2024.pdf

. We understand the report to refer to The Dayton Power and Light Company as AES Ohio and Indianapolis Power & Light Company as AES Indiana, each a subsidiary of AES Corporation.

2. International Examples

63. Many transmission providers elsewhere in the world have similar, or greater, levels of experience with DLRs as those in the United States, with some running pilot projects and others using DLRs in operations. Like the U.S. examples cited above, these projects illustrate the potential for DLRs to more accurately estimate transmission transfer capability and reduce costs due to decreased congestion.>

64. Elia (Belgium's system operator) uses DLRs on 33 transmission lines that range from 70 kV to 380 kV.

A representative from Elia stated the following at a September 10, 2021 Commission workshop: “the lines equipped with [DLRs] are more reliable than other lines” and that Elia knows “more about those lines than any other lines in the grid.”

RTE, France's transmission operator, used DLR to integrate wind power generation and avoid a $30 million transmission line replacement.

Idaho National Laboratory,

A Guide to Case Studies of Grid Enhancing Technologies

33 (Dec. 2022),

https://inldigitallibrary.inl.gov/sites/sti/sti/Sort_64025.pdf

Workshop to Discuss Certain Performance-based Ratemaking Approaches,

Docket No. RM20-10, Technical Video Conference (Sept. 10, 2021), Tr. 240:9-13 (Victor le Maire, Elia System Operator) (filed Oct. 13, 2021).

Idaho National Laboratory,

A Guide to Case Studies of Grid Enhancing Technologies,

at 13 (Dec. 2022).

65. Austria has installed DLR on 15% of its transmission system, leading to almost $17 million in congestion cost savings in 2016.

The Slovenian system operator has used DLR on each span of 31 transmission lines since 2016, increasing capacity an average of 22%.

A joint project between the University of Palermo and Terna Rete Italia SPA to install 90 DLR monitors in Italy saved roughly $1.25 million per transmission line per year, with a payback period of two years or less.

Idaho National Laboratory,

A Guide to Case Studies of Grid Enhancing Technologies,

at 22 (Oct. 2022).

Špela Vidrih, Andrej Matko, Janko Kosmač, Tomaž Tomšič, Aleš Donko,

Operational Experiences with the Dynamic Thermal Rating System,

at 8, 2d South East European Regional CIGRE Conference, Kyiv (2018).

Idaho National Laboratory,

A Guide to Case Studies of Grid Enhancing Technologies,

at 18 (Oct. 2022).

66. In 2020, LineVision and the European Commission's FARCROSS consortium, a project to boost cross-border transmission in the European Union, announced a partnership to install DLR in Hungary, Greece, Slovenia, and Austria.

T&D World,

LineVision Announces EU-Funded Projects with European Utilities

(Apr. 14, 2020),

https://www.tdworld.com/overhead-transmission/article/21128758/linevision-announces-eu-funded-projects-with-european-utilities

67. The United Kingdom's National Grid has installed DLR on a 275 kV circuit in Cumbria, with estimated savings of £1.4 million per year.

In Scotland, SP Energy Networks installed DLR at a cost of approximately $240,000 to increase capacity on two circuits and avoid the need for a transmission line rebuild that would have cost $2.25 million, roughly 10 times the cost of DLR installation.

100

LineVision,

National Grid installs LineVision's Dynamic Line Rating sensors to expand the capacity of existing power lines,

(Oct. 2022),

https://www.linevisioninc.com/news/national-grid-installs-linevisions-dynamic-line-rating-sensors-to-expand-the-capacity-of-existing-power-lines

100

Idaho National Laboratory,

A Guide to Case Studies of Grid Enhancing Technologies,

at 28 (October. 2022).

68. Analysis of four AltaLink transmission lines in Canada found

DLRs were higher than static transmission line ratings “up to 95.1% of the time, with a mean increase of 72% over a static rating.”

101

Moreover, DLRs were higher than seasonal ratings 76.6% of the time, with an average capacity improvement of 22% over static ratings.

102

101

Bishnu P. Bhattarai, Jake P. Gentle, Timothy McJunkin, Porter J. Hill, Kurt S. Myers, Alexander W. Abboud, Rodger Renwick, & David Hengst,

Improvement of Transmission Line Ampacity Utilization by Weather-Based Dynamic Line Rating,

IEEE Transactions on Power Delivery 1853, 1861 (2018),

https://doi.org/10.1109/TPWRD.2018.2798411

102

Id.

at 1853, 1861.

B. Consideration of Reforms

69. We are considering reforms that would require implementation of certain DLR practices, including: requiring transmission line ratings to reflect solar heating based on the sun's position and forecastable cloud cover; requiring transmission line ratings to reflect forecasts of wind conditions—wind speed and wind direction—on certain transmission lines; and enhancing data reporting practices to identify candidate transmission lines for the wind requirement in non-RTO/ISO regions. Such reforms may ensure that transmission line ratings result in jurisdictional rates that are just and reasonable.

70. In Order No. 881, the Commission found that transmission line ratings, and the rules by which they are established, are practices that directly affect the rates for the transmission of electric energy in interstate commerce and the sale of electric energy at wholesale in interstate commerce (hereinafter referred to collectively as “wholesale rates”).

103

The Commission further found that, because of the relationship between transmission line ratings and wholesale rates, inaccurate transmission line ratings result in wholesale rates that are unjust and unreasonable.

104

Acting pursuant to FPA section 206, the Commission concluded that certain revisions to the

pro forma

OATT and the Commission's regulations were necessary to ensure just and reasonable wholesale rates.

105

103

Order No. 881, 177 FERC ¶ 61,179 at P 29.

104

Id.

105

Id.

71. In Order No. 881, the Commission recognized that, in addition to ambient air temperatures and daytime/nighttime solar heating, other weather conditions such as wind, cloud cover, solar heating intensity, precipitation, and transmission line conditions such as tension and sag, can affect the amount of transfer capability of a given transmission facility. The Commission explained that incorporating these additional inputs provides transmission line ratings that are closer to the true thermal transmission line limits than AARs.

106

Id.

P 36.

72. We preliminarily find that transmission line ratings that do not reflect solar heating based on the sun's position and up-to-date forecasts of forecastable cloud cover may result in unjust and unreasonable wholesale rates. We further preliminarily find that transmission line ratings that do not reflect up-to-date forecasts of wind conditions on certain transmission lines may also result in unjust and unreasonable wholesale rates. We seek comment on both of these preliminary findings.

73. We also preliminarily find that transmission line ratings that better reflect solar heating and, where appropriate, wind conditions would result in more accurate system transfer capability, thereby resulting in just and reasonable rates. As the Commission noted in Order No. 881, increasing transfer capability will, on average, reduce congestion costs because transmission providers will be able to import less expensive power into what were previously constrained areas, resulting in cost savings, as discussed above, and wholesale rates that avoid unnecessary congestion costs.

107

For example, as discussed above, PPL's implementation of DLRs on just two of its transmission lines reduced annual congestion costs by approximately $77 million annually.

108

107

Id.

P 34 (“Such congestion cost changes and related overall price changes will more accurately reflect the actual congestion on the system, leading to wholesale rates that more accurately reflect the cost the wholesale service bring provided.”);

see also

Order No. 881, 177 FERC ¶ 61,179 at PP 44-45.

a. Components of a Wind Requirement

99. We preliminarily propose to require transmission providers to reflect up-to-date forecasts of wind speed and wind direction in transmission line ratings on lines subject to the wind requirement. We propose to apply this wind requirement to only transmission lines exceeding thresholds for wind speed and congestion. A potential final rule imposing such a wind requirement would modify

pro forma

OATT

Attachment M and specify details of the wind requirement, including the time horizon, wind forecasting requirements, sensor requirements, exceptions, and transparency of relevant data. Below we provide additional detail and seek comment on these elements of a wind requirement.

100. As noted in section III. The Potential Need for Reform above, we preliminarily find that certain transmission line ratings that do not reflect up-to-date forecasts of wind speed and direction may result in unjust and unreasonable wholesale rates.

i. Time Horizon and Forecasting Requirement

101. For transmission lines subject to a wind requirement, we preliminarily propose to require transmission providers to use transmission line ratings that account for wind speed and direction as the basis for evaluating requests for transmission services that will end within 48 hours of the transmission service request (48-hour transmission service). For those transmission lines, this approach would require transmission providers to use transmission line ratings that reflect up-to-date forecasts of wind speed and direction to evaluate requests for hourly and daily point-to-point transmission services under the

pro forma

OATT that fall within the 48-hour time horizon. All longer-term (weekly, monthly, yearly) point-to-point services would not be affected by this requirement. For those transmission lines, transmission providers would also use transmission line ratings that incorporate the proposed wind requirement in determining whether to curtail, interrupt, or redispatch transmission service on transmission lines subject to a wind requirement, if such curtailment or redispatch is necessary because of issues related to flow limits on transmission lines and anticipated to occur within the next 48 hours of such determination.

102. In the NOI, the Commission asked about the timeframes (and corresponding types of transmission service) for which DLRs should be used. In response, some commenters argue that DLRs should be used for a variety of transmission services, including hourly, daily, and weekly services.

139

Other commenters argue that DLRs should be used only in real-time operations for decisions regarding curtailment, interruption, and redispatch.

140

139

Clean Energy Parties Comments, Docket No. AD22-5, at 15 (filed Apr. 25, 2022) (hourly or sub-hourly); LADWP Comments, Docket No. AD22-5, at 7 (filed Apr. 25, 2022) (daily or hourly); WATT/CEE Comments, Docket No. AD22-5, at 16 (filed Apr. 25, 2022) (near-term transmission service as defined in Order 881).

140

APS Comments, Docket No. AD22-5, at 12 (filed Apr. 25, 2022); NYTOs Comments, Docket No. AD22-5, at 16 (filed Apr. 25, 2022); EEI Comments, Docket No. AD22-5, at 5 (filed Apr. 25, 2022); Eversource Comments, Docket No. AD22-5, at 4-5 (filed Apr. 25, 2022); NYISO Comments, Docket No. AD22-5, at 6 (filed Apr. 25, 2022); Entergy Comments, Docket No. AD22-5, at 5 (filed Apr. 25, 2022); MISO Comments, Docket No. AD22-5, at 32 (filed Apr. 25, 2022).

103. Accordingly, we seek comment on the appropriateness of the proposed 48-hour time horizon. We note that current DLR implementations reflect the use of DLRs across timeframes sufficient to include DLRs in the real-time and day-ahead markets of RTOs/ISOs. For example, PPL uses DLRs in the PJM real-time and day-ahead energy markets.

141

We also understand that DLR vendors offer services that calculate DLRs as far as 10 days into the future.

142

However, given that the forecast uncertainty for wind speed and direction that would underlie a wind requirement likely increases the longer the time period, we preliminarily believe that the time horizon for a wind requirement should be shorter than the 10-day horizon for the existing AAR requirement.

141

See

PPL Comments, Docket No. AD22-5, at 14 (filed Apr. 25, 2022).

142

See, e.g.,

LineVision,

Technology: Software,

(stating that LineVision's LineRate DLR product provides “[f]orecasted DLR, hourly, up to 240 hours (10 days) out”),

www.linevisioninc.com/technology#software.

104. The appropriate time horizon for which transmission service evaluations should incorporate a wind requirement depends on whether the accuracy benefit of incorporating wind forecasts exceeds the burden of calculating and managing the ratings for such forward hours. At longer time horizons, forecast uncertainty increases, perhaps resulting in the need for larger forecast margins to ensure the necessary level of confidence in the forecasts.

143

On the other hand, limiting the wind requirement to a short time horizon would forego the benefits of more accurate transmission line ratings because those benefits would only accrue for a smaller number of hours and a more limited set of transmission services.

143

In Order No. 881, the Commission required transmission providers to use AARs as the basis for evaluating “near-term” transmission service requests, defined as transmission service that ends not more than 10 days after the transmission service request date, because the Commission determined that forecasts of ambient air temperature were sufficiently accurate up to 10 days into the future, and that transmission line ratings based on such 10-day-ahead forecasts would provide sufficient benefits. Order No. 881, 177 FERC ¶ 61,179 at PP 120-121. For transmission service that is beyond 10 days forward, however, the Commission found that seasonal line ratings are the appropriate transmission line ratings because ambient air temperature forecasts for such future periods have more uncertainty than near-term forecasts, and thus tend to converge to the longer-term ambient air temperature forecasts used in seasonal line ratings.

Id.

P 200;

cf. id.

P 105 (discussing the justification for the 10-day threshold for the use of AARs).

105. Because the bulk of the effort of calculating and archiving of transmission line ratings on transmission lines subject to the wind requirement is in the setup of the automated systems, we anticipate that the data burdens of this option would not vary significantly depending on the time horizons.

144

Nevertheless, we seek comment on whether applying a wind requirement to transmission line ratings over longer time horizons would result in a greater data burden as compared to a wind requirements for shorter-time horizons.

144

For example, Clean Energy Parties and WATT/CEE state that system integration is a one-time engineering effort before it becomes plug-and-play, and that resources for subsequent installation on additional transmission lines will be limited to the time needed to determine the location of, and to install, DLR sensors. Clean Energy Parties Comments, Docket No. AD22-5, at 20 (filed Apr. 25, 2022); WATT/CEE Comments, Docket No. AD22-5, at 19-20 (filed Apr. 25, 2022).

106. Considering all of these factors, we preliminarily find that a 48-hour time horizon provides a reasonable balance between the benefits and burdens associated with a wind requirement and may therefore be appropriate for a potential wind requirement. Such a timeframe seems to strike the right balance of creating significant benefits by covering important transmission service transactions, such as those in the RTO/ISO day-ahead markets, while reflecting that implementing a wind requirement for longer timeframes may not supply sufficient value to justify the burden. We seek comment on whether the 48-hour time horizon is the appropriate timeframe or whether the Commission should consider requiring a longer time horizon (

e.g.,

a week, 10 days, monthly). We seek comment on the accuracy of the forecasting of wind speed and wind direction in these time horizons (including the 48-hour time horizon), and any potential benefits and burdens that may result from a longer time horizon. We also seek comment on the ability of DLR vendors to calculate DLRs in these time horizons, and at what level of confidence.

ii. Sensor Requirements

107. We preliminarily propose that transmission providers, for their transmission lines subject to the wind requirement, install sensors that measure wind speed and direction as

determined to be necessary for forecast training or to otherwise ensure adequate information about local weather conditions.

108. We seek comment on whether the Commission should require a transmission provider to determine what sensors, if any, need to be installed for forecast validation and forecast training in order to ensure that forecasts of wind speed and direction are sufficiently accurate. We propose that, in doing so, transmission providers should consider a non-exhaustive list of factors including: average ambient wind speed at the relevant altitude(s), distribution of wind direction at the relevant altitude(s), length and configuration of conductors, local topography, local vegetation, and position of weather stations. We seek comment on what other factors transmission providers should be required to consider when determining what sensors, if any, need to be installed.

109. Further, if commenters believe that detailed sensor configuration requirements are not necessary for transmission lines subject to a wind requirement, we seek comment on why that approach is preferable and how such requirements should be constructed.

110. We also seek comment on whether the Commission should mandate sensors at all. We understand that some vendors are offering approaches to DLRs that do not use sensors.

145

For example, a wind requirement could simply require that transmission line ratings reflect up-to-date forecasts of wind speed and wind direction. Under such an approach, the wind requirement would be defined in terms of the wind conditions that must be reflected in the transmission line ratings, rather than what technical equipment transmission providers must use to produce wind forecasts. This approach is similar to the requirements adopted in Order No. 881 for AARs to reflect up-to-date forecasts of ambient air temperature. We seek comment on whether the technology and capability to determine accurate forecasts of wind speed and wind direction currently exists, or will exist in the near future, such that transmission providers can use a sensor-less DLR to accurately and safely determine their transmission line ratings. We seek comment on whether there are benefits to a sensor-less approach, beyond cost savings, as compared to a sensor-based approach. We also seek comment on the costs of sensor-less approaches, including any comparison to the costs of measuring wind speed and direction using sensors. We seek comment on whether there any certain scenarios (

i.e.,

line configurations, types of lines) where a sensor-based approach may be preferable to sensor-less approach.

145

See, e.g.,

SPLIGHT Comments, Docket No. AD22-5, at 4 (filed Mar. 21, 2024) (referencing “software-only solutions [that can enable] DLR utilization across entire grid systems”); Renan Giovanini,

GE Digital Grid Software: Orchestrate the Clean Energy Grid,

General Electric presentation at FERC's Software Conference referencing sensor-free digital twin DLR at slide 6 (June 27, 2023),

https://www.ferc.gov/media/renan-giovanini-general-electric-edinburgh-uk.

111. We also seek comment on whether, if a wind requirement generally requires the use of sensors, the Commission should give transmission providers the discretion to determine that

no sensors

are required in certain instances. Specifically, we seek comment on what types of factors transmission providers should consider when identifying such instances and whether such factors should be reflected in any ultimate Commission directive. We also seek comment on whether an explicit provision would be necessary to give transmission providers such latitude, or if requiring the use of sensors “as determined to be necessary” would be sufficient to provide such latitude. Additionally, to the extent that the Commission does not require the use of sensors, we seek comment on how this would affect other proposals in this rule (

i.e.,

the congestion threshold, timing considerations, etc.).

112. We seek comment on the applicability of NERC Facility Ratings Reliability Standard FAC-008-5 and NERC Transmission Relay Loadability Reliability Standard PRC-023-4 to the wind requirement and whether any changes would need to be made to these or other NERC Reliability Standards to accommodate a potential wind requirement.

113. Further, we seek comment on the type and costs of needed communications equipment, computer hardware, and computer software required to integrate sensors and associated data into the transmission provider's EMS. We seek comment on whether changes are needed to the NERC Critical Infrastructure Protection (CIP) Reliability Standards or other industry practices to ensure the physical security and cybersecurity of the sensors, data communications, transmission line rating and forecasting systems, and EMS improvements used to implement a wind requirement. In particular, we seek comment on whether additional controls are necessary to validate that sensors are operating correctly and that any changes in ratings based on sensor data are appropriate for that particular transmission line, taking all relevant considerations into account. Further, we seek comment on whether entities should have a backup or other means to acquire the data or establish transmission line ratings if the DLR systems are compromised or not functioning properly.

b. Proposed Criteria To Identify Transmission Lines Subject to a Wind Requirement

114. As discussed in section II.C.3. Current Use of DLRs, research and select experience suggest that incorporating a wind requirement could provide significant benefits through more accurate line ratings. However, the record gathered through the NOI suggests that implementing the wind requirement would produce significant benefits only under certain circumstances.

146

We preliminarily agree with several commenters to the NOI that candidate transmission lines for a wind requirement should be identified through Commission-determined criteria

147

instead of relying on cost-benefit analyses. Thus, we preliminarily propose to apply the wind requirement only to transmission lines that meet certain wind speed and congestion thresholds and to limit the number of lines subject to the wind requirement in any one year.

146

See, e.g.,

APPA/LPPC Comments, Docket No. AD22-5, at 8-10,12 (filed Apr. 25, 2022); APS Comments, Docket No. AD22-5, at 4 (filed Apr. 25, 2022); DOE Comments, Docket No. AD22-5, Attachment A at ii (filed Apr. 25, 2022) (addressing the impacts of grid-enhancing technologies generally); AEP Comments, Docket No. AD22-5, at 10 (filed Apr. 25, 2022); EGM Comments, Docket No. AD22-5, at 8 (filed Apr. 22, 2022); LADWP Comments, Docket No. AD22-5, at 3 (filed Apr. 25, 2022); MISO Comments, Docket No. AD22-5, at 17-18 (filed Apr. 25, 2022); NRECA Comments, Docket No. AD22-5, at 14 (filed Apr. 25, 2022); NYTOs Comments, Docket No. AD22-5, at 11 (filed Apr. 25, 2022); PPL Comments, Docket No. AD22-5, at 9 (filed Apr. 25, 2022); PJM Comments, Docket No. AD22-5, at 2-3 (filed May 9, 2022); Southern Company Comments, Docket No. AD22-5, at 2-3 (filed Apr. 25, 2022); Tri-State Comments, Docket No. AD22-5, at 3 (Apr. 25, 2022); WATT/CEE Comments, Docket No. AD22-5, at 10 (filed Apr. 25, 2022).

147

See, e.g.,

BPA Comments, Docket No. AD22-5, at 10-11 (filed Apr. 25, 2022); CAISO Comments, Docket No. AD22-5, at 3 (filed Apr. 25, 2022); Certain TDUs Comments, Docket No. AD22-5, at 7 (filed Apr. 25, 2022); EGM Comments, Docket No. AD22-5, at 5-6 (filed Apr. 22, 2022); PJM Comments, Docket No. AD22-5, at 5-9 (filed May 9, 2022).

i. Number of Transmission Lines Subject to the Wind Requirement Annually

115. We recognize that implementing the wind requirement may present some challenges (particularly during the initial implementation), such as siting

and installing sensors, particularly in remote locations, integrating DLRs with existing operations, and ensuring secure data communication and cybersecurity.

148

Thus, in order to ensure that any wind requirement is implemented in a reliable and effective manner, we preliminarily propose to limit the number of transmission lines on which a transmission provider must implement the wind requirement in any given year. We preliminarily propose that such a limit account for the fact that larger transmission providers tend to have more resources to implement the wind requirement than smaller transmission providers. With that in mind, we preliminarily propose to require that, for transmission providers with transmission lines subject to the wind requirement, transmission providers apply the wind requirement to, at least, a number of transmission lines equal to 0.25% (or 1 in 400) of that transmission provider's Commission-jurisdictional transmission lines, rounded up to the next whole number.

149

Alternatively, we seek comment on whether the minimum number of lines that a transmission provider must apply the wind requirement in an implementation cycle should be based on a percentage of lines that meet the wind and congestion thresholds rather than, as proposed above, a percentage of all lines. We anticipate that, after initial implementation, transmission providers will have the experience necessary to apply the wind requirements on more lines per year. We are also concerned that applying the wind requirements to only 0.25% of the transmission provider's total transmission lines per year will be too slow of a pace. Accordingly, we seek comment on the best approach to increasing the requirement. We seek comment on whether the Commission should increase the percentage of lines to which transmission providers must apply the wind requirements, for any transmission lines that meet the thresholds (

i.e.,

0.25% of lines in years 1 and 2 after implementation, 0.5% of lines in years 3 through 5, and 1% of lines in ensuing years)? Alternatively, we seek comment on whether the Commission should select a time upon which transmission providers must incorporate the wind requirement to all lines that meet the wind speed and congestion thresholds (

i.e.,

at least 0.25% per year for the first five years after implementation, but all lines that meet the thresholds must apply the wind requirement by year six). Further, as discussed below, transmission providers would be required to implement the wind requirement only on transmission lines that meet both a wind speed threshold and a congestion threshold.

148

See, e.g.,

Order No. 881, 177 FERC ¶ 61,179 at P 254; AEP Comments, Docket No. AD22-5, at 5 (filed Apr. 25, 2022); APPA/LPPC Comments, Docket No. AD22-5, at 3-7 (filed Apr. 25, 2022), BPA Comments, Docket No. AD22-5, at 7-8 (filed Apr. 25, 2022).

149

For example, for a transmission provider with 1,130 transmission lines in a given year, 0.25% of its lines would be (0.0025) * (1,130) = 2.825 lines. As such, that transmission provider would not be required to implement the wind requirement on more than 3 of its transmission lines in that year, even if more than 3 of its transmission lines meet both a wind speed threshold and a congestion threshold. Transmission providers could, of course, voluntarily implement the wind requirement on additional transmission lines in any given year, but under this preliminary proposal they would not be

required

to do so.

116. For purposes of counting a transmission provider's total number of transmission lines and determining the number of transmission lines that would be subject to a wind requirement in a given year, we preliminarily propose to define a single transmission line as the transmission conductor that runs between its substation or switchyard start and end points (

e.g.,

dead-end structures). Other transmission facilities and equipment, such as circuit breakers, line traps, and transformers, would not count toward the transmission provider's total number of transmission lines. We seek comment on whether we should instead count the total number of transmission facilities based on the number of pieces of individually rated Commission-jurisdictional transmission equipment, as identified by the transmission provider and included in the database of transmission line ratings.

150

In other words, the number of transmission lines would be approximated based on the size of the transmission line ratings database developed for Order No. 881 compliance for a given transmission provider.

150

See

Order No. 881, 177 FERC ¶ 61,179 at PP 330, 336-340.

117. We seek comment on the preliminary proposal to require that transmission providers implement the wind requirement, for any transmission lines that meet the thresholds, on at least 0.25% of their transmission lines in each annual cycle. We seek comment on approximately how many jurisdictional transmission lines 0.25% represents, and how many transmission lines the average transmission provider operates. We seek comment on whether the Commission should adopt a different initial annual percentage. Alternatively, should the Commission consider a requirement for transmission providers, after a few years of DLR experience, to review their pace of implementation? We also seek comment on whether the Commission would need to adjust this approach if it determines that sensors are not needed for the wind requirement. We seek comment on whether we should consider alternative approaches to limiting a transmission provider's annual implementation requirements, such as limits based on the peak load on the transmission provider's transmission system or other appropriate criteria or metrics. We also seek comment on whether and how considerations such as staffing, supply chains, vendor availability, and limited experience with sensor technology for many transmission providers should factor into any such annual limitation on implementation of the wind requirement. We also seek comment on the appropriateness of establishing a limit on the number of transmission lines subject to a wind requirement.

ii. Wind Speed Threshold

118. We preliminarily propose to apply a wind requirement only to transmission lines where at least 75% of the length of the transmission line is located in areas with historical average wind speeds of at least 3 meters per second (m/s) (6.7 miles per hour) measured at 10 meters above the ground, roughly the height of most transmission lines. While we believe that requiring application of a wind speed threshold over the entire length of the line could be too limiting, ultimately excluding transmission lines where application of the wind requirement would yield net benefits, we also believe that including too long of a non-windy portions of the line will cause those segments to bind more often and limit the additional capacity from the wind requirement. Thus, we have proposed 75% of the line length located in areas with wind as the threshold. In NOI comments, WATT/CEE suggests using a similar wind speed threshold of 4 m/s.

151

Based on outreach and further research, however, we preliminarily propose a wind speed threshold of 3 m/s, on average.

152

151

WATT/CEE Comments, Docket No. AD22-5, at 7 (filed Apr. 25, 2022).

152

See, e.g.,

Jake Gentle,

et al., Forecasting for Dynamic Line Ratings,

Idaho National Laboratory presentation at FERC DLR Workshop at slide 13 (Sept. 10, 2019),

https://www.ferc.gov/sites/default/files/2020-09/Gentle-INL.pdf.

119. We note that historical wind speed data are published in graphical and raster format for the continental United States by the National Renewable Energy Laboratory

(NREL),

153

and we preliminarily propose that transmission providers use this NREL data source as the basis for implementing the wind speed threshold.

153

NREL,

Geospatial Data Science: Wind Resource Maps and Data, https://www.nrel.gov/gis/wind-resource-maps.html.

120. We seek comment on the proposed wind speed threshold of 3 m/s, on average, including whether another wind speed would be a more appropriate threshold. We also seek comment on the proposal to apply the wind requirement only on transmission lines where at least 75% of the transmission line length is located in areas with average wind speeds at or above the threshold, including whether another approach to applying the wind speed threshold would be more appropriate for transmission lines located in areas both above and below the threshold. Further, we seek comment on the preliminary proposal to require that transmission providers use NREL data for historical wind speeds at 10 meters above the ground for purposes of evaluating whether a transmission line is above or below the wind speed threshold, and whether an alternative data source would be more appropriate.

121. Finally, we acknowledge that wind direction is another important factor. Wind moving perpendicular to a transmission line cools the line much more effectively than wind moving parallel to the line. However, we preliminarily find that establishing a threshold that includes an average historical wind direction would be much more burdensome to calculate because it would require that the transmission provider determine the wind direction relative to the position of each transmission line. We seek comment on whether wind direction should also be considered when identifying transmission lines subject to a wind requirement, and if so, how such consideration should be structured and what data sources should be used.

iii. Congestion Threshold

122. We preliminarily propose to use congestion caused by a transmission line rating as a second threshold for identifying the transmission lines that would be subject to a wind requirement. Below, we discuss how to calculate a congestion value for each transmission line in RTO/ISO regions and, separately, in non-RTO/ISO regions, and how to establish a threshold to identify congested transmission lines in each region. Transmission lines that have no congestion or congestion levels below the proposed threshold would not be subject to any wind requirement even if they meet the wind speed threshold because, absent sufficient levels of congestion, we do not expect the benefits resulting from a more accurate transmission line rating to exceed the costs.

(a) RTO/ISO Regions

(1) Congestion Costs

123. We seek comment on the appropriate congestion cost threshold to use in the RTO/ISO regions. In response to the NOI, some commenters propose to directly use congestion costs to indicate which transmission lines should be subject to a DLR requirement in RTO/ISO regions, and even propose specific annual congestion cost thresholds. At the low end of the range of suggestions, WATT/CEE and Clean Energy Parties recommend requiring DLRs on any transmission line with congestion costs of at least $500,000 over the past year.

154

Citing the Midcontinent Independent System Operator, Inc. transmission owners' cost estimate of $100,000-$200,000 for DLR implementation per transmission line, WATT/CEE argues that this threshold would allow customers to break even on DLR installations within approximately two years.

155

At the high end of the range of suggestions, PJM recommends requiring DLRs on any transmission line with annual congestion costs of at least $2 million.

156

154

Clean Energy Parties Comments, Docket No. AD22-5, at 8 (filed Apr. 25, 2022); WATT/CEE Comments, Docket No. AD22-5, at 6 (filed Apr. 25, 2022).

155

WATT/CEE Comments, Docket No. AD22-5, at 6 (filed Apr. 25, 2022).

156

PJM Comments, Docket No. AD22-5, at 9 (filed May 9, 2022).

124. At this point, the Commission has a limited record on the best approach for calculating congestion costs in RTOs/ISOs for purposes of defining a congestion threshold for a wind requirement. As discussed above in section II.D.2. Existing Data Reporting on Congestion, or Proxies of Congestion, RTOs/ISOs regularly compute and publish various congestion metrics, but these metrics generally relate to marginal congestion costs rather than the total congestion costs caused by a transmission constraint. Thus, we seek comment on what approaches to calculating or estimating congestion costs caused by a transmission constraint would be most appropriate to use as part of a congestion threshold for a potential wind requirement in RTOs/ISOs. Relatedly, we seek comment on whether congestion costs caused by a transmission constraint should be determined based on the real-time markets, day-ahead markets, or a combination of the two.

125. Further, we seek comment on what congestion threshold the Commission should establish in RTO/ISO regions for a potential wind requirement, recognizing that the appropriate level of the congestion threshold could vary depending on the method used to calculate congestion costs. For example, were the Commission to use an annual congestion method as assumed by some commenters in response to the NOI, we seek comment on the values proposed and approximately how many transmission lines would meet the various thresholds. We note that WATT/CEE proposed $500,000 per year,

157

and PJM proposed $2 million per year.

158

Alternatively, as proposed by several commenters to the NOI, a congestion threshold could be set so that only transmission lines that have an average annual congestion cost of $1 million or more during the data collection period, discussed below in section IV.B.3. Phased-In Implementation Timeframe for the Wind Requirement, would be subject to the wind requirement. We also seek comment on whether the annual threshold should be annually adjusted for inflation; if so, how; and whether that adjustment should vary based on the method used for calculating congestion costs.

157

WATT/CEE Comments, Docket No. AD22-5, at 6 (filed Apr. 25, 2022).

158

PJM Comments, Docket No. AD22-5, at 9 (filed May 9, 2022).

126. We seek comment on how RTOs/ISOs should measure congestion costs at interties and whether the same congestion threshold should be used for both intertie and internal congestion costs measurements. We also seek comment on how entities in non-RTO/ISO market constructs, such as the Western Energy Imbalance Market, should measure congestion costs at their interties.

127. Finally, we seek comment on whether a different congestion threshold would be appropriate if it is determined that the wind requirement does not require sensors. If the wind requirement can be met without sensors, this may lower the costs necessary to comply with the requirement. The lower costs may in turn provide more net benefits at lower levels of congestion.

(b) Non-RTO/ISO Regions

(1) Limiting Element Rate

(i) Overview

128. In non-RTO/ISO regions, congestion costs are not reflected separately as a component in market

prices and are not typically published in reports. Based on available information (at least some of which is currently publicly reported in some form,

159

and some of which is available to transmission providers but not currently published), we preliminarily propose a new metric to serve as a proxy for congestion in these regions—a Limiting Element Rate (LER). The LER metric would express, as an average rate (in MWh/year), the adverse impacts on transmission service due to a transmission line rating serving as a limiting element. Below we discuss how a transmission provider would calculate the LER, including data to be collected for certain “triggering events,” what LER metric threshold would be appropriate to identify transmission lines that are sufficiently congested to be subject to a wind requirement, and whether there are alternatives measures of congestion to identify transmission lines that should be subject to a wind requirement.

159

For example, limiting element data are already required to be made publicly available for certain constrained paths under § 37.6(a)(2)(ii) of the Commission's regulations. 18 CFR 37.6(a)(2)(ii) (2023).

(ii) Triggering Events

129. We preliminarily propose to require that transmission providers record information for five types of triggering events where firm transmission service is denied or disrupted because of a transmission line's line rating. This information would provide the basis to identify transmission lines that are subject to a wind requirement.

130. In particular, the five events where firm transmission service is denied or disrupted because of a transmission line's line rating are: (1) denials of requested firm point-to-point transmission service; (2) denials of requests to designate network resources or load; (3) curtailment of firm point-to-point transmission service under section 13.6 of the

pro forma

OATT; (4) curtailment of network integration transmission service or secondary network integration transmission service under section 33 of the

pro forma

OATT; and/or (5) redispatch of network integration transmission service or secondary network integration transmission service under sections 30.5 and 33 of the

pro forma

OATT.

131. While we preliminarily propose to reflect each hour of a firm point-to-point transmission service reservation that is denied in the calculation of LER, in practice transmission customers do not typically schedule transmission service for every hour of their long-term reservations. For example, a transmission customer requesting a 100 MW reservation for annual transmission service may intend to use that service only during select hours totaling only six months of that year. Recognizing that fact, we seek comment on whether, for denials of requested firm point-to-point transmission service, the number of hours reflected in the LER calculations should reflect a discount from the number of hours reflected in the actual request. If so, we seek comment on what such discount factor(s) should be, and whether a specific discount factor should apply to all such denied firm point-to-point services, or if such a discount factor should vary by service type (daily, weekly, monthly, or yearly) to reflect how different service types might be scheduled at different rates.

132. We seek comment on whether it would be appropriate to include a sixth triggering event as a proxy for congestion in the LER. This event would account for times when ATC in the operating hour

160

is less than or equal to 25% of TTC.

161

Such “low ATC events” would be limited to events on paths that meet the definition of a “posted path” under § 37.6(b)(1)(i) of the Commission's regulations. Accounting for low ATC events would be intended to capture instances when such low ATC could dissuade potential transmission customers from making a transmission service request in the first place. We seek comment on whether, and to what extent, a transmission line's low operating-hour ATC indicates congestion in any given hour, such that it should reasonably be factored in as a proxy for congestion that may trigger the wind requirement. We also seek comment on other triggering events that the Commission should consider.

160

Either the operating hour or the future hour closest to the operating hour for which the transmission provider calculates ATC, hereafter simply “operating hour” for conciseness.

161

This approach reflects that the Commission's regulations already consider posted paths that have an ATC that is less than or equal to 25% of TTC to be “constrained.”

See

18 CFR 37.6(b)(1)(ii).

(iii) Data To Be Collected and Reported

133. For any triggering event, we preliminarily propose to require the transmission provider to record the: (1) date/time of the record being added to its database of transmission line ratings;

162

(2) dates and times of the start and end of the event;

163

(3) event type; (4) specification of the transmission line with a transmission line rating that was the limiting element causing the event; and (5) MWh of transmission service (or potential transmission service) that was impacted by the event.

162

See infra

P 156.

163

For denials or curtailments of service the date/time would be the date/time for which the service was requested.

134. The details of how the transmission provider would determine the impacted MWh vary by event type. For instances of denied firm point-to-point service, the transmission provider would determine the impacted MWh by multiplying the MW of the service requested by the duration of the request in hours.

164

If, instead of a complete denial of requested point-to-point service, a lower level of interim service is granted, then the MW value used in such a calculation would reflect only the portion of the original requested service deferred or not granted.

165

For instances of curtailed or redispatched point-to-point or network transmission service, the transmission provider would determine the impacted MWh by multiplying the MW curtailed or redispatched by the duration of the event in hours.

166

If, in such an instance, the MW curtailed or redispatched varies during the duration of the curtailment or redispatch, then the transmission provider may use an average MW value, or record the different hours or periods as different events. We preliminarily propose that transmission providers be required to reflect in such determinations any curtailments made as part of conditional firm transmission service provided under section 15.4 of the

pro forma

OATT. Finally, for instances of denied requests to designate new network resources or load without an end date, we preliminarily propose to reflect that such designations are generally long-term events by considering such denied requests to have a duration of 180 days (4,320 hours).

167

We seek comment on

the use of this assumed duration, or whether a different assumed duration or another approach would result in a better consideration of the congestion reflected in denials of requests to designate network resources or load.

164

For example, if a request for 100 MW of three weeks of weekly firm point-to-point transmission service were denied, the MWh impacted would be determined as (100 MW) * (3 weeks) * (7 days/week) * (24 hours/day) = 50,400 MWh.

165

For example, if in the proceeding example 75 of the requested 100 MW were ultimately granted, then the MWh impacted would be determined as (25 MW) * (3 weeks) * (7 days/week) * (24 hours/day) = 12,600 MWh.

166

For example, if a transmission provider curtailed an instance of transmission service by 25 MW for a period of 2 hours, then the impacted MWh would be determined as (25 MW) * (2 hours) = 50 MWh. Similarly, if a transmission provider redispatched down one if its network customer's network resources by 75 MW for 2 hours, then the impacted MWh would be determined as (75 MW) * (2 hours) = 150 MWh.

167

For example, if a request to designate a network resource with a capacity of 500 MW is denied, then the impacted MWh would be determined as (500 MW) * (4,320 hours) = 2,160,000 MWh.

(iv) LER Threshold

135. We seek comment on what LER metric threshold would be appropriate to identify transmission lines that are sufficiently congested to be subject to a wind requirement, along with an estimate of how many transmission lines would meet any discussed threshold. As proposed above, the LER measurement that will be compared to such a threshold would be measured in impacted MWh. One potential approach is to attempt to identify an LER threshold that would be the rough equivalent of any congestion cost threshold that we might ultimately adopt for RTO/ISO regions (discussed above), given an assumed cost of impacted MWh. For example, if one assumes a cost of an impacted MWh of $100, then an LER threshold that would be the rough equivalent of a $1 million RTO/ISO congestion cost threshold would be calculated as ($1,000,000)/($100/MWh) = 10,000 MWh. However, this would only be a rough equivalence because what is measured by LER and the congestion cost that we propose to be measured for RTO/ISO regions are not reflective of the exact same events, and any assumption for the cost of an impacted MWh will necessarily need to be some estimate of the average cost of such MWh. Another potential approach is to use hourly systemwide incremental costs, which are already required to be used for both energy imbalances under Schedule 4 and generator imbalances under Schedule 9 of the

pro forma

OATT, to calculate an estimated cost of impacted MWh.

168

We seek comment on the costs that transmission providers include in hourly energy or generator imbalance charges, in particular whether these charges reflect only the energy component or a full redispatch cost, including congestion and production costs. Finally, we seek comment on whether using a different value, or another approach altogether, to identify transmission lines that should be subject to a potential wind requirement would be appropriate.

168

See Pro forma

OATT, Schedule 4 Energy Imbalance Service. “The Transmission Provider may charge a Transmission Customer a penalty for either hourly energy imbalances under this Schedule [4] or a penalty for hourly generator imbalances under Schedule 9 for imbalances occurring during the same hour, but not both unless the imbalances aggravate rather than offset each other.”

Id.

(2) Potential Alternatives for Comment

136. We seek comment on alternatives to our preliminary proposal of using LER as a proxy for congestion in non-RTO/ISO regions. In particular, we seek comment on the possibility of using information that is currently non-public, such as redispatch costs, to measure actual congestion costs that are incurred in non-RTO/ISO regions.

(i) Non-RTO/ISO Congestion Costs

137. As an alternative to the LER metric, we seek comment on whether non-RTO/ISO regions could measure congestion costs to identify candidate transmission lines for a potential wind requirement. Under section 33.2 of the

pro forma

OATT, a transmission provider must perform redispatch of resources on a least-cost basis, without consideration of whether a resource is owned by the transmission provider or a network customer.

169

Based on this requirement, we believe that transmission providers consider redispatch costs for both network resources and their own resources serving their native load, although the information on such costs may currently be non-public. Such congestion costs could be measured within non-RTO/ISO regions for the purpose of identifying transmission lines that would benefit the most from a potential wind requirement. Because we believe such costs are formally tracked and associated with the limiting transmission line ratings necessitating each instance of redispatch, it should be possible to attribute redispatch costs to the particular transmission line whose transmission line ratings are causing such costs. We seek comment on using redispatch costs to measure congestion costs and to what extent this approach would be preferable to the LER approach. We seek comment on measuring congestion costs at intertie locations and whether redispatch costs could be used to identify interties that would benefit the most from a potential wind requirement.

169

Pro forma

OATT, section 33.2 (Transmission Constraints).

138. We also seek comment on whether measuring congestion costs in non-RTO/ISO regions should be used in

conjunction

with an approach like the LER approach (

i.e.,

congested transmission lines would be identified through some combination of how much redispatch cost their transmission line ratings cause

and

how many MWh are impacted by denials, disruptions, etc.).

170

If using a combined approach, we seek comment on how these components should be used together,

e.g.,

how much weight each measure of congestion is given, to develop an overall indicator of how congested a transmission line in a non-RTO/ISO region is.

170

We preliminarily assume, if a redispatch cost approach were used in conjunction with an LER approach, that the LER would be modified to (at a minimum) exclude consideration of the impacted MWh from redispatch of network resources, given that such events would already be reflected in terms of their redispatch cost.

139. Finally, we seek comment on additional methods for calculating congestion costs both within non-RTO/ISO regions and at interties connecting with non-RTO/ISO regions. For instance, average hourly incremental/decremental cost (that transmission providers are required to use under

pro forma

OATT Schedules 4 and 9 in the calculation of hourly imbalances charges discussed above) or electricity hub prices could be used to estimate congestion costs.

c. Self-Exceptions From the Wind Requirement

i. Self-Exception Categories

140. We preliminarily propose to allow transmission providers to self-except a transmission line from the wind requirement if it determines, consistent with good utility practice: (1) that the transmission line rating is not affected by wind conditions; or (2) that implementing the wind requirement on such a transmission line would not produce net benefits. These self-exceptions recognize that there may be instances where the congestion threshold and wind speed threshold criteria identify transmission lines that would nonetheless not be good candidates for implementation of a wind requirement. For example, certain transmission lines that might not benefit from the wind requirement, such as a partially underground transmission line where the cable is the limiting element, may nonetheless trigger the proposed criteria. As another example, applying the wind requirement to a particular transmission line may only relieve thermal constraints slightly before a voltage or stability constraint bind, resulting in little value for the cost of implementing the wind requirement.

141. Under either self-exception category, a transmission provider would log the self-exception and justification in its transmission line rating database (as outlined below). This proposal is supported by NOI comments that argue a wind requirement should provide exceptions for cost, reliability, and other negative impacts, and assert that the

cost exception should require a showing by the transmission provider.

171

ELCON Comments, Docket No. AD22-5, at 8-9 (filed Apr. 25, 2022); R Street Institute Comments, Docket No. AD22-5, at 5-6 (filed Apr. 26, 2022).

142. We seek comment on the concept of allowing a transmission provider to self-except transmission lines from the wind requirement.

143. The first self-exception category—that the transmission line rating is not affected by wind speed—is similar to the exception to the AAR requirement established by Order No. 881 and set forth in Attachment M of the

pro forma

OATT that permits transmission providers to use a transmission line rating that is not an AAR where the transmission line is not affected by ambient air temperature or solar heating.

172

We expect that the same (or largely the same) transmission lines that are excepted from Order No. 881's requirement to implement AARs or seasonal line ratings (because the transmission line is not affected by ambient air temperature) would be eligible for exception from the wind requirement under the first self-exception category. We seek comment on whether there are transmission lines whose transmission line ratings would not be affected by wind speed and whether the first self-exception category is appropriate in such cases.

172

See

Order No. 881, 177 FERC ¶ 61,179 at P 227;

see supra

P 84 (discussing the self-exception that would apply to the proposed requirement to include solar heating in transmission line ratings).

144. To implement the second self-exception category, we preliminarily propose that transmission providers conduct a net benefit analysis that sums all of the anticipated benefits attributable to the implementation of the wind requirement on the relevant line and, similarly, sums all of the costs attributable to the wind requirement on the relevant line. If the benefits do not exceed the costs, then a transmission provider may self-except the transmission line. Examples of benefits that could be considered in a net benefit analysis include: production cost savings (including increased transmission capacity, reduced congestion costs, reduced dispatch costs, and other related factors), and deferred costs of new transmission lines. Examples of costs in a net benefit analysis include: the installation of sensors, as well as the communications equipment or other costs attributable to implementing the wind requirement at the specified location or on the specified transmission lines. We preliminarily propose that transmission providers would not include, in the net benefit analysis, costs that they must incur to implement DLRs generally,

i.e.,

for communication equipment needed for enterprise-wide DLR implementation, computer hardware and software, EMS, physical security, and cybersecurity protections. We seek comment on the net benefit analysis proposal, including the potential benefits and costs to include in the analysis; whether there are costs or benefits that should

not

be included in a net benefits analysis; whether the Commission should specify which costs and benefits can or should be included in a net benefits analysis; whether such determinations should be left to the transmission providers' discretion; and whether transmission providers should be required to specify in their tariffs which costs and benefits can or must be included in a net benefits analysis. We also seek comment on whether benefits attributable to a wind requirement and used in a net benefits analysis should be limited to a particular time horizon, such as 10 years; or how transmission providers should attribute costs, including whether treatments such as amortization or depreciation would be appropriate, for purposes of the net benefits analysis, and the relevant time horizon.

145. We also preliminarily propose that a transmission provider that makes a self-exception finding must document, in its database of transmission line ratings and transmission line rating methodologies on OASIS or another website with authentication control including multi-factor authentication,

173

any exceptions to the wind requirement, including the nature of and basis for each exception, the date(s) and time(s) that the exception was initiated, and (if applicable) documentation of the net benefit analysis calculation, methodology, and assumptions. We seek comment on this approach to justifying and documenting self-exceptions.

173

While prior Commission orders, including Order No. 881, have references to “password-protected websites” instead of website(s) with authentication control, NAESB standards that incorporate NIST standards require utilities to use authentication control, including multi-factor authentication, on their OASIS websites or any alternative websites.

See

National Institute of Standards and Technology,

NIST Special Publication 800-63B

(Oct. 2023),

https://pages.nist.gov/800-63-3/sp800-63b.html;

North American Energy Standards Board,

Standards for Business Practices and Communication Protocols for Public Utilities

5 (Mar. 2020),

https://www.naesb.org/pdf4/naesb_033020_weq_version_003.3_report.pdf

(“In response, the subcommittees revised WEQ-002-5 to require transmission providers or the agent to whom a transmission provider has delegated the responsibility of meeting any requirements associated with OASIS, referred to as a Transmission Services Information Provider (`TSIP'), to apply industry-recognized best practices in the implementation and maintenance of OASIS nodes and supporting infrastructure. Included in these modifications is a requirement that TSIPs must implement guidelines for user passwords and authentication aligned with NIST SP 800-63B.”). As such, we believe that this text does not impose any new requirements on utilities. The Commission has adopted these NAESB standards.

See Standards for Bus. Pracs. & Communication Protocols for Pub. Utils.,

Order No. 676-J, 86 FR 29491 (June 2, 2021), 175 FERC ¶ 61,139 (2021).

146. Under this preliminary proposal, a transmission provider would not be required to implement the wind requirement on a specific transmission line if it takes a self-exception for that particular transmission line, but a self-exception would not reduce the transmission provider's overall implementation burden with respect to the wind requirement that year. A transmission provider would still be required to implement the wind requirement on its next most congested transmission line, unless no further transmission lines met the criteria for the wind requirement that year.

147. Furthermore, under our preliminary proposal, a transmission provider would be required to reevaluate and log any exceptions taken every year during the annual wind requirement implementation cycles for the wind requirement as discussed in the IV.B. Compliance and Transition and Implementation Time

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