Implementation of Dynamic Line Ratings, 57690-57716 [2024-14666]

Download as PDF 57690 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM24–6–000] Implementation of Dynamic Line Ratings Federal Energy Regulatory Commission. ACTION: Advance notice of proposed rulemaking. AGENCY: 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 SUMMARY: 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. Æ Mail via U.S. Postal Service Only: Addressed to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426. Æ 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 ddrumheller on DSK120RN23PROD with PROPOSALS4 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 ............................................................................................................................ D. 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 ......................................................................... VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 E:\FR\FM\15JYP4.SGM 15JYP4 1 4 5 5 9 10 14 15 16 18 19 20 21 22 25 33 36 37 38 39 45 46 47 48 49 50 53 54 55 56 63 69 79 79 81 83 85 91 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules 57691 TABLE OF CONTENTS—Continued Paragraph Nos. 3. Potential Wind Requirement ..................................................................................................................................... a. Components of a Wind Requirement ................................................................................................................. i. Time Horizon and Forecasting Requirement ..................................................................................................... ii. Sensor Requirements .......................................................................................................................................... b. Proposed Criteria To Identify Transmission Lines Subject to a Wind Requirement ..................................... i. Number of Transmission Lines Subject to the Wind Requirement Annually .......................................... ii. Wind Speed Threshold ............................................................................................................................... iii. Congestion Threshold ................................................................................................................................ (a) RTO/ISO Regions ........................................................................................................................................ (1) Congestion Costs ........................................................................................................................................ (b) Non-RTO/ISO Regions ............................................................................................................................... (1) Limiting Element Rate ............................................................................................................................... (i) Overview ..................................................................................................................................................... (ii) Triggering Events ....................................................................................................................................... (iii) Data To Be Collected and Reported ........................................................................................................ (iv) LER Threshold ........................................................................................................................................... (2) Potential Alternatives for Comment .......................................................................................................... (i) Non-RTO/ISO Congestion Costs ................................................................................................................. c. Self-Exceptions From the Wind Requirement ................................................................................................... i. Self-Exception Categories ............................................................................................................................. ii. Challenges to Self-Exceptions .................................................................................................................... d. Transmission Lines Formerly Subject to the Wind Requirement ................................................................... e. Potential Transparency Reforms and Request for Comment ............................................................................ i. Potential Reforms to Congestion Data Collection ....................................................................................... ii. Posting of Congestion Data ......................................................................................................................... iii. Posting of Transmission Line Ratings Subject to a Wind Requirement ................................................. 4. Requirements for Reflecting Solar and/or Wind in Transmission Line Ratings in RTOs/ISOs ........................... 5. Implications for Emergency Ratings ......................................................................................................................... 6. Confidence Levels ...................................................................................................................................................... B. Compliance and Transition and Implementation Timelines ......................................................................................... 1. Pro forma OATT Revisions and Implementation .................................................................................................... 2. Implementation Timeframe for the Solar Requirement ........................................................................................... 3. Phased-In Implementation Timeframe for the Wind Requirement ........................................................................ a. Annual Wind Requirement Implementation Cycles ......................................................................................... b. Transmission Provider Compliance Requirement ............................................................................................ c. Compliance for Transmission Providers That Are Subsidiaries of the Same Public Utility Holding Company ...................................................................................................................................................................... V. Comment Procedures ............................................................................................................................................................... VI. Document Availability ........................................................................................................................................................... ddrumheller on DSK120RN23PROD with PROPOSALS4 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),1 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.2 The Commission is also considering reforms to ensure transparency in the development and implementation of dynamic line ratings. 2. In 2021, the Commission issued Order No. 881, to revise its pro forma Open Access Transmission Tariff 1 16 U.S.C. 824e. e.g., 18 CFR 35.28(b)(14). 2 See, VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 (OATT) and the Commission’s regulations to improve the accuracy and transparency of transmission line ratings.3 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.4 The Commission found that inaccurate transmission line ratings result in unjust and unreasonable Commission-jurisdictional rates.5 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 3 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). 4 Id. P 3. 5 Id. PP 3, 29. PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 97 99 101 109 116 117 120 124 125 125 130 130 130 131 135 137 138 139 142 142 151 152 153 156 158 160 162 166 169 174 174 176 177 177 180 182 183 186 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 Commissionjurisdictional service are just and E:\FR\FM\15JYP4.SGM 15JYP4 57692 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules 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.6 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 ambientadjusted ratings (AAR) and DLRs.7 Therefore, the Commission adopted requirements for the use of AARs,8 and the use of uniquely determined emergency ratings that include separate 6 177 FERC ¶ 61,179. 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. 8 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). ddrumheller on DSK120RN23PROD with PROPOSALS4 7 Unlike VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 AAR calculations, for use in the operations horizon and in postcontingency simulations of constraints.9 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.10 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.11 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.12 Although organizationally Order No. 881 discussed the DLR requirement for RTOs/ISOs separately from the AAR requirement,13 the Commission defined DLRs to include ambient air temperature and solar heating.14 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.15 7. The Commission agreed with commenters that highlighted the 9 ‘‘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. 10 Order No. 881, 177 FERC ¶ 61,179 at P 149. 11 Id. P 150. 12 18 CFR 35.28(b)(14); see Order No. 881, 177 FERC ¶ 61,179 at PP 7, 235, 238. 13 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’’). 14 See supra n.12. 15 This ANOPR does not propose any changes to the requirements of Order No. 881. PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 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.16 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.17 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.18 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.19 8. The Commission required implementation of the requirements adopted in Order No. 881 by July 12, 2025, three years after compliance filings were due.20 2. Notice of Inquiry 9. On February 17, 2022, the Commission issued a Notice of Inquiry 21 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 16 Order No. 881, 177 FERC ¶ 61,179 at P 255. P 253. 18 Id. P 254. 19 Id. PP 7–9. 20 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). 21 Implementation of Dynamic Line Ratings, Notice of Inquiry, 178 FERC ¶ 61,110 (2022) (NOI). 17 Id. E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules entities, and supplemental comments from four entities.22 ddrumheller on DSK120RN23PROD with PROPOSALS4 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.23 Other commenters highlight DLR benefits related to reduced renewable energy curtailment and reduced interconnection costs.24 11. Commenters assert that DLR implementation can help mitigate congestion associated with planned and/or unplanned long-term outages of generation or transmission.25 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.26 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 22 A list of commenters in the NOI proceeding and their abbreviated names is located in the appendix. 23 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). 24 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 GridEnhancing 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). 25 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). 26 Clean Energy Parties Comments, Docket No. AD22–5, at 15 (filed Apr. 25, 2022). VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 to verify weather conditions in real time, which may be especially useful along frequently limiting spans.27 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).28 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.29 As the Commission explained, ‘‘Relevant transmission equipment may include, but is not limited to, circuit breakers, line traps, and transformers.’’ 30 For purposes of the discussion that follows, references to transmission ‘‘line’’ ratings encompass ratings for all transmission equipment that has a rating. 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 shortterm 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 27 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. 28 Order No. 881, 177 FERC ¶ 61,179 at P 44. 29 Id. 30 Id. PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 57693 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.31 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.32 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.33 Choosing 31 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). 32 See, e.g., IEEE Standard C2–2023, ‘‘2023 National Electric Safety Code,’’ 2023, at section 23. 33 Lisa Sosna, et al., Demonstration of Potential Data/Calculation Workflows Under FERC Order 881’s Ambient-Adjusted Rating (AAR) E:\FR\FM\15JYP4.SGM Continued 15JYP4 57694 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules 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. 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. ddrumheller on DSK120RN23PROD with PROPOSALS4 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.34 In practice, the typical increase in 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-datacalculationworkflows-under-ferc-order-no-881s-ambientadjusted. 34 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. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 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.35 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.36 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.’’ 37 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. 23. DLR implementation requires making reliable short-term forecasts 38 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.39 35 See Order No. 881, 177 FERC ¶ 61,179 at P 128 (acknowledging concerns about temperature forecast margins being too low or too high). 36 See id. P 26. 37 See id. P 7. 38 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. 39 See, e.g., Jake Gentle, et al., Dynamic Line Ratings Forecast Time Frames, Idaho National Lab (2023), Dynamic-Line-Rating-Forecasting-TimeFrames.pdf (inl.gov); Managing Transmission Line PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 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).40 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.41 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, groundbased sensors are more vulnerable to physical tampering and could pose a security threat for safe operations.42 Some DLR systems incorporate photospatial sensors (e.g., light detection and ranging (LiDAR)) and/or line sensors installed on or close to the monitored transmission line.43 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. 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 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.’’). 40 See Order No. 881, 177 FERC ¶ 61,179 at P 7. 41 Managing Transmission Line Ratings, Staff Report, Docket No. AD19–15–000, at 9 (issued Aug. 23, 2019). 42 Id. 43 Id. at 7–8. E:\FR\FM\15JYP4.SGM 15JYP4 ddrumheller on DSK120RN23PROD with PROPOSALS4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules 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.44 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.45 However, 44 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. 45 WATT/CEE Comments, Docket No. AD22–5, at 14 (filed Apr. 25, 2022). VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 because wind speed and direction are highly variable and subject to local geographic differences,46 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. 31. Generally, placing more sensors at rating-limiting elements or spans ensures more granular data to calculate transmission line ratings.47 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. 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-theshelf computer systems, cloud solutions, and/or services offered by vendors.48 Instead, transmission providers may have to build their own 46 Clean Energy Parties Comments, Docket No. AD22–5, at 12 (filed Apr. 25, 2022). 47 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). 48 See, e.g., PPL Comments, Docket No. AD22–5, at 17–18 (filed Apr. 25, 2022). PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 57695 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. 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 mostlimiting 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.49 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 mostlimiting segment for purposes of AAR calculations can be relatively simple once the transmission line rating formula and weather data processing is established.50 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 microgeographic differences, forecasting wind speed and direction may require more 49 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. 50 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-datacalculationworkflows-under-ferc-order-no-881s-ambientadjusted (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. E:\FR\FM\15JYP4.SGM 15JYP4 57696 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules 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.51 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. 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. ddrumheller on DSK120RN23PROD with PROPOSALS4 D. Pro forma Transmission Scheduling and Congestion Management Practices 37. As relevant here, transmission line ratings are used by transmission providers 52 in determining: (1) whether a transmission service request is approved or denied; and (2) when and how transmission service must be 51 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. 52 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). VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 curtailed or redispatched to protect reliability or interrupted to provide service to a higher-priority customer.53 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.54 Point-to-point transmission service is offered on a firm and non-firm basis.55 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).56 53 Transmission line ratings are also used by transmission providers for other purposes, including as part of transmission planning. 54 Pro forma OATT, section 1.37 (Point-To-Point Transmission Service). 55 Id.; id. section 13.6 (Curtailment of Firm Transmission Service). 56 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 loadserving entities to generation from interconnected systems to meet generation reliability requirements, or such definition as contained in Commissionapproved 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). PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 Specifically, ATC is calculated as: ATC = TTC ¥ ETC ¥ CBM ¥ TRM.57 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.58 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).59 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. 57 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). 58 Pro forma OATT, section 15.4(b). 59 Id. section 15.4(c); id. section 19.3 (System Impact Study Procedures). E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules 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-ofdelivery.60 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.61 ddrumheller on DSK120RN23PROD with PROPOSALS4 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-topoint.62 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.63 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.64 60 Pro forma OATT, pt. III (Network Integration Transmission Service Preamble); id. section 28 (Nature of Network Integration Transmission Service). 61 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). 62 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). 63 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). 64 Id. section 33.2 (Transmission Constraints). VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 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.65 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).66 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).67 For example, if an 65 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. 66 See, e.g., ISO–NE, FAQs: Locational Marginal Pricing, (Feb. 2024), https://www.iso-ne.com/ participate/support/faq/lmp; NYISO, LBMP InDepth Course: Congestion Price Component 4–15 (Nov. 2022), https://www.nyiso.com/coursematerials; MISO, MTEP18: Book 4 Regional Energy Information, at 8 (2018). 67 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. PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 57697 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.68 LMPs and shadow prices reflect marginal rather than total costs. 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.69 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.70 For all posted paths, ATC, TTC, CBM, and TRM values must be automatically posted.71 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 68 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-andagreements/tariff/; CAISO, Business Practice Manual for Definitions & Acronyms 128, (Jan. 21, 2023), https://bpmcm.caiso.com/BPM%20 Document%20Library/Definitions%20 and%20Acronyms/2023-Jan31_BPM_for_ Defintions_and_Acronyms_V20_Redline.pdf. 69 18 CFR 37.6. 70 Id. § 37.6(b)(1)(i). 71 Id. § 37.6(b)(3). E:\FR\FM\15JYP4.SGM 15JYP4 57698 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS4 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.72 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.73 For all constrained posted paths, additional detailed information must be made available upon request.74 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.75 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).76 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. ii. Redispatch Costs 53. Under the pro forma OATT, transmission providers may redispatch resources due to the existence of transmission constraints in certain circumstances.77 Because non-RTO/ISO 72 Id. § 37.6(a). § 37.6(b)(1)(ii). 74 Id. § 37.6(b)(2)(ii). 75 Id. 76 Id. § 37.6(b)(3). 77 Section 33.2 of the pro forma OATT provides that during any period when the Transmission Provider determines that a transmission constraint 73 Id. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 regions do not publish nodal prices that reflect congestion costs, the cost of redispatching resources is less transparent.78 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. 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.79 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 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. 78 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). 79 Order No. 881, 177 FERC ¶ 61,179 at P 3. PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 associated benefits before discussing potential reforms. 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 realtime and day-ahead markets.80 By contrast, PPL states that it internally estimated the cost to reconductor the Susquehanna-Harwood double-circuit line to be approximately $12 million.81 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%.82 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 JuniataCumberland 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 80 Idaho National Laboratory, A Guide to Case Studies of Grid Enhancing Technologies 11 (Oct. 2021), https://inl.gov/content/uploads/2023/03/AGuide-to-Case-Studies-for-Grid-EnhancingTechnologies.pdf; T&D World, PPL Electric Utilities Wins 95th Annual Edison Award (June 2023), https://www.tdworld.com/electric-utilityoperations/article/21267742/ppl-electric-utilitieswins-95th-annual-edison-award. 81 PPL Comments, Docket No. AD22–5, at 14–15 (filed Apr. 25, 2022). 82 PPL Supplemental Comments, Docket No. AD22–5, at 2–4 (filed Feb. 9, 2024). E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules on five additional transmission lines by the end of 2024.83 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.84 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).85 The DLR sensors were reported as ‘‘easy to install, reliable, and effective at reporting periods of either excess or limited capacity.’’ 86 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.87 The report noted that installation costs in this instance totaled approximately $4.8 million and that DLR system costs are ddrumheller on DSK120RN23PROD with PROPOSALS4 83 Id. 84 PJM Supplemental Comments, Docket No. AD22–5, at 2 (filed Jan. 17, 2024). 85 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://cigreusnc.org/wp-content/uploads/2021/11/AnEmpirical-Analysis-of-the-Operational-Efficienciesand-Risks-Associated-with-Line-RatingMethodologies.pdf. 86 Idaho National Laboratory, A Guide to Case Studies of Grid Enhancing Technologies 8 (Oct. 2022), https://inl.gov/content/uploads/2023/03/AGuide-to-Case-Studies-for-Grid-EnhancingTechnologies.pdf. 87 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. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 often only a fraction of the cost of reconductoring or rebuilding a transmission line.88 61. In August 2021, Duquesne Light Company (Duquesne), a transmission owner in PJM, partnered with LineVision on a DLR pilot project.89 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.90 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.91 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.92 A representative from Elia stated the following at a September 10, 2021 Commission workshop: ‘‘the lines 88 Id. 89 Duquesne, Duquesne Light Company Investing in New Technology to Enhance Grid Capacity and Reliance, NewsRoom (Aug. 2021), https:// newsroom.duquesnelight.com/duquesne-lightcompany-investing-in-new-technology-to-enhancegrid-capacity-and-reliance. 90 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-enhancestransmission-capacity-reliability-with-gridenhancing-technology. 91 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. 92 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. PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 57699 equipped with [DLRs] are more reliable than other lines’’ and that Elia knows ‘‘more about those lines than any other lines in the grid.’’ 93 RTE, France’s transmission operator, used DLR to integrate wind power generation and avoid a $30 million transmission line replacement.94 65. Austria has installed DLR on 15% of its transmission system, leading to almost $17 million in congestion cost savings in 2016.95 The Slovenian system operator has used DLR on each span of 31 transmission lines since 2016, increasing capacity an average of 22%.96 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.97 66. In 2020, LineVision and the European Commission’s FARCROSS consortium, a project to boost crossborder transmission in the European Union, announced a partnership to install DLR in Hungary, Greece, Slovenia, and Austria.98 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.99 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 68. Analysis of four AltaLink transmission lines in Canada found 93 Workshop to Discuss Certain Performancebased 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). 94 Idaho National Laboratory, A Guide to Case Studies of Grid Enhancing Technologies, at 13 (Dec. 2022). 95 Idaho National Laboratory, A Guide to Case Studies of Grid Enhancing Technologies, at 22 (Oct. 2022). 96 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). 97 Idaho National Laboratory, A Guide to Case Studies of Grid Enhancing Technologies, at 18 (Oct. 2022). 98 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-fundedprojects-with-european-utilities. 99 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-installslinevisions-dynamic-line-rating-sensors-to-expandthe-capacity-of-existing-power-lines. 100 Idaho National Laboratory, A Guide to Case Studies of Grid Enhancing Technologies, at 28 (October. 2022). E:\FR\FM\15JYP4.SGM 15JYP4 57700 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules 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 ddrumheller on DSK120RN23PROD with PROPOSALS4 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 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 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. 103 Order No. 881, 177 FERC ¶ 61,179 at P 29. 104 Id. 105 Id. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 explained that incorporating these additional inputs provides transmission line ratings that are closer to the true thermal transmission line limits than AARs.106 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 74. The use of DLRs may also provide benefits to customers by mitigating the need for more expensive upgrades. PPL’s internal estimate to reconductor the Susquehanna-Harwood doublecircuit line discussed above was approximately $12 million. In contrast, the cost to install DLRs on that line was less than $500,000.109 In addition, a recent report on an initial deployment of DLRs by subsidiaries of AES Corporation compares estimated costs and implementation times of DLR deployment and reconductoring.110 For P 36. 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 supra section III.A.1. 108 See supra P 57. 109 See PPL Comments, Docket No. AD22–5, at 14–15 (filed Apr. 25, 2022). 110 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 PO 00000 106 Id. 107 Id. Frm 00012 Fmt 4701 Sfmt 4702 a 345 kV transmission line in the AES Indiana footprint located in an area where significant load growth was expected, the cost to reconductor the transmission line was estimated to be $590,000 per mile, while the cost for DLR implementation was estimated to be $45,000 per mile.111 The implementation time for reconductoring was estimated to be two years while the implementation for DLR was estimated to be nine months. For a 69 kV transmission line in the AES Ohio footprint that was experiencing regular thermal overload, the cost for full reconductoring was estimated to be $1.63 million, while the cost for DLR with targeted reconductoring was estimated to be $390,000.112 The implementation timelines were two years for full reconductoring and one year for DLR with targeted reconductoring. 75. Likewise, the ability to increase transmission flows into load pockets may reduce a transmission provider’s reliance on local reserves inside load pockets. This may reduce local reserve requirements and the costs to maintain that required level of reserves, which, in turn, may result in cost reductions and wholesale rates that avoid unnecessary congestion costs.113 76. DLRs can also provide reliability benefits by increasing the transfer capability on the existing transmission system in a way that provides system operators with more options during stressed system conditions. For example, as PJM explained, the presence of DLRs on its system during Winter Storm Elliott contributed to system reliability because the higher transmission line ratings allowed it to avoid re-dispatching its system.114 DLR systems also give transmission providers a more complete picture of how the system is operating, particularly in contingency situations, which allows transmission providers to maximize their system’s performance while maintaining a safe, reliable, and efficient system.115 DLRs can also improve reliability by monitoring the condition of transmission lines and alerting utilities to hazardous conditions or potential failures on transmission lines, which may otherwise go Indianapolis Power & Light Company as AES Indiana, each a subsidiary of AES Corporation. 111 Id. at 14. 112 Id. at 18. 113 Order No. 881, 177 FERC ¶ 61,179 at P 34. 114 See supra P 58. 115 See DOE Comments, Docket No. AD22–5, Attachment A at 58 (filed Apr. 25, 2022); AES Corporation and LineVision, Inc., Lessons from First Deployment of Dynamic Line Ratings, at 5–6 (Apr. 2024). E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules undetected.116 In addition, DLRs with certain sensors, such as LiDAR, can support public safety by providing for greater situational awareness by monitoring the clearance of transmission lines from the ground or nearby vegetation and providing data to assist in wildfire prevention strategies, including when to clear vegetation and when to upgrade equipment.117 77. The Commission also explained that decreasing transfer capability when it is overstated can avoid placing transmission lines at risk of inadvertent overload and can signal to the market that more generation and/or transmission investment may be needed in the long term.118 78. Finally, we preliminarily find that certain transparency reforms are necessary to ensure accurate transmission line ratings. As discussed below, the record indicates a lack of transparency for congestion costs in non-RTO/ISO regions. Understanding if, and how much, congestion may exist on a transmission line is essential to understanding whether that transmission line may benefit from the preliminary proposals in this rulemaking. As the Commission explained in Order No. 881, if a stakeholder does not know the basis for a given transmission line rating, particularly for a transmission line that frequently binds and elevates prices, it cannot determine whether the transmission line rating is accurately calculated.119 We seek comment on this preliminary finding. IV. Potential Reforms and Request for Comment ddrumheller on DSK120RN23PROD with PROPOSALS4 A. Potential Transmission Line Ratings Reforms and Request for Comment 79. As detailed above in section II.C.3. Current Use of DLRs and below in sections IV.A.2. Potential Solar Requirement and IV.A.3. Potential Wind Requirement, the current record suggests that DLRs can result in more accurate transmission line ratings 120 and significant benefits, including cost savings, through increased transfer capability. Specifically, we preliminarily find that the benefits of 116 See PPL Comments, Docket No. AD22–5, at 15 (filed Apr. 25, 2022). 117 See AES Corporation and LineVision, Inc., Lessons from First Deployment of Dynamic Line Ratings, at 17 (Apr. 2024); DOE Comments, Docket No. AD22–5, attach. A at 57–58 (filed Apr. 25, 2022). 118 Order No. 881, 177 FERC ¶ 61,179 at P 35. 119 Id. P 39. 120 The proposed reforms in this ANOPR apply only to thermal ratings. Therefore, unless otherwise noted, use of the term ‘‘rating’’ hereafter should be assumed to mean ‘‘thermal rating.’’ VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 more accurate transmission line ratings outweigh the cost of implementation for DLRs that reflect more detailed solar heating based on the sun’s position and forecastable cloud cover and, for certain transmission lines, that reflect forecasts of wind conditions. The applicability of the solar and wind requirements proposed below—applying a solar requirement for all transmission lines and a wind requirement for only certain lines—follows our understanding from outreach that reflecting solar heating based on the sun’s position and forecastable cloud cover can be done without installing sensors and that reflecting wind conditions likely requires sensors. We seek comment on the proposed framework, as discussed below. 80. As noted above, in Order No. 881, the Commission, in effect, required RTOs/ISOs to be able to accept DLRs.121 We do not propose to change this requirement here. 1. Framework for a Potential Requirement 81. We preliminarily propose a DLR framework for reforms to improve the accuracy of transmission line ratings.122 These reforms would require transmission providers to implement DLRs that—on all transmission lines— reflect solar heating, based on the sun’s position and forecastable cloud cover, and—on certain transmission lines— reflect forecasts of wind speed and wind direction. Thus, the proposed DLR framework sets forth both a solar requirement and a wind requirement. Additionally, the reforms would ensure transparency into the development and implementation of transmission line ratings and would enhance data reporting practices related to congestion in non-RTO/ISO regions to identify candidate transmission lines for the wind requirement. Under the proposed framework, these requirements would be subject to certain exceptions and/or implementation limits, as detailed below. 82. The NOI asked whether other weather conditions should be part of a potential DLR requirement.123 However, there appears to be neither a strong record of the impact of other non-wind/ non-solar weather conditions on transmission line ratings nor a standard P 255. note that, per Attachment M of the pro forma OATT, a transmission line rating would apply to both the conductor and any relevant transmission equipment, which includes but is not limited to circuit breakers, line traps, and transformers. See pro forma OATT, attach. M, Transmission Line Rating. 123 NOI, 178 FERC ¶ 61,110 at P 17 (Question 17). PO 00000 121 Id. 122 We Frm 00013 Fmt 4701 Sfmt 4702 57701 for incorporating those weather conditions into transmission line ratings, as there is for solar heating and wind conditions (e.g., IEEE 738 and CIGRE TB 299).124 Thus, we do not propose to include such other variables in the proposed framework. We seek comment on the impact of non-wind/ non-solar weather conditions on transmission line ratings, relevant standards associated with those weather conditions, and whether and how the Commission should require consideration of other weather conditions in its proposed rule. 2. Potential Solar Requirement 83. We preliminarily propose to require that all transmission line ratings used for evaluating transmission service that ends not more than 10 days after the transmission service request date (hereinafter ‘‘near-term transmission service’’) 125 be subject to a solar requirement to reflect solar heating in two ways, one based on solar heating derived from the sun’s position and one based on up-to-date forecasts of forecastable cloud cover, subject to certain exceptions. 84. This proposal would apply to all transmission line ratings because it is our understanding that the solar requirement can be incorporated without installing sensors, enabling the benefit of additional transfer capability through more accurate accounting of solar heating with only minimal implementation costs. Further, this proposal would apply the solar requirement to near-term transmission service because the requirement effectively would subsume the daytime/ nighttime solar heating requirement set forth in Order No. 881, which applies to near-term transmission service. The currently effective Attachment M of the pro forma OATT already provides for transmission providers to take a selfexception to the requirement to include solar heating in transmission line ratings for transmission lines for which the technical transfer capability of the limiting conductors and/or limiting transmission equipment is not dependent on solar heating, and for transmission lines whose transfer capability is limited by a transmission 124 Institute of Electrical and Electronics Engineers, IEEE Standard for Calculating the Current-Temperature Relationship of Bare Overhead Conductors 21–23, IEEE Std 738–2023 (2023) (IEEE 738); Conseil International des Grands Réseaux Électriques/International Council of Large Electric Systems (CIGRE), Guide for selection of weather parameters for bare overhead conductor ratings, Technical Brochure 299, Aug. 2006 (CIGRE TB 299). 125 See pro forma OATT, attach. M, Near-Term Transmission Service. E:\FR\FM\15JYP4.SGM 15JYP4 57702 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules system limit that is not dependent on solar heating.126 The existing exception would also apply to the proposed requirement that transmission line ratings reflect solar heating based on the sun’s position and forecastable cloud cover. a. Reflecting Solar Heating Based on the Sun’s Position 85. We preliminarily propose to require that all transmission line ratings used for near-term transmission service reflect solar heating based on the sun’s position accounting for the relevant geographic location, date, and hour. Under this approach, transmission line ratings would reflect the potential for the sun to heat the transmission lines during each hour based on its position in the sky, assuming zero cloud cover. Stated another way, transmission providers will need to calculate, for each hour, the effect of the sun’s position on its transmission line ratings. Transmission providers would have the discretion to calculate the effect of the sun’s position on their transmission line ratings using more granular time increments. Because solar heating based on the sun’s position starts at close to zero in the hours shortly after sunrise, rises throughout the morning hours to the midday peak, and then decreases through the afternoon to near zero again in the hours shortly before sunset, requiring all transmission line ratings used for near-term transmission service to reflect solar heating based on the sun’s position may produce more accurate transmission line ratings than the daytime/nighttime assumptions required under Order No. 881. 86. As the Commission explained in Order No. 881,127 clear-sky solar heating assumptions based on the sun’s position can be computed with accuracy from formulas, such as those provided in standards like IEEE 738 or CIGRE TB 601.128 Such calculations depend only on geographic location, date, and time and are therefore free of any forecast uncertainty. Likewise, such calculations do not require local sensors or weather data. The Commission considered whether AARs should incorporate such hourly clear-sky solar heating assumptions in Order No. 881 but elected at that time to instead require the simpler but less precise daytime/ nighttime approach to solar heating. Under that approach, the AARs are required to reflect only the absence of solar heating during nighttime periods, where local sunrise/sunset times are updated at least monthly. The Commission found that, compared to the hourly clear-sky solar heating approach, the simpler daytime/ nighttime approach ‘‘balance[d] the benefits and burdens’’ associated with the rule.129 87. However, upon considering the NOI comments, and based on subsequent outreach and further research, we preliminarily find that the benefits of more accurate transmission line ratings that reflect solar heating based on the sun’s position are significant. This is particularly true during the hours right after sunrise and right before sunset—hours with relatively little solar heating. Because electric demand often peaks in the hours just before sunset, assuming midday solar heating during these hours may understate the amount of transfer capability available and increase the costs and challenges of reliably meeting peak demand. Additionally, regions with high levels of solar generation may benefit from the additional transmission capacity as load rises and solar generation declines, which further demonstrates that understating the amount of transfer capability available during these hours may increase the costs and challenges of maintaining reliability. 88. The record in the Order No. 881 proceeding indicates that considering solar heating based on the sun’s position can affect a transmission line’s rating by as much as 5% to 11%.130 Also, joint research by Commission staff and NOAA staff modeled the effect of the absence of solar heating on the rating of a typical aluminum conductor steel reinforced (ACSR) cable and found that transmission line ratings could increase by about 12% in the hours immediately after sunrise and before sunset.131 While 129 Order No. 881, 177 FERC ¶ 61,179 at P 150. Economic Comments, Docket No. RM20–16, at 15 (filed Mar. 23, 2021) (‘‘We estimate that the average size of [setting solar irradiance to zero] for nighttime ratings to be an 11 percent increase’’); PG&E Comments, Docket No. RM20–16, at 11 (filed Mar. 22, 2021) (‘‘PJM’s research shows that at least 14% of their line ratings are increased by 10% by considering solar irradiance’’); Entergy Comments, Docket No. RM20–16, at 8 (filed Mar. 22, 2021) (‘‘The shade of the night provides an additional 5% to the ratings of the lines’’). 131 Lisa Sosna, et al., Demonstration of Potential Data/Calculation Workflows Under FERC Order 881’s Ambient-Adjusted Rating (AAR) 130 Potomac ddrumheller on DSK120RN23PROD with PROPOSALS4 126 See id., attach. M, Obligations of the Transmission Provider; see also Order No. 881, 177 FERC ¶ 61,179 at P 227. 127 Order No. 881, 177 FERC ¶ 61,179 at P 150. 128 Institute of Electrical and Electronics Engineers, IEEE Standard for Calculating the Current-Temperature Relationship of Bare Overhead Conductors 21–23, IEEE Std 738–2023 (2023) (IEEE 738); 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. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 this range of percentages represents expected transmission line rating increases between assuming full midday sun and assuming no sun whatsoever, they nonetheless demonstrate that transmission line ratings would likely significantly increase in the early morning and late afternoon hours, and moderately increase in most other daytime hours, relative to assuming full midday sun conditions during all daylight hours. For example, Commission and NOAA staff’s modeling found that considering hourly clear-sky solar heating increased transmission line ratings (relative to the daytime/ nighttime ratings approach) in each of the four hours immediately after sunrise and before sunset by 4% to 12%.132 89. We seek comment on our preliminary proposal to require that all transmission line ratings used for nearterm transmission service reflect solar heating based on the sun’s position for the relevant geographic location, date, and hour under a clear sky. We also seek comment on the costs, nonfinancial burdens, and financial and non-financial benefits of this requirement. 90. As noted in section III. The Potential Need for Reform above, we preliminarily find that transmission line ratings used for near-term transmission service that do not reflect solar heating based on the sun’s position may result in unjust and unreasonable wholesale rates. In addition to the requests for comments on specific aspects of this preliminary proposal, we seek comment on whether reflecting solar heating based on the sun’s position in transmission line ratings used for nearterm transmission service would result in more accurate transmission line ratings and would, in turn, better reflect system transfer capability. We also seek comment on whether the greater accuracy of transmission line ratings would result in cost savings and just and reasonable wholesale rates. Further, given that the sun’s position is forecastable without uncertainty, we seek comment on whether transmission providers should reflect solar heating based on the sun’s position for transmission service longer than 10 days forward. Requirements, joint FERC/NOAA staff presentation at FERC’s 2022 Software Conference at slide 29 (June 23, 2022), https://www.ferc.gov/media/ demonstration-potential-datacalculationworkflows-under-ferc-order-no-881s-ambientadjusted. Actual increases could vary from the modeled increase, depending on conductor surface conditions and other factors. 132 Id. E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS4 b. Reflecting Solar Heating Based on Forecastable Cloud Cover 91. We preliminarily propose to require that all transmission line ratings used for near-term transmission service reflect solar heating based on up-to-date forecasts of forecastable cloud cover. Transmission providers will need to reflect, for each hour, the effect of forecastable cloud cover on its transmission line ratings. Transmission providers would have the discretion to calculate the effect of the sun’s position on their transmission line ratings using more granular time increments. This proposal does not imply that the cloud cover must be forecastable for the entire 10 days, but rather that transmission providers should reflect forecastable cloud cover in their up-to-date forecasts as that information becomes available.133 Based on outreach and research, we understand that certain overcast periods can be forecast accurately in certain conditions. For example, some portions of the continental United States regularly see overcast conditions for weeks at a time. During such periods, solar heating can be significantly reduced, significantly increasing transmission transfer capability. 92. We preliminarily propose to define forecastable cloud cover as cloud cover that is reasonably determined, in accordance with good utility practice, to be forecastable to a sufficient level of confidence to be reflected in transmission line ratings. We clarify that we are not proposing to require that transmission providers seek to forecast individual clouds, or even most cloud formations. We seek comment on this definition of forecastable cloud cover and the level of confidence that is necessary to incorporate and benefit from a cloud cover forecast. 93. We also seek comment on whether sensors are needed to accurately forecast cloud cover. If commenters believe local sensors are required to accurately forecast cloud cover events, we seek comment on how such sensors improve such forecasts. 94. We note that some cloud cover events may be more easily forecast forward than other cloud cover events. Some overcast conditions will not be forecastable at all. For many or most weather systems that produce forecastable cloud cover conditions, such conditions may be forecastable only for a short time ahead of a given operating hour, rather than for the full 10 days forward. For other very large weather systems, or for periods of seasonal overcast conditions in some parts of the country, such conditions may be forecastable for longer periods. 95. Therefore, we propose to limit the proposed requirement to reflect up-todate forecasts of forecastable cloud cover because, if a cloud cover event is not ‘‘forecastable,’’ then we believe it would not be practical to require that it be reflected. However, if a cloud cover event becomes ‘‘forecastable’’ during the relevant timeframe, it must be reflected in the up-to-date forecasts under the proposed requirement. Specifically, under the proposed requirement, forecastable cloud cover data must be incorporated into ratings calculations as close to real time as reasonably possible (i.e., as close to the time that a relevant forecast becomes available) given the timelines needed to obtain forecast data and perform the calculation, as well as any other steps needed for validation, communication, or implementation of the transmission line rating.134 We seek comment on this proposal to require that transmission providers incorporate up-to-date forecasts of forecastable cloud cover into all transmission line ratings used for near-term transmission service. We also seek comment on whether the requirement to incorporate up-to-date forecasts of forecastable cloud cover should apply to transmission services other than nearterm transmission service and whether all transmission service should be subject to this requirement, not just near-term transmission service. 96. We seek comment on the costs, non-financial burdens, and financial and non-financial benefits of reflecting solar heating through the use of up-todate forecasts of forecastable cloud cover in transmission line ratings used for near-term transmission service, and the extent to which this practice would increase the accuracy of the resulting transmission line rating. Further, we seek comment on whether transmission providers should reflect up-to-date forecasts of forecastable cloud cover in transmission line ratings used for transmission service up to 10 days forward or whether these forecasts should be reflected only in the transmission line ratings used for a shorter time frame, such as 36 or 48 hours forward. If parties believe sensors are required to accurately forecast cloud cover, we seek comment on whether cloud cover should alternatively be reflected only in transmission line ratings for transmission lines that exceed a congestion threshold, and what that threshold should be. We seek 134 See 133 See infra P 95. VerDate Sep<11>2014 19:58 Jul 12, 2024 Order No. 881, 177 FERC ¶ 61,179 at P 143. Jkt 262001 PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 57703 comment on whether, alternatively, upto-date forecasts of forecastable cloud cover should be reflected only in the ratings of the more limited set of transmission lines we propose would be subject to a wind requirement (described below). 3. Potential Wind Requirement 97. We preliminarily propose to additionally require certain transmission lines to reflect up-to-date forecasts of wind conditions, including wind speed and direction, in their transmission line ratings for use in 48hour transmission service, as defined below in section IV.A.3.a.i.a 48-Hour Transmission Service. We preliminarily propose that this wind requirement would be implemented only on transmission lines 135 exceeding thresholds for wind speed 136 and congestion.137 Other transmission lines would not be subject to the wind requirement but would still be subject to the solar requirement discussed above. 98. We preliminarily propose that, for each transmission line that is subject to the wind requirement, individual transmission providers apply good utility practice to determine which specific electric system equipment associated with that line—beyond the conductor—is affected by wind conditions and thus also would be subject to the wind requirement. This approach is similar to that taken by the Commission in Order No. 881 with respect to AARs.138 We seek comment on whether the wind requirement should explicitly apply only to the conductor portion of a transmission line, and if so why. 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 135 Id. P 44. threshold is described below in section IV.A.3.b.ii Wind Speed Threshold. 137 This threshold is described below in section IV.A.3.b.iii Congestion Threshold. 138 This proposal is consistent with the definition of Transmission Line Rating in Attachment M of the pro forma OATT, which includes ‘‘considering the technical limitations on conductors and relevant transmission equipment . . . [which] may include, but is not limited to, circuit breakers, line traps, and transformers.’’ See pro forma OATT, attach. M, Definitions; see also Order No. 881, 177 FERC ¶ 61,179 at PP 44–45. 136 This E:\FR\FM\15JYP4.SGM 15JYP4 57704 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS4 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 upto-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 139 Clean Energy Parties Comments, Docket No. AD22–5, at 15 (filed Apr. 25, 2022) (hourly or subhourly); 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). VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 operations for decisions regarding curtailment, interruption, and redispatch.140 103. 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. 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 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). 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. 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 10day-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). PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 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. 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. 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 48hour 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 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). E:\FR\FM\15JYP4.SGM 15JYP4 ddrumheller on DSK120RN23PROD with PROPOSALS4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules 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-todate 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 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-generalelectric-edinburgh-uk. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 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. 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 PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 57705 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 Commissiondetermined 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. 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 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). E:\FR\FM\15JYP4.SGM 15JYP4 57706 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS4 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 Commissionjurisdictional 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 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. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 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. 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. 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 150 See Order No. 881, 177 FERC ¶ 61,179 at PP 330, 336–340. PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 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 nonwindy 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.152 119. 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 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. E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS4 (NREL),153 and we preliminarily propose that transmission providers use this NREL data source as the basis for implementing the wind speed threshold. 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 153 NREL, Geospatial Data Science: Wind Resource Maps and Data, https://www.nrel.gov/gis/ wind-resource-maps.html. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 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.156 124. 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 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). PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 57707 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. 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 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). E:\FR\FM\15JYP4.SGM 15JYP4 57708 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS4 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. (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-topoint 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-topoint transmission service reservation that is denied in the calculation of LER, in practice transmission customers do not typically schedule transmission 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). VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 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-topoint 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. (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 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). 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. PO 00000 Frm 00020 Fmt 4701 Sfmt 4702 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. 134. The details of how the transmission provider would determine the impacted MWh vary by event type. For instances of denied firm point-topoint 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 longterm events by considering such denied requests to have a duration of 180 days (4,320 hours).167 We seek comment on 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. E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules 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. ddrumheller on DSK120RN23PROD with PROPOSALS4 (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. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 (2) Potential Alternatives for Comment 136. We seek comment on alternatives to our preliminary proposal of using LER as a proxy for congestion in nonRTO/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. 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, forma OATT, section 33.2 (Transmission Constraints). 170 We preliminarily assume, if a redispatch cost approach were used in conjunction with an LER PO 00000 169 Pro Frm 00021 Fmt 4701 Sfmt 4702 57709 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. 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 selfexcept 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 selfexceptions 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 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. E:\FR\FM\15JYP4.SGM 15JYP4 ddrumheller on DSK120RN23PROD with PROPOSALS4 57710 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules cost exception should require a showing by the transmission provider.171 142. 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 selfexception 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. 144. To implement the second selfexception 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 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). 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). VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 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, 173 While prior Commission orders, including Order No. 881, have references to ‘‘passwordprotected 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). PO 00000 Frm 00022 Fmt 4701 Sfmt 4702 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. 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 selfexception 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 Timelines section. In some instances, this proposal may merely require a review of the inputs and assumptions to the original selfexception analysis, to verify that they have not changed. In other instances, if such inputs and assumptions have changed, then analyses would need to be updated. If the technical basis for an exception is found to no longer apply, the transmission provider would be required to update the relevant transmission line rating(s) in a timely manner. We seek comment on this proposal for annual re-evaluations of self-exceptions, including whether another timeframe is more appropriate. We seek comment on the information that should be included in the transmission line rating log to justify a self-exception under either selfexception finding. 148. We note that Order No. 881 and the System Reliability section of the pro forma OATT Attachment M provides for the temporary use of a transmission line rating different than would otherwise be required if such rating is determined to be necessary to ensure the safety and reliability of the transmission system.174 Under this preliminary proposal, we would maintain that System Reliability provision in Attachment M, which would similarly apply to any 174 Order No. 881, 177 FERC ¶ 61,179 at P 232; pro forma OATT, attach. M (System Reliability). E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules transmission lines to which the wind requirement would otherwise apply. ddrumheller on DSK120RN23PROD with PROPOSALS4 ii. Challenges to Self-Exceptions 149. We propose to allow any person that disagrees with a transmission provider’s self-exception to challenge that self-exception by filing a complaint with the Commission under FPA section 206. Examples of potential complaints concerning a transmission provider’s self-exceptions could include that a transmission provider improperly claimed that the transmission line is not affected by wind speed, or that a transmission provider made a faulty demonstration that the transmission line ratings subject to wind requirement would not produce net benefits on the transmission line, such as through improper calculations of costs or benefits. The Commission could also institute an investigation under FPA section 206 on its own motion to examine any self-exception. We seek comment on whether there should be another means to challenge a selfexception. d. Transmission Lines Formerly Subject to the Wind Requirement 150. In cases when a transmission provider determines that a transmission line subject to a wind requirement no longer exceeds the thresholds for high levels of congestion and wind speed, we preliminarily propose that the wind requirement no longer apply to the transmission line and that transmission providers will no longer be required to include wind conditions when calculating the transmission line rating. For example, the transmission provider would be permitted, inter alia, to decommission the sensors if any, on that transmission line. Similarly, if a transmission provider determines that a transmission line previously subject to a wind requirement is no longer expected to produce net benefits, then we preliminarily propose that the wind requirement no longer apply to the transmission line and that the transmission provider will no longer be required to include wind measurements when calculating the transmission line rating and the transmission provider would be permitted to decommission any sensors on that transmission line. We further preliminarily propose that, when calculating the net benefits of a wind requirement to determine if a particular transmission line should be subject to the wind requirement sunk costs, such as past installations of sensors, should not be included. Under the preliminary proposal, such transmission providers would be required to document their decision to VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 stop applying the wind requirement and to decommission any sensors and provide a justification. Similar to the proposed self-exception process, transmission providers would log such decision, including the nature of and basis for each decommissioning, the date(s) and time(s) that the decommissioning was initiated, and (if applicable) documentation of the net benefit analysis calculation, methodology, and assumptions in their database of transmission line ratings and transmission line rating methodologies on OASIS or another website with authentication control including multi-factor authentication at least one year prior to the decommissioning. A justification could be, for example, that a transmission line no longer meets the congestion or wind speed thresholds or that the wind requirement no longer provides net benefits on a transmission line. Such justifications for removing the wind requirement would be subject to the same opportunities to be challenged pursuant to FPA section 206 discussed above for the self-exception process. Also, a goal of applying DLRs, including the wind requirement, to a transmission line is to reduce congestion. It stands to reason that a transmission line that is subject to the wind requirement may experience less congestion because of the wind requirement, such that it no longer meets the congestion threshold. In such cases, it may be counterintuitive to remove the wind requirement. As such, we preliminarily propose that any decision to remove the wind requirement from a transmission line must examine and compare the congestion with the wind requirement in place against the estimated congestion if the wind requirement were not in place. We seek comment on this preliminary proposal for a decommissioning process. Further, we seek comment on the costs and other burdens associated with decommissioning DLR equipment. We also seek comment on whether the threshold criteria should be required to no longer be met for a longer period of time (e.g., 5 years) before decommissioning is allowed. e. Potential Transparency Reforms and Request for Comment 151. We preliminarily propose new transparency reforms, including requirements to enhance data reporting practices related to congestion in nonRTO/ISO regions to identify candidate transmission lines for a wind requirement, and posting and retention of congestion data in both RTO/ISO and non-RTO/ISO regions. The proposed PO 00000 Frm 00023 Fmt 4701 Sfmt 4702 57711 reforms will provide transparency into the transmission providers’ identification of transmission lines that would be subject to the wind requirement and enable the Commission and stakeholders to verify the transmission providers’ analysis. Order No. 881 already requires a database of transmission line ratings and methodologies to be posted.175 This posting requirement would extend to transmission line ratings on transmission lines subject to the solar and wind requirements as well. 152. Some commenters in the NOI proceeding support adopting the same transparency measures for transmission lines subject to a wind requirement as the Commission adopted in Order No. 881.176 In addition, some commenters support going further and requiring the filing and posting of informational reports on which transmission lines meet the Commission’s wind requirement criteria, as well as the transmission line ratings and methodologies used for implementation of the wind requirement.177 153. As noted in section III. The Potential Need for Reform above, we preliminarily find that existing transmission line ratings and transmission line rating methodologies may result in unjust and unreasonable wholesale rates that result from inaccurate transmission line ratings. In addition to the preliminarily proposed reforms described above, we make a concomitant preliminary finding that certain transparency reforms are necessary to implement the preliminary proposal. In addition to the requests for comments on specific aspects of the preliminary proposal, we seek comment on whether the proposed data reporting practices related to congestion in nonRTO/ISO regions that would identify transmission lines that are candidates for a wind requirement and the posting 175 See Order No. 881, 177 FERC ¶ 61,179 at PP 330, 336–340. The transmission provider must post the information on the password-protected section (or section subject to authentication control including multi-factor authentication) of its OASIS site or on another website with authentication control including multi-factor authentication. Id. P 336; see supra n.200. 176 DC Energy Comments, Docket No. AD22–5, at 4 (filed Apr. 25, 2022); LADWP Comments, Docket No. AD22–5, at 4–5 (filed Apr. 25, 2022); PJM Comments, Docket No. AD22–5, at 6–7 (filed May 9, 2022); TAPS Comments, Docket No. AD22–5, at 8 (filed Apr. 25, 2022). 177 DC Energy Comments, Docket No. AD22–5, at 5 (filed Apr. 25, 2022); ELCON Comments, Docket No. AD22–5, at 2, 8–9, 11 (filed Apr. 25, 2022); LADWP Comments, Docket No. AD22–5, at 4–5 (filed Apr. 25, 2022); R Street Institute Comments, Docket No. AD22–5, at 9 (filed Apr. 26, 2022); TAPS Comments, Docket No. AD22–5, at 7 (filed Apr. 25, 2022); WATT/CEE Comments, Docket No. AD22–5, at 9 (filed Apr. 25, 2022). E:\FR\FM\15JYP4.SGM 15JYP4 57712 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS4 of underlying congestion data, as set forth below, would result in just and reasonable rates. i. Potential Reforms to Congestion Data Collection 154. As preliminarily proposed above in section IV.A.3.b.iii.b.1. Limiting Element Rate, transmission providers would be required to maintain a database of the following events: (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-topoint 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 (5) redispatch of network integration transmission service or secondary network integration transmission service under sections 30.5 and 33 of the pro forma OATT. Specifically, as preliminarily proposed above, transmission providers would be required to record for each event: (1) date/time of the record being added to the database; (2) dates and times of the start and end of the event; (3) event type; (4) specification of the transmission line with a transmission line rating that was the limiting element causing the event; and (5) the MWh of transmission service (or potential transmission service) that was impacted by the event. We seek comment on this preliminary proposal to require transmission providers to record this LER metric data, including the changes in data collection practices it would cause, and the associated burden. We seek comment on whether data identifying limiting transmission lines during all the periods of congestion listed above already exist, and whether the above descriptions of those events (duration, energy impacted, etc.) are being recorded by transmission providers and/or posted in OASIS currently. We also seek comment on the challenges in data collection practices and associated burden required to record the alternative methods to estimate congestion costs in non-RTO/ ISO regions and at non-RTO/ISO seams discussed above in section IV.A.3.b.iii.b.2.i Non-RTO/ISO Congestion Costs such as recording redispatch costs caused with a given transmission constraint. 155. As discussed below in section IV.4. Requirements for Reflecting Solar and/or Wind in Transmission Line Ratings in RTOs/ISOs, we preliminarily propose that RTOs/ISOs would use the LER metric only for congestion at their VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 seams, and not on the internal transmission lines for which they have explicit congestion data. However, we also preliminarily propose to require that transmission providers in RTOs/ ISOs maintain data on annual overall congestion costs caused by binding constraints on each transmission line. Finally, we also seek comment on whether any changes or additional data requirements would be needed to track congestion costs, or causes of congestion costs, in RTO/ISO regions. ii. Posting of Congestion Data 156. Similar to the Commission’s determination in Order No. 881, we preliminarily propose to require transmission providers to post on OASIS or another website with authentication control including multifactor authentication the new congestion databases associated with this rulemaking, such as an LER metric database, with a data retention requirement of at least five years. We preliminarily find that, without further transparency, the Commission and market participants would not have the information needed to determine the transmission lines on which transmission providers in non-RTO/ISO regions are required to implement the wind requirement. 157. We seek comment on this congestion data transparency proposal, including whether the congestion data proposed to be recorded in the congestion databases or other elements should be posted on OASIS or another website with authentication control including multi-factor authentication. We also seek comment on posting on OASIS or another website with authentication control including multifactor authentication the data associated with the alternative methods to estimate congestion costs in non-RTO/ISO regions and at seams with non-RTO/ISO regions discussed above in section IV.A.3.b.iii.b.2.i Non-RTO/ISO Congestion Costs such as recording redispatch costs caused by a given transmission constraint. We also seek comment on whether posting of additional congestion cost data, beyond the overall congestion costs caused by binding constraints on each transmission line, should be required in RTO/ISO regions. We seek comment on whether a different data posting, access restrictions, and data retention requirement is appropriate. iii. Posting of Transmission Line Ratings Subject to a Wind Requirement 158. In Order No. 881, the Commission required the maintenance and posting of all transmission line PO 00000 Frm 00024 Fmt 4701 Sfmt 4702 ratings in a line rating database.178 That requirement would apply to any transmission line ratings under a potential final rule in this proceeding as well.179 159. However, given the unique circumstances surrounding a potential wind requirement, including the need to be able to evaluate the effectiveness of such a requirement, we preliminarily propose that, for transmission lines subject to a wind requirement, the transmission provider would be required to post the transmission line ratings for each period calculated both with and without the consideration of forecasted wind conditions. We preliminarily believe that the posting of both transmission line ratings for the periods in which the wind requirement applies would provide the transparency necessary to evaluate the effectiveness of implementing the wind requirement on each transmission line subject to the wind requirement. We seek comment on this proposed posting requirement. 4. Requirements for Reflecting Solar and/or Wind in Transmission Line Ratings in RTOs/ISOs 160. In Order No. 881, the Commission required AARs to be used (1) in the day-ahead and real-time energy markets, (2) in any reliability or intra-day reliability unit commitment processes, and (3) for transmission service over RTO/ISO seams.180 The Commission declined to apply the AAR requirement to the evaluation of internal point-to-point or through-and-out transactions.181 The Commission explained that the vast majority of energy transactions in RTOs/ISOs are executed and financially settled in the day-ahead and real-time markets, and thus requiring AARs to be used for internal point-to-point and through-andout transactions would provide very little additional benefits in the RTO/ISO markets.182 161. For the solar requirement, which we propose to apply to all transmission lines, we preliminarily propose that RTOs/ISOs use transmission line ratings that reflect solar heating based on the sun’s position and forecastable cloud cover in their day-ahead and real-time markets as well as for seams transactions that are near-term transmission service (i.e., that start and 178 Order No. 881, 177 FERC ¶ 61,179 at PP 330, 336; see pro forma OATT, attach. M (Obligations of Transmission Provider). 179 See pro forma OATT, attach. M, Obligations of Transmission Provider; see also Order No. 881, 177 FERC ¶ 61,179 at PP 330, 336–340. 180 Order No. 881, 177 FERC ¶ 61,179 at P 89. 181 Id. P 134. 182 Id. E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS4 stop within the next 10 days). We do not propose to require RTOs/ISOs to use such transmission line ratings for internal point-to-point transmission service or through-and-out service. 162. For the wind requirement, which we propose to apply only to select transmission lines, we preliminarily propose a different approach. Specifically, we preliminarily propose that RTOs/ISOs comply with the wind requirement 183 by using transmission line ratings that reflect up-to-date forecasts of wind speed and wind direction: (1) in their day-ahead and real-time markets; and (2) for seams transactions, internal point-to-point transmission service, and for throughand-out service that are 48-hour transmission services (i.e., that start and end within 48 hours of the request). We preliminarily propose this broader requirement for these transmission lines because we preliminarily believe that the additional accuracy of using the transmission line ratings that incorporate the wind requirement on highly congested transmission lines may justify the burden. 163. We seek comment on these preliminary proposals for applying the proposed solar and wind requirements to transmission line ratings in RTOs/ ISOs. In particular, we seek comment on whether RTOs/ISOs should instead not be required to apply the wind requirement for internal point-to-point and through-and-out transactions, consistent with the AAR requirements of Order No. 881 and the instant proposal for the potential solar requirement. 5. Implications for Emergency Ratings 164. In Order No. 881, the Commission required that transmission providers use uniquely determined emergency ratings for contingency analysis in the operations horizon and in post-contingency simulation of constraints. The Commission also required that such emergency ratings include separate AAR calculations for each emergency rating duration used.184 165. We preliminarily propose to require that all uniquely determined emergency ratings used for contingency analysis in the operations horizon and in post-contingency simulation of constraints must reflect solar heating based on the sun’s position and up-todate forecasts of forecastable cloud cover. We preliminarily find that 183 Transmission lines subject to the wind requirement are also subject to the solar requirement, as described above in section IV.A.3 Potential Wind Requirement. 184 Id. P 297; pro forma OATT, attach. M, Obligations of Transmission Provider. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 applying the solar requirement to both normal and emergency ratings will enhance the accuracy of transmission line ratings. We seek comment on this proposed approach. 166. In addition, for transmission lines subject to a wind requirement, we preliminarily propose to require that all uniquely determined emergency ratings used for contingency analysis in the operations horizon and in postcontingency simulation of constraints must reflect up-to-date forecasts of wind speed and direction, consistent with the wind requirement for normal ratings. We preliminarily find that, for transmission lines that will be subject to a wind requirement, reflecting wind conditions in both normal and emergency ratings will enhance the accuracy of transmission line ratings. We seek comment on this proposed approach. 6. Confidence Levels 167. In statistical forecasting, ‘‘quantile forecasting’’ is the practice of forecasting upper or lower limits of a particular future observation.185 Quantile forecasting is the type of forecasting typically involved with determining transmission line ratings: forecasters seek to predict the extreme values (upper or lower, depending on the variable) of weather variables that serve as inputs into transmission line rating calculations, and to calculate sufficiently conservative transmission line ratings from those forecasts. In quantile forecasting, a ‘‘confidence level’’ reflects how much certainty forecasters have that a particular observation will not exceed their forecast when the observation is repeated many times. For example, if each day a meteorologist publishes a forecast of next-day high temperatures, and the method for producing such forecast is designed to meet a 98% confidence level, then over time the corresponding observed high temperatures should be less than or equal to such forecasts 98% of the time. 168. We understand that line ratings always have an associated confidence level. Because such confidence levels are typically relatively high, such as 98%, in most instances the forecasted transmission line ratings are conservative, such that the observed weather (when that forecasted hour becomes the operating hour) is within the range predicted by the forecast. However, infrequently, as the forecast 185 See, e.g., Electric Power Systems: Advanced Forecasting Techniques and Optimal Generation Scheduling, section 5 at 20 (João P.S. Catalão ed., 2017). PO 00000 Frm 00025 Fmt 4701 Sfmt 4702 57713 for a given hour is updated it could cause a transmission provider to have to manage (through curtailments or other actions) a reduction in transmission capability from what had been previously forecasted. 169. The Commission’s outreach and research indicate that it is commonplace for DLRs to be calculated to a default confidence of 98%. We preliminarily believe that there may be some benefit to having a default confidence level for calculations of transmission line ratings subject to the solar and/or wind requirement across regions: first, to discourage the use of overly conservative confidence levels, which will erode the benefits of using weather forecasts; 186 and second, to ensure that sharply differing practices do not produce sharply different transmission line ratings. 170. Given the importance of confidence levels to transmission line ratings accuracy and reliability, we seek comment on whether the Commission should establish a default confidence level transmission providers are required to use when calculating transmission line ratings subject to the solar and/or wind requirement, unless they document a particular reason for needing and using a different confidence level. If so, we seek comment on what such a default confidence level should be, and how the use of confidence levels different from the default should be documented by transmission providers to justify such deviations. 171. If such a default confidence level were adopted, we preliminarily propose that it apply not to the underlying weather forecasts (wind speed, wind direction, ambient air temperature, solar heating, etc.) individually, but instead to the forecast of the transmission line rating overall. We preliminarily believe that applying the default confidence level to the underlying weather forecasts would result in a confidence level for the overall forecasted transmission line rating that is less than the default level. We seek comment on this proposal to apply any default confidence level to overall transmission line rating forecasts. We seek comment on what confidence levels are currently typically applied to different types of transmission line ratings. 186 In Order No. 881 the Commission acknowledged that ‘‘transmission line ratings using unreasonably high forecast margins would also yield inaccurate transmission line ratings and, in turn, would result in an underutilization of existing transmission facilities, price signals based on less transfer capability than is truly available, and wholesale rates that are unjust and unreasonable.’’ Order No. 881, 177 FERC ¶ 61,179 at P 52. E:\FR\FM\15JYP4.SGM 15JYP4 57714 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules B. Compliance and Transition and Implementation Timelines 1. Pro Forma OATT Revisions and Implementation 172. We preliminarily propose to promulgate these potential reforms through revisions to the pro forma OATT, which is applicable to all transmission providers. We seek comment on this proposal including whether such requirements should be reflected in Attachment M of the pro forma OATT or elsewhere. Commenters are invited to propose pro forma OATT language, including proposed revisions to existing pro forma OATT language, and to explain why such language would be appropriate. 173. While the requirements we preliminarily propose here would be imposed on transmission providers, we recognize as we did in Order No. 881 that transmission owners determine transmission line ratings.187 In many instances, particularly outside of RTOs/ ISOs, the transmission provider and transmission owner are the same entity. However, within RTOs/ISOs and in limited other instances, the transmission provider and transmission owner are separate entities. For such instances, we preliminarily propose that the limit for how many transmission lines must apply the wind requirement, for any transmission lines that meet the thresholds, (i.e., the proposed 0.25% of the total number of the transmission providers’ transmission lines for the initial period) apply to each individual transmission owner and not to the transmission provider on an RTO-wide basis.188 We also preliminarily propose that transmission owners will determine transmission line ratings for all of their transmission lines. We also propose to require transmission owners to provide their transmission line ratings and transmission line rating methodology to the transmission provider. We seek comment on this aspect of the preliminary proposal, including which responsibilities would or should be ddrumheller on DSK120RN23PROD with PROPOSALS4 187 See Order No. 881, 177 FERC ¶ 61,179 at P 140; see also id. P 300 (requiring transmission providers, where the transmission provider is not the transmission owner, to include in its compliance filing and implementation of pro forma Attachment M, that the transmission owner has the obligation for making and communicating to the transmission provider the timely calculations and determinations related to emergency ratings). 188 For example, if an RTO has four transmission owners, each with 1,600 transmission lines, each transmission owner would be required to implement DLRs on at least four transmission lines per year (provided that at least that many transmission lines meet the criteria discussed above). The potential requirement would not be implemented by the RTO transmission provider on 16 transmission lines on an RTO-wide basis. VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 carried out by transmission providers and transmission owners, whether such roles and responsibilities should be set forth in pro forma OATT provisions or left to RTO/ISO compliance proceedings, and how transmission providers should ensure that transmission owners appropriately perform their responsibilities. 2. Implementation Timeframe for the Solar Requirement 174. Recognizing that the proposed solar requirement may not require installing sensors, we preliminarily propose that this requirement be met no more than twelve months after any final rule is published in the Federal Register. We seek comment on the timeframe necessary to implement the proposed solar requirement. We seek comment on whether the clear-sky component and cloud cover component of a proposed solar requirement should have different implementation deadlines. 3. Phased-In Implementation Timeframe for the Wind Requirement a. Annual Wind Requirement Implementation Cycles 175. We preliminarily propose to require transmission providers to undertake an annual wind requirement implementation cycle. Starting with the effective date of any potential final rule, transmission providers would gather congestion data for each transmission line for one year, as described above in section IV.A.3.b.iii. Congestion Threshold, and determine during that year which of their transmission lines meet the wind speed threshold, as described above in section IV.A.3.b.ii. Wind Speed Threshold. Finally, for any transmission lines that meet the determined wind speed and congestion thresholds, transmission providers would have six months to implement the necessary systems, based on the minimum implementation requirement as described above in section IV.A.3.b.i. Number of Transmission Lines Subject to the Wind Requirement Annually, to implement the wind requirement. This proposal aims to provide ample time for transmission providers to use congestion data that reflect implementation of AARs as required by Order No. 881, while also ensuring that a wind requirement is applied to transmission lines that would benefit from a wind requirement within a reasonable timeframe. We seek comment on this proposed approach. We specifically seek comment on the duration of the data collection period, and implementation period. While we PO 00000 Frm 00026 Fmt 4701 Sfmt 4702 believe one year of congestion data will be sufficient for the first implementation cycle, we seek comment on whether this is the appropriate time period for data collection and whether the Commission should mandate a different timeframe for subsequent cycles (e.g., for cycle two, whether transmission providers should consider two years of congestion data). We also seek comment on whether the Commission should set a limit on the vintage of the congestion data (i.e., whether congestion data from five years ago is stale and no longer relevant). We also seek comment on how this approach should change if the Commission does not require sensors for the wind requirement. 176. Most commenters argue that the Commission should not require implementation of any DLR requirements until after transmission providers have implemented AARs in July 2025 and gained experience with the use of AARs.189 While not explicitly tied to Order No. 881, the preliminary proposal, if adopted in a final rule, is intended to reflect the importance of having adequate data for the purpose of identifying transmission lines where the wind requirement would be implemented, particularly in light of the likely changing congestion patterns after the implementation of Order No. 881. The Commission seeks comment on when implementation of the proposal should commence. 177. We seek comment on the preliminary proposal to use an annual implementation cycle. We also seek comment on whether the proposed annual implementation period would accurately identify transmission lines for implementation of the wind requirement or if the Commission should require (or allow, if preferred) a lower frequency (such as every two to three years) of cycles and higher linesper-cycle limit for the wind requirement cycle. 189 AEP Reply Comments, Docket No. AD22–5, at 4–5 (filed May 25, 2022); APPA/LPPC Comments, Docket No. AD22–5, at 12–13 (filed Apr. 25, 2022); APS Comments, Docket No. AD22–5, at 14 (filed Apr. 25, 2022); CAISO Comments, Docket No. AD22–5, at 2 (filed Apr. 25, 2022); EEI Comments, Docket No. AD22–5, at 33 (filed Apr. 25, 2022); ELCON Comments, Docket No. AD22–5, at 12 (filed Apr. 25, 2022); ISO–NE Comments, Docket No. AD22–5, at 5–6 (filed Apr. 25, 2022); ITC Comments, Docket No. AD22–5, at 15 (filed Apr. 25, 2022); MISO Comments, Docket No. AD22–5, at 8 (filed Apr. 25, 2022); NYISO Comments, Docket No. AD22–5, at 1–2 (filed Apr. 25, 2022); Potomac Economics Comments, Docket No. AD22–5, at 3 (filed Apr. 26, 2022); Southern Company Comments, Docket No. AD22–5, at 11 (filed Apr. 25, 2022); Tri-State Comments, Docket No. AD22–5, at 4 (filed Apr. 25, 2022). E:\FR\FM\15JYP4.SGM 15JYP4 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules b. Transmission Provider Compliance Requirement 178. As described above in section IV.A.3.b.i. Number of Transmission Lines Subject to the Wind Requirement Annually, we preliminarily propose that transmission providers be required to implement the wind requirement on the whole number greater than 0.25% (or 1 in 400) of the transmission provider’s transmission lines in each annual implementation cycle. As described above, transmission providers would be required to implement the wind requirement only on transmission lines that meet the congestion threshold and wind speed threshold. 179. We preliminarily propose to require transmission providers to implement the wind requirement on candidate transmission lines starting with the most highly congested transmission line (based on the congestion metric value, as discussed above) and moving on to the next most highly congested transmission line, and so on. This process would continue until either the yearly implementation requirement is met or there are no more candidate transmission lines waiting for implementation of the wind requirement. c. Compliance for Transmission Providers That Are Subsidiaries of the Same Public Utility Holding Company ddrumheller on DSK120RN23PROD with PROPOSALS4 180. Transmission providers (or transmission owners in cases where the transmission owners and transmission provider are not the same entity) that are operating company subsidiaries of the same public utility holding company may operate their transmission facilities as a single transmission system. We seek comment on whether such transmission systems should be counted together for purposes of the transmission providers’ compliance with any wind requirement, such as for counting the transmission providers’ total number of transmission lines and for determining the number of transmission lines that would be included in the transmission providers’ implementation cycle. This may result in implementation of the wind requirement being distributed unevenly across transmission providers that are operating company subsidiaries of the same public utility holding company. We seek comment on whether transmission providers in such situations, or the RTOs/ISOs of which they are members, should propose on compliance how they would treat such transmission providers and transmission systems. V. Comment Procedures 181. The Commission invites interested persons to submit comments on the matters and issues proposed in this ANOPR to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due October 15, 2024 and Reply Comments are due November 12, 2024. Comments must refer to Docket No. RM24–6–000, and must include the commenter’s name, the organization they represent, if applicable, and their address in their comments. All comments will be placed in the Commission’s public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters. 182. The Commission encourages comments to be filed electronically via the eFiling link on the Commission’s website at https://www.ferc.gov. The Commission accepts most standard word processing formats. Documents created electronically using word processing software must be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing. 183. Commenters that are not able to file comments electronically may file an original of their comment by USPS mail or by courier-or other delivery services. For submission sent via USPS only, filings should be mailed to: Federal Energy Regulatory Commission, Office 57715 of the Secretary, 888 First Street NE, Washington, DC 20426. Submission of filings other than by USPS should be delivered to: Federal Energy Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852. VI. Document Availability 184. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through the Commission’s Home Page (https:// www.ferc.gov). 185. From the Commission’s Home Page on the internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field. 186. User assistance is available for eLibrary and the Commission’s website during normal business hours from the Commission’s Online Support at (202) 502–6652 (toll free at 1–866–208–3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502–8371, TTY (202)502–8659. Email the Public Reference Room at public.referenceroom@ferc.gov. List of Subjects in 18 CFR Part 35 Electric power rates, Electric utilities, Reporting and recordkeeping requirements. By direction of the Commission. Commissioner Rosner is not participating. Issued: June 27, 2024. Debbie-Anne A. Reese, Acting Secretary. Note: The following appendix will not appear in the Code of Federal Regulations. Appendix A: List of Short Names/ Acronyms of Commenters in Docket No. AD22–5 Short name/acronym Commenter AEP ................................. APPA/LPPC .................... APS ................................. BPA ................................. American Electric Power Company, Inc. American Public Power Association (APPA) and the Large Public Power Council (LPPC). Arizona Public Service Company. Bonneville Power Administration. The BPA Comments were filed as appendix B to the DOE Comments and were not submitted as a separate filing. Pagination cited in the ANOPR is internal to the BPA Comments. California Independent System Operator Corporation. Certain Transmission Dependent Utilities consist of: Alliant Energy Corporate Services, Inc. (Alliant Energy), Consumers Energy Company (Consumers Energy), and DTE Electric Company (DTE Electric). Natural Resources Defense Council, Sustainable FERC Project, Southern Environmental Law Center, Western Resource Advocates, Conservation Law Foundation, RMI, and Fresh Energy. DC Energy, LLC. United States Department of Energy. CAISO ............................. Certain TDUs .................. Clean Energy Parties ...... DC Energy ...................... DOE ................................ VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 PO 00000 Frm 00027 Fmt 4701 Sfmt 4702 E:\FR\FM\15JYP4.SGM 15JYP4 57716 Federal Register / Vol. 89, No. 135 / Monday, July 15, 2024 / Proposed Rules Short name/acronym Commenter EEI .................................. EGM ................................ ELCON ............................ Entergy ............................ Idaho Power .................... ISO–NE ........................... ITC .................................. Edison Electric Institute. Electrical Grid Monitoring. Electricity Consumers Resource Council. Entergy Services, LLC. Idaho Power Company. ISO New England Inc. International Transmission Company d/b/a ITC Transmission, Michigan Electric Transmission Company, LLC, ITC Midwest LLC, and ITC Great Plains, LLC. Los Angeles Department of Water and Power. LineVision, Inc. Midcontinent Independent System Operator, Inc. North American Electric Reliability Corporation. National Rural Electric Cooperative Association. New York Independent System Operator, Inc. The New York Transmission Owners consist of: Central Hudson Gas & Electric Corporation; Consolidated Edison Company of New York, Inc.; Niagara Mohawk Power Corporation d/b/a National Grid; New York Power Authority; New York State Electric & Gas Corporation; Orange and Rockland Utilities, Inc.; Long Island Power Authority; and Rochester Gas and Electric Corporation. Organization of MISO States. Potomac Economics, Ltd. PPL Electric Utilities Corporation. R Street Institute. Southern Company Services, Inc. acting as agent for Alabama Power Company, Georgia Power Company, and Mississippi Power Company. Transmission Access Policy Study Group. Tri-State Generation and Transmission Association, Inc. TS Conductor Corporation. Working for Advanced Transmission Technologies (WATT) and Clean Energy Entities (CEE), which consist of American Clean Power Association, Advanced Energy Economy, and the Solar Energy Industries Association. LADWP ........................... LineVision ....................... MISO ............................... NERC .............................. NRECA ........................... NYISO ............................. NYTOs ............................ OMS ................................ Potomac Economics ....... PPL ................................. R Street Institute ............. Southern Company ......... TAPS ............................... Tri-State .......................... TS Conductor .................. WATT/CEE ..................... [FR Doc. 2024–14666 Filed 7–12–24; 8:45 am] ddrumheller on DSK120RN23PROD with PROPOSALS4 BILLING CODE 6717–01–P VerDate Sep<11>2014 19:58 Jul 12, 2024 Jkt 262001 PO 00000 Frm 00028 Fmt 4701 Sfmt 9990 E:\FR\FM\15JYP4.SGM 15JYP4

Agencies

[Federal Register Volume 89, Number 135 (Monday, July 15, 2024)]
[Proposed Rules]
[Pages 57690-57716]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-14666]



[[Page 57689]]

Vol. 89

Monday,

No. 135

July 15, 2024

Part IV





Department of Energy





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Federal Energy Regulatory Commission





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18 CFR Part 35





Implementation of Dynamic Line Ratings; Proposed Rule

Federal Register / Vol. 89 , No. 135 / Monday, July 15, 2024 / 
Proposed Rules

[[Page 57690]]


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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.

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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.
    [cir] Mail via U.S. Postal Service Only: Addressed to: Federal 
Energy Regulatory Commission, Secretary of the Commission, 888 First 
Street NE, Washington, DC 20426.
    [cir] 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, 
[email protected]
Lisa Sosna (Technical Information), Office of Energy Policy and 
Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-6597, 
[email protected]
Ryan Stroschein (Legal Information), Office of the General Counsel, 888 
First Street NE, Washington, DC 20426, (202) 502-8099, 
[email protected]

SUPPLEMENTARY INFORMATION: 

                            Table of Contents
 
                                                         Paragraph Nos.
 
I. Introduction......................................                  1
II. Background.......................................                  4
    A. Transmission Line Rating Proceedings..........                  5
        1. Order No. 881.............................                  5
        2. Notice of Inquiry.........................                  9
        3. Comments Supporting DLRs..................                 10
    B. Transmission Line Ratings Background..........                 14
        1. Different Types of Transmission Line                       15
         Ratings: Based on Thermal, Voltage, and
         Stability Limits............................
        2. Calculating Thermal Ratings...............                 16
        3. Variables That Impact Thermal Ratings of                   18
         Transmission Lines..........................
            a. Ambient Air Temperature...............                 19
            b. Solar Heating.........................                 20
            c. Wind Speed and Direction..............                 21
    C. Incorporating Weather Variables Into Thermal                   22
     Ratings.........................................
        1. Sensors and Their Use in DLRs.............                 25
        2. Incorporating Local Weather Forecasts Into                 33
         DLRs........................................
        3. Current Use and Benefits of DLRs..........                 36
    D. Pro forma Transmission Scheduling and                          37
     Congestion Management Practices.................
        1. How Transmission Service Is Procured......                 38
            a. Transmission Service Under the pro                     39
             forma OATT..............................
            b. Congestion Management Under the pro                    45
             forma OATT..............................
            c. Transmission Scheduling and Congestion                 46
             Management in the RTOs/ISOs.............
        2. Existing Data Reporting on Congestion, or                  47
         Proxies of Congestion.......................
            a. RTOs/ISOs.............................                 48
            b. Non-RTO/ISO Regions...................                 49
                i. ATC and Constrained Posted-Paths..                 50
                ii. Redispatch Costs.................                 53
III. The Potential Need for Reform...................                 54
    A. Demonstrated DLR Benefits.....................                 55
        1. U.S. Examples.............................                 56
        2. International Examples....................                 63
    B. Consideration of Reforms......................                 69
IV. Potential Reforms and Request for Comment........                 79
    A. Potential Transmission Line Ratings Reforms                    79
     and Request for Comment.........................
        1. Framework for a Potential Requirement.....                 81
        2. Potential Solar Requirement...............                 83
            a. Reflecting Solar Heating Based on the                  85
             Sun's Position..........................
            b. Reflecting Solar Heating Based on                      91
             Forecastable Cloud Cover................

[[Page 57691]]

 
        3. Potential Wind Requirement................                 97
            a. Components of a Wind Requirement......                 99
            i. Time Horizon and Forecasting                          101
             Requirement.............................
            ii. Sensor Requirements..................                109
            b. Proposed Criteria To Identify                         116
             Transmission Lines Subject to a Wind
             Requirement.............................
                i. Number of Transmission Lines                      117
                 Subject to the Wind Requirement
                 Annually............................
                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                       135
                 Reported............................
                (iv) LER Threshold...................                137
                (2) Potential Alternatives for                       138
                 Comment.............................
                (i) Non-RTO/ISO Congestion Costs.....                139
            c. Self-Exceptions From the Wind                         142
             Requirement.............................
                i. Self-Exception Categories.........                142
                ii. Challenges to Self-Exceptions....                151
            d. Transmission Lines Formerly Subject to                152
             the Wind Requirement....................
            e. Potential Transparency Reforms and                    153
             Request for Comment.....................
                i. Potential Reforms to Congestion                   156
                 Data Collection.....................
                ii. Posting of Congestion Data.......                158
                iii. Posting of Transmission Line                    160
                 Ratings Subject to a Wind
                 Requirement.........................
        4. Requirements for Reflecting Solar and/or                  162
         Wind in Transmission Line Ratings in RTOs/
         ISOs........................................
        5. Implications for Emergency Ratings........                166
        6. Confidence Levels.........................                169
    B. Compliance and Transition and Implementation                  174
     Timelines.......................................
        1. Pro forma OATT Revisions and                              174
         Implementation..............................
        2. Implementation Timeframe for the Solar                    176
         Requirement.................................
        3. Phased-In Implementation Timeframe for the                177
         Wind Requirement............................
            a. Annual Wind Requirement Implementation                177
             Cycles..................................
            b. Transmission Provider Compliance                      180
             Requirement.............................
            c. Compliance for Transmission Providers                 182
             That Are Subsidiaries of the Same Public
             Utility Holding Company.................
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),\1\ 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.\2\ The Commission is also considering reforms 
to ensure transparency in the development and implementation of dynamic 
line ratings.
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    \1\ 16 U.S.C. 824e.
    \2\ See, e.g., 18 CFR 35.28(b)(14).
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    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.\3\ 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.\4\ The Commission found that inaccurate 
transmission line ratings result in unjust and unreasonable Commission-
jurisdictional rates.\5\
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    \3\ 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).
    \4\ Id. P 3.
    \5\ Id. PP 3, 29.
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    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

[[Page 57692]]

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.\6\ 
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.\7\ Therefore, the Commission adopted requirements for the use of 
AARs,\8\ 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.\9\ 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.\10\ 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.\11\
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    \6\ 177 FERC ] 61,179.
    \7\ 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.
    \8\ 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).
    \9\ ``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.
    \10\ Order No. 881, 177 FERC ] 61,179 at P 149.
    \11\ Id. P 150.
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    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.\12\ Although organizationally Order No. 881 
discussed the DLR requirement for RTOs/ISOs separately from the AAR 
requirement,\13\ the Commission defined DLRs to include ambient air 
temperature and solar heating.\14\ 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.\15\
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    \12\ 18 CFR 35.28(b)(14); see Order No. 881, 177 FERC ] 61,179 
at PP 7, 235, 238.
    \13\ 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'').
    \14\ See supra n.12.
    \15\ This ANOPR does not propose any changes to the requirements 
of Order No. 881.
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    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.\16\ 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.\17\ 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.\18\ 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.\19\
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    \16\ Order No. 881, 177 FERC ] 61,179 at P 255.
    \17\ Id. P 253.
    \18\ Id. P 254.
    \19\ Id. PP 7-9.
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    8. The Commission required implementation of the requirements 
adopted in Order No. 881 by July 12, 2025, three years after compliance 
filings were due.\20\
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    \20\ 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).
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2. Notice of Inquiry
    9. On February 17, 2022, the Commission issued a Notice of Inquiry 
\21\ 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

[[Page 57693]]

entities, and supplemental comments from four entities.\22\
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    \21\ Implementation of Dynamic Line Ratings, Notice of Inquiry, 
178 FERC ] 61,110 (2022) (NOI).
    \22\ A list of commenters in the NOI proceeding and their 
abbreviated names is located in the appendix.
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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.\23\ Other commenters highlight 
DLR benefits related to reduced renewable energy curtailment and 
reduced interconnection costs.\24\
---------------------------------------------------------------------------

    \23\ 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).
    \24\ 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.\25\ 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.\26\
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    \25\ 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).
    \26\ 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.\27\
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    \27\ 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).\28\ 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.\29\ As the Commission 
explained, ``Relevant transmission equipment may include, but is not 
limited to, circuit breakers, line traps, and transformers.'' \30\ For 
purposes of the discussion that follows, references to transmission 
``line'' ratings encompass ratings for all transmission equipment that 
has a rating.
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    \28\ Order No. 881, 177 FERC ] 61,179 at P 44.
    \29\ Id.
    \30\ 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.\31\ 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.\32\
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    \31\ See, e.g., IEEE Standard 738-2023, ``IEEE Standard for 
Calculating the Current-Temperature Relationship of Bare Overhead 
Conductors,'' 2023 (IEEE 738); and CIGR[Eacute] Technical Brochure 
207, ``Thermal Behavior of Overhead Conductors, Working Group 
22.12,'' 2002 (CIGR[Eacute] 207).
    \32\ 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.\33\ Choosing

[[Page 57694]]

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.
---------------------------------------------------------------------------

    \33\ 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.\34\ 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.\35\
---------------------------------------------------------------------------

    \34\ 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.
    \35\ 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.\36\ 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.'' \37\ 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.
---------------------------------------------------------------------------

    \36\ See id. P 26.
    \37\ See id. P 7.
---------------------------------------------------------------------------

    23. DLR implementation requires making reliable short-term 
forecasts \38\ 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.\39\
---------------------------------------------------------------------------

    \38\ 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 R[eacute]seaux 
[Eacute]lectriques/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.
    \39\ 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).\40\
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    \40\ 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.\41\ 
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.\42\ 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.\43\ 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.
---------------------------------------------------------------------------

    \41\ Managing Transmission Line Ratings, Staff Report, Docket 
No. AD19-15-000, at 9 (issued Aug. 23, 2019).
    \42\ Id.
    \43\ 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

[[Page 57695]]

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.\44\
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    \44\ 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.
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    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.\45\ However, 
because wind speed and direction are highly variable and subject to 
local geographic differences,\46\ 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.
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    \45\ WATT/CEE Comments, Docket No. AD22-5, at 14 (filed Apr. 25, 
2022).
    \46\ 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.\47\ 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.
---------------------------------------------------------------------------

    \47\ 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.\48\ 
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.
---------------------------------------------------------------------------

    \48\ See, e.g., PPL Comments, Docket No. AD22-5, at 17-18 (filed 
Apr. 25, 2022).
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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.\49\ 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.\50\
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    \49\ 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.
    \50\ 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

[[Page 57696]]

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.\51\ 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.
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    \51\ 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.
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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 \52\ 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.\53\
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    \52\ 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).
    \53\ Transmission line ratings are also used by transmission 
providers for other purposes, including as part of transmission 
planning.
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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.\54\ Point-to-point transmission service is 
offered on a firm and non-firm basis.\55\ 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).\56\ Specifically, ATC is calculated as: ATC = TTC - ETC - CBM - 
TRM.\57\
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    \54\ Pro forma OATT, section 1.37 (Point-To-Point Transmission 
Service).
    \55\ Id.; id. section 13.6 (Curtailment of Firm Transmission 
Service).
    \56\ 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. Sec.  37.6(b)(1)(viii).
    \57\ 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).
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    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.\58\ 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).\59\
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    \58\ Pro forma OATT, section 15.4(b).
    \59\ Id. section 15.4(c); id. section 19.3 (System Impact Study 
Procedures).
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    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.

[[Page 57697]]

    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.\60\ 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.\61\
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    \60\ Pro forma OATT, pt. III (Network Integration Transmission 
Service Preamble); id. section 28 (Nature of Network Integration 
Transmission Service).
    \61\ 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).
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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.\62\ 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.\63\ 
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.\64\
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    \62\ 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).
    \63\ 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).
    \64\ Id. section 33.2 (Transmission Constraints).
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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.\65\
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    \65\ 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).\66\ 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).\67\ 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.\68\ LMPs and shadow 
prices reflect marginal rather than total costs.
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    \66\ 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).
    \67\ 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.
    \68\ 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.\69\ 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.\70\ For all posted paths, ATC, TTC, CBM, and TRM 
values must be automatically posted.\71\ 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

[[Page 57698]]

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.\72\
---------------------------------------------------------------------------

    \69\ 18 CFR 37.6.
    \70\ Id. Sec.  37.6(b)(1)(i).
    \71\ Id. Sec.  37.6(b)(3).
    \72\ Id. Sec.  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.\73\ For all constrained posted paths, additional detailed 
information must be made available upon request.\74\ 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.\75\
---------------------------------------------------------------------------

    \73\ Id. Sec.  37.6(b)(1)(ii).
    \74\ Id. Sec.  37.6(b)(2)(ii).
    \75\ 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).\76\ 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.
---------------------------------------------------------------------------

    \76\ Id. Sec.  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.\77\ Because non-RTO/ISO regions do not publish nodal 
prices that reflect congestion costs, the cost of redispatching 
resources is less transparent.\78\ 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.
---------------------------------------------------------------------------

    \77\ 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.
    \78\ 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.\79\ 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.
---------------------------------------------------------------------------

    \79\ 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.\80\ By contrast, PPL states that it internally 
estimated the cost to reconductor the Susquehanna-Harwood double-
circuit line to be approximately $12 million.\81\ 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%.\82\ 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

[[Page 57699]]

on five additional transmission lines by the end of 2024.\83\
---------------------------------------------------------------------------

    \80\ 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.
    \81\ PPL Comments, Docket No. AD22-5, at 14-15 (filed Apr. 25, 
2022).
    \82\ PPL Supplemental Comments, Docket No. AD22-5, at 2-4 (filed 
Feb. 9, 2024).
    \83\ Id.
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    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.\84\
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    \84\ 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).\85\ The DLR sensors were reported as 
``easy to install, reliable, and effective at reporting periods of 
either excess or limited capacity.'' \86\
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    \85\ 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.
    \86\ 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.\87\ 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.\88\
---------------------------------------------------------------------------

    \87\ 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.
    \88\ Id.
---------------------------------------------------------------------------

    61. In August 2021, Duquesne Light Company (Duquesne), a 
transmission owner in PJM, partnered with LineVision on a DLR pilot 
project.\89\ 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.\90\
---------------------------------------------------------------------------

    \89\ 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.
    \90\ 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.\91\
---------------------------------------------------------------------------

    \91\ 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.\92\ 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.'' \93\ RTE, France's transmission operator, used DLR to integrate 
wind power generation and avoid a $30 million transmission line 
replacement.\94\
---------------------------------------------------------------------------

    \92\ 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.
    \93\ 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).
    \94\ 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.\95\ 
The Slovenian system operator has used DLR on each span of 31 
transmission lines since 2016, increasing capacity an average of 
22%.\96\ 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.\97\
---------------------------------------------------------------------------

    \95\ Idaho National Laboratory, A Guide to Case Studies of Grid 
Enhancing Technologies, at 22 (Oct. 2022).
    \96\ [Scaron]pela Vidrih, Andrej Matko, Janko Kosma[ccaron], 
Toma[zcaron] Tom[scaron]i[ccaron], Ale[scaron] Donko, Operational 
Experiences with the Dynamic Thermal Rating System, at 8, 2d South 
East European Regional CIGRE Conference, Kyiv (2018).
    \97\ 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.\98\
---------------------------------------------------------------------------

    \98\ 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 [pound]1.4 million per 
year.\99\ 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\
---------------------------------------------------------------------------

    \99\ 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

[[Page 57700]]

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\
---------------------------------------------------------------------------

    \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 supra section III.A.1.
    \108\ See supra P 57.
---------------------------------------------------------------------------

    74. The use of DLRs may also provide benefits to customers by 
mitigating the need for more expensive upgrades. PPL's internal 
estimate to reconductor the Susquehanna-Harwood double-circuit line 
discussed above was approximately $12 million. In contrast, the cost to 
install DLRs on that line was less than $500,000.\109\ In addition, a 
recent report on an initial deployment of DLRs by subsidiaries of AES 
Corporation compares estimated costs and implementation times of DLR 
deployment and reconductoring.\110\ For a 345 kV transmission line in 
the AES Indiana footprint located in an area where significant load 
growth was expected, the cost to reconductor the transmission line was 
estimated to be $590,000 per mile, while the cost for DLR 
implementation was estimated to be $45,000 per mile.\111\ The 
implementation time for reconductoring was estimated to be two years 
while the implementation for DLR was estimated to be nine months. For a 
69 kV transmission line in the AES Ohio footprint that was experiencing 
regular thermal overload, the cost for full reconductoring was 
estimated to be $1.63 million, while the cost for DLR with targeted 
reconductoring was estimated to be $390,000.\112\ The implementation 
timelines were two years for full reconductoring and one year for DLR 
with targeted reconductoring.
---------------------------------------------------------------------------

    \109\ See PPL Comments, Docket No. AD22-5, at 14-15 (filed Apr. 
25, 2022).
    \110\ 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.
    \111\ Id. at 14.
    \112\ Id. at 18.
---------------------------------------------------------------------------

    75. Likewise, the ability to increase transmission flows into load 
pockets may reduce a transmission provider's reliance on local reserves 
inside load pockets. This may reduce local reserve requirements and the 
costs to maintain that required level of reserves, which, in turn, may 
result in cost reductions and wholesale rates that avoid unnecessary 
congestion costs.\113\
---------------------------------------------------------------------------

    \113\ Order No. 881, 177 FERC ] 61,179 at P 34.
---------------------------------------------------------------------------

    76. DLRs can also provide reliability benefits by increasing the 
transfer capability on the existing transmission system in a way that 
provides system operators with more options during stressed system 
conditions. For example, as PJM explained, the presence of DLRs on its 
system during Winter Storm Elliott contributed to system reliability 
because the higher transmission line ratings allowed it to avoid re-
dispatching its system.\114\ DLR systems also give transmission 
providers a more complete picture of how the system is operating, 
particularly in contingency situations, which allows transmission 
providers to maximize their system's performance while maintaining a 
safe, reliable, and efficient system.\115\ DLRs can also improve 
reliability by monitoring the condition of transmission lines and 
alerting utilities to hazardous conditions or potential failures on 
transmission lines, which may otherwise go

[[Page 57701]]

undetected.\116\ In addition, DLRs with certain sensors, such as LiDAR, 
can support public safety by providing for greater situational 
awareness by monitoring the clearance of transmission lines from the 
ground or nearby vegetation and providing data to assist in wildfire 
prevention strategies, including when to clear vegetation and when to 
upgrade equipment.\117\
---------------------------------------------------------------------------

    \114\ See supra P 58.
    \115\ See DOE Comments, Docket No. AD22-5, Attachment A at 58 
(filed Apr. 25, 2022); AES Corporation and LineVision, Inc., Lessons 
from First Deployment of Dynamic Line Ratings, at 5-6 (Apr. 2024).
    \116\ See PPL Comments, Docket No. AD22-5, at 15 (filed Apr. 25, 
2022).
    \117\ See AES Corporation and LineVision, Inc., Lessons from 
First Deployment of Dynamic Line Ratings, at 17 (Apr. 2024); DOE 
Comments, Docket No. AD22-5, attach. A at 57-58 (filed Apr. 25, 
2022).
---------------------------------------------------------------------------

    77. The Commission also explained that decreasing transfer 
capability when it is overstated can avoid placing transmission lines 
at risk of inadvertent overload and can signal to the market that more 
generation and/or transmission investment may be needed in the long 
term.\118\
---------------------------------------------------------------------------

    \118\ Order No. 881, 177 FERC ] 61,179 at P 35.
---------------------------------------------------------------------------

    78. Finally, we preliminarily find that certain transparency 
reforms are necessary to ensure accurate transmission line ratings. As 
discussed below, the record indicates a lack of transparency for 
congestion costs in non-RTO/ISO regions. Understanding if, and how 
much, congestion may exist on a transmission line is essential to 
understanding whether that transmission line may benefit from the 
preliminary proposals in this rulemaking. As the Commission explained 
in Order No. 881, if a stakeholder does not know the basis for a given 
transmission line rating, particularly for a transmission line that 
frequently binds and elevates prices, it cannot determine whether the 
transmission line rating is accurately calculated.\119\ We seek comment 
on this preliminary finding.
---------------------------------------------------------------------------

    \119\ Id. P 39.
---------------------------------------------------------------------------

IV. Potential Reforms and Request for Comment

A. Potential Transmission Line Ratings Reforms and Request for Comment

    79. As detailed above in section II.C.3. Current Use of DLRs and 
below in sections IV.A.2. Potential Solar Requirement and IV.A.3. 
Potential Wind Requirement, the current record suggests that DLRs can 
result in more accurate transmission line ratings \120\ and significant 
benefits, including cost savings, through increased transfer 
capability. Specifically, we preliminarily find that the benefits of 
more accurate transmission line ratings outweigh the cost of 
implementation for DLRs that reflect more detailed solar heating based 
on the sun's position and forecastable cloud cover and, for certain 
transmission lines, that reflect forecasts of wind conditions. The 
applicability of the solar and wind requirements proposed below--
applying a solar requirement for all transmission lines and a wind 
requirement for only certain lines--follows our understanding from 
outreach that reflecting solar heating based on the sun's position and 
forecastable cloud cover can be done without installing sensors and 
that reflecting wind conditions likely requires sensors. We seek 
comment on the proposed framework, as discussed below.
---------------------------------------------------------------------------

    \120\ The proposed reforms in this ANOPR apply only to thermal 
ratings. Therefore, unless otherwise noted, use of the term 
``rating'' hereafter should be assumed to mean ``thermal rating.''
---------------------------------------------------------------------------

    80. As noted above, in Order No. 881, the Commission, in effect, 
required RTOs/ISOs to be able to accept DLRs.\121\ We do not propose to 
change this requirement here.
---------------------------------------------------------------------------

    \121\ Id. P 255.
---------------------------------------------------------------------------

1. Framework for a Potential Requirement
    81. We preliminarily propose a DLR framework for reforms to improve 
the accuracy of transmission line ratings.\122\ These reforms would 
require transmission providers to implement DLRs that--on all 
transmission lines--reflect solar heating, based on the sun's position 
and forecastable cloud cover, and--on certain transmission lines--
reflect forecasts of wind speed and wind direction. Thus, the proposed 
DLR framework sets forth both a solar requirement and a wind 
requirement. Additionally, the reforms would ensure transparency into 
the development and implementation of transmission line ratings and 
would enhance data reporting practices related to congestion in non-
RTO/ISO regions to identify candidate transmission lines for the wind 
requirement. Under the proposed framework, these requirements would be 
subject to certain exceptions and/or implementation limits, as detailed 
below.
---------------------------------------------------------------------------

    \122\ We note that, per Attachment M of the pro forma OATT, a 
transmission line rating would apply to both the conductor and any 
relevant transmission equipment, which includes but is not limited 
to circuit breakers, line traps, and transformers. See pro forma 
OATT, attach. M, Transmission Line Rating.
---------------------------------------------------------------------------

    82. The NOI asked whether other weather conditions should be part 
of a potential DLR requirement.\123\ However, there appears to be 
neither a strong record of the impact of other non-wind/non-solar 
weather conditions on transmission line ratings nor a standard for 
incorporating those weather conditions into transmission line ratings, 
as there is for solar heating and wind conditions (e.g., IEEE 738 and 
CIGRE TB 299).\124\ Thus, we do not propose to include such other 
variables in the proposed framework. We seek comment on the impact of 
non-wind/non-solar weather conditions on transmission line ratings, 
relevant standards associated with those weather conditions, and 
whether and how the Commission should require consideration of other 
weather conditions in its proposed rule.
---------------------------------------------------------------------------

    \123\ NOI, 178 FERC ] 61,110 at P 17 (Question 17).
    \124\ Institute of Electrical and Electronics Engineers, IEEE 
Standard for Calculating the Current-Temperature Relationship of 
Bare Overhead Conductors 21-23, IEEE Std 738-2023 (2023) (IEEE 738); 
Conseil International des Grands R[eacute]seaux [Eacute]lectriques/
International Council of Large Electric Systems (CIGRE), Guide for 
selection of weather parameters for bare overhead conductor ratings, 
Technical Brochure 299, Aug. 2006 (CIGRE TB 299).
---------------------------------------------------------------------------

2. Potential Solar Requirement
    83. We preliminarily propose to require that all transmission line 
ratings used for evaluating transmission service that ends not more 
than 10 days after the transmission service request date (hereinafter 
``near-term transmission service'') \125\ be subject to a solar 
requirement to reflect solar heating in two ways, one based on solar 
heating derived from the sun's position and one based on up-to-date 
forecasts of forecastable cloud cover, subject to certain exceptions.
---------------------------------------------------------------------------

    \125\ See pro forma OATT, attach. M, Near-Term Transmission 
Service.
---------------------------------------------------------------------------

    84. This proposal would apply to all transmission line ratings 
because it is our understanding that the solar requirement can be 
incorporated without installing sensors, enabling the benefit of 
additional transfer capability through more accurate accounting of 
solar heating with only minimal implementation costs. Further, this 
proposal would apply the solar requirement to near-term transmission 
service because the requirement effectively would subsume the daytime/
nighttime solar heating requirement set forth in Order No. 881, which 
applies to near-term transmission service. The currently effective 
Attachment M of the pro forma OATT already provides for transmission 
providers to take a self-exception to the requirement to include solar 
heating in transmission line ratings for transmission lines for which 
the technical transfer capability of the limiting conductors and/or 
limiting transmission equipment is not dependent on solar heating, and 
for transmission lines whose transfer capability is limited by a 
transmission

[[Page 57702]]

system limit that is not dependent on solar heating.\126\ The existing 
exception would also apply to the proposed requirement that 
transmission line ratings reflect solar heating based on the sun's 
position and forecastable cloud cover.
---------------------------------------------------------------------------

    \126\ See id., attach. M, Obligations of the Transmission 
Provider; see also Order No. 881, 177 FERC ] 61,179 at P 227.
---------------------------------------------------------------------------

a. Reflecting Solar Heating Based on the Sun's Position
    85. We preliminarily propose to require that all transmission line 
ratings used for near-term transmission service reflect solar heating 
based on the sun's position accounting for the relevant geographic 
location, date, and hour. Under this approach, transmission line 
ratings would reflect the potential for the sun to heat the 
transmission lines during each hour based on its position in the sky, 
assuming zero cloud cover. Stated another way, transmission providers 
will need to calculate, for each hour, the effect of the sun's position 
on its transmission line ratings. Transmission providers would have the 
discretion to calculate the effect of the sun's position on their 
transmission line ratings using more granular time increments. Because 
solar heating based on the sun's position starts at close to zero in 
the hours shortly after sunrise, rises throughout the morning hours to 
the midday peak, and then decreases through the afternoon to near zero 
again in the hours shortly before sunset, requiring all transmission 
line ratings used for near-term transmission service to reflect solar 
heating based on the sun's position may produce more accurate 
transmission line ratings than the daytime/nighttime assumptions 
required under Order No. 881.
    86. As the Commission explained in Order No. 881,\127\ clear-sky 
solar heating assumptions based on the sun's position can be computed 
with accuracy from formulas, such as those provided in standards like 
IEEE 738 or CIGRE TB 601.\128\ Such calculations depend only on 
geographic location, date, and time and are therefore free of any 
forecast uncertainty. Likewise, such calculations do not require local 
sensors or weather data. The Commission considered whether AARs should 
incorporate such hourly clear-sky solar heating assumptions in Order 
No. 881 but elected at that time to instead require the simpler but 
less precise daytime/nighttime approach to solar heating. Under that 
approach, the AARs are required to reflect only the absence of solar 
heating during nighttime periods, where local sunrise/sunset times are 
updated at least monthly. The Commission found that, compared to the 
hourly clear-sky solar heating approach, the simpler daytime/nighttime 
approach ``balance[d] the benefits and burdens'' associated with the 
rule.\129\
---------------------------------------------------------------------------

    \127\ Order No. 881, 177 FERC ] 61,179 at P 150.
    \128\ Institute of Electrical and Electronics Engineers, IEEE 
Standard for Calculating the Current-Temperature Relationship of 
Bare Overhead Conductors 21-23, IEEE Std 738-2023 (2023) (IEEE 738); 
Conseil International des Grands R[eacute]seaux [Eacute]lectriques/
International Council of Large Electric Systems (CIGRE), Guide for 
Thermal Rating Calculations of Overhead Lines, Technical Brochure 
601, Dec. 2014.
    \129\ Order No. 881, 177 FERC ] 61,179 at P 150.
---------------------------------------------------------------------------

    87. However, upon considering the NOI comments, and based on 
subsequent outreach and further research, we preliminarily find that 
the benefits of more accurate transmission line ratings that reflect 
solar heating based on the sun's position are significant. This is 
particularly true during the hours right after sunrise and right before 
sunset--hours with relatively little solar heating. Because electric 
demand often peaks in the hours just before sunset, assuming midday 
solar heating during these hours may understate the amount of transfer 
capability available and increase the costs and challenges of reliably 
meeting peak demand. Additionally, regions with high levels of solar 
generation may benefit from the additional transmission capacity as 
load rises and solar generation declines, which further demonstrates 
that understating the amount of transfer capability available during 
these hours may increase the costs and challenges of maintaining 
reliability.
    88. The record in the Order No. 881 proceeding indicates that 
considering solar heating based on the sun's position can affect a 
transmission line's rating by as much as 5% to 11%.\130\ Also, joint 
research by Commission staff and NOAA staff modeled the effect of the 
absence of solar heating on the rating of a typical aluminum conductor 
steel reinforced (ACSR) cable and found that transmission line ratings 
could increase by about 12% in the hours immediately after sunrise and 
before sunset.\131\ While this range of percentages represents expected 
transmission line rating increases between assuming full midday sun and 
assuming no sun whatsoever, they nonetheless demonstrate that 
transmission line ratings would likely significantly increase in the 
early morning and late afternoon hours, and moderately increase in most 
other daytime hours, relative to assuming full midday sun conditions 
during all daylight hours. For example, Commission and NOAA staff's 
modeling found that considering hourly clear-sky solar heating 
increased transmission line ratings (relative to the daytime/nighttime 
ratings approach) in each of the four hours immediately after sunrise 
and before sunset by 4% to 12%.\132\
---------------------------------------------------------------------------

    \130\ Potomac Economic Comments, Docket No. RM20-16, at 15 
(filed Mar. 23, 2021) (``We estimate that the average size of 
[setting solar irradiance to zero] for nighttime ratings to be an 11 
percent increase''); PG&E Comments, Docket No. RM20-16, at 11 (filed 
Mar. 22, 2021) (``PJM's research shows that at least 14% of their 
line ratings are increased by 10% by considering solar 
irradiance''); Entergy Comments, Docket No. RM20-16, at 8 (filed 
Mar. 22, 2021) (``The shade of the night provides an additional 5% 
to the ratings of the lines'').
    \131\ 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 
2022 Software Conference at slide 29 (June 23, 2022), https://www.ferc.gov/media/demonstration-potential-datacalculation-workflows-under-ferc-order-no-881s-ambient-adjusted. Actual 
increases could vary from the modeled increase, depending on 
conductor surface conditions and other factors.
    \132\ Id.
---------------------------------------------------------------------------

    89. We seek comment on our preliminary proposal to require that all 
transmission line ratings used for near-term transmission service 
reflect solar heating based on the sun's position for the relevant 
geographic location, date, and hour under a clear sky. We also seek 
comment on the costs, non-financial burdens, and financial and non-
financial benefits of this requirement.
    90. As noted in section III. The Potential Need for Reform above, 
we preliminarily find that transmission line ratings used for near-term 
transmission service that do not reflect solar heating based on the 
sun's position may result in unjust and unreasonable wholesale rates. 
In addition to the requests for comments on specific aspects of this 
preliminary proposal, we seek comment on whether reflecting solar 
heating based on the sun's position in transmission line ratings used 
for near-term transmission service would result in more accurate 
transmission line ratings and would, in turn, better reflect system 
transfer capability. We also seek comment on whether the greater 
accuracy of transmission line ratings would result in cost savings and 
just and reasonable wholesale rates. Further, given that the sun's 
position is forecastable without uncertainty, we seek comment on 
whether transmission providers should reflect solar heating based on 
the sun's position for transmission service longer than 10 days 
forward.

[[Page 57703]]

b. Reflecting Solar Heating Based on Forecastable Cloud Cover
    91. We preliminarily propose to require that all transmission line 
ratings used for near-term transmission service reflect solar heating 
based on up-to-date forecasts of forecastable cloud cover. Transmission 
providers will need to reflect, for each hour, the effect of 
forecastable cloud cover on its transmission line ratings. Transmission 
providers would have the discretion to calculate the effect of the 
sun's position on their transmission line ratings using more granular 
time increments. This proposal does not imply that the cloud cover must 
be forecastable for the entire 10 days, but rather that transmission 
providers should reflect forecastable cloud cover in their up-to-date 
forecasts as that information becomes available.\133\ Based on outreach 
and research, we understand that certain overcast periods can be 
forecast accurately in certain conditions. For example, some portions 
of the continental United States regularly see overcast conditions for 
weeks at a time. During such periods, solar heating can be 
significantly reduced, significantly increasing transmission transfer 
capability.
---------------------------------------------------------------------------

    \133\ See infra P 95.
---------------------------------------------------------------------------

    92. We preliminarily propose to define forecastable cloud cover as 
cloud cover that is reasonably determined, in accordance with good 
utility practice, to be forecastable to a sufficient level of 
confidence to be reflected in transmission line ratings. We clarify 
that we are not proposing to require that transmission providers seek 
to forecast individual clouds, or even most cloud formations. We seek 
comment on this definition of forecastable cloud cover and the level of 
confidence that is necessary to incorporate and benefit from a cloud 
cover forecast.
    93. We also seek comment on whether sensors are needed to 
accurately forecast cloud cover. If commenters believe local sensors 
are required to accurately forecast cloud cover events, we seek comment 
on how such sensors improve such forecasts.
    94. We note that some cloud cover events may be more easily 
forecast forward than other cloud cover events. Some overcast 
conditions will not be forecastable at all. For many or most weather 
systems that produce forecastable cloud cover conditions, such 
conditions may be forecastable only for a short time ahead of a given 
operating hour, rather than for the full 10 days forward. For other 
very large weather systems, or for periods of seasonal overcast 
conditions in some parts of the country, such conditions may be 
forecastable for longer periods.
    95. Therefore, we propose to limit the proposed requirement to 
reflect up-to-date forecasts of forecastable cloud cover because, if a 
cloud cover event is not ``forecastable,'' then we believe it would not 
be practical to require that it be reflected. However, if a cloud cover 
event becomes ``forecastable'' during the relevant timeframe, it must 
be reflected in the up-to-date forecasts under the proposed 
requirement. Specifically, under the proposed requirement, forecastable 
cloud cover data must be incorporated into ratings calculations as 
close to real time as reasonably possible (i.e., as close to the time 
that a relevant forecast becomes available) given the timelines needed 
to obtain forecast data and perform the calculation, as well as any 
other steps needed for validation, communication, or implementation of 
the transmission line rating.\134\ We seek comment on this proposal to 
require that transmission providers incorporate up-to-date forecasts of 
forecastable cloud cover into all transmission line ratings used for 
near-term transmission service. We also seek comment on whether the 
requirement to incorporate up-to-date forecasts of forecastable cloud 
cover should apply to transmission services other than near-term 
transmission service and whether all transmission service should be 
subject to this requirement, not just near-term transmission service.
---------------------------------------------------------------------------

    \134\ See Order No. 881, 177 FERC ] 61,179 at P 143.
---------------------------------------------------------------------------

    96. We seek comment on the costs, non-financial burdens, and 
financial and non-financial benefits of reflecting solar heating 
through the use of up-to-date forecasts of forecastable cloud cover in 
transmission line ratings used for near-term transmission service, and 
the extent to which this practice would increase the accuracy of the 
resulting transmission line rating. Further, we seek comment on whether 
transmission providers should reflect up-to-date forecasts of 
forecastable cloud cover in transmission line ratings used for 
transmission service up to 10 days forward or whether these forecasts 
should be reflected only in the transmission line ratings used for a 
shorter time frame, such as 36 or 48 hours forward. If parties believe 
sensors are required to accurately forecast cloud cover, we seek 
comment on whether cloud cover should alternatively be reflected only 
in transmission line ratings for transmission lines that exceed a 
congestion threshold, and what that threshold should be. We seek 
comment on whether, alternatively, up-to-date forecasts of forecastable 
cloud cover should be reflected only in the ratings of the more limited 
set of transmission lines we propose would be subject to a wind 
requirement (described below).
3. Potential Wind Requirement
    97. We preliminarily propose to additionally require certain 
transmission lines to reflect up-to-date forecasts of wind conditions, 
including wind speed and direction, in their transmission line ratings 
for use in 48-hour transmission service, as defined below in section 
IV.A.3.a.i.a 48-Hour Transmission Service. We preliminarily propose 
that this wind requirement would be implemented only on transmission 
lines \135\ exceeding thresholds for wind speed \136\ and 
congestion.\137\ Other transmission lines would not be subject to the 
wind requirement but would still be subject to the solar requirement 
discussed above.
---------------------------------------------------------------------------

    \135\ Id. P 44.
    \136\ This threshold is described below in section IV.A.3.b.ii 
Wind Speed Threshold.
    \137\ This threshold is described below in section IV.A.3.b.iii 
Congestion Threshold.
---------------------------------------------------------------------------

    98. We preliminarily propose that, for each transmission line that 
is subject to the wind requirement, individual transmission providers 
apply good utility practice to determine which specific electric system 
equipment associated with that line--beyond the conductor--is affected 
by wind conditions and thus also would be subject to the wind 
requirement. This approach is similar to that taken by the Commission 
in Order No. 881 with respect to AARs.\138\ We seek comment on whether 
the wind requirement should explicitly apply only to the conductor 
portion of a transmission line, and if so why.
---------------------------------------------------------------------------

    \138\ This proposal is consistent with the definition of 
Transmission Line Rating in Attachment M of the pro forma OATT, 
which includes ``considering the technical limitations on conductors 
and relevant transmission equipment . . . [which] may include, but 
is not limited to, circuit breakers, line traps, and transformers.'' 
See pro forma OATT, attach. M, Definitions; 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

[[Page 57704]]

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.
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    \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.
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    \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

[[Page 57705]]

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).
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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

[[Page 57706]]

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

[[Page 57707]]

(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\
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    \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.
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    \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

[[Page 57708]]

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.
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    \159\ For example, limiting element data are already required to 
be made publicly available for certain constrained paths under Sec.  
37.6(a)(2)(ii) of the Commission's regulations. 18 CFR 
37.6(a)(2)(ii) (2023).
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(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 Sec.  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.
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    \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).
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(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.
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    \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

[[Page 57709]]

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.
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    \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.
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(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.
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    \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

[[Page 57710]]

cost exception should require a showing by the transmission 
provider.\171\
---------------------------------------------------------------------------

    \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 Timelines section. In some instances, 
this proposal may merely require a review of the inputs and assumptions 
to the original self-exception analysis, to verify that they have not 
changed. In other instances, if such inputs and assumptions have 
changed, then analyses would need to be updated. If the technical basis 
for an exception is found to no longer apply, the transmission provider 
would be required to update the relevant transmission line rating(s) in 
a timely manner. We seek comment on this proposal for annual re-
evaluations of self-exceptions, including whether another timeframe is 
more appropriate. We seek comment on the information that should be 
included in the transmission line rating log to justify a self-
exception under either self-exception finding.
    148. We note that Order No. 881 and the System Reliability section 
of the pro forma OATT Attachment M provides for the temporary use of a 
transmission line rating different than would otherwise be required if 
such rating is determined to be necessary to ensure the safety and 
reliability of the transmission system.\174\ Under this preliminary 
proposal, we would maintain that System Reliability provision in 
Attachment M, which would similarly apply to any

[[Page 57711]]

transmission lines to which the wind requirement would otherwise apply.
---------------------------------------------------------------------------

    \174\ Order No. 881, 177 FERC ] 61,179 at P 232; pro forma OATT, 
attach. M (System Reliability).
---------------------------------------------------------------------------

ii. Challenges to Self-Exceptions
    149. We propose to allow any person that disagrees with a 
transmission provider's self-exception to challenge that self-exception 
by filing a complaint with the Commission under FPA section 206. 
Examples of potential complaints concerning a transmission provider's 
self-exceptions could include that a transmission provider improperly 
claimed that the transmission line is not affected by wind speed, or 
that a transmission provider made a faulty demonstration that the 
transmission line ratings subject to wind requirement would not produce 
net benefits on the transmission line, such as through improper 
calculations of costs or benefits. The Commission could also institute 
an investigation under FPA section 206 on its own motion to examine any 
self-exception. We seek comment on whether there should be another 
means to challenge a self-exception.
d. Transmission Lines Formerly Subject to the Wind Requirement
    150. In cases when a transmission provider determines that a 
transmission line subject to a wind requirement no longer exceeds the 
thresholds for high levels of congestion and wind speed, we 
preliminarily propose that the wind requirement no longer apply to the 
transmission line and that transmission providers will no longer be 
required to include wind conditions when calculating the transmission 
line rating. For example, the transmission provider would be permitted, 
inter alia, to decommission the sensors if any, on that transmission 
line. Similarly, if a transmission provider determines that a 
transmission line previously subject to a wind requirement is no longer 
expected to produce net benefits, then we preliminarily propose that 
the wind requirement no longer apply to the transmission line and that 
the transmission provider will no longer be required to include wind 
measurements when calculating the transmission line rating and the 
transmission provider would be permitted to decommission any sensors on 
that transmission line. We further preliminarily propose that, when 
calculating the net benefits of a wind requirement to determine if a 
particular transmission line should be subject to the wind requirement 
sunk costs, such as past installations of sensors, should not be 
included. Under the preliminary proposal, such transmission providers 
would be required to document their decision to stop applying the wind 
requirement and to decommission any sensors and provide a 
justification. Similar to the proposed self-exception process, 
transmission providers would log such decision, including the nature of 
and basis for each decommissioning, the date(s) and time(s) that the 
decommissioning was initiated, and (if applicable) documentation of the 
net benefit analysis calculation, methodology, and assumptions in their 
database of transmission line ratings and transmission line rating 
methodologies on OASIS or another website with authentication control 
including multi-factor authentication at least one year prior to the 
decommissioning. A justification could be, for example, that a 
transmission line no longer meets the congestion or wind speed 
thresholds or that the wind requirement no longer provides net benefits 
on a transmission line. Such justifications for removing the wind 
requirement would be subject to the same opportunities to be challenged 
pursuant to FPA section 206 discussed above for the self-exception 
process. Also, a goal of applying DLRs, including the wind requirement, 
to a transmission line is to reduce congestion. It stands to reason 
that a transmission line that is subject to the wind requirement may 
experience less congestion because of the wind requirement, such that 
it no longer meets the congestion threshold. In such cases, it may be 
counterintuitive to remove the wind requirement. As such, we 
preliminarily propose that any decision to remove the wind requirement 
from a transmission line must examine and compare the congestion with 
the wind requirement in place against the estimated congestion if the 
wind requirement were not in place. We seek comment on this preliminary 
proposal for a decommissioning process. Further, we seek comment on the 
costs and other burdens associated with decommissioning DLR equipment. 
We also seek comment on whether the threshold criteria should be 
required to no longer be met for a longer period of time (e.g., 5 
years) before decommissioning is allowed.
e. Potential Transparency Reforms and Request for Comment
    151. We preliminarily propose new transparency reforms, including 
requirements to enhance data reporting practices related to congestion 
in non-RTO/ISO regions to identify candidate transmission lines for a 
wind requirement, and posting and retention of congestion data in both 
RTO/ISO and non-RTO/ISO regions. The proposed reforms will provide 
transparency into the transmission providers' identification of 
transmission lines that would be subject to the wind requirement and 
enable the Commission and stakeholders to verify the transmission 
providers' analysis. Order No. 881 already requires a database of 
transmission line ratings and methodologies to be posted.\175\ This 
posting requirement would extend to transmission line ratings on 
transmission lines subject to the solar and wind requirements as well.
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    \175\ See Order No. 881, 177 FERC ] 61,179 at PP 330, 336-340. 
The transmission provider must post the information on the password-
protected section (or section subject to authentication control 
including multi-factor authentication) of its OASIS site or on 
another website with authentication control including multi-factor 
authentication. Id. P 336; see supra n.200.
---------------------------------------------------------------------------

    152. Some commenters in the NOI proceeding support adopting the 
same transparency measures for transmission lines subject to a wind 
requirement as the Commission adopted in Order No. 881.\176\ In 
addition, some commenters support going further and requiring the 
filing and posting of informational reports on which transmission lines 
meet the Commission's wind requirement criteria, as well as the 
transmission line ratings and methodologies used for implementation of 
the wind requirement.\177\
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    \176\ DC Energy Comments, Docket No. AD22-5, at 4 (filed Apr. 
25, 2022); LADWP Comments, Docket No. AD22-5, at 4-5 (filed Apr. 25, 
2022); PJM Comments, Docket No. AD22-5, at 6-7 (filed May 9, 2022); 
TAPS Comments, Docket No. AD22-5, at 8 (filed Apr. 25, 2022).
    \177\ DC Energy Comments, Docket No. AD22-5, at 5 (filed Apr. 
25, 2022); ELCON Comments, Docket No. AD22-5, at 2, 8-9, 11 (filed 
Apr. 25, 2022); LADWP Comments, Docket No. AD22-5, at 4-5 (filed 
Apr. 25, 2022); R Street Institute Comments, Docket No. AD22-5, at 9 
(filed Apr. 26, 2022); TAPS Comments, Docket No. AD22-5, at 7 (filed 
Apr. 25, 2022); WATT/CEE Comments, Docket No. AD22-5, at 9 (filed 
Apr. 25, 2022).
---------------------------------------------------------------------------

    153. As noted in section III. The Potential Need for Reform above, 
we preliminarily find that existing transmission line ratings and 
transmission line rating methodologies may result in unjust and 
unreasonable wholesale rates that result from inaccurate transmission 
line ratings. In addition to the preliminarily proposed reforms 
described above, we make a concomitant preliminary finding that certain 
transparency reforms are necessary to implement the preliminary 
proposal. In addition to the requests for comments on specific aspects 
of the preliminary proposal, we seek comment on whether the proposed 
data reporting practices related to congestion in non-RTO/ISO regions 
that would identify transmission lines that are candidates for a wind 
requirement and the posting

[[Page 57712]]

of underlying congestion data, as set forth below, would result in just 
and reasonable rates.
i. Potential Reforms to Congestion Data Collection
    154. As preliminarily proposed above in section IV.A.3.b.iii.b.1. 
Limiting Element Rate, transmission providers would be required to 
maintain a database of the following events: (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 (5) redispatch of network integration 
transmission service or secondary network integration transmission 
service under sections 30.5 and 33 of the pro forma OATT. Specifically, 
as preliminarily proposed above, transmission providers would be 
required to record for each event: (1) date/time of the record being 
added to the database; (2) dates and times of the start and end of the 
event; (3) event type; (4) specification of the transmission line with 
a transmission line rating that was the limiting element causing the 
event; and (5) the MWh of transmission service (or potential 
transmission service) that was impacted by the event. We seek comment 
on this preliminary proposal to require transmission providers to 
record this LER metric data, including the changes in data collection 
practices it would cause, and the associated burden. We seek comment on 
whether data identifying limiting transmission lines during all the 
periods of congestion listed above already exist, and whether the above 
descriptions of those events (duration, energy impacted, etc.) are 
being recorded by transmission providers and/or posted in OASIS 
currently. We also seek comment on the challenges in data collection 
practices and associated burden required to record the alternative 
methods to estimate congestion costs in non-RTO/ISO regions and at non-
RTO/ISO seams discussed above in section IV.A.3.b.iii.b.2.i Non-RTO/ISO 
Congestion Costs such as recording redispatch costs caused with a given 
transmission constraint.
    155. As discussed below in section IV.4. Requirements for 
Reflecting Solar and/or Wind in Transmission Line Ratings in RTOs/ISOs, 
we preliminarily propose that RTOs/ISOs would use the LER metric only 
for congestion at their seams, and not on the internal transmission 
lines for which they have explicit congestion data. However, we also 
preliminarily propose to require that transmission providers in RTOs/
ISOs maintain data on annual overall congestion costs caused by binding 
constraints on each transmission line. Finally, we also seek comment on 
whether any changes or additional data requirements would be needed to 
track congestion costs, or causes of congestion costs, in RTO/ISO 
regions.
ii. Posting of Congestion Data
    156. Similar to the Commission's determination in Order No. 881, we 
preliminarily propose to require transmission providers to post on 
OASIS or another website with authentication control including multi-
factor authentication the new congestion databases associated with this 
rulemaking, such as an LER metric database, with a data retention 
requirement of at least five years. We preliminarily find that, without 
further transparency, the Commission and market participants would not 
have the information needed to determine the transmission lines on 
which transmission providers in non-RTO/ISO regions are required to 
implement the wind requirement.
    157. We seek comment on this congestion data transparency proposal, 
including whether the congestion data proposed to be recorded in the 
congestion databases or other elements should be posted on OASIS or 
another website with authentication control including multi-factor 
authentication. We also seek comment on posting on OASIS or another 
website with authentication control including multi-factor 
authentication the data associated with the alternative methods to 
estimate congestion costs in non-RTO/ISO regions and at seams with non-
RTO/ISO regions discussed above in section IV.A.3.b.iii.b.2.i Non-RTO/
ISO Congestion Costs such as recording redispatch costs caused by a 
given transmission constraint. We also seek comment on whether posting 
of additional congestion cost data, beyond the overall congestion costs 
caused by binding constraints on each transmission line, should be 
required in RTO/ISO regions. We seek comment on whether a different 
data posting, access restrictions, and data retention requirement is 
appropriate.
iii. Posting of Transmission Line Ratings Subject to a Wind Requirement
    158. In Order No. 881, the Commission required the maintenance and 
posting of all transmission line ratings in a line rating 
database.\178\ That requirement would apply to any transmission line 
ratings under a potential final rule in this proceeding as well.\179\
---------------------------------------------------------------------------

    \178\ Order No. 881, 177 FERC ] 61,179 at PP 330, 336; see pro 
forma OATT, attach. M (Obligations of Transmission Provider).
    \179\ See pro forma OATT, attach. M, Obligations of Transmission 
Provider; see also Order No. 881, 177 FERC ] 61,179 at PP 330, 336-
340.
---------------------------------------------------------------------------

    159. However, given the unique circumstances surrounding a 
potential wind requirement, including the need to be able to evaluate 
the effectiveness of such a requirement, we preliminarily propose that, 
for transmission lines subject to a wind requirement, the transmission 
provider would be required to post the transmission line ratings for 
each period calculated both with and without the consideration of 
forecasted wind conditions. We preliminarily believe that the posting 
of both transmission line ratings for the periods in which the wind 
requirement applies would provide the transparency necessary to 
evaluate the effectiveness of implementing the wind requirement on each 
transmission line subject to the wind requirement. We seek comment on 
this proposed posting requirement.
4. Requirements for Reflecting Solar and/or Wind in Transmission Line 
Ratings in RTOs/ISOs
    160. In Order No. 881, the Commission required AARs to be used (1) 
in the day-ahead and real-time energy markets, (2) in any reliability 
or intra-day reliability unit commitment processes, and (3) for 
transmission service over RTO/ISO seams.\180\ The Commission declined 
to apply the AAR requirement to the evaluation of internal point-to-
point or through-and-out transactions.\181\ The Commission explained 
that the vast majority of energy transactions in RTOs/ISOs are executed 
and financially settled in the day-ahead and real-time markets, and 
thus requiring AARs to be used for internal point-to-point and through-
and-out transactions would provide very little additional benefits in 
the RTO/ISO markets.\182\
---------------------------------------------------------------------------

    \180\ Order No. 881, 177 FERC ] 61,179 at P 89.
    \181\ Id. P 134.
    \182\ Id.
---------------------------------------------------------------------------

    161. For the solar requirement, which we propose to apply to all 
transmission lines, we preliminarily propose that RTOs/ISOs use 
transmission line ratings that reflect solar heating based on the sun's 
position and forecastable cloud cover in their day-ahead and real-time 
markets as well as for seams transactions that are near-term 
transmission service (i.e., that start and

[[Page 57713]]

stop within the next 10 days). We do not propose to require RTOs/ISOs 
to use such transmission line ratings for internal point-to-point 
transmission service or through-and-out service.
    162. For the wind requirement, which we propose to apply only to 
select transmission lines, we preliminarily propose a different 
approach. Specifically, we preliminarily propose that RTOs/ISOs comply 
with the wind requirement \183\ by using transmission line ratings that 
reflect up-to-date forecasts of wind speed and wind direction: (1) in 
their day-ahead and real-time markets; and (2) for seams transactions, 
internal point-to-point transmission service, and for through-and-out 
service that are 48-hour transmission services (i.e., that start and 
end within 48 hours of the request). We preliminarily propose this 
broader requirement for these transmission lines because we 
preliminarily believe that the additional accuracy of using the 
transmission line ratings that incorporate the wind requirement on 
highly congested transmission lines may justify the burden.
---------------------------------------------------------------------------

    \183\ Transmission lines subject to the wind requirement are 
also subject to the solar requirement, as described above in section 
IV.A.3 Potential Wind Requirement.
---------------------------------------------------------------------------

    163. We seek comment on these preliminary proposals for applying 
the proposed solar and wind requirements to transmission line ratings 
in RTOs/ISOs. In particular, we seek comment on whether RTOs/ISOs 
should instead not be required to apply the wind requirement for 
internal point-to-point and through-and-out transactions, consistent 
with the AAR requirements of Order No. 881 and the instant proposal for 
the potential solar requirement.
5. Implications for Emergency Ratings
    164. In Order No. 881, the Commission required that transmission 
providers use uniquely determined emergency ratings for contingency 
analysis in the operations horizon and in post-contingency simulation 
of constraints. The Commission also required that such emergency 
ratings include separate AAR calculations for each emergency rating 
duration used.\184\
---------------------------------------------------------------------------

    \184\ Id. P 297; pro forma OATT, attach. M, Obligations of 
Transmission Provider.
---------------------------------------------------------------------------

    165. We preliminarily propose to require that all uniquely 
determined emergency ratings used for contingency analysis in the 
operations horizon and in post-contingency simulation of constraints 
must reflect solar heating based on the sun's position and up-to-date 
forecasts of forecastable cloud cover. We preliminarily find that 
applying the solar requirement to both normal and emergency ratings 
will enhance the accuracy of transmission line ratings. We seek comment 
on this proposed approach.
    166. In addition, for transmission lines subject to a wind 
requirement, we preliminarily propose to require that all uniquely 
determined emergency ratings used for contingency analysis in the 
operations horizon and in post-contingency simulation of constraints 
must reflect up-to-date forecasts of wind speed and direction, 
consistent with the wind requirement for normal ratings. We 
preliminarily find that, for transmission lines that will be subject to 
a wind requirement, reflecting wind conditions in both normal and 
emergency ratings will enhance the accuracy of transmission line 
ratings. We seek comment on this proposed approach.
6. Confidence Levels
    167. In statistical forecasting, ``quantile forecasting'' is the 
practice of forecasting upper or lower limits of a particular future 
observation.\185\ Quantile forecasting is the type of forecasting 
typically involved with determining transmission line ratings: 
forecasters seek to predict the extreme values (upper or lower, 
depending on the variable) of weather variables that serve as inputs 
into transmission line rating calculations, and to calculate 
sufficiently conservative transmission line ratings from those 
forecasts. In quantile forecasting, a ``confidence level'' reflects how 
much certainty forecasters have that a particular observation will not 
exceed their forecast when the observation is repeated many times. For 
example, if each day a meteorologist publishes a forecast of next-day 
high temperatures, and the method for producing such forecast is 
designed to meet a 98% confidence level, then over time the 
corresponding observed high temperatures should be less than or equal 
to such forecasts 98% of the time.
---------------------------------------------------------------------------

    \185\ See, e.g., Electric Power Systems: Advanced Forecasting 
Techniques and Optimal Generation Scheduling, section 5 at 20 
(Jo[atilde]o P.S. Catal[atilde]o ed., 2017).
---------------------------------------------------------------------------

    168. We understand that line ratings always have an associated 
confidence level. Because such confidence levels are typically 
relatively high, such as 98%, in most instances the forecasted 
transmission line ratings are conservative, such that the observed 
weather (when that forecasted hour becomes the operating hour) is 
within the range predicted by the forecast. However, infrequently, as 
the forecast for a given hour is updated it could cause a transmission 
provider to have to manage (through curtailments or other actions) a 
reduction in transmission capability from what had been previously 
forecasted.
    169. The Commission's outreach and research indicate that it is 
commonplace for DLRs to be calculated to a default confidence of 98%. 
We preliminarily believe that there may be some benefit to having a 
default confidence level for calculations of transmission line ratings 
subject to the solar and/or wind requirement across regions: first, to 
discourage the use of overly conservative confidence levels, which will 
erode the benefits of using weather forecasts; \186\ and second, to 
ensure that sharply differing practices do not produce sharply 
different transmission line ratings.
---------------------------------------------------------------------------

    \186\ In Order No. 881 the Commission acknowledged that 
``transmission line ratings using unreasonably high forecast margins 
would also yield inaccurate transmission line ratings and, in turn, 
would result in an underutilization of existing transmission 
facilities, price signals based on less transfer capability than is 
truly available, and wholesale rates that are unjust and 
unreasonable.'' Order No. 881, 177 FERC ] 61,179 at P 52.
---------------------------------------------------------------------------

    170. Given the importance of confidence levels to transmission line 
ratings accuracy and reliability, we seek comment on whether the 
Commission should establish a default confidence level transmission 
providers are required to use when calculating transmission line 
ratings subject to the solar and/or wind requirement, unless they 
document a particular reason for needing and using a different 
confidence level. If so, we seek comment on what such a default 
confidence level should be, and how the use of confidence levels 
different from the default should be documented by transmission 
providers to justify such deviations.
    171. If such a default confidence level were adopted, we 
preliminarily propose that it apply not to the underlying weather 
forecasts (wind speed, wind direction, ambient air temperature, solar 
heating, etc.) individually, but instead to the forecast of the 
transmission line rating overall. We preliminarily believe that 
applying the default confidence level to the underlying weather 
forecasts would result in a confidence level for the overall forecasted 
transmission line rating that is less than the default level. We seek 
comment on this proposal to apply any default confidence level to 
overall transmission line rating forecasts. We seek comment on what 
confidence levels are currently typically applied to different types of 
transmission line ratings.

[[Page 57714]]

B. Compliance and Transition and Implementation Timelines

1. Pro Forma OATT Revisions and Implementation
    172. We preliminarily propose to promulgate these potential reforms 
through revisions to the pro forma OATT, which is applicable to all 
transmission providers. We seek comment on this proposal including 
whether such requirements should be reflected in Attachment M of the 
pro forma OATT or elsewhere. Commenters are invited to propose pro 
forma OATT language, including proposed revisions to existing pro forma 
OATT language, and to explain why such language would be appropriate.
    173. While the requirements we preliminarily propose here would be 
imposed on transmission providers, we recognize as we did in Order No. 
881 that transmission owners determine transmission line ratings.\187\ 
In many instances, particularly outside of RTOs/ISOs, the transmission 
provider and transmission owner are the same entity. However, within 
RTOs/ISOs and in limited other instances, the transmission provider and 
transmission owner are separate entities. For such instances, we 
preliminarily propose that the limit for how many transmission lines 
must apply the wind requirement, for any transmission lines that meet 
the thresholds, (i.e., the proposed 0.25% of the total number of the 
transmission providers' transmission lines for the initial period) 
apply to each individual transmission owner and not to the transmission 
provider on an RTO-wide basis.\188\ We also preliminarily propose that 
transmission owners will determine transmission line ratings for all of 
their transmission lines. We also propose to require transmission 
owners to provide their transmission line ratings and transmission line 
rating methodology to the transmission provider. We seek comment on 
this aspect of the preliminary proposal, including which 
responsibilities would or should be carried out by transmission 
providers and transmission owners, whether such roles and 
responsibilities should be set forth in pro forma OATT provisions or 
left to RTO/ISO compliance proceedings, and how transmission providers 
should ensure that transmission owners appropriately perform their 
responsibilities.
---------------------------------------------------------------------------

    \187\ See Order No. 881, 177 FERC ] 61,179 at P 140; see also 
id. P 300 (requiring transmission providers, where the transmission 
provider is not the transmission owner, to include in its compliance 
filing and implementation of pro forma Attachment M, that the 
transmission owner has the obligation for making and communicating 
to the transmission provider the timely calculations and 
determinations related to emergency ratings).
    \188\ For example, if an RTO has four transmission owners, each 
with 1,600 transmission lines, each transmission owner would be 
required to implement DLRs on at least four transmission lines per 
year (provided that at least that many transmission lines meet the 
criteria discussed above). The potential requirement would not be 
implemented by the RTO transmission provider on 16 transmission 
lines on an RTO-wide basis.
---------------------------------------------------------------------------

2. Implementation Timeframe for the Solar Requirement
    174. Recognizing that the proposed solar requirement may not 
require installing sensors, we preliminarily propose that this 
requirement be met no more than twelve months after any final rule is 
published in the Federal Register. We seek comment on the timeframe 
necessary to implement the proposed solar requirement. We seek comment 
on whether the clear-sky component and cloud cover component of a 
proposed solar requirement should have different implementation 
deadlines.
3. Phased-In Implementation Timeframe for the Wind Requirement
a. Annual Wind Requirement Implementation Cycles
    175. We preliminarily propose to require transmission providers to 
undertake an annual wind requirement implementation cycle. Starting 
with the effective date of any potential final rule, transmission 
providers would gather congestion data for each transmission line for 
one year, as described above in section IV.A.3.b.iii. Congestion 
Threshold, and determine during that year which of their transmission 
lines meet the wind speed threshold, as described above in section 
IV.A.3.b.ii. Wind Speed Threshold. Finally, for any transmission lines 
that meet the determined wind speed and congestion thresholds, 
transmission providers would have six months to implement the necessary 
systems, based on the minimum implementation requirement as described 
above in section IV.A.3.b.i. Number of Transmission Lines Subject to 
the Wind Requirement Annually, to implement the wind requirement. This 
proposal aims to provide ample time for transmission providers to use 
congestion data that reflect implementation of AARs as required by 
Order No. 881, while also ensuring that a wind requirement is applied 
to transmission lines that would benefit from a wind requirement within 
a reasonable timeframe. We seek comment on this proposed approach. We 
specifically seek comment on the duration of the data collection 
period, and implementation period. While we believe one year of 
congestion data will be sufficient for the first implementation cycle, 
we seek comment on whether this is the appropriate time period for data 
collection and whether the Commission should mandate a different 
timeframe for subsequent cycles (e.g., for cycle two, whether 
transmission providers should consider two years of congestion data). 
We also seek comment on whether the Commission should set a limit on 
the vintage of the congestion data (i.e., whether congestion data from 
five years ago is stale and no longer relevant). We also seek comment 
on how this approach should change if the Commission does not require 
sensors for the wind requirement.
    176. Most commenters argue that the Commission should not require 
implementation of any DLR requirements until after transmission 
providers have implemented AARs in July 2025 and gained experience with 
the use of AARs.\189\ While not explicitly tied to Order No. 881, the 
preliminary proposal, if adopted in a final rule, is intended to 
reflect the importance of having adequate data for the purpose of 
identifying transmission lines where the wind requirement would be 
implemented, particularly in light of the likely changing congestion 
patterns after the implementation of Order No. 881. The Commission 
seeks comment on when implementation of the proposal should commence.
---------------------------------------------------------------------------

    \189\ AEP Reply Comments, Docket No. AD22-5, at 4-5 (filed May 
25, 2022); APPA/LPPC Comments, Docket No. AD22-5, at 12-13 (filed 
Apr. 25, 2022); APS Comments, Docket No. AD22-5, at 14 (filed Apr. 
25, 2022); CAISO Comments, Docket No. AD22-5, at 2 (filed Apr. 25, 
2022); EEI Comments, Docket No. AD22-5, at 33 (filed Apr. 25, 2022); 
ELCON Comments, Docket No. AD22-5, at 12 (filed Apr. 25, 2022); ISO-
NE Comments, Docket No. AD22-5, at 5-6 (filed Apr. 25, 2022); ITC 
Comments, Docket No. AD22-5, at 15 (filed Apr. 25, 2022); MISO 
Comments, Docket No. AD22-5, at 8 (filed Apr. 25, 2022); NYISO 
Comments, Docket No. AD22-5, at 1-2 (filed Apr. 25, 2022); Potomac 
Economics Comments, Docket No. AD22-5, at 3 (filed Apr. 26, 2022); 
Southern Company Comments, Docket No. AD22-5, at 11 (filed Apr. 25, 
2022); Tri-State Comments, Docket No. AD22-5, at 4 (filed Apr. 25, 
2022).
---------------------------------------------------------------------------

    177. We seek comment on the preliminary proposal to use an annual 
implementation cycle. We also seek comment on whether the proposed 
annual implementation period would accurately identify transmission 
lines for implementation of the wind requirement or if the Commission 
should require (or allow, if preferred) a lower frequency (such as 
every two to three years) of cycles and higher lines-per-cycle limit 
for the wind requirement cycle.

[[Page 57715]]

b. Transmission Provider Compliance Requirement
    178. As described above in section IV.A.3.b.i. Number of 
Transmission Lines Subject to the Wind Requirement Annually, we 
preliminarily propose that transmission providers be required to 
implement the wind requirement on the whole number greater than 0.25% 
(or 1 in 400) of the transmission provider's transmission lines in each 
annual implementation cycle. As described above, transmission providers 
would be required to implement the wind requirement only on 
transmission lines that meet the congestion threshold and wind speed 
threshold.
    179. We preliminarily propose to require transmission providers to 
implement the wind requirement on candidate transmission lines starting 
with the most highly congested transmission line (based on the 
congestion metric value, as discussed above) and moving on to the next 
most highly congested transmission line, and so on. This process would 
continue until either the yearly implementation requirement is met or 
there are no more candidate transmission lines waiting for 
implementation of the wind requirement.
c. Compliance for Transmission Providers That Are Subsidiaries of the 
Same Public Utility Holding Company
    180. Transmission providers (or transmission owners in cases where 
the transmission owners and transmission provider are not the same 
entity) that are operating company subsidiaries of the same public 
utility holding company may operate their transmission facilities as a 
single transmission system. We seek comment on whether such 
transmission systems should be counted together for purposes of the 
transmission providers' compliance with any wind requirement, such as 
for counting the transmission providers' total number of transmission 
lines and for determining the number of transmission lines that would 
be included in the transmission providers' implementation cycle. This 
may result in implementation of the wind requirement being distributed 
unevenly across transmission providers that are operating company 
subsidiaries of the same public utility holding company. We seek 
comment on whether transmission providers in such situations, or the 
RTOs/ISOs of which they are members, should propose on compliance how 
they would treat such transmission providers and transmission systems.

V. Comment Procedures

    181. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this ANOPR to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due October 15, 2024 and Reply 
Comments are due November 12, 2024. Comments must refer to Docket No. 
RM24-6-000, and must include the commenter's name, the organization 
they represent, if applicable, and their address in their comments. All 
comments will be placed in the Commission's public files and may be 
viewed, printed, or downloaded remotely as described in the Document 
Availability section below. Commenters on this proposal are not 
required to serve copies of their comments on other commenters.
    182. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's website at https://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software must be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    183. Commenters that are not able to file comments electronically 
may file an original of their comment by USPS mail or by courier-or 
other delivery services. For submission sent via USPS only, filings 
should be mailed to: Federal Energy Regulatory Commission, Office of 
the Secretary, 888 First Street NE, Washington, DC 20426. Submission of 
filings other than by USPS should be delivered to: Federal Energy 
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.

VI. Document Availability

    184. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
internet through the Commission's Home Page (https://www.ferc.gov).
    185. From the Commission's Home Page on the internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    186. User assistance is available for eLibrary and the Commission's 
website during normal business hours from the Commission's Online 
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202)502-8659. Email the Public Reference Room at 
[email protected].

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By direction of the Commission. Commissioner Rosner is not 
participating.

    Issued: June 27, 2024.
Debbie-Anne A. Reese,
Acting Secretary.

    Note:  The following appendix will not appear in the Code of 
Federal Regulations.

Appendix A: List of Short Names/Acronyms of Commenters in Docket No. 
AD22-5



------------------------------------------------------------------------
      Short name/acronym                        Commenter
------------------------------------------------------------------------
AEP...........................  American Electric Power Company, Inc.
APPA/LPPC.....................  American Public Power Association (APPA)
                                 and the Large Public Power Council
                                 (LPPC).
APS...........................  Arizona Public Service Company.
BPA...........................  Bonneville Power Administration. The BPA
                                 Comments were filed as appendix B to
                                 the DOE Comments and were not submitted
                                 as a separate filing. Pagination cited
                                 in the ANOPR is internal to the BPA
                                 Comments.
CAISO.........................  California Independent System Operator
                                 Corporation.
Certain TDUs..................  Certain Transmission Dependent Utilities
                                 consist of: Alliant Energy Corporate
                                 Services, Inc. (Alliant Energy),
                                 Consumers Energy Company (Consumers
                                 Energy), and DTE Electric Company (DTE
                                 Electric).
Clean Energy Parties..........  Natural Resources Defense Council,
                                 Sustainable FERC Project, Southern
                                 Environmental Law Center, Western
                                 Resource Advocates, Conservation Law
                                 Foundation, RMI, and Fresh Energy.
DC Energy.....................  DC Energy, LLC.
DOE...........................  United States Department of Energy.

[[Page 57716]]

 
EEI...........................  Edison Electric Institute.
EGM...........................  Electrical Grid Monitoring.
ELCON.........................  Electricity Consumers Resource Council.
Entergy.......................  Entergy Services, LLC.
Idaho Power...................  Idaho Power Company.
ISO-NE........................  ISO New England Inc.
ITC...........................  International Transmission Company d/b/a
                                 ITC Transmission, Michigan Electric
                                 Transmission Company, LLC, ITC Midwest
                                 LLC, and ITC Great Plains, LLC.
LADWP.........................  Los Angeles Department of Water and
                                 Power.
LineVision....................  LineVision, Inc.
MISO..........................  Midcontinent Independent System
                                 Operator, Inc.
NERC..........................  North American Electric Reliability
                                 Corporation.
NRECA.........................  National Rural Electric Cooperative
                                 Association.
NYISO.........................  New York Independent System Operator,
                                 Inc.
NYTOs.........................  The New York Transmission Owners consist
                                 of: Central Hudson Gas & Electric
                                 Corporation; Consolidated Edison
                                 Company of New York, Inc.; Niagara
                                 Mohawk Power Corporation d/b/a National
                                 Grid; New York Power Authority; New
                                 York State Electric & Gas Corporation;
                                 Orange and Rockland Utilities, Inc.;
                                 Long Island Power Authority; and
                                 Rochester Gas and Electric Corporation.
OMS...........................  Organization of MISO States.
Potomac Economics.............  Potomac Economics, Ltd.
PPL...........................  PPL Electric Utilities Corporation.
R Street Institute............  R Street Institute.
Southern Company..............  Southern Company Services, Inc. acting
                                 as agent for Alabama Power Company,
                                 Georgia Power Company, and Mississippi
                                 Power Company.
TAPS..........................  Transmission Access Policy Study Group.
Tri-State.....................  Tri-State Generation and Transmission
                                 Association, Inc.
TS Conductor..................  TS Conductor Corporation.
WATT/CEE......................  Working for Advanced Transmission
                                 Technologies (WATT) and Clean Energy
                                 Entities (CEE), which consist of
                                 American Clean Power Association,
                                 Advanced Energy Economy, and the Solar
                                 Energy Industries Association.
------------------------------------------------------------------------

[FR Doc. 2024-14666 Filed 7-12-24; 8:45 am]
BILLING CODE 6717-01-P

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