Managing Transmission 

Line Ratings

A STAFF PAPER:

FEDERAL ENERGY REGULATORY 

COMMISSION

AUGUST 2019

DOCKET NO. AD19-15-000

For further information, please contact:

Dillon Kolkmann

Office of Energy Policy and Innovation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502‐8650

Dillon.Kolkmann@ferc.gov

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Contents

EXECUTIVE SUMMARY.................................................................................... 1

1. BACKGROUND ........................................................................................... 4

A. TRANSMISSION LINE RATING BASICS .......................................................... 4

B. COMMON APPROACHES TO TRANSMISSION LINE RATINGS ......................... 5

i. Static Ratings............................................................................................... 6

ii. Seasonal Ratings ...................................................................................... 7

iii. Ambient-Adjusted Ratings (AARs)............................................................ 7

iv. Dynamic Line Ratings (DLRs) ................................................................. 7

C. DYNAMIC LINE RATINGS TECHNOLOGY CONSIDERATIONS......................... 8

i. Line identification and sensor installation .................................................. 8

ii. Data communication and analytics.......................................................... 9

iii. Computing and forecasting .................................................................... 10

iv. Validation ............................................................................................... 10

2. LINE RATING APPROACHES IN RTOS/ISOS.................................... 11

A. USE OF SEASONAL LINE RATINGS IN RTOS/ISOS ..................................... 12

B. USE OF AARS IN PJM AND ERCOT........................................................... 12

C. USE OF STATIC RATINGS IN LONG TERM PLANNING ................................. 13

3. DYNAMIC LINE RATING PILOT PROJECTS.................................... 14

4. ANALYSIS................................................................................................... 17

A. EVALUATION OF DYNAMIC LINE RATINGS AND AMBIENT-ADJUSTED 

RATINGS............................................................................................................... 17

i. Benefits....................................................................................................... 17

ii. Challenges.............................................................................................. 21

B. DISCUSSION ON POTENTIAL IMPROVEMENTS TO MANAGING 

TRANSMISSION LINE RATINGS............................................................................. 26

i. Implementing AARs.................................................................................... 27

ii. Integrating DLRs into EMS.................................................................... 27

iii. Study of the most congested transmission lines ..................................... 28

iv. Transparency of transmission line rating methodologies...................... 28

The opinions and views expressed in this FERC staff paper do not necessarily 

represent those of the Federal Energy Regulatory Commission, its Chairman, or 

individual Commissioners, and are not binding on the Commission.

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Executive Summary

Transmission line ratings are used by reliability coordinators, transmission system

operators, planning authorities, and transmission planners in reliability models and 

market models to ensure that flows on transmission lines do not increase risks of 

reliability events or damage to lines or equipment. The transmission line ratings directly 

affect flows on electric power systems, and thus affect the price of electric power and the 

reliability of the electric grid. These ratings are determined by transmission owners. It 

appears that transmission owners sometimes set these ratings with few or no updates to 

reflect changes in ambient conditions, and with limited transparency into both the 

methodology and resulting rating. Improving the methods for determining thermal 

transmission line ratings could reduce costs, increase efficiency, and provide reliability 

benefits. This paper reviews various transmission line rating practices. These practices 

along with potential improvements to managing transmission line ratings will be

discussed at the upcoming FERC staff-led technical conference to be held in September

2019 in Washington, DC. There will also be an opportunity to file post-technical 

conference comments in this docket, Managing Transmission Line Ratings, Docket No. 

AD19-15-000. 

This paper draws on staff outreach, which included discussions with regional 

transmission organizations/independent system operators (RTOs/ISOs), transmission 

owners, and trade groups, as well as staff participation in a November 2017 Idaho 

National Laboratory workshop. During outreach, FERC staff reviewed existing and 

advanced approaches to transmission line ratings and discussed the potential adoption of 

advanced approaches, and more efficient and reliable use of transmission assets. 

This paper focuses on transmission line ratings that are based on the thermal limits

of transmission lines to assure that lines do not overheat. In determining thermal limits, 

engineers balance environmental and physical design factors that contribute to line 

heating and cooling, in order to prevent the line from overheating. Overheating can 

damage a line or cause it to sag and create reliability and/or public safety concerns. 

There is a spectrum of approaches to line ratings, across which the approaches are more 

responsive or less responsive to changes in the relevant ambient weather conditions that 

underpin the ratings. On the least dynamic end of the spectrum, “static line ratings” are 

derived using conservative assumptions for ambient weather conditions. On the most 

dynamic end of the spectrum, “dynamic line ratings” (DLRs) account for real-time

ambient conditions such as air temperature, wind conditions, and solar irradiance

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intensity, among other things, and update ratings frequently (e.g., hourly or every 15 

minutes).

Today, most RTOs/ISOs implement either static line ratings or “seasonal line 

ratings,” as provided by transmission owners for use in reliability planning, operations 

and market models.1 On the less dynamic end of the spectrum, seasonal line ratings are 

similar to static line ratings, but transmission owners determine different line ratings for 

different seasons (typically winter and summer), based on worst case assumptions for 

each season. Using a more dynamic approach, the Electric Reliability Council of Texas 

(ERCOT) and PJM implement “ambient-adjusted ratings” (AARs) which adjust 

frequently based on local ambient air temperatures.

2

 Non-RTO/ISO transmission owners 

generally implement seasonal line ratings.

Aside from these standard practices, there have been several pilot projects to test 

the development and potential application of DLRs. For the most part, these DLRs have 

not been deployed in real-time system or market operations.3

Drawing on the outreach discussed above, this staff paper:

1) Discusses and evaluates the spectrum of transmission line rating methodologies;

2) Describes current RTO/ISO practices; 

 

1 The seven RTOs/ISOs in the United States are all registered by the North 

American Electric Reliability Corporation (NERC) as balancing authorities, reliability 

coordinators, planning authorities/coordinators and transmission service providers. All of 

these registered functions use transmission line ratings for their respective reliability 

models. The six FERC-jurisdictional RTOs/ISOs under sections 205 and 215 of the 

Federal Power Act are: California Independent System Operator Corporation (CAISO), 

ISO New England Inc. (ISO-NE), Midcontinent Independent System Operator, Inc. 

(MISO), New York Independent System Operator, Inc. (NYISO), PJM Interconnection, 

L.L.C. (PJM), Southwest Power Pool, Inc. (SPP). 

2 MISO and SPP also can accommodate ambient-adjusted ratings in their real-time 

models.

3 Researching projects involving dynamic line ratings is not a new concept. These 

activities date back decades.

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3) Highlights some prominent advanced transmission rating pilot projects; and

4) Presents potential improvements to managing transmission line ratings for 

discussion at the FERC staff-led technical conference. These are:

a. Whether to require all transmission owners to implement AARs on their

lines;

b. Whether to require all RTOs/ISOs to implement software and 

communications capabilities and standards to allow transmission owners to 

flow DLR data directly into the RTO/ISO’s energy management systems 

(EMS);

c. Whether transmission owners should study their most congested 

transmission lines to assess whether DLRs would be cost effective; and

d. Whether to make line rating methodologies more transparent.

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1. Background

In spring 2019, a FERC staff team conducted outreach to all FERC-jurisdictional 

RTOs/ISOs, ERCOT,

4

seven transmission owners, Potomac Economics (the market 

monitor for MISO, NYISO, ISO-NE and ERCOT), and Working for Advanced 

Transmission Technologies (WATT, a trade group representing manufacturers of 

advanced transmission technologies). In addition, staff attended and presented at a 

November 2017 technical workshop on DLRs at the Idaho National Laboratory.

This paper draws on this outreach to examine approaches to transmission line 

rating and to present possible policy options to facilitate the adoption of more advanced 

line rating methodologies in order to reduce costs and achieve increased efficiency in the 

use of transmission assets without undermining reliability.

5

 Increased efficiency can 

result in important economic benefits, such as lower costs, as well as reliability and 

operational benefits. More advanced line rating methodologies, however, also present 

challenges relating to DLR sensor management, forecasting, rating coordination, and 

reliability, among other things.

A.Transmission Line Rating Basics

Transmission line ratings are used by reliability coordinators, transmission system

operators, planning authorities, and transmission planners in reliability models and 

market models to ensure that flows on transmission lines do not increase risks of 

reliability events or damage to lines or equipment.

6

 They can be expressed in terms of 

either electrical current (measured in units of amps (A)) or power-carrying capacity 

 

4 ERCOT is jurisdictional under section 215 of the Federal Power Act.

5 While this paper draws on FERC staff outreach, the views expressed may not 

necessarily reflect the positions of the outreach entities. Any errors in the representation 

of outreach entities’ positions are unintentional.

6 Some entities in this list of transmission line rating users have overlapping roles. 

For example, an RTO/ISO is transmission system operator and a transmission system 

operator may also be a NERC reliability coordinator. 

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(measured in units of megawatts (MW) or megavolt-amps (MVA)). In this paper, a

transmission line rating respects the most limiting applicable equipment rating of the 

individual equipment associated with the line,7and is based on the thermal limit.

8

 

The electric current flowing through a transmission line heats the line due to the 

line’s electrical resistance. Other conditions and phenomena can also tend to heat 

transmission lines, particularly solar irradiance. Conversely, some conditions and 

phenomena tend to cool transmission lines, particularly convective cooling from wind.

Thermal transmission line ratings are generally negatively correlated to ambient 

temperature and solar irradiance intensity, but positively correlated with wind speeds. 

Conductor temperatures further depend upon conductor material properties, conductor 

diameters, and conductor surface conditions. Engineers consider these environmental 

and physical design factors when establishing thermal limits of transmission lines.

B. Common Approaches to Transmission Line Ratings

To ensure that transmission line ratings used in the reliable planning and operation 

of the bulk electric system (BES) are determined based on technically-sound principles, 

the North American Electric Reliability Corporation (NERC) Reliability Standard FAC008-3 requires each transmission owner to have a documented methodology for 

determining transmission line ratings. The standard affords flexibility on underlying 

methodologies and assumptions, including how changing ambient conditions are used. In 

practice, rating methodologies have evolved along a spectrum from fully static ratings 

with no change in ambient condition assumptions for thermal limits on conductors (or 

sometimes based on “nameplate ratings” for limiting transmission equipment) to nearly 

 

7 Specifically, the NERC Glossary of Terms Used in Reliability Standards (NERC 

Glossary) includes a transmission line in its definition for a facility (“A set of electrical 

equipment that operates as a single Bulk Electric System Element (e.g., a line, a 

generator, a shunt compensator, transformer, etc.)”) and defines a facility rating as: “The 

maximum or minimum voltage, current, frequency, or real or reactive power flow 

through a facility that does not violate the applicable equipment rating of any equipment 

comprising the facility.”

8 Staff note that transmission lines can be limited by their thermal rating, a voltage 

limit, or a stability limit. The advanced line rating approaches discussed in this paper 

would directly affect only lines that are limited by a thermal rating.

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“real-time” ratings where ambient condition assumptions are updated every hour or 

multiple times an hour. Figure 1 shows this spectrum of line rating practices:

During industry outreach, staff observed that the terms “AAR” and “DLR” were 

not well defined and not always used in a consistent manner. For the purposes of this 

paper and subsequent discussions in this docket, FERC staff uses the terms “static line 

ratings,” “seasonal line ratings,” AARs, and DLRs in specific ways as defined below.

In each type of transmission line rating, ratings may depend on the limitations of 

individual segments of the transmission line. And the limits on the individual line 

segments may depend on different ambient condition assumptions.

i. Static Ratings

Static ratings are the least dynamic rating methodology, and are intended to reflect 

ratings under the worst case ambient condition assumptions. Often, static ratings reflect a

manufacturer’s equipment “nameplate rating” reflecting such worst-case assumptions. 

Static ratings are only updated when equipment is changed or ambient condition 

assumptions are updated. Thus, static ratings may remain unchanged for years or 

decades, or may never change at all during the lifetime of a transmission line. While the 

assumptions used to inform static transmission line ratings vary by transmission owner, 

one outreach participant, for example, indicated that its static ratings assumed an ambient 

air temperature of 40 degrees Celsius (104 degrees Fahrenheit), wind speeds and 

direction of 2 feet per second at a 90-degree wind-conductor angle, and clear atmospheric

with noontime sun intensity. 

Less Dynamic More Dynamic

Seasonal line

rating

Static line 

rating

Ambient-adjusted

rating (AAR)

Dynamic line

rating (DLR)

Figure 1: Common line rating methodologies on the spectrum from least 

dynamic to most dynamic

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ii. Seasonal Ratings

Seasonal ratings are similar to static ratings but use a different set of ambient 

condition assumptions for summer and winter. Summer ratings are commonly used from

May through October, and winter ratings are commonly used from November through 

April. Seasonal ratings are the most commonly used ratings. Summer transmission line 

ratings use conservative ambient temperature assumptions, and are often based on 95 or 

100 degrees Fahrenheit. Winter ratings are often based on 32 degrees Fahrenheit.

iii. Ambient-Adjusted Ratings (AARs)

AAR transmission line ratings are more dynamic than static and seasonal ratings, 

and their rating values change on a more frequent basis (e.g., daily, hourly, or every 15 

minutes). 

Ambient air temperature forecasting is critical to the use of AARs. Some 

transmission owners or AAR/DLR vendors perform temperature forecasting using 

relevant ambient air temperature data from online weather monitoring services (such as 

the National Oceanic and Atmospheric Administration (NOAA)), and then use those

temperature forecasts to calculate updated line ratings. In ERCOT and PJM, AARs are 

implemented using step functions where AAR line ratings exist for 5-degree temperature 

blocks (5 degrees Fahrenheit for ERCOT and 5 degrees Celsius for PJM).

iv. Dynamic Line Ratings (DLRs)

Presently, DLRs are the most dynamic line rating methodology incorporating 

ambient conditions such as local weather conditions, solar irradiance, and/or line tension, 

photo-spatial sensors (e.g., LIDAR), and/or line sensors installed on or close to the 

monitored line.

9

 DLR weather sensors can measure weather parameters such as ambient 

temperature, precipitation, wind speed/direction, and solar irradiance intensity. DLR 

photo-spatial sensors or line sensors may measure conductor parameters such as 

temperature, tension, and conductor clearance. DLR determined ratings can be updated 

frequently depending on the characteristics of the DLR monitoring equipment.

 

9 LIDAR, or Light Detection and Ranging, is a commonly used surveying 

technique to measure distance to a target by illuminating the target with a laser and using 

a sensor to measure reflected light. 

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As with AARs, weather forecasting over a reasonable period of time (e.g., one 

hour or 15 minutes) is important with DLR systems to allow transmission operators to 

more efficiently and reliably operate their systems. When employing DLRs, automatic 

processing of sensor data translates monitored data into updated line ratings.

C. Dynamic Line Ratings Technology Considerations

The previous section provided introductory information on transmission line rating

methodologies. As background, this section presents a snapshot of important technical 

information about how some transmission owners and RTOs/ISOs implement DLRs. 

This section also discusses some of the key technical challenges related to implementing 

DLRs, but which are not necessarily relevant to implementing AARs. 

The Institute of Electrical and Electronics Engineers (IEEE) and the Council on 

Large Electric Systems (CIGRE) standards establish the accepted methods for calculating 

the thermal behavior of transmission lines based on the conductor properties and weather 

conditions.

10 Based on these standards, modern technologies work in a coordinated

manner to calculate and update transmission line ratings in real-time, and to communicate 

these updates to transmission system operators. These technologies include remote 

sensing, measurement, communication, data analytics, high-performance computing 

(including cloud computing), networking, and automation (including artificial 

intelligence). Implementing a DLR system requires the following steps: line 

identification; sensor installation; data communication; data analytics; computing and 

temperature forecasting; and, finally, validation. These implementation steps are 

discussed in greater detail below.

i. Line identification and sensor installation

As a first implementation step, transmission owners and/or RTOs/ISOs identify 

the transmission lines on which DLRs would be cost-effective. Use of DLRs is typically 

 

10 See IEEE Standard 738-2012, “IEEE Standard for Calculating the CurrentTemperature Relationship of Bare Overhead Conductors,” 2012 (IEEE 738); and CIGRÉ 

Technical Brochure 207, “Thermal Behavior of Overhead Conductors, Working Group 

22.12,” 2002(CIGRÉ 207).

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cost-effective on a subset of a transmission owner’s transmission lines. Transmission 

lines that are not sufficiently congested, such that they do not sufficiently limit desired 

market activity, may not benefit from DLRs. Similarly, transmission systems that are 

constrained by voltage, stability, or substation limitations may not benefit from DLRs. In 

addition to identifying the transmission lines that will benefit from DLRs, the 

transmission owners must identify which specific line spans need to be monitored, and 

whether ground-based or line-based sensors should be used, as discussed further below in

Section 4.B.ii.

Both ground-based and line-based sensor approaches to DLRs have their 

advantages and disadvantages. Line-based conductor measurements provide more direct 

and accurate data on line conditions than measurement of ambient weather conditions.

However, line-based measurements have limits to how they can be extrapolated to yield 

reliable information on non-monitored line segments. Also, line-based sensors may 

require transmission line outages to install and maintain. Ground-based sensors can be 

easier to install and maintain, but are more vulnerable to physical tampering.

ii. Data communication and analytics

Once sensors are operational, as a next implementation step, their data are 

typically collected at a data concentrator and/or managed by a Supervisory Control and 

Data Acquisition (SCADA) system or EMS. Measurement data or information is 

commonly collected from individual sensors or sensor stations using a cellular network, 

but satellite, microwave, or radio networks are also possible. The choice of 

communication medium and methods depends on location, amount of data, and required 

data transmission rate. Also, DLR system reliability, physical and cyber security features 

are important factors in complying with NERC Reliability Standards to ensure the 

availability, integrity, and confidentiality of DLR systems and data. Relevant Reliability 

Standards include the following:

 FAC-008-3, Facility Ratings, Requirements R7 and R8;

11

 

11 On June 7, 2019, in Docket RM19-7-000 (pending), NERC filed a petition to 

retire certain requirements of various reliability standards, including Requirements R7 

and R8 of Reliability Standard FAC-008-3, which require transmission and generator 

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 CIP-002-5.1a, Cyber Security – BES Cyber System Categorization;

 CIP-006-6, Cyber Security – Physical Security of BES Cyber Systems;

 CIP-012-1, Cyber Security – Communications between Control Centers;12 and

 CIP-014-1, Physical Security.

iii. Computing and forecasting

After the relevant data is collected, it is processed and translated (according to the 

technical standards discussed above) into a line current-carrying capacity in amps (A), 

which is further used to determine the transmission line’s power-carrying capacity in

MW. As mentioned earlier, forecasting of the relevant weather conditions and line 

ratings over some operationally useful period (e.g., one hour or fifteen minutes) is 

necessary for DLR implementation. 

iv. Validation

The final implementation step is validation. Rating validation should detect data 

anomalies, possibly utilizing sensitivities that can limit the change in weather data 

parameters that in turn can change transmission line ratings, and automatically integrate 

DLRs into the control room SCADA, EMS, and/or security constrained economic 

dispatch (SCED) engine.13 This step ensures confidence in the resulting transmission line 

ratings.

 

owners to provide facility ratings to reliability coordinators, transmission system 

operators and other entities upon request.

12 On April 18, 2019, in Docket No. RM18-20-000 (pending), the Commission 

issued a notice of proposed rulemaking to approve CIP-012-1 (CybersecurityCommunications between Control Centers) and to direct NERC to develop certain 

modifications to require protections regarding the availability of communication links 

and data communicated between bulk electric system control centers and, further, to 

clarify the types of data that must be protected.

13 While exact SCED definitions vary, one representative definition is “an 

algorithm capable of clearing, dispatching, and pricing Energy, Operating Reserve, Up 

Ramp Capability, and Down Ramp Capability in a simultaneously co-optimized basis 

that minimizes Production Costs and Operating Reserve Costs while enforcing multiple 

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During outreach, multiple parties indicated that reliability and operational 

complexity concerns have hampered DLR (and AAR) adoption. Specifically, they 

expressed concern that inaccurate or unreliable line ratings could be communicated 

directly to transmission system operators, who would then be burdened with determining 

whether to rely upon the ratings. However, line rating and human factors engineering 

experts that FERC staff spoke to during outreach argued that proper implementation can 

address this concern. The human factors engineering experts contended that all data and 

rating validation must be complete before a transmission system operator ever sees a 

DLR or AAR rating, allowing the operator to have confidence in the accuracy of 

DLR/AAR ratings. Engineers should ensure that the rating is appropriate for the current 

operational horizon so that the transmission system operator does not have to secondguess the rating. In this way, the human factors engineering experts asserted, a 

transmission system operator’s use of DLRs or AARs should be similar to the use of 

static ratings.

One difference between DLRs/AARs and static ratings, however, is that the DLRs 

and AARs change across their forecasting periods. As such, transmission system 

operators may need access to the future period’s rating forecasts, and/or be notified by 

EMS if significant rating changes will take place.

2.Line Rating Approaches in RTOs/ISOs

Transmission owners in RTOs/ISOs use either seasonal ratings or AARs to 

calculate thermal transmission line ratings. In CAISO, ISO-NE, MISO, NYISO, and 

SPP, seasonal ratings are the norm.

14

 In ERCOT and PJM, AARs are used. 

 

security constraints. The algorithm keeps the commitment of Resources fixed in the 

dispatch. The model is described in Schedule 29.” MISO Open Access Transmission 

Tariff, Module A. 

14 MISO and SPP also can accommodate ambient-adjusted ratings in their realtime models, but our understanding is that few participants currently use this 

functionality.

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A.Use of Seasonal Line Ratings in RTOs/ISOs

Five RTOs/ISOs – CAISO, ISO-NE, MISO, NYISO and SPP – predominantly use 

seasonal line ratings, but with important regional differences. Some RTOs/ISOs tend to 

be more deferential to transmission owner-developed line ratings than others. Certain 

RTOs/ISOs indicated that some transmission owners provide seasonal ratings in which

winter line ratings equal summer ratings. Partially at the request of their transmission 

owners, both MISO and SPP have updated their EMS to automatically accept frequently 

changing line ratings. In MISO and SPP, transmission owners can automatically update 

transmission line ratings hourly in the real-time reliability and market models in addition 

to updates to current day and day-ahead transmission line ratings.

Several of the RTOs/ISOs indicated that they used a process whereby the 

RTO/ISO, on an ad hoc basis, could request real-time transmission line rating “uprates” 

which, if available, could be granted by the transmission owner based on differences 

between actual ambient air temperatures and seasonal line rating assumptions. They 

indicated that such practices are used to manage conditions such as outages, congestion, 

or possible reliability events. Frequency and timing of usage varies by RTO/ISO. One 

RTO/ISO described uprates occurring only on congested lines in the summer. Uprates 

may be limited to the real-time reliability and market models or specific load pockets, 

depending on the RTO/ISO. 

B.Use of AARs in PJM and ERCOT

PJM and ERCOT rate transmission lines using AAR methodologies with regional 

variations. Both PJM and ERCOT use temperature-rating step functions to rate 

transmission facilities. In the real-time market, using transmission owner-submitted 

temperature-based line ratings, a PJM computer program selects transmission line ratings 

based on temperature readings taken from local weather stations for 5 degree Celsius (9

degree Fahrenheit) temperature increments from zero to 40 degree Celsius (32 to 104

degree Fahrenheit). In the PJM day-ahead market, transmission line ratings are 

determined from forecasted ambient air temperatures specific to each zone in its dayahead studies.

ERCOT has a similar practice, in which real-time transmission line ratings are 

automatically updated based on temperature fluctuations according to temperature tables 

provided by each transmission owner and which reside within the ERCOT network 

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model.15 ERCOT temperature tables are stepwise functions for each 5 degree Fahrenheit

(2.8 degree Celsius) increment between 20 and 115 degree Fahrenheit (approx. −7 to 46

degree Celsius). Similar to PJM, for the day-ahead market, ERCOT obtains forecasted 

temperatures for the next operating day, and uses transmission owner’s temperature 

tables to obtain line ratings for its day-ahead studies.

C.Use of Static Ratings in Long Term Planning

Each RTO/ISO conducts long term transmission planning using seasonal static 

ratings. None of the RTOs/ISOs consider using DLRs or AARs as an alternative to 

building physical transmission.16 Outreach consensus suggests that both transmission 

owners the RTOs/ISOs consider it important to plan transmission for summer and winter 

peak loading conditions while using seasonal static ratings and believe that neither DLRs 

nor AARs can substitute for building and repairing transmission lines. While Order No. 

890-A held (and Order No. 1000 reiterated) the transmission planning process is 

generally required to have comparable treatment for advanced technologies,17 neither 

order provided specific guidance on how advanced technologies should be considered. 

While some outreach participants acknowledged that the use of DLRs could replace some 

economic projects (i.e., projects designed to reduce congestion costs rather than to 

address a reliability need), these participants reiterated the need to plan for the worst case

conditions when planning transmission because worst case conditions do materialize. 

 

15 ERCOT Nodal Protocols. Section 3.10.8 Dynamic Ratings. February 7, 2018, 

available at http://www.ercot.com/mktrules/nprotocols/current.

16 This is also the norm outside of RTO/ISOs.

17 See Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890 at P 494, 118 FERC ¶ 61,119, order on reh’g, Order No. 890-A, 121 

FERC ¶ 61,297, at P 215-16 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 

61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on 

clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009); Transmission Planning and 

Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 

FERC Stats. & Regs. ¶ 31,323, at P 315 (2011), order on reh’g, Order No. 1000-A, 139 

FERC ¶ 61,132, order on reh’g and clarification, Order No. 1000-B, 141 FERC ¶ 61,044 

(2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014). 

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3.Dynamic Line Rating Pilot Projects

Most of the seven transmission owners with whom FERC staff spoke indicated 

that they had some experience using dynamic line ratings in research projects. However, 

transmission owners typically test DLRs on only a few transmission lines, do not 

incorporate DLRs into RTO/ISO markets, and do not publicize the test results widely.

Some prominent DLR pilots have been undertaken in ERCOT, NYISO, and PJM.

Two of the better documented and publicized DLR pilot projects were undertaken 

by the ERCOT transmission owner, transmission operator, transmission planner and 

distribution provider ONCOR, and by the NYISO generator owner, generator operator, 

transmission planner and transmission owner New York Power Authority (NYPA), both 

funded through grants under the Department of Energy’s Smart Grid Demonstration 

Program. The NYPA project partnered with the Electric Power Research Institute (EPRI) 

to install EPRI sensor technology designed to measure conductor temperature, weather 

conditions, and conductor sag on three 230 kilovolt (kV) transmission lines. NYPA’s 

goal was to test a variety of prototype technologies; demonstrate the viability for use in 

system engineering, operations, and planning; and demonstrate a correlation between 

increased dynamic ratings and increased wind generation. The results of the NYPA pilot 

were calculations of DLRs, on average, in excess of 30 to 44 percent above static 

ratings.18

Partnering with the cable and transmission line manufacturer Nexans, ONCOR 

tested conductor tension-monitor technology along with conductor sag and clearance 

monitors on eight transmission circuits (138 kV and 345 kV). Similar to NYPA, 

ONCOR’s goals were to test the commercial viability of DLR technology. But ONCOR

also incorporated DLRs into real-time operations and developed a DLRs best practice 

guide. ONCOR succeeded in incorporating DLRs directly into ERCOT’s EMS. 

ONCOR’s project also identified the potential for DLRs to integrate wind resources,

 

18 Wang, Warren and Pinter, Sarah. Dynamic Line Rating Systems for 

Transmission Lines. April 25, 2014 p. 36, available at 

https://www.smartgrid.gov/files/SGDP_Transmission_DLR_Topical_Report_04-25-

14_FINAL.pdf.

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observing a relative increase in wind generation at the same times when DLR systems 

increased study lines’ transmission capacities. Lastly, ONCOR calculated DLRs of, on 

average, 30 to 70 percent greater than static line ratings. Relative to ERCOT’s normal 

AARs, however, ONCOR observed real-time rating increases between only 6 and 14 

percent on average (when excluding data anomalies, outage periods, and periods when 

the DLR may have been lower than AARs).

19

In PJM, DLR pilot studies were conducted on the 345 kV Cook-Olive 

transmission line and on a second target transmission line.20 In the first phase of DLR 

testing, LineVision, AEP, and PJM installed LineVision-designed ground-based sensors 

to measure power flow, conductor position/sag, and weather conditions in order to 

calculate DLRs along AEP’s Cook-Olive transmission line. The results of this first phase

indicated that Cook-Olive’s DLRs were significantly greater than static ratings.21

In phase two, LineVision, AEP, and PJM attempted to quantify the financial 

impact of DLRs. To do this, LineVision, AEP, and PJM identified a target transmission 

line similar to Cook-Olive, and which had already demonstrated DLR viability. The 

target line was chosen because both it and Cook-Olive are high voltage transmission lines 

of similar length (18 and 22 miles respectively), both are heavily congested, and both 

have a straight transmission path, making DLR implementation easier.22

 

19 Id. at 59.

20 The Cook-Olive transmission line is located in the AEP footprint spanning 

southwest Michigan to northern Indiana. 

21 Marmillo, J, Mehraban, B, Murphy, S, and Pinney, N. A Non-Contact Sensing 

Approach for the Measurement of Overhead Conductor Parameters and Dynamic Line 

Ratings. CIGRE US National Committee 2017 Grid of the Future Symposium, 

Cleveland, OH, available at 

https://watttransmission.files.wordpress.com/2017/11/genscape-cigre-gotf-whitepaper2017.pdf. 

22 Straight transmission paths can make DLR implementation easier by increasing 

the consistency of the speed and direction at which the wind contacts a transmission line, 

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16

Absent installing DLR sensors in phase two, LineVision, AEP, and PJM

extrapolated DLRs for the target line using weather data from NOAA at urban-center and 

airport-based meteorological stations. To quantify the benefits, the study conducted an 

analysis comparing a study year 2018 with static ratings to simulated market results using 

DLRs on the target line. The analysis results demonstrated approximately $10.4 million 

in annual congestion savings along the target line, but also found increased downstream 

congestion on several nearby 230 kV lines, resulting in approximately $4 million in 

annual net congestion savings. PJM explained that the analysis was not able to respect 

other possibly limiting constraints, such as voltage constraints or substation-based 

constraints. PJM indicated that a key drawback to its study is that the 2018 target line’s

limiting element was often set by substation equipment, not line limits.

23 (For more 

information on challenges created by other limiting elements see Section 4.A.ii.c).)

Other examples FERC staff encountered of transmission owners or RTOs/ISOs 

implementing pilots or test DLRs indicated that these entities considered testing DLRs as 

a means to mitigate the effects of transmission outages by increasing transmission line 

limits. Separate entities described different DLR pilots implemented to improve 

transmission access to a load pocket, to provide additional bridge transmission capacity 

as transmission was built or rebuilt, and, one in the late 1990s, to alleviate congestion as 

transmission upgrades were being built.

 

thus minimizing differing rating patterns across a transmission line. Straight transmission 

paths can also make radio transmission of data easier, when relevant. 

23 Dumitriu, N, Marmillo, J, Mehraban, B, Murphy, S, and Pinney, N. Simulating 

the Economic Impact of a Dynamic Line Rating Project in a Regional Transmission 

Operator (RTO) Environment. CIGRE US National Committee 2018 Grid of the Future 

Symposium, Reston, VA, available at 

https://cdn2.hubspot.net/hubfs/4412998/CIGRE%20GOTF%202018%20NGN%20-

%20PJM%20AEP%20LineVision%20-%20Final.pdf?t=1540927429509.

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4.Analysis

A.Evaluation of Dynamic Line Ratings and AmbientAdjusted Ratings

As a general matter, the more dynamic a transmission line rating, the more 

accurate the line capacity and potential benefits, as well as challenges are expected from 

its implementation. Outreach indicates that while the benefits of DLRs may be greater 

than the benefits of AARs, the use of DLRs has greater challenges and costs. As 

discussed below, some of the benefits and challenges accrue to both DLRs and AARs, 

and some only to DLRs. 

i. Benefits

a) Economic Benefits

Rating transmission lines more dynamically allows for adjusting line limits of 

those lines, which have the potential to increase transmission system efficiency; reduce 

production costs, congestion costs, curtailments, and reserve requirements; and help 

manage system disturbances. Both DLRs and AARs tend to provide more accurate line 

limits. Particularly in the summer season, this greater accuracy tends to raise 

transmission line ratings, which has the potential to increase system efficiency.24 For 

example, in MISO, Potomac Economics found that the potential savings as a result of 

AARs reducing congestion costs would have been $165 million in 2015, $155 million in 

2016, and $127 million in 2017.25 Similarly, increasing transmission flows into load 

pockets can improve access for low cost generation, reduce curtailments, and may reduce 

 

24 Staff notes, however, increased accuracy may not result in increased line ratings. 

Particularly during the winter season, when real-time ambient air temperatures may be 

greater than the static winter temperature assumption, line capacities under DLRs or 

AARs may decrease from their seasonal ratings.

25 Potomac Economics. 2017 State of the Market Report for the MISO Electricity 

Markets. June 2018. p. 83-84. 

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reserve requirements. Lastly, in the event of a generation or transmission outage, both 

DLRs and AARs may help mitigate the resulting congestion impacts.26

DLRs and AARs can potentially defer capital costs by improving utilization of 

existing assets. Outreach participants indicated that, because transmission upgrades can 

be difficult to build, DLRs are an important bridge source of transmission capacity in the 

interim between the identification of need and project completion. Deferred capital costs 

can be a benefit of AARs, but to a lesser degree.

DLRs (but not AARs) may also be particularly beneficial for transmission owners 

integrating wind generation. When wind speed increases, this increases output from wind 

generators. However, the increase in wind speed also lowers the temperature of the 

transmission line which, under a DLR, would increase the rating of the line. This benefit 

was demonstrated by the NYPA and ONCOR pilot projects discussed above. 

Recognizing this correlation between wind production and lower transmission line 

temperatures, at least one transmission owner suggested that a wind generator could 

utilize DLRs to cost-effectively reduce the size of its interconnection facility. They

explained that interconnection studies typically use static line rating assumptions that 

often have wind speed assumptions that are lower than is needed to power a wind turbine. 

They suggested that, by conducting wind generator interconnection studies using higher 

wind speed assumptions, it may be possible to increase wind power deliverability 

assumptions and lower interconnection costs for wind generators, at least in some 

circumstances.

27

 

26 An important caveat repeatedly mentioned during outreach, however, was the 

applicability of DLRs to older transmission lines. Outreach participants explained that 

many of the most congested lines are older lines. Applying DLRs to such lines may have 

short-term value, but such lines may be reaching the end of their useful life. In such 

instances, it may be more cost-efficient to simply repair and/or rebuild the line. 

However, repaired or rebuilt lines tend to not be congested. Even so, there may be value 

to applying DLRs as a bridge to manage a transmission line while repairs occur.

27 Interconnection facilities are defined using the same definition as FERC Order 

No. 2003, which explained that “Interconnection Facilities are found between the 

Interconnection Customer's Generating Facility and the Transmission Provider's 

Transmission System...Network Upgrades include only facilities at or beyond the point 

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Some outreach participants, however, expressed skepticism regarding the 

possibility of using DLRs to reduce interconnection costs for wind generation. The 

interconnection process currently utilizes static line rating assumptions to determine 

interconnection cost responsibilities. Transmission owners and RTOs/ISOs stress the 

need to plan for worst case conditions. Outreach also indicates that wind developers 

and/or their financing partners may be reluctant to make major generation investments 

without building the full interconnection capacity to deliver the generation’s total output 

to the system.

b) Reliability/Operational Benefits

DLRs and AARs can also provide reliability benefits by helping to avoid and/or 

relieve transmission overloads without the need to re-dispatch, curtail transmission 

service, shed load or reconfigure the system.

DLRs (but not AARs) can provide transmission owners more information about 

the status of a transmission line. By using actual, real-time inputs, DLRs provide 

reliability benefits by reflecting the actual current-carrying capabilities of the conductor

which may, at times, be less than a static rating would have allowed. Outreach 

highlighted the ability of DLR systems to inform transmission owners and RTOs/ISOs of 

the small percentage of instances in which static ratings exceeded a DLR, and in which

there may be a heightened risk of either a reliability event or damage to either 

transmission lines or equipment. During outreach, one outreach participant estimated 

that these instances where static ratings exceed DLRs could be up to five percent of 

intervals, while data from LineVision presented at the 2017 Idaho National Laboratory’s 

 

where the Interconnection Customer's Generating Facility interconnects to the 

Transmission Provider's Transmission System.” See Standardization of Generator 

Interconnection Agreements and Procedures, Order No. 2003, 104 FERC ¶ 61,103, at P 

21 (2003), order on reh’g, Order No. 2003-A, 106 FERC ¶ 61,220, order on reh’g, Order 

No. 2003-B, 109 FERC ¶ 61,287 (2004), order on reh’g, Order No. 2003-C, 111 FERC ¶ 

61,401 (2005), aff'd sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 

F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008).

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2017 DLR workshop estimated that such instances constituted about three percent of 

intervals, as shown in Figure 2.

Figure 2. Indicative Transmission Line Rating Static and Dynamic Line 

Rating Duration Curve28

The additional information about a transmission line provided by DLRs can also 

increase situational awareness, helping an RTO/ISO or transmission owner to monitor the 

condition/health of a line in real-time. For example, in addition to informing an 

RTO/ISO or transmission owner of instances in which the actual current-carrying 

capabilities of the conductor is less than a static rating, such information gained through 

increased situational awareness can allow an RTO/ISO or transmission owner to detect 

dangerous instances of transmission icing and conductor galloping.29 

 

28 Marmillo, Jonathan (2017, November). Genscape LineVision. Vision for 

Integration into Overall Asset Management Strategy, Idaho National Laboratory 2017 

Dynamic Line Ratings Workshop, Idaho Falls, Idaho. p. 8, available at 

https://renewableenergy.inl.gov/Conventional%20Renewable%20Energy/2017%20DLR

%20Workshop/DLR%202017%20Presentations/11.8%20Vision%20for%20Integration%

20(Genscape)_Marmillo.pdf (used by permission).

29 Conductor galloping is a low-frequency physical oscillation of power lines 

caused by wind. Galloping can lead to increases in stress on insulators and transmission 

structures, increasing the risk of line or structure failure, or shortening equipment life. 

Galloping can also affect line clearances, raising the risk of electrical faults. Some types 

of DLR sensors can detect and/or monitor lines for galloping. 

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c) Open Access Benefits

DLRs and AARs can also provide open access benefits, such as reducing the 

likelihood of ad hoc transmission uprates, and thereby helping to ensure equal access to 

the transmission system via markets on a comparable basis.

30

 Current releases of 

additional transfer capability may lack the transparency that should be afforded to all 

transmission customers. Upon RTO/ISO request, typically during periods of tight 

operations, transmission owners periodically provide transmission uprates, temporarily 

increasing transmission line limits. Generally, these transmission uprates help reliability. 

Making these increases part of normal operations through the adoption of DLRs or AARs

on a transparent basis may help reduce the frequency of ad hoc transmission uprates. 

While transmission uprates may frequently make available transmission capability in 

real-time that was not reasonably foreseeable in advance, adoption of DLRs or AARs 

could help ensure that all market participants are able to access the transmission system 

on a comparable basis. 

ii. Challenges 

Many of the challenges to advanced line rating methodology implementation are 

unique to DLRs. Challenges unique to DLR implementation relate to sensor placement, 

sensor maintenance, and physical and cyber risks, as well as its tendency to cause line 

rating fluctuations. By contrast, both DLRs and AARs face challenges related to 

automation, coordination with other transmission owners, market coordination, limiting 

elements, and reliability.

 

30 See Promoting Wholesale Competition Through Open Access NonDiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by 

Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 

(1996) (cross-referenced at 77 FERC ¶ 61,080), order on reh’g, Order No. 888-A, FERC 

Stats. & Regs. ¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220), order on reh’g, Order 

No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 

61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group 

v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 

(2002).

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a) DLR Sensors

The most obvious challenges applicable only to DLRs are the placement and 

maintenance of DLR sensors. First, sensor placement is a challenge because more 

sensors are needed the longer a line is. But while placing more sensors at limiting 

elements ensures more geographically-granular data to calculate line ratings at more line 

spans, it costs more. While placing fewer sensors costs less, it requires the extrapolation 

of data using complicated software and analysis to predict weather conditions, which can 

be difficult or impractical. Extrapolating line conditions on monitored line spans to other 

spans, particularly over varied terrain, can be difficult. Moreover, the more turns in a 

transmission path and/or the more diverse the terrain a transmission line traverses, the 

greater the number of sensors required and the more difficult it is to use one sensor to 

extrapolate over multiple spans. Consequently, sensor placement challenges are often 

more acute both with Midwestern utilities that tend to have longer transmission lines and 

with utilities located in hilly, mountainous, or generally varied terrain.

Sensor maintenance can also be challenging. Repairs to DLR sensors often 

require a specially trained technician. If a sensor is placed on a line, repairs may require 

coordination between the transmission owner and a repair technician. Repairing linebased sensors may also require a line to be taken out of service, which could necessitate 

coordination between the transmission owner and the RTO/ISO. Further, ground-based 

sensors can be susceptible to physical tampering that could either take them out of service 

or create false data readings. Lastly, when transmitting DLR sensor data, there may be 

potential cyber security risks.

b) Forecasting Challenges

Both DLRs and AARs require weather forecasting to be successfully 

implemented. But because DLRs can be particularly sensitive to both wind speeds and 

direction, forecasts for DLRs can be more difficult to produce. Swirling winds and 

changing wind speeds can cause significant rating fluctuations that would be difficult for 

transmission system operators to implement if such ratings were sent in raw form. In the 

presence of hard-to-forecast wind conditions, DLR line rating forecasts may need to 

assume that wind cooling cannot be relied upon. Under such assumptions, DLRs may 

provide little benefit beyond what could be obtained with the simpler AARs.

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c) Limiting Elements 

 

Physical limitations, other than those related to the transmission line conductor,

can reduce the benefits of DLRs and AARs. Because overall transmission line ratings 

must be set by the most limiting element for each transmission line, substation equipment

(e.g., breaker, wave trap, or switch) limits could be a limiting element for a line 

regardless of the effect of AARs or DLRs. For example, many wind generating facilities

are located at the top of hills and are connected by transmission lines running through 

valleys. DLR implementation (but not AAR) would have to account for differing wind 

conditions across the terrain, only increasing a transmission rating by the most limiting 

wind condition, likely at the floor of a valley. Additionally, transmission owners 

explained that many wind facilities, particularly in the Midwest, tend to be interconnected 

via long transmission lines. Longer AC transmission lines tend to be voltage constrained, 

not thermally constrained.

d) Automation and Data Coordination

Implementation of both DLRs and AARs requires automation and data 

coordination. DLRs require at least automatic weather and/or line measurements, and 

communication of that data to a transmission operator control center where that data is

used to calculate a rating forecast. AARs are typically derived by obtaining their ambient 

air temperature data from NOAA or similar weather services, so measurement and data 

communication are less of an issue. But under AARs, online data must still be 

downloaded and used to calculate a rating forecast. As an example of the interaction 

between data availability and AAR implementation, outreach indicated that the five week

U.S. Government shut-down of 2018-2019 resulted in limited data availability from 

NOAA, which affected AAR implementation.

After collecting and communicating data and using that data to calculate updated 

DLRs or AARs, several additional automation and data coordination challenges remain.

Calculated transmission line ratings must be automatically checked before being 

transmitted to the RTO/ISO or transmission operator control center. Finally, the

transmission line ratings are input to a SCED and/or EMS, ideally automatically. 

Most RTOs/ISOs indicated that automation of this kind is possible. However, due 

to the additional costs and technological requirements, the amount of automation and 

database management needed may be difficult for some non-RTO/ISO transmission 

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owners to implement. Further, outreach indicated that this level of constant automation 

and data coordination also creates a database management challenge.

e) Market Alignment 

Some outreach participants expressed concern with using line ratings other than 

static or seasonal ratings in the day-ahead market. They explained that if AAR or DLR 

ratings were used in the day-ahead market, and weather was warmer than expected, the 

anticipated transmission capacity may not materialize in real-time, while load would 

simultaneously be higher than expected, causing reliability concerns. However, in such 

instances, not implementing either AARs or DLRs in both the real-time and day-ahead 

market might result in misalignments between day-ahead and real-time markets, creating 

inefficiencies. Other outreach participants indicated that an appropriately conservative 

implementation of AARs and/or DLRs could be made in the day-ahead timeframe in a 

way that would help align the day-ahead and real-time markets, while still maintaining 

reliability.

The use of AARs or DLRs in real-time and day-ahead markets could also result in 

coordination challenges with the financial transmission rights (FTR) market.31 Static line 

ratings are typically used to determine the amount of transmission capacity available for 

auction in FTR and related auctions in RTOs/ISOs. The exception appears to be ERCOT, 

which conducts a historical analysis of the maximum peak-hour temperatures for the 

previous 10 years, for each month, to determine the amount of transmission capacity 

available for auction in FTR auctions. In the two markets (ERCOT and PJM) that 

 

31 While exact FTR definitions vary, one representative definition is “a financial 

instrument that entitles the holder to receive compensation for or requires the holder to 

pay certain congestion related transmission charges that arise when the Transmission 

System is congested and differences in Marginal Congestion Components of Day-Ahead 

Ex Post LMPs result.” MISO Open Access Transmission Tariff, Module A. FTRs go by 

different names in different RTOs/ISOs. PJM, MISO and ISO-NE use the term FTR. 

However, CAISO uses the term Congestion Revenue Right (CRR). NYISO uses the term 

Transmission Congestion Contract (TCC). SPP uses the term Transmission Congestion 

Right (TCR). For simplicity, this paper uses the term FTR to refer to the relevant product 

in all these markets interchangeably.

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presently use AARs during operations, the use of AARs is transparent to market 

participants, and informs all market participants of where congestion is anticipated so that 

this information can be factored into FTR bids submitted by market participants.

32

 

f) Coordination between Transmission Owners

DLR or AAR implementation may lead to coordination challenges, if not all 

transmission owners implement the same transmission rating methodology. For example, 

for power that flows over multiple owners’ transmission lines, if only one of those 

transmission owners is updating their transmission ratings using either AARs or DLRs, 

then transmission flows may be limited by the transmission owners that do not implement 

AARs or DLRs. 

g) Reliability Margins

Some outreach parties indicated that implementing either DLRs or AARs may 

create reliability challenges by reducing their reliability margins. Specifically, a 

reliability margin can be thought of as the difference between the true thermal

transmission line limit, calculated by accurately incorporating all relevant line rating 

inputs, and the transmission line limit currently implemented. When transmission owners

implement DLRs or AARs, they typically understand that, for most hours of the year,

their transmission lines in fact will have more capacity than their static or seasonal 

ratings. However, because transmission owners rate transmission lines, and because 

there is not currently a mechanism for a third party (except, in some circumstances, for an 

RTO/ISO) to request to use uprated transmission capacity, currently only transmission 

owners may know about or be able to use this additional capacity.

 

While some argue that implementing AARs or DLRs may create reliability 

challenges, AARs and DLRs tend to also provide more accurate line ratings. Particularly 

in the winter season, AAR and DLR implementation could result in less transmission line 

 

32 PJM publishes Transmission Owner Guidelines. According to the introduction, 

“they are intended to provide common PJM Transmission Provider connection 

requirement criteria concerning design philosophy, design requirements and operating 

practices for interconnecting Generation Facilities, Transmission Facilities, and End-User 

Facilities”, available at https://www.pjm.com/planning/design-engineering/maac-toguidelines.aspx.

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capacity for those hours during the year when DLRs and AARs are less than current 

static or seasonal ratings. In response to questions about AAR and DLR reliability 

challenges, some outreach participants indicated their view that reliability reserve margin 

capacity should be reserved to accommodate unexpected events to ensure reliability of 

the electrical grid. However, FERC staff believes that reserve margins should not be 

dependent on capacity that may or may not be available depending on ambient 

conditions. AAR and DLR implementation may reduce transmission capability margins. 

However, on balance, the more accurate winter ratings, reducing transmission line 

capacity for those hours during the year when DLRs and AARs are less than current 

static or seasonal ratings, may appropriately counterbalance the loss of transmission 

capability margins, while ensuring reserve margins are accurately calculated.

B. Discussion on Potential Improvements to Managing 

Transmission Line Ratings

In light of FERC staff’s outreach and research, staff sets forth four ideas to

improve methods for determining transmission line ratings, including making the 

information about the line ratings more transparent to all users of the transmission 

system. These options will be used to guide further discussion about transmission line 

rating practices at the September 2019 technical conference. FERC staff expects that 

these improvements could reduce costs, increase efficiency, and provide reliability 

benefits without compromising reliability of the transmission system. In addition to the 

benefits and challenges discussed earlier, FERC staff anticipates learning from 

stakeholders more about current transmission line rating practices, the benefits and 

challenges of these and other practices, and about possible ways to incent increased DLR 

implementation.

33

 

 

33 In its recent inquiry regarding the Commission’s electric transmission incentives 

policy, the Commission sought and received comment on over one hundred questions. 

Topics on which the Commission sought comment included whether the costs of dynamic 

line ratings should be considered for inclusion in rate base as a regulatory asset, and 

whether and how flexible transmission characteristics, such as increased line rating 

precision and greater power flow control, should be incentivized. Inquiry Regarding the 

Commission's Electric Transmission Incentives Policy, 166 FERC ¶ 61,208 (2019).

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i. Implementing AARs

As one option, transmission owners could adopt AARs, under which a 

transmission owner would adjust transmission line ratings based on ambient air 

temperatures. Such an approach could realize the benefits of more accurate line ratings 

without the costs and complexities of implementing DLR technologies. In particular, 

AARs have the potential to reduce congestion, improve planned outage coordination, and 

provide reliability benefits. At the same time, AARs do not implicate challenges that 

apply to DLR implementation such as sensor placement, sensor maintenance, and 

physical risks. Further, as noted above, several transmission owners actively 

implementing AARs said they see little net benefits to DLR implementation above those 

already provided by AAR implementation on their specific transmission lines. 

Under this option, an RTO/ISO could use AARs in operations planning 

(transmission line outage scheduling) and directly in its security-constrained economic 

dispatch process to dispatch resources and calculate market prices. AARs could be 

applied to all transmission lines or a subset of transmission lines. Staff understands, for 

instance, that transmission owners in PJM and ERCOT typically apply AARs to all of 

their transmission lines. However, it may be reasonable to apply AARs only to congested 

transmission lines, or at least to exclude some transmission lines that are expected to 

never be congested, even under unexpected circumstances. 

Transmission owners in bilateral markets could incorporate AARs into the ATC 

calculations for the appropriate point-to-point transmission service (expected to be daily 

and hourly point-to-point transmission service). To the extent practical, the application to 

ATC calculations may help increase the frequency that real-time weather related 

transmission uprates are also made available to third parties on a consistent basis. 

ii. Integrating DLRs into EMS

Under this option, an RTO/ISO would implement software and communication 

changes to allow transmission owners to flow DLR data directly into the RTO/ISOs’ 

EMSs. While, on a generic basis, an AAR approach to transmission line ratings may be 

most appropriate, the information obtained during FERC staff outreach suggests that 

there may be specific transmission lines on which the costs and complexities of DLRs are 

in fact outweighed by the benefits. This option would require RTOs/ISOs to adopt

minimum software and communication capabilities and standards (data formats, internet

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protocols, cyber security requirements, etc.) necessary to ensure transmission owners are 

able to flow DLR data directly into the RTO/ISO’s EMS. Outreach indicates that these 

minimum capabilities and standards already exist in some RTOs/ISOs. Requiring 

RTOs/ISOs to adopt minimum capabilities and standards to accept DLRs into their EMS 

would remove barriers to entry for DLR technology. Absent these minimum capabilities 

and standards, the implementation of DLRs by transmission owners in RTOs/ISOs would 

be of limited value as the more dynamic ratings may not be incorporated into RTO/ISO 

markets. 

iii. Study of the most congested transmission lines

To help highlight some locations where DLR implementation might be costeffective, transmission owners could perform studies of the cost-effectiveness of 

implementing DLRs on the most congested transmission lines. Under such an option, 

FERC staff initially suggest that transmission owners identify the most congested 

transmission lines based on cost of congestion (rather than MWh or hours of congestion). 

These and many other details would need to be discussed and developed. Among such 

details is whether the transmission owner is the best entity to perform such studies, or 

whether another entity such as an RTO/ISO or an independent evaluator might be better 

placed to conduct such studies. 

iv. Transparency of transmission line rating methodologies

Finally, some outreach participants commented that line rating methodologies are 

opaque, particularly in systems where transmission charges are increasing rapidly. These 

participants stated that they have had little success obtaining information on how 

transmission line ratings are set, what assumptions the ratings are based on, or how often 

such ratings and assumptions are updated. With this concern in mind, it might be 

necessary to make the basic details of line rating methodologies transparent, for instance, 

by either publicly posting or incorporating them into both RTO/ISO and TO tariffs.

34

 

 

34 Staff notes that NERC reliability standard FAC-008-3 R8 requires transmission 

owners to make their transmission rating methodologies available upon request, but such 

requests can only be made by reliability coordinators, planning coordinators, transmission 

Planners, Transmission Owners and Transmission Operators. However, such requests 

ensure that the transmission line rating methodologies remain non-public. Moreover, on 

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June 7, 2019, FAC-008-3’s R8 was proposed to be removed in Docket No. RM19-7-000. 

This would remove the possibility of even non-public requests for transmission line 

rating methodologies. 

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Managing Transmission Line Ratings_Public Paper.DOCX..................1-31

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