2019 Staff Report

2019 FERC and NERC Staff Report

The South Central 

United States

 Cold Weather Bulk 

Electric System 

Event of January 17, 2018 

FERC and NERC Staff Report

July 2019 
*NASA Worldview Snapshot satellite image of The United States showing weather pattern for January 17, 2018.
The South Central United States 

Cold Weather Bulk Electric System 

Event of January 17, 2018

FERC and NERC Staff Report July 2019

This report was prepared by the staff of the Federal Energy Regulatory

Commission in consultation with staff from the North American Electric

Reliability Corporation and its Regional Entities.

This report does not necessarily reflect the views of the Commission.

The South Central United States 

Cold Weather Bulk Electric System 

Event of January 17, 2018

FERC and NERC Staff Report July 2019

This report was prepared by the staff of the Federal Energy Regulatory

Commission in consultation with staff from the North American Electric

Reliability Corporation and its Regional Entities.

This report does not necessarily reflect the views of the Commission.
Page 2 of 153

Table Of Contents 

I. EXECUTIVE SUMMARY.................................................................................... 6

II. BACKGROUND ................................................................................................... 14

A. Affected System Overview ........................................................................ 14

B. MISO Regional Directional Transfer and Related

Agreements ................................................................................................. 17

III. REVIEW OF ENTITIES’ PREPARATIONS FOR WINTER 2017/2018 ...... 19

A. Entities’ Preparations for Winter 2017-2018 Operations ..................... 19

1. Projected Resource Adequacy for Winter 2017-2018 ...................... 19

2. Seasonal Transmission Assessments for Winter 2017-2018 ............ 22

3. 2017-2018 Winterization Readiness Preparation ............................. 24

a) Reliability Coordinators and Balancing Authorities...................................... .............24

b) Generator Owner/Operators............................................................................. ............28

IV. NEAR-TERM FORECASTS AND PREPARATIONS FOR THE WEEK OF

JANUARY 15 ........................................................................................................ 31

A. Short Range Weather and Load Forecasts ............................................. 31

1. Impending Weather Conditions ......................................................... 31

2. Mid- and Short-Term Load Forecasts ............................................... 31

B. Generation Unavailable for the Entire Event ......................................... 33

C. Changes/Adjustments Made by RCs Due to Impending

Conditions Forecast ................................................................................... 36

1. Pre-real-time Resource Commitment Process .................................. 36

2. Next-Day Operational Planning Analysis (OPA) of

Transmission Conditions (Performed on January 16, 2018 for

the January 17 Operating Day) .......................................................... 38

3. Alerts Issued Before January 17 ........................................................ 39
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V. JANUARY 17, 2018 EVENT: ADDITIONAL GENERATION OUTAGES, 

EXTREME BELOW-NORMAL COLD WEATHER CONDITIONS, AND 

WIDE-AREA CONSTRAINED TRANSMISSION SYSTEM CONDITIONS

................................................................................................................................ 40

A. Extreme Weather and Record Peak Loads............................................. 40

B. Growing BES Problems Due to Generation Outages and 

Derates........................................................................................................ 43

1. By 2 a.m. CST: BES Transmission Conditions Become a 

Growing Concern................................................................................. 48

2. By 6 a.m. CST: BES Energy Emergency and Wide-Area 

Constrained Transmission Conditions .............................................. 52

3. By 8 a.m. CST: MISO Energy Emergency Continues and 

Four RCs Take More Consequential Steps to Maintain BES 

Reliability.............................................................................................. 64

4. Post-8 a.m.-peak hour: Conditions Gradually Improve .................. 72

VI. POST-EVENT ACTIONS BY THE RCS AND JOINT PARTIES................. 75

VII. PRIOR SIMILAR EVENTS................................................................................ 78

VIII. FINDINGS AND RECOMMENDATIONS....................................................... 80

APPENDICES................................................................................................................103

 

 
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Acknowledgement

This report 0F

1 results from the combined efforts of many dedicated individuals in 

multiple organizations. The team behind the report (the Team) consisted of individuals 

from the Federal Energy Regulatory Commission (FERC or the Commission), the North 

American Electric Reliability Corporation (NERC), Regional Reliability Entities 

Midwest Reliability Organization (MRO), SERC Corporation (SERC), ReliabilityFirst 

Corporation (RF), and Western Electricity Coordinating Council (WECC),1 F

2 all of whom

are named in Appendix A. They were assisted by other non-Team members within their 

respective organizations. The inquiry which led to the report arose out of two 

presentations describing the January, 2018 event to FERC Staff: one by Midcontinent 

Independent System Operator, Inc. (MISO), and the other a combined presentation by 

Southwest Power Pool, Inc. (SPP), Tennessee Valley Authority (TVA), and the 

Southeastern Reliability Coordinator (SeRC)/Southern Company (SoCo), as well as other 

Joint Parties to a settlement between MISO and SPP, namely Associated Electric 

Cooperative, Inc. (AECI), Louisville Gas and Electric/Kentucky Utilities (LG&E/KU), 

 1 This report is written for a reader who is already familiar with principles of 

energy markets, transmission system operations and generation unit operations. For 

readers who are not as familiar, the Team has provided a variety of appendices which 

may be helpful. See, e.g., Appendix B, Primer on Electric Markets and Reliable 

Operations of the Bulk Electric System (BES)(begins at page 104), Appendix C, 

Reliability Coordinator and Transmission Operator Tools and Actions to Operate the 

BES (begins at page 109), Appendix D, Glossary of Terms Used in the Report (begins at 

page 114), Appendix E, Categories of NERC Registered Entities (begins at page 123), 

and Appendix F, Acronyms Used in the Report (begins at page 124). In addition, the 

Reliability Primer prepared by Commission Staff (https://www.ferc.gov/legal/staffreports/2016/reliability-primer.pdf) and appendices from the Report on Outages and 

Curtailments During the Southwest Cold Weather Event of February 1-5, 2011: Causes 

and Recommendations (https://www.ferc.gov/legal/staff-reports/08-16-11-report.pdf )

may be helpful. Helpful appendices in the 2011 report include: Electricity: How it is 

Generated and Distributed, Power Plant Design for Ambient Weather Conditions, Impact 

of Wind Chill [on generating units], Winterization for Generators, Natural Gas: 

Production and Distribution, Natural Gas Transportation Contracting Practices, and 

Impact of Cold Weather on Gas Production. Appendix G of this report, which begins at 

page 126, contains the 2011 report’s Recommendations on Preparation for Cold-Weather 

Events.

2 Although the Event did not occur in WECC’s footprint, WECC was invited to 

participate due to its experience with issues relating to the “seams” or borders between 

two Reliability Coordinator footprints.
Page 5 of 153

and PowerSouth. Following these presentations, the Commission and NERC announced 

a joint inquiry with the Regional Entities, citing, among other factors, “reports of multiple 

forced generation outages, voltage deviations and near-overloads during peak 

operations,” and the need to “understand and underscore the importance of seamless RCto-RC interactions.”2F

3

Without the excellent cooperation of these entities, the Team could never have 

produced a thorough analysis. In addition to the owners of generating units affected by 

the extreme weather conditions, the Team would especially like to thank the staffs of 

MISO, SPP, TVA, SeRC/Southern Company, AECI, LG&E/KU, and PowerSouth. All 

of these entities provided data, and the non-generator entities attended multi-day 

meetings to answer questions and share perspectives. Some answered multiple rounds of 

questions as the Team clarified its understanding of key concepts. All were generous 

with their data and time, and the Team is grateful.3F

4 The Team conducted outreach to 

share its preliminary findings and recommendations. Those invited to outreach sessions 

included MISO, SPP, TVA, Southern Company, and the Joint Parties, the Regional 

Entities not already participating in the Inquiry, market monitors for MISO and SPP, and 

industry groups including the ISO/RTO Council, Edison Electric Institute, the Electric 

Power Supply Association, the North American Transmission Forum, the North 

American Generator Forum, the National Rural Electric Cooperative Association, the 

American Public Power Association, the Electricity Consumers Resource Council, the 

Canadian Electricity Association, and the Transmission Access Policy Study Group. The 

Team thanks all who participated in the outreach for their insight.

 3 https://www.ferc.gov/media/news-releases/2018/2018-3/09-12-18.pdf

4 The entities provided data to the Team with the assurance that it would be kept 

confidential until the entities provided permission to release it publicly. The Team has 

obtained permission from the entities to share the data included in the report.
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I. Executive Summary

On January 17, 2018, a large area of the south central region of the United States 

experienced unusually cold weather. The below-average temperatures in this area 

resulted in a total of 183 individual generating units within the Reliability Coordinator 

(RC)4F

5 footprints of SPP, MISO, TVA,5 F6 and SeRC experiencing either an outage, a 

derate,6F

7 or a failure to start between January 15 and January 19, 2018. Between Monday, 

January 15, and the morning peak hour (between 7 and 8 a.m. Central Standard Time 

(CST)) on Wednesday, January 17, approximately 14,000 MW of generation experienced 

an outage, derate or failure to start. Including generation already on planned or 

unplanned outages or derated before January 15, the four RCs had over 30,000 MW of 

generation unavailable in the south central portions of their footprints by the January 17 

morning peak hour. MISO declared an Energy Emergency, 7F

8 because it had insufficient 

reserves to balance generation and load in the MISO South portion of its footprint, while 

all four of the RCs experienced constrained bulk electrical system (BES) 8F

9 transmission 

 5 See Appendix E, “Categories of NERC Registered Entities.”

6 TVA is a Reliability Coordinator for its TVA Balancing Authority area as well as 

for the Balancing Authority areas of AECI and LG&E/KU. This report will clarify 

whether it is referring to TVA as the RC, including AECI and LG&E/KU, or only to 

TVA’s own Balancing Authority area.

7 Reductions in capacity of a generating unit short of a total outage.

8 See Appendix C, “RC and TOP Tools and Actions to Operate the BES in Real 

Time.”

9 The Commission’s jurisdiction extends to the Bulk-Power System, defined by 

Section 215(a) (1) of the Federal Power Act as “facilities and control systems necessary 

for operating an interconnected electric energy transmission network (or any portion 

thereof), and electric energy from generating facilities needed to maintain transmission 

system reliability.” The mandatory Reliability Standards apply to owners and operators of 

the bulk electric system (BES). In Order No. 773, the Commission approved a definition 

of BES that generally covers all elements operated at 100 kV or higher, with a list of 

specific inclusions and exclusions. Revisions to Electric Reliability Organization 

Definition of Bulk Electric System and Rules of Procedure, Order No. 773, 141 FERC ¶ 

61,236 (2012); order on reh’g, Order No. 773-A, 143 FERC ¶ 61,053 (2013), order on 

reh’g and clarification, 144 FERC ¶ 61,174 (2013). This report will use BES because its 

primary audience is most familiar with that term.
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conditions across portions of their footprints, spanning all or parts of nine states. While 

the system remained stable, this combination of an Energy Emergency and wide-area 

constrained transmission conditions on January 17 meant that had MISO’s next single 

contingency generation outage in MISO South of 1,163 MW9 F

10 occurred, continued 

reliable BES operations would have depended on system operators shedding firm load 

promptly to prevent further degradation of BES conditions. 

The combination of an Energy Emergency and wide-area constrained conditions 

constitutes the South Central U.S. Cold Weather BES Event of January 17, 2018, 

hereafter referred to as “the Event,” which occurred in an area (the “Event Area”)1 0F

11

consisting of:

• MISO South (Arkansas, eastern Texas, Louisiana, and Mississippi) 

• Southeastern portion of the SPP RC footprint (lower Kansas-Missouri border, the 

eastern half of Oklahoma, Arkansas, eastern Texas, and Louisiana)

• Western portion of the TVA RC footprint (western Tennessee, lower Missouri, 

northeastern Oklahoma, northern Mississippi and Alabama)

• Western portion of the SeRC footprint (southern Mississippi and Alabama).

 10 The mandatory Reliability Standards set forth requirements that provide for the 

reliable operation of the BES. Federal Power Act (FPA) § 215(a)(3). In turn, “reliable 

operation” is defined in the FPA as “operating the elements of the [BES] within 

equipment and electric system thermal, voltage and stability limits, so that instability, 

uncontrolled separation or cascading will not occur as a result of a sudden disturbance, 

including a cybersecurity incident or unanticipated failure of system elements.” Id.

11 The sources or credits for all Figures are listed in Appendix H, “Source of 

Figures Used in the Report (begins at page 139).”
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Figure 1: January 17, 2018 Event Area – Low Temperature Deviation From the 

Normal Daily Minimum

Below-average temperatures began to occur as early as Friday, January 12, from 

the Great Plains south through the Mississippi Valley. Going into the work week 

beginning Monday, January 15, MISO, SPP, and the other RCs, which are located within 

the MRO, SERC, and RF regions,11 F

12 knew that Wednesday, January 17, was likely going 

to be the coldest day of an extremely cold week for much of their respective footprints. 

Because their footprints stretch further eastward than SPP’s, MISO, TVA and SeRC also 

expected cold weather conditions for their respective areas on Thursday, January 18, as 

forecasts showed the cold weather moving eastward. With temperatures forecast by the 

National Oceanic and Atmospheric Administration to be “much below normal” for 

January 17, RCs in the Event Area expected very high system loads. 

Planned and unplanned generation outages already existed going into the week of 

January 15, but as the colder weather conditions developed, MISO was projecting 

extremely tight reserve margins for MISO South in meeting its forecast peak load for the 

morning of January 17, beginning at 7 a.m. CST. Still, even with a high system load 

forecast and pre-existing generation outages, MISO did not expect to have a problem 

 12 These are among the Regional Entities to which NERC has delegated some of 

its duties as the Electric Reliability Organization, as part of the statutory scheme which 

gave rise to mandatory Reliability Standards. 
Page 9 of 153

meeting customer demand on January 17 in MISO South, based on anticipated generator 

availability and precautionary measures that MISO took to increase projected reserves. 

However, an extraordinary amount of continuing generation outages and derates

increasingly tightened already tight reserves, requiring emergency measures. In addition, 

MISO’s five-day, four-day and three-day-out MISO South load forecasts for January 17 

were less accurate (underestimating load by approximately 18.9%/6,000 MW, 

10.2%/3,250 MW, and 6.1%/1,900 MW, respectively) than the other RCs’ forecasts for 

the same period. Improved forecasting accuracy for future extreme weather conditions

could increase MISO’s ability to rely on long-lead-time resources and give it more time 

to prepare for severe weather events. The Team recommends that MISO work with its 

Local Balancing Authorities and adjacent RCs to improve the accuracy of its near-term 

load forecasts for MISO South.

In order to meet forecast load plus reserves for the morning peak hour (7 to 8 a.m.) 

on January 17, MISO instructed its local balancing authorities (LBAs) in MISO South to 

issue public appeals to reduce demand.12 F

13 MISO estimated the total load reduction 

achieved from this effort was 700 MW. Some of the Load Modifying Resources

(LMR)13 F

14 participating in MISO’s load reduction required more notice than MISO was 

able to provide at the time of this appeal.1 4F

15 MISO also needed to purchase emergency 

energy from suppliers in adjacent RCs to meet its peak load. 

The MISO South footprint was severely stressed as the morning peak hour 

approached. During the peak hour, MISO system analysis showed that if it incurred the

worst single contingency generation outage of 1,163 MW in MISO South (hereafter 

MISO South WSC),15 F

16 it would need to rely on post-contingency manual firm load shed 

 13 MISO attributed the need for public appeals to “forced generation outages and 

higher than forecast load.”

14 Load Modifying Resources are demand resources or behind-the-meter 

generation.

15 On January 18, the day after the Event, when MISO was able to provide more 

notice, it achieved 930 MW of Load Modifying Resources.

16 In addition to the Most Severe Single Contingency (MSSC) for its entire BA 

area (for the morning of January 17, 2018, MISO’s MSSC was a 1,732 MW facility in 

the Midwest region of its BA), which MISO is required to cover under the Reliability 

Standards, MISO planned for sufficient reserves in MISO South to cover its worst single 

contingency in the MISO South portion of its footprint. It is this latter “worst single 

contingency” that the report will discuss and refer to as the MISO South WSC.
Page 10 of 153

to maintain voltages within limits and shed additional firm load to maintain system 

balance and restore reserves for the MISO South region. MISO South’s load peaked at 

31,852 MW on January 17. At one point on January 17, MISO South had as much as 

17,000 MW of generation unavailable, including 13,000 MW of it unplanned.16 F

17

MISO was not the only RC that lost generation in the Event Area. Going into 

Wednesday January 17, SPP, TVA RC and SeRC had 8,300 MW, 5,000 MW, and 1,400 

MW of generation unavailable, respectively. The entire Event Area had as much as 

33,500 MW of total unavailable generation (including planned outages) at one point on 

January 17, out of approximately 118,000 MW of capacity in the Event Area, and over

30,000 MW unavailable by the start of the morning peak load timeframe. 17F

18

The majority of the problems experienced by the many generators that 

experienced outages, derates, or failures to start during the Event were attributable, either 

directly or indirectly, to the cold weather itself. For the entire Event Area, from January 

15 to January 19, Generator Owner/Operators (GO/GOPs) directly attributed 14 percent 

of the generator failures to weather-related causes, including frozen sensing lines, frozen 

equipment, frozen water lines, frozen valves, blade icing, low temperature cutoff limits, 

and the like. Another 30 percent were indirectly attributable to the weather, occasioned 

by natural gas curtailments to gas-fired generators (16%) and mechanical causes known 

to be related to cold weather (14%). 18F

19 The Team found that total outages from January 

15 to 19 increased as temperatures decreased, with correlation coefficients of between -

0.5 to -0.7, depending on the city. More than one-third of the GO/GOPs that lost 

generation during the Event did not have a winterization plan. Given the relationship 

between the cold and generator outages, the wealth of prior voluntary recommendations 

for generators to prepare for winter weather, 19F

20 and that 70% of the unplanned outages 

occurred in gas-fired units, with 16% of those outages were directly attributed to gas 

supply issues, the Team recommends a three-pronged approach to address generator 

 17 Substantial percentages of the MISO South generation fleet were unavailable in 

Louisiana (57.1%), Arkansas (23.5%), and Mississippi (16.8%). 

18 See Figure 22, Total Unavailable Generation. Peak non-coincident system loads

for January 17 in the four BA footprints combined was 222,924 MW. See Figure 18, 

January 17, 2018 Peak Loads for Relevant Entities. The peak load figures cover the 

entire MISO, SPP, TVA and SeRC, footprints, whereas the capacity figure of 118,000 is 

an estimate of generating capacity just within the Event Area. 

19 All percentages in this and the preceding sentence are based on number of units.

20 See discussion in Recommendation 1, in Section VIII below.
Page 11 of 153

reliability during extreme cold weather. This approach includes NERC developing one 

or more mandatory Reliability Standards that require Generator Owner/Operators to 

prepare for the winter and to provide information regarding their preparations (or lack 

thereof) to their RCs and Balancing Authorities (BAs), as well as enhanced outreach to 

the GO/GOPs, and market incentives for those GO/GOPs in organized markets. 

In addition to the primary cause of the Event, which was the significant unplanned 

loss of generators in the Event Area that correlated with the drop in ambient 

temperatures, several other factors contributed to the BES conditions faced by system 

operators, including:

• increased customer electricity demand across the Event Area due to extreme low 

temperatures;

• large power transfers:

o MISO’s Regional Directional Transfer (RDT)20 F

21 from MISO Midwest to 

MISO South, which exceeded its contractual firm and non-firm limit 

(Regional Directional Transfer Limit (RDTL)) of 3,000 MW to provide 

replacement for MISO’s generation outages and derates in MISO South; 

but also 

o remote generation power transfers, including MISO’s and SPP’s dispatch of 

wind generation output from distant locations; and

o transfers between SPP and the ERCOT Interconnection via SPP’s High 

Voltage Direct Current (HVDC) ties. 

On January 17, MISO relied on its contractually-available transmission capacity 

under the RDT to schedule power to flow from generation in MISO Midwest into MISO 

South, to help cover the record winter electrical demand plus reserves. The RDT flow 

steadily increased in a north-to-south direction affecting the BES transmission system 

footprints of MISO, SPP, RC and SeRC, and it exceeded MISO’s 3,000 MW RDTL 

during the early morning hours of January 17, reaching a maximum of 4,331 MW, as 

measured in real time, around 6:30 am CST. Although MISO exceeded the RDTL, and 

did not reduce the RDT below the 3,000 MW limit within 30 minutes as contemplated by 

the settlement agreement, MISO operators communicated with adjacent RCs (which are 

parties to the settlement agreement that established the RDT) that MISO would be 

exceeding the limit, and that if MISO’s RDT flows caused a system emergency for the 

adjacent RCs, MISO would take appropriate actions. While the adjacent RCs did not 

determine that their systems were in an emergency state during the Event, they were 

made aware of the continuing generation outages and derates in MISO South, of MISO’s

 21 See section II.B and Figure 32 for background on MISO’s RDT.
Page 12 of 153

Energy Emergency declaration, and of MISO’s likely need to perform firm load shed if 

its next-worst contingency occurred. 

Before the morning of January 17, none of the RCs had anticipated the multiplewide-area21 F

22 constrained transmission conditions that simultaneously occurred in the SPP, 

TVA, SeRC, and MISO South RC footprints. The Team recommends seasonal studies

that consider more-severe conditions, modeling same-direction simultaneous transfers 

and other stressed but realistic conditions, and sharing the results with operations staff to 

aid in planning for more extreme days like January 17. These widespread constrained 

conditions caused reserves to be stranded from MISO South.22 F

23 The Team also 

recommends that RCs consider deliverability of reserves, and that MISO notify the other 

RCs when it is counting on the as-available, non-firm portion of the RDT to meet its 

reserves for MISO South, so that the RCs can timely communicate if conditions on the 

other RCs’ systems are projected to limit MISO’s ability to rely on the RDT.

The RCs also did not expect the numerous mitigation measures they would need to 

take to maintain BES reliability on January 17, including Transmission Loading Relief, 

transmission reconfiguration, and the need to be prepared to shed firm load in the event 

of an outage of the MISO South WSC of 1,163 MW. Had this outage occurred, during

the morning peak hour on January 17, MISO would have likely had to order firm load

shed in MISO South for two reasons. First, MISO would not have had sufficient 

deliverable reserves to cover its MISO South region peak load, and second, it 

concurrently would have likely needed to shed firm load to alleviate low voltages at 

many locations that were calculated to be significantly below their limits. Normally, 

voltage stability is a greater risk during summer than winter, however, there can be an 

increased risk of voltage stability under extreme cold winter weather conditions, heavy 

imports, and facility outage conditions.23 F

24 Although the system remained stable on 

 22 The “wide area” each RC is responsible for includes its “entire RC Area as well 

as the critical flow and status information from adjacent Reliability Coordinator Areas as 

determined by detailed system studies to allow the calculation of Interconnected 

Reliability Operating Limits.” (See NERC Glossary of Terms). The January 17 event 

involved critical flows experienced concurrently in four RC areas.

23 By “stranded,” the Team means reserves that cannot be delivered due to 

transmission constraints which cannot be alleviated.

24 It has been studied that under high loads and heavy imports in a different winterpeaking area of the U.S., credible single and multiple contingencies could result in 

widespread post-contingency steady state voltage instability. The entity has identified 

these conditions as an Interconnection Reliability Operating Limit (IROL). In this 
Page 13 of 153

January 17, the Team recommends that MISO and other RCs perform voltage stability 

analysis when under similarly constrained conditions, benchmark planning and 

operations models against actual events which strained the system, perform periodic 

impact studies to identify which elements in the adjacent RCs’ systems have the most 

impact on their own systems, and perform drills with entities involved in load shedding to 

prepare to execute load-shedding for maintaining reserves while at the same time 

alleviating severe transmission conditions.

Actions by operators to address real-time issues were effective and timely. The 

RC operators for SPP, MISO, TVA, and SeRC had situational awareness, communicating 

and coordinating their analyses and discussing mitigation actions necessary to maintain 

BES reliability, up to shedding firm load. RC operators also communicated as necessary 

with the Transmission Operators to verify that System Operating Limits (SOLs) took into 

account the extreme cold temperatures. Because some SOLs which operated as 

constraints on January 17 were based on summer temperatures or on static, year-round 

ratings, the Team recommends that SOLs and their associated equipment ratings be based 

on, at a minimum, ambient temperature conditions that would be expected during high 

summer load and high winter load conditions, respectively.

System conditions began to gradually improve after the morning peak ended at 8 

a.m. CST and as the cold weather moved out of the Event Area. Warmer temperatures 

resulted in some generators returning to service, and decreased system loads. While 

MISO still sought emergency power for the evening peak on January 17, wide-area BES 

conditions were not as constrained as they were approaching the morning peak. 

The affected RCs performed a post-Event analysis. Among the areas they 

identified for improvement was the joint Regional Transfer Operations Procedure 

(RTOP) used to govern MISO’s use of the RDT, which was in effect at the time of the 

Event. The improvements they made to the RTOP, along with the Team’s additional 

recommendations to add specificity and clarity during emergency situations, underscore 

the need for clear operating procedures for the system operators, to address similar 

multiple-wide-area constrained transmission conditions. The Team’s recommended 

changes to the RTOP would clarify roles and timing, require affected entities to declare 

an emergency before MISO sheds firm load to reduce the RDT, and implement studies to 

 

instance, voltage stability analysis (VSA) is conducted daily for the next operating day to 

determine if the limit can be increased or decreased depending on system conditions (i.e., 

load, power flows, internal generation in the area, outages, etc.). The IROL is also 

monitored in real time using VSA to perform real-time calculations for the IROL limit 

based on real-time conditions.
Page 14 of 153

be performed before temporarily changing the RDTL or making emergency energy 

purchases.

In addition to the Team’s recommendations, the report discusses sound practices 

followed by the entities involved in the Event, and reaffirms recommendations from the 

2011 Report.24 F

25

II. Background

A. Affected System Overview 

The Event Area is located within the Eastern Interconnection (which stretches 

from the East Coast to the Rocky Mountains, omitting the majority of Texas), and from 

eastern Canada to the Gulf Coast. Of the 15 NERC-approved RCs in North America 

which are responsible for having the wide-area view to oversee grid reliability, four were 

responsible for the reliable operations of the BES in the Event Area: MISO, SPP, TVA 

and SeRC.

The extra-high voltage (EHV) (345 kilovolts (kV) and above) portion of the Event 

Area comprises 500 kV transmission facilities spanning Arkansas, western Tennessee, 

Mississippi, Louisiana and Alabama. These 500 kV facilities are connected to the north 

and west within the Event Area via transformers to 345 kV transmission facilities located 

in lower Missouri and Kansas, and which run through Oklahoma and along the eastern 

border of Texas. There are two asynchronous HVDC connections between these 345 kV 

transmission facilities and ERCOT (to the west, in Texas), which operates as a 

functionally separate interconnection. These two HVDC ties to ERCOT (the North DC 

Intertie, and the East DC Intertie) allow power exchanges with the Eastern 

Interconnection through SPP. SPP also has several DC ties with the Western 

Interconnection. Other high-voltage BES transmission facilities within the Event Area 

include 230 kV, 161 kV, 138 kV and 115 kV facilities. 

 25 See Appendix G, “2011 Recommendations on Preparation for Cold-Weather 

Events.”
Page 15 of 153

Figure 2: MISO and SPP Regional Transmission Organization Footprints

As the table below illustrates, the BES system between MISO and SPP is far more 

extensive than the limited number of ties between MISO Midwest and MISO South:

Figure 3: Tie Lines Between MISO and SPP RC Versus Within MISO

Voltage Level (kV) Number of Tie-lines 

between MISO and SPP

Number of transmission 

lines between MISO 

Midwest and MISO

South

69 85 0

115 30 0

138 5 0

161 41 0

230 13 0

345 16 0

500 3 1

Total 193 1
Page 16 of 153

Figure 4: Electric Transmission Lines and Cities Within the Event Area

Transmission facilities within the Event Area serve load centers such as: 

Oklahoma City, OK Tulsa, OK Joplin, MO Springfield, MO

Ft. Smith, AR Little Rock, AR Memphis, TN Texarkana, TX/AR 

Shreveport, LA Lafayette, LA Jackson, MS Hattiesburg, MS

Baton Rouge, LA Beaumont, TX New Orleans, LA Wichita, KS

These BES transmission facilities also span many rural locations, serving thousands of 

smaller cities and towns, as well as large commercial, agricultural, and industrial loads

located across portions of the south central U.S. This region of the country is normally 

not generation-capacity-limited. Under normal conditions MISO South has a substantial 

surplus of capacity, often leading to transmission flows in a southern-to-northern 

direction. This was not the case on January 17, 2018, due to the extensive generation 

outages experienced.
Page 17 of 153

B. MISO Regional Directional Transfer and Related Agreements

MISO and SPP Regional Transmission Organizations (RTOs) share a border, or 

seam, and are parties to a Joint Operating Agreement designed to address power flows 

and improve operations along that seam. On December 19, 2013, MISO expanded its 

footprint by integrating the Entergy Operating Companies, among others, as transmission 

owning members (they now comprise the MISO South region). Since that date, MISO 

has two regions within its BA area, joined by a single firm transmission path: MISO 

Midwest, and MISO South. The addition of MISO South extended the seam between 

MISO and SPP to its current length: from the Canadian border in the north to the Gulf of 

Mexico in the South. 

At the time the Entergy Operating Companies considered joining MISO, a dispute 

arose between MISO and SPP about interpreting provisions in the MISO-SPP Joint 

Operating Agreement about whether and/or how the two would share available 

transmission capacity on their respective transmission systems, particularly as to the 

amount of power flow, known under the Agreement as Regional Directional Transfer, or 

RDT, which MISO could use for intra-market flows between MISO Midwest and MISO

South. The dispute was the subject of numerous filings and proceedings before the 

Commission and included parties in addition to MISO and SPP that were also affected by 

operations of the expanded MISO footprint.25 F

26 The parties resolved the dispute by 

entering into a Settlement Agreement, which the Commission accepted on January 21, 

2016.26 F

27 Under the Settlement Agreement, MISO agreed to a Regional Directional 

Transfer Limit, or RDTL,27F

28 which limits MISO’s north-to-south intra-market flows to 

3,000 MW (1,000 MW being firm and 2,000 MW being non-firm, as-available) and 

 26 See, e.g., Sw. Power Pool, Inc., 146 FERC ¶ 61,231 (2014) (consolidating the 

proceedings in Docket Nos. EL11-34-002, EL14-21-000, EL14-30-000, and ER14-1174-

000, and establishing hearing and settlement judge procedures).

27 Sw. Power Pool, Inc., 154 FERC ¶ 61,021 (2016). The parties to the Settlement 

Agreement are SPP, MISO, AECI, Southern Company, TVA, LG&E/KU, PowerSouth, 

and NRG Energy, Inc.

28 The Settlement Agreement between MISO and SPP refers to the flows between 

MISO Midwest and MISO South as Regional Directional Transfer (“RDT”). On the other 

hand, within MISO, the RDT-related constraint on flows is referred to as Sub-Regional 

Power Balance Constraint (SRPBC). In either case, the limit is contractual in nature, and 

is not an actual physical transmission constraint. 
Page 18 of 153

2,500 MW flowing south-to-north from MISO South (1,000 MW being firm and 1,500 

MW being non-firm, as-available). 

Figure 5: MISO Midwest to MISO South Intra-Market Regional Directional 

Transfers (RDT)

Section 7.2.1 of the Settlement Agreement provided that the RDTL may be 

temporarily increased or decreased to avoid a transmission system emergency or during 

such an emergency, as long as the increased flow does not cause an emergency on the 

system of another party to the Settlement Agreement. Any party requesting an RDTL 

increase or decrease must contact the affected RCs and notify all other RCs via a posting 

to the Reliability Coordinator Information System (RCIS). The affected RC must assess 

the effects of an RDTL increase or decrease, and then notify the requesting RC whether it 

can accommodate such a change.

To implement the Settlement Agreement in real-time operations, the parties have a 

joint Regional Transfer Operations Procedure (RTOP), which addresses actions to be 

taken when the RDT is exceeded, requests to raise or lower the RDTL, congestion 

management, the effect of system emergencies and a procedure for conducting post-event 

reviews of events.
Page 19 of 153

III. Review of Entities’ Preparations for Winter 2017/2018

BES operations for any season begin well in advance, with planning and 

preparation based on certain historical data and assumptions. As real-time operations 

approach, this planning is refined with ever-more-accurate information. The Team 

reviewed how the relevant entities (RTOs, RCs, BAs and GO/GOPs) planned for the 

upcoming winter 2017/2018 season, and how those preparations assisted in, or could be 

improved for, ensuring reliable BES operations during the Event. The Team reviewed 

the relevant entities’ 2017/2018 winter season:

• forecast peak loads,

• resource (generation) adequacy,

• transmission assessments, and 

• generation winterization plans.

As part of its review, the Team asked the entities if they had considered relevant 

recommendations from similar events in their winter 2017/2018 planning.

A. Entities’ Preparations for Winter 2017-2018 Operations

1. Projected Resource Adequacy for Winter 2017-2018 

Historically, MISO and SPP are summer-peaking entities, TVA’s BA has summer 

and winter peaks of similar magnitude, and SoCo BA (comprising the majority of the 

SeRC footprint) has more recently been a winter-peaking entity, with winter heating 

loads as a primary contributing factor. The table below shows the winter 2017-2018 peak 

forecast load, actual peak load, and actual peak load for January 17, 2018 for the entities’ 

respective footprints. 
Page 20 of 153

Figure 6: Forecast 2017/2018 Winter Peak Loads

MISO

(Total)

MISO 

South

Region

SPP TVA BA SoCo BA

Previous All-Time 

Winter Peak

(GW)

109.3 31.1 41.5 33.4 45.9

2017/2018 50/50 

Forecast Peak 

(GW)

103.4 28.4 41.1 31.9 41.0

2017/2018 

Extreme Forecast 

Peak (GW)28 F

29

110.6 31.2 42.5 33.4 47.0

2017/2018 Actual 

Peak (GW) / Date

106.1 /

1/17/2018

32.1 / 

1/17/2018

43.5 / 

1/17/2018

32.5 / 

1/18/2018

44.4 / 

1/18/2018

January 17, 2018 

Peak (GW)

106.1 32.1 43.5 31.6 41.6

Above 50/50 Forecast Peak/Above Extreme Forecast Peak

None of the affected RCs forecast having a shortage of generation to meet their 

winter peak loads. MISO, SPP, TVA BA and SeRC all provided resource adequacy 

projections for their entire footprints for winter 2017-2018 as part of NERC’s 2017-2018 

Winter Reliability Assessment, which ranged from 32% to 67% resource reserve margins 

(excluding planned and expected unplanned generation outages), well-above their 

required reserve margins of 12% to 17%. 29F

30 The 29.6% reserve margin predicted for the 

MISO South region was also much higher than any of the required reserve margins.30 F

31

The above reserve margin values do not take into account planned or scheduled 

generation outages to perform maintenance, or refueling outages for nuclear generation. 

In portions of the south central U.S., where winter typically brings relatively mild 

temperatures, lower system loads, and adequate reserve margins (i.e., 30% or greater), 

 29 SPP and SeRC calculated extreme scenario forecasts, while MISO and TVA 

used 90/10 scenarios.

30 Data Source: NERC 2017/2018 Winter Reliability Assessment, available at 

https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_WRA_11

202017_%20Final.pdf

31 The annual Weighted Equivalent Forced Outage Rate (wEFOR) for 2017 for 

MRO was 10.5%, and for SERC was 7.6%.
Page 21 of 153

generation outages may be planned for the winter months. This allows maximum 

generation availability during summer, when much higher loads are experienced. MISO 

and SPP, both summer-peaking entities,31 F

32 would have planned more generation outages 

for the winter season than the summer (as well as during the so-called “shoulder” seasons 

of spring and fall). While planned outages can be rescheduled at times if system 

operators have sufficient notice of narrowing reserve margins, eventually the outages 

must occur to allow required unit maintenance. For example, from September 21-25, 

2017, temperatures were unseasonably high throughout the MISO footprint. High 

planned outage rates, typical of shoulder months, and 1,100 MW of forced outages

contributed to tight system conditions, leading MISO to declare a Maximum Generation 

Event on September 22, 2017.32 F

33 MISO coordinated with Generator Operators during the 

operations planning horizon, asking them to shift their outages if possible to another time 

of the year when system loads and planned generation outages were forecast to be lower 

than the September 2017 conditions. One of the Generator Operators agreed to shift its 

planned outage until January, 2018, and thus was not available during the January 17 

Event.

Winter reliability assessments also do not attempt to quantify the risk of fuel 

supply interruptions, although the Winter 2017-2018 assessments did include the data 

below illustrating the capacity of generation resources by fuel type.33 F

34

 32 The scheduling of significant generation outages during the winter months is 

less likely in other, winter-peaking areas of the country, where their typical winter 

temperatures are much lower - resulting in much higher system loads and therefore lower 

supply reserve margins.

33 IMM Quarterly Report: Fall 2017, MISO Independent Market Monitor, 

Potomac Economics, available at https://www.potomaceconomics.com/wpcontent/uploads/2017/12/IMM-Quarterly-Report_Fall-2017-Final.pdf.

34 Data source for SPP and MISO: NERC Winter 2017/2018 Reliability 

Assessment. Data for SeRC/Southern and TVA BA was aggregated into SERC into the 

NERC Winter Reliability Assessment; therefore, the Team used publicly-available data 

for SeRC and TVA BA.
Page 22 of 153

Figure 7: Generation Capacity Data by Fuel Type

Figure 7: Generation Capacity Data by Fuel Type 

MISO SPP SeRC-SoCo BA TVA BA

MW Percent MW Percent MW Percent MW Percent

Biomass 535 0.4% 39 0.1% 116 0.2% --- ---

Coal 61,452 42.7% 23,995 34.6% 16,890 36.0% 8,200 20.4%

Hydro 1,237 0.9% 4,771 6.9% 1,661 3.5% 5,149 12.8%

Natural 

Gas

60,328 41.8% 33,873 48.8% 19,514 41.6% 15,371 38.2%

Nuclear 12,866 8.9% 1,943 2.8% 3,680 7.8% 8,609 21.5%

Other --- --- 62 0.1% 3 0.0% --- ---

Petroleum 3,168 2.2% 1,717 2.5% --- --- --- ---

P. Storage 2,562 1.8% 482 0.7% 1,095 2.3% 1,615 4.0%

Solar 159 0.1% 197 0.3% 2,504 5.3% 1,100 2.7% Wind 1,675 1.2% 2,247 3.2% 1,474 3.1%

As the above table demonstrates, MISO, SPP, TVA and SeRC rely on a substantial 

amount of natural gas-fired generation. None of these RCs expected any gas pipeline 

issues for the winter 2017-2018 that would detrimentally impact electric generation 

availability, based on their communications with pipeline operators. For instance, MISO 

stated in its 2017-2018 Winter Readiness presentation34 F

35 that lessons learned from the 

2014 Polar Vortex helped it to plan for the coming winter, including monitoring of, and 

communications with gas pipelines; gas/electric market timeline changes; and gas usage 

profiles of generators. However, as discussed below in section VIII, gas pipeline issues 

did adversely affect electric generation during the Event.

2. Seasonal Transmission Assessments for Winter 2017-2018

MISO, SPP, and the other relevant Planning Coordinator entities generally 

perform seasonal transmission assessment studies several months before the winter and 

summer seasons, which are intended to test system performance under conditions 

anticipated that season, including expected transmission outages and realistic estimates of 

load, generation and transfers across the system. The affected entities performed their 

 35 Data Source: MISO Winter Readiness Presentation, October 19, 2017.
Page 23 of 153

winter 2017-2018 assessments in three separate, although somewhat coordinated, 

processes. 

MISO: MISO performed its Coordinated Seasonal Transmission Assessment in 

the fall of 2017 to analyze transmission performance for north-to-south and south-tonorth intra-market power transfers to determine power transfer limits for the 2017-18 

Winter Peak season. MISO works with members and neighboring planning entities on 

the study scope, modeling and outage updates, and analysis review; the results then 

inform winter readiness efforts, such as MISO’s annual Winter Readiness Workshop. 

MISO’s winter 2017-18 Coordinated Seasonal Transmission Assessment included

five analyses: 1) Steady-State AC Contingency Analysis; 2) First Contingency 

Incremental Transfer Capacity Analysis; 3) Critical Interface Voltage Stability Analysis; 

4) Wind Generation Sensitivity; and 5) Phase Angle Analysis. MISO modeled transfers 

by increasing generation in the study export area while reducing generation in the study 

import area and honoring maximum generation limits. MISO’s First Contingency 

Incremental Transfer Capacity Analysis included transfers from MISO Midwest (MISO 

North and Central Regions) to MISO South, the same transfer path at issue in the Event,

resulting in an inter-regional transfer capability of 4,650 MW. Since the agreed RDTL for 

real-time flows from MISO Midwest to MISO South Region is 3,000 MW, the study 

indicated that the 4,650 MW transfer capability was considered adequate for the 

upcoming winter season. To reach this conclusion, MISO adjusted transfers in its First 

Contingency Incremental Transfer Capacity analysis by increasing or decreasing 

generation in the desired area(s) on a sliding scale. The analysis did not model the 

outages of individual generators that would likely occur during actual system conditions.

MISO explained that power transfer distribution factors35F

36 are sensitive to, and 

vary substantially on, the generation dispatch modeling in the study. While the 2017-18

Coordinated Seasonal Transmission Assessment showed a winter season First 

Contingency Incremental Transfer Capacity of 4,650 MW, during the Event, SPP, TVA 

and other affected entities started experiencing constraints on their systems when MISO’s

Midwest to South transfers were much lower than 4,650 MW (e.g., at or below 3,000 

MW).36 F

37 MISO’s First Contingency Incremental Transfer Capacity analysis was not used 

to inform lowering or raising of the RDTL, leaving the RDTL changes to be determined 

in the real-time operations horizon, without the benefit of any insights which could have 

been gleaned from the First Contingency Incremental Transfer Capacity Analysis. Even 

if the First Contingency Incremental Transfer Capacity analysis in MISO’s Coordinated 

 36 See Appendix D.

37 See Section V, below.
Page 24 of 153

Seasonal Transmission Assessment had indicated a lower transfer limit for a particular set 

of inputs (available generation, transfers, load, etc.), MISO did not use the Seasonal 

Transmission Assessment results to support MISO in its requests to raise or lower the 

RDTL for any particular days of that season. 

SPP performed its winter assessment by creating two different snapshot cases for 

each week covering the study period of November 2017 through the end of March 2018,

using Wednesday and Sunday cases to represent high-load and low-load periods for each 

week. SPP performed an initial contingency analysis to observe any transmission or 

voltage violations caused by loss of the contingency elements. To remedy any limit 

exceedances found in the contingency analysis, SPP applied a security constrained 

redispatch (SCRD) to each case as needed. The SCRD simulated iterative changes to 

SPP’s generation dispatch in order to reduce or eliminate violations, while minimizing 

the creation of additional constraints. Once the redispatch was completed, a final 

contingency analysis was performed and any resulting violations were analyzed for 

further mitigations, overlapping outages that need rescheduling, or reported for further 

study. SPP’s winter assessment revealed no expected issues and noted that extreme 

weather or fuel delivery issues could result in localized or brief capacity constraints, but 

that existing SPP congestion management procedures, documented mitigation strategies 

and operating guides appeared to be sufficient to manage any potential issues. SPP did 

not analyze intra-market transfers, such as those that might result from widespread 

generation outages.

TVA and SeRC participate in SERC’s seasonal assessment. As a measure of 

projected transmission system performance for the 2017/18 winter season, the relevant 

study utilized assessments of incremental transfer capabilities among the SERC member 

systems. SERC’s analysis to determine transfer capabilities was similar to MISO’s in 

that transfers were simulated by increasing generation in an exporting area and 

decreasing generation in the associated importing area. However, in some instances, 

loads were reduced within subregions in SERC, to provide sufficient capacity to model 

desired levels of transfer. The studies did not identify any constraints relevant to the 

Event.

3. 2017-2018 Winterization Readiness Preparation 

a) Reliability Coordinators and Balancing Authorities

RCs have the wide-area view of the BES (typically including multiple BAs and 

TOPs) and are responsible for its reliable operation, while the BAs’ responsibilities 

within their BA footprint include integrating resource plans and maintaining generation-
Page 25 of 153

load balance. 37F

38 The Team found that MISO, SPP, TVA and SeRC routinely take steps 

to verify that the BES Generator Owners/Operators on which they depend are prepared 

for winter weather and extreme cold events. To better understand the topic of 

generators preparing for winter in the Event Area, one must first understand common 

differences between generating facilities in northern areas versus those in southern or 

other warm weather areas.38F

39

Geographic location and the corresponding ambient weather conditions, 

including expected temperatures and wind speed, have a direct impact on the 

preferred design for generating facilities. In the northern regions of the United States, 

most generating plants (especially steam-cycle plants) are designed and constructed with 

the boilers, turbines/generators, and certain ancillary equipment housed in one or more 

enclosed buildings. In the colder months, heat radiated from boilers, other generation 

equipment, and supplemental heaters maintain temperatures at a high enough level to 

prevent freezing. Enclosed areas are generally designed and constructed with fresh

air inlets and roof-mounted exhaust ventilators for cooling purposes during the hot 

weather months.

Figure 8: Enclosed Coal-fired Power Plant in the Northeastern United States

In the southern and other warm weather regions of the U.S., generating plants are 

designed and constructed without enclosed building structures, with the boilers, 

turbine/generators, and other ancillary systems exposed to the weather, in order to 

 38 NERC Glossary of Terms.

39 The following two paragraphs, including the photographs, are drawn from the 

“Appendix: Power Plant Design for Ambient Weather Conditions” to the joint 

Commission/NERC Staff Report on Outages and Curtailments During the Southwest 

Cold Weather Event of February 1-5, 2011: Causes and Recommendations, found at 

https://www.ferc.gov/legal/staff-reports/08-16-11-report.pdf
Page 26 of 153

avoid excessive heat build-up. For the colder months, when temperatures may fall 

below freezing, Generator Owners and Operators undertake specific freeze protection 

efforts, which typically involve a combination of heat tracing, insulation, temporary 

heating, and temporary wind breaks (to prevent heat loss from normal operations and 

from supplemental heating sources).

Figure 9: Non-Enclosed Coal-fired Power Plant in the Southern United States

Generally, the affected RCs and BAs had issued winter readiness guidelines to 

Generator Owners/Operators within their footprints for the winter 2017-2018 season. 

PowerSouth, TVA BA, and Southern Company included specific freeze protection plans 

for generating units, as well as other winter assessment processes, to be performed prior 

to the winter season, as early as October in some instances. Some of these assessment 

processes included identifying systems and equipment within generating plants requiring 

winterization; completing items on a winter preparation checklist; and engaging 

meteorologists to preview winter forecasts and assess risks for extreme temperatures. 

 

Some of the RCs and BAs also checked on generating units prior to winter 

weather to confirm the units’ winter readiness. For instance, LG&E/KU (within TVA

RC) held calls with individual generating plants to verify the plants had prepared for 

winter. TVA BA conducted winter readiness inspections of its units. Several other 

entities including PowerSouth (within SeRC), which owns generating units, have 

winterization plans that include checking plant equipment to ensure it is properly 

winterized.

MISO issued surveys to its Generator Operators on fuel availability prior to the 

winter. Some of the surveys included guidelines from the NERC winterization 

checklist39 F

40 and ERCOT’s winterization process. MISO noted that prior to the 2014 polar 

 40 The NERC Winterization guidelines provide details on specific components that 

must be addressed in an effective winter weather readiness program, including: (I) 

Safety; (II) Management Roles and Expectations; (III) Processes and Procedures; (IV) 
Page 27 of 153

vortex event, it did not have a process for Generator Operators to report issues pertaining 

to winter readiness, such as fuel unavailability. However, following the 2014 event, 

MISO developed and implemented a process for generating units to update MISO about 

their readiness for the winter, including fuel availability. MISO implemented this process 

as part of the cold weather alert it issued prior to the January 17, 2018 event. 

Most of the affected RCs and BAs educated their personnel and stakeholders on 

important generator winter readiness preparations through workshops in the fall of 2017. 

For instance, SPP and MISO held “Seasonal Preparedness” and “Winter Readiness” 

workshops, respectively. The workshops included discussions on high load and extreme 

outage scenarios, adequacy of generation resources to meet demand, and weather 

forecasts for the upcoming winter season. Southern Company, PowerSouth (in SeRC) 

and LG&E/KU (in TVA RC), which also own generating units, reported that they trained 

their operators to address freezing weather hazards to personnel and equipment. These 

entities also held post-winter meetings to review successes and setbacks from the 

previous winter season and get a head start on preparing for the next winter season.

RCs and BAs also prepared for winter by anticipating potential fuel supply issues. 

At least two large interstate pipelines in the affected regions declared force majeure40 F

41

during the Cold Weather Event, and at least one intrastate pipeline in the affected regions 

issued a critical notice for its entire pipeline group warning of imminent extreme cold 

temperatures, which increase demand for gas used by generators as well as to heat homes 

and businesses. Some generating units in the affected RC areas reported that they did not 

have firm gas supply or transportation contracts for their generating units. However, 

Southern Company (in SeRC), with fuel tank storage at its generating facilities, was able 

to re-supply generating units in the Event Area when their main fuel supplies were

interrupted as a result of gas pipeline issues. Gas supply issues caused by the extreme 

cold temperatures, including interruptible supply, low gas pressure, and other pipeline 

and gas supply issues, led to outages of 38 generating units, totaling approximately 2,200 

MW, during January 15 to 19 in the Event Area. 

 

Evaluation of Potential Problem Areas; (V) Testing; (VI) Training; and (VII) 

Communications.

41 Force majeure clauses allow parties to excuse non-performance under a contract 

when some unavoidable event occurs (such as a hurricane). In the gas pipeline context, 

declaring force majeure can excuse a pipeline which fails to deliver to shippers which had 

firm transportation contracts. It can also potentially excuse a gas seller’s failure to 

deliver.
Page 28 of 153

When fuel supplies are interrupted, dual-fuel41 F

42 units can help to protect reliability, 

but only if the unit can successfully switch to its backup fuel. From January 15 to 19, 

2018, 40 out of 55 units operated by Southern Company (in SeRC) successfully switched 

to their secondary fuel sources and provided needed energy supply. Four of the seven 

BAs had procedures in place to test dual-fuel generating units prior to the 2017-2018 

winter season, and TVA BA tests its dual-fuel units routinely during operations. For 

instance, LGE/KU (in TVA RC footprint) requires twice-yearly tests of dual-fuel units, 

whereas SeRC entities conducted annual tests to confirm that dual-fuel generating units 

can successfully switch to their alternate fuels. MISO noted that it does not currently 

have a program to ensure that generating units can switch fuels, however it would 

accommodate GO/GOPs that wish to test their fuel switching capabilities. SPP does not 

currently conduct any tests to confirm the fuel-switching capability of generating units 

within its service area. 

Load Modifying Resources (LMR), and Demand Side Management (DSM) are 

tools used during capacity shortages to help maintain the energy balance. Entities took 

varying approaches to ensuring that these resources would be able to perform when 

needed. For instance, MISO implemented its LMR operational capabilities during the 

Event, even though those resources were not required to perform in the winter.4 2F

43 Other 

RCs reported that no penalties are assessed if their LMR is unavailable due to planned 

maintenance or force majeure.

b) Generator Owner/Operators

Twenty-one Generator Owner/Operator entities, many of which owned and/or 

operated multiple generating units, provided data regarding outages that occurred 

between January 15 and 19, 2018. Of those 21, more than a third43 F

44 did not have

winterization procedures at the time of the Event. Those that did have plans to prepare 

for the winter included one or more of the following elements: 

 42 Some generators have dual-fuel capability – that is, they allow for a unit to 

switch from its primary source of fuel (e.g., natural gas) to a secondary source of fuel 

(e.g., oil or coal) if needed. Fuel switching is one method that generators can use to 

alleviate the strain when a particular fuel source is in short supply. It can also be useful 

when seeking cheaper alternatives for fuel. 

43 Unless the resource had bid in and was dispatched in real time.

44 Eight out of 21.
Page 29 of 153

• freeze protection measures (discussed in more detail below);

• enhanced staffing measures, which could include the addition of a “freeze 

protection operator,” responsible for inspecting critical equipment, ensuring 

appropriate protections are in place, and the addition of more staff during severe 

weather; and

• fuel supply and dual-fuel capability: These procedures include checking fuel tank 

levels at least every other day during seasonal cold weather to ensure sufficient 

fuel during a cold weather event, and pre-freeze test firing of dual-fuel units that 

have not fired on their secondary fuel source during the previous year.

The ambient temperature design rating of a generating unit is an important aspect 

of preparing for winter weather and severe cold weather events, because it specifies the 

temperature(s) at which the unit’s full output can be achieved. Most of the units in the 

Event Area for which the ambient temperature design rating is known were rated between 

-10 and 10 degrees Fahrenheit,44 F

45 with some exceptions. A handful of units had ambient 

temperature design ratings to -20 degrees, and four units were rated for use to -40 

degrees. Some entities did not know their units’ ambient temperature design ratings, or 

did not incorporate those ratings into their freeze protection measures.

Several affected entities did account for their units’ ambient temperature design 

ratings in their operating procedures. For example, one entity set minimum freeze 

protection temperatures for each plant site, with specific guidance for physical 

assessment of existing critical freeze protection systems and the development of action 

plans if those systems do not meet the ambient temperature minimums. 

Among the freeze protection measures contained in winterization plans were the 

following steps:

• Checking and maintaining adequate inventories of all commodities, equipment, 

and consumables that would aid in severe winter weather.

• Insulating exposed equipment and checking for missing or damaged insulation 

prior to cold weather.

• Checking heat tracing on all critical lines and piping to ensure that the circuits 

remain functional. Temperature guns can be used to check that heat tracing is 

working correctly.

• Closing doors on boiler enclosures to prevent cold air from entering.

• Confirming fuel heaters are in service and working properly prior to cold weather.

 45 All temperature references in this report will be to degrees Fahrenheit.
Page 30 of 153

• Considering pre-warming scheduled units prior to a forecast cold weather event.

• Checking that all critical site-specific problem areas have adequate protection to 

ensure operability, and emphasizing the points in the plant where equipment 

freezing could cause a unit trip, derate or failure to start. 

• Placing thermometers in areas containing equipment sensitive to extreme cold 

conditions and in freeze protection enclosures, ensuring that temperatures are

monitored and maintained above freezing. 

• Evaluating plant electrical circuits for adequate load capacity and ensuring that 

Ground Fault Circuit Interrupters are used properly.

• Reviewing work management systems for open corrective maintenance work 

orders that could affect the operation and reliability of the generating unit in cold 

weather, and ensuring that the work orders are prioritized correctly so that the 

work is completed prior to the winter season. 

• Ensuring that all modifications and construction activities are performed such that 

the changes maintain cold weather readiness for the generating unit. (i.e., the 

changes do not degrade the generating unit’s ability to withstand cold weather—

for example, tearing pipe insulation).

• Disconnecting sensing lines on pressure transmitters to prevent freezing of these 

lines.

• Installing wind barriers, such as tarps or semi-permanent barriers constructed of 

wood or metal, to protect critical instruments, sensing lines, controllers and piping.

• Cleaning coal feed chutes as needed to keep coal supply flowing.

• Closing all building doors to prevent cold air from entering.

• Monitoring and removal of ice and snow.

Proper training of operators on winterization is critical to ensure they will be 

prepared to take the necessary actions before and during extreme cold weather events. 

Many of the affected entities employ preventative cold weather training, such as an 

annual review of site-specific winterization procedure for all operators, or requiring 

initial and recurring operator certification on procedures which include winterization plan 

procedures. Less experienced operators may be asked to perform a cold weather 

checklist with experienced operators. 

With a few exceptions, the majority of the GO/GOPs that had winterization plans 

also conduct “lessons learned” following major weather events, including severe cold 

weather events. In these evaluations, the entities review their performance during the 

severe weather, determine root causes of any weather-related problems, and develop 

additional best practices for future similar events. In many cases, the entities incorporate 

the takeaways from those evaluations in their written guidance on winter weatherization 

procedures. Some entities consider best practices from neighboring generation or 
Page 31 of 153

industry partners in keeping their winterization processes comprehensive and up-to-date. 

Some entities provided specific examples of differences between their current 

winterization procedures and previous ones as a result of lessons learned. Several of 

these are worth highlighting, such as the required “freeze protection” training for new 

hires and annual “refresher” trainings for appropriate personnel, and the addition of 

materials for extended stays of personnel in severe cold weather events (e.g., cots, food, 

camp stoves).

IV. Near-Term Forecasts and Preparations for the Week of January 15

A. Short Range Weather and Load Forecasts

1. Impending Weather Conditions

In general, average temperatures remained at or above-freezing for the deep south 

into Monday January 15; however, as arctic high pressure moved from the northern 

plains to the central and eastern U.S. on January 15-17,4 5F

46 it resulted in average 

temperatures well below freezing for areas including parts of the plains, the Mississippi 

Valley, and Tennessee.46 F

47 This cold front was forecast several days in advance. On 

Friday, January 12, at 3 p.m., the National Weather Service issued its “US Hazards 

Outlook” covering the period that included January 15 to 19.47 F

48 It predicted that an 

“arctic air mass” would reach the eastern half of the U.S. by January 17 and “last for 

several days,” bringing “much below normal temperatures,” with “maximum and 

minimum temperatures 12 -28 degrees [Fahrenheit] below normal.” 

2. Mid- and Short-Term Load Forecasts

MISO generates Mid-Term Load Forecasts and Short-Term Load Forecasts within 

the operating horizon (next four-six days prior to the operating day). MISO’s Mid-Term 

 46 Source: US HAZARDS OUTLOOK 300 PM EST JANUARY 10 2018, NWS 

Climate Prediction Center 

(http://www.cpc.ncep.noaa.gov/products/archives/hazards/data/2018/KWNCPMDTHR.2

0180110).

47 https://www.timeanddate.com/weather/usa, based on NOAA historical weather 

observations.

48http://www.cpc.ncep.noaa.gov/products/archives/hazards/data/2018/KWNCPM

DTHR.20180112 s
Page 32 of 153

Load Forecasts were the primary load forecasts used as an input to its operational 

planning to make longer-lead-time resource commitment decisions. The table below 

compares load forecasts generated on January 12, 13, 14, 15 and 16 for January 17, 2018 

for MISO South. 

Figure 10: MISO’s Near-term Peak Load Forecasts and Percent Error for MISO 

South: 5-day, 4-day, 3-day, 2-day, and 1-day ahead of January 17, 2018

MISO’s five-day, four-day and three-day-ahead “mid-term” peak load forecast 

errors in forecasting the actual MISO South peak load for January 17, 2018 were larger 

(approximately 18.9%/6,000 MW, 10.2%/3,250 MW, and 6.1%/1,900 MW lower than 

actual peak load, respectively) than forecast error rates for the same period for the other 

RCs involved in the event. SPP’s, TVA’s BA, and SeRC’s (SoCo BA) load forecasts 

comparable to this timeframe were much more accurate (with error rates ranging from 

5.6% lower to 3.0% higher than actual peak load for five-days-out, 4.6% lower to 4.8% 

higher than actual for four-days-out, and 2.8% lower to 4.0% higher than actual for threedays-out). Improved Mid-Term Load Forecast accuracy could have helped MISO plan 

for additional longer-lead-time actions to be better prepared for the operating day of 

January 17, 2018. MISO provided the high and low temperature forecasts for January 17 
Page 33 of 153

from January 12, 13, 14, and 15, which it incorporated into its load forecasts for January 

17, as shown below:

Figure 11: MISO’s High and Low Temperature Forecasts Used in MISO South Load 

Forecasts: 5-day, 4-day, 3-day, 2-day, 1-day ahead of January 17, 2018

City 

Name, 

State

1/12/18 for 

1/17/18

1/13/18 for 

1/17/18

1/14/18 for 

1/17/18

1/15/18 for 

1/17/18 Actual for 1/17/18

Little 

Rock, AR 33/19 30/15 28/12 32/12 29/9

Jackson, 

MS 41/21 35/16 32/14 33/15 31/10

Baton 

Rouge, 

LA

47/31 41/24 40/22 39/20 37/12

New 

Orleans, 

LA

51/34 42/27 41/25 38/24 36/19

The forecast temperatures MISO used in its MISO South load forecasts for 

January 17 on January 12 (five days ahead) were considerably higher than the actual 

highs and lows on January 17. The five-day-ahead forecast was in the normal range for 

mid-January, and was therefore not effective in providing a warning for the severity of 

the upcoming cold snap. The forecasts improved somewhat, but even the forecasts for 

January 15 (two days ahead) were 3 to 8 degrees higher than the minimum temperature

observed on January 17. 

B. Generation Unavailable for the Entire Event 

Planned generator outages are typically scheduled months or even years in 

advance, to perform necessary maintenance, or in the case of nuclear power plants, 

refueling. While Reliability Coordinators like MISO can ask Generator 

Owners/Operators to reschedule their planned generation outages for system reliability, 

they cannot require the Generator Owners/Operators to do so. At some point, the 

maintenance or refueling must be accomplished, and there are only so many opportunities 

to schedule outages so as to avoid peak system conditions and ensure sufficient 

generation remains available. 
Page 34 of 153

MISO South’s planned generation outages totaled 4,049 MW for the week of 

January 15, 2018, which included three generators larger than 500 MW and one over 

1,000 MW. MISO was able to reschedule 1,700 MW of generation outages during the 

week of January 15, which would otherwise have added to the 4,049 MW. In addition to 

the planned generation outages, MISO South experienced a number of forced generation 

outages and derates, as shown in the table below. SPP RC, TVA RC, and SeRC’s 

planned and unplanned outages within the Event Area from January 15 to the start of 

January 17 are also shown in the table below.

Figure 12: Event Area Approximate Planned and Unplanned Generation Outages, at 

the Start of January 15, and January 17, 2018

Planned,

at the start of:

Unplanned,

at the start of:

Total 

Unavailable,

at the start of:

Event Area

Approx.

Jan. 15 Jan. 17 Jan. 15 Jan. 17 Jan. 15 Jan. 17 Capacity

(MW) (MW) (MW) (MW) (MW) (MW) (MW)

MISO 

South

4,000 4000 5,700 7,600 9,700 11,600 41,800

SeRC 700 700 300 700 1,000 1,400 24,400

SPP 2,300 2,300 2,500 6,000 4,800 8,300 34,500

TVA RC 100 100 2,100 4,900 2,200 5,000 17,400

TOTAL 7,100 7,100 10,600 19,200 17,700 26,300 118,100

At the start of the week of January 15, MISO forecast the following conditions for its 

MISO South region:

Figure 13: MISO South Region Forecast Peak Load for January 17, 2018 and 

Available Generation, at the Start of January 15, 2018

Approx. 

Capacity

Total Unavailable 

Generation

Available 

Generation

January 17, 2018 

Forecast Peak Load

(MW) (MW) (MW) (MW)

MISO 

South 41,800 9,700 32,100 30,761
Page 35 of 153

By the start of January 17, 2018, planned generation outages within the MISO 

South, SPP, TVA RC, and SeRC portions of the Event Area totaled approximately 7,100 

MW, and forced generation outages and derates totaled approximately 19,200 MW, for a 

total of 26,300 MW, or approximately 22%, out of a total Event Area estimated

generation capacity of approximately 118,000 MW.48 F

49 By the start of January 17, 

outages and derates in MISO South reached 28% of its capacity, and SPP’s southern 

footprint within the Event Area reached 24%. The areas in which generation outages and 

derates occurred by the start of January 17, and the Event Area generation capacity 

statistics for each RC, are shown below. January 17, by RC Footprint

Figure 14: Total Generation Outages and Derates Within the Event Area, Beginning 

January 17, by RC Footprint

 49 This total includes forced outaged and derated generation, with some that 

occurred prior to the week of January 15, as well as on January 15-16. The Event Area 

did not include the entire footprints of MISO, SeRC, SPP, and TVA. The Event Area

generation capacity numbers cited are only a portion of the total generation capacity of 

MISO, SeRC, SPP, and TVA. The remaining areas of the MISO, SeRC, SPP, and TVA 

RC footprints were not affected by the Event.
Page 36 of 153

C. Changes/Adjustments Made by RCs Due to Impending Conditions 

Forecast

1. Pre-real-time Resource Commitment Process

For the week of January 15, MISO performed a “forward reliability assessment 

commitment” (FRAC) in advance of the January 17 operating day. FRACs occur four- to 

six-days-ahead of the operating day, and commit longer-lead generation (i.e., units that 

require 20 hours or more advance notice to come online). MISO’s FRAC projected for 

January 17 took into account available generation capacity located in MISO South, 

external interchange imports and exports scheduled for the MISO South region. MISO 

committed these resources on an hourly basis so that the total (generation capacity and 

net exchange) met or exceeded the total of the MISO South forecast daily peak loads, 

plus peak load forecast uncertainty of 5% and MISO South’s single worst contingency.4 9F

50 

The FRAC did not rely on MISO’s intra-market RDT capacity to calculate or provide

reserves for MISO South.

• During the January 14-16 timeframe, MISO revised its forecast peak load 

conditions, with each day forecasting a higher peak load for Wednesday, January 

17, 2018 for MISO South:

• On January 14, 3-day-ahead forecast peak load: 29,899 MW

• On January 15, 2-day-ahead forecast peak load: 30,761 MW

• On January 16, next-day forecast peak load: 32,455 MW

MISO’s January 16 day-ahead and January 17 real-time unit commitments 

differed from the four- to six-day-ahead FRAC in that they relied upon the entire 3,000 

MW MISO Midwest-to-South RDT (including both the 1,000 MW firm transmission 

capacity, and the non-firm, as-available 2,000 MW) in its calculation of reserves. Even 

though MISO included the RDT to meet its MISO South reserves for the next day, in its

security-constrained unit commitment and economic dispatch, MISO normally commits 

or schedules sufficient generation capacity for MISO South, so that the RDT is generally

held at a “zero” transfer level between MISO Midwest and MISO South.50F

51

 50 Normally MISO South’s single worst contingency was 1,415 MW, but that unit 

was on forced outage, leaving the 1,163 MW unit as the single worst contingency for 

MISO South FRAC calculations for January 17.

51 MISO’s Enhanced Reserves Procurement Process filing, accepted by the 

Commission in August of 2018, reflected that MISO intends to rely upon the full 3,000 
Page 37 of 153

As of January 16, with a higher forecast MISO South peak load (32,455 MW) for 

the next day, and with MISO South available reserves now forecast to be 2,147 MW, 

MISO fell short of covering the next-day forecast load + MISO South single worst 

contingency + load forecast reserve/uncertainty, by 576 MW. The reserves shortfall 

would need to be in part supplied from MISO Midwest, using MISO’s RDT, unless other 

actions were taken by MISO, such as scheduling imports directly into MISO South, via 

power transfers from directions other than the north-to-south RDT. MISO made the 

following declarations as January 17 approached and its projected reserves narrowed:

Figure 15: Declarations Made by MISO in Preparation for January 17 and 18

Declaration

MISO

Region Issuance Start Time End Time 

(CST) (CST) (CST)

Conservative Operations51F

52 South 1/15/18 4:59 1/15/18 5:00 1/18/18 13:00

Cold Weather Alert 52F

53 South 1/15/18 15:00 1/16/18 5:00 1/16/18 13:00

Maximum Generation 

Alert53 F

54

South 1/16/18 21:50 1/17/18 4:00 1/17/18 11:00

 

MW of RDT, including the as-available, non-firm portion, in establishing reserves for 

MISO South. Midcontinent Independent System Operator, Inc., 164 FERC ¶ 61,129 

(2018).

52 MISO’s “Conservative System Operations” procedure identifies the actions 

resulting from this declaration. Actions include additional control center staffing and 

deferring or canceling maintenance or testing of BES generation and transmission 

equipment, and critical computer systems (e.g. energy management systems). SO-PNOP-00-449 Rev 0 Conservative System Operations.pdf (#1981). The reasons given for 

the Conservative Operations declaration were record low temperatures and high loads 

forecast, forced generation outages and derates, as well as delayed outage returns.

53 MISO’s “Cold Weather Alert” procedure identifies the actions resulting from 

this declaration. Actions include communication to GOPs to implement plans to winterize 

units and plants to ensure availability during emergency conditions, coordinate personnel 

staffing to ensure all scheduled combustion turbines and diesel generators are available 

for loading during load pick up period, and review fuel supply/delivery schedules 

availability during emergency conditions. Reliability Coordinator Information System 

(RCIS) log.

54 MISO attributed the Maximum Generation Alert to forced generation outages 

and higher than forecast load. Among other measures, the Maximum Generation Alert 
Page 38 of 153

SPP, TVA BA and SeRC had similar near-term processes for their 

generation/resource commitment, and they each predicted sufficient generation supplies 

across their respective footprints for the next day, January 17. In addition to meeting 

their respective footprint’s electrical demand, as described further below in section V of 

the report, both TVA BA and SeRC/Southern Company were able to provide emergency 

energy to MISO South on January 17.

2. Next-Day Operational Planning Analysis (OPA) of Transmission 

Conditions (Performed on January 16, 2018 for the January 17 

Operating Day)

In order to develop their Operational Planning Analyses (OPA), 54 F

55 MISO RC, SPP RC, 

TVA RC, and SeRC performed next-day contingency analyses, including both steadystate thermal and voltage stability analyses. The completed contingency analyses were 

compared against relevant limits, including SOLs and IROLs, as well as voltage limit 

criteria,55 F

56 which are shown in Figure 16.

 

declaration called for all available economic resources to be committed to meet load, firm 

transactions and reserve requirements, as well as verification of available LMRs that 

could help reduce system load if called upon. Note that at this point, MISO only verified 

the LMRs; i.e., the Maximum Generation Alert does mean that it issued scheduling 

instructions for the LMRs to modify their load by a certain time, for a given duration. 

Source: Reliability Coordinator Information System (RCIS) log.

55 Under the mandatory Reliability Standards, each RC (e.g., MISO, SPP, TVA, 

SeRC) is required to “perform an Operational Planning Analysis that will allow it to 

assess whether the planned operations for the next-day [sic] will exceed SOLs and 

Interconnection Operating Reliability Limits (IROLs) within its Wide Area,” as well as 

an Operating Plan to address any potential SOL and IROL exceedances revealed by the 

OPA. IRO-008-2 R1&R2. Transmission Operators have a similar requirement to 

perform daily OPAs, and prepare Operating Plans to address the OPA’s findings, under 

TOP-002-4 R1&R2. See Appendix B, “Primer on Electric Markets and Reliable 

Operations of the BES,” for more information on the RCs’ OPA processes.

56 Planning coordinators and transmission planners use voltage criteria in planning 

for future BES conditions for their respective footprints, which includes N-0 (no 

contingencies) and N-1 (outage of a single BES element or “single contingency”). 

However, the January 17, 2018 event was an “N-many” condition, due to the numerous 

generation outages during that timeframe. For more information on voltage criteria 

requirements applicable to transmission planners and planning coordinators, see NERC 
Page 39 of 153

Figure 16: Comparison of Transmission Planning Voltage Criteria (Percent) – Low 

Limits for Relevant RC Footprints in the Event Area

The analyses and resulting next-day Operating Plans were completed by late afternoon on 

January 16, and thus could not reflect the significant amount of additional unplanned 

generation outages, derates and failures to start which occurred overnight, and the 

impacts of the higher power transfer levels and decreased system voltage levels resulting 

from those losses.

3. Alerts Issued Before January 17

Taking into account the extreme below average colder temperatures, elevated 

system loads, and unplanned outages that had already occurred, and the extreme 

temperatures and elevated system loads expected to continue, RC operators took the

 

Reliability Standards, Transmission Planning (TPL), TPL-001-4 - Transmission System 

Planning Performance Requirements, Requirement R5 at 7, available at 

https://www.nerc.com/pa/stand/Pages/ReliabilityStandardsUnitedStates.aspx?jurisdiction

=United States
Page 40 of 153

following measures ahead of January 17, 2018:

V. January 17, 2018 Event: Additional Generation Outages, Extreme BelowNormal Cold Weather Conditions, and Wide-Area Constrained Transmission 

System Conditions

A. Extreme Weather and Record Peak Loads

In addition to the arctic air, the weather front on January 14 to 17 brought snow 

and ice to parts of the Midwest, South and East. Temperatures in the Event Area dropped 

far below normal lows, as shown in the tables below. While not record lows, New 

Orleans recorded its lowest temperature in 29 years, while Little Rock, AR experienced 

the lowest temperature in 22 years.

Jan. 14 

Conservative 

Ops SeRC

Jan. 15 

Conservative 

Ops; then Cold 

Weather Alert 

for MISO South 

through18th

Jan. 15 

Conservative 

Ops Alert by 

TVA; Cold 

Weather Alert 

by SPP

Jan.16

SeRC begins 

manning all 

remote CT 

sites 24-7 

(through 19th)

Jan. 16 

9:50 p.m. 

MISO issues 

Max Gen Alert 

for 4-11am on 

1-17
Page 41 of 153

Figure 17: Comparison of Actual Highs and Lows to Average Daily High and Low 

Temperatures, January 16 through January 18, 2018

By early January 17, every Mississippi county reported icy roads. 56F

57 In addition to 

having the potential to freeze certain components of open-frame generating units, the icy

conditions caused the loss of six (3-230 kV and 3-115 kV) transmission facilities, which 

occurred the evening of January 16 and during the early morning hours of January 17 in 

Southern Louisiana, and significantly degraded the transfer capability in that area. 

As shown in Figure 18, most of the affected entities’ peak loads on January 17 

exceeded their forecast 2017-2018 winter peak loads. Further, the January 17, 2018 peak 

loads for both the SPP footprint, and for the MISO South region reached all-time highs 

for the winter season - breaking previous winter peak records, and nearing MISO South’s 

all-time summer peak demand of 32,700 MW. 

 57 Source: The Weather Channel (weather.com) January 17 2018 09:00 P.M. EDT 

(https://weather.com/storms/winter/news/2018-01-14-winter-storm-inga-midwestnortheast-south-snow-forecast-mid-january)
Page 42 of 153

Figure 18: January 17, 2018 Peak System Loads for Relevant Entities

All-Time 

Peak 

Winter 

Loads

Seasonal 

Forecast 2017-

2018 Winter 

Peak Load

Actual 

January 17, 2018 

Peak Load Difference

(MW) (MW) (MW) (%)

MISO BA 

(total)

109,300 103,400 106,100 3%

MISO South

footprint

31,100 28,400 31,582 11%

SoCo BA* 45,900 41,054 41,600 1%

SPP BA 41,500 41,129 43,584 6%

TVA BA** 33,352 31,925 31,640 -1%

 * Actual peak occurred January 18, 2018: 44,400 8%

 ** Actual peak occurred January 18, 2018: 32,509 2%

As frigid air moved into the region, it increased system loads for each of the 

entities. While it is not abnormal for weather patterns to influence hour-by-hour electric 

use, the below-normal temperature pattern resulted in sharp increases in system loads due 

in part to electric heating demands throughout the early morning hours, as shown in the 

following illustration.

Figure 19: January 17, 2018 System Loads and Average Event Area Temperature
Page 43 of 153

B. Growing BES Problems Due to Generation Outages and Derates

• Unplanned generation outages and derates continued

• Throughout the night, MISO focused on meeting MISO South forecast load for 

morning peak (7-8 a.m. CST)

At the time MISO issued the Maximum Generation Alert (as described in section 

IV.C above) for its MISO South region on January 16 at 9:50 p.m. CST, it forecast the 

following operating reserve conditions for the peak hour, from 7 to 8 a.m. CST:

• Forecast load plus operating reserve requirement:57F

58 33,300 MW

• Economic maximum generation:58 F

59

32,891 MW

• Forecast imports into MISO South: 166 MW

• Projected energy shortfall for MISO South: 243 MW

By the start of January 17, 2018, the Event Area, normally rich in generation 

capacity, had lost nearly 22 percent of its approximately 118,000 MW of generation by 

planned and forced outages and derates. MISO South was the hardest hit, with 11,600

MW outaged or derated, while SPP’s southern footprint had approximately 8,300 MW 

outaged/derated. TVA RC had 5,000 MW outaged/derated in its RC footprint, while 

SeRC had only 1,400 MW outaged/derated. 

 

 58 MISO’s operating reserve for its MISO South sub-area is defined in its FRAC as 

equaling the forecast load, plus the single worst contingency in MISO South (normally 

1,415 MW but 1,163 MW on January 17), plus a load forecast uncertainty of 5%. 

59 Includes MISO north-to-south intra-market RDT schedule of 3,000 MW.
Page 44 of 153

Figure 20: Total Generation Outages and Derates Within the Event Area, Beginning 

January 17, by Approximate Geographical Area

However, none of the RC/BA entities had anticipated what was to occur 

overnight—that the Event Area was about to lose a significant amount of additional

generation at the same time that system loads would increase due to severe cold. 

4,000 MW

3,300 MW

1,000 MW

4,100 MW

1,400 MW

3,200 MW

2,900 MW

800 MW

600 MW

2,500 MW

2,500 MW
Page 45 of 153

Figure 21: January 15-19, 2018 – Number of Generation Unit Outages and Derates 

Versus Temperature, by Hour, for Event Area

Through the early morning hours of January 17, as the winter storm and cold weather 

conditions moved across the region, additional unexpected generation outages and 

derates caused BES reserve margins to further decrease. The chart below illustrates the 

trend in total generation outages on January 17, 2018 for the Event Area, which peaked at 

approximately 33,500 MW.
Page 46 of 153

Figure 22: Total Unavailable Generation over Time, for January 17, 2018, by RC 

Footprint

MISO South, especially, could ill afford these outages and derates as it already had lost 

generation output equivalent to approximately 40 percent of its seasonally-forecast winter 

peak load of 29,000 MW by the start of January 17. But by 8 a.m. that same day, MISO

South would lose generation equivalent to nearly 50% of its forecast winter peak load. 

Figure 23: MISO South Region Approximate Generation Outages and Derates at the 

Start of January 17, 2018, and by Hour Ending 8am Central Time

Planned 

Outages

Pre-existing 

Unplanned 

Outages

By Hour Ending 

8am, Additional 

Unplanned Outages Total

(MW) (MW) (MW) (MW)

MISO 

South 4,000 7,600 3,400 15,000

As these additional unplanned generation outages and derates in MISO South 

unfolded in the early hours of January 17 (see Figure 24), MISO realized it had

insufficient available generation capacity to meet its MISO South load (forecast to be at a 
Page 47 of 153

morning peak load level between 7:00 and 8:00 a.m. CST) and would have to rely on 

emergency purchases and north-to-south RDT flows. 

Figure 24: Total Incremental Unavailable Generation in the Event Area for January 

17, 2018

Shortly after MISO’s above-illustrated increase in unplanned generation outages 

and derates, it declared an Energy Emergency Alert (EEA) Level 2, and a Maximum 

Generation Event Step 2 a/b for the MISO South region, due to forced generation outages 

and higher than forecast load.59 F

60 Under this declaration, MISO verified commitment of 

all available resources, and directed load serving entities within the MISO South footprint 

to initiate public appeals for voluntary load reductions, as well as other load management 

steps to reduce system load. At the time MISO issued the EEA Level 2, it forecast the 

following operating reserve conditions for the peak hour, ending at 8 a.m. CST:

 60 Reliability Coordinator Information System (RCIS) log. MISO has specified in 

its protocols certain triggering events that require taking action to prevent uncontrolled 

loss of firm load. In doing so, it has patterned its emergency protocols on the Reliability 

Standard EOP-011-1 – Emergency Operations, which prescribes EEAs to be declared for 

Energy Emergencies. EEA Level 2 declares that load management procedures are in 

effect.
Page 48 of 153

• Forecast load plus operating reserve requirement:60F

61 33,300 MW

• Emergency maximum generation: 29,593 MW

• Forecast imports into MISO South: 3,000 

MW61 F

62

• Projected energy shortfall for MISO South: 707 MW

As part of the EEA Level 2/Maximum Generation Event, MISO sent Load 

Modifying Resources scheduling instructions for 900 MW of load reduction for hour 

ending 7 a.m. through hour ending 10 a.m. Central.62 F

63 At the same time, realizing that 

voluntary load reduction alone might not alleviate the shortfall, MISO contacted Southern 

Company to see if MISO could purchase emergency energy for MISO South to provide 

sufficient supply for the peak hour from 7 to 8 a.m. Emergency purchases from Southern 

Company for the MISO South capacity shortfall would also equally decrease their 

calculated north-to-south RDT.

1. By 2 a.m. CST: BES Transmission Conditions Become a Growing 

Concern

• System loads increasing

• Transmission congestion first occurs

• MISO issues Transmission Loading Relief (TLR)63F

64 for transfers sinking in TVA BA

With increasing generation outages and derates in the Event Area continuing 

through the early hours of January 17, as part of their real-time monitoring of the BES, 

SPP’s operators observed that their real-time contingency analysis (RTCA)64 F

65 results 

began to show intermittent transmission congestion with flows into portions of the south 

central U.S.: simulated post-contingency limit exceedances for two transmission facilities 

in southeast Kansas bordering southwestern Missouri (as shown in the figure below by 

the orange circles). 

 61 See fn. 58.

62 MISO’s north-to-south intra-market RDT schedule of 3,000 MW.

63 Item 9_LMR Performance During January 2018 Maximum Generation 

Event.pdf

64 See Appendix C, “RC and [Transmission Operator] Tools and Actions to 

Operate the BES in Real Time.”

65 See Appendix C.
Page 49 of 153

Figure 25: By 2am CST – BES Transmission Congestion Began to Occur

Southerly Power Flows and Situational Awareness of Conditions

The effects of simultaneous southerly power transfers began to constrain the BES. 

These transfers included MISO’s RDT, which by the start of January 17 was approaching 

2,600 MW (1,000 MW firm transmission capacity and 1,600 as available non-firm 

transmission service). In addition to the RDT flow, the more-southern of the congested 

facilities illustrated above, in southeastern Kansas/southwestern Missouri, was also 

known to be impacted by flows from neighboring non-market areas, as well as SPP and 

MISO wind.65 F

66 Further, the flows on SPP’s transmission facilities in this congested area 

 66 SPP Market Monitoring Unit, State of the Market Winter 2018 at page 32, 

available at https://spp.org/documents/56890/spp_mmu_qsom_winter_2018.pdf.
Page 50 of 153

would have been increased by nearby unplanned generation outages and derates in SPP.66 F

67 

SPP’s operators later performed generation redispatch and discussed the potential need to 

open the congested facilities.67 F

68 

Also near the start of January 17, based on their real-time monitoring of the MISO 

transmission system, MISO RC operators issued a TLR to curtail power transfers with 

non-firm transmission reservations being delivered to TVA BA, because those transfers 

were affecting transmission flowgates in MISO’s Midwest footprint. While MISO’s TLR 

did not have any significant influence on the contingency loading conditions on the 

congested transmission lines shown above, it showed that RC operators were using their 

real-time tools to determine and take appropriate actions, which alleviated transmission 

loadings.6 8F

69

In the early hours of January 17, voltages on the BES were close to what SPP 

typically experienced for prior January days, and prevailing BES voltages across the four

RC footprints were within normal limits (i.e., between 95% and 105% of the “nominal 

voltage”—such as 345 for a 345 kV bus).

Key RC-to-RC Communications 

From the onset of the higher transmission loading conditions, the SPP and MISO 

RC control room operators communicated and took coordinated actions to alleviate 

transmission loading. During the early morning hours of January 17, the operators’ 

communications focused on managing the dispatch of increasing wind generation output. 

MISO’s actual wind generation on January 17 substantially exceeded its forecast, as the 

following graphic shows.

 67 Southwestern Missouri had over 750 MW of unavailable generation during the 

Event. Transmission flows to serve SPP’s firm network transmission customer loads in 

that area would have contributed to the congested flows. 

68 3:53 am call transcript.

69 See Appendix C. Under the mandatory Reliability Standards, each RC (e.g., 

MISO, SPP, TVA, and SeRC) shall ensure that a real-time assessment is performed at 

least once every 30 minutes, for the purpose of prevent BES instability, uncontrolled 

separation, or cascading. IRO-008-2, Requirement R4. Transmission Operators have a 

similar requirement to perform real-time assessments, under TOP-001-4, Requirement 

R13.
Page 51 of 153

Figure 26: MISO Wind Forecast Versus Actual for Winter 2017-2018

Beginning at 1:04 a.m. CST, in an effort to effectively dispatch increasing wind 

generation output while avoiding transmission overloads, MISO and SPP RC operators 

agreed to activate market-to-market binding constraints on several wind-affected 

flowgates. As the output of wind generation increased, the RC operators continued close 

coordination in managing these flows throughout the morning hours. 

At 1:29 a.m. CST, MISO, SPP, TVA RC, and SeRC, among other RCs, held a 

normally-scheduled conference call to discuss daily outlook conditions. Both MISO and 

SPP predicted that their load for the January 17 morning peak (7 a.m. – 8 a.m. CST) 

would exceed their historic winter peak loads. The MISO South RC operator explained 

that MISO South was “at the point where we have no reserves” and that MISO would be 

asking to exceed the RDTL of 3,000 MW and seeking energy from its neighbors, 

especially Southern Company, because transfers from Southern Company provided onefor-one credit when calculating the RDT.6 9F

70 SeRC and TVA RC reported that they were 

in conservative operations. SPP reported its projected morning peak load of 42,500 MW 

 7020180117 0229 Call transcript.
Page 52 of 153

would exceed its all-time winter peak by five percent, and that it had sufficient reserves 

to cover its forecast peak.

MISO measured its RDT flow by two methods, in real time using load and 

generation telemetered values sourced from State Estimator (often referred to by MISO 

and SPP as “raw”), and through its Unit Dispatch System (UDS), which runs every five 

minutes for the upcoming five minute interval (looking 10 minutes out). According to 

the Regional Transfer Operations Procedure in effect during the Event (RTO-RTOAOP1-r0 (effective date February 1, 2016)), MISO operators would track, and act on, the 

UDS rather than the real-time measurements. On January 17, MISO’s real-time/raw and 

UDS RDT flow measurements diverged substantially at times. For example, at 2 a.m., 

the real-time RDT was approximately 2,700 MW in a north-to-south direction, but only 

2,183 according to the UDS.

2. By 6 a.m. CST: BES Energy Emergency and Wide-Area Constrained 

Transmission Conditions 

• Unplanned generation outages and derates continued, as temperatures reached 

their lowest levels

• System loads increased as the forecast morning peak load approached

• Stranded reserves in northern MISO, RDT flows increasing

• MISO declared Energy Emergency, arranged emergency purchases

• Increasing wide-area transmission congestion

• Transmission reconfiguration steps taken to address some congested facilities

• For other congested facilities, RC operators relied on post-contingency firm load 

shedding 

• BES voltages trending lower
Page 53 of 153

Figure 27: By 6 a.m. CST – Unavailable Generation, Total and as a Percentage of 

Event Sub-Area Capacity

Figure 28: By 6am CST, Total Generation Outages and Derates Within the Event 

Area, by Approximate Geographical Area
Page 54 of 153

Deliverability of MISO reserves

As described earlier, when MISO declared an EEA Level 2/Maximum Generation 

Event Step 2 a/b, it allowed MISO to call upon Load Modifying Resources to effectively 

reduce MISO South system load. By 5 a.m. CST, MISO’s RDT real-time metered70F

71 flow 

reached 3,000 MW, just as MISO’s RC operators had predicted on the 1:29 a.m. CST 

scheduled RC conference call described above. MISO’s overall Balancing Authority 

Area footprint had sufficient reserves available; however, increasing their RDT scheduled 

flow to aid in providing reserves for MISO South meant exceeding the north-to-south 

scheduling limit (RDTL) agreed upon with the Joint Parties, and contributing to the widearea constrained transmission system conditions. The result was that MISO had reserves 

that were stranded in its northern footprint, limited by transmission system constraints. 

Because MISO could not reliably provide reserves from its Midwest to its South region 

without exceeding the RDTL, at 5:04 a.m. CST, MISO asked SPP to agree to raise the 

RDT north-to-south limit above 3,000 MW.71 F

72 At 5:14a.m. CST, MISO declared a 

Maximum Generation Event Step 2 c/d72 F

73 for the MISO South region, justified by forced 

generation outages and higher than forecast load.73F

74 At the time MISO made this 

declaration, it forecast the following operating reserve conditions:

• Peak hour for MISO South sub-area (hour-ending): 08:00 CST

 71 MISO’s RDT flow is metered by using the net actual interchange flow for the 

MISO South footprint, as a means to track their performance in meeting their RDT 

scheduled flow.

72Under the version of the Regional Transfer Operations Procedure in effect during 

the Event, a party could request a temporary increase or decrease in the RDT to avoid a 

system emergency, or address emergent or actual system emergencies. Version RTORTOA-OP1-r0, section 3.3.1. See page 71 for SPP’s response.

73 Maximum Generation Event steps c and d allowed MISO to: 

• Make emergency energy purchases from neighboring BAs through existing 

Emergency contractual agreements in order to conserve Operating Reserves

• Requested load serving entities to enact load modifying resources to now 

include issuing public appeals to reduce demand per their internal procedures. 

74 Source: Reliability Coordinator Information System (RCIS) log. 
Page 55 of 153

• Forecast load plus operating reserve requirement:74F

75 33,300 MW

• Emergency maximum generation: 32,000 

MW75 F

76

• Forecast imports into MISO South: 800 MW

• Projected energy shortfall for MISO South: 500 MW

Increasing Wide-Area Constrained Transmission Conditions

As simultaneous north-to-south flows increased to offset generation outages and 

derates and meet the increasing system electricity demands and MISO’s RDT flow, 

transmission loading conditions and constraints began to increase in number and severity, 

across a wider area. From 2 a.m. to 6 a.m. CST, the constrained transmission conditions 

spread across three RC footprints and five U.S. states. Market-based generation 

redispatch within MISO and SPP was still being used by the RC operators on a precontingent basis as a means to reduce transmission overloads as they arose, including in 

the southeastern Kansas/southwestern Missouri area. During this time, SPP and TVA 

RCs used generation redispatch to mitigate more than a dozen post-contingency 

overloads ranging from 115 to 345 kV. TVA and SPP RC operators, in agreement with 

the relevant TOPs within their footprints, coordinated their use of transmission 

reconfiguration to address both real-time and post-contingency limit exceedances during 

this timeframe. By 4 a.m., there were numerous additional areas where transmission 

congestion occurred over a wide geographic area within the MISO, SPP, and TVA RC 

footprints, in Kansas, Kentucky, Louisiana, Mississippi, Missouri, Oklahoma, and eastern 

Texas, as illustrated below:

 75 See fn. 58. 

76 Includes MISO north-to-south intra-market RDT schedule of 3,000 MW.
Page 56 of 153

Figure 29: By 4 a.m. CST – Numerous Additional Transmission Constraints for 

Wide-Area of South Central U.S.

Critical Role of Accurate Facility Ratings

Opening a BES transmission facility (transmission reconfiguration) to alleviate an 

actual overload, or to prevent a post-contingency limit exceedance, is one of the more 

consequential operator actions. Generally, except for planned maintenance, new 

construction, or to aid in restoration from an outage, transmission facilities are not 

reconfigured (e.g. opened). On the morning of January 17, as southerly simultaneous 

transfers placed unpredicted additional loading on the transmission system,76 F

77 operators 

began studying the option of transmission reconfiguration to address system overloads. 

As RC operators acted to manage congestion via methods such as generation redispatch, 

they noted that some of the power flows would approach the facilities’ respective SOLs

intermittently, and then decrease in flow. But over time, the operators found that some 

 77 The southeastern Kansas/southwestern Missouri congested facility was 

projected only to be at 80% loading, not congested, based on SPP’s day-ahead 

Operational Planning Analysis for January 17, 2018.
Page 57 of 153

facilities ceased the intermittent flow patterns previously described, and their actual flows 

remained near their SOLs, which required additional operator action. The rising power 

flows caused the RC operators to study the opening some of these facilities; but before 

taking action, the RC operators verified flows and their associated SOLs.

The RCs were using SOLs based on transmission facility ratings established by the 

Transmission Owners.77 F

78 For the most part, these ratings reflected the expected ambient 

conditions (i.e., winter/low ambient temperatures). In general, using SOLs based on the 

colder temperatures afford more capacity to transfer needed power to locations within the 

Event Area. 78F

79 For example, Southern Company enabled SeRC to have what it called

“dynamically rated” transmission lines, based on the extremely cold weather, which 

effectively raised the SOLs, allowing more power to reliably flow.79F

80 Had SeRC used 

static limits (e.g., year-round/summer limits), it would have needed to employ significant 

generation redispatch (detrimentally impacting BA contingency reserves), possible 

transmission reconfiguration, and/or TLRs.

However, SPP monitored flows on certain facilities in the Event Area using SOLs 

that were based on average ambient conditions (warmer weather) rather than on the 

 78 Under the mandatory Reliability Standards, each Transmission Owner is 

required to have facility ratings based on their methodology, which includes 

consideration of “ambient conditions (for particular or average conditions or as they vary 

in real-time).” FAC-008-3 – Facility Ratings. These facility ratings form the basis for 

the RCs’ SOL methodologies for the operating horizon (FAC-011-3), which is required 

to be used by Transmission Planners (TPs) and Transmission Operators (TOPs) in 

establishing SOLs. FAC-014-2. 

79 Some SOLs are based on facility ratings of transmission line equipment which 

is located at the termination points of the transmission line (e.g., protection systems), and 

do not vary based on the ambient conditions. Transmission Owners commonly strive to 

upgrade this terminal equipment so that it does not result in limiting the full utilization of 

the capacity of overhead transmission line investment.

80 Southern Company dynamically rated the lines by applying temperatureadjusted limits that were based on the facilities’ ratings for 30 degrees, instead of using 

static winter limits, due to the extremely cold weather during the Event. These ratings 

better-reflected the current ambient conditions (e.g. 16 degrees for one facility).
Page 58 of 153

colder weather conditions of January 17.8 0F

81 On the morning of January 17, to address the 

constrained system conditions, SPP operators consulted with their TOP operators to 

verify these SOLs to aid in determining potential mitigation measures. If the ratings and 

SOLs had reflected cold weather ambient conditions, SPP may have been able to avoid 

some of the generation redispatch and transmission reconfiguration measures they took 

on the morning of January 17.81 F

82 

In addition to using appropriate SOLs, system operators must carefully study the 

potential outcomes before using transmission reconfiguration, to ensure that 

reconfiguring one facility does not place the BES in a less reliable state, such as by 

shifting the power flow and overloading other BES transmission facilities, or contributing 

to localized low voltage conditions on the sub-transmission system. The Team reviewed 

documentation showing that the RCs performed one or more studies before using 

transmission reconfiguration. For example, during the 4 to 6 a.m. timeframe, TVA RC 

operators observed that a heavily-loaded transmission facility in northeastern Oklahoma 

approached 100% of its pre-contingency limit.82F

83 TVA RC analyzed the situation and 

worked with the local TOP to perform transmission reconfiguration to alleviate the 

overload. 

 81 Within a week of the Event, the following were daytime high temperatures for 

select cities within the Event Area:

• Kansas City: 64 degrees, on January 21, 2018

• Springfield, MO: 70 degrees, on January 21, 2018

• Tulsa, OK: 70-72 degrees, on January 20-21, 2018

• Little Rock, AR: 66 degrees, on January 21, 2018

82 The Team noted that for several facilities, including the southeastern 

Kansas/southwestern Missouri mentioned earlier, the transmission facility limits the 

operators were using reflected lower summer season limits, versus ratings one would 

expect to see for winter ambient temperature conditions, which normally allow for higher 

power transfers to occur. 83 Even though this facility had a relatively low limit for a 138 kV facility due to a 

relay limitation (114 MVA, which was especially low as compared to a conductor 

limitation for the prevailing colder weather conditions), the RC operators were required 

to operate the BES to the limits set by the Transmission Owner, and to take actions 

necessary to maintain reliability. 
Page 59 of 153

Between 4 and 6 a.m., the RCs had nearly exhausted their less-consequential

options, yet system loads and transmission congestion continued to increase. TVA and 

MISO RCs issued two TLRs to curtail non-firm transmission schedules for flowgates in 

Kentucky and western Missouri. As generation outages and derates continued to rise, 

and system loads increased in MISO South, operators had fewer options for generation 

redispatch to alleviate a growing number of post-contingency limit exceedances. 

Because BES conditions were so constrained at the time, MISO and the MISO South 

TOPs agreed to continue operating with the then-existing post-contingency overloads, 

when normally MISO would have taken mitigating measures in real time, such as 

redispatching generation or reconfiguring transmission facilities, to bring the facilities’ 

post-contingency loading below 100%. MISO and the TOPs agreed instead that if any 

facility was lost, immediate load shed would be required. For more severe postcontingency overloads, before relying on post-contingency load shed, MISO analyzed 

whether the SOL was an IROL, to rule out the need for pre-contingency load shed. SPP 

also had transmission facilities for which post-contingency load shed was the only option, 

due to similar conditions of area generation outages and derates, and elevated system 

loads. By 6 a.m., SPP had five transmission facilities located mostly in Oklahoma and 

Texas, and MISO had 18 facilities located in Louisiana and Mississippi, for which the 

RCs and TOPs had agreed to post-contingency load shed plans to alleviate postcontingency flow limit exceedances. 
Page 60 of 153

Figure 30: By 6am Central – Further Transmission Constraints Occurring Over a 

Wide-Area of South Central U.S. 

BES Voltage Patterns

During the early morning hours, RC operators monitoring BES transmission 

flows, congestion, and voltages noted a lower voltage level pattern in certain locations 

within the Event Area, compared to what they typically would experience on high load 

days in January. While BES voltages predominantly remained within limits across the 

Event Area from the start of January 17 until approximately 5 a.m. CST, EHV real-time 

bus voltages for certain areas had decreased as compared to midnight, as shown in the 

chart below. 
Page 61 of 153

Figure 31: 5am Central: Decrease in Southwestern-to-Southeastern Oklahoma 

345kV Bus Voltages, Early Morning Hours of January 17, 2018

By 5:57 a.m. CST, one of MISO’s 500 kV busses dropped below 97.5%, and remained 

below this level for approximately four hours. Its lowest level was 96.2%. 

Key RC-to-RC Communications

During this early-morning timeframe, on a regularly-scheduled conference call 

among MISO, SPP, TVA RC, SeRC, and other Eastern Interconnection RCs, the MISO 

operator warned that MISO South was “about tapped out,” and that MISO was 

contemplating the issuance of a Max Gen Alert/EEA 1, at which point it would “curtail 

interruptible loads” and “would be asking the parties to the transfer agreement . . . if we 

could go above that 3,000 MW transfer limit which we’re pretty close to right now.” 

MISO noted that it had just lost an “800 MW unit which . . . was our cushion,” and that 

“we’re . . . at the point where we have no reserves and we would be . . . asking neighbors 

for help.” MISO said it would try “to import as much from Southern [Company] as 

possible because it’s a one-to-one credit on our [RDT] transfer agreement.” 

MISO and SPP RC Operators communicated regularly and cooperated to mitigate 

system conditions during the early morning hours leading into the peak. For example, at 
Page 62 of 153

2:58 a.m. CST, SPP and MISO RC operators spoke by phone to discuss the status of their 

congestion management efforts. The MISO operator asked about the southeastern 

Kansas/southwestern Missouri congested flowgate and SPP responded that it was close to 

overloading in real time and had been “near the top” of its simulated post-contingency 

loading for an extended period. SPP indicated that it would need to open the flowgate if 

it were to suffer the outage of the next most-severe contingency. The MISO operator 

offered to activate/bind the constraint and perform market-to-market redispatch between 

SPP and MISO, in an effort to alleviate loading conditions on SPP’s congested 

flowgate.83F

84

At 5:04 a.m. CST, MISO emailed SPP, TVA and Southern Company, asking to 

raise the RDT north-to-south limit above 3,000 MW (as its operator had earlier 

predicted), although the RDT would not exceed 3,000 according to the UDS until 7 a.m. 

In support, MISO noted:

MISO is in extremely tight conditions and is forecasting an expected 

Winter peak for the South Region of 33,911 MW for Hour Ending 0800. 

Previous Winter peak is 30,930 MW.

MISO has declared a Max Gen Event step 2a-b and a NERC EEA level 2 –

due to [the loss of] a number of units (~3,000 MW) and transmission lines 

over the evening hours due to the cold weather and icing conditions.

MISO is expecting the Regional Directional Transfer to be maximized 

flowing from North to South at the 3,000 MW limit and possibly exceeding 

the limit of 3,000 MW. Please consider that MISO has limited ability to 

reduce the flows on the RDT and would like for all to consider raising the 

limit.84 F

85

At 5:33 a.m. CST, as the morning peak hour (7 to 8 a.m.) approached for MISO 

South, MISO made an official request for emergency energy assistance to SeRC for the 

purpose of meeting its forecast load plus reserves obligations. Southern Company agreed 

to provide 700 MW of emergency purchase for a 4 hour period. For approximately an 

hour, MISO BA coordinated with Southern Company BA arranging for the purchase to 

start at 6:30 a.m. CST, in time for peak hour conditions.

At 5:39 a.m. CST, the MISO South operator informed SPP that the RDT was at its 

limit and asked about SPP’s system conditions. The SPP operator noted that SPP had 

multiple flowgates with post-contingency overloads, and one real-time overload (which 

 84 20180117 02:58 CST Call from MISO North to SPP RC.

85 Email from MISO to TVA, SPP and Southern. See page 71 for response.
Page 63 of 153

was mitigated by operator actions as described below). MISO told SPP that it was 

purchasing emergency power from Southern Company, and should SPP experience 

emergency conditions, MISO was prepared to take actions necessary to reduce the RDT. 

SPP indicated that it was not yet experiencing emergency conditions. Within five 

minutes, the MISO South RC operator had discussed the same information with TVA RC 

and SeRC. The Regional Transfer Operations Procedure in effect at the time did not 

clearly address specific actions to be taken when RDT flows were affecting adjacent

RCs.85 F

86 

Figure 32: MISO Regional Directional Transfer – January 17, 2018

 86 As a result of the Event, MISO, SPP, TVA and SeRC revised the Regional 

Transfer Operations Procedure; the revised version became effective in December 2018.
Page 64 of 153

3. By 8 a.m. CST: MISO Energy Emergency Continues and Four RCs 

Take More Consequential Steps to Maintain BES Reliability 

• System loads continued to increase as the morning load peaked from 7 to 8 a.m.

• RDT peaked at nearly 1,000 MW over the RDTL

• MISO South received emergency energy from Southern Company and TVA BA

• Additional transmission reconfiguration/more consequential operator steps

• Many next-contingency conditions that would lead to firm customer load shed in 

MISO South and SPP

System operators were already facing dozens of post-contingency overload 

conditions as discussed above, but system loads were still increasing due to the severe 

low temperatures and the approaching morning peak load. Market redispatch or 

additional non-firm transmission interchange curtailment such as TLRs were lessavailable options during this timeframe, due to the excessive generation outages and 

derates in the Event Area. 

As for more consequential overload mitigation actions, several transmission 

facilities were opened in addition to TVA RC’s earlier transmission reconfiguration. SPP 

RC and its TOP operators agreed to reconfigure the southeastern Kansas/southwestern 

Missouri congested flowgate that had been studied multiple times during the Event, due 

to the actual/real-time loading of the facility now remaining above 100% of its normal 

limit of 203 MVA.86 F

87 Also, based on SPP RC’s additional study87 F88 to prepare for 

transmission reconfiguration, SPP and the TOP agreed to open the other facility in 

southeastern Kansas that had post-contingency overloads showing up in RTCA since late 

in the evening of January 16. The final decision to open the second southeastern Kansas 

facility was due to its actual/real-time loading intermittently exceeding its normal limit of 

167 MVA at 5:15. 88F

89 TVA RC operators worked with AECI TOP to reconfigure a 161 

 87 The Team noted that for this 161 kV facility, the transmission facility limits the 

operators were using reflected summer season limits (lower limits) versus winter ambient 

temperature conditions, which may have not required the RC operators to perform 

transmission reconfiguration.

88 SPP RC performed contingency analysis study at 7:07 a.m. CST, evaluating 

reconfiguration of this facility, and the study showed no resultant real-time SOL 

exceedances.

89 The Team noted that for this 161 kV facility, the transmission facility normal 

and emergency (post-contingency) limits were of equal value. While this is a possibility 

for terminal-limited transmission lines, Transmission Owners typically address those 
Page 65 of 153

kV facility in southwest Missouri because its real-time loading exceeded 100% of its 

normal limit. By 8 a.m. CST, three other facilities remained open from earlier operator 

actions, and five others (one in TVA RC, four in Southeastern RC footprints) had postcontingency plans for reconfiguration. MISO operators, out of reserves in MISO South 

and prepared to shed firm load throughout MISO South for the WSC in MISO South, also

had over 20 transmission facilities for which localized load shed would be necessary 

should the next contingency occur, all of which were in Louisiana and Mississippi, where

MISO had suffered generation outages, derates, and failures to start. Approximately 20 

of these facilities would require localized load shed if the same contingency (the MISO 

South WSC) occurred, while approximately six more facilities would require localized 

load shedding if additional contingencies occurred.

EHV real-time bus voltages trended downward between midnight and 6 a.m. in 

the southern Oklahoma portion of SPP’s footprint, as shown in Figure 33 below. 

Figure 33: 6am Central: Further Decrease in Southwestern-to-Southeastern 

Oklahoma 345kV Bus Per Unit Voltages, Early Morning Hours of January 17, 2018

 

limitations early on to ensure they can achieve maximum value of their transmission 

facility investment to serve customers’ needs. The Team also noted these limits reflected 

summer season limits (lower limits) versus winter ambient temperature conditions, which 

may have not have required the RC operators to perform transmission reconfiguration.
Page 66 of 153

However, for the most part, EHV voltages in Arkansas, Louisiana, and Mississippi 

remained close to their nominal levels (i.e. 100% or 1 p.u.), as shown in figure 34 below. 

Figure 34: BES Pre-Contingency Voltage Conditions (P.U.) for Select EHV Buses, 

January 17, 2018, Approximately 6am CST

Both SPP and MISO experienced low real-time BES voltages for several rural 

locations in southeastern Oklahoma, southern Arkansas, and Louisiana, as shown in 

Figure 35. 

0.98 115 kV 

1.013 500 kV 0.999 500 kV 

0.993 500 kV 

1.027 500 kV 

500 kV 

500 kV 345 kV 

345 kV 

345 kV 

345 kV 1.038

1.017

0.992

0.976

0.988

0.988

0.962 500 kV 
Page 67 of 153

Figure 35: BES Voltage Conditions (P.U.) for High Voltage Buses below Normal 

(Pre-Contingency) Limits, January 17, 2018, Approximately 6am CST

It was clearly evident that real-time BES voltages were decreasing in some areas

throughout the early morning hours of January 17, as shown in Figure 33. However, for 

the most part, EHV voltages remained near nominal levels, as shown in Figure 34. 

Furthermore, SPP and MISO experienced real-time voltages below 95% at several rurallocated BES facilities in eastern Oklahoma, Arkansas, and Louisiana (ranging from 92% 

to 94% for several 115kV and 138 kV buses) as shown in Figure 35, as well as rural subtransmission facilities (e.g., 69 kV) in southern Oklahoma and eastern Texas.89 F

90

 90 After review of similar rural location voltage data for the day before the event, 

the Team could not attribute all of SPP’s rural location simulated post-contingency 

voltages to increased power transfers such as the RDT. Nonetheless, SPP identified 

mitigation measures (e.g., post-contingency capacitors for voltage correction) to address 

the conditions.
Page 68 of 153

Impact of MISO South WSC for Both Reserves AND Number of Transmission 

Voltage Limit Exceedances 

For the morning of January 17, the MISO South WSC outage of a single 1,163-

MW unit would have left MISO South without adequate generation supply and also 

would have resulted in the most BES facility post-contingency low voltages (nine 115 kV 

buses, eight 230 kV buses, and three 500 kV buses) within MISO South, based on 

MISO’s RTCA (as compared to the results of any other single simulated contingency). 

Figure 36: BES Post-Contingency Range of Voltages below Limits for Buses in 

MISO South, January 17, 2018, at Approximately 06:30am CST, for the Simulated 

Outage of the MISO South WSC 

While it is important to note that the lowest BES voltages on MISO South buses 

identified in MISO’s RTCA for the simulated loss of the MISO South WSC were 

predominantly located in suburban areas of southeastern Louisiana and southwestern 

Mississippi (north of the urban centers and the industrial corridor in southeastern 

Louisiana), MISO’s 500 kV network simulated post-contingency voltages were also 

indicating lower voltages, as shown below. The MISO RC analyzed and discussed its 

RTCA post-contingent thermal and voltage violations with its TOP system operators, and 

they agreed on the post-contingent mitigation measures that would be taken in the event 

of the actual loss of the 1,163 MW generating unit.

Number Lowest Highest

of Buses P.U. Voltage P.U. Voltage Mitigation Plan

115kV: 9 0.860 0.964* Post-contingency load shed

230kV: 8 0.880 0.913 Post-contingency load shed

500kV: 3 0.899 0.948* Post-contingency load shed

* Monitoring based on nuclear power plant voltage limits.
Page 69 of 153

Figure 37: BES Post-Contingency Voltage Conditions (P.U.) Below Limits for EHV 

Buses in MISO South, January 17, 2018, at Approximately 06:30am CST, for the 

Simulated Outage of the MISO South WSC

The MISO RC analyzed and discussed its RTCA post-contingent thermal and 

voltage violations with the local TOPs’ operators and developed post-contingent action 

plans. For the loss of the MISO South WSC, there were no unsolved contingencies 

within the MISO RTCA. This indicated to the MISO operators that upon the loss of any 

contingency, the area load pockets would remain stable and allow operators the time to 

implement post-contingent load shed to address each next contingency on a case-by-case 

basis. SPP also included the MISO South WSC in its RTCA, and relied on the fact that 

its RTCA case converged as an indicator of voltage stability.90 F

91

 91 SPP’s post-contingency results did not indicate any resulting low BES voltages 

within its footprint, but did confirm low voltages at the same buses in the MISO South 

region as projected by MISO’s RTCA.
Page 70 of 153

While winter season peak electricity demands in general impose less reactive 

power demand on the BES than summer peak conditions, and urban centers are generally 

less susceptible under winter peak load conditions to voltage instability than during 

summer peak load conditions, the loss of the MISO South WSC during the morning peak 

on January 17, 2018 would have added stress to an already-constrained system, due to the 

large power transfers needed to compensate for the unplanned generation outages and 

derates. Any replacement generation would necessarily have been transferred from 

MISO Midwest, thereby further increasing RDT real-time transmission flows into MISO 

South through SPP, TVA RC and SeRC footprints. MISO’s RTCA showed 

progressively worsening projected post-contingency voltage results, including voltages as 

low as 88% on certain 230kV buses, and 20 transmission facilities with projected postcontingency thermal overloads between 7 and 8 a.m. CST.

Additionally, the loss of the MISO South WSC would have further lowered the 

already-depressed area voltages to a point where voltage stability could have quickly 

become a concern. Further, had MISO and its TOPs failed to timely perform the postcontingency manual firm load shed on which they were relying to restore voltages before 

another contingency occurred, voltage(s) could have decreased even more. While the 

MISO RC operators would be trying to coordinate load shed with the TOPs to restore 

voltages, they would concurrently have been faced with the likelihood of an EEA Level 3 

for the loss of the MISO South WSC, causing them to simultaneously perform MISO 

South-wide firm load shed to meet load and restore reserves for MISO South. 

Neither MISO nor SPP performed voltage stability analysis for the simulated loss 

of the MISO South WSC that morning.91 F

92 MISO had online voltage stability tools, and 

SPP could have performed an offline study, however, preparing its offline study could 

have taken several hours and thus not provided timely results for the RC operators that 

morning. Voltage stability studies could have aided MISO and SPP in determining 

whether SPP needed to declare a system emergency and whether MISO needed to take 

pre-contingency steps to position their systems for the potential loss of the MISO South 

WSC. MISO was relying on the TOPs within its footprint to be able to promptly execute 

the necessary load shed to alleviate the numerous low voltages, if the MISO South WSC

had occurred. Voltage stability analysis would be especially important given that MISO 

recognizes that one of its load pockets is “a voltage/thermal sensitive area and is 

susceptible to low voltages under outage conditions or a loss of a key transmission 

 92 While voltage stability analysis is not specifically required by the Standards, 

RCs and TOPs are required to perform a real-time assessment which evaluates system 

conditions using real-time data to assess existing (pre-contingency) and potential (postcontingency) operating conditions. IRO-008-2, and TOP-001-4.
Page 71 of 153

element.” Sharing the voltage stability analysis with adjacent RC operators would give 

them another source of simulated post-contingency voltage data to determine if additional 

pre-contingency protective measures are needed.

Key RC-to-RC Communications

MISO’s RDT flow hit its peak of 4,331 MW by real-time measurement, and 

nearly 4,000 MW as calculated by UDS, at approximately 6:30 a.m. MISO had already 

arranged 700 MW of emergency energy from Southern Company, but based on the latest 

projected supply and demand conditions in MISO South for the upcoming peak hour, 

beginning at 6:12 a.m. CST, MISO sought additional emergency energy from Southern 

Company, as well as from SPP and TVA BA. TVA BA had 300 MW emergency power 

available, and TVA BA and MISO arranged for its delivery, for a total of 1,000 MW the 

emergency power obtained ahead of the peak hour.92 F

93 MISO’s EMS automatically 

allocates the emergency purchases between MISO’s North and South regions when

calculating the RDT, taking into account transmission distribution factors. MISO 

expected the emergency purchases made for MISO South reserves to decrease the RDT, 

and shared this expectation with other RC operators. This expectation proved correct 

when the RDT did begin to decrease just after emergency power deliveries began. 93F

94

Just before the peak hour, SPP RC denied MISO’s request to raise the RDT limit 

above 3,000 MW via email, and shortly thereafter, SPP notified MISO that it had 

emergency power available, but it was not deliverable to MISO South. 

LMRs to Aid MISO South During Peak Load Conditions

As part of MISO’s Maximum Generation Emergency/ EEA-2 procedures, MISO 

sent LMR94F

95 scheduling instructions (SI) for load reduction to help cover their MISO 

South peak load. MISO sent the SI just after MISO’s declaration of EEA Level 2. The 

Team learned that the LMRs were not obligated to be available in the winter (only 

required in the summer season), and that long notification times limited the availability of 

some LMRs for the morning peak. MISO deployed a total of 700 MW of LMR on 

 93 In response to MISO’s request for additional emergency energy above the 700 

MW from Southern Company, Southern Company assisted MISO in obtaining an 

additional 150 MW of emergency energy from Southern Company BA during the peak 

hour.

94 See Figure 32.

95 See fn. 14.
Page 72 of 153

January 17, but was able to increase its LMR to 930 MW by providing notice well in 

advance of the morning peak on January 18.95 F

96 

4. Post-8 a.m.-peak hour: Conditions Gradually Improve 

• System conditions improved after morning peak, as load demands dropped from 

peak levels

• Generation conditions improved as units returned to service with rising 

temperatures

• SPP wind generation decreased sharply after morning peak conditions

• SPP EHV voltages returned to more typical levels 

• Many pre- and post-contingency measures remained in effect

• MISO again sought emergency power as it prepared for evening peak

After the morning peak on January 17, MISO South operators began to focus on 

evening peak reserves. MISO was still projecting the evening peak to be short of the 

necessary reserves for MISO South. Before 10 am, MISO RC Operators asked Southern 

Company if MISO could continue emergency energy purchases for the evening peak. 

MISO reduced its emergency energy to 350 MW until 1:30 p.m., after which it sought 

additional emergency energy for the evening peak (predicted to occur between 7 and 10 

p.m. CST) from SPP, Southern Company and TVA BA. MISO briefly dropped down to 

EEA Level 1, returning to EEA Level 2 just before 2 p.m., when it declared Maximum 

Generation Event Step 2a/b and EEA Level 2 for MISO South effective 7 p.m. until early 

the morning of January 18. MISO finally dropped back down to EEA Level 1 at 

approximately 8 p.m. System conditions improved primarily due to the return of some of 

the generation units which had not been available during the early morning hours. 

By 10 a.m. CST, SPP’s EHV voltages returned to more typical voltage range for 

those locations. For example, the following chart shows a comparison between earlier 

morning real-time voltage levels and those measured at approximately 10 a.m. CST, for 

southern Oklahoma EHV locations:

 96https://cdn.misoenergy.org/2018%20IMM%20Quarterly%20Report%20Winter1

62312.pdf; Appendix I.
Page 73 of 153

Figure 38: 10 am CST: Improvement in Southwestern-to-Southeastern Oklahoma 

345 kV Per Unit Bus Voltages, Early Morning, January 17, 2018

TVA BA declared a Power Supply Alert I in effect for its Balancing Authority 

area, and later declared EEA Level 1, which it exited by 1 p.m. TVA BA experienced its 

winter peak load on January 18, one day later than MISO and SPP, as the cold front 

moved northeast. 

All six MISO South transmission facility outages (3-230 kV and 3-115 kV), which 

were caused by freezing rain, returned to service by the end of the day:

o 2-230 kV lines were restored by January 17, 11:07 a.m. CST,

o 2-115 kV lines were restored by January 17, 11:18 a.m. CST, and

o the two remaining transmission facilities were restored by 11:46p.m.

CST.

Post-contingency overload conditions began to shift further east as the cold front 

moved, occurring more in Missouri, Tennessee and eastern Mississippi. However, many 

pre- and post-contingency measures already taken remained in effect in SPP, MISO and 

TVA RC. As new constraints occurred, the RCs coordinated well to manage system 

conditions. SPP developed post-contingent load-shed plans at four facilities in Oklahoma 

and Louisiana, as well as plans for post-contingent redispatch coordinated among SPP 

and TVA. MISO and TVA RC took mitigation actions via transmission reconfiguration 
Page 74 of 153

in Mississippi to alleviate a real-time overload as well as a simulated severe postcontingency condition.

MISO’s wind generation output continued to rise, reaching a record peak of 

15,038 MW on January 17.96F

97 SPP’s wind generation output decreased significantly just 

after the morning peak load, from 10,000 MW to 8,000 MW, and remained at around 

8,000 MW until just before evening peak, when it sharply increased to almost 13,000 

MW (95% of its all-time peak wind generation output), and remained at that output the 

remainder of January 17.

Figure 39: MISO and SPP Wind Output, January 16 Through 19, 2018

 97 MISO’s previous wind generation peak of 14,683 MW was set in December, 

2017. The January 2018 record was broken in March 2019, with 16,317 MW of peak 

wind generation output.
Page 75 of 153

VI. Post-Event Actions by the RCs and Joint Parties

A. RTOC Meetings and Entities’ Report

On March 15, 2018, MISO, SPP, TVA and SeRC met to discuss the event, lessons 

learned and ways to increase coordination among the four Reliability Coordinators.97 F

98 

The Regional Transfer Operating Committee (RTOC), a six-member committee which 

includes two members each for MISO, SPP and the Joint Parties, 98F

99 met at least three 

times before providing a report to the Team in September, 2018, and continued to work 

on action items identified in the September report.99 F

100 Among the action items identified 

by the RTOC were four aspects of improving coordination as to the RDT, which 

ultimately culminated in a new RDT procedure, as well as a written “statement of 

understanding” about interim and long-term methods of addressing RDT-impacted 

flowgates, as discussed in section C, below. 

 

B. FERC Tariff Change on Deliverability of Reserves100 F

101

On April 27, 2018, MISO filed proposed revisions to its Tariff to authorize the 

application of the Tariff’s reserve procurement enhancement provisions to the Sub-

 98 Although the Regional Transfer Operations Procedure in place during the Event, 

RTO-RTOA-OP1-r0, provided for a formal “Operations Review” upon request by one of 

the RCs under circumstances including when an increase in the RDTL had been 

requested (section 3.4), the Joint Parties did not characterize their report as resulting from 

a formal “Operations Review,” but it accomplished the purpose of analyzing the event 

and agreeing on next steps. The RTOC’s post-event analysis, “Regional Transfer 

Operating Committee Event Review Report (September 9, 2018),” is included as 

Appendix I.

99 The Joint Parties include AECI, LG&E/KU, PowerSouth, Southern Co. and 

TVA.

100 See Appendix I.

101 Prior to the Event, MISO had initiated the Resource Availability and Need 

(RAN) initiative, a broad analysis and plan to confront the increase in Maximum 

Generation emergencies even though sufficient capacity appeared to be available through 

the Planning Reserve Auction. The RAN initiative has led to several filings, including 

some of the filings described below, aimed at improving capacity availability in all 

seasons.
Page 76 of 153

Regional Power Balance Constraints (MISO’s internal name for the RDTL). The 

Commission accepted MISO’s filing, effective August 26, 2018.101 F

102 MISO supported its 

filing by stating that the “reserve procurement enhancement” provisions were designed to 

address certain problems arising from the fact that the deliverability of reserves was not 

fully addressed by its Tariff’s then-existing approach to the setting of zonal reserve 

requirements. However, the original reserve procurement enhancements applied only to 

transmission constraints and did not apply to Sub-Regional Power Balance Constraints, 

which are contractual in nature. MISO contended that the contractual nature of SubRegional Power Balance Constraints should not preclude the application of the reserve 

procurement enhancement. MISO asserted that the revisions it proposed will enable it to 

use reserve procurement to manage flows, including post reserve deployment flows, 

between MISO Midwest and MISO South in accordance with the RDTL. 

C. Revised Regional Transfer Operations Procedure and RDT-Impacted 

Flowgate Statement of Understanding

In December, 2018, a new version 2.0 of the Regional Transfer Operations 

Procedure (RTOP), which implements the Settlement among the Joint Parties, became 

effective. This version “incorporate[es] January 17, 2018 Lessons Learned” according to 

the Revision History, and, like the earlier version, is approved by MISO, SPP, TVA and 

SeRC. The revised version improves on the original in the following ways:

• Requiring MISO to ensure that both UDS and real-time RDT remain at or below 

the RDTL (versus only UDS during the Event)102F

103

• Requiring MISO to provide forecasts of the RDT to SPP, TVA, and SeRC103 F

104 and 

share key information which could affect the RDT for rolling 5 days into the 

future104F

105

 102 Midcontinent Independent System Operator, Inc., 164 FERC ¶ 61,129 (2018). 

On March 15, 2019, MISO submitted revisions to conform additional provisions with

recently accepted Tariff changes on the consideration of Post Reserve Deployment 

Constraints, including Sub-Regional Power Balance Constraints. 

103 3.1.3.

104 3.1.4.

105 3.1.4.2.
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• Identifying criteria for determining RDT-impacted flowgates105 F

106

• More specific actions to be taken to address congestion and RDTL 

exceedances,106 F

107 including an ordering of congestion management procedures and 

a new subsection on potential load shed conditions.107 F

108

To implement the identification of RDT-impacted flowgates,108 F

109 MISO, SPP and the Joint 

Parties agreed to a two-step process for performing the necessary calculations for 

determining RDT-impacted flowgates. The interim step is required because as intramarket flow, MISO’s RDT flow is not currently input into the Interchange Distribution 

Calculator (IDC) used to implement TLRs, but integrating the RDT flow into the IDC is 

planned for the second phase.

D. Additional MISO Tariff Revisions Relevant Post- Event

MISO has been studying the issue of capacity resources that are not available 

during periods when the system is under stress, particularly in non-summer periods and 

particularly in MISO South. Prior to the Event, MISO started a process known as the 

Resource Availability and Need Initiative. Some of the early fruits of the Initiative are 

tariff changes to better insure capacity availability, as described below.

On February 19, 2019, the Commission accepted MISO’s Tariff revisions that 

now require LMR resources that become capacity resources to identify the period of the 

year that they are available and the notification time they require for deployment. This 

must include the four summer months with a notification time of no more than12 hours. 

The resource must be able to justify the availability it identifies. On March 29, 2019, the 

Commission accepted, subject to condition, MISO’s Tariff revisions109 F

110 that were 

intended to supplement the existing Generator Planned Outage process by improving 

transparency through forward signals and incentives.110 F

111 MISO’s revisions, which 

included a penalty for planned outages and derates that occur during Max Generation 

events, were intended to: (1) provide additional incentives for Generator Owners to 

 106 3.1.5.

107 3.1.6, 3.2 and 3.3.

108 3.3.8.

109 As discussed in section 3.1.5 of the RTOP.

110 Open Access Transmission, Energy, and Operating Reserve Markets Tariff.

111 Midcontinent Independent System Operator Inc., 166 FERC ¶ 61,236 (2019).
Page 78 of 153

schedule Generator Planned Outages and derates well in advance of the scheduled start 

time and (2) identify times with increased system risk due to correlation of outages and 

derates. The Commission agreed with MISO’s efforts to enhance its Generator Planned 

Outage scheduling practices, believing that MISO’s proposal will “promote advanced 

scheduling of Generator Planned Outages, improve Generator Planned Outage 

coordination, and help MISO address the recent increase in the number of declared 

Emergency events during non-summer seasons.”111F

112

The same day, the Commission accepted, subject to condition, MISO’s proposal to 

enhance the testing requirements in its Tariff for resources that participate in MISO’s 

markets as LMRs. 112 F

113 The Commission agreed with MISO’s efforts to ensure that the 

LMRs it relies upon can in fact supply their registered load- reduction capability during 

emergency events. The Commission found it necessary for MISO to have confidence 

that LMRs will perform when scheduled, and stated that it expects MISO’s proposed 

testing requirements to enhance LMR performance.

VII. Prior Similar Events

2011 Southwest Cold Weather Event of February 5-11, 20111 13F

114 

This event, which affected the southwest region of the United States (Texas and 

New Mexico) during the first week of February, 2011, was similar to the Event in that 

extreme low temperatures caused widespread generation outages. In the 2011 cold 

weather event, many cities in Texas and New Mexico experienced a 50 degree drop in 

temperature. The cold temperature conditions in 2011 were similar to what was found 

for the Event, where many south central cities experienced a 40-50 degree drop in 

temperature over a several-day period: daytime high temperatures in the 60s to low-70s 

on Friday, January 11, in cities such as Little Rock, Texarkana, Shreveport, Jackson, 

Beaumont, Baton Rouge and New Orleans, dropped to daytime highs in the high teens to 

upper 20s on January 17. In both events, many generators did not winterize to protect 

against freezing weather conditions, despite recommendations from the 2011 report to do 

so. In both events, massive generation outages and derates led to energy emergencies, 

 112 Id. at P. 60.

113 Midcontinent Independent System Operator Inc., 166 FERC ¶ 61,235 (2019). 

See fn. 14 for more information about LMRs.

114 Report on Outages and Curtailments During the Southwest Cold Weather Event 

of February 1-5, 2011: Causes and Recommendations, found at 

https://www.ferc.gov/legal/staff-reports/08-16-11-report.pdf
Page 79 of 153

however, in the 2011 event, the RC needed to perform controlled load shedding to 

maintain system reliability, whereas in the Event, emergency energy purchases and 

LMRs, among other tools, allowed the RCs to avoid shedding firm load (although firm 

load shedding could have occurred if the MISO South WSC occurred).

2014 Polar Vortex114 F

115

The Polar Vortex event of early January, 2014, which affected the Midwest, 

South- central, and East Coast regions, similarly involved significant unplanned 

generation outages and derates, Both the Polar Vortex and the 2011 event were similar to 

January 17, 2018, in that generation reserves were depleted within the event areas, due to

significant unplanned generation outages and derates, requiring energy emergency 

measures ranging from voluntary load reduction to interruptible load shed to rotating 

blackouts/firm load shedding. 

Cold Wave of 1994115 F

116

A complicating characteristic of the Event not found in the Polar Vortex or 2011 

events was wide-area constrained BES conditions, stretching across four RC footprints. 

The Cold Wave that occurred the week of January 16, 1994, in the Midwest and MidAtlantic states, also had wide-area constrained conditions combined with 

capacity/reserves shortfalls, similar to the Event. Faced with unusually high electricity 

demands, and cold weather-related generator outages and reduced fuel supply, utilities 

with generation shortages imported large blocks of power over their transmission systems 

from other utilities. System operators managed several transmission paths near their 

post-contingency transfer limits, to ensure reliability while the large power transfers 

occurred, although some localized voluntary load shedding occurred. 

Could This Happen Again?

The Event, combined with the other events, reaffirms the importance of generators 

remaining in operation during extreme cold weather conditions, to support reliable BES

operations. More recently, MISO and SPP generators performed better in the January 30-

31, 2019 Polar Vortex which affected the Midwest. Unlike facilities in warmer climates 

such as the south central U.S., generating stations in the colder Midwest are typically 

 115 NERC report on 2014 Polar Vortex, 

https://www.nerc.com/pa/rrm/January%202014%20Polar%20Vortex%20Review/Polar_

Vortex_Review_29_Sept_2014_Final.pdf.

116 NERC report on Electric Utilities’ Response to the Cold Wave of January, 

1994.
Page 80 of 153

designed and constructed so that their boilers, turbines, and other auxiliary systems are 

not exposed to ambient weather conditions.116 F

117 Unusually cold temperatures in warmerweather areas, combined with a lack of generator preparation for conditions expected, 

could again lead to substantial unplanned generation outages, with similar effects on 

reserves and potentially, BES conditions.

VIII. Findings and Recommendations 

Generator Cold Weather Reliability

Finding: The South Central U.S. Cold Weather BES Event of January 17, 2018 was 

caused by failure to properly prepare or “winterize” the generation facilities for 

cold temperatures.

• A comparison of below-freezing temperatures in the Event Area and unplanned 

generation outages and derates from January 15 through 19 resulted in three cities 

with correlation coefficients117F

118 of -0.7 or better, and the majority of cities with 

coefficients of between -0.5 to -0.7, indicating that as temperatures decreased, 

unplanned outages and derates increased.

• At least 44% of the unplanned outages or derates during January 15 to 19 were 

directly attributed to, or likely related to, the extreme cold weather, as calculated 

by numbers of units. Fourteen percent of the generator failures were directly 

attributed by the Generator Owners/Operators to weather-related causes, including 

frozen sensing lines, frozen equipment, frozen water lines, frozen valves, blade 

icing, low temperature cutoff limits, and the like. Another 30 percent were 

indirectly attributable to the weather (occasioned by natural gas curtailments to 

gas-fired generators (16%) and attributed to mechanical causes known to be 

related to cold weather (14%)).118 F

119

 117 2011 Southwest Cold Weather Event FERC/NERC Report, Appendix: Power 

plant design for ambient design temperatures at page 142.

118 A correlation coefficient is a number or function that indicates the degree of 

correlation between two sets of data or between two random variables and that is equal to 

their covariance divided by the product of their standard deviations. (Source: MerriamWebster Dictionary.) A negative correlation coefficient indicates that as one variable 

increases, the other decreases, and vice-versa. In this case, the negative correlation meant

that as temperatures decreased, generation outages increased.

119 These causes included issues with specific equipment known to be vulnerable 

to freezing, including drum level transmitter sensor lines, inlet guide vanes, gas purge 

valves, steam turbine intercept valves and other valves; issues related to cold oil, such as 
Page 81 of 153

• Unplanned generation outages and derates during the period of extreme cold 

accumulated to approximately 14,000 MW in the Event Area by the morning peak 

hour ending 8 am CST on January 17, 2018.

• Generator Owners attributed at least 35% of the generation outages and derates on 

January 17, 2018 to the extreme weather conditions: 19% to freezing-related 

mechanical issues and 16% to cold-related fuel supply issues.11 9F

120

Figure 40: January 15-19, 2018 - Causes of Unplanned Generation Outages and 

Derates for Event Area

 

oil pressure drop or failure to start; wet/frozen coal causing problems with feeders or 

conveyors; and loss of feedwater.

120 More than 35% of the generator outages and derates on January 17 were likely 

related to the extreme cold. The Team found that for January 15 through 19, 14% of the 

outages and derates attributed to mechanical causes were actually caused by issues 

known to be related to cold weather. The Team did not perform this analysis for January 

17 alone. 
Page 82 of 153

Figure 41: January 15-19, 2018 – Sub-causes for Unplanned Generation Outages and 

Derates due to Freezing Issues, for Event Area

Figure 42: January 17, 2018 - Causes of Generation Outages for Event Area, By RC
Page 83 of 153

Figure 43: January 17, 2018 – Causes of Unplanned Generation Outages and Derates 

for Event Area

Figure 44: January 17, 2018 – Sub-causes for Unplanned Generation Outages and 

Derates due to Fuel Supply Problems, for Event Area
Page 84 of 153

Figure 45: January 17, 2018 – Sub-causes for Unplanned Generation Outages and 

Derates due to Freezing Issues, for Event Area

Finding: Gas supply issues contributed to the Event, and natural gas-fired units 

represented at least 70% of the unplanned generation outages and derates.

• From January 15 to 19 in the Event Area, natural gas-fired units were 70% of the 

unplanned generation outages and derates when calculated by numbers of units, 

and 74% when calculated by MW. 

• During the same period, gas supply issues caused by the extreme cold 

temperatures, including interruptible supply, low gas pressure, and other pipeline 

and gas supply issues, led to outages of 38 units, for a total of approximately 2,200

MW.

• The Team found that temperatures in the Event Area were generally above the 

ambient temperature design specifications 120F

121 for many natural gas-fired generating 

units.

 121 Most of the units in the Event Area have an ambient temperature design rating 

between -10 and 10 degrees, with some exceptions. A handful of units have an ambient 

temperature design rating to -20 degrees, and four units are rated for use to -40 degrees. 

Some entities did not incorporate (or did not know) their units’ ambient temperature 

design ratings.
Page 85 of 153

Figure 46: January 15-19, 2018 – Sub-causes for Unplanned Generation Outages and 

Derates due to Fuel Supply Problems, for Event Area

Figure 47: January 15-19, 2018 – Fuel Type for Unplanned Generation Outages and 

Derates due to Freezing Issues, for Event Area (by Number of Generators)
Page 86 of 153

Figure 48: January 15-19, 2018 – Fuel Type for Unplanned Generation Outages and 

Derates due to Freezing Issues, for Event Area (by MW of Generation)

 

Generator Cold Weather Reliability 

Recommendation 1: The Team recommends a three-pronged approach to ensure 

Generator Owners/Generator Operators, Reliability Coordinators and Balancing 

Authorities prepare for cold weather conditions: 1) development or enhancement of 

one or more NERC Reliability Standards, 2) enhanced outreach to Generator 

Owners/Generator Operators, and 3) market (Independent System 

Operators/Regional Transmission Organizations) rules where appropriate. This 

three-pronged approach121F

122 should be used to address the following needs: 

• The need for Generator Owners/Generator Operators to perform 

winterization activities on generating units to prepare for adverse cold 

weather, in order to maximize generator output and availability for BES 

reliability during these conditions. These preparations for cold weather 

should include Generator Owners/Generator Operators:

 122 While any one of the three approaches may provide significant benefits in 

solving this problem, the Team does not view any one of the three as the only solution. 

The Team envisions that a successful resolution of the problem will likely involve 

concurrent use of all three.
Page 87 of 153

o Implementing freeze protection measures and technologies (e.g., installing 

adequate wind breaks on generating units where necessary).

o Performing periodic adequate maintenance and inspection of freeze 

protection elements (e.g., generating units’ heat tracing equipment and 

thermal insulation).

o If gas-fueled generating units, clearly informing their Reliability 

Coordinators and Balancing Authorities whether they have firm 

transportation capacity for natural gas supply

o Conducting winter-specific and plant-specific operator awareness 

training.

• The need for Generator Owners/Operators to ensure accuracy of their 

generating units’ ambient temperature design specifications. 122 F

123 The accurate 

ambient temperature design specifications and expected generating unit 

performance, including for peak winter conditions, should be incorporated 

into the plans, procedures and training for operating generating units, and 

shared with Reliability Coordinators and Balancing Authorities.

• The need for Balancing Authorities and Reliability Coordinators to be aware 

of specific generating units’ limitations, such as ambient temperatures beyond 

which they cannot be expected to perform or lack of firm gas transportation, 

and take such limitations into account in their operating processes to 

determine contingency reserves, and in performing operational planning 

analyses, respectively.

Staff analysis of the outages between January 15 and 19 found that of 183 total 

units affected, the Generator Owners/Operators directly attributed 16% to freezing, and 

14% to fuel supply issues related to the extreme cold. An additional 14% were likely 

caused by the extreme weather conditions. Outages in this last subcategory had been 

placed in the “mechanical/ electrical failures” category (59% of the outages between 

January 15 and 19) by the Generator Owner/Operators, but based on more detailed 

information, were found to be caused by problems known from earlier cold-weather 

events to be associated with extreme cold. Adding the categories directly attributed to and 

likely related to the extreme cold (16% plus 14% plus 14%) results in 44% of the total 

outages being directly or likely related to cold. Inquiry Staff also found that the total 

generation outages for January 15 through 19 (including all categories and subcategories) 

 123 The Team found that temperatures were generally above the ambient 

temperature design specifications for many natural gas-fired generating units (See fn

121).
Page 88 of 153

were statistically correlated with temperatures, with a -0.7 correlation overall. One-third 

of the GO/GOP entities surveyed had no winterization provisions.

These findings echo those from the Joint FERC-NERC Report on Outages and 

Curtailments during the Southwest Cold Weather Event of February 1-5, 2011 and the 

NERC 2014 Polar Vortex Report, both of which found that many generators failed to 

adequately prepare for winter weather conditions. 

One of the recommendations from the 2011 Southwest Cold Weather Event was to 

create a mandatory winterization Reliability Standard. In September, 2012, NERC 

submitted a Standard Authorization Request (SAR) which proposed to require Generator 

Owner/Operators to:

• report generating unit capabilities based on anticipated winter weather using 

criteria developed by the standard drafting team using stakeholder input. 

• ensure winter weather preparation plans are created, maintained, implemented and 

monitored as appropriate to help ensure generating units can operate to the criteria 

developed above. The plans shall include appropriate annual winterization 

measures. 

When NERC’s Operating Committee proposed a voluntary Reliability Guideline titled 

Generating Unit Winter Readiness, instead of a mandatory Reliability Standard, the 

Standards Committee rejected the SAR.12 3F

124

In addition to the recommendations made in the 2011 Southwest Cold Weather 

Event and the 2014 Polar Vortex Reports on winter preparedness, and NERC’s 

Reliability Guideline, other voluntary steps have been taken since 2011, including:

• NERC video on “Winter Weather Preparedness”

• NERC webinar on “Winter Preparation for Severe Weather Events” 

• Numerous NERC “Lessons Learned” documents issued pertaining to winter 

weather preparedness

 124 The rejection was also based on industry comments and a recommendation 

from NERC’s Reliability Issues Steering Committee. See NERC’s July 2013 letter to the 

proponent of the SAR:

https://www.nerc.com/pa/Stand/Project%20201301%20Cold%20Weather%20Pre

paredness/SAR_Response_Letter_SM_071813.pdf For more information regarding the 

proposed SAR, see https://www.nerc.com/pa/Stand/Pages/Project2013-

01_Cold_Weather.aspx
Page 89 of 153

• NERC-developed training package on “Extreme Weather Events” posted for 

industry use,

• Gas and Electrical Operational Coordination Considerations Reliability Guideline 

developed by the NERC Operating Committee, and

• Regional Entities’ cold-weather guidance (e.g. SERC’s Cold Weather 

Preparedness efforts,124F

125 ReliabilityFirst’s cold weather resources, including 

Winterization Visit Best Practices and Review of Winter Preparedness Following 

the Polar Vortex12 5F

126).

However, despite the guidance above, cold-weather events continue to occur involving 

extensive unplanned generation outages, which imperil reliable BES operations. A 

mandatory Reliability Standard would require Generator Owner/Operators to properly 

prepare for extreme cold weather, and would help RCs and BAs identify units which may 

not be able to perform during an extreme weather event. However, the process from 

SAR to Commission approval of a mandatory Reliability Standard could take a year or 

more. In the meantime, enhanced outreach and actions by ISOs/RTOs to incent generator 

performance can also help to prevent a recurrence of the large-scale unplanned outages 

like those seen during the Event, the Polar Vortex and in ERCOT in 2011.

Situational Awareness and RC-to-RC Communication 

Findings: 

• The Relevant RCs (MISO, SPP, TVA and SeRC) had situational awareness 

throughout the event and communicated as necessary to preserve system 

reliability.

o RCs were regularly performing real-time assessments to determine system 

state and next courses of action, including identifying operating limit 

exceedances and voltage conditions for both real-time and for simulated 

post-contingency conditions. 

o The RC operators communicated and coordinated their analyses and 

discussed mitigation actions necessary to maintain BES reliability, up to 

shedding firm load. 

o During the Event, the Joint Parties affected by transfers between MISO 

Midwest and MISO South, including the four RCs, had a written procedure, 

the Regional Transfer Operations Procedure, which covered their 

interactions as to MISO’s Regional Directional Transfer. 

 125 www.serc1.org/coldweatherprep

126 https://rfirst.org/KnowledgeCenter/Risk%20Analysis/ColdWeather
Page 90 of 153

o After the Event, the Joint Parties implemented a revised Regional Transfer 

Operations Procedure, RTO-RTOA-OP1-r2.0, effective December 1, 2018.

• The generation outages and derates on January 17 created energy emergency 

conditions which required voluntary load reduction and plans for firm load 

shed if MISO’s 1,163 MW worst single contingency in MISO South occurred. 

o MISO invoked energy emergency alerts and purchased emergency energy 

for MISO South due to stranded reserves within its BA footprint.

o The system in the Event Area was severely capacity-constrained. Even 

after emergency purchases, MISO South’s reserves were down to 172 MW 

for the hour ending 8 a.m. CST. 

o Constrained transmission conditions spanned a large area, across all or 

portions of nine states (Arkansas, Alabama, Kansas, Louisiana, Mississippi, 

Missouri, Oklahoma, Tennessee, and Texas), and four RC footprints 

(MISO, SPP, TVA and SeRC).

o As the morning peak (7 to 8 a.m. CST) neared on January 17, for the MISO 

South WSC, it would have likely resulted in firm load shed across the 

MISO South region to maintain generation and load balance and prepare to 

meet the next worst single contingency, while simultaneously triggering 

further and additional firm load shed in specific areas of the MISO South

footprint to maintain BES voltages within post-contingency limits.

Situational Awareness Recommendations: 

Recommendation 2: Reliability Coordinators should perform real-time voltage 

stability analysis in addition to RTCA, for constrained conditions occurring within 

their own and/or within adjacent Reliability Coordinator areas, such as those 

experienced by MISO the morning of January 17, and communicate the results of 

their analysis to adjacent Reliability Coordinator areas. Constrained system 

conditions during the Event included: multiple generation outages and derates in 

MISO South, high system loads, large regional transfers due to stranded reserves, 

transmission outages in generation-limited load pockets, and limited additional 

transfer capability. On January 17 some of these conditions were also occurring 

simultaneously in neighboring Reliability Coordinator footprints. Real-time voltage 

stability analysis could assist Reliability Coordinators in determining if other 

mitigation actions are necessary as well as whether an emergency condition exists. 

If such stressed system conditions are projected for the next day, voltage stability 

analysis should also be performed as part of the Reliability Coordinators’ 

Operational Planning Analyses.
Page 91 of 153

Recommendation 3: To provide accurate results for the Reliability Coordinators’ 

real-time tools, adjacent Reliability Coordinators should benchmark their planning 

and operations models to actual events, like the January 17 event that stressed both 

the Reliability Coordinator and its adjacent Reliability Coordinator(s), and correct

any inconsistencies identified. 

Recommendation 4: Reliability Coordinators should also perform periodic impact 

studies to determine which elements of their adjacent Reliability Coordinators’

systems have the most impact (i.e., the effect an outaged element located in an 

adjacent Reliability Coordinator area has on its voltages, facility loadings, or other 

conditions) on their systems. Reliability Coordinators should consider adding any 

identified external facilities to their models and should share associated real-time 

external network data. Beyond the enhanced model incorporation into tools such as 

RTCA, these sensitivity studies could identify external facilities which have such an 

impact that the Reliability Coordinator may also implement real-time EMS alerting 

for the loss of the external facility.

Recommendation 5: Balancing Authorities and Transmission Operators should 

conduct periodic capacity and energy emergency drills simultaneous with 

transmission emergency drills with their Reliability Coordinators, to ensure 

readiness, coordination of control room personnel to conduct multiple load-shedrelated tasks while continuing to maintain situational awareness, and coordination 

between additional local control center and field personnel. On January 17 during 

the peak hour, MISO system analysis showed that if its next-contingency generation 

outage in MISO South of 1,163 MW occurred, it would need to rely on postcontingency manual firm load shed to maintain voltages within limits, while faced 

with potential additional firm load shedding to maintain system balance and restore 

reserves for MISO South region. Operators may be required to perform additional 

tasks if the load shed must be executed within narrow boundaries (e.g. limited load 

shed options that will result in alleviating transmission overload and/or low voltage 

conditions), coupled with conditions (such as extreme temperatures), which create 

the need for rotational load shedding to protect life or health.

Had the MISO South WSC occurred during the morning peak hour of 7 to 8 a.m. 

CST, it would have required replacement generation from MISO Midwest, thereby 

further increasing RDT transmission flows into MISO South partly through parallel paths 

within SPP, TVA RC and SeRC footprints. Both MISO and SPP included the MISO 

South WSC as a contingency, both model each other’s systems to an extent in their 

RTCA applications, and both showed their RTCA converging, which means that they did 

not expect instability or cascading as a result of the simulated outage of the 1,163 MW 

WSC. 
Page 92 of 153

However, MISO’s RTCA projected a trend of post-contingency low voltage, 

including voltages as low as 88% on certain 230kV buses, and 24 transmission facilities 

with projected post-contingency thermal overloads between 7 and 8 a.m. CST. MISO 

operators relied on RTCA convergence, which indicates steady-state stability,1 26F

127 to 

assure that voltage stability could be maintained despite numerous post-contingent 

system conditions. Also, MISO relied on the TOPs within its footprint to quickly execute 

the necessary load shed if the MISO South WSC occurred, to alleviate numerous low 

voltages. This analysis would be especially important given that MISO recognizes that 

one of its load pockets is “a voltage/thermal sensitive area and is susceptible to low 

voltages under outage conditions or a loss of a key transmission element,” and for 

MISO’s WSC in MISO South of 1,163 MW, it would have likely resulted in the need for 

post-contingency load shedding steps to alleviate numerous transmission facilities from 

experiencing low voltage conditions, while faced with potential additional firm load 

shedding to maintain system balance and restore reserves for MISO South region. 

RC-to-RC Communications Recommendations

Version 2.0 of the Regional Transfer Operations Procedure is an improvement on 

the Procedure in use during the Event. The Joint Parties should consider the following 

revisions that would further enhance RC communications:

Recommendation 6: Make the following changes to the Regional Transfer 

Operations Procedure:

• Provide operators with more specificity for applying section 3.1.6.1 through 

3.1.6.4 regarding how to return the Regional Directional Transfer to a level at 

or below the Regional Directional Transfer Limit within 30 minutes, and the 

relationship between 3.1.6.1 through 3.1.6.4 and 3.2 (congestion 

management). Also, clarify the roles and/or reference certain steps in the 

applicable emergency procedures that may assist the operators in taking 

prompt actions to return Regional Directional Transfer at or below the 

Regional Directional Transfer Limit.

• Clarify the relationship between 3.1.6.1 and 3.1.6.4 regarding calls to adjacent

Reliability Coordinators and when the Reliability Coordinator operator will 

initiate reduction of the Regional Directional Transfer. Consider a 

timeline/flowchart of the sequence of communications, similar to the 

 127 Capability of an electric power system to maintain its initial condition after 

small interruption or to reach a condition very close to the initial one when the 

disturbance is still present.
Page 93 of 153

Transmission Loading Relief curtailment timing, found in the Joint NAESB 

System Operator’s Transmission Loading Relief Reference Manual.

• Clarify the section on “Potential Load Shed conditions” (section 3.3.8) to 

require the adjacent Reliability Coordinators to communicate an emergency 

condition if conditions in the Reliability Coordinator footprint so warrant. 

This change further aligns the procedure steps with the Reliability 

Standards.127 F

128

• Clarify that when making emergency energy purchases (for example, 

purchasing emergency energy, for meeting load plus reserves, or to alleviate 

Regional Directional Transfer flow before shedding load), Reliability 

Coordinator /Balancing Authority Operators should analyze the flow impacts 

prior to implementing the emergency energy schedule to avoid 

unintentionally causing detrimental impacts to Regional Directional Transfer 

-impacted flowgates or lead to an operating Emergency for Transmission 

Operator(s) area(s).

• In determining the need for temporary changes to the Regional Directional 

Transfer Limit (see 3.3.1) for the operating horizon/next-day analysis or 

during the operating day, MISO, in coordination with SPP and neighboring 

entities, should determine the maximum simultaneous transfer capability 

north-to-south (or south-to-north if applicable), based on the latest operating 

conditions expected during the timeframe for determination. This study 

should be used to support any decisions on making temporary changes to the 

Regional Directional Transfer Limit.

Transmission Operations and Reserves

Findings: The generation outages during the peak hour ending 8 a.m. CST on 

January 17 created an “N-many”128F

129 BES condition, and led the affected entities to 

transfer power from distant generation into the affected region to cover energy 

 128 Linking the obligation to shed firm load to the Reliability Standards will protect 

MISO if it needs to shed firm load to reduce the RDT. The RDT is a contractual limit 

rather than a limit imposed by one of the Commission-approved mandatory Reliability 

Standards (e.g. SOL, IROL). In the past, the Commission approved a penalty against a 

Balancing Authority/Transmission Operator that shed firm load when the load shedding 

was not required by a Reliability Standard. See In re California System Operator 

Corporation, 141 FERC ¶ 61,209 (2012)). 

129That is, a large number of generation contingencies had occurred (generation 

units experienced unplanned outages, derates or failures to start).
Page 94 of 153

demands and provide reserves. These large power transfers resulted in wide-area 

BES transmission-constrained conditions in four RC footprints.

• On a seasonal basis, both MISO and SPP separately performed assessments for the 

2017/18 winter and shared their results; however, these assessments neither 

analyzed simultaneous power flows and transfers like those seen on January 17, 

nor quantified results of their combined impact. 

• On a seasonal basis, MISO had predicted that it could transfer up to 4,650 MW in 

a north-to-south direction, but this analysis was based on less-severe transfer 

conditions.

• The transmission system conditions observed on the morning of January 17, 2018, 

were not solely due to MISO’s north-to-south regional directional power transfer 

(RDT) flow to cover the supply shortfall caused by unplanned generation outages 

and derates MISO South, but to a combination of the RDT flow and additional 

factors including generation outages and derates in the rest of the Event Area (e.g., 

southeastern SPP footprint), high system loads related to extreme low 

temperatures in the Event Area, higher-than-forecast wind generation power 

transfers in MISO and SPP, and DC power transfer flows between SPP and the 

ERCOT Interconnection.

• To address the constrained system conditions, RC operators needed to consult with 

their TOP operators to verify system operating limits to aid in determining 

potential mitigation measures, and some RCs opened transmission facilities based 

on SOLs which did not reflect winter cold weather conditions.

• Although the Event Area normally has generous reserves (i.e., greater-than-20% 

projected reserve margins for winter peak conditions), the unplanned generation 

outages and derates created stranded reserves from the distant generation, 

especially in MISO South. 

• In its next-day forward reliability assessment commitment, as well as during the 

January 17 event operating day, MISO utilized its full 3,000 MW RDT to aid in 

providing reserves for its MISO South firm load.

Seasonal Studies Recommendations:

Recommendation 7: Planning Coordinators and Transmission Planners should

jointly develop and study more-extreme condition scenarios to be better prepared 

for seasonal extreme conditions. Examples of more-extreme condition modeling 

include: 
Page 95 of 153

• removing generation units entirely to represent actual generation outages 

(especially outages known to occur during severe weather), versus scaling 

of generating unit outputs;

• modeling system loads so that the study accurately tests the system for the 

extreme conditions being studied; and

• modeling and studying actual extreme events experienced in the Planning 

Coordinator area and actual severe scenarios experienced in other 

Planning Coordinator areas.

Results of these more-extreme condition studies should then be shared with 

operations staff for training purposes, and to aid in their planning for days where 

more extreme transfers are expected. 

Recommendation 8: MISO and SPP should jointly perform seasonal transfer 

studies and sensitivity analyses in which MISO and SPP model same-direction 

simultaneous transfers (e.g. north to south, south to north, west to east) to determine 

constrained facilities so that they can develop mitigation plans or other procedures 

for the operators. Such studies should include, but not be limited to:

• intra-market power transfers, without offsetting transfers in a way that 

would reduce the impact on determining constrained facilities;

• transfers of wind generation output to load areas using near-peak wind 

generation levels;

• simultaneous generation outages in adjacent Reliability Coordinator

footprints (e.g. MISO South and southern SPP footprints); and

• increasing simultaneous transfers to levels that constraints cannot be fully 

alleviated.

System impacts of the modeled transfers in the studies could vary based on which 

generators are removed. Sensitivity study cases should be performed for example, to 

produce a potential range of transfer capabilities based on varying generation 

outage scenarios.

For its Winter 2017-2018 Coordinated Seasonal transmission Assessment, MISO 

performed transfer studies which included studying MISO Midwest to MISO South intraBalancing Authority area transfers to determine First-Contingency Incremental Transfer 

Capabilities for both north-to-south and south-to-north transfers. The maximum power 

transfer projected was 4,650 MW in a north-to-south direction, and MISO concluded this 

was adequate for the upcoming 2017-2018 winter season. However, the reported 

maximum power transfer value was based on less-severe power transfer conditions, since 

MISO modeled the power transfer by scaling generation between the internal north and 

south regions for the simulation of the transfer, versus modeling certain generators offline 
Page 96 of 153

in MISO South in the study case to yield a transfer capability based on more extreme 

event conditions. This scaling of generation between the internal north and south regions 

for the simulation of the transfer did not entirely represent the effects on the power grid 

that outages of actual generating units would cause, such as loss of voltage support. 

Additionally, MISO did not model the simultaneous north-to-south transfers in 

adjacent RCs (transfers from locations where generation reserves were available to those 

in which generation outages and derates), as well as high system loads (i.e., in MISO 

South, and in the southeastern SPP footprint), which occurred on January 17. These 

simultaneous north-to-south parallel flows contributed to numerous BES postcontingency limit exceedances and lower than normal system voltages, necessitating 

many post-contingency mitigations to be ready for the next contingency. The MISO and 

SPP footprints combined cover the entire mid-section of the U.S., and weather patterns 

may simultaneously and similarly impact their real-time operations, as on January 17. 

Loss of southern generation occurred in MISO as well as SPP, and the parallel 

impact of those flows resulted in lower-than-expected real-time RDT capability. The 

Team also found that the results of the studies were not used to inform/support MISO’s 

operations staff to aid in management of the RDT (e.g., lowering or raising of the RDT) 

for the operations planning horizon. If MISO performed more-severe condition studies, 

operators could use the study results in planning for conditions where more extreme RDT 

transfers are forecast.

System Operating Limits Recommendation:

Recommendation 9: Transmission Owners and Transmission Operators, as part of 

establishing facility ratings and System Operating Limits, respectively,129F

130 should 

conduct analysis that delineates different summer and winter ratings, for both 

normal and emergency conditions. The established facility ratings and associated 

System Operating Limits should consider, at a minimum, ambient temperature 

conditions that would be expected during high summer load and high winter load

conditions, respectively.130F

131 These ratings and limits should be provided to the 

Reliability Coordinator and other applicable entities for use in tools for operation, 

 130 See fn 89.

131 Some entities may have, for example, a winter rating based on 32 degrees and a 

summer rating based on 95 degrees. Other entities may have temperature-dependent 

ratings, which would also be consistent with the recommendation. Care should be taken 

when implementing ratings and limits, to account for unseasonal weather, e.g.., warmerthan-normal winter days.
Page 97 of 153

such as Energy Management System and Real-Time Contingency Analysis

applications.131 F

132

EMS systems have the capability to promptly update transmission facility limits 

for system operators so that they have accurate limits that reflect the current ambient 

conditions. The Team found that certain overhead-line transmission limits used by 

system operators during the Event reflected summer season conditions instead of the 

ambient cold weather conditions experienced during the event. Generally, limits based

on colder conditions would have allowed the use of a higher capacity rating. The 

Regional Transfer Operations Procedure, RTO-RTOA-OP1-r2.0, contemplates in 3.2.2.1 

the use of dynamic and emergency ratings as the first step in congestion management, 

which assumes the existence of such ratings. During its inquiry, the Team observed 

constrained transmission facilities for which one static rating was used year-round (i.e., 

Summer Normal =Summer Emergency=Winter Normal=Winter Emergency) and some of 

which had ratings that were atypically much lower than typical overhead circuit ratings 

applied at the same voltage. The use of seasonal ratings or dynamic ratings could allow 

for greater capacity ratings, thereby potentially reducing congestion and potentially 

ameliorating system conditions during an emergency.

Reserves Recommendations:

Recommendation 10: Balancing Authorities should consider deliverability of 

reserves to avoid stranded reserves.132 F

133 

Recommendation 11: When MISO Balancing Authority relies upon 3,000 MW of 

Regional Directional Transfer flows in determining total reserve levels for MISO 

South, it should remain mindful that, as the Commission noted, “any amount above 

1,000 MW of the 3,000 MW north-to-south limit . . . [is] only available on a nonfirm, as-available basis.”133 F

134 MISO should notify the other Reliability Coordinators 

operating under the Regional Transfer Operations Procedure (SPP, TVA and 

SeRC) when it needs to rely on any amount of the non-firm, as-available, portion of 

the Regional Directional Transfer to meet its reserves, due to a capacity shortage in

 132 The Transmission Operator may need to work with the Transmission Owner to 

obtain facility ratings which do not limit the Transmission Operator’s ability to provide 

the recommended limits.

133 See Planning and Reserves Recommendation No. 3, in Appendix G, 2011 

Recommendations on Preparation for Cold-Weather Events.

134 Midcontinent Independent System Operator, Inc., 164 FERC ¶ 61.129, at P 37 

(2018).
Page 98 of 153

MISO South, so that the Reliability Coordinator Operators can timely communicate 

and act if conditions in the other Reliability Coordinators’ footprints are projected 

to limit Regional Directional Transfer flows. 

By depending on the total RDT, which consisted of 1,000 MW firm transmission 

capacity plus 2,000 MW as-available non-firm transmission capacity, MISO ran the risk 

of curtailment of the “non-firm, as available” portion of the RDT to alleviate transmission 

overloads, which could result in stranded reserves along with the potential for firm load 

shed in the MISO South region. These risks could increase further if emergency energy 

is unavailable or not deliverable from neighboring resources to provide reserves due to 

RDT curtailment.

Load Forecasting

Findings: MISO’s 5- to 3-day out load forecasts for MISO South were significantly 

lower than the actual peak load on January 17, and less accurate than adjacent 

RCs’ forecasts for the same period.

• MISO South region’s five-, four-, and three-day-ahead “mid-term” peak load 

forecast errors in forecasting the actual peak load on January 17, 2018 were 

significantly larger (approximately 18.9%/6,000 MW, 10.2%/3,250 MW, and 

6.1%/1,900 MW low, respectively) than the other RCs relevant to this event. 

• Other RCs’ load forecasts within the Event Area were much more accurate 

(with error rates ranging from 5.6% lower to 3.0% higher than actual peak load 

for five-days-out, 4.6% lower to 4.8% higher than actual for four-days-out, and 

2.8% lower to 4.0% higher than actual for three-days-out).

Recommendations:

Recommendation 12: MISO should work with its entities serving load/Local 

Balancing Authorities in the MISO South footprint to ensure that accurate and 

realistic load forecasts are provided to MISO in the five-, four-, and three-dayahead forecasts. The Local Balancing Authorities should incorporate actual historic 

temperatures and loads from the January 17 event and other cold weather events 

into their future forecasts to capture potential peak demands during severe cold 

weather events.

Recommendation 13: MISO should work with adjacent Reliability Coordinators to 

improve the accuracy of its mid-term peak load forecasts for impending extreme 

weather conditions. This includes:

• Sharing five-, four-, and three-day-ahead temperature forecasts with adjacent

Reliability Coordinators for upcoming extreme weather operating day(s) 
Page 99 of 153

forecast (e.g., much below or above normal temperature conditions), for 

regions within their footprints.

• Identifying causes of any significant differences between forecasts.

• Re-forecast peak loads to reduce significant differences in forecast error for 

these timeframes.

• Incorporating actual historic temperatures and loads from atypical events 

like January 17, 2018, into future forecasts to capture potential peak 

demands during severe cold weather events.

With improved forecasting accuracy during the five-, four-, and three-day-ahead

timeframes, additional longer-lead-time actions, including additional Load Modifying

Resources, could have been taken to be better prepared for the operating day of January 

17, 2018.

A. Sound Practices 

Sound practices are just that—practices applied by one or more of the entities 

involved in the Event, which went beyond the requirements set forth in the mandatory 

Reliability Standards. The Team did not make a determination that they were “best 

practices,” but found them worthy of note.

Transmission Sound Practices

1) In evaluating next-day system conditions, and due to the time typically needed to 

start a generating unit, SeRC uses an “N-1-1 tool” for evaluating the need to 

commit additional generation resources to provide area reliability for voltage 

and/or thermal line flow problems. The N-1-1 tool will evaluate the outage of a 

generator as the first contingency (N-1), followed by the removal of a transmission 

element as a second contingency (N-1-1), to determine if additional online 

generation resources are needed to reliably operate. 

2) Given that large power transfers within BAs134 F

135 can impact neighboring systems, 

to improve reliable operation among neighboring BAs and RCs, MISO, SPP and 

the Joint Parties have established a method for identifying RDT-impacted 

flowgates based upon simulated power transfers, for:

a. The planning horizon, to perform the appropriate prior outage coordination 

activities and development of operating guides

 135 These power transfers are not interchange schedules between BAs. Intramarket/intra-BA transfers like these may exist elsewhere in the country and MISO’s 

experience may prove helpful to others.
Page 100 of 153

b. Real-time operations, to calculate the impact of RDT on flowgates to 

determine amount of RDT flow decrease needed based on the congestion 

on the RDT-impacted flowgate.

3) Neighboring RC operators demonstrated sound communication and coordination 

in managing real-time transmission constraints during the January 17, 2018 event. 

Faced with managing increasing transfers of power from remote generation135 F

136 to 

the south central U.S. to serve the record electricity demands, MISO operators 

contacted SPP operators offering and implementing generation redispatch actions 

to alleviate transmission constraints through their coordinated market-to-market 

process. Both RCs’ operators communicated and coordinated these types of 

actions at numerous times during the early morning hours on January 17, which 

aided in reliable BES operation.

4) To improve reliable operation during generation emergencies, MISO modified the 

rules for its Load Modifying Resources. The modified rules include requiring an 

LMR within MISO’s footprint to offer its capability based on actual capability in 

all seasons, and to deploy based on the shortest notification requirement that it can 

consistently meet.1 36F

137 Before the Event, some of MISO’s LMRs had very long 

notification requirements that limited their usefulness during unexpected events 

like those of January 17. 

5) To support reliable operations during extreme weather events such as the Event, 

SeRC employed what it called “dynamically rated” operating limits for 

transmission facilities based on the extremely cold weather, which effectively 

raised the limits allowing more power to reliably flow. Had static limits (yearround/summer limits) been used, it would have resulted in significant generation 

redispatch (detrimentally impacting BA contingency reserves), possible 

transmission reconfiguration, and/or TLRs. 

Generation Sound Practices

1) Southern Company (in the SeRC footprint), performed numerous generator fuel 

switches, using alternative fuel sources to help prevent a fuel supply emergency. 

 136 MISO and SPP wind generation provided one source of power supply to both 

footprints which suffered unplanned generation outages and derates.

137 See 166 FERC 61,116, ER19-650-000.
Page 101 of 153

Fuel-switching is especially important during cold weather. During extreme cold 

weather events, natural gas limitations can be predicted/expected to occur as

residential and commercial gas heating needs compete with electric generation 

needs, and gas pipeline entities can be expected to limit pipeline use to sustain gas 

pressure throughout the cold weather demand. 

2) Continuous monitoring of heat tracing systems complete with a display panel and 

indicator lights.

3) Inspection of heat tracing circuits, including power supplies, prior to winter.

4) Having regular, periodic operational checks of heat tracing circuits.

5) Annual update of winter preparation checklist, incorporating lessons learned from 

previous winter.

6) Completion of freeze protection-related maintenance prior to winter weather.

7) Increased operator rounds/increased staffing prior to, and during winter weather to 

check for proper operation of plant equipment susceptible to freezing conditions.

8) Addition of a “freeze protection operator,” during adverse weather who is 

responsible for inspecting critical equipment, and ensuring appropriate protection 

is in place.

9) Firing of dual fuel units that have not fired on their secondary fuel source during 

the previous year, prior to a forecast cold weather event.

10) RTO or RC conducting a survey of GO/GOP to determine winter preparedness 

activities have been completed, and fuel switching testing has been performed.

11) Sharing lessons learned by GO/GOP from extreme events, including through the 

NERC Events Analysis lessons learned program, or through Regional processes.

12) Developing procedures and training for Generator Operators on when to call for 

fuel switchable resources.

13) Maintaining inventory of pre-arranged supplies and equipment for extreme 

weather events by Generator Owners and Operators.
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14) Generator Owners and Operators conducting readiness drills on extreme weather 

preparation.

15) Generators connecting to multiple pipelines when possible to allow for obtaining 

gas supply during tight market conditions if one or more pipelines has operational 

issues or high utilization that forces cuts to interruptible supply.

16) Generators keeping close contact with natural gas pipeline companies during 

events to keep abreast of timely public postings of operational details such as 

operationally available capacity and unexpected outages, which allows generators 

to make more flexible and timely decisions.
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Appendices

FERC Staff

Office of Electric Reliability

Sanjay Bhatia

Robert Clark

David Huff

Anuj Kapadia

Thanh Luong

Mahmood Mirheydar

Matt Nutter

Raymond Orocco-John

Jomo Richardson

Office of Energy Market

Regulation

Noah Lichtenstein

Zeny Magos

Office of Energy Policy &

Innovation

Darren Sheets

Mary Wierzbicki

Office of Enforcement

Adam Bennett

Alan Haymes

Candace Jamison

Jeremy Medovoy

Heather Polzin

Jessica Wack

Office of the General Counsel

Kevin Ryan

NERC Staff

Clayton Calhoun

Kiel Lyons

Sonia Mendonca

Steven Noess

Tiffany Whaley

Regional Entity Staff

Midwest Reliability Organization

Richard Burt

John Seidel

ReliabilityFirst Corporation

Larry Bugh

Jeff Craigo

Dwayne Fewless

SERC Reliability Corporation

Melinda Montgomery

Tim Ponseti

Western Electricity Coordinating 

Council

Steve Ashbaker

Tim Reynolds

Appendix A: January 17, 2018 Cold Weather Inquiry Joint Team Members
Page 104 of 153

To help ensure that the electric grid operates as reliably and efficiently as possible, 

Congress granted FERC jurisdiction over electric grid reliability through the enactment 

of the Energy Policy Act of 2005 (EPAct), by adding a new section to the Federal Power 

Act, 16 U.S.C. § 215. Pursuant to its EPAct authority, FERC certified the North 

American Electric Reliability Corporation (NERC) as the Electric Reliability 

Organization (ERO) responsible for establishing mandatory Reliability Standards, which 

then must be approved by FERC. FERC also promulgated regulations, approved 

Regional Entities to serve as regional compliance authorities,137 F

138 and approved over 100 

NERC-proposed mandatory Reliability Standards. This jurisdiction and oversight over 

the grid’s reliability by FERC and NERC is vital to assuring consistent and dependable 

access to electricity. NERC currently has 16 Reliability Coordinators (RC) in North 

America to ensure that the grid is run efficiently and reliably. These RCs cover wide 

areas, and have the operating tools and processes to do so, including the authority to 

prevent or mitigate emergency operating situations. Midcontinent Independent System 

Operator (MISO), Southwest Power Pool (SPP), Tennessee Valley Authority (TVA) and 

Southeastern RC (SeRC) all served as RCs in the Event Area, and MISO and SPP are 

also Regional Transmission Organizations and Independent System Operators.13 8F

139 In the 

United States, RTOs and ISOs (hereafter, we will use RTO to refer to both) plan, operate 

and administer wholesale markets for electricity. MISO and SPP are RTOs that serve 

much of the Event Area discussed in this report. These entities, which are regulated by 

FERC, manage markets for energy and related services, for specific regions of the 

country. 

Ensuring reliable operation of the power grid is complex and requires constant 

analysis and assessment. This is true for two fundamental reasons: (1) it is difficult to 

economically store large quantities of electricity, so electricity must be produced the 

moment it is needed; and (2) because alternating current (AC) electricity flows freely 

along all available transmission paths through the path of least resistance, it must be 

constantly monitored to maintain electricity flows over transmission lines and voltages 

within appropriate limits. The power system therefore must be operated so that it is 

 138 The Regional Entities relevant to this event are ReliabilityFirst, Midwest 

Reliability Organization, and SERC Reliability Corporation.

139 See Figure 4 in the body of the report for a map of the Event Area.

Appendix B: Primer on Electric Markets and Reliable Operations of the BES
Page 105 of 153

prepared for conditions that could occur, but have not happened yet.139 F

140 Should an outage 

or reliability issue occur, system operators must act promptly to mitigate adverse 

conditions and remain within appropriate limits. For conditions severe enough that they 

could cause instability, uncontrolled separation or cascading outages, mitigation must 

occur within no more than 30 minutes. Equally vital to the continued operation of the 

grid is that it is restored to a condition where it can once again withstand the next-worst 

single contingency. 

All of the RTOs operate both “day-ahead” and a “real-time” energy markets. In 

the day-ahead market, buyers and sellers schedule electricity production and consumption 

before the operating day, which produces a financially-binding schedule, the day-ahead 

generation resource unit commitment, for electricity production and consumption one day 

prior to the actual generation and use. This provides generators and electricity loadserving entities a forecast of their needs prior to the day’s operations and enables system 

operators to prepare an Operating Plan Analysis for the next day.1 40F

141 To perform the dayahead unit commitment, RTO operators look for the most economic generators to 

schedule to be online for each hour of the following day, taking into account factors such 

as a unit’s minimum and maximum output levels, how quickly those levels can be 

adjusted and whether the unit has minimum time it must run once started, as well as 

operating costs. Operators need to take into account forecast electricity demand or load 

 140 NERC’s mandatory Reliability Standards require that the bulk-power system be 

operated so that it generally remains in reliable condition, without instability, 

uncontrolled separation or cascading, even with the occurrence of any single 

contingency, such as the loss of a generator, transformer, or transmission line. This is 

commonly referred to as the “N-1 criterion.” N-1 contingency planning allows entities to 

identify potential N-1 contingencies before they occur and to adopt mitigating measures, 

as necessary, to prevent instability, uncontrolled separation, or cascading. As FERC 

stated in Order No. 693 with regard to contingency planning, “a single contingency 

consists of a failure of a single element that faithfully duplicates what will happen in the 

actual system. Such an approach is necessary to ensure that planning will produce results 

that will enhance the reliability of that system. Thus, if the system is designed such that

failure of a single element removes from service multiple elements in order to isolate the 

faulted element, then that is what should be simulated to assess system performance.” 

Mandatory Reliability Standards for the Bulk Power System, Order No. 693, FERC Stats. 

& Regs. ¶ 31,242, at P 1716 (2007), order on reh’g, Mandatory Reliability Standards for 

the Bulk-Power System, 120 FERC ¶ 61,053 (Order No. 693-A) (2007).

141 See Appendix C, “RC and TOP Tools and Actions to Operate the BES in Real 

Time.”
Page 106 of 153

conditions for every hour of the next day, and other factors that could affect grid 

capabilities such as expected generation and transmission facility outages, any adverse 

weather conditions (e.g. severe heat or cold, precipitation, high winds), and line 

capacities. If the analysis suggests that optimal economic dispatch cannot be carried out 

reliably, more expensive generators may need to replace the cheaper generators to 

operate reliably. 

The current operating day, or real-time market, begins with the Operating Plan 

Analysis, created with generators who bid into and were chosen in the day-ahead market. 

It then reconciles any differences between the day-ahead schedule and the real-time load, 

while taking into account real-time conditions such as forced or unplanned generation 

and transmission outages, as well as electricity flow limits on transmission lines and other 

criteria, such as voltage, for BES reliability. 

RTOs also act as Reliability Coordinators and/or Transmission Operators, and 

may also act as Balancing Authorities, to oversee system reliability in their footprints.14 1F

142 

These are three of the functions for which the entities responsible for operating the BES 

in a reliable manner can register with NERC. These registrations then guide which of the 

mandatory Reliability Standards the entity must follow. A single entity can conduct 

multiple reliability functions and therefore have multiple NERC registrations. The 

NERC functional entity types most relevant to this event are Reliability Coordinator, 

Balancing Authority, Transmission Owner, Transmission Operator, Generator Owner, 

Generator Operator, Planning Coordinator, and Transmission Planner. 

The Reliability Coordinator is responsible for overseeing transmission operations 

for the wide area of the interconnection that it oversees. Similar to the Transmission 

Operator, below, the Reliability Coordinator ensures the reliable real-time operation of 

transmission assets by performing OPAs and preparing Operating Plans, but the 

Reliability Coordinator has the “wide-area” view, beyond any individual Transmission 

Operator. In coordination with other Reliability Coordinators, the Reliability Coordinator 

maintains situational awareness beyond its own boundaries, to enable it to operate within 

its Interconnection Reliability Operating Limits (limits necessary to prevent system 

instability and cascading outages) and maintain reliability of its area. Like the Balancing 

Authority, below, the Reliability Coordinator ensures the generation-demand balance is 

maintained, but within the larger Reliability Coordinator Area, thereby ensuring that the 

Interconnection frequency remains within acceptable limits. The Reliability Coordinators 

for the Event Area include MISO, SPP, TVA and SeRC.

 142 See Appendix E, “Categories of NERC Registered Entities.”
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The Balancing Authority (BA) integrates resource plans ahead of time, contributes 

to the Interconnection frequency in real time, and maintains the balance of electricity 

resources (generation and interchange) and electricity demand or load within the 

Balancing Authority Area. SPP RC, TVA RC, and SeRC contain multiple Balancing 

Authority Areas.

Transmission Operator and Generator Operator

The Transmission Operator (TOP) ensures the real-time operating reliability of the 

transmission assets within its area. It has the authority to take actions to ensure the 

continued reliable operation of the Transmission Operator Area. Like the RC, it performs 

daily OPAs and prepares Operating Plans, but for its smaller TOP footprint. The TOP 

coordinates with neighboring BAs and TOPs, as well as RCs, for reliable operations. The 

TOP also develops contingency plans, operates within established System Operating 

Limits, and monitors operations of the transmission facilities within its area. The 

following TOPs, among others, were affected by this event: AECI, LG&E and KU 

Services Co., MISO (MISO is registered as Transmission Operator and Transmission 

Planner in the RF and SERC Regions), PowerSouth, Southern Company Transmission, 

and TVA.

The Generator Owner (GO) owns and maintains generating facility(ies), while the 

Generator Operator (GOP) operates generating unit(s) which supply energy. The GOP 

also performs other services required to support reliable system operations, such as 

providing regulation and reserve capacity, and sharing data with BAs and TOPs as 

required. Many entities are both GOs and GOPs.

The Planning Authority (PA) coordinates and integrates transmission facility and 

service plans, resource plans, and protection systems, while the Transmission Planner 

(TP) develops a long-term (generally one year and beyond) plan for the reliability 

(adequacy) of the interconnected bulk electric transmission systems within its portion of 

the Planning Authority area.

Some of the key concepts to ensure the reliability of the electric transmission grid 

include:

• Voltage Control – Maintaining consistent voltage levels is imperative, as wide 

deviations in the voltage levels can have severe consequences. Voltage below 

certain limits could lead to an electric system imbalance or collapse. Voltages 

above certain limits can exceed insulation capabilities and cause dangerous 

electric arcs. Winter peak electricity loads include resistive loads such as resistive 

heating, which has a higher load power factor than during summer peak 

conditions. Load power factor is an indicator of reactive demand —the higher the 
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load power factor, the lower the reactive power demand. A relatively small 

percentage change in power factor, such as a change from 88% summer peak load 

power factor, to a 92% winter peak load power factor, can result in 30% less need 

for reactive power to be supplied during the winter. Summer peak electricity load 

includes air conditioning, which, like other induction motors, has lower power 

factors and consumes more reactive power than winter loads. Even with more 

stable voltages during winter peak conditions, system operators must continually 

monitor and evaluate system conditions, examining reactive reserves and voltages, 

and adjust the system as necessary for secure operation. 142 F

143

• Power Flow/Stability Control – Because of the danger resulting from low voltage 

levels, voltage stability limits are set to ensure that the unplanned loss of a 

generator or line will not cause dangerously low voltage levels. Additionally, 

power (or angle) stability limits are set to ensure that unplanned losses will not 

cause the remaining generators or lines to lose synchronism (or operate out of 

step) with each other, causing equipment damage.

• Short-Term and Long-Term Planning – Detailed system planning, design, 

maintenance, and analysis ensure reliable and safe operation of the system in the 

near- and long-term. Operations planning assesses day-ahead, week-ahead, 

seasonal, and up to one-year planning horizons. Short-term planning focuses on 

one- to five-year planning horizons, and long-term planning evaluates adequate 

generation resources and transmission capacity to ensure the system will be able to 

withstand severe contingencies in the future without widespread, cascading 

outages.

• Coordination and Communication Between Entities –the Reliability Standards 

encourage principal entities (e.g., Reliability Coordinators, Balancing Authorities, 

Transmission Operators, Generator Operators, and Distribution Providers) to 

communicate effectively in real-time to maintain system balance between 

generation and load, stay within operating limits, and address issues that arise. 

Ultimately, the RCs, BAs, TOPs and other responsible entities must work 

individually and together to comply with the mandatory Reliability Standards and to 

ensure the continued reliable operation of the bulk power system.

 143 U.S.-Canada Power System Outage Task Force “Final Report on the August 

14, 2003 Blackout in the United States and Canada: Causes and Recommendations” 

(April 2004) at 26.
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RCs and TOPs employ system operators and engineers who use various methods 

to forecast and evaluate upcoming and real-time issues, so as to avoid or mitigate 

problems that arise in their electric grids. They continually monitor transmission 

facilities 24 hours a day, seven days a week, for situational awareness of the power grid. 

System operators typically have available a variety of real-time computer tools for 

monitoring the system, including State Estimator (SE) and Real-Time Contingency 

Analysis (RTCA). 143 F

144 RC system operators are constantly monitoring RTCA and 

RTCA-based displays, including lists of facilities that exceed System Operating Limits or 

have voltages deviating from voltage criteria in real time, and lists of facilities that would 

exceed System Operating Limits or have voltages deviating from voltage criteria if a 

contingency were to occur (another system element, such as a line, transformer or 

generating unit, is outaged) (the latter list is called post-contingency exceedances). 

For both real-time and post-contingency limit exceedances, the system operators 

have a number of step-wise mitigating actions they can take to restore the facilities to 

within system limits or voltages to within voltage criteria. For simulated postcontingency exceedances, some operator actions are taken before the contingency occurs, 

while for other post-contingency exceedances, the operator relies on mitigation to be 

taken only if the contingency were to occur. Operators should only rely on postcontingency mitigation if they are confident that there would be sufficient time to 

complete the mitigation before adverse system conditions (such as instability or 

cascading outages) would occur. 

The mere fact that an actual or real-time system operating limit is exceeded does 

not necessarily mean that immediate reduction below the limit is required, although it 

does require immediate operator action. As an example, RC operators may contact 

Transmission Owners to determine if a temporarily-higher rating is warranted. For a 

projected next- or post-contingency System Operating Limit (SOL) exceedance, if also 

projected to exceed an Interconnection Reliability Operating Limit (IROL, meaning that 

it could lead to instability, uncontrolled separation, or cascading outages that adversely 

 144 SE constructs a representation of the state of the system using voltages, 

currents, and breaker status from the real-time data, and calculates values for which data 

are not directly collected; while RTCA runs frequently, for example, every two to six 

minutes for MISO and SPP, and informs the operators how the system would be affected 

for the computer-simulated outage or in other words used interchangeably, “for loss of” 

(FLO) a specific system facility such as a transmission line or a transformer.

Appendix C: RC and TOP Operator Tools and Actions to Operate the BES in 

Real Time
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impact the reliability of the BES), operators have a maximum of 30 minutes to take 

actions alleviate the IROL exceedance.144 F

145 Otherwise, operators identify mitigation 

measures they could take as part of their operating plan, which may include measures that 

would be implemented prior to, or if the next contingency occurred.

To aid in monitoring and regulating power flows across the transmission system 

(often referred to as managing transmission “congestion”), system operators in RTO 

areas define “flowgates,” by pairing specific transmission facilities and their associated 

next contingencies that would compound the transmission facility loading if the 

associated next contingency occurred. In addition to RTCA, RC operators in the Eastern 

Interconnection possess computer-based flowgate monitoring tools, which use the shared 

interchange distribution calculator (IDC) to calculate percentages of power flow impacts 

that each interchange power transfer schedule has on each flowgate; i.e., its transfer 

distribution factor, or TDF. For instance, if the need arises to reduce flowgate loading to 

remain within system operating limits, or in other words, alleviate market “congestion”, 

the flowgate monitoring tool enables the operators to determine the appropriate megawatt 

power flow amount that can be reduced in the external market transfer to achieve this 

goal. 

To manage the grid, the RC can take a wide-area view of all the regional resources 

available to it, resulting in a “dispatch stack” that contains generators from all generationowning members of the region, including utility and non-utility Generator Owners, as 

well as some generation resources outside the footprint. Many utilize a security 

constrained economic dispatch (SCED) algorithm to determine the appropriate and leastcost generating units to dispatch at any given time depending on market conditions. 

SCED aids the RTOs by, among other tasks, simultaneously balancing energy injections 

and withdrawals, managing congestion, and ensuring adequate operating reserves. The 

SCED process runs every five minutes to establish dispatch instructions for generators to 

meet the future load of the next five-minute period. The purpose of the algorithm is to 

minimize the cost to meet the forecast demand, scheduled interchange, and reserve 

requirements while also being subject to transmission congestion and other system 

reliability constraints. 

An initial approach to relieving transmission congestion constraints in RCs which 

are also RTOs is redispatching generation at different locations on the grid, done through 

SCED. When standard operating limits are reached, i.e., when constraints reach a 

 145 This time is defined as the “Interconnection Reliability Operating Limit Tv” which 

is the maximum time that an Interconnection Reliability Operating Limit can be violated 

before the risk to the interconnection or other Reliability Coordinator Area(s) becomes 

greater than acceptable. Each Interconnection Reliability Operating Limit’s Tv shall be 

less than or equal to 30 minutes.
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threshold at which other resources will soon need to be dispatched, market operators/RCs 

proactively enter constraints into SCED to begin preparation for unanticipated system 

events. When system operators change the day-ahead generation dispatch schedule to 

accommodate constraints or unexpected transmission or generation outages, it is known 

as “security constrained redispatch.” If non-cost measures do not alleviate the congestion 

concerns, operators should utilize least-cost redispatch measures, including initiating 

market-to-market (M2M) redispatch procedures for reciprocally coordinated flowgates 

(RCFs) between RTOs, or utilizing a transmission loading relief procedure (TLR), which 

prioritizes the various types of transmission services, allowing system operators to cut 

less-firm transportation flows first. 

Some RTOs that share a “seam,” or common border, including MISO and SPP, 

utilize the M2M coordination process between the RTOs to assist in maintaining 

efficient, reliable service for their respective regions. The M2M process allows for both 

RTOs’ RCs to coordinate interface pricing by modeling the same constraint. The 

previously-defined RCFs are monitored closely to gauge the impact of market flows and 

parallel flows from adjacent regions and markets. MISO and SPP can utilize M2M upon 

constraint activation in the market. During the course of the Event, MISO and SPP’s RC 

System Operators were in frequent communication with each other, analyzing congestion 

and engaging in M2M congestion management when necessary to relieve congestion on 

binding constraints, particularly during the early morning hours of January 17, 2018. 

Between the hours of 1 am and 10 am CST on January 17, MISO and SPP’s RC 

Operators had approximately 20 calls with each other to discuss grid issues and 

especially congested constraints, ultimately using M2M to alleviate congestion on several 

constraints. 

RC Operators can issue one or more TLR(s) to curtail transmission flowgate 

loadings on an hour-by-hour basis. TLRs are used to ration transmission capacity when 

demand for the transmission is greater than the available capacity. TLRs are typically 

utilized when the transmission system is overloaded to the point where power flows must 

be reduced in order to protect the system. The rationing is done based upon a priority 

structure that lowers or limits the power flows based on size, contractual terms, and 

scheduling, as opposed to the redispatch of lowest cost generation in M2M. 145 F

146 This 

method can be used in MISO and SPP at the RC’s discretion. 

 146 The NERC TLR Procedure is an Eastern Interconnection-wide process that allows 

Reliability Coordinators to mitigate potential or actual operating security limit violations 

while respecting transmission service reservation priorities. See 

https://www.nerc.com/pa/rrm/TLR/Pages/default.aspx
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The RC operators also used transmission reconfiguration to address real-time or 

post-contingency overloads during this timeframe. The practice of transmission 

reconfiguration, which involves mitigating the overload by opening and/or a combination 

of opening and closing switches (i.e. breakers), is typically not the first tool an operator 

would use to potentially alleviate overloaded facilities, because it brings with it potential 

reliability tradeoffs. But it still has an important practice in maintaining system reliability 
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and preventing worse outcomes, like cascading and uncontrolled loss of firm load. 

Transmission reconfiguration is included in the TLR process as Level 4. Before using 

transmission reconfiguration to alleviate overloads, the operators must conduct an 

assessment to pre-determine that the proposed reconfiguration will not introduce other 

reliability issues. Issues that operators would want to avoid include other, potentially 

more severe, real-time or next-contingency System Operating Limit exceedances 

(thermal, voltage or stability) on other bulk power system facilities, unexpected or 

unwanted changes to specific normal or emergency operating procedure steps, and 

changes to the expected behavior (resulting automatic actions) of system protection 

schemes and/or remedial action schemes which may be needed to clear a faulted 

condition on the transmission system. After assessment, the operator may determine that 

other changes need to be made to avoid one or more of the above issues, or may 

determine that transmission reconfiguration is not a viable option. Some reconfigurations 

may have already been studied, with pre-set procedures established for certain overload 

conditions for which system engineers have already analyzed the above issues.

If none of the preceding actions have eliminated the transmission system 

conditions, operators may need to use emergency procedures, ranging from calling on 

Load Modifying Resources to emergency energy purchases, up to firm load shed as a last 

resort. The high flows throughout the Event Area, but especially in MISO and SPP, 

caused the system operators to use nearly all available actions, short of shedding firm 

load, to maintain reliability of the bulk-electric system. 

The following illustration is a summary of MISO’s steps found in their Maximum 

Generation Emergency Procedures, and how they relate to the EEA levels defined by the 

Reliability Standards: 
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Adjacent RC - A Reliability Coordinator whose Reliability Coordinator Area is 

interconnected with another Reliability Coordinator Area.

Alternating Current (AC) - Electric current that changes periodically in magnitude and

direction with time. In power systems, the changes follow the pattern of a sine wave 

having a frequency of 60 cycles per second in North America. AC is also used to refer to 

voltage which follows a similar sine wave pattern.

Appendix D: Glossary of Terms Used In Report
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Ambient Conditions - Common, prevailing, and uncontrolled atmospheric conditions at 

a particular location, either indoors or out. The term is often used to describe the 

temperature, humidity, and airflow or wind that equipment or systems are exposed to.

Asynchronous - In AC power systems, two systems are asynchronous if they are not 

operating at exactly the same frequency. Two systems may also be considered 

asynchronous if, at potential interconnection points, there is a significant difference in 

phase angle between their respective voltage waveforms. 

Bulk Electric System - All Transmission Elements operated at 100 kV or higher and 

Real Power and Reactive Power resources connected at 100 kV or higher. This does not 

include facilities used in the local distribution of electric energy. The NERC Glossary of 

Terms Used in the Reliability Standards contains the list of inclusions and exclusions, 

and can be found at 

https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.

Capacitor - A capacitor is a device that stores an electric charge. Although there is 

energy associated with the stored charge, it is negligible in terms of its capability to serve 

load. A capacitor bank is made of up of many individual capacitors. Its purpose is to 

provide reactive power to the system to help support system voltage by compensating for 

reactive power losses incurred in the delivery of power.

Cascading - The uncontrolled successive loss of System Elements triggered by an 

incident at any location. Cascading results in widespread electric service interruption that 

cannot be restrained from sequentially spreading beyond an area predetermined by 

studies.

Constrained System Conditions - Conditions where multiple transmission facilities 

(lines, transformers, breakers, etc.) are approaching, are at, or are beyond their System 

Operating Limits.

Conductor - In physical terms, any material, usually metallic, exhibiting a low resistance 

to the flow of electric current. A conductor is the opposite of an insulator. In electric 

power systems, the term conductor generally refers to the actual wires in overhead 

transmission and distribution lines, underground cables, and the metallic tubing used for 

busses in substations. Aluminum and copper are the predominant metals used for 

conductors in power systems.

Contingency - The unexpected and sudden failure or outage of a power system 

component, such as a generator, transmission line, transformer, or other electrical 

element.
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Contingency Reserve - Contingency reserve is the provision of capacity deployed by a 

Balancing Authority to meet the Disturbance Control Standard (DCS) and other NERC 

and Regional Reliability Organization contingency requirements. Adequate generating

capacity must be available at all times to maintain scheduled frequency, and avoid loss of 

firm load following transmission or generation contingencies. This capacity is necessary 

to replace capacity and energy lost due to forced outages of generation or transmission 

equipment.

Curtail / Curtailment - A reduction in the scheduled capacity or energy delivery of an 

Interchange Transaction.

Demand - 1. The rate at which electric energy is delivered to or by a system or part of a 

system, generally expressed in kilowatts or megawatts, at a given instant or averaged 

over any designated interval of time. 2. The rate at which energy is being used by the

customer.

Demand Side Management - All activities or programs undertaken by any applicable 

entity to achieve a reduction in Demand.

Derate - A reduction in a generating unit’s net dependable capacity.

Direct Current (DC) - Electric current that is steady and does not change in either 

magnitude or direction with time. DC is also used to refer to voltage and, more generally, 

to smaller or special purpose power supply systems utilizing direct current either 

converted from AC, from a DC generator, from batteries, or from other sources such as 

solar cells.

Distribution Factor - The portion of an Interchange Transaction, typically expressed in 

per unit that flows across a transmission facility (Flowgate).

Emergency - Any abnormal system condition that requires automatic or immediate 

manual action to prevent or limit the failure of transmission facilities or generation 

supply that could adversely affect the reliability of the Bulk Electric System.

Emergency Rating - The rating as defined by the equipment owner that specifies the 

level of electrical loading or output, usually expressed in megawatts (MW) or MVAr or 

other appropriate units, that a system, facility, or element can support, produce, or 

withstand for a finite period. The rating assumes acceptable loss of equipment life or 

other physical or safety limitations for the equipment involved.
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Energy Emergency – A condition when a Load-Serving Entity or Balancing Authority 

has exhausted all other resource options and can no longer meet its expected Load 

obligations.

Energy Management System (EMS) - A system of computer-aided tools used by 

system operators to monitor, control and optimize system performance.

Export – In electric power systems, exports refer to energy that is generated in one 

power system, or portion of a power system, and transmitted to, and consumed in, 

another.

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.)

Facility Rating - 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.

Firm Load (or Firm Demand) - That portion of the Demand that a power supplier is 

obligated to provide except when system reliability is threatened or during emergency 

conditions.

Firm Transmission Service/Capacity - The highest quality (priority) service offered to 

customers under a filed rate schedule that anticipates no planned interruption.

Flowgate – 1) A portion of the Transmission system through which the Interchange 

Distribution Calculator calculates the power flow from Interchange Transactions. 2) A 

mathematical construct, comprised of one or more monitored transmission Facilities and 

optionally one or more contingency Facilities, used to analyze the impact of power flows 

upon the Bulk Electric System.

Force Majeure - A superior force, “act of God” or unexpected and disruptive event, 

which may serve to relieve a party from a contract or obligation.

Forced Outage – 1) The removal from service availability of a generating unit, 

transmission line, or other facility for emergency reasons. 2) The condition in which the 

equipment is unavailable due to unanticipated failure. 

Generation – The process of producing electrical energy from other sources of energy 

such as coal, natural gas, uranium, hydro power, wind, etc. More generally, generation 

can also refer to the amount of electric power produced, usually expressed in kilowatts 

(kW) or megawatts (MW) and/or the amount of electric energy produced, expressed in 

kilowatt hours (kWh) or megawatt hours (MWh).
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Generator - Generally, a rotating electromagnetic machine used to convert mechanical 

power to electrical power. The large synchronous generators common in electric power 

systems also serve the function of voltage support and voltage regulation by supplying or 

withdrawing reactive power from the transmission system, as needed.

Grid - An electrical transmission and/or distribution network. Broadly, an entire 

interconnection.

Heat Tracing – The application of a heat source to pipes, lines, and other equipment 

which, in order to function properly, must be kept from freezing. Heat tracing typically 

takes the form of a heating element running parallel with and in direct contact with 

piping.

Hour Ending - Data measured on a Clock Hour basis.

Interchange – Energy transfers that cross Balancing Authority boundaries.

Interchange Distribution Calculator (IDC) - The mechanism used by Reliability 

Coordinators in the Eastern Interconnection to calculate the distribution of Interchange 

Transactions over specific Flowgates. It includes a database of all Interchange 

Transactions and a matrix of the Distribution Factors for the Eastern Interconnection.

Import – In electric power systems, imports refer to energy that is transmitted to, and 

consumed in one power system, which is generated in another power system, or portion 

of another power system. 

Independent System Operator (ISO) - An organization responsible for the reliable 

operation of the power grid in a particular region and for providing open access 

transmission access to all market participants on a nondiscriminatory basis. 

Interchange - Electrical energy transfers that cross Balancing Authority boundaries.

Interchange Schedule - An agreed-upon Interchange Transaction size (megawatts), start 

and end time, beginning and ending ramp times and rate, and type required for delivery 

and receipt of power and energy between the Source and Sink Balancing Authorities 

involved in the transaction.

Interconnection – A geographic area in which the operation of Bulk Power System 

components is synchronized such that the failure of one or more of such components may 

adversely affect the ability of the operators of other components within the system to 

maintain Reliable Operation of the Facilities within their control. When capitalized, any 
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one of the four major electric system networks in North America: Eastern, Western, 

ERCOT and Quebec.

Interconnection Reliability Operating Limit - A System Operating Limit that, if 

violated, could lead to instability, uncontrolled separation, or Cascading outages that 

adversely impact the reliability of the Bulk Electric System.

Interruptible Load - Demand that the end-use customer makes available to its LoadServing Entity via contract or agreement for curtailment.

Load - See Demand (Electric).

Load-serving – Serves the electrical demand and energy requirements of its end-use 

customers.

Load Shed – The reduction of electrical system load or demand by interrupting the load 

flow to major customers and/or distribution circuits, normally in response to system or 

area capacity shortages or voltage control considerations. In cases of capacity shortages, 

load shedding is often performed on a rotating basis, systematically and in a 

predetermined sequence.

Market Flow - The total amount of power flowing across a specified Facility or set of 

Facilities due to a market dispatch of generation internal to the market to serve load 

internal to the market.

Most Severe Single Contingency (MSSC) - The Balancing Contingency Event, due to a 

single contingency identified using system models maintained within the Reserve Sharing 

Group (RSG) or a Balancing Authority’s area that is not part of a Reserve Sharing Group, 

that would result in the greatest loss (measured in MW) of resource output used by the 

RSG or a Balancing Authority that is not participating as a member of a RSG at the time 

of the event to meet Firm Demand and export obligation (excluding export obligation for 

which Contingency Reserve obligations are being met by the Sink Balancing Authority). 

Near-Term – The time period that covers the next day to multiple days ahead of the 

operating day.

Operating Plan - A document that identifies a group of activities that may be used to 

achieve some goal. An Operating Plan may contain Operating Procedures and Operating 

Processes. A company-specific system restoration plan that includes an Operating 

Procedure for black-starting units, Operating Processes for communicating restoration 

progress with other entities, etc., is an example of an Operating Plan.
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Operating Process - A document that identifies general steps for achieving a generic 

operating goal. An Operating Process includes steps with options that may be selected 

depending upon Real-time conditions. A guideline for controlling high voltage is an 

example of an Operating Process.

Operational Planning Analysis - An evaluation of projected system conditions to assess 

anticipated (pre-Contingency) and potential (post-Contingency) conditions for next-day 

operations. The evaluation shall reflect applicable inputs including, but not limited to, 

load forecasts; generation output levels; Interchange; known Protection System and 

Special Protection System status or degradation; Transmission outages; generator 

outages; Facility Ratings; and identified phase angle and equipment limitations. 

(Operational Planning Analysis may be provided through internal systems or through 

third-party services.)

Operating Reserve - That capability above firm system demand required to provide for 

regulation, load forecasting error, forced and scheduled equipment outages, and local area 

protection. It consists of spinning and non-spinning reserve.

Outage – The period during which a generating unit, transmission line, or other facility is 

out of service. Outages are typically categorized as forced, due to unanticipated problems 

that render a facility unable to perform its function and/or pose a risk to personnel or to 

the system, or scheduled / planned for the sake of maintenance, repairs, or upgrades.

Peak Load (or Peak Demand) – 1. The highest hourly integrated Net Energy For Load 

within a Balancing Authority Area occurring within a given period (e.g., day, month, 

season, or year). 2. The highest instantaneous demand within the Balancing Authority 

Area.

Post-Contingency - The resulting power system conditions (determined by computer 

simulation, or by actual real-time data) following the unexpected and sudden failure or 

outage of a power system component, such as a generator, transmission line, transformer, 

or other electrical element.

Power - In physics, power is defined as the rate at which energy is expended to do work. 

In the electric power industry, power is measured in watts (W), kilowatts (1 kW = 1,000 

watts), megawatts (1 MW = 1 million watts), or gigawatts (1 GW = 1 billion watts). For 

reference, 1 kW = 1.342 horsepower (hp).

Power System - The collective name given to the elements of the electrical system. The 

power system includes the generation, transmission, distribution, substations, etc. The 

term power system may refer to one section of a large interconnected system or to the 

entire interconnected system.
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Power Transfer Distribution Factor - In the pre-contingency configuration of a system 

under study, a measure of the responsiveness or change in electrical loadings on 

transmission system Facilities due to a change in electric power transfer from one area to 

another, expressed in percent (up to 100%) of the change in power transfer.

Rating - The operational limits of a transmission system element under a set of specified 

conditions. In power systems, equipment and facility power-handling ratings are usually 

expressed either in megawatts (MW) or in mega-volt-amperes (MVA). The term is also 

sometimes used to describe the output capability of generators.

Reactive Power – The portion of electricity that establishes and sustains the electric and 

magnetic fields of AC equipment. Reactive power must be supplied to most types of 

magnetic equipment, such as motors and transformers. It is also needed to make up for 

the reactive losses incurred when power flows through transmission facilities. Reactive 

power is supplied primarily by generators, capacitor banks, and the natural capacitance of 

overhead transmission lines and underground cables (with cables contributing much more 

per mile than lines). It can also be supplied by static VAR converters (SVCs) and other 

similar equipment utilizing power electronics, as well as by synchronous condensers. 

Reactive power directly influences system voltage such that supplying additional reactive 

power increases the voltage. It is usually expressed in kilovars (KVAr) or megavars 

(MVAr), and is also known as “imaginary power.”

Real-Time – Bulk Electric System conditions, characteristics and/or data representing 

what actually occurred at specific times or timeframes during the Event.

Real-Time Assessment – An evaluation of system conditions using Real-time data to 

assess existing (pre-Contingency) and potential (post-Contingency) operating conditions. 

The assessment shall reflect applicable inputs including, but not limited to: load, 

generation output levels, known Protection System and Special Protection System status 

or degradation, Transmission outages, generator outages, Interchange, Facility Ratings, 

and identified phase angle and equipment limitations. (Real-time Assessment may be 

provided through internal systems or through third-party services.)

Real-Time Contingency Analysis (RTCA) – A computer application which evaluates 

system conditions using real-time data to assess potential (post-contingency) operating 

conditions.

Regional Entity - An independent, regional entity having delegated authority from 

NERC to propose and enforce Reliability Standards and to otherwise promote the 

effective and efficient administration of bulk-power system reliability.

Regional Transmission Organization (RTO) - A voluntary organization of electric 

Transmission Owners, transmission users and other entities approved by FERC to 
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efficiently coordinate electric transmission planning (and expansion), operation, and use 

on a regional (and interregional) basis. Operation of transmission facilities by the RTO 

must be performed on a non-discriminatory basis.

Reliability Coordinator Area - The collection of generation, transmission, and loads 

within the boundaries of the Reliability Coordinator. Its boundary coincides with one or 

more Balancing Authority Areas.

System Operator: An individual at a control center of a Balancing Authority, 

Transmission Operator, or Reliability Coordinator, who operates or directs the operation 

of the Bulk Electric System in real‐time.

Stability – The ability of an electric system to maintain a state of equilibrium during 

normal and abnormal conditions or disturbances.

State Estimator – A computer application which evaluates system conditions using realtime data to assess existing operating conditions.

Transformer - A type of electrical equipment in the power system that operates on 

electromagnetic principles to increase (step up) or decrease (step down) voltage.

Transmission – An interconnected group of lines and associated equipment for the 

movement or transfer of electric energy between points of supply and points at which it is 

transformed for delivery to customers or is delivered to other electric systems.

Transmission Line – A system of structures, wires, insulators and associated hardware 

that carry electric energy from one point to another in an electric power system. Lines are 

operated at relatively high voltages varying from 69 kV up to 765 kV, and are capable of 

transmitting large quantities of electricity over long distances.

Trip - This refers to the automatic disconnection of a generator or transmission line by its 

circuit breakers. 

Voltage - The force characteristic of a separation of charge that causes electric current to 

flow. The symbol is “V” and units are volts or kilovolts (kV).

Wide Area - The entire Reliability Coordinator Area as well as the critical flow and 

status information from adjacent Reliability Coordinator Areas as determined by detailed 

system studies to allow the calculation of Interconnected Reliability Operating Limits.
Page 123 of 153

All registered entities fall within one or more of the following categories must 

register with NERC. Many entities carry out multiple roles and therefore have multiple 

registrations.

Function Type Acronym Definition/Discussion

Balancing 

Authority

BA The responsible entity that integrates resource plans 

ahead of time, maintains Demand and resource 

balance within a Balancing Authority Area, and 

supports Interconnection frequency in real time.

Generator Operator GOP The entity that operates generating Facility(ies) and 

performs the functions of supplying energy and 

Interconnected Operations Services.

Generator Owner GO Entity that owns and maintains generating 

Facility(ies).

Planning 

Authority/Planning 

Coordinator

PA/PC The responsible entity that coordinates and 

integrates transmission Facilities and service plans, 

resource plans, and Protection Systems.

Reliability 

Coordinator

RC The entity that is the highest level of authority who 

is responsible for the Reliable Operation of the Bulk 

Electric System, has the Wide Area view of the Bulk 

Electric System, and has the operating tools, 

processes and procedures, including the authority to

prevent or mitigate emergency operating situations 

in both next-day analysis and real-time operations. 

The Reliability Coordinator has the purview that is 

broad enough to enable the calculation of 

Interconnection Reliability Operating Limits, which 

may be based on the operating parameters of 

transmission systems beyond any Transmission 

Operator’s vision.

Transmission 

Operator

TOP The entity responsible for the reliability of its “local” 

transmission system, and that operates or directs the 

operations of the transmission Facilities.

Transmission 

Owner

TO The entity that owns and maintains transmission 

Facilities.

Transmission 

Planner

TP The entity that develops a long-term (generally one 

year and beyond) plan for the reliability (adequacy) 

of the interconnected bulk electric transmission 

systems within its portion of the Planning Authority 

area.

Appendix E: Categories of NERC Registered Entities
Page 124 of 153

AC Alternating Current

AECI Associated Electric Cooperative, Inc.

BA Balancing Authority

BES Bulk Electric System

CST Central Standard Time

DC Direct Current

DSM Demand-Side Management

EEA Energy Emergency Alert

EHV Extra-High Voltage

EMS Energy Management System

EOP Emergency Operations Planning

ERCOT Electric Reliability Council of Texas

ERO Electric Reliability Organization

FERC Federal Energy Regulatory Commission

FRAC Forward Reliability Assessment Commitment

GFCI Ground Fault Circuit Interrupter

GO Generator Owner

GOP Generator Operator

HVDC High Voltage Direct Current

IROL Interconnection Operating Reliability Limit

ISO Independent System Operator

kV Kilovolt

LBA Local Balancing Authority

LG&E/KU Louisville Gas and Electric/Kentucky Utilities

LMR Load Modifying Resources

MSSC Most Severe Single Contingency

MISO Midcontinent Independent System Operator, Inc.

MRO Midwest Reliability Organization

MVA Megavolt-Ampere

MW Megawatt

NERC North American Electric Reliability Corporation

OPA Operational Planning Analysis

PC Planning Coordinator

RC Reliability Coordinator

RCIS Reliability Coordinator Information System

RDT Regional Directional Transfer

RDTL Regional Directional Transfer Limit

RF ReliabilityFirst Corporation

RTCA Real-Time Contingency Analysis

Appendix F: Acronyms Used in the Report
Page 125 of 153

RTO Regional Transmission Organization

RTOC Regional Transfer Operating Committee

RTOP Regional Transfer Operating Procedure

SCED Security Constrained Economic Dispatch

SCRD Security Constrained Redispatch

SERC SERC Corporation

SeRC Southeastern Reliability Coordinator

SOL System Operating Limit

SPP Southwest Power Pool, Inc.

SRPBC Sub-Regional Power Balance Constraint

TLR Transmission Loading Relief

TO Transmission Owner

TOP Transmission Operator

TP Transmission Planner

TVA Tennessee Valley Authority

UDS Unit Dispatch System

VSA Voltage Stability Analysis

WECC Western Electricity Coordinating Council

wEFOR Weighted Equivalent Forced Outage Rate

WSC Worst Single Contingency
Page 126 of 153

In September, 2011, after an inquiry into the controlled shedding of 4,000 MW of 

firm load in Texas’s ERCOT footprint, NERC and the Commission issued a group of 

recommendations aimed at helping other entities in warm climates avoid losing firm load 

when extreme cold weather strikes. Many of those recommendations are equally 

appropriate for this event, so we reprint them below, with minor edits as shown in italics. 

Supporting text has been edited to make it more broadly applicable. The numbers [may] 

not be sequential due to the omission of highly ERCOT-specific recommendations. We 

also briefly discuss actions taken in response to the recommendations.

PLANNING AND RESERVES

1. Balancing Authorities, Reliability Coordinators, Transmission

Operators and Generator Owner/Operators in summer peaking areas should 

consider preparation for the winter season as critical as preparation for the summer 

peak season.

The large number of generating units that failed to start, tripped offline or had to 

be derated during the event demonstrates that the generators did not adequately anticipate 

the full impact of the cold weather. While plant personnel and system operators, in the 

main, performed admirably during the event, more thorough preparation for cold weather 

could potentially have prevented many of the weather-related outages. Capacity margins 

going into the winter were adequate on paper. But those margins did not take into account 

whether many of the units counted would be capable of running during the severe cold 

weather that materialized in mid-January. While the probability of a winter event in the 

predominantly summer peaking south-central U.S. appears to be low, shedding load in 

the winter places lives and property at risk. The task force recommends that all entities 

responsible for the reliability of the bulk power system in the Southwest prepare for the 

winter season with the same sense of urgency and priority as they prepare for the summer 

peak season.

2. Planning authorities should augment their winter assessments with sensitivity 

studies incorporating conditions like the Event to ensure there are sufficient 

generation and reserves in the operational time horizon.

All of the affected RCs undertake planning studies to ensure that sufficient reserves 

are available to meet seasonal peak loads. However, conditions experienced on January 

17 were more severe than predicted in seasonal studies.

Appendix G: 2011 Recommendations Regarding Preparation for 

Cold-Weather Events
Page 127 of 153

Planners should undertake a sensitivity study, using the 2011 actual conditions [or 

another actual severe winter event] as a possible extreme scenario that reflects expected 

limits on available generation. These limits would include those due to planned outages, 

limited operations during periods of extreme cold weather, ambient temperature 

operating limitations, and any likely loss of fuel sources. This sensitivity study should be 

used by operational planners to identify various system stress points, and by Reliability 

Coordinators, Balancing Authorities, and Transmission Operators to improve and refine 

strategies to preserve the reliability of the bulk power system during an extended cold 

weather event. These strategies should include procedures relating to utilization of 

generators with fuel switching capabilities and implementing early start-ups for 

generators with long start-up times.

3. Balancing Authorities and Reserve Sharing Groups should review the 

distribution of reserves to ensure that they are useable and deliverable during 

contingencies.

This recommendation is designed to ensure that Balancing Authorities take into 

account transmission constraints, other demands on reserve sharing resources, the 

possibility that more than one reserve sharing group member might experience 

simultaneous emergencies, and other factors that might affect the availability or 

deliverability of reserves. 

4. This Recommendation was focused on ERCOT’s specific outage request protocol, 

which ERCOT changed as a result of the Recommendation. Some of the supporting 

text may be helpful and remains below.

ISOs, RCs and TOPs should consider whether they have the authority to cancel 

previously approved outages in cases of approaching extreme weather conditions, even 

up to the time of the event itself. In making this evaluation, they should take into account 

the costs that would be imposed on the generator as well as the practical difficulties of 

returning it to service if plant components are disassembled, as well as the generator’s 

need to perform maintenance at some point while also avoiding the high- demand 

summer season. In addition to the criteria for outage evaluation currently provided the 

report also recommended taking into consideration the potential loss of units based on 

weather conditions beyond their design limits, and the effects likely to result from the 

totality of scheduled and proposed outages.

In furtherance of these criteria, ISOs, RCs and TOPs should:

• Have available the design temperatures of all generation resources.

• Take into consideration as an extreme weather event approaches which plants will 

not be available based on their design temperature limits.
Page 128 of 153

• Consider increasing reserve levels during extreme weather events.

• Commit, for purposes of serving load and being counted as reserves, only those 

plants whose temperature design limits fall within the forecast temperature range.

• Determine, prior to approving an outage, if the combination of previously 

approved scheduled outages with the proposed scheduled outages might cause 

reliability problems.

5. RCs and TOPs should consider increasing responsive reserve requirements in 

extreme low temperatures, (ii) directing generating units to utilize preoperational 

warming prior to anticipated severe cold weather, and (iii) verifying with each 

generating unit its preparedness for severe cold weather, including operating limits, 

potential fuel needs and fuel switching abilities.

ERCOT data on forced outages during the 50 coldest days between 2005-

2011 show a correlation between low temperatures and forced outages. This was 

demonstrated not only by the February 2011 event but also by the 1989 event; in both 

cases, extremely low temperatures led to the loss of large amounts of generation and the 

implementation of rolling blackouts. Increasing the amount of responsive reserves going 

into a cold weather event would compensate for the probability that a number of 

generating units might fail, and would provide better response to system instability in the 

event of such losses. Additionally, pre-operational warming would help prevent freezing 

and identify other operational problems. Running a unit prior to the start of extreme cold 

weather would utilize the unit’s own radiant heat to help prevent freezing. And starting it 

up would permit correction of any problems that otherwise would not be noticed until the 

unit was called upon for performance. While pre-operational warming has considerable 

value, issues of whether or how generators are to be compensated for taking such actions 

at ERCOT’s direction would need to be addressed.

COORDINATION WITH GENERATOR OWNERS/OPERATORS

6. Transmission Operators, Balancing Authorities, and Generator Owner/Operators 

should consider developing mechanisms to verify that units that have fuel switching 

capabilities can periodically demonstrate those capabilities.

During the ERCOT cold weather event, a quarter of the 20 units that attempted to 

switch fuel were unsuccessful. If a unit represents itself as having fuel switching 

capability, verification of the adequacy of its capability would provide useful information 

to the Balancing Authority or Transmission Operator as to the availability of that unit in 

the event of natural gas curtailments. Fuel switching verification might consist of the 

following:
Page 129 of 153

• Documented time required to switch equipment,

• Documented unit capacity while on alternate fuel,

• Operator training and experience,

• Fuel switching equipment problems, and

• Boiler and combustion control adjustments needed to operate on alternate fuel.

7. Balancing Authorities, Transmission Operators and Generator

Owners/Operators should take the steps necessary to ensure that black start units 

can be utilized during adverse weather and emergency conditions.

8. Balancing Authorities, Reliability Coordinators and Transmission Operators 

should require Generator Owner/Operators to provide accurate ambient 

temperature design specifications. Balancing Authorities, Reliability Coordinators 

and Transmission Operators should verify that temperature design limit 

information is kept current and should use this information to determine whether

individual generating units will be available during extreme weather events.

In order to ascertain actual capabilities during extreme weather conditions,

Balancing Authorities and Reliability Coordinators should require Generator

Owner/Operators to provide accurate ambient temperature design operating limits for 

each generating unit that is included in its portfolio (including the accelerated cooling 

effect of wind), and update them as necessary. These limits should take into account all 

temperature-affected generator, turbine, and boiler equipment, and associated ancillary 

equipment and controls. The Balancing Authorities should take steps to verify that 

Generator Owner/Operators comply with this requirement, and should prepare for the 

winter season by developing a catalog of individual generating unit temperature 

limitations. These should be used to determine if forecast temperatures place a particular 

generating unit in a high-risk category. Lastly, Balancing Authorities and Reliability 

Coordinators should consider the feasibility of counting on a generating unit whose rating 

falls below forecast weather conditions, and should consider whether to take into account 

weather-related design specifications in ranking units in the supply stack during critical 

weather events.

9. Transmission Operators and Balancing Authorities should obtain from

Generator Owner/Operators their forecasts of real output capability in advance of 

an anticipated severe weather event; the forecasts should take into account both the 

temperature beyond which the availability of the generating unit cannot be 

assumed, and the potential for natural gas curtailments.
Page 130 of 153

This Recommendation previously referred to Reliability Standard TOP-002-02 

R15, which is no longer in effect. Balancing Authorities and Transmission Operators 

could obtain similar, although perhaps not exact, results through Reliability Standard 

TOP-003-3, which allows Balancing Authorities and Transmission Operators to 

designate specific data required from entities like the Generator Owner/Operators. 

Doing so would allow operators to make proactive decisions prior to the onset of cold 

weather, including but not limited to:

• Requesting cancellation of planned outages,

• Directing advanced fuel switching,

• Directing startup of units with startup times greater than one day,

• Requesting startup of seasonally mothballed units, and

• Making advance requests for conservation.

Consideration needs to be given to ensuring that there is an adequate cost recovery 

mechanism in place for reliability measures taken by the generators at the direction of the 

Balancing Authority or Transmission Operator.

10. Balancing Authorities should plan ahead so that emergency enforcement 

discretion regarding emission limitations [from state or Federal environmental 

authorities] can be quickly implemented in the event of severe capacity shortages.

WINTERIZATION

11. States should examine whether Generator/Operators ought to be required to 

submit winterization plans, and should consider enacting legislation where 

necessary and appropriate.

The task force determined during its inquiry that certain generators were better 

prepared than others to respond to the February [2011] cold weather event. In many cases 

the entities that performed well had emergency operations or winterization plans in place 

to provide direction to employees on how to keep their units operating. Although the 

implementation of a winterization plan cannot guarantee that a unit will not succumb to 

cold weather conditions, it can reduce the likelihood of unit trips, derates and failed 

starts.

. . .[T]he task force recommends that planning take into account not only forecasts 

but also historical weather patterns, so that the required procedures accommodate 
Page 131 of 153

unusually severe events. Statutes should ideally direct utility commissions to develop best 

winterization practices for its state, and make winterization plans mandatory.

Lastly, it is recommended that legislatures consider granting utility commissions the 

authority to impose penalties for non-compliance, as well as to require senior 

management to acknowledge that they have reviewed the winterization plans for their 

generating unit, that the plans are an accurate representation of the winterization work 

completed, and that they are appropriate for the unit in light of seasonal weather 

conditions. In 2011, NERC staff concluded there would be a reliability benefit from 

amending the EOP Reliability Standards to require Generator Owner/Operators to 

develop, maintain, and implement plans to winterize plants and units prior to extreme 

cold weather, in order to maximize generator output and availability.

Accordingly, NERC intends to submit a Standard Authorization Request, the first step in 

the Reliability Standards development process, proposing modifications to the Reliability 

Standards for Emergency Preparedness and Operations. Although NERC did submit the 

Standard Authorization Request, no such modification was made to the Reliability 

Standards.

Plant Design

12. Consideration should be given to designing all new generating plants and 

designing modifications to existing plants (unless committed solely for summer 

peaking purposes) to be able to perform at the lowest recorded ambient 

temperature for the nearest city for which historical weather data is available, 

factoring in accelerated heat loss due to wind speed.

The ideal time to prepare a generating unit to withstand cold temperatures is in the 

design stage. For that reason, the low temperatures and wind chills that can occur during 

the occasional severe storm should be incorporated in the design process.

13. The temperature design parameters of existing generating units should be 

assessed.

The task force found that for existing generating units, it is often not known with 

any specificity at what temperature the unit will be able to operate, or to what 

temperature heat tracing and insulation can prevent the water or moisture in its critical 

components from freezing. For that reason, Generator Owner/Operators should conduct 

engineering analyses to ascertain each unit’s operating parameters, and then take 

appropriate steps to ensure that each unit will be able to achieve the optimum level of 

performance of which it is capable.

The task force recommends the following:
Page 132 of 153

• Each Generator Owner/Operator should obtain or perform a comprehensive 

engineering analysis to identify potential freezing problems or other cold weather 

operational issues. The analysis should identify components/systems that have the 

potential to: initiate an automatic unit trip, prevent successful unit start-up, initiate 

automatic unit runback schemes and/or cause partial outages, adversely affect 

environmental controls that could cause full or partial outages, adversely affect the 

delivery of fuel to the units, or cause other operational problems such as slowed 

valve/damper operation.

• If a Generator Owner/Operator does not have accurate information about the 

ambient temperature to which an existing unit was designed, or if extensive 

modifications have been made since the unit was designed (including changes to 

plant site), it should obtain an engineering analysis regarding the lowest ambient 

temperatures at which the unit can reliably operate (including wind chill 

considerations).

• Each Generator Owner/Operator should ensure that its heat tracing, insulation, 

lagging and wind breaks are designed to maintain water temperature (in those lines 

with standing water) at or above 40 degrees when ambient temperature, taking into 

account the accelerated heat loss due to wind, falls below freezing.

• Each Generator Owner/Operator should determine the duration that it can maintain 

water, air, or fluid systems above freezing when offline, and have contingency 

plans for periods of freezing temperatures exceeding this duration.

Maintenance/inspections generally

14. Generator Owner/Operators should ensure that adequate maintenance and 

inspection of freeze protection elements be conducted on a timely and repetitive 

basis.

The task force found a number of inadequacies in generating units’ preparations 

for winter performance. These included a lack of accountability and senior management 

review, lack of an adequate inspection and maintenance program, and failure to perform 

engineering analyses to determine the correct capability needed for their protection 

equipment.

The task force recommends the following:

• Each Generator Owner/Operator’s senior management should establish policies 

that make winter preparation a priority each fall, establish personnel accountability 

and audit procedures, and reinforce the policies annually.
Page 133 of 153

• Each Generator Owner/Operator should develop a winter preventive maintenance 

program for its freeze protection elements, which should specify inspection and 

testing intervals both before and during the winter. At the end of winter, an 

additional round of inspections and testing should be performed and an evaluation 

made of freeze protection performance, in order to identify potential 

improvements, required maintenance, and freeze protection component 

replacement for the following winter season.

• Each Generator Owner/Operator should prioritize repairs identified by the 

inspection and testing the proper functioning of freeze protection systems will be 

completed before the following winter.

• Each Generator Owner/Operator should use the recommended comprehensive 

engineering analysis, combined with previous lessons learned, to prepare and 

update a winter preparation checklist. Generator Owner/Operators should 

update checklists annually, using the previous winter’s lessons learned and 

industry best practices.

Specific Freeze Protection Maintenance Items

The task force found that many generating units tripped, were derated, or failed 

to start as a result of problems associated with a failure to install and maintain adequate 

freeze protection systems and equipment. Based on these findings, on an examination 

of freeze protection systems of many of the affected generating units, and in some case 

on standards issued by the Institute of Electrical and Electronics Engineers, the task 

force has prepared a number of recommendations designed to prevent a repeat of the 

spotty generator performance experienced during the February cold weather event. Of 

course, specific actions should conform to best industry practices at the time 

improvements are made, as well as to the requirements of any mandatory winterization 

standards imposed by regulatory or legislative bodies.

Heat tracing

15. Each Generator Owner/Operator should inspect and maintain its generating 

units’ heat tracing equipment.

Specifically, the task force recommends:

• Each Generator Owner/Operator should, before each winter begins and before 

forecast freezing weather, inspect the power supply to all heat trace circuits, 

including all breakers and fuses.
Page 134 of 153

• Each Generator Owner/Operator should, before each winter begins and before 

forecast freezing weather, inspect the continuity of all heat trace circuits, check 

the integrity of all connections in the heat trace circuits, and ensure that all 

insulation on heat traces is intact. This inspection should include checking for 

loose connections, broken wires, corrosion, and other damage to the integrity of 

electrical insulation which could cause grounds.

• Each Generator Owner/Operator should, before each winter begins, inspect, test, 

and maintain all heat trace controls or monitoring devices for proper operation, 

including but not limited to thermostats, local and remote alarms, lights, and 

monitoring cabinet heaters.

• Each Generator Owner/Operator should, before each winter begins, test the 

amperage and voltage for its heat tracing circuits and calculate whether the 

circuits are producing the output specified in the design criteria, and maintain or 

repair the circuits as needed.

• Each Generator Owner/Operator should be aware of the intended useful life of 

its heat tracing equipment and should plan for its replacement in accordance with 

the manufacturer’s recommendations.

Thermal Insulation

16. Each Generator Owner/Operator should inspect and maintain its units’ 

thermal insulation.

Specifically, the task force recommends:

• Each Generator Owner/Operator should, before each winter begins, inspect all 

accessible thermal insulation and verify that there are no cuts, tears, or holes in 

the insulation, or evidence of degradation.

• Each Generator Owner/Operator should require visual inspection of thermal 

insulation for damage after repairs or maintenance have been conducted in the 

vicinity of the insulation.

• Each Generator Owner/Operator should ensure that valves and connections are 

insulated to the same temperature specifications as the piping connected to it.

• Each Generator Owner/Operator should be aware of the intended useful life of 

the insulation of water lines and should plan for its replacement in accordance 

with the manufacturer’s recommendations.
Page 135 of 153

Use of Wind breaks/enclosures

17. Each Generator Owner/Operator should plan on the erection of adequate wind 

breaks and enclosures, where needed.

Specifically, the task force recommends:

• A separate engineering assessment should be performed for each generating unit 

to determine the proper placement of temporary and/or permanent wind breaks 

or enclosures to protect and prevent freezing of critical and vulnerable elements 

during extreme weather.

• Temporary wind breaks should be designed to withstand high winds, and should 

be fabricated and installed before extreme weather begins.

• Generator Owner/Operators should take into account the fact that sustained 

winds and/or low temperatures can result in heat loss and freezing even in 

enclosed or semi-enclosed areas.

Training

18. Each Generator Owner/Operator should develop and annually conduct winterspecific and plant-specific operator awareness and maintenance training.

Operator training should include awareness of the capabilities and limitations of 

the freeze protection monitoring system, proper methods to check insulation integrity 

and the reliability and output of heat tracing, and prioritization of repair orders when 

problems are discovered.

Other Generator Owner/Operator Actions

19. Each Generator Owner/Operator should take steps to ensure that 

winterization supplies and equipment are in place before the winter season, that 

adequate staffing is in place for cold weather events, and that preventative action 

in anticipation of such events is taken in a timely manner.

Specifically, the task force recommends:

• Each Generator Owner/Operator should maintain a sufficient inventory of 

supplies at each generating unit necessary for extreme weather preparations and 

operations.
Page 136 of 153

• Each Generator Owner/Operator should place thermometers in rooms containing 

equipment sensitive to cold and in freeze protection enclosures to ensure that 

temperature is being maintained above freezing and to determine the need for 

additional heaters or other freeze protection.

• During extreme cold weather events, each Generator Owner/Operator should 

schedule additional personnel for around-the-clock coverage.

• Each Generator Owner/Operator should evaluate whether it has sufficient 

electrical circuits and capacity to operate portable heaters, and perform 

preventive maintenance on all portable heaters prior to cold weather.

• Each Generator Owner/Operator should drain any non-critical service water lines 

in anticipation of severe cold weather.

Transmission Facilities

20. Transmission Operators should ensure that transmission facilities are capable 

of performing during cold weather conditions.

Transmission Operators reported several incidents of unplanned outages during 

the February 2011 event as a result of circuit breaker trips, transformer trips, and other 

transmission line issues. Although these outages did not generally contribute materially 

to any transmission limitations, some transmission breaker outages did lead to the loss 

of generating units. Many breaker trips were the result of low air in the breaker, low 

sulfur hexa-fluoride (SF6) gas pressure, failed or inadequate heaters, bad contacts, and 

gas leaks.

Specifically, the task force recommends:

• Transmission Owner/Operators should ensure that the SF6 gas in breakers and 

metering and other electrical equipment is at the correct pressure and 

temperature to operate safely during extreme cold, and also perform annual 

maintenance that tests SF6 breaker heaters and supporting circuitry to assure that 

they are functional.

• Transmission Owner/Operators should maintain the operation of power 

transformers in cold temperatures by checking heaters in the control cabinets, 

verifying that main tank oil levels are appropriate for the actual oil temperature, 

checking bushing oil levels, and checking the nitrogen pressure if necessary.

• Transmission Owner/Operators should determine the ambient temperature to 

which their equipment, including fire protection systems, is protected (taking 
Page 137 of 153

into account the accelerated cooling effect of wind), and ensure that temperature 

requirements are met during operations

24. All Transmission Operators and Balancing Authorities should examine their 

emergency communications protocols or procedures to ensure that not too much 

responsibility is placed on a single system operator or on other key personnel 

during an emergency, and should consider developing single points of contact 

(persons who are not otherwise responsible for emergency operations) for 

communications during an emergency or likely emergency.

The task force’s review of incidents during the event, as well as of operating 

procedures and protocols in place at the time, indicated that critical employees such as 

operators had numerous responsibilities that, while manageable in non-emergency 

situations, could prove impossible to meet during the often-compressed time frame of an 

emergency situation. In at least one instance, overloading a single on-call operations 

representative appears to have led to a delay in making emergency power purchases.

LOAD SHEDDING

25. Transmission Operators and Distribution Providers should conduct critical 

load review for gas production and transmission facilities, and determine the level 

of protection such facilities should be accorded in the event of system stress or load 

shedding.

Keeping gas production facilities in service is critical to maintaining an adequate 

supply of natural gas, particularly in the Southwest where there is a relatively small 

amount of underground gas storage. And keeping electric-powered compressors running 

can be important in maintaining adequate pressure in gas transmission lines.

The task force suggests that a review of curtailment priorities be made, to consider 

whether gas production facilities should be treated as protected loads in the event of load 

shedding.

26. Transmission Operators should train operators in proper load shedding 

procedures and conduct periodic drills to maintain their load shedding skills.

The task force found that at least one Transmission Operator in WECC 

experienced a minor delay in initiating its load shedding sequence, due to problems 

notifying the concerned Distribution Provider. Another Transmission Operator 

experienced delay in executing its load shedding because the individual operators had 

never shed load before and had not had recent drills. These incidents underscore the 

necessity of adequate training in load shedding procedures.

Actions taken in Texas following 2011 Recommendations
Page 138 of 153

Following the issuance of FERC and NERC’s guidance in the February 2011 Cold 

Weather Report, Texas regulators and lawmakers took affirmative action to investigate 

and improve industry practices during extreme weather events. In that Report, FERC and 

NERC made several recommendations directed at improving reliability during extreme 

weather events, including recommending the assessment of whether minimum standards 

should be adopted for the winterization of gas production and processing facilities and 

assessments related to the priority and efficiency of natural gas curtailments.146 F

147 

The Texas Public Utility Commission (Texas PUC) required utilities to strengthen 

their emergency preparedness plans and to ensure those plans included provisions for 

severe cold weather. The Texas PUC amended its Electric Service Emergency 

Operations Plans regulation (16 T.A.C. § 25.53) to require that electric generation 

utilities’ emergency operations plans (filed with the Texas PUC) include “a plan for 

identification of potentially severe weather events, including . . . severely cold weather,” 

a plan for “the inventory of pre-arranged supplies for emergencies,” a plan addressing 

“staffing during severe weather events,” “checklists for generating facility personnel to 

address emergency events,” and a plan for “alternative fuel testing if the facility has the 

ability to utilize alternative fuels.” 16 T.A.C. § 25.53(c)(2)(D-G, I) (2018). 

The Texas PUC also commissioned a third-party report on best practices for 

extreme weather preparedness. This report, published in September 2012, made 

additional recommendations regarding the identification and awareness of extreme 

weather events, the identification and understanding of critical failure points within plants 

and adequate staffing levels, and training for such events, and was submitted to the Texas 

state legislature. 

Together, the Texas PUC, the Railroad Commission of Texas, and the Texas State 

Energy Conservation Office collaborated on an Energy Assurance Plan that was 

published in November 2012.147 F

148 This Plan demonstrated the thoughtful engagement of 

these entities on reliability issues surrounding extreme weather events. It included 

evaluating updates to the 1973 gas curtailment plan and potentially refining the Texas 

PUC’s list of its critical nodes. Additionally, as part of the Plan, ERCOT engaged a third 

party to conduct a gas curtailment risk study. 

 147 2011 Report at 214-17.

148 Texas Energy Assurance Plan, Nov. 2012, found at 

https://www.puc.texas.gov/industry/electric/reports/energy_assurance/Energy_Assurance

_Plan-Texas.pdf (last accessed April 9, 2019).
Page 139 of 153

Figure No. Title Created By Source of Data

1 January 17, 

2018 Event Area 

– Low 

Temperature 

Deviation from 

the Normal 

Daily Minimum

Commission 

Staff

NOAA weather data, prepared 

using ABB Ventyx Velocity 

Suite© software

2 MISO and SPP 

RTO Footprints

MISO and 

SPP

SEAMS WHITE PAPER

FOR ORGANIZATION OF 

MISO STATES (OMS) AND SPP 

REGIONAL STATE 

COMMITTEE (RSC)

LIAISON COMMITTEE 

(November 2, 2018) 

(https://www.spp.org/documents/59006/

sppmiso_rsc_oms_response_spp_miso_final

_v3.pdf), used by permission from 

Organization of MISO States.

3 Tie Lines 

Between MISO 

and SPP RC 

Versus Within 

MISO

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

4 Electric 

Transmission 

Lines and Cities 

within the Event 

Area

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 

Velocity Suite© software

5 MISO Midwest 

to MISO South 

Intra-Market 

Regional 

Directional 

Transfers (RDT)

Entities, 

Commission 

Staff

Illustration provided by entities, 

with additional graphics added 

using MS® Office 2013

6 Upcoming 

Season Forecast 

2017/2018 

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

Appendix H: Source of Figures Used in Report
Page 140 of 153

Winter Peak 

Loads

7 Generation 

Capacity Data 

by Fuel Type

Commission 

Staff

NERC 2017-2018 Winter 

Reliability Assessment Resource 

Adequacy Data – Existing OnPeak Generation 

(https://www.nerc.com/pa/RAPA/ra/Reli

ability%20Assessments%20DL/NERC_

WRA_11202017_%20Final.pdf ), and 

other publicly-available data, 

prepared using MS® Office 2013 

8 Enclosed coal 

fired power 

plant in the 

northeastern 

United States

Previously 

obtained 

permission 

for 

publication

“Appendix: Power Plant Design 

for Ambient Weather Conditions” 

to the joint Commission/NERC 

Staff Report on Outages and 

Curtailments During the

Southwest Cold Weather Event of 

February 1-5, 2011: Causes and 

Recommendations

9 Non-enclosed 

coal fired power 

plant in the 

northeastern 

United States

Previously 

obtained 

permission 

for 

publication

“Appendix: Power Plant Design 

for Ambient Weather Conditions” 

to the joint Commission/NERC 

Staff Report on Outages and 

Curtailments During the 

Southwest Cold Weather Event of 

February 1-5, 2011: Causes and 

Recommendations

10 MISO’s Nearterm Peak Load 

Forecasts and 

Percent Error for 

MISO South: 5-

day, 4-day, 3-

day, 2-day, and 

1-day ahead of 

January 17, 

2018

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

11 MISO’s High 

and Low 

Temperature 

Forecasts Used 

in MISO South 

Load Forecasts: 

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013 
Page 141 of 153

5-day, 4-day, 3-

day, 2-day, 1-

day ahead of 

January 17, 

2018

12 Event Area 

Approximate 

Planned and 

Unplanned 

Generation 

Outages, at the 

Start of January 

15, and January 

17, 2018

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

13 MISO South 

Region 

Forecasted Peak 

Load for 

January 17, 

2018 and 

Available 

Generation, at 

the Start of 

January 15, 

2018

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

14 Total 

Generation 

Losses Within 

the Event Area, 

Beginning 

January 17, by 

RC Footprint

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 

Velocity Suite© software and 

MS® Office 2013

15 Declarations 

Made by MISO 

in Preparation 

for January 17 

and 18

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

16 Comparison of 

Transmission 

Planning 

Voltage Criteria 

(Percent) – Low 

Commission 

Staff

Data provided by entities, and 

publicly-available information, 

prepared using MS® Office 2013
Page 142 of 153

Limits for 

Relevant 

Entities in the 

Event Area

17 Comparison of 

Actual Highs 

and Lows to 

Average Daily 

High and Low 

Temperatures, 

January 16 

through January 

18, 2018

NERC Staff NOAA weather data

18 January 17, 

2018 Peak 

Loads for 

Relevant 

Entities

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

19 January 17, 

2018 System 

Loads and 

Average Event 

Area Temp.

Commission 

Staff

Data provided by entities, and 

NOAA weather data, prepared 

using MS® Office 2013

20 Total 

Generation

Losses Within 

the Event Area, 

Beginning 

January 17, by 

Approximate 

Geographical 

Area

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 

Velocity Suite© software and 

MS® Office 2013

21 January 15-19, 

2018 – Number 

of Generation 

Unit Losses 

Versus 

Temperature, by 

Hour, for Event 

Area

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Analysis ToolPak

22 Total 

Unavailable 

Generation Over 

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013
Page 143 of 153

Time, for 

January 17, 

2018, by RC 

Footprint 

23 MISO South 

Region 

Approximate 

Generation 

Outages and 

Derates January 

17, 2018, by 

8am Central 

Time

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

24 Total 

Incremental 

Unavailable 

Generation in 

the Event Area 

for January 17, 

2018

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

25 By 2am CST –

BES 

Transmission 

Congestion 

Began to Occur

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 

Velocity Suite© software and 

MS® Office 2013

26 MISO Wind 

Forecast Versus 

Actual for 

Winter 2017-

2018

MISO Market 

Monitor, 

Potomac 

Economics. 

Used by 

permission.

https://www.potomaceconomics.c

om/wpcontent/uploads/2018/03/IMMQuarterly-Report_Winter2018_final.pdf Slide 28

27 By 6 a.m. CST –

Unplanned 

Outages, Total 

and as a 

Percentage of 

Event Sub-Area 

Capacity

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 

Velocity Suite© software and 

MS® Office 2013

28 By 6am CST, 

Total 

Generation 

Outages and 

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 

Velocity Suite© software and 

MS® Office 2013
Page 144 of 153

Derates Within 

the Event Area, 

by Approximate 

Geographical 

Area

29 By 4 a.m. CST –

Numerous 

Additional 

Transmission 

Constraints for 

Wide-Area of 

South Central 

U.S.

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 

Velocity Suite© software and 

MS® Office 2013

30 By 6am Central 

– Further 

Transmission 

Constraints 

Occurring for 

Wide-Area of 

South Central 

U.S.

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 

Velocity Suite© software and 

MS® Office 2013

31 5am Central: 

Decrease in 

Southwesternto-Southeastern 

Oklahoma 

345kV Bus 

Voltages, Early 

Morning Hours 

of January 17, 

2018

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

32 MISO Regional 

Dispatch 

Transfer –

January 17, 

2018

Entities, 

Commission 

Staff

Illustration provided by entities, 

with additional graphics added 

using MS® Office 2013

33 6am Central: 

Further 

Decrease in 

Southwesternto-Southeastern 

Oklahoma 

345kV Bus Per 

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013
Page 145 of 153

Unit Voltages, 

Early Morning 

Hours of 

January 17, 

2018

34 BES PreContingency 

Voltage 

Conditions 

(P.U.) for Select 

EHV Buses, 

January 17, 

2018, 

Approximately 

6am CST

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx

Velocity Suite© software and 

MS® Office 2013

35 BES Voltage 

Conditions 

(P.U.) for High 

Voltage Buses 

below Normal 

(PreContingency) 

Limits, January 

17, 2018, 

Approximately 

6am CST

Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 

Velocity Suite© software and 

MS® Office 2013

36 BES PostContingency 

Range of 

Voltages below 

Limits for Buses 

in MISO South, 

January 17, 

2018, at 

Approximately 

06:30am CST, 

for the 

Simulated 

Outage of the 

MISO South 

WSC

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

37 BES PostContingency Commission 

Staff

Data provided by entities, 

prepared using ABB Ventyx 
Page 146 of 153

Voltage 

Conditions 

(P.U.) Below 

Limits for EHV 

Buses in MISO 

South, January 

17, 2018, at 

Approximately 

06:30am CST, 

for the 

Simulated 

Outage of the 

MISO South 

WSC 

Velocity Suite© software and 

MS® Office 2013

38 10am CST: 

Improvement in 

Southwesternto-Southeastern 

Oklahoma 345 

kV per unit Bus 

Voltages, Early 

Morning, 

January 17, 

2018

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013

39 MISO and SPP 

Wind Output, 

January 16 

through 19, 

2018

Entities, 

Commission 

Staff

Illustration provided by entities, 

with additional graphics added 

using MS® Office 2013

40 January 15-19, 

2018 - Causes of 

Unplanned 

Generation 

Outages and 

Derates for 

Event Area

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Stata® Software

41 January 15-19, 

2018 – Subcauses for 

Unplanned 

Generation 

Outages and 

Derates due to 

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Stata® Software
Page 147 of 153

Freezing Issues, 

for Event Area 

42 January 17, 

2018 - Causes of 

Generation 

Outages for 

Event Area, By 

RC 

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Stata® Software

43 January 17, 

2018 – Causes 

of Unplanned 

Generation 

Outages and 

Derates for 

Event Area

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Stata® Software

44 January 17, 

2018 – Subcauses for 

Unplanned 

Generation 

Outages and 

Derates due to 

Fuel Supply 

Problems, for 

Event Area

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Stata® Software

45 January 17, 

2018 – Subcauses for 

Unplanned 

Generation 

Outages and 

Derates due to 

Freezing Issues, 

for Event Area

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Stata® Software

46 January 15-19, 

2018 – Subcauses for 

Unplanned 

Generation 

Outages and 

Derates due to 

Fuel Supply 

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Stata® Software
Page 148 of 153

Problems, for 

Event Area

47 January 15-19, 

2018 – Fuel 

Type for 

Unplanned 

Generation 

Outages and 

Derates due to 

Freezing Issues, 

for Event Area 

(by Number of 

Generators)

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Stata® Software

48 January 15-19, 

2018 – Fuel 

Type for 

Unplanned 

Generation 

Outages and 

Derates due to 

Freezing Issues, 

for Event Area 

(by MW of 

Generation)

Commission 

Staff

Data provided by entities, 

prepared using MS® Office 2013, 

and Stata® Software
Page 149 of 153

Appendix I: Regional Transfer Operating Committee Event Review Report

(September 9, 2018)
Page 150 of 153
Page 151 of 153
Page 152 of 153
Page 153 of 153
 

 

FERC and NERC Staff Report July 2019 

This report was prepared by the staff of the Federal Energy Regulatory 

Commission in consultation with staff from the North American Electric 

Reliability Corporation and its Regional Entities. 

This report does not necessarily reflect the views of the Commission. 

*NASA Worldview Snapshot satellite image of The United States showing weather pattern for January 17, 2018.
FERC and NERC Staff Report

July 2019